Obsidian Energy Announces Third Quarter 2023 Results
- Increased average production by 10 percent over the third quarter of 2022 due to the strong performance of our development program
- Generated funds flow from operations of $98.9 million during the quarter, resulting in free cash flow of $47.7 million and net debt reduction to $294.3 million
- Commenced second half 2023 development program while completing major facility debottlenecking project subsequent to the quarter
- Continued return of capital to shareholders via the repurchase of ~4.4 percent of our outstanding shares through our buyback program in 2023
Calgary, Alberta–(Newsfile Corp. – November 9, 2023) – OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to report solid operating and financial results for the third quarter of 2023.
|Three months ended
|Nine months ended
|(millions, except per share amounts)|
|Cash flow from operating activities||95.3||121.4||235.0||330.3|
|Basic per share ($/share)2||1.18||1.48||2.89||4.03|
|Diluted per share ($/share)2||1.15||1.44||2.82||3.92|
|Funds flow from operations3||98.9||104.6||280.6||340.2|
|Basic per share ($/share)4||1.22||1.27||3.45||4.16|
|Diluted per share ($/share)4||1.19||1.24||3.37||4.04|
|Basic per share ($/share)||0.31||0.50||0.91||2.18|
|Diluted per share ($/share)||0.30||0.48||0.89||2.12|
|Light oil (bbl/d)||12,452||11,062||12,590||11,480|
|Heavy oil (bbl/d)||6,260||5,854||5,952||5,940|
|Natural gas (mmcf/d)||69||64||67||63|
|Total production5 (boe/d)||32,937||29,985||32,376||30,324|
|Average sales price2,6|
|Light oil ($/bbl)||109.56||118.66||102.67||125.99|
|Heavy oil ($/bbl)||80.14||81.78||62.44||91.19|
|Natural gas ($/mcf)||2.65||5.31||3.09||5.90|
|Risk management gain (loss)||0.96||(0.59||)||1.25||(3.92||)|
|Net sales price||67.25||75.99||63.38||79.72|
|Net operating costs3||(13.60||)||(14.57||)||(14.40||)||(14.17||)|
(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 (“FFO”), 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 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 realized risk management gains/(losses).
Detailed information can be found in Obsidian Energy’s unaudited interim consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the three and nine-month periods ended September 30, 2023 on our website at www.obsidianenergy.com, which will also be filed on SEDAR+ and EDGAR in due course.
KEY THIRD QUARTER 2023 RESULTS
During the third quarter of 2023, we announced our three-year growth plan to increase our production to 50,000 boe/d in 2026, which is anchored by expanded development of our Peace River asset. In conjunction with this announcement, we also increased our 2023 capital program by $40 million due to higher WTI prices, resulting in additional development in our Viking and Pembina assets over the balance of this year. Our team was active across our core areas over the quarter with our second half development program commencing in late July, and work proceeding on our debottlenecking project and facility maintenance turnarounds. Third quarter production increased 10 percent to 32,937 boe/d over the same period in 2022 due to the strong performance of our first half 2023 development program.
Compared to the third quarter of 2022, lower commodity prices and the increase in stock-based compensation (non-cash, and driven by a 44 percent gain in our share price during the quarter) offset higher production, resulting in a five percent decrease in FFO from the 2022 period. Netbacks decreased slightly as lower commodity prices were partially offset by a corresponding decrease in royalties as well as lower net operating costs and realized hedging gains. During the quarter, the Company reduced our net debt, and repurchased and cancelled additional shares through our share buyback program.
2023 Third Quarter Financial Highlights
Solid Funds Flow – FFO was $98.9 million ($1.22 per basic share) in the third quarter of 2023 compared to $104.6 million ($1.27 per basic share) for the same period in 2022. Lower commodity prices primarily drove the decrease, partially offset by higher production, realized hedging gains (including $5.0 million on natural gas hedges), improvements in heavy oil differentials and lower royalty and net operating costs in 2023.
The Company’s significant share price increase during the quarter ($11.18 per share on September 30, 2023, compared to $7.75 on June 30, 2023) impacted FFO, resulting in a higher share-based compensation expense of $13.1 million during the period. None of the share-based awards vested during the third quarter of 2023, so did not impact available cash.
Additional Debt Reduction – Strong free cash flow (“FCF“) generation resulted in a decrease in net debt to $294.3 million at September 30, 2023, from $323.1 million at September 30, 2022.
Continued Share Buyback Program – In the third quarter of 2023, a total of approximately 1.6 million shares were repurchased and cancelled under the Company’s normal course issuer bid (“NCIB“) for $14.4 million ($9.17 per share). In total, we repurchased and cancelled 3.6 million shares as at November 8, 2023, for approximately $32.9 million ($9.13 per share) for the year.
Repurchased Senior Unsecured Notes – During the third quarter of 2023, the Company completed our semi-annual repurchase offer of senior unsecured notes (“Notes“) for $5.0 million at a mandated price of $1,030 per $1,000 principal amount. In addition, Obsidian Energy repurchased for cancellation an additional $0.7 million of Notes on the open market during the third quarter at an average price of $993 per $1,000 principal amount.
Subsequent to September 30, 2023, a further $1.0 million of Notes were repurchased on the open market at an average price of $1,005 per $1,000, resulting in $117.4 million of Notes currently outstanding.
Reduced Net Operating Costs – Net operating costs were lower at $13.60/boe in the third quarter of 2023 compared to $14.57/boe in the third quarter of 2022 due to the Company’s higher production base and lower power prices in 2023.
Lower G&A Costs – General and administrative (“G&A“) costs were $1.51/boe in the third quarter of 2023 compared to $1.73/boe in the third quarter of 2022; the decrease in 2023 is primarily attributable to our higher production base.
Positive Net Income – Positive operational results contributed to net income of $24.8 million ($0.31 per basic share) for the third quarter of 2023 compared to net income of $40.7 million ($0.50 per basic share) in the comparable period of 2022.
2023 Third Quarter Operational Highlights
Increased Production Levels – Average production was 32,937 boe/d, a 10 percent increase from 29,985 boe/d in the third quarter of 2022 due to the strong performance of our development program with 35 (34.6 net) wells brought on production during the first nine months of 2023.
Commenced Second Half Program – Our third quarter capital program largely focused on development activities with the construction of new pads and the start of new drilling with seven (6.7 net) wells rig released and two (2.0 net) wells placed on production. Capital expenditures were $45.9 million (2022 – $74.0 million) with decommissioning expenditures of $5.3 million (2022 – $3.5 million); our second half capital program spend is planned to be higher in the fourth quarter of 2023.
- Completed Turnaround and Facility Maintenance – We completed major turnarounds at our Peace River Seal 9-15 and Pembina 9-17 gas plants to ensure optimal operations. Also in the quarter, we completed maintenance and infrastructure projects across our properties, including a 37-kilometre road upgrade in Peace River at the Dawson area, providing all season access for new exploration/appraisal activity.
2023 Highlights Subsequent to the Quarter
- Completed Willesden Green Facility Debottlenecking Project – In late October, we successfully completed a major facility debottlenecking project at Willesden Green. The project expanded field compression, which lowers field pressures and allows for future development in this area and is expected to bring an additional ~1,000 boe/d of net initial production online once volumes stabilize.
THREE-YEAR GROWTH PLAN
In September, we announced our three-year corporate plan (2024 – 2026), focused primarily on growth from the Peace River asset. Our strategy for the three-year corporate growth plan is to maintain production levels in our Willesden Green and Pembina (Cardium), and Viking light oil business, and use the significant FCF from these assets to fund growth in our heavy oil business at Peace River. While our plan anticipates continued development in both the Bluesky and Clearwater formations, the largest growth is expected from Bluesky production given the significant inventory adjacent to existing fields and our new Walrus development area.
Key highlights of the three-year growth plan include:
Annualized production growth rate of 16 percent – We expect our production to grow steadily over the three-year period, reaching 50,000 boe/d in 2026, while maintaining 25 percent flat annual corporate decline rate. Our light oil production will remain stable at approximately 26,000 boe/d while the Peace River asset grows substantially from 6,600 boe/d to 24,000 boe/d.
Significant inventory remains for growth post 2026 – In total, our plan anticipates drilling 346 (318.3 net) development and appraisal/exploration wells over the three-years:
Peace River: 199 (199 net) wells of the 869 un-risked locations as at year-end 2023; and
Light oil business: 147 (119.3 net) wells in our light oil business (Willesden Green/Pembina and Viking, including non-operated wells), leaving 43 percent of the proved plus probable locations remaining from the total identified in our year-end 2022 reserve report (post 2023 drilling locations).
Increased FFO – With year-over-year production growth and an increasing liquids weighting, we expect our FFO to grow from $440 million in 2024 to $655 million in 2026 at US$75.00/bbl WTI, representing $8.19 per share in 2026 (based on our issued and outstanding share amount of 80.0 million as at August 31, 2023).
Higher FCF generation – Our three-year growth plan calls for capital expenditures of $380 million, $445 million and $420 million in 2024, 2025 and 2026, respectively, which is expected to generate FCF of $53 million, $36 million and $213 million in each year.
Substantial flexibility and optionality – With full ownership of our Peace River land, we control the pace of development and can quickly respond to changes in commodity prices.
2023 SECOND HALF DEVELOPMENT PROGRAM
With an expanded second half 2023 capital program, Obsidian Energy’s drilling preparation and execution began in July and continued through the third quarter, accelerating in October with four rigs in operation across our Peace River, Willesden Green, Pembina and Viking areas. We are pleased with the start of our second half development program with seven (6.7 net) wells drilled and two (2.0 net) wells placed on production during the third quarter. In addition, Obsidian Energy participated in six non-operated development wells (2.7 net) in the Pembina area during the quarter, one of which was a water injector well.
Most of our second half development drilling results are expected in the fourth quarter and early 2024. The third quarter focused on construction of new pads, spudding new wells, completing planned facility turnaround maintenance and progressing the Willesden Green facility debottleneck project.
As WTI prices continued to strengthen during the third quarter, as previously announced, we elected to increase our 2023 capital expenditures by approximately $40 million and add 12 (12.0 net) wells (Viking – eight (8.0 net) wells; Pembina – four (4.0 net) wells) to our program with production expected in early 2024. The following operated wells are expected to be rig released during the year:
|H1 Gross (Net)
|H2 Gross (Net)
|Total Gross (Net)
|Heavy Oil Assets|
|Peace River (Bluesky)||6 (6.0)1||6 (6.0)||12 (12.0)|
|Peace River (Clearwater)||1 (1.0)||3 (3.0)||4 (4.0)|
|Light Oil Assets|
|Willesden Green (Cardium)||5 (5.0)||8 (7.7)||13 (12.7)|
|Pembina (Cardium / Devonian)||2 (1.8)||6 (6.0)||8 (7.8)|
|Viking||11 (11.0)||8 (8.0)||19 (19.0)|
|25 (24.8)||31 (30.7)||56 (55.5)2|
|Peace River (OSE)||4 (4.0)||–||4 (4.0)|
|TOTAL OPERATED WELLS||29 (28.8)||31 (30.7)||60 (59.5)2,3|
(1) Two of the six wells are exploration/appraisal wells to further delineate the Bluesky play.
(2) 36 (35.5 net) wells rig released in 2023 are expected to be brought on production by the end of 2023 with the remaining 18 (18.0 net) wells expected to be on production in early 2024.
(3) In addition, Obsidian Energy is planning to participate in a total of 20 non-operated (7.2 net) wells in 2023, three of which are water injection wells.
With rigs active in all areas, we are focused on completing the drilling of the remainder of the 31 well (30.7 net) second half program by year-end. In total, we expect 60 operated wells (59.5 net) will be rig-released in 2023 (including the four oilsands exploration (“OSE“) wells), of which 36 wells (35.5 net) are expected to be on production by the end of the year and the remaining 18 (18.0 net) wells on production in the first quarter of 2024.
The third quarter of 2023 was extremely busy for the Peace River team as we analyzed the results from our first half exploration/appraisal drilling program and finalized our three-year growth plan, which is largely focused on development in the Bluesky and Clearwater formations in Peace River. At the same time, the Company focused on planned facility turnaround maintenance, continued construction of pads and road infrastructure, and began second half Bluesky development drilling.
In the third quarter, we completed a major turnaround at our Peace River Seal 9-15 gas plant to enable continued optimized operations. A key asset within our advantaged infrastructure position, the plant has approximately 10 mmcf/d of capacity with ample room for our future growth in the area. Also in the quarter, we completed maintenance and infrastructure projects across our properties, including a recently acquired 37-kilometre road upgrade in Peace River at the Dawson area, providing all season access for new exploration/appraisal activity.
We are encouraged with the initial results of our second half development program at Peace River, which follow up on previous success in Harmon Valley South (“HVS“), Cadotte and our new development area at Walrus. In the third quarter of 2023, we began drilling six (6.0 net) wells targeting the Bluesky formation in our second half 2023 development program with five (5.0 net) wells rig released during the period. Two (2.0 net) wells were drilled from existing pads at the HVS 4-32 Pad and Cadotte 2-05 Pad; both wells were completed and on production in August with the following initial results:
- 4-32 Pad – One (1.0 net) well is on production with an average 30-day initial production (“IP“) rate of 239 boe/d (99 percent oil) and peak rate of 419 boe/d (100 percent oil).
- 2-05 Pad – One (1.0 net) well is on production at an average 30-day IP rate of 366 boe/d (100 percent oil), and peak rate of 461 boe/d (100 percent oil).
After establishing Walrus as a new development area in the first half of 2023, we drilled four (4.0 net) wells in the field over the quarter with all wells rig released by mid-October. Following up on the success of the Walrus 13-19 Pad well that achieved peak production rate of 303 bbl/d (100 percent oil), initial results are encouraging with all wells drilled quickly in in the high-quality targeted Bluesky zone. One (1.0 net) well at the Walrus 13-19 Pad is also testing a lower Bluesky zone, which could add significant future well inventory and further expand this play. These four (4.0 net) wells are expected to come on production by the end of November 2023 through permanent production facilities.
The core data analyzed from the OSE wells in the first half of the year helped to further delineate our land position in Peace River, providing detailed subsurface data for both Bluesky and Clearwater formations. In parallel with the Bluesky, our Clearwater acreage offers a compelling opportunity for significant exploration and development upside with identified drilling opportunities.
Acting on the solid data and results from the first half OSE wells, we drilled and rig released the first of three (3.0 net) exploration/appraisal wells targeting the Clearwater formation in the Dawson area. The 7-13 Pad well (1.0 net) is expected to be on production in November, while the two (2.0 net) wells at the 13-23 Pad will commence drilling in November.
During the third quarter, Obsidian Energy drilled three (3.0 net) wells targeting the Cardium formation and placed one (0.7 net) well on production. The well at the Open Creek 9-17 Pad surpassed internal expectations, despite being wellsite facility constrained, with strong initial peak rates and an average IP 30-day rate of 491 boe/d (86 percent oil). Given the strong performance of this well we will be returning the eastern part of our Willesden Green asset in early 2024 with several follow up locations. We expect to complete the drilling of an additional five (5.0 net) wells in our Willesden Green area during the remainder of 2023 with most of the production coming on stream in early 2024.
We continued our work on the major debottlenecking project in the East Crimson part of our Willesden Green area to both lower field pressures and expand facility capacity during the quarter. The project was completed in late October and is estimated to bring on an additional ~1,000 boe/d net production once volumes stabilize. In addition to increasing base production, the facility will allow for higher onstream rates at lower wellhead pressures for new wells, increase recoveries and reserves from existing wells, expand capacity and provide opportunities to accelerate new development locations.
We completed several planned turnaround maintenance projects in the Pembina area during the third quarter, including our Pembina 9-17 gas plant, methane emission reduction work and pipeline expansions, which will aid future operations and development. At the same time, we completed construction to begin drilling at the Paddy North 10-28 Pad in October. The two (2.0 net) wells were rig released in late October and early November and are expected to be onstream in December. Added to the second half 2023 development program in September, the four-well 7-36 Pad was constructed in the quarter with drilling commencing at the first (1.0 net) well in November. The remaining three (3.0 net) wells will be completed and rig released prior to year-end; production from all four wells is expected to be onstream in early 2024.
Following up on the success of our first half drilling on the western side of the play, we added an eight (8.0 net) well second half development program at Viking. During the third quarter, Obsidian Energy began construction of the 2-22 Pad with drilling commencing in October. In total, four wells were rig released in October with the rest expected to be released in November. Production additions from the program is anticipated to come onstream in January 2024, providing additional cash flow from this shallow, low-risk, highly economic resource play.
UPDATED 2023 GUIDANCE
With both our recent strong well performance and financial results, we have further revised our 2023 guidance from the update announced in September with an increase in the bottom end of our production range to 32,000, which has increased the midpoint of our 2023 production. In addition, accounting for the non-cash impact of higher third quarter 2023 share-based compensation expense due to our higher share price and share repurchases, our FFO, FCF and net debt have also been revised slightly as applicable, while maintaining our WTI forecast of US$85/bbl for the balance of 2023. Our formal 2024 guidance is expected to be provided in mid-January 2024.
|September 2023E Guidance||Revised 2023E Guidance|
|Production1||boe/d||31,750 – 32,500||32,000 – 32,500|
|% oil and NGLs||%||66%||66%|
|Capital expenditures2||$ millions||300||300|
|Decommissioning expenditures||$ millions||26 – 28||26 – 28|
|Net operating costs||$/boe||14.25 – 14.75||14.25 – 14.75|
|General & administrative||$/boe||1.60 – 1.70||1.60 – 1.70|
|Based on midpoint of above guidance|
|FFO per share (basic) 4||$/share||~4.90||~4.80|
|Net debt5||$ millions||~290||~310|
|Net debt to FFO5||Times||0.7||0.8|
(1) Approximate mid-point of September 2023E guidance range: 12,700 bbl/d light oil, 5,800 bbl/d heavy oil, 2,600 bbl/d NGLs and 66.2 mmcf/d natural gas with a minimal amount of forecasted production associated with exploratory capital expenditures. Approximate mid-point of Revised 2023E guidance range: 12,500 bbl/d light oil, 6,000 bbl/d heavy oil, 2,600 bbl/d NGLs and 66.9 mmcf/d natural gas with a minimal amount of forecasted production associated with exploratory capital expenditures.
(2) Capital expenditures include approximately $25 million for exploration/appraisal well activity with minimal impact on forecasted production volumes.
(3) Pricing assumptions of September 2023E guidance were forecasted for October 1, 2023, to December 31, 2023. Full year pricing assumptions, including actuals realized at that time, resulting in WTI US$79.18/bbl, AECO $2.66/mcf, WCS differentials of US$16.87/bbl and FX of 1.34x CAD/USD.
Pricing assumptions of Revised 2023 guidance are forecasted for November 1, 2023, to December 31, 2023. Full year pricing assumptions, including actuals realized thus far, result in WTI US$79.34/bbl, AECO $2.78/mcf, WCS differentials of US$17.15/bbl and FX of 1.35x CAD/USD.
(4) September 2023E guidance FFO and FCF included risk management (hedging) adjustments up to September 18, 2023, and includes approximately $5 million of estimated charges for full year 2023 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts, which are based on a share price of $10.00 per share. FFO per share was based on a total estimated average of 81.2 million shares outstanding for 2023.
Revised 2023E guidance FFO and FCF include risk management (hedging) adjustments up to October 31, 2023, and includes approximately $17 million of estimated charges for full year 2023 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on a share price of $12.00 per share. FFO per share was based on a total estimated average of 81.0 million shares outstanding for 2023.
(5) September 2023E guidance net debt figures estimated as at December 31, 2023, and included the impact of approximately $21.2 million of share purchases under the NCIB to August 31, 2023. Revised 2023E guidance net debt figures estimated as at December 31, 2023, and includes the impact of approximately $33.0 million of share purchases under the NCIB to November 8, 2023. Due to changes in the timing of our capital program, our expected working capital deficiency at December 31, 2023, increased by $20 million in our Revised 2023E guidance.
|Guidance Sensitivity Table1|
|Range||Change in 2023 FFO ($ millions)|
|WTI (US$/bbl)||+/- $1.00/bbl||~1.4|
|MSW light oil differential (US$/bbl)||+/- $1.00/bbl||~0.8|
|WCS heavy oil differential (US$/bbl)||+/- $1.00/bbl||~0.4|
|Change in AECO ($/GJ)||+/- $0.25/GJ||~0.5|
(1) Includes risk management (hedging) adjustments up to October 31, 2023.
We have added to our WTI hedge positions through a combination of WTI near months swaps and collars as well as to our power hedge position. For the first nine months of 2023, Obsidian Energy realized $12.8 million in positive hedge gains with natural gas and a loss of $1.8 million with oil. Currently, the following contracts are in place on a weighted average basis:
|WTI Swap||October 2023||1,781 bbl/d||US$87.96|
|WTI Swap||November 2023||1,083 bbl/d||US$80.77|
|Oil Collars||October 2023||8,500 bbl/d||$115.70 – $124.05|
|Oil Collars||November 2023||3,917 bbl/d||$112.24 – $117.74|
|WCS Differential||October – December 2023||1,500 bbl/d||($21.20)|
AECO Natural Gas Contracts
|AECO Swap||October 2023||49,929||75%||3.48|
|AECO Swap||November 2023 – March 2024||26,588||41%||3.47|
(1) Percentage calculated based on annual expected pre-royalty natural gas production of 66.9 mmcf/d (midpoint of Revised 2023E guidance).
|Power Swap||January – December 2024||144 MWh/d||$92.83|
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.
This news release discloses drilling locations or inventory in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the reserves report prepared by GLJ Ltd. effective as of December 31, 2022, and dated January 20, 2023 (the “Reserves Report“) and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked drilling locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources.
Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.
The Company has an aggregate of 284 (233 net) booked proved locations and 372 (311 net) booked probable locations as set forth in the Reserves Report.
Of the 869 (869 net) un-risked locations in Peace River as at year-end 2023 based on our current internal estimates, 8 (8 net) are proved locations, 9 (9 net) are probable locations, and 852 (852 net) are unbooked locations.
Of the 670 (670 net) un-risked locations in Peace River that we anticipate remaining at the end of 2026, 0 (0 net) are proved locations, 0 (0 net) are probable locations, and 670 (670 net) are unbooked locations.
Of the 199 (199 net) development and appraisal/exploration locations we plan to drill in Peace River over the course of our three-year plan, 8 (8 net) are proved locations, 9 (9 net) are probable locations, and 182 (182 net) are unbooked locations.
Of the 147 (119.3 net) development locations we plan to drill in Willesden Green/Pembina and Viking) over the course of our three-year plan, 103 (80.9 net) are proved locations, 15 (11.2 net) are probable locations, and 29 (27.2 net) are unbooked locations (based on the Reserves Report).
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 MD&A as at and for the three and nine months ended September 30, 2023 are available on the Company’s website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca and EDGAR profile at www.sec.gov. 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; 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, 2023, 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 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: FFO (basic per share ($/share) and diluted per share ($/share)), which use FFO as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component; and net debt to FFO, which uses net debt and FFO as components. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2023, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and G&A costs ($/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, 2023, for an explanation of the composition of these measures.
Non-GAAP Measures Reconciliations
Cash Flow from Operating Activities, FFO and FCF
|Three months ended
|Nine months ended
|Cash flow from operating activities||$||95.3||$||121.4||$||235.0||$||330.3|
|Change in non-cash working capital||(3.6||)||(21.9||)||16.7||(13.9||)|
|Onerous office lease settlements||2.2||2.3||6.7||6.9|
|Settlement of restricted share units||0.1||–||4.7||–|
|Deferred financing costs||(0.6||)||(0.7||)||(1.7||)||(2.1||)|
|Funds flow from operations||98.9||104.6||280.6||340.2|
|Free Cash Flow||$||47.7||$||27.1||$||69.2||$||106.7|
(1) Excludes the non-cash portion of restructuring and other expenses.
Netback to Sales Price
|Three months ended
|Nine months ended
|Risk management gain (loss)||2.9||(1.6||)||11.0||(32.4||)|
|Net sales price||203.8||209.5||560.2||660.0|
|Net operating costs||(41.2||)||(40.1||)||(127.2||)||(117.3||)|
Net Operating Costs to Operating Costs
|Three months ended
|Nine months ended
|Less processing fees||(3.4||)||(1.6||)||(10.7||)||(5.5||)|
|Less road use recoveries||(2.1||)||(1.8||)||(5.2||)||(4.9||)|
|Net operating costs||$||41.2||$||40.1||$||127.2||$||117.3|
Net Debt to Long-Term Debt
|Syndicated credit facility||$||118.0||$||134.0|
|Senior unsecured notes||118.4||127.6|
|Unamortized discount of senior unsecured notes||(1.8||)||(2.4||)|
|Deferred financing costs||(3.9||)||(5.5||)|
|Working capital deficiency|
|Prepaid expenses and other||(16.3||)||(14.7||)|
|Accounts payable and accrued liabilities||163.5||163.7|
|API||American Petroleum Institute||mcf||thousand cubic feet|
|bbl||barrel or barrels||mcf/d||Thousand cubic feet per day|
|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||bcf||billion cubic feet|
|mmbbls||million barrels||NGL||natural gas liquids|
|mmboe||million barrels of oil equivalent||GJ||gigajoule|
|MSW||Mixed Sweet Blend||AECO||Alberta benchmark price for natural gas|
|WTI||West Texas Intermediate|
|WCS||Western Canadian Select|
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, 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.
Without limitation of the foregoing, this news release contains information regarding our growth plans through 2026, including estimates of our 2023 to 2026 capital expenditures, production levels, FFO, FFO per share, FCF, FCF per share, net operating costs, net debt and net debt to FFO ratio, which are based on various factors and assumptions that are subject to change including regarding production levels, commodity prices, operating and other costs and capital expenditure levels, and in the case of the years other than 2023, such estimates are provided for illustration purposes only and are based on budgets and plans that have not been finalized and are subject to a variety of contingencies including prior years’ results. To the extent that such estimates constitute FOFI or a financial outlook, they were approved by management of the Company on November 8, 2023, and are included to provide readers with an understanding of the Company’s anticipated plans and financial results based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.
Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements“) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: that we will file the unaudited interim consolidated financial statements and MD&A on our website, SEDAR+ and EDGAR in due course; our expectations for our three-year growth plan including but not limited to production, development, inventory and locations, growth and decline rates, liquids weighting, FFO, FCF, capital expenditures and optionality as prices change; expectations in connection with the debottlenecking project; expected timing for drilling, rig releases, on-production dates; our expectations in connection with our Bluesky and Clearwater acreage; our expectations for development program completion and future development; our pricing assumptions; our updated guidance for production, production percentages, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FCF, net debt and net debt to FFO; our guidance sensitivities; our expected release timing for 2024 guidance; our hedges; and our expectations for an updated corporate presentation.
With respect to forward-looking statements and FOFI contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements and FOFI contained herein do not assume the completion of any transaction); that regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; that the Company’s operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to any resurgence of the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; Obsidian Energy’s views with respect to its financial condition and prospects, the stability of general economic and market conditions, currency exchange rates and interest rates, the availability of cash or other financing sources to fund for repurchases of common shares under the NCIB and our ability to comply with applicable terms and conditions under the Company’s debt agreements, the existence of alternative uses for Obsidian Energy’s cash resources and compliance with applicable laws and regulations (including Canadian and U.S. securities laws and Canadian corporate law) pertaining to the NCIB; our ability to execute our plans as described herein and in our other disclosure documents, including our three-year growth plan, and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future net operating costs and G&A costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; and our ability to add production and reserves through our development and exploitation activities.
Although the Company believes that the expectations reflected in the forward-looking statements and FOFI contained in this document, and the assumptions on which such forward-looking statements and FOFI are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements and FOFI included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements and FOFI involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements and FOFI contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements and FOFI. These risks and uncertainties include, among other things: our inability to repurchase common shares under the NCIB in the amounts permitted or at all due to a lack of financial resources, the inability to comply with our debt agreements, legal restrictions on share repurchases, competing demands for our financial resources, or other factors; the anticipated benefits of repurchasing our shares under the NCIB do not materialize; Obsidian Energy’s future capital requirements; general economic and market conditions; demand for Obsidian Energy’s products; and unforeseen legal or regulatory developments and other risk factors detailed from time to time in Obsidian Energy reports filed with the Canadian securities regulatory authorities and the United States Securities and Exchange Commission; the possibility that we change our 2023 budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full (including our recent announced three-year growth plan), and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, and the responses of governments and the public to any pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company’s contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our senior unsecured notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities and senior unsecured notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior unsecured notes; the possibility that we are unable to complete the Offer with our noteholders; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine and/or hostilities in the Middle East; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company’s ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to public opinion and/or special interest groups. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company’s Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) which may be accessed through the SEDAR+ website (www.sedarplus.ca), EDGAR website (www.sec.gov) or Obsidian Energy’s website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
Unless otherwise specified, the forward-looking statements and FOFI contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements and FOFI contained in this document are expressly qualified by this cautionary statement.
Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol “OBE”.
All figures are in Canadian dollars unless otherwise stated.
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