- Strong performance and production increases from all development areas resulted in 33,153 boe/d average production for the quarter
- Funds flow from operations was $94.3 million in the quarter (20 percent increase from the first quarter of 2022)
- Peace River development and exploration program extends Walrus Bluesky play and further delineates acreage for both Bluesky and Clearwater formations
- Settled $9.8 million of equity award plans in cash as opposed to issuing more shares, given the significant discount of our share price to our intrinsic value
Calgary, Alberta–(Newsfile Corp. – May 4, 2023) – Obsidian Energy Ltd.( TSX: OBE) (NYSE American: OBE) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to report strong operating and financial results for the first quarter of 2023.
|Three months ended
|(millions, except per share amounts)|
|Cash flow from operating activities||72.6||83.9|
|Basic per share ($/share)2||0.89||1.03|
|Diluted per share ($/share)2||0.87||1.00|
|Funds flow from operations3||94.3||78.6|
|Basic per share ($/share)4||1.15||0.97|
|Diluted per share ($/share)4||1.12||0.94|
|Basic per share ($/share)||0.37||0.29|
|Diluted per share ($/share)||0.36||0.28|
|Light oil (bbl/d)||12,809||11,114|
|Heavy oil (bbl/d)||6,241||5,789|
|Natural gas (mmcf/d)||69||60|
|Total production5 (boe/d)||33,153||29,407|
|Average sales price2,6|
|Light oil ($/bbl)||101.51||117.91|
|Heavy oil ($/bbl)||44.98||84.77|
|Natural gas ($/mcf)||4.06||4.96|
|Risk management gain (loss)||0.88||(6.58||)|
|Net sales price||61.77||70.49|
|Net operating costs4||(14.57||)||(13.93||)|
(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-month period ended March 31, 2023 on our website at www.obsidianenergy.com, which will also be filed on SEDAR and EDGAR in due course.
The majority of our first half 2023 development program was completed across our Peace River, Willesden Green, Pembina and Viking assets in the first quarter, with the remaining activity to be finished in May. First quarter 2023 production increased to 33,153 boe/d – a 13 percent increase over the 29,407 boe/d in the first quarter of 2022 which contributed to increased FFO and net income from the first quarter of 2022.
2023 First Quarter Financial Highlights
- Strong Funds Flow – FFO increased to $94.3 million ($1.15 per basic share) for the first quarter of 2023 compared to $78.6 million ($0.97 per basic share) for the same period in 2022. Increased production combined with realized hedging gains primarily drove the increase over 2022.
- Capital Development Growth – The Company’s first half development program was active with the majority of spending incurring in the first quarter, which resulted in 29 (28.8 net) operated wells drilled (including four oilsands exploration wells). Total first quarter capital expenditures were $107.1 million (2022 – $103.4 million) and decommissioning expenditures were $8.7 million (2022 – $8.5 million).
- Stable G&A Costs – General and administrative (“G&A“) costs were $1.60 per boe in the first quarter of 2023 compared to $1.57 per boe in the first quarter of 2022 due to the Company’s focus on managing our cost structure.
- Managed Net Operating Costs – Net operating costs were higher at $14.57 per boe in the first quarter of 2023 compared to $13.93 per boe in the first quarter of 2022. The increase in net operating costs is mainly due to higher power costs and usage with an increased production base and general inflationary pressures experienced across the industry.
- Higher Net Income – Higher production and solid netbacks contributed to $30.5 million ($0.37 per basic share) of net income for the first quarter of 2023 compared to $23.8 million in the same period in 2022 ($0.29 per basic share). The increase was partially offset by lower commodity prices and a non-cash deferred income tax expense related to the deferred income tax asset recognized in 2022 in conjunction with our significant tax pool position.
- Continued Liquidity and Debt Focus – The amount available under our syndicated credit facility increased to $200.0 million from $175.0 million, with an extension of the revolving period to May 31, 2024, and the term-out date to May 31, 2025, through the early completion of our semi-annual borrowing base redetermination. With capital expenditures from our first half drilling program heavily weighted to the first quarter of 2023, net debt increased to $351.4 million at March 31, 2023, compared to $316.8 million at December 31, 2022, but decreased from $448.8 million at March 31, 2022.
- Approval of Normal Course Issuer Bid to Facilitate Share Buyback – The Board of Directors authorized a normal course issuer bid (“NCIB“) to provide a return of capital to shareholders, which was approved by the Toronto Stock Exchange (“TSX“) and allows the Company to buy back up to 10 percent of our “public float”, as defined by the TSX, up to February 27, 2024. Purchases under the NCIB will be subject to maintaining $65 million of liquidity and complying with the terms of our current credit facilities. The Company is currently in active discussions with several parties to further enhance our liquidity position to afford more flexibility on a return of capital strategy.
- Settlement of Equity-Linked Award Plans in Cash to Avoid Dilution – As we believe the intrinsic value of our shares far exceeds our current trading price, we elected to pay out performance share units and restricted share units that vested in the first quarter in cash ($9.8 million) rather than our usual practice of issuing shares at the current market price.
2023 First Quarter Operational Highlights
- Achieved Robust Development Well Results – Our active first quarter 2023 capital development continued the momentum from our 2022 program, resulting in drilling results with strong initial production (“IP“) rates. With five rigs deployed across the Peace River, Willesden Green, Pembina and Viking areas, 25 (24.8 net) development and exploration/appraisal wells were rig released in the first quarter and 21 (20.6 net) wells are now on production; additionally, we drilled four (4.0 net) oilsands exploration (“OSE“) wells in Peace River.
- Established New Walrus Development Area in Peace River – Results of our two (2.0 net) Bluesky 2023 exploration/appraisal wells initially produced an average of over 500 boe per day on a combined basis and further delineated our Peace River acreage while opening a new development area at the Walrus field.
- Peace River Potential – Initial results from the drilling and analysis of the well cores gathered from our four (4.0 net) OSE wells in the first quarter provided encouraging results. Placed strategically across our land base, they help to further delineate our extensive land position in Peace River by providing detailed subsurface data for both Bluesky and Clearwater formations.
- Expanded Western Side of Viking Play – Following up on the success of the 2022 step-out well on the western side of the play, we drilled and completed 11 (11.0 net) wells in our first half 2023 program by the end of April. The initial three (3.0 net) wells were brought on production in the first quarter with the first two (2.0 net) wells showing a strong average 30-day IP rate of 212 boe/d (87 percent light oil).
2023 DEVELOPMENT PROGRAM
We are pleased with the results of both our development and exploration/appraisal programs, providing solid production increases across our Peace River, Willesden Green, Pembina, and Viking areas. We further developed our Viking area following the successful step-out well in 2022, established a new development area at Walrus in Peace River, and further delineated our extensive land position in Peace River for both the Bluesky and Clearwater formations. During the first quarter, 25 (24.8 net) operated producing wells and four (4.0 net) operated OSE wells were rig released. We currently have 21 (20.6 net) wells on production of which 11 (10.7 net) wells were spud in 2022 and tied into permanent facilities in 2023. The table below provides our well drilling and on production breakdown by area.
|Operated Wells||Wells Rig Released1||Wells On Production|
|Willesden Green (Cardium)||5 (5.0||)||6 (6.0||)|
|Pembina (Cardium / Devonian)||2 (1.8||)||4 (3.6||)|
|Peace River (Bluesky)||4 (4.0||)||5 (5.0||)|
|Viking||11 (11.0||)||3 (3.0||)|
|Total Development||22 (21.8||)||18 (17.6||)|
|Peace River (Bluesky)||2 (2.0||)||2 (2.0||)|
|Peace River (Clearwater)||1 (1.0||)||1 (1.0||)|
|OSE (Peace River)||4 (4.0||)||N/A|
|Total Exploration/Appraisal||7 (7.0||)||3 (3.0||)|
|TOTAL||29 (28.8||)||21 (20.6||)|
(1) Rig released well totals do not include 11 wells (10.7 net) rig released in 2022 and put on production in 2023, or the eight (2.4 net) non-operated development wells participated in during the first quarter, one of which was a water injection well.
(2) 37 (35.2 net) wells rig released in 2023 are expected to be brought on production by the end of 2023 with nine in early 2024. In total, 45 (43.0 net) wells will be brought on production in 2023.
In addition, Obsidian Energy participated in eight non-operated development wells (2.4 net) during the quarter, one of which was a water injection well.
Our focus at Peace River is on realizing the potential across our acreage from both a development and exploration/appraisal basis. As a result of our team’s work, our first quarter program provided strong production additions while opening the Walrus field for substantial future development and increases to future locations and reserves. We further delineated our extensive land position for both Bluesky and Clearwater formations through the drilling and analysis of our four OSE wells. In 2023, we will continue with our strategy to both develop and appraise future development opportunities in Peace River, and will outline a multi-year development and appraisal plan for the Bluesky and Clearwater formations in the third quarter of this year.
The first half 2023 Bluesky development program provided solid results with five (5.0 net) wells on production in the first quarter.
- 06-04 Pad – Two (2.0 net) wells spud in 2022 were placed on production in February with an average 30-day IP rate of 133 boe/d (100 percent heavy oil) per well.
- 02-05 Pad – Two (2.0 net) wells on the three-well pad were completed and are producing to permanent facilities with an average 30-day IP rate of 265 boe/d (100 percent oil) per well. In addition, one (1.0 net) well that was previously producing into temporary facilities at a 30-day IP rate of 134 boe/d (100 percent oil) is now tied into permanent facilities.
- 14-05 Pad – One (1.0 net) well is on production and cleaning up after remedial completion work.
Recognizing the strong results from the three wells drilled at the Harmon Valley South (“HVS“) 6-31 Pad in early 2022, the Company added a second well to the offsetting 4-32 Pad in our first half Bluesky program. Both wells on the 4-32 Pad are on production and in the process of cleaning up.
Located to the east of our successful HVS development field, the potential of our Walrus acreage was largely unexplored until the first quarter of 2023. The results of our two (2.0 net) 2023 exploration/appraisal wells at the Walrus 16-20 Pad (in the north) and the Walrus 13-19 Pad (in the south) exceeded production expectations, providing key data on the Bluesky formation and effectively delineating the field for future large-scale development. Peak production rates achieved to date were 211 bbl/d (100 percent oil) for the 16-20 Pad well (1.0 net) and 303 bbl/d (100 percent oil) for the 13-19 Pad well (1.0 net). Due to restricted access in the area, typical for this time of year, the 16-20 Pad has been temporarily shut-in until access permits later in 2023.
In the first quarter of 2023, we returned to organic exploration/appraisal work with the completion of our four vertical OSE wells. Placed strategically across our Peace River acreage, the wells further analyze and assess the development potential of our large land base in multiple formations. The information gathered from the cores are encouraging. Along with the results from the Dawson 12-33 Pad well (1.0 net), this data is being used to optimize future well design and placement as we define our second half 2023 program.
Our Cardium play in Willesden Green continued to yield solid drilling results and production additions during the first quarter, providing a strong foundation for the Company. All five (5.0 net) wells drilled in the 2023 first half program were rig released in the quarter and placed on production prior to the end of April.
- 08-09 Crimson Pad – Two (2.0 net) wells showed an average 30-day IP rate of 574 boe/d (73 percent oil) per well.
- 12-26 Crimson Pad – One (1.0 net) well rig released in early January exhibited solid results with a 30-day IP rate of 276 boe/d (62 percent oil).
- 08-36 Crimson Pad – Two (2.0 net) wells drilled in the first quarter were just placed on production and are cleaning up.
We completed our 2023 first half program in Pembina during the quarter, adding production from four (3.6 net) Cardium wells.
- 06-33 PCU#9 – Rig released in December 2022, the two (1.8 net) wells from this pad were placed on production in January 2023 with average 30-day IP rates of 293 boe/d (87percent light oil) per well.
- Lodgepole 03-14 Pad – Two (1.8 net) wells were placed on production with average 30-day IP rates of 183 boe/d (82 percent light oil) per well.
Additionally, Obsidian Energy also participated in the development of the non-operated Pembina Cardium Unit 11 (“PCU#11“), which continues to progress. Seven (3.1 net) wells were drilled since mid-2022, including 2 (0.9 net) injection wells. The three (1.3 net) wells drilled in the second half of 2022 have average 90-day IP rates of 420 boe/d (93 percent liquids) per well. Our partner’s full-year program includes 12 (5.4 net) Cardium wells in PCU#11.
Our 2023 first half program at Viking focuses on extending the play by further developing the potential of the western side of our acreage following the successful 2022 step-out well, recognized as the top 2022 Viking well in the basin on a cumulative and daily average production basis1. During the first quarter, 11 (11.0 net) wells were rig released with the first two wells on production showing 30-day IP rates averaging 212 boe/d (87 percent light oil). The majority of the remaining wells were brought on production in early May.
During the first quarter of 2023, $8.7 million was spent on decommissioning expenses to progress our environmental remediation efforts with a focus on abandoning and reclaiming inactive fields in Northern and Eastern Alberta. Obsidian Energy also completed work in February 2023 related to the Alberta Government’s Alberta Site Rehabilitation Program that ended in 2022. Total support received from the province over the three-year period was $30.2 million (on a gross basis), helping us successfully abandon a combined total of 796 net wells and 1,121 net kilometres of pipeline when combined with our decommissioning expenditures from 2020 to 2022.
RECONFIRMATION OF 2023 GUIDANCE
With our solid first quarter operational and development results, we are reiterating our guidance issued on January 30, 2023. Our first half program provided further information for our Peace River and Viking areas, and we expect to optimize our second half 2023 development plans in the coming months. We expect to generate strong free cash flow in 2023 that will be used to repay debt as well as return capital to shareholders. At the same time, we will remain flexible to commodity prices and will adjust our plans accordingly to maintain the financial strength of the Company. Our full year 2023 guidance is presented below.
|Production1||boe/d||32,000 – 33,500|
|% Oil and NGLs||%||67%|
|Capital expenditures2||$ millions||260 – 270|
|Decommissioning expenditures||$ millions||26 – 28|
|Net operating costs||$/boe||13.50 – 14.40|
|General & administrative||$/boe||1.60 – 1.70|
|Based on midpoint of above guidance|
|Free Cash Flow (prior to NCIB)||$ millions||~105|
|Net debt (prior to NCIB)4||$ millions||~215|
|Net debt to FFO4||times||0.5|
(1) Approximate mid-point of guidance range: 12,700 bbl/d light oil, 6,900 bbl/d heavy oil, 2,500 bbl/d NGLs and 63.9 mmcf/d natural gas. Average production volumes include 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 outlined are forecasted for the full year of 2023 and include risk management (hedging) adjustments as of May 3, 2023. Guidance FFO and free cash flow (“FCF“) includes approximately $6 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 $9.00 per share.
(4) Net debt figures estimated as at December 31, 2023, prior to the impact of any share purchased under the NCIB.
|Guidance Sensitivity Table|
|Variable||Range||Change in 2023 FFO ($ millions)|
|WTI (US$/bbl)||+/- $1.00/bbl||8.6|
|MSW light oil differential (US$/bbl)||+/- $1.00/bbl||5.5|
|WCS heavy oil differential (US$/bbl)||+/- $1.00/bbl||3.1|
|Change in AECO ($/GJ)||+/- $0.25/GJ||3.2|
The Company has primarily focused our hedging program on AECO positions across 2023 and into early 2024 given our concerns on natural gas storage levels. As at May 3, 2023, the following oil and natural gas contracts are in place on a weighted average basis:
|WCS Differential||July 2023 – December 2023||1,000 bbl/d||($21.72)|
|WTI Swap||April 2023||1,900 bbl/d||$111.33|
AECO Natural Gas Contracts
|Percentage Hedged1||Swap Price (C$/mcf)|
|AECO Swap||April 2023 – October 2023||49,203||77%||3.50|
|AECO Swap||November 2023 – March 2024||26,588||42%||3.46|
(1) Percentage calculated based on annual expected pre-royalty natural gas production of 63.9 mmcf/d (midpoint of 2023E guidance).
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 notes and MD&A as at and for the three months ended March 31, 2023 are available on the Company’s website at www.obsidianenergy.com and under our SEDAR profile at www.sedar.com 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 months ended March 31, 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 months ended March 31, 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 ($/boe). See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three months ended March 31, 2023, for an explanation of the composition of these measures.
Non-GAAP Measures Reconciliations
Cash Flow from Operating Activities, FFO and FCF
|Three months ended
|(millions, except per share amounts)||2023||2022|
|Cash flow from operating activities||$||72.6||$||83.9|
|Change in non-cash working capital||6.6||(18.0||)|
|Onerous office lease settlements||2.3||2.3|
|Settlement of restricted share units||4.6||–|
|Deferred financing costs||(0.5||)||(0.7||)|
|Free Cash Flow||$||(21.5||)||$||(33.3||)|
(1) Excludes the non-cash portion of restructuring and other expenses.
Netback to Sales Price
|Three months ended|
|Risk management gain (loss)||2.6||(17.4||)|
|Net sales price||184.3||186.6|
|Net operating costs||(43.5||)||(36.9||)|
Net Operating Costs to Operating Costs
|Three months ended|
|Less processing fees||(3.6||)||(1.9||)|
|Less road use recoveries||(1.9||)||(1.5||)|
|Net operating costs||$||43.5||$||36.9|
Net Debt to Long-Term Debt
|Syndicated credit facility||$||139.0||$||311.8|
|Senior unsecured notes||127.6||–|
|Senior secured notes||–||47.1|
|PROP Limited recourse loan||–||10.5|
|Unamortized discount of senior unsecured notes||(2.2||)||–|
|Deferred financing costs||(5.1||)||(2.0||)|
|Working capital deficiency|
|Prepaid expenses and other||(12.3||)||(10.0||)|
|Accounts payable and accrued liabilities||188.8||189.3|
|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|
|WTI||West Texas Intermediate||AECO||Alberta benchmark price for natural gas|
|WCS||Western Canadian Select|
1 National Bank of Canada Financial Markets, ‘Oil, Gas & Consumable Fuels, North American Drilling Productivity Report’, March 21, 2023.
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