CALGARY, Alberta, Nov. 10, 2021 (GLOBE NEWSWIRE) — Prairie Provident Resources Inc. (“Prairie Provident”, “PPR” or the “Company”) (TSX: PPR) 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.”
- 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.
4 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.
5 Comprised of average production of approximately 232 bbl/d of heavy crude oil and 1,128 Mcf/d of conventional natural gas.
6 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|
|($000s except per unit amounts)||September 30,
|Light & medium crude oil (bbl/d)||2,261||2,730||2,408||2,963|
|Heavy crude oil (bbl/d)||384||200||228||225|
|Conventional natural gas (Mcf/d)||8,986||8,704||8,783||9,411|
|Natural gas liquids (bbl/d)||131||135||133||134|
|Average Realized Prices|
|Light & medium crude oil ($/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 ($/bbl)||59.16||24.96||51.70||22.47|
|Operating Netback ($/boe)1|
|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).
|September 30, 2021||December 31, 2020|
|Borrowings outstanding (principal plus deferred interest)||(120.1||)||(121.3||)|
|Total net debt2||(121.0||)||(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 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
|Nine Months Ended
|Net (working interest) wells||2.0||N/A||4.0||1.0|
|Success rate, net wells (%)||100||%||N/A||100||%||100||%|
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.
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.