Yahoo Finance Prairie Provident Resources Announces First Quarter 2022 Financial Results and Successful First Quarter Drilling Program
CALGARY, Alberta, May 11, 2022 (GLOBE NEWSWIRE) -- Prairie Provident Resources Inc. ("Prairie Provident", "PPR" or the "Company") is pleased to announce our operating and financial results for the three months ended March 31, 2022. PPR’s unaudited condensed interim consolidated financial statements for the three months ended March 31, 2022 (“Interim Financial Statements”) and related Management’s Discussion and Analysis (“MD&A”) are available on our website at www.ppr.ca and filed on SEDAR.
MESSAGE TO SHAREHOLDERS
Tony Berthelet, President & Chief Executive Officer commented: “The production results from our first quarter Michichi drill campaign confirms the optimized wellbore placement in the lower Banff, and the benefit of increased stage count on initial production results. We will monitor production results to determine improved recovery from this development design change, but we remain very encouraged by the early reservoir pressure and production stabilized rates. Upward cost pressure across all services and materials will continue to be a focus for Q2 as the industry adjusts to inflationary pressures.”
Q1 2022 HIGHLIGHTS
Successful drilling and capital program: During the quarter, we successfully drilled and completed two gross (2.0 net) Banff formation wells in the Michichi area. The wells both commenced production in early March 2022, with average IP30 rates of approximately 1471boe/d and 1152boe/d, respectively. Current average production of these wells is approximately 420(3) boe/d. During Q1 2022, we incurred Net Capital Expenditures4 of $7.4 million primarily in the Michichi area, including the drill, completion, equip and tie-in of the two wells described above, converting a producing well to an injection well to expand our waterflood in the area and incurred costs related to facility upgrades. Additionally, we spent $0.2 million on the reactivation of the Loyalist field, which was shut-in in 2020 due to weak commodity prices. Production in the Loyalist area is expected to resume in the second quarter of 2022.
Increased production: Production was on budget for the quarter and averaged 4,175 boe/d (65% liquids), which was 3% or 104 boe/d higher than Q1 2021, due primarily to production additions from the successful 2021 five well (5.0 net) Princess drilling program, partially offset by natural declines. Due to the on production timing of the Q1 2022 drills, the incremental production had a limited impact for the quarter of approximately 755 boe/d, but is expected to have a greater impact on the production of future quarters in 2022.
Record operating netback4: Operating netback for Q1 2022 was $15.7 million ($41.84/boe) before the impact of derivatives, a record high since PPR became a publicly listed company in 2016. Operating netback before realized losses on derivatives increased by $25.67/boe or 159% relative Q1 2021 driven by significant commodity price recoveries. Q1 2022 operating netback after realized losses on derivatives was $10.2 million ($27.06/boe), an increase of $13.83/boe or 105% from Q1 2021.
Adjusted funds flow ("AFF")4: AFF for Q1 2022 totaled $6.9 million ($0.05 per basic and diluted share), excluding $2.1 million of decommissioning settlements, reflecting a 230% improvement from the same quarter of 2021 primarily due to increased operating netbacks.
Decreased net loss: Net loss totaled $1.9 million in Q1 2022, a $9.6 million improvement compared to Q1 2021. The decrease was primarily driven by a $15.0 million non-cash impairment reversal recognized in Q1 2022, partially offset by an increase in unrealized losses on derivative instruments of $5.8 million. The $4.8 million increase in AFF excluding decommissioning settlements was largely offset by a $3.4 million increase in loss on warrant liability.
Net debt4: Net debt at March 31, 2022, totaled $128.1 million, an increase of $3.8 million from December 31, 2021 as the Company sought to take advantage of high commodity prices through execution of its capital program and to meet its environmental stewardship goals through meaningful reductions in its decommissioning obligations. As such, the increase was attributed to aggregate capital expenditures, lease payments, decommissioning settlements and restructuring costs in that exceeded AFF4 in the quarter, as well as the recognition of $0.5 million of deferred interest on long-term debt, partially offset by a $1.1 million unrealized foreign exchange gain on our US dollar denominated debt.
Liquidity: At March 31, 2022, PPR had US$49.3 million of borrowings drawn against its US$53.8 million revolving facility ("Revolving Facility"), leaving the Company with US$4.5 million (CAN$5.66 million equivalent (December 31, 2021 — US$6.4 million)) borrowing capacity under the Revolving Facility. In addition, US$48.8 million (CAN$61.06 million) of senior subordinated notes were outstanding at March 31, 2022, for total borrowings of US$98.1 million (CAN$125.76 million equivalent).
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1 Average initial production over a 30-day period commencing March 3, 2022, during which the well produced an average of 126 bbl/d of light & medium crude oil and 113 Mcf/d of conventional natural gas and 2 bbl/d of natural gas liquids from the Banff 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.
2 Average initial production over a 30-day period commencing March 4, 2022, during which the well produced an average of 82 bbl/d of light & medium crude oil, 176 Mcf/d of conventional natural gas and 4 bbl/d of natural gas liquids from the Banff 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 Comprised of average production of approximately 310 bbl/d of light & medium crude oil and 650 Mcf/d of conventional natural gas.
4 Non-GAAP financial measure – see below under “Non-GAAP and Other Financial Measures”.
5 Comprised of average production of approximately 61 bbl/d of light & medium crude oil, 78 Mcf/d of conventional natural gas and 2 bbl/d of natural gas liquids.
6 Converted using the month end exchange rate of $1.00 USD to $1.2496 CAD as at March 31, 2022 and $1.00 USD to $1.2678 CAD as at December 31, 2021.
FINANCIAL AND OPERATING SUMMARY
Three Months Ended | ||||
($000s except per unit amounts) | 2022 | 2021 | ||
Production Volumes | ||||
Light & medium crude oil (bbl/d) | 1,809 | 2,453 | ||
Heavy crude oil (bbl/d) | 791 | 117 | ||
Conventional natural gas (Mcf/d) | 8,763 | 8,233 | ||
Natural gas liquids (bbls/d) | 115 | 129 | ||
Total (boe/d) | 4,175 | 4,071 | ||
% Liquids | 65 | % | 66 | % |
Average Realized Prices | ||||
Light & medium crude oil ($/bbl) | 116.73 | 60.34 | ||
Heavy crude oil ($/bbl) | 80.33 | 51.76 | ||
Conventional natural gas ($/Mcf) | 4.83 | 3.48 | ||
Natural gas liquids ($/bbl) | 81.06 | 44.79 | ||
Total ($/boe) | 78.17 | 46.31 | ||
Operating Netback ($/boe)1 | ||||
Realized price | 78.17 | 46.31 | ||
Royalties | (9.52 | ) | (3.34 | ) |
Operating costs | (26.81 | ) | (26.80 | ) |
Operating netback | 41.84 | 16.17 | ||
Realized gains (losses) on derivative instruments | (14.78 | ) | (2.94 | ) |
Operating netback, after realized gains (losses) on derivative instruments | 27.06 | 13.23 | ||
1 Operating netback is a non-IFRS measure (see “Non-IFRS Measures” below).
Capital Structure | As at | As at | ||
Working capital (deficit)1 | (2,437 | ) | (367 | ) |
Borrowings outstanding (principal plus deferred interest) | (125,685 | ) | (123,972 | ) |
Total net debt2 | (128,122 | ) | (124,339 | ) |
Debt capacity3 | 5,621 | 4,498 | ||
Common shares outstanding (in thousands) | 128,882 | 128,725 |
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 of USD$53.8 million at March 31, 2022 and USD$53.8 million at December 31, 2021, converted at an exchange rate of $1.0000 USD to $1.2496 CAD on March 31, 2022 and $1.0000 USD to $1.2678 CAD on December 31, 2021.
Three Months Ended | ||||
Drilling Activity | 2022 | 2021 | ||
Gross wells | 2.0 | 2.0 | ||
Net (working interest) wells | 2.0 | 2.0 | ||
Success rate, net wells (%) | 100 | % | 100 | % |
OPERATIONAL UPDATE
The two Michichi Banff wells have stabilized at approximately 210 boe/d each, comprised of 155 bbls of oil and 325 mcf of gas per day. As a result of improvements in drilling and completions the wells are performing well above type curve, currently producing 50 - 75% above expectations with low early declines and original reservoir pressure. The 102/01-04-032-17W4M well was converted to injection to support the waterflood expansion in section 04-032-17W4M. The improved production performance and original reservoir pressure result confirms the proof of concept of Banff development in Michichi targeting undrained reserves in the Lower Banff. This new development modelling will improve Banff recovery in the Michichi field, unlocking additional value for shareholders from the large original oil in place.
NON-CORE DISPOSITION UPDATE
Bids were received for several packages in the non-core disposition package that was marketed in the first quarter. We are reviewing bids and will provide a further update when we have evaluated the optimum disposition outcomes.
OUTLOOK
During the first quarter of 2022 PPR spent $9.7 million of the previously announced full year $22 million capital program, including asset retirement obligation spending. PPR is very encouraged by the initial flow rates of the recently drilled Michichi Banff wells and has identified several reactivation and recompletion opportunities within it’s suspended well inventory. The second half capital program is currently under evaluation as we prioritize remaining investment opportunities and PPR will provide further clarity on the second half program in the coming weeks. We intend to work to maintain the budgeted outcomes from the allocated capital, however the key elements of the remaining program will be optimized to maximize value for PPR shareholders.
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 Berthelet
President and Chief Executive Officer
Tel: (403) 292-8125
Email: tberthelet@ppr.ca
Jason Dranchuk
Vice President, Finance and Chief Financial Officer
Tel: (403) 292-8150
Email: jdranchuk@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: estimated on production timing of the Loyalist reactivation; higher expected production for the remainder of 2022; and the expectation the new development model in Michichi will improve Banff recovery and unlock additional value.
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-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) | March 31, | December 31, | ||
Current assets | 22,444 | 19,603 | ||
Less: current derivative instrument assets | — | — | ||
Current assets excluding current derivatives instruments | 22,444 | 19,603 | ||
Less: Accounts payable and accrued liabilities | 24,881 | 19,970 | ||
Working capital | (2,437 | ) | (367 | ) |
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) | March 31, | December 31, | ||
Working capital (deficit) | (2,437 | ) | (367 | ) |
Borrowings outstanding (principal plus deferred interest) | (125,685 | ) | (123,972 | ) |
Total net debt | (128,122 | ) | (124,339 | ) |
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 | |||||
($000s) | 2022 | 2021 | |||
Oil and natural gas revenue | 29,372 | 16,967 | |||
Royalties | (3,577 | ) | (1,225 | ) | |
Operating expenses | (10,075 | ) | (9,819 | ) | |
Operating netback | 15,720 | 5,923 | |||
Realized (losses) gains on derivatives | (5,552 | ) | (1,076 | ) | |
Operating netback, after realized (losses) gains on | 10,168 | 4,847 | |||
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 | |||||
($000s) | 2022 | 2021 | |||
Cash flow from operating activities | 2,469 | 4,617 | |||
Changes in non-cash working capital | 1,122 | (2,604 | ) | ||
Other | (35 | ) | (34 | ) | |
Transaction, restructuring and other costs | 1,259 | 0 | |||
Adjusted funds flow ("AFF") | 4,815 | 1,979 | |||
Decommissioning settlements | 2,124 | 125 | |||
AFF - excluding decommissioning settlements | 6,939 | 2,104 | |||
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 | |||||
($000s) | 2022 | 2021 | |||
Exploration and evaluation expenditures | 128 | 321 | |||
Property and equipment expenditures | 7,328 | 4,205 | |||
Capitalized stock-based compensation | 3 | 8 | |||
Asset disposition (net of acquisition) | (20 | ) | (102 | ) | |
Net capital expenditures | 7,439 | 4,432 | |||
