PPR Prairie Provident Resources Inc

Prairie Provident Resources Inc. ("Prairie Provident", "PPR" or the "Company") (TSX:PPR) is pleased to announce our operating and financial results for the fourth quarter and year ended 2021. PPR’s audited annual consolidated financial statements ("Annual Financial Statements") and related Management’s Discussion and Analysis (“MD&A”) and annual information form dated March 29, 2022 (“AIF”) are available on our website at www.ppr.ca and filed on SEDAR at www.sedar.com.

MESSAGE TO SHAREHOLDERS  

Tony Berthelet, President & Chief Executive Officer commented: “2021 saw the Company increase focus to maximizing cash flow from existing assets and unlocking the significant potential of the Michichi asset. Waterflood reserves recognition from the Michichi waterflood pilot in 2021 sets the foundation for further waterflood expansion and reserves development. Enhancing the team across all disciplines sets the Company up for continued optimization of the existing asset base and maximizing value from these legacy assets. The focus for PPR in 2022 is to continue to improve the balance sheet through non-core dispositions and debt reduction.”

2021 HIGHLIGHTS

• Successful 2021 drilling program and fully funded by adjusted funds flow ("AFF")1: During 2021, we incurred net capital expenditures(1) of $14.7 million, $12.1 million of which to drill, complete, equip and tie-in five gross (5.0 net) wells in the Princess area. All five wells came on production during the year and contributed approximately 415(2) boe/d of incremental production in 2021 and are anticipated to deliver annualized average production of approximately 875(3) boe/d over the 12-month period from their respective on initial production dates. Our capital program was fully funded by 2021 AFF(1) of $15.5 million (excluding decommissioning settlements). The final well was brought on production on December 1, 2021 with an IP30(4) rate of approximately 775 boe/d. Current production on this well remains at approximately 400(5) boe/d.
• Maintained exit production: Production for 2021 averaged 4,268 boe/d (65% liquids), which was 11% lower than 2020 primarily due to natural declines, partially offset by production from our 2021 drilling program. Even with the suspension of our capital program during 2020, we maintained our year-over-year exit production rate with our 2021 drilling program and workover activities, where Q4 2021 production averaged 4,369 boe/d (65% liquids), similar to Q4 2020.
• Record operating netback(1) per boe: Operating netback before realized losses on derivatives for Q4 and year of 2021 was $28.86/boe and $22.87/boe, respectively, a record high since PPR became a publicly listed company in 2016. 2021 operating netback before realized losses on derivatives increased by $17.48/boe or 324% from 2020 driven by significant commodity price recoveries in the year. Q4 2021 operating netback per boe before realized losses on derivatives increased by 237% from Q4 2020, due to the same factor that led to the annual increase.
• Net earnings amidst commodity price recovery: Net earnings totaled $10.4 million in 2021, compared to a net loss of $90.8 million in 2020, driven primarily by impairment reversals recognized in 2021 related to our Evi and Princess CGUs as a result of recoveries of commodity prices versus impairment losses recognized in 2020. For Q4 2021, net income totaled $7.9 million driven by AFF and non-cash items including fourth quarter impairment reversals, unrealized gains on derivative instruments and gains on debt modifications.
• Improved AFF(1): PPR generated AFF of $15.5 million for 2021 ($0.11 per basic and $0.09 per diluted share), excluding $3.3 million of decommissioning settlements, an increase of 29% or $3.5 million from 2020, reflecting improved operating netbacks. Q4 2021 AFF, excluding $2.6 million of decommissioning settlements, was $4.3 million ($0.03 per basic and diluted share), a 121% increase from Q4 2020.
• Reduced decommissioning liabilities: During 2021, we actively reduced our decommissioning liabilities with a combination of $2.2 million of funding from Alberta’s Site Rehabilitation Program ("SRP") and $3.3 million of internal funding. In addition, we removed $0.5 million of decommissioning liabilities through property dispositions. PPR continues to increase its focus on environmental stewardship and has budgeted $4.0 million of internally funded decommission settlements for 2022, in addition to $3.7 million of settlements anticipated to be covered by grants under the SRP.
• Secured liquidity by extending maturity dates of long-term debt: In December 2021, PPR entered into agreements with our lenders for the renewal of our credit facilities including the extension of the maturity date of the revolving facility to December 31, 2023. The amendments also provide for added borrowing base certainty during 2022, as there is to be no scheduled redetermination of the borrowing base until after December 31, 2022. Additionally, the maturity date of the US$28.5 million aggregate original principal of subordinated senior notes issued in October 2017 and November 2018 (together with deferred interest amounts) was extended to June 30, 2024.
• Net debt(1): As at December 31, 2021, net debt1 totaled $124.3 million which increased by $8.4 million from December 31, 2020. The increase was attributed to accelerating capital spending to take advantage of commodity pricing by drilling short cycle wells in Princess and advancing development of the Michichi Q1 2022 capital program to unlock value from these high quality assets. These capital expenditures coupled with lease payments, deferred interest on long-term debt, decommissioning settlements, and transaction, restructuring and other costs in 2021 exceeded of AFF1. PPR had US$6.4 million (CAN$8.1(6) million equivalent) at December 31, 2021 (December 31, 2020 — US$11.2 million) of available borrowing capacity under the Company's senior secured revolving note facility.

________________________1  Non-GAAP financial measure – see below under “Non-GAAP and Other Financial Measures”.2  Comprised of average production of approximately 258 bbl/d of heavy crude oil and 942 Mcf/d of conventional natural gas.3  Anticipated annualized 12-month average production from these 5 wells is comprised of and estimated 605 bbl/d of heavy crude oil and an estimated 1,620 Mcf of conventional natural gas, and is calculated based on actual production from the wells' respective on-production dates to February 28, 2022 plus forecasted production provided by Sproule Associates Limited ("Sproule") and applied by Sproule in its evaluation of reserves as of December 31, 2021 for the remaining period to total 12-month of production. Readers are cautioned that forecasted production volumes and rates may differ materially from actual production volumes and rates.4  Average initial production over a 30-day period commencing December 1, 2021, during which the well produced an average of 640 bbl/d of heavy crude oil and 810 Mcf/d of conventional natural gas from the Glauconite formation. Readers are cautioned that short-term initial production rates are preliminary in nature and may not be indicative of stabilized on-stream production rates, future product types, long-term well or reservoir performance, or ultimate recovery. Actual future results will differ from those realized during an initial short-term production period, and the difference may be material.5  Comprised of average production of approximately 308 bbl/d of heavy crude oil and 552 Mcf/d of conventional natural gas.6  Converted using the month end exchange rate of $1.00 USD to $1.27 CAD as at December 31, 2021.

FINANCIAL AND OPERATING SUMMARY

	Three Months Ended December 31,				Year Ended December 31,
($000s except per unit amounts)	2021		2020		2021		2020
Production Volumes
Light & medium crude oil (bbl/d)	2,198		2,639		2,355		2,881
Heavy crude oil (bbl/d)	492		163		294		210
Conventional natural gas (Mcf/d)	9,246		9,080		8,900		9,328
Natural gas liquids (bbl/d)	138		140		135		136
Total (boe/d)	4,369		4,455		4,268		4,781
% Liquids	65	%	66	%	65	%	67	%
Average Realized Prices
Light & medium crude oil ($/bbl)	80.81		45.04		71.83		38.05
Heavy crude oil ($/bbl)	79.98		40.91		72.12		35.26
Conventional natural gas ($/Mcf)	4.89		2.71		3.73		2.25
Natural gas liquids ($/bbl)	74.35		30.98		57.25		24.59
Total ($/boe)	62.36		34.67		54.19		29.56
Operating Netback ($/boe)1
Realized price	62.36		34.67		54.19		29.56
Royalties	(8.32	)	(3.18	)	(6.16	)	(2.87	)
Operating costs	(25.18	)	(22.93	)	(25.16	)	(21.30	)
Operating netback	28.86		8.56		22.87		5.39
Realized gains (losses) on derivative instruments	(9.82	)	5.64		(6.13	)	8.71
Operating netback, after realized gains (losses) on derivative instruments	19.04		14.20		16.74		14.10

Notes:1 Operating netback is a Non-GAAP financial measure (see “Non-GAAP and Other Financial Measures” below) calculated as oil and natural gas revenue less royalties less operating costs.

Capital Structure($ millions)	As atDecember 31, 2021		As atDecember 31, 2020
Working capital1	(0.4	)	5.3
Borrowings outstanding (principal plus deferred interest)	(124.0	)	(121.3	)
Total net debt2	(124.3	)	(115.9	)
Debt capacity3	8.1		21.8
Common shares outstanding (in millions)4	128.7		172.3

Notes:1 Working capital (deficit) is a non-GAAP financial measure (see "Non-GAAP and Other Financial Measures" below) calculated as current assets less current portion of derivative instruments, minus accounts payable and accrued liabilities.2 Net debt is a non-GAAP financial measure (see "Non-GAAP and Other Financial Measures" below), calculated by adding working capital (deficit) and borrowings outstanding under long-term debt.3 Debt capacity reflects the undrawn capacity of the Company's revolving facility, which had a borrowing base of USD$53.8 million at December 31, 2021 and USD$60.0 million at December 31, 2020, converted at an exchange rate of $1.0000 USD to $1.2678 CAD on December 31, 2021 and $1.0000 USD to $1.2732 CAD on December 31, 2020.4 Subsequent to December 31, 2020, PPR cancelled 44,711,330 common shares that were surrendered to the Company for nominal consideration. After giving effect to the cancellation, PPR had 128.0 million common shares outstanding.

	Three Months Ended December 31,		Year Ended December 31,
Drilling Activity	2021	2020	2021	2020
Gross wells	1.0	—	5.0	1.0
Net (working interest) wells	1.0	—	5.0	1.0
Success rate, net wells (%)	100	N/A	100	100

OPERATIONAL UPDATE

In the first quarter of 2022, PPR advanced the development of its Banff Formation properties in the Michichi area near Drumheller. PPR finalized the drilling and completion of two gross (2.0 net) wells, both of which came on production in the first week of March, ahead of the budgeted schedule. The wells are currently on pump and cleaning up with load water being recovered and peak rates still to be seen. Early indications trend the production to be at or above forecasted type curves1. The wells were targeted in the Lower Banff to maximize oil recovery and assist in an optimized water injection scheme. PPR is in the process of converting the first of three wells in Michichi planned in 2022 to injection to aid in the secondary oil recovery program from the Banff Formation.

1 Based on type curves developed by Sproule and applied by Sproule in its evaluation of the Company's reserves as of December 31, 2021 in accordance with National Instrument 51-101 - Standards of Dislcosure for Oil and Gas Activities.

NON-CORE DISPOSITION UPDATE

As previously announced, PPR continues to advance the disposition of several non-core properties with the goals of reducing liabilities, fixed operating costs, and reducing debt. Bids are due in April 2022.

ENVIRONMENT SOCIAL AND GOVERNANCE UPDATE

PPR continues to increase its focus on environmental stewardship, as well as on social and governance initiatives and expects to publish its inaugural Environmental, Social and Governance ("ESG") report on its website (www.ppr.ca) in early April 2022. Additionally, in early 2022 an ESG board committee was formed and a corporate ESG policy has been developed.

OUTLOOK

On February 22, 2022, PPR announced its planned 2022 capital budget (see press release at www.ppr.ca). PPR's 2022 development plan builds on 2021 successful drilling programs and waterflood results in Evi and Michichi. Unlocking the significant reserves potential in Michichi is a key focus for 2022 through a combination of drilling activity and waterflood expansion. PPR expects to fully fund budgeted 2022 capital expenditures and decommissioning settlements from cash from operating activities, though PPR may utilize borrowing capacity under the Revolving Facility for liquidity from time to time to temporarily fund operations during periods should expenditures exceed cash from operating activities.

ABOUT PRAIRIE PROVIDENT

Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas properties in Alberta. The Company’s strategy is to optimize cash flow from our existing assets, grow a base waterflood business in Evi (Slave Point Formation) and Michichi (Banff Formation) providing stable low decline cash flow, and organically develop a new complementary play to facilitate reserves and production growth. The Princess area in Southern Alberta continues to provide short cycle returns through successful development of the Glauconite and Ellerslie Formations.

For further information, please contact:

Prairie Provident Resources Inc. Tony BertheletPresident and Chief Executive Officer Tel: (403) 292-8125Email: tberthelet@ppr.ca

Forward-Looking Statements

This news release contains certain statements ("forward-looking statements") that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future performance, events or circumstances, are based upon internal assumptions, plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”, “potential”, “project”, “continue”, “may”, “will”, “should” or similar words suggesting future outcomes or events or statements regarding an outlook.

Without limiting the foregoing, this news release contains forward-looking statements pertaining to: plans to improve the balance sheet in 2022 through non-core dispositions and debt reduction; anticipated annualized 12-month production from the 5 wells brought on production in 2021; anticipated decommissioning spending in 2022 and expected coverage under the government‐sponsored Site Rehabilitation Program (SRP); the conversion of Michichi wells to injectors to aid in a secondary recovery program; and the expected filing date of the inaugural ESG report.

Forward-looking statements are based on a number of material factors, expectations or assumptions of Prairie Provident which have been used to develop such statements but which may prove to be incorrect. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements, which are inherently uncertain and depend upon the accuracy of such expectations and assumptions. Prairie Provident can give no assurance that the forward-looking statements contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized. Actual results or events will differ, and the differences may be material and adverse to the Company. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: that Prairie Provident will continue to conduct its operations in a manner consistent with past operations; results from drilling and development activities, and their consistency with past operations; the quality of the reservoirs in which Prairie Provident operates and continued performance from existing wells (including with respect to production profile, decline rate and product type mix); the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident's reserves volumes; future commodity prices; future operating and other costs; future USD/CAD exchange rates; future interest rates; continued availability of external financing and cash flow to fund Prairie Provident's current and future plans and expenditures, with external financing on acceptable terms; the impact of competition; the general stability of the economic and political environment in which Prairie Provident operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Prairie Provident to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Prairie Provident has an interest in to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Prairie Provident to secure adequate product transportation; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Prairie Provident operates; and the ability of Prairie Provident to successfully market its oil and natural gas products.

The forward-looking statements included in this news release are not guarantees of future performance or promises of future outcomes, and should not be relied upon. Such statements, including the assumptions made in respect thereof, 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 statements including, without limitation: changes in realized commodity prices; changes in the demand for or supply of Prairie Provident's products; the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the geologic formations targeted by Prairie Provident’s operations; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Prairie Provident or by third party operators; increased debt levels or debt service requirements; inaccurate estimation of Prairie Provident's oil and gas reserves volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and such other risks as may be detailed from time-to-time in Prairie Provident's public disclosure documents (including, without limitation, those risks identified in this news release and the AIF).

The forward-looking statements contained in this news release speak only as of the date of this news release, and Prairie Provident assumes no obligation to publicly update or revise them to reflect new events or circumstances, or otherwise, except as may be required pursuant to applicable laws. All forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Barrels of Oil Equivalent

The oil and gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant gate, which is where Prairie Provident sells its production volumes. Boes may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.

Non-GAAP and Other Financial Measures

This news release discloses certain financial measures, as described below, that are 'non-GAAP financial measures', 'supplementary financial measures' and 'non-GAAP ratios' within the meaning of applicable Canadian securities laws. Such measures do not have a standardized or prescribed meaning under International Financial Reporting Standards (IFRS) and, accordingly, may not be comparable to similar financial measures disclosed by other issuers. Non-GAAP and other financial measures are provided as supplementary information by which readers may wish to consider the Company's performance but should not be relied upon for comparative or investment purposes. Readers must not consider non-GAAP and other financial measures in isolation or as a substitute for analysis of the Company’s financial results as reported under IFRS.

Working Capital – Working capital (deficit) is a non-GAAP financial measure, calculated as current assets excluding the current portion of derivative instruments, less accounts payable and accrued liabilities and corresponds with the terms defined under the Company's debt agreements for the calculation of the Current Ratio covenant (see Note 8(c) Long-Term Debt - Covenants in the Annual Financial Statements for additional information on the Company's debt covenants). In addition to measuring covenant compliance, this measure is used to assist management and investors in understanding liquidity at a specific point in time.

The following table provides a reconciliation of Working Capital:

($000s)	December 31,2021		December 31,2020
Current assets	19,603		20,807
Less: current derivative instrument assets	—		(798	)
Current assets excluding current derivatives instruments	19,603		20,009
Less: Accounts payable and accrued liabilities	19,970		14,683
Working capital	(367	)	5,326

Net Debt – Net debt is a non-GAAP financial measure, defined as borrowings under long-term debt plus Working Capital. Net debt is commonly used in the oil and gas industry for assessing the liquidity of a company.

The following table provides a reconciliation of Net Debt:

($000s)	December 31,2021		December 31,2020
Working capital (deficit)	(367	)	5,326
Borrowings outstanding (principal plus deferred interest)	(123,972	)	(121,274	)
Total net debt	(124,339	)	(115,948	)

Operating Netback – Operating netback is a non-GAAP financial measure commonly used in the oil and gas industry, which the Company believes is a useful measure to assist management and investors to evaluate operating performance at the oil and gas lease level. Operating netbacks included in this news release are determined as oil and natural gas revenue less royalties less operating costs. Operating netback may be expressed in absolute dollar terms or a per boe basis. Per boe amounts are determined by dividing the absolute value by gross working interest production. Operating netback per boe is a non-GAAP ratio.

The following table provides a reconciliation of Operating Netback:

	Three Months Ended December 31,				Year Ended December 31,
($000s)	2021		2020		2021		2020
Oil and natural gas revenue	25,064		14,211		84,423		51,720
Royalties	(3,346	)	(1,305	)	(9,603	)	(5,027	)
Operating expenses	(10,120	)	(9,399	)	(39,194	)	(37,271	)
Operating netback	11,598		3,507		35,626		9,422
Realized (losses) gains on derivatives	(3,947	)	2,313		(9,556	)	15,241
Operating netback, after realized (losses) gains on derivatives	7,651		5,820		26,070		24,663

Adjusted Funds Flow (AFF) – Adjusted funds flow is a non-GAAP financial measure calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs, restructuring costs and other non-recurring items. The Company believes that adjusted funds flow provides a useful measure of PPR’s operational performance on a continuing basis by eliminating certain non-cash charges and charges that are non-recurring or discretionary. Management utilizes the measure to assess PPR's ability to finance capital expenditures and debt repayments. Adjusted funds flow as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted funds flow per share is calculated based on the weighted average number of common shares outstanding consistent with the calculation of earnings per share. Adjusted funds flow per share is a non-GAAP ratio.

The following table reconciles cash flow from operating activities to AFF and AFF excluding decommissioning settlements which are seasonal in nature as a significant portion of PPR's decommissioning liabilities are located in winter access only areas:

	Three Months Ended December 31,				Year Ended December 31,
($000s)	2021		2020		2021		2020
Cash flow from operating activities	(1,305	)	3,958		9,681		10,182
Changes in non-cash working capital	2,324		(493	)	1,501		1,779
Other	(46	)	(1,743	)	(56	)	(1,727	)
Transaction, restructuring and other costs	745		131		1,068		238
Adjusted funds flow ("AFF")	1,718		1,853		12,194		10,472
Decommissioning settlements	2,584		93		3,276		1,542
AFF - excluding decommissioning settlements	4,302		1,946		15,470		12,014

Net Capital Expenditures – Net capital expenditures is a non-GAAP financial measure commonly used in the oil and gas industry, which the Company believes is a useful measure to assist management and investors to assess PPR’s investment in its existing asset base. Net capital expenditures is calculated by taking total capital expenditures, which is the sum of property and equipment expenditures and exploration and evaluation expenditures from the consolidated statement of cash flows, plus capitalized stock-based compensation, plus acquisitions from business combinations, which is the outflow cash consideration paid to acquire oil and gas properties, less asset dispositions (net of acquisitions), which is the cash proceeds from the disposition of producing properties and undeveloped lands.

The following table provides a reconciliation of Net Capital Expenditures:

	Three Months Ended December 31,				Year Ended December 31,
($000s)	2021		2020		2021		2020
Exploration and evaluation expenditures	76		121		456		271
Property and equipment expenditures	3,493		120		14,316		3,758
Capitalized stock-based compensation	—		0		(10	)	15
Asset disposition (net of acquisition)	(116	)	(65	)	(56	)	(249	)
Net capital expenditures	3,453		176		14,706		3,795