Calgary, Alberta – OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to report operating and financial results for the third quarter of 2022.
|Three months ended
|Nine months ended
|(millions, except per share amounts)|
|Cash flow from operating activities||121.4||65.5||330.3||136.1|
|Basic per share ($/share)2||1.48||0.88||4.03||1.83|
|Diluted per share ($/share)2||1.44||0.85||3.92||1.78|
|Funds flow from operations3||104.6||59.3||340.2||137.9|
|Basic per share ($/share)4||1.27||0.79||4.16||1.86|
|Diluted per share ($/share)4||1.24||0.77||4.04||1.81|
|Adjusted Funds flow from operations3||107.4||61.7||365.5||151.6|
|Basic per share ($/share)4||1.31||0.82||4.46||2.04|
|Diluted per share ($/share)4||1.27||0.80||4.34||1.99|
|Basic per share ($/share)||0.50||0.62||2.18||5.28|
|Diluted per share ($/share)||0.48||0.60||2.12||5.14|
|Light oil (bbl/d)||11,062||10,314||11,480||10,389|
|Heavy oil (bbl/d)||5,854||2,688||5,940||2,712|
|Natural gas (mmcf/d)||64||54||63||53|
|Total production5 (boe/d)||29,985||24,164||30,324||24,017|
|Average sales price 2,6|
|Light oil ($/bbl)||118.66||84.27||125.99||76.35|
|Heavy oil ($/bbl)||81.78||60.87||91.19||49.94|
|Natural gas ($/mcf)||5.31||3.89||5.90||3.44|
|Risk management loss||(0.59||)||(0.93||)||(3.92||)||(1.27||)|
|Net sales price||75.99||55.28||79.72||48.84|
|Net operating costs4||(14.57||)||(13.28||)||(14.17||)||(13.50||)|
(1) We adhere to generally accepted accounting principles (“GAAP“); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including funds flow from operations, adjusted funds flow from operations, net debt, netback and net operating costs. Additionally, other financial measures are also used to analyze performance. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS“) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities, as indicators of our performance.
(2) Supplementary financial measure. See “Non-GAAP and Other Financial Measures“.
(3) Non-GAAP financial measure. See “Non-GAAP and Other Financial Measures“.
(4) Non-GAAP financial ratio. See “Non-GAAP and Other Financial Measures“.
(5) Please refer to the “Oil and Gas Information Advisory” section below for information regarding the term “boe”.
(6) Before risk management gains/(losses).
Detailed information can be found in Obsidian Energy’s unaudited consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the three and nine months ended September 30, 2022, on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.
KEY THIRD QUARTER 2022 RESULTS
With active drilling and completions in all the Company’s core areas, third quarter production increased 24 percent to 29,985 boe/d over 2021, and further grew to over 33,000 boe/d currently with the addition of seven new wells (6.8 net) on production in the fourth quarter. Higher production and commodity prices in the third quarter resulted in a 76 percent increase in funds flow from operations (“FFO“) from the third quarter of 2021 and generated positive free cash flow of $27.1 million. During the third quarter and into the fourth quarter, we achieved strong production results from our ongoing development program, reduced our net debt, successfully acquired additional land for prospective Bluesky, Clearwater and Cardium opportunities, purchased a key gas plant in Peace River to secure future offtake capacity and commenced exploration drilling in our highly prospective Clearwater play.
2022 Third Quarter Financial Highlights
- Strong Funds Flow – FFO increased 76 percent to $104.6 million ($1.27 per basic share) for the quarter compared to $59.3 million ($0.79 per basic share) in the third quarter of 2021, largely due to the higher commodity price environment and increased production levels.
- Capital Development Growth – The Company began second half development activities in all areas during the third quarter, resulting in capital expenditures of $74.0 million (2021 – $45.1 million) and decommissioning expenditures of $3.5 million (2021 – $1.6 million).
- Continued Debt Reduction – Strong free cash flow generation and our continued focus on reducing debt resulted in a decrease in net debt by 25 percent to $323.1 million at September 30, 2022, from $428.1 million at September 30, 2021. We completed our refinancing that incorporated both senior and subordinated debt during the quarter, resulting in a more favourable debt structure for the Company (see ‘Debt Refinancing‘).
- Net Operating Costs – Net operating costs of $14.57 per boe in the third quarter of 2022 were higher than in 2021 or the second quarter of 2022, largely from higher power and fuel costs due to rate increases, particularly in August and September.
- G&A Costs – General and administrative (“G&A“) costs were lower at $1.73 per boe in the third quarter of 2022 compared to $1.82 per boe for the same period in 2021.
- Net Income – Continued strong commodity prices contributed to net income of $40.7 million ($0.50 per basic share) for the third quarter of 2022 compared to net income of $46.6 million ($0.62 per basic share) in the comparable period of 2021. In the third quarter of 2021, net income was aided by an impairment reversal of $26.5 million in our Peace River area, which was mainly due to our acquisition of the remaining 45 percent ownership in the Peace River Oil Partnership.
2022 Third Quarter Operational Highlights
- Production Levels – Average production was 29,985 boe/d, a 24 percent increase from 24,164 boe/d in the third quarter of 2021.
- Second Half Development Program – Although development activities were delayed due to wet weather conditions in July, the Company successfully drilled 13 wells (12.8 net) with 11 wells (11.0 net) completed and brought on stream, including eight Viking wells (8.0 net) drilled in our first half development program.
- Peace River Acquisition – We purchased the Seal 9-15 gas plant within our core Peace River asset during the quarter. This acquisition contributes to our dominant infrastructure position in the area (70 percent of the total area gas processing capacity), providing capacity for future development and expected strong future cash flow through third-party processing fees.
- Turnaround and Facility Expansion – In September, we completed a major turnaround at our Pembina Lodgepole gas plant and oil battery. In parallel, we executed a low-cost expansion project that increased the facility’s capacity by 40 percent (30 percent net), which immediately brought an additional 600 boe/d net production online and created capacity for planned development activity.
- Continued Focus on Decommissioning Liabilities Reduction – With continued decommissioning work, we are on track to meeting our goal of abandoning over 270 net wells and over 500 kilometres of pipelines (net) in 2022.
2022 Highlights Subsequent to the Quarter
- Acquired Additional Peace River Land – In October 2022, we purchased an additional 10 sections (approximately 6,400 acres) of prospective Clearwater and Bluesky rights from the Alberta land sale in the Peace River region for a consideration of $4.0 million, further expanding our ownership in the area.
2022 DEVELOPMENT PROGRAM UPDATE
The largest development program that the Company has undertaken in several years, our second half 2022 program is well underway in all our core areas with 13 wells (12.8 net) rig-released in the third quarter: five Cardium wells (4.8 net) in Pembina and Willesden Green, six Bluesky wells (6.0 net) in Peace River, one Mannville gas well (1.0 net) in Willesden Green, and one vertical Devonian well (1.0 net). Of those wells, six wells (6.0 net) are on production in Peace River along with eight Viking wells (8.0 net) that were rig-released in the second quarter of 2022.
Another six wells (6.0 net) were rig-released and nine wells (8.8 net) brought on production in October, resulting in strong initial production (“IP“) rates in the Peace River and Willesden Green areas. With a second rig now drilling in the Peace River area, we are focused on completing the drilling of the remainder of the 35 well (33.9 net) second half program by year-end. In total, we expect 65 wells (63.4 net) will be rig-released in 2022, of which 52 wells (50.7 net) are expected to be on production by the end of the year.
In the third quarter, we rig-released six Bluesky wells (6.0 net) from our second half 2022 program, with an additional two Bluesky wells (2.0 net) rig-released in October. Three wells (3.0 net) were on production in the third quarter; the remaining five wells (5.0) are expected to come on production throughout the fourth quarter. Results are in line with expectations with six of the recent wells drilled on production at ~800 boe/d (98 percent heavy oil) in total. Some of these wells are producing through rate limited temporary production facilities to accelerate clean-up times; production rates will continue to strengthen as the wells transition to higher oil rates. In addition, we began drilling the first well (1.0 net) of the remaining five Bluesky wells (5.0 net) to be drilled in the fourth quarter.
While testing an edge location of a producing pool, we encountered reservoir stability issues resulting in low productivity on a single two-well pad drilled late in the first half of 2022, which is reflected in our updated production guidance (see ‘Updated 2022 Guidance’). The information gathered during the drilling of this pad has been incorporated into our mapping and future inventory locations.
In late October 2022, we furthered the delineation and exploration of our land base with the spud of the first of two wells (2.0 net) targeting the Clearwater play; our second well is expected to spud in December. As part of our larger exploration process, these wells will provide key information towards an extensive 2023 Clearwater exploration program. Both wells will be evaluated and tested in late 2022 and early 2023, respectively. In parallel with the Bluesky, our Clearwater acreage offers significant exploration and development upside with identified drilling opportunities, and represents a compelling risked value opportunity.
During the third quarter, we purchased the Seal 9-15 gas plant in Peace River, contributing to our dominant infrastructure position in the area (approximately 70 percent of the total area gas processing capacity) while providing expected strong future cash flow through third-party processing fees. The Seal gas plant has approximately 10 mmcf/d of capacity and is currently operating at about 65 percent capacity. Obsidian Energy currently delivers less than 1 mmcf/d of gas to the facility, leaving ample room for our near term and future development programs. Ownership of this plant combined with our existing infrastructure solidifies Obsidian Energy’s unique position compared to peers in this increasingly competitive development area. The acquisition supports our long-term Environmental, Social and Governance strategy of minimizing flaring and emissions, and aides in meeting provincial gas conservation regulations unique to this area. The Company currently conserves over 95 percent of gas in the Peace River area.
In October 2022, we increased our substantial land position in the Peace River area with the purchase of 10 sections (approximately 6,400 acres) of prospective Bluesky and Clearwater rights at the Alberta land sale for a consideration of approximately $4.0 million. The Company has identified 51 potential Bluesky locations and 32 potential Clearwater opportunities on this newly acquired acreage through technical evaluation of the parcels. In total, we have acquired 33.5 sections for a total consideration of $17.9 million in 2022. This brings our total land ownership to 497 sections of heavy oil rights in Peace River. Through the 2022 land sales acquisitions, Obsidian Energy estimates that it has added a total of 79 potential Bluesky locations and 46 potential Clearwater opportunities.
Willesden Green continues to provide high quality economic development across multiple formations for the Company. During the third quarter, Obsidian Energy drilled four wells (4.0 net) targeting the Cardium formation and one liquids-rich Mannville well (1.0 net). Currently, four wells (4.0 net) are on production, providing excellent rates and robust economic returns. The two wells at the Crimson 3-03 Pad are meeting expectations and capital efficiencies for top tier Cardium development with average IP 30-day rates of 597 boe/d (69 percent oil) per well. The third well on the 4-17 Pad surpassed internal expectations with peak daily production rates of 698 boe/d (84 percent oil). The Mannville gas well is still in early production with a peak daily rate of 1,158 boe/d (16 percent oil). We expect to complete the drilling of three additional wells in our Willesden Green area during the remainder of 2022.
The two Cardium wells (1.8 net) on the 16-09 Pad were drilled and rig released during the third quarter. Online in early October, total pad production is currently approximately 560 boe/d (72 percent oil) as the wells continue to clean up and improve. In addition, one exploration vertical Devonian well (1.0 net) was drilled and is currently under evaluation during the quarter. Drilling of the final well on the three-well 14-6 Pad in South Lodgepole is being completed, and we expect to finish drilling three additional Cardium wells (2.7 net) and one vertical Devonian well (0.5 net) by year-end.
All eight (8.0 net) wells from our first half Viking program are on production, adding a peak total rate of over 1,000 boe/d to the Esther field. As part of this program the Company drilled a step-out well to test the western extent of the play, which displayed peak and last 60-day production rates of 242 boe/d (88 percent oil) and 211 boe/d (86 percent oil), respectively, and exhibits minimal decline. As one of the most prolific Viking wells drilled in the area, it provides an outstanding economic return and effectively delineates the area, opening multiple additional development locations on our extensive land position.
On July 27, 2022, we completed a private placement issuance of senior unsecured notes and entered into new syndicated credit facilities providing a more favourable debt structure with long-term debt capital and credit facilities to meet our ongoing operational liquidity needs. The refinancing was composed as follows:
- Senior Unsecured Notes: We issued five-year senior unsecured notes (the “Notes“) in the amount of $127.6 million (the “Offering“) at a rate of 11.95 percent due on July 27, 2027.
- New Credit Facilities: The Company entered into new syndicated credit facilities with borrowing capacity of $205.0 million (the “New Credit Facilities“), consisting of $175.0 million revolving syndicated credit facilities (the “New Syndicated Facilities“) and a $30.0 million non-revolving term loan (the “New Term Loan“). The New Term Loan was fully repaid in September 2022 from free cash flow from our operations.
- Debt Repayment: Upon completion of the Offering, we repaid all our previous senior secured notes due November 30, 2022, the outstanding balances under our previous credit facilities due November 30, 2022, and the PROP limited recourse loan due on December 31, 2022. In addition, the Company also closed out hedges that were put in place for the PROP 45 limited recourse financing (US$3.4 million loss) and paid fees associated with the refinancing ($6.5 million).
2022 UPDATED GUIDANCE
Our 2022 guidance has been updated to capture our latest production estimates that incorporate several strategic and investment decisions. A prolonged break-up period due to excessively wet ground conditions delayed the start of our second half development operations in Central Alberta. The Company chose to focus on capital efficiency rather than incur significant additional costs to enforce a premature start. Our updated guidance incorporates this modified second half development program, including on-stream production delays, recent strong well results, lower than expected results on one Peace River pad from the first half of 2022 (see “Peace River’) and our 2022 development program adjustment to 65 wells (63.4 net) from a total of 68 wells (65.0 net) for the year.
Production guidance has been lowered by approximately three percent to 31,000 boe per day (at the midpoint), representing a 26 percent increase over 2021, with associated adjustments to net operating costs and general and administrative expenses on a per boe basis. Operating cost guidance reflects the impact of higher than anticipated third quarter electrical power rates and additional inflationary pressures. Our capital expenditures guidance has been increased to account for: incremental success in land sale activity in our Clearwater, Bluesky and Cardium plays; acquisition of the Seal 9-15 gas plant; accelerated exploration investment in our Clearwater holdings; higher working interest in certain operated projects; incremental non-operated activity; and inflationary pressures. Regarding 2023, the Company is currently reviewing our program and, once the 2023 capital budget has been approved (which is expected to occur in mid-December) detailed guidance will be provided, which will supersede our previously disclosed preliminary 2023 forecast. With the release of our 2023 guidance, we also expect to announce our intentions regarding our shareholder return of capital plans. Our updated 2022 guidance is presented below.
|Production1||boe/d||31,500 – 32,500||30,800 – 31,200|
|% Oil and NGLs||66%||65%|
|Capital expenditures||$ millions||295 – 305||320 – 330|
|Decommissioning Expenditures2||$ millions||17||18|
|Net operating costs||$/boe||12.70 – 13.50||13.50 – 14.00|
|General & administrative||$/boe||1.45 – 1.55||1.55 – 1.65|
|Based on midpoint of above guidance|
|WTI Range3||US$/bbl||90.00 – 120.00||85.00 – 95.00|
|AECO Range3||CAD$/GJ||5.50 – 7.50||5.80|
|FFO||$ millions||455 – 580||441 – 456|
|Adjusted FFO4||$ millions||499 – 624||487 – 502|
|Free cash flow4||$ millions||137 – 262||98 – 113|
|Net debt5||$ millions||257 – 132||335 – 320|
|Net debt to FFO4,5||times||0.6x – 0.2x||0.8x – 0.7x|
1) Mid-point of 2022E updated guidance range: 11,715 bbl/d light oil, 6,065 bbl/d heavy oil, 2,475 bbl/d NGLs and 64.5 mmcf/d natural gas. Mid-point of 2022E previous guidance of 12,350 bbl/d light oil, 6,325 bbl/d heavy oil, 2,525 bbl/d NGLs and 64.6 mmcf/d natural gas. Average production volumes in 2022 do not include any forecasted production associated with Clearwater exploratory capital expenditures.
2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the Alberta Site Rehabilitation Program (“ASRP“).
3) 2022E updated guidance pricing assumptions are for November to December. Mid-point pricing assumptions for our 2022E updated guidance include WTI at US$90.00/bbl and AECO at $5.80/GJ from November to December; and for our 2022E previous guidance was WTI at US$105.00/bbl and AECO at $6.50/GJ from July to December.
4) Pricing assumptions for our 2022E updated guidance outlined are forecasted for November and December 2022 and includes risk management (hedging) adjustments as of November 4, 2022. Guidance FFO and free cash flow (“FCF“) includes approximately $46 million of estimated charges for 2022 related to the deferred share units, performance share units and non-treasury incentive plan awards share-based compensation amounts which are based on a share price of $15.00 per share. The charge is primarily due to the Company’s increased share price in 2022 compared to the closing price on December 31, 2021, of $5.21 per share. Adjusted FFO excludes the estimated non-cash share-based compensation amounts for 2022.
5) Net debt figures estimated as at December 31, 2022.
The Company continues to focus our hedging program on near term WTI positions to protect cashflow given our first half capital program. As at November 7, 2022, the following financial oil and gas contracts are in place on a weighted average basis:
WTI Oil Contracts
|Swap Price (C$/bbl)|
|WTI Collar||October 2022||10,000||109.75||130.07||–|
|WTI Swap||November 2022||1,950||123.97|
|WTI Collar||November 2022||7,000||106.07||126.77||–|
|WTI Collar||December 2022||2,000||105.00||130.20||–|
AECO Natural Gas Contracts
|AECO Swap||October 2022||26,065||4.74|
|AECO Swap||April 2023 – October 2023||17,487||4.01|
UPDATED CORPORATE PRESENTATION
For further information on these and other matters, Obsidian Energy will post an updated corporate presentation later today on our website, www.obsidianenergy.com.
ADDITIONAL READER ADVISORIES
OIL AND GAS INFORMATION ADVISORY
Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 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 conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.
TEST RESULTS AND INITIAL PRODUCTION RATES
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.
NON-GAAP AND OTHER FINANCIAL MEASURES
Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance. The Company’s unaudited consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the three and nine months ended September 30, 2022 are available on the Company’s website at www.obsidianenergy.com and under our SEDAR profile at www.sedar.com. The disclosure under the section “Non-GAAP and Other Financial Measures” in the MD&A is incorporated by reference into this news release.
Non-GAAP Financial Measures
The following measures are non-GAAP financial measures: FFO; adjusted FFO; net debt; net operating costs; netback; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
For a reconciliation of FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of adjusted FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of net debt to long-term debt, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of net operating costs to operating costs, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of netback to sales price, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of FCF to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
The following measures are non-GAAP ratios: funds flow from operations (basic per share ($/share) and diluted per share ($/share)), which use funds flow from operations as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and general and administrative costs ($/boe). See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures.
Non-GAAP Measures Reconciliations
2022 and 2021 Cash Flow from Operating Activities, Funds Flow from Operations and Free Cash Flow
|Three months ended
|Nine months ended
|(millions, except per share amounts)||2022||2021||2022||2021|
|Cash flow from operating activities||$||121.4||$||65.5||$||330.3||$||136.1|
|Change in non-cash working capital||(21.9||)||(9.1||)||(13.9||)||(1.1||)|
|Onerous office lease settlements||2.3||2.3||6.9||7.0|
|Deferred financing costs||(0.7||)||(1.7||)||(2.1||)||(4.4||)|
|Financing fees paid||–||–||–||4.4|
|Restructuring charges (1)||–||0.1||2.5||(1.8||)|
|Other expenses (1)||–||0.6||0.6||(7.7||)|
|Funds flow from operations||104.6||59.3||340.2||137.9|
|Share based compensation (2)||2.8||2.4||25.3||13.7|
|Adjusted Funds flow from operations||107.4||61.7||365.5||151.6|
|Share based compensation (2)||(2.8||)||(2.4||)||(25.3||)||(13.7||)|
|Free Cash Flow||$||27.1||$||12.6||$||106.7||$||36.4|
(1) Excludes the non-cash portion of restructuring and other expenses.
(2) Includes expenses associated with our cash settled share-based incentive plans, being the Deferred Share Unit Plan, Performance Share Unit Plan and the Non-Treasury Incentive Award Plan.
2022 and 2021 Netback to Sales Price
|Three Months Ended||Nine Months Ended|
|September 30||September 30|
|Risk management loss||(0.59||)||(0.93||)||(3.92||)||(1.27||)|
|Net sales price||75.99||55.28||79.72||48.84|
|Net operating costs||(14.57||)||(13.28||)||(14.17||)||(13.50||)|
2022 and 2021 Net Operating Costs to Operating Costs
|Three Months Ended||Nine Months Ended|
|September 30||September 30|
|Less processing fees||(1.6||)||(1.6||)||(5.5||)||(4.9||)|
|Less road use recoveries||(1.8||)||(1.2||)||(4.9||)||(3.7||)|
|Net operating costs||$||40.1||$||29.5||$||117.3||$||88.5|
2022 and 2021 Net Debt to Long-Term Debt
|(millions)||September 30, 2022||December 31, 2021|
|Syndicated credit facility||$||134.0||$||321.5|
|Senior unsecured notes||127.6||–|
|Senior secured notes||–||54.9|
|PROP Limited recourse loan||–||16.0|
|Unamortized discount of senior unsecured notes||(2.4||)||–|
|Deferred financing costs||(5.5||)||(2.7||)|
|Working capital deficiency|
|Prepaid expenses and other||(14.7||)||(9.1||)|
|Accounts payable and accrued liabilities||163.7||107.8|
|bbl||barrel or barrels||mcf||thousand cubic feet|
|bbl/d||barrels per day||mmcf||million cubic feet|
|boe||barrel of oil equivalent||mmcf/d||million cubic feet per day|
|boe/d||barrels of oil equivalent per day||AECO||Alberta benchmark price for natural gas|
|MSW||Mixed Sweet Blend||NGL||natural gas liquids|
|WTI||West Texas Intermediate|
FUTURE-ORIENTED FINANCIAL INFORMATION
This release contains future-oriented financial information (“FOFI“) and financial outlook information relating to the Company’s prospective results of operations, operating costs, expenditures, production, FFO, adjusted FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under “Forward-Looking Statements“. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company’s business as of the date hereof and such information may not be appropriate for other purposes.