November 11, 2021

Prairie Provident Resources Announces Third Quarter 2021 Financial and Operating Results and Leadership Changes

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Calgary, Alberta – November 10, 2021 – Prairie Provident Resources Inc. (“Prairie Provident”, “PPR” or the “Company”) today announces our financial and operating results for the three and nine months ended September 30, 2021. PPR’s unaudited condensed interim consolidated financial statements for the three and nine months ended September 30, 2021 and related Management’s Discussion and Analysis (“MD&A”) for the same periods are available on our website at www.ppr.ca and filed on SEDAR.

MESSAGE TO SHAREHOLDERS

Tony Berthelet, President & Chief Executive Officer commented: “I am excited to welcome Ryan and Allison to the leadership team at Prairie Provident. They bring the experience, energy and attitude to help drive change and assist in maximizing value from our asset base. As promised last quarter, we continued our drilling success in Princess, delivering solid results from a strong drilling inventory. We look forward to a strong finish to the year setting us up for a successful 2022 program.”

Q3 2021 HIGHLIGHTS
  • Executive leadership changes bring technical and commercial skills to improve value from the existing asset base and to assist in the execution of Prairie Provident’s strategy of waterflood expansion, new play development and ARO management.  As of September 2021, Allison Massey has been appointed Vice President, Land & Commercial; and Ryan Rawlyk has been appointed Vice President, Production & Operations. The Company also announces the departures of Gjoa Taylor and Brad Likuski and wishes them all the best in their future endeavours.
  • Successful drilling program resulting in the addition of supplemental well in the fourth quarter:  During Q3 2021, we incurred $4.7 million of Net Capital Expenditures1 to drill, complete, equip and tie-in our third and fourth Princess wells to date in 2021.  We brought on production an Ellerslie well in Princess on September 14, 2021 with an IP30(2) rate of approximately 190 boe/d and a Glauconite well in Princess on October 2, 2021 with an IP30(3) rate of approximately 220 boe/d. These two wells, plus two Princess wells that came on production in the second quarter of 2021, are currently producing approximately 715(4) boe/d (67% liquids), and contributed approximately 420(5) boe/d of incremental production for Q3 2021.  Due to the strong results of the four-well drilling program coupled with strong commodity prices, PPR has added an additional well to its 2021 drilling program.  Drilling commenced in mid-October 2021, with on-stream timing anticipated before the end of 2021.
  • Production:  Production during the quarter averaged 4,273 boe/d (65% liquids) in Q3 2021, a 5% or 243 boe/d decrease from Q3 2020, primarily driven by natural declines, partially offset by additional production from our 2021 drilling program.
  • Higher operating netback1:  Operating netback for Q3 2021 was $23.72/boe before realized loss on derivatives, the highest level since 2018 and exceeding second quarter 2021 netbacks by $1.56/boe.  PPR generated cash flow of $9.3 million at the field level, representing a 170% increase from Q3 2020.  After realized derivative losses, we recognized $7.0 million ($17.93/boe) of operating netback, reflecting a 18% increase from Q3 2020.  Compared to Q3 2020, on a per boe basis, operating netback before and after the realized derivative losses increased by 186% and 18%, respectively, reflecting higher realized prices and higher realized derivative losses.
  • Net loss:  Net loss totaled $9.9 million for Q3 2021, compared to $8.3 million for Q3 2020.  The increase in net loss was primarily driven by increased unrealized foreign exchange losses and warrant liability losses partially offset by higher adjusted funds flow excluding decommissioning settlements and a decrease in unrealized derivative losses.
  • Improved adjusted funds flow (AFF)1:  AFF for Q3 2021, excluding $0.5 million of decommissioning settlements, was $4.8 million ($0.04 per basic and diluted share), a 23% or $0.9 million increase from Q3 2020, reflecting improved netbacks. The positive effect on AFF of further improved commodity pricing was partially offset by realized losses on required derivative contracts arising from mandatory hedge positions pursuant to credit facility covenants which were entered into when the pricing environment was volatile.  Approximately 55% of our fourth quarter 2021 forecast production is hedged with 3-way collars on 1,675 bbl/d capped at an average ceiling price of WTI US$60.80/bbl.
  • Reducing decommissioning liabilities: During the nine months ended September 30, 2021, we actively reduced our decommissioning liabilities with a combination of $1.8 million of funding from Alberta’s Site Rehabilitation Program and $0.7 million of internal funding.  In addition, we removed $0.5 million of decommissioning liabilities through property dispositions.  In the fourth quarter of 2021, we have committed to further reduce our obligation by $3.0 million through abandonment and reclamation activities.
  • Net debt1:  Net debt at September 30, 2021 totaled $121.0 million, an increase of $5.0 million from December 31, 2020 primarily due to lease payments, decommissioning settlements and net capital expenditures1 in the first nine months of 2021 that exceeded AFF1; together with $1.3 million of deferred interest on the Company’s long-term debt and $0.3 million of unrealized foreign exchange loss on our US dollar denominated debt.
  • Maintained liquidity:  At September 30, 2021, PPR had US$13.3 million (CAN$16.9(6) million equivalent) (December 31, 2020 — US$11.2 million) of available borrowing capacity under the Company’s senior secured revolving note facility.

1 Non-IFRS measure – see below under “Non-IFRS Measures”
2 Average initial production over a 30-day period commencing September 14, 2021, during which the well produced an average of 111 bbl/d of heavy crude oil and 474 Mcf/d of conventional natural gas from the Ellerslie 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.
3 Average initial production over a 30-day period commencing October 2, 2021, during which the well produced an average of 185 bbl/d of heavy crude oil and 222 Mcf/d of conventional natural gas from the Glauconite formation. Readers are cautioned that short-term test 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 test period, and the difference may be material.
Comprised of average production of approximately 480 bbl/d of heavy crude oil and 1,410 Mcf/d of conventional natural gas based on field estimates.
Comprised of average production of approximately 232 bbl/d of heavy crude oil and 1,128 Mcf/d of conventional natural gas.
Converted using the month end exchange rate of $1.00 USD to $1.27 CAD as at September 30, 2021.

FINANCIAL AND OPERATING SUMMARY
Three Months Ended   Nine Months Ended
($000s except per unit amounts) September 30,
2021
September 30, 2020 September 30,
2021
September 30,
2020
Production Volumes
Light & medium crude oil (bbl/d) 2,261 2,730 2,408 2,963
Heavy crude oil (bbl/d) 384 200 228 225
Conventional natural gas (Mcf/d) 8,986 8,704 8,783 9,411
Natural gas liquids (bbl/d) 131 135 133 134
Total (boe/d) 4,273 4,516 4,234 4,891
% Liquids 65% 68% 65% 68%
Average Realized Prices
Light & medium crude oil ($/bbl) 76.12 43.84 69.06 35.95
Heavy crude oil ($/bbl) 71.78 42.12 66.18 34.00
Conventional natural gas ($/Mcf) 3.69 2.26 3.32 2.09
Natural gas liquids ($/bbl) 59.16 24.96 51.70 22.47
Total ($/boe) 56.30 33.47 51.35 27.99
Operating Netback ($/boe)1
Realized price 56.30 33.47 51.35 27.99
Royalties (6.89) (3.38) (5.41) (2.78)
Operating costs (25.69) (21.79) (25.15) (20.80)
Operating netback 23.72 8.30 20.79 4.41
Realized gains (losses) on derivatives (5.79) 6.85 (4.85) 9.65
Operating netback, after realized gains (losses) on derivatives 17.93 15.15 15.94 14.06

1   Operating netback is a non-IFRS measure (see “Non-IFRS Measures” below).

Capital Structure

($000s)

September 30, 2021 December 31, 2020
Working capital1 (0.9) 5.3
Borrowings outstanding (principal plus deferred interest) (120.1) (121.3)
Total net debt2 (121.0) (115.9)
Debt capacity3 16.9  14.3
Common shares outstanding (in millions) 128.4  172.3

1 Working capital is a non-IFRS measure (see “Non-IFRS Measures” below) calculated as current assets less current portion of derivative instruments, minus accounts payable and accrued liabilities. 
2 Net debt is a non-IFRS measure (see “Non-IFRS Measures” below), calculated by adding working capital and long-term debt. 
3 Debt capacity reflects the undrawn capacity of the Company’s revolving facility of USD$57.7 million at September 30, 2021 and December 31, 2020, converted at an exchange rate of $1.00 USD to $1.27 CAD on September 30, 2021 and $1.00 USD to $1.27 CAD on December 31, 2020.

Three Months Ended

September 30,

Six Months Ended

September 30,

Drilling Activity 2021 2020 2021 2020
Gross wells 2.0 0.0 4.0 1.0
Net (working interest) wells 2.0 N/A 4.0 1.0
Success rate, net wells (%) 100% N/A 100  % 100  %
OPERATIONAL UPDATE

Performance from the four gross (4.0 net) Princess wells drilled in the first nine months of 2021 are in line with our expectations and Sproule’s(1) type curves.  Drilling of the fifth Princess 103/03-29-018-10W4 horizontal well targeting the lower Mannville Glauconite channel to a measured depth of 3,512 meters commenced in mid-October 2021.  The well was drilled in zone for the entire 2,397 meters of lateral section with high quality sands and oil shows throughout. The casing liner was run and cemented successfully to total depth and the completion strategy has been optimized with a reduced spacing of 65 meters resulting in a total of 38 frac sleeves.

ENVIRONMENTAL SOCIAL AND GOVERNANCE UPDATE

PPR continues with efforts towards reducing the Company’s environmental impact through ongoing internal emission reduction initiatives and through participation in government programs that provide cost incentives or grants for environmental stewardship.

PPR employs a rigorous pipeline integrity program to mitigate the risk of environmental impact and maintains top tier regulatory compliance approval level relative to industry.

PPR is a participant in Alberta’s Area Based Closure (“ABC”) program, under which upstream oil and gas companies are encouraged to work together to decommission, remediate and reclaim groups of inactive sites, providing operational efficiencies and cost reductions due to economies of scale and regulatory incentives.

To date we have qualified for $6.1 million of gross funding under Alberta’s Site Rehabilitation Program, which provides grants to oil field service contractors to perform well, pipeline, and oil and gas site closure and reclamation work, and have allocated an additional $3.5 million of 2021 internal funding towards the retirement of inactive assets, with the majority of the decommissioning activities occurring in the second half of 2021. PPR anticipates that it will abandon over 150 gross wells during 2021, representing approximately 14% of our gross inactive well count, in addition to the abandonment of numerous inactive pipelines.  PPR has also initiated a significant reclamation program on inactive sites, under which we have added over 120 gross sites in varying stages of reclamation to the program in 2021 alone.

We have also received funding through Alberta’s Baseline and Reduction Opportunity Assessment Program, which offers financial support to small and medium conventional oil and gas operators to assess and reduce on-site methane emissions.  We are continuously working towards identification and implementation of emission reduction initiatives. Current reduction projects include replacing controllers with improved technology and low-bleed models at 58 of our existing sites.

1 Based on type curves developed by Sproule Associates Limited (“Sproule”) and applied by Sproule in its evaluation of Prairie Provident’s reserves as of December 31, 2020.

OUTLOOK

Following the drilling successes in Princess, we expanded our 2021 drilling program by one additional Glauconite well.  As this fifth Princess well is largely funded with the remainder of our capital budget, our total 2021 capital expenditures are forecasted to be materially in line with previous guidance.  The Glauconite well is expected to be on production before the end of 2021.  While our average 2021 production is forecasted to be slightly below guidance, we expect our exit production to exceed guidance of 4,370 boe/d, providing a head start to our 2022 production volume.

As a result of the activity and capital program completed during 2021, Prairie Provident is well positioned for further success in 2022 with predictable funds flow from our low-decline assets and an attractive inventory of drilling locations.  Our three core areas offer well-balanced light/medium oil and natural gas exposures, with a relatively low base decline rate of approximately 17%.  At the current commodity prices, our drilling inventory provides multiple capital allocation options.  We look forward to sharing our 2022 capital budget and operational guidance when they are finalized.

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 Glauc and Ellerslie Formations.

For further information, please contact: 

Tony Berthelet
President and Chief Executive Officer
Tel:(403) 292-8125
Email: tberthelet@ppr.ca 

Or 

Prairie Provident Resources Inc.
Mimi Lai
EVP and Chief Financial Officer
Tel: (403) 292-8171
Email: mlai@ppr.ca

Prairie Provident Resources Inc.
Website: www.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: expected on-stream timing for the fifth Princess well drilled in the fourth quarter of 2021; the scale and timing of planned decommissioning activities for 2021, including that most will occur in the second half of 2021, the expected amount of further reduction in decommissioning liabilities in the fourth quarter of 2021, and the expected number of gross wells to be abandoned during 2021; emission reduction initiatives; funding of the fifth Princess well primarily with the remainder of the 2021 capital budget and related expectations for total capital expenditures relative to previous guidance; and the expectation that exit production will exceed prior guidance.

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 Prairie Provident’s current Annual Information Form as filed with Canadian securities regulators and available from the SEDAR website (www.sedar.com) under Prairie Provident’s issuer profile).

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-IFRS Measures

The Company uses certain terms in this news release and within the MD&A that do not have a standardized or prescribed meaning under International Financial Reporting Standards (IFRS), and, accordingly these measurements may not be comparable with the calculation of similar measurements used by other companies. For a reconciliation of each non-IFRS measure to its nearest IFRS measure, please refer to the “Non-IFRS Measures” section in the MD&A.  Non-IFRS 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.  The non-IFRS measures used in this news release are summarized as follows: 

Working Capital – Working capital is calculated as current assets excluding the current portion of derivative instruments, less accounts payable and accrued liabilities. This measure is used to assist management and investors in understanding liquidity at a specific point in time.  The current portion of derivatives instruments is excluded as management intends to hold derivative contracts through to maturity rather than realizing the value at a point in time through liquidation. The current portion of decommissioning expenditures is excluded as these costs are discretionary and warrant liabilities are excluded as it is a non-monetary liability.  Lease liabilities have historically been excluded as they were not recorded on the balance sheet until the adoption of IFRS 16 – Leases on January 1, 2019.

Net Debt – Net debt is defined as borrowings under long-term debt plus working capital surplus.  Net debt is commonly used in the oil and gas industry for assessing the liquidity of a company.

Operating Netback – Operating netback is a non-IFRS measure commonly used in the oil and gas industry. This measurement assists management and investors to evaluate the specific operating performance at the oil and gas lease level. Operating netbacks included in this news release were determined as oil and gas revenues less royalties less operating costs.  Operating netback may be expressed in absolute dollar terms or a per unit basis.  Per unit amounts are determined by dividing the absolute value by gross working interest production. Operating netback after gains or losses on derivative instruments, adjusts the operating netback for only realized gains and losses on derivative instruments.

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

Net Capital Expenditures – Net capital expenditures is a non-IFRS measure commonly used in the oil and gas industry. The measurement assists management and investors to measure PPR’s investment in the Company’s existing asset base. Net capital expenditures is calculated by taking total capital expenditures, which is the sum of property and equipment 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.