CALGARY, Alberta, Aug. 11, 2021 (GLOBE NEWSWIRE) -- Prairie Provident Resources Inc. ("Prairie Provident", "PPR" or the "Company") today announces our financial and operating results for the three and six months ended June 30, 2021. PPR’s unaudited condensed interim consolidated financial statements for the three and six months ended June 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: “The second quarter results demonstrate the underlying value of the portfolio, with strong well results and improved operating netback. The team continues to make significant progress on our decommissioning program helping to address overall liabilities. We remain excited about the remaining inventory in our portfolio and look to build on recent drilling success in the Princess area in the second half of 2021.”
Q2 2021 HIGHLIGHTS
- Net earnings amidst commodity price recovery: Net earnings totaled $24.0 million for Q2 2021, compared to a net loss of $11.5 million for Q1 2021. The increase in net earnings was primarily driven by a $35.0 million impairment reversal recognized in Q2 2021 related to our Evi and Princess CGUs as a result of significant increases in forecast benchmark commodity prices.
- Improved adjusted funds flow ("AFF")1: AFF for Q2 2021, excluding $0.1 million of decommissioning settlements, was $4.3 million ($0.03 per basic and diluted share), a 103% or $2.2 million increase from Q1 2021 reflecting improved netbacks and higher production. While PPR benefited from the improving commodity price environment, our AFF was impacted by realized losses on required derivative contracts arising from mandatory hedge positions pursuant to credit facility covenants which were entered when pricing environment was volatile. Approximately 50% of our second half 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.
- Production: Production during the quarter averaged 4,354 boe/d (65% liquids) in Q2 2021, a 7% or 283 boe/d increase from Q1 2021, primarily driven by additional production from our 2021 drilling program.
- Higher operating netback1: Operating netback for Q2 2021 was $22.16/boe before realized loss on derivatives, the highest level since 2018. PPR generated cash flow of $8.8 million at the field level, representing a 48% increase from Q1 2021. After realized derivative losses, we recognized $6.5 million ($16.46/boe) of operating netback, reflecting a 35% increase from Q1 2021. Compared to Q1 2021, on a per boe basis, operating netback before and after the realized derivative losses increased by 37% and 24%, respectively, reflecting higher realized prices and lower operating expenses.
- Successful drilling program: During Q2 2021, we incurred $2.1 million of Net Capital Expenditures1. We brought on production our first Ellerslie well in Princess on April 29, 2021 with an IP30(2) rate of approximately 210 boe/d, proving an emerging play. In addition, we successfully, completed, equipped and tied-in a Glauconite well in Princess that commenced production on May 20, 2021 with an IP30(3) rate of approximately 529 boe/d. These two wells are currently producing approximately 460(4) boe/d, and contributed approximately 390(5) boe/d of incremental production for Q2 2021. PPR commenced the drilling of two additional wells in the Princess area in July and August 2021 with expected on-stream timing for both around September 2021.
- Net debt1: Net debt at June 30, 2021 totaled $116.8 million, an increase of $0.8 million from December 31, 2020 primarily due to $0.9 million deferred interest accrued on the Company's subordinated senior notes.
- Maintained liquidity: At June 30, 2021, PPR had US$12.3 million (CAN$15.2(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 April 29, 2021, during which the well produced an average of 129 bbl/d of heavy crude oil and 483 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 May 20, 2021, during which the well produced an average of 221 bbl/d of heavy crude oil and 1,849 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. |
| 4 | Comprised of average production of approximately 250 bbl/d of heavy crude oil and 1,260 Mcf/d of conventional natural gas based on field estimates. |
| 5 | Comprised of average production of approximately 210 bbl/d of heavy crude oil and 1,080 Mcf/d of conventional natural gas. |
| 6 | Converted using the month end exchange rate of $1.00 USD to $1.24 CAD as at June 30, 2021. |
FINANCIAL AND OPERATING SUMMARY
| Three Months Ended | Six months ended | |||||||||
| ($000s except per unit amounts) | June 30, 2021 | June 30, 2020 | March 31, 2021 | June 30, 2021 | June 30, 2020 | |||||
| Production Volumes | ||||||||||
| Light & medium crude oil (bbl/d) | 2,514 | 2,996 | 2,453 | 2,483 | 3,080 | |||||
| Heavy crude oil (bbl/d) | 179 | 183 | 117 | 149 | 238 | |||||
| Conventional natural gas (Mcf/d) | 9,122 | 9,351 | 8,233 | 8,680 | 9,768 | |||||
| Natural gas liquids (bbl/d) | 140 | 141 | 129 | 135 | 134 | |||||
| Total (boe/d) | 4,354 | 4,879 | 4,071 | 4,213 | 5,080 | |||||
| % Liquids | 65% | 68% | 66% | 66% | 68% | |||||
| Average Realized Prices | ||||||||||
| Light & medium crude oil ($/bbl) | 71.00 | 23.05 | 60.34 | 65.78 | 32.42 | |||||
| Heavy crude oil ($/bbl) | 63.72 | 12.55 | 51.76 | 58.70 | 30.58 | |||||
| Conventional natural gas ($/Mcf) | 2.81 | 1.93 | 3.48 | 3.13 | 2.02 | |||||
| Natural gas liquids ($/bbl) | 50.55 | 15.35 | 44.79 | 47.64 | 21.12 | |||||
| Total ($/boe) | 51.13 | 18.77 | 46.31 | 48.82 | 25.53 | |||||
| Operating Netback ($/boe)1 | ||||||||||
| Realized price | 51.13 | 18.77 | 46.31 | 48.82 | 25.53 | |||||
| Royalties | (5.87 | ) | (2.33 | ) | (3.34 | ) | (4.65 | ) | (2.51 | ) |
| Operating costs | (23.10 | ) | (18.09 | ) | (26.80 | ) | (24.88 | ) | (20.35 | ) |
| Operating netback | 22.16 | (1.65 | ) | 16.17 | 19.29 | 2.67 | ||||
| Realized gains (losses) on derivatives | (5.70 | ) | 18.21 | (2.94 | ) | (4.37 | ) | 10.90 | ||
| Operating netback, after realized gains (losses) on derivatives | 16.46 | 16.56 | 13.23 | 14.92 | 13.57 | |||||
| 1 Operating netback is a non-IFRS measure (see “Non-IFRS Measures” below). | ||||||||||
| Capital Structure ($000s) | June 30, 2021 | December 31, 2020 | ||
| Working capital1 | 1.9 | 5.3 | ||
| Borrowings outstanding (principal plus deferred interest) | (118.7 | ) | (121.3 | ) |
| Total net debt2 | (116.8 | ) | (115.9 | ) |
| Debt capacity3 | 15.2 | 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 June 30, 2021 and December 31, 2020, converted at an exchange rate of $1.00 USD to $1.24 CAD on June 30, 2021 and $1.00 USD to $1.27 CAD on December 31, 2020. | ||||
| Three Months Ended June 30, | Six Months Ended June 30, | |||
| Drilling Activity | 2021 | 2020 | 2021 | 2020 |
| Gross wells | 0.0 | 0.0 | 2.0 | 1.0 |
| Net (working interest) wells | N/A | N/A | 2.0 | 1.0 |
| Success rate, net wells (%) | N/A | N/A | 100 % | 100 % |
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.
We have qualified for $6.1 million of government 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 and significant reclamation progress on inactive sites.
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.
OUTLOOK
For the second half of 2021, we expect to focus our drilling efforts in the Princess area, while monitoring our pilot waterflood program at Michichi. Prairie Provident's full-year 2021 guidance estimates remain unchanged from those presented in the Company’s news release dated March 26, 2021. Additional details on Prairie Provident's 2021 capital program and guidance can be found on the Company’s website at www.ppr.ca.
To prioritize balance sheet strength and protect shareholder value, the scale and pace of our capital program is grounded on commodity market fundamentals, instead of short-term commodity price movements. As we gain assurance on global economic recovery and longer term commodity price stability, we will adjust our capital program accordingly. We have capital project inventory ready to execute upon available funding so that we can take advantage of commodity price recovery.
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 grow organically in combination with accretive acquisitions of conventional oil prospects, which can be efficiently developed. Prairie Provident's operations are primarily focused at the Michichi and Princess areas in Southern Alberta targeting the Banff, the Ellerslie and the Lithic Glauconite formations, along with an established and proven waterflood project at our Evi area in the Peace River Arch. Prairie Provident protects our balance sheet through an active hedging program and manages risk by allocating capital to opportunities offering maximum shareholder returns.
For further information, please contact:
Prairie Provident Resources Inc.
Tony Berthelet
President and Chief Executive Officer
Tel: (403) 292-8125
Email: tberthelet@ppr.ca
Mimi Lai
EVP and Chief Financial Officer
Tel: (403) 292-8171
Email: mlai@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 two wells drilled in Princess in the third quarter of 2021; the scale and timing of planned decommissioning activities for 2021, including that most will occur in the second half of 2021 and the expected number of gross wells to be abandoned during 2021; emission reduction initiatives; potential adjustment in our capital program; and continued focus on Princess development while monitoring our pilot waterflood program at Michichi.
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.
