CALGARY, Alberta – 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|
|($000s except per unit amounts)||June 30,
|Light & medium crude oil (bbl/d)||2,514||2,996||2,453||2,483||3,080|
|Heavy crude oil (bbl/d)||179||183||117||149||238|
|Conventional natural gas (Mcf/d)||9,122||9,351||8,233||8,680||9,768|
|Natural gas liquids (bbl/d)||140||141||129||135||134|
|Average Realized Prices|
|Light & medium crude oil ($/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 ($/bbl)||50.55||15.35||44.79||47.64||21.12|
|Operating Netback ($/boe)1|
|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).|
|June 30, 2021||December 31, 2020|
|Borrowings outstanding (principal plus deferred interest)||(118.7||)||(121.3||)|
|Total net debt2||(116.8||)||(115.9||)|
|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
|Six Months Ended
|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.
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.