Obsidian Energy Announces Fourth Quarter and Full Year 2023 Results

•  Average 2023 production increased five percent over 2022 and 12 percent on a per share basis
•  Generated funds flow from operations of $377.6 million and free cash flow of $58.5 million
•  Repurchased and cancelled six percent of shares outstanding for $47.4 million

Calgary, Alberta--(Newsfile Corp. - February 22, 2024) - 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 fourth quarter and full year 2023.

		Three months ended December 31						Year ended December 31
		2023			2022			2023			2022
FINANCIAL1
(millions, except per share amounts)
Cash flow from operating activities		117.7			126.5			352.7			456.8
Basic per share ($/share)2		1.49			1.54			4.36			5.57
Diluted per share ($/share)2		1.44			1.50			4.19			5.41
Funds flow from operations3		97.0			110.5			377.6			450.7
Basic per share ($/share)4		1.23			1.34			4.67			5.50
Diluted per share ($/share)4		1.18			1.31			4.49			5.34
Net income		34.3			631.7			108.0			810.1
Basic per share ($/share)		0.44			7.69			1.33			9.88
Diluted per share ($/share)		0.42			7.47			1.28			9.60
Capital expenditures		100.0			97.1			292.5			314.8
Decommissioning expenditures		7.7			3.0			26.6			18.8
Long-term debt		220.0			225.3			220.0			225.3
Net debt3		330.2			316.8			330.2			316.8
OPERATIONS
Daily Production
Light oil (bbl/d)		12,176			12,105			12,485			11,636
Heavy oil (bbl/d)		5,851			5,983			5,927			5,950
NGL (bbl/d)		2,614			2,520			2,608			2,434
Natural gas (mmcf/d)		68			67			68			64
Total production5 (boe/d)		31,974			31,742			32,275			30,682
Average sales price2,6
Light oil ($/bbl)		100.38			110.45			102.11			121.92
Heavy oil ($/bbl)		58.53			62.19			61.46			83.84
NGL ($/bbl)		55.65			64.33			53.83			71.02
Natural gas ($/mcf)		2.63			5.66			2.98			5.84

 

Netback ($/boe)
Sales price		59.08			70.87			61.37			80.31
Risk management gain (loss)		2.27			0.18			1.50			(2.85	)
Net sales price		61.35			71.05			62.87			77.46
Royalties		(8.52	)		(11.93	)		(8.30	)		(13.24	)
Net operating costs4		(13.66	)		(14.63	)		(14.21	)		(14.29	)
Transportation		(3.67	)		(3.28	)		(3.48	)		(3.14	)
Netback4 ($/boe)		35.50			41.21			36.88			46.79

 

(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 audited annual consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the year ended December 31, 2023 on our website at www.obsidianenergy.com, which will also be filed on SEDAR+ and EDGAR in due course.

KEY 2023 RESULTS

Obsidian Energy had an active 2023 capital program with both development and exploration/appraisal activities, providing a solid foundation as we enter the first year of our three-year growth plan (the "Growth Plan") to increase production to over 50,000 boe/d in 2026. Activity in our Peace River, Willesden Green/Pembina (Cardium) and Viking areas contributed to a five percent increase in average annual production to 32,275 boe/d, reaching 34,000 boe/d in December 2023. When the impact of our share buyback program initiated in 2023 is included, this translates into 12 percent growth on a production per share basis based on shares outstanding at December 31, 2022, and 2023. In addition, we achieved over 120 percent reserve replacement of 2023 production in all reserve categories.

In 2023, commodity prices decreased over 2022 levels with WTI oil prices averaging US$77.62 per barrel compared to US$94.23 per barrel in 2022, and natural gas prices weakening due to supply growth and increased inventory levels. These lower commodity prices resulted in a 24 percent decline in our realized sales price (19 percent decline net of hedging activity) and drove a decrease to both our FFO and netbacks compared to 2022, which was partially offset by our higher production levels, lower net operating costs and realized hedging gains. Capital expenditures totaled $292.5 million for the year, and we repurchased and cancelled $47.4 million of shares outstanding to return capital to shareholders despite the lower commodity price environment.

2023 Fourth Quarter And Full Year Financial Highlights

• Substantial Funds Flow - FFO was robust at $377.6 million ($4.67 basic per share) for 2023 compared to $450.7 million ($5.50 basic per share) in the prior year even with an 18 percent and 50 percent decrease in WTI oil and AECO natural gas prices, respectively. Fourth quarter 2023 FFO totaled $97.0 million ($1.23 per basic share) compared to $110.5 million ($1.34 per basic share) in the fourth quarter of 2022. Lower commodity prices in both 2023 periods primarily drove the decrease, partially offset by higher production, lower net operating costs and realized hedging gains.

• Capital Development Growth - In 2023, our capital program provided production growth from established development areas as we continued to delineate, extend and discover new development areas (specifically in our Peace River area). Capital expenditures totalled $292.5 million (2022 - $314.8 million), while decommissioning expenditures totaled $26.6 million (2022 - $18.8 million). Fourth quarter capital expenditures were $100.0 million (2022 - $97.1 million) and decommissioning expenditures were $7.7 million (2022 - $3.0 million). Our activity over the fourth quarter of 2023 provided us with strong operational momentum as we begin to execute on our Growth Plan in 2024.

• Active Share Buyback Program - A total of approximately 5.4 million shares were repurchased and cancelled under the Company's normal course issuer bid ("NCIB") for $49.9 million ($9.30 per share) from NCIB inception in 2023 to February 21, 2024. Current shares outstanding are 77,303,538. Of this amount, 2.2 million shares were repurchased and cancelled in the fourth quarter for $22.4 million ($10.22 per share). The Board of Directors approved renewing our NCIB once it expires later in February.

• Stable Net Debt - Net debt levels increased slightly to $330.2 million at December 31, 2023, compared to $316.8 million at December 31, 2022, largely due to a higher working capital deficiency from our active development program late in 2023 and our share buyback program during the year. In total, net debt was comprised of $107.5 million drawn on our $240.0 million syndicated credit facility, $117.4 million of senior unsecured notes ("Notes") and a $105.3 million working capital deficiency. Our balance sheet remains strong with a Net Debt/FFO ratio of 0.9 times at year-end 2023. Based on our current liquidity estimates and the terms and conditions of the applicable agreements, the Company expects to make a semi-annual repurchase offer of $2.0 million to noteholders in March 2024.

• Reduced Net Operating Costs - Net operating costs were lower at $14.21 per boe in 2023 compared to $14.29 per boe in 2022 as the Company benefited from our higher production base while executing an active maintenance program. For the fourth quarter of 2023, net operating costs decreased by seven percent to $13.66 per boe (2022: $14.63 per boe) due to lower power costs in addition to our higher production base.

• Lower G&A Costs - General and administrative ("G&A") costs decreased to $1.61 per boe in 2023 compared to $1.64 per boe in 2022, and by eight percent to $1.51 per boe in the fourth quarter of 2023 compared to $1.64 per boe for the quarter in 2022. The decrease in 2023 is primarily attributable to our higher production base.

• Renewed Office Lease on Improved Terms - In the fourth quarter of 2023, the Company entered an office lease extension beginning in February 2025 to mid-2028. Under the terms of the extension, we expect cash savings of approximately $8.5 million per year at the commencement of the lease.

• Net Income - Net income in 2023 was $108.0 million ($1.33 per share basic) due to our strong operational results, which helped offset the impact of lower commodity prices compared to the prior year. In 2022, net income of $810.1 million ($9.88 per basic share) benefited from an asset impairment reversal (due to our significantly higher reserve value and higher commodity prices in the year) and the recognition of our substantial tax pool position through a deferred income tax asset. For the fourth quarter of 2023, the Company had net income of $34.3 million ($0.44 per basic share) compared to net income of $631.7 million ($7.69 per share) in the fourth quarter of 2022, largely due to the asset impairment reversal and the recording of our deferred income tax asset.

2023 Fourth Quarter And Full Year Operational Highlights

• Strong Asset Performance and Efficiencies - We achieved strong 2023 reserve results with volume increases across all categories, replacing production, adding new locations, and improved efficiency of our capital program.

  • We replaced 124 percent of 2023 production on a proved developed producing ("PDP") basis, 157 percent on a total proved ("1P") basis and 217 percent on a total proved plus probable ("2P") basis¹.

    • On a per share basis, reserve volumes increased by 13 percent, 15 percent and 17 percent for PDP, 1P and 2P, respectively, in 2023 over 2022.

    • The impact of drilling field extensions from our 2023 capital program combined with positive technical revisions were the major contributing factors to increased reserves.

  • Reserves before-tax net present value discounted at 10 percent ("NPV10") decreased from 2022 levels largely due to the impact of lower commodity prices to $1.5 billion, $1.9 billion and $2.6 billion on a PDP, 1P and 2P basis, respectively.

  • Our total undeveloped 2P reserve locations increased by over 30 new net locations to 343 total net locations booked (including 237 net locations in the Cardium, 42 net locations in the Bluesky, 11 net locations in the Clearwater, 48 net locations in the Viking, one net location in the Devonian and four net locations in the Mannville) ².

    • These locations were booked with a highly achievable total 2P five-year future development capital ("FDC") of $1.4 billion (approximately $286 million per year).

  • Improvements from between four to 17 percent in both finding and development ("F&D") and Finding, Development and Acquisition ("FD&A") costs year-over-year show the stability of our reserve book and our ability to bring new production onstream efficiently.

• Achieved Robust Well Results - Applying technical advancements across our acreage, our team realized considerable success in replacing production with new reserve additions, opening new development areas and attaining strong initial production ("IP") rates, including:

  • Strong IP results from the four (4.0 net) Bluesky wells drilled at the Walrus 13-19 Pad in Peace River during the second half of 2023 that also successfully tested a lower Bluesky zone, further expanding the potential of this play.

  • Solid production rates in our Dawson field in Peace River led to over 20 follow-up Clearwater inventory locations (currently unbooked in our 2023 reserve report) identified in the area.

    • Since our last update, the 13-23 Pad had a pad peak rate of 558 boe/d (100 percent oil) with individual well IP 30-day rates of 226 boe/d (100 percent oil) and 126 boe/d (100 percent oil), respectively.

  • Continued strong performance at the Willesden Green (Cardium) Open Creek 9-17 Pad with flat declines and high production rates, leading to further area development in 2024.

• Established New Development Fields - We focused on unlocking the multi-zone potential of our Peace River asset through exploration/appraisal activities in early 2023, resulting in the discovery and establishment of two new development fields at Walrus (Bluesky formation) and Dawson (Clearwater formation). The Dawson acreage established the Company's first Clearwater development area.

• Successful Viking Development Program - The Company expanded and further delineated the western region of our Viking play in 2023 with 19 (19.0 net) wells brought on production by the end of the year. Robust average production rates from this shallow, low-risk, highly economic resource play provide additional cash flow for the Company's capital programs in 2023 and 2024.

• Finalized Three-Year Growth Plan (2024 - 2026) - Our Growth Plan highlights steady production increases over the three-year period with an annualized production growth rate of 16 percent, reaching 50,000 boe/d in 2026 and contributing to increased FFO and higher FCF generation. Our strategy is to maintain production levels in our Willesden Green / Pembina (Cardium), and Viking light oil plays, and use the significant FCF from these assets to fund growth in our heavy oil business at Peace River.

• Active Decommissioning Program - We successfully abandoned a combined total of 157 net wells and 617 net kilometres of pipeline in 2023 as part of activities from our decommissioning spend of $26.6 million.

2023 GUIDANCE AND RESULTS

All operational metrics met or bettered our 2023 guidance, including production, capital expenditures, decommissioning expenditures, net operating costs and G&A. Lower commodity prices in the fourth quarter largely contributed to FFO and FCF that were slightly below our guidance levels. Net debt and leverage ratios were above forecasts largely due to the active share buyback program in the fourth quarter.

			2023E Guidance	2023 Results
Production1	boe/d		32,000 - 32,500	32,275
% Oil and NGLs	%		66%	65%
Capital expenditures2	$ millions		300	292.5
Decommissioning expenditures	$ millions		26 - 28	26.6
Net operating costs	$/boe		14.25 - 14.75	14.21
General & administrative	$/boe		1.60 - 1.70	1.61
Based on midpoint of above guidance
FFO3	$ millions		~390	377.6
FFO per share (basic)3	$/share		~4.80	4.67
FCF3	$ millions		~60	58.5
Net debt4	$ millions		~310	330.2
Net debt to FFO4	times		0.8	0.9
Commodity Prices (Nov. & Dec. 2023)5
WTI	US$/bbl		85.00	74.75
WCS differential	US$/bbl		15.00	23.71
AECO	$/GJ		3.00	2.14

 

(1) Mid-point of 2023E guidance: 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) 2023E capital expenditures include approximately $25 million for exploration/appraisal well activity with minimal impact on forecasted production volumes.
(3) 2023E guidance FFO and FCF included risk management (hedging) adjustments up to October 31, 2023, and included 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.
(4) 2023E guidance net debt figures estimated as at December 31, 2023, and included the impact of approximately $33.0 million of share purchases under the NCIB to November 8, 2023. Our net debt increased by $20 million due to changes in the timing of our capital program (which increased our expected working capital deficiency) and additional NCIB purchases post November 8, 2023.
(5) 2023E guidance pricing assumptions were forecasted for November 1, 2023, to December 31, 2023.

2023 DEVELOPMENT PROGRAM

Our 2023 program included drilling 59 (58.5 net) wells across all our areas, including four (4.0 net) oilsands exploration ("OSE") wells in Peace River to further develop and delineate our broad, high quality asset base. With a high activity level throughout the year and an accelerated drilling program in the fourth quarter of 2023, a total of 56 (55.3 net) wells were put on production by the end of 2023, contributing to significant reserve additions and production growth. All the remaining seven (7.0 net) wells rig released in 2023 are now onstream.

	Operated Wells Rig Released Gross (net)	Operated Wells On Production Gross (net)
H1 2023	29 (28.8)1	33 (32.6)1
H2 2023	30 (29.7)	23 (22.7)
TOTAL	59 (58.5)2,3	56 (55.3)2
(1) Two of the six wells drilled in Peace River were exploration/appraisal wells to further delineate the Bluesky play. (2) 48 (47.5 net) wells rig released in 2023 were brought on production by the end of 2023, 4 (4.0 net) OSE wells do not get put on production, and the remaining seven (7.0 net) wells were brought onstream in the first quarter of 2024. (3) Obsidian Energy participated in a total of 18 non-operated (6.7 net) wells in 2023, three of which were water injection wells.

 

As we placed the remaining wells from our 2023 program onstream, the Company had a solid start to our 2024 first half development program with continued development and exploration/appraisal drilling in the Clearwater and Bluesky formations in Peace River, and development of our Willesden Green/Pembina (Cardium) assets. Highlights from 2023 and an update on our 2024 activity can be found in our 2023 capital program and 2024 guidance releases.

HEDGING UPDATE

In 2023, the Company had an active hedging program and entered into various oil and natural gas contracts, leading to a realized gain of $17.7 million during the year, including $15.5 million related to natural gas and $2.2 million related to oil. In 2024, our focus has been on solidifying our natural gas hedge position given our concerns on natural gas storage levels. The following contracts are currently in place on a weighted average basis:

Oil Contracts

Type	Term	Volume (bbl/d)		Swap Price ($/bbl)
WCS Differential	April - June 2024	750		($18.80)

 

AECO Natural Gas Contracts

Type	Term	Volume (mcf/d)	Percentage Hedged1	Swap Price ($/mcf)
AECO Swap	January - March 2024	32,749	46%	$3.35
AECO Swap	April - October 2024	43,365	61%	$2.52
AECO Swap	November 2024 - March 2025	14,929	21%	$3.74
AECO Collars	November 2024 - March 2025	4,976	7%	$3.43 - $4.11

 

(1) Based on 2024E natural gas production of 70.8 mmcf/d.

Electricity Contracts

Type	Term	Volume (MWh/d)		Swap Price ($/MWh)
Power Swaps	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.

SCOTIA HOWARD WELL ENERGY & POWER CONFERENCE

Obsidian Energy will be participating in the 52^nd Annual Scotia Howard Weil Energy & Power Conference in Miami, Florida at the Mandarin Oriental Hotel. Stephen Loukas, President and Chief Executive Officer, along with Peter Scott, Senior Vice President and Chief Financial Officer will be hosting one-on-one meetings on February 28 and 29, 2024 at the conference centre.

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.

In addition, this news release contains several oil and gas metrics, including "F&D costs" and "FD&A costs," which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics are commonly used in the oil and gas industry and have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

F&D costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period for the reserve category. F&D costs exclude the impact of acquisitions and divestitures.

FD&A costs are the sum of capital expenditures incurred in the period for the reserves category and including the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category.

Under NI 51-101, 1P reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For 2P reserves, under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserve estimate. The reserve estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

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.

DRILLING LOCATIONS

This news release discloses drilling locations or inventory. 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.

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 and cash flow from operating activities as indicators of our performance. The Company's audited annual consolidated financial statements and MD&A as at and for the year ended December 31, 2023, will be available in due course 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 year ended December 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.

Non-GAAP Financial Ratios

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 year ended December 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 year ended December 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 December 31						Year ended December 31
(millions)	2023			2022			2023			2022
Cash flow from operating activities	$	117.7		$	126.5		$	352.7		$	456.8
Change in non-cash working capital		(30.3	)		(20.9	)		(13.6	)		(34.8	)
Decommissioning expenditures		7.7			3.0			26.6			18.8
Onerous office lease settlements		2.3			2.3			9.0			9.2
Settlement of restricted share units		0.1			-			4.8			-
Deferred financing costs		(0.6	)		(0.4	)		(2.3	)		(2.5	)
Restructuring charges1		-			-			-			2.5
Transaction costs		-			-			-			0.1
Other expenses1		0.1			-			0.4			0.6
Funds flow from operations		97.0			110.5			377.6			450.7
Capital expenditures		(100.0	)		(97.1	)		(292.5	)		(314.8	)
Decommissioning expenditures		(7.7	)		(3.0	)		(26.6	)		(18.8	)
Free Cash Flow	$	(10.7	)	$	10.4		$	58.5		$	117.1

 

(1) Excludes the non-cash portion of restructuring and other expenses.

Netback to Sales Price

	Three months ended December 31						Year ended December 31
(millions)	2023			2022			2023			2022
Sales price	$	173.6		$	207.0		$	722.8		$	899.4
Risk management gain (loss)		6.7			0.5			17.7			(31.9	)
Net sales price		180.3			207.5			740.5			867.5
Royalties		(25.0	)		(34.8	)		(97.8	)		(148.3	)
Net operating costs		(40.2	)		(42.7	)		(167.4	)		(160.0	)
Transportation		(10.8	)		(9.6	)		(41.0	)		(35.1	)
Netback	$	104.3		$	120.4		$	434.3		$	524.1

 

Net Operating Costs to Operating Costs

	Three months ended December 31						Year ended December 31
(millions)	2023			2022			2023			2022
Operating costs	$	45.8		$	47.6		$	188.9		$	175.3
Less processing fees		(3.6	)		(2.9	)		(14.3	)		(8.4	)
Less road use recoveries		(2.0	)		(2.0	)		(7.2	)		(6.9	)
Net operating costs	$	40.2		$	42.7		$	167.4		$	160.0

 

Net Debt to Long-Term Debt

	As at
	December 31
(millions)	2023			2022
Long-term debt
Syndicated credit facility	$	107.5		$	105.0
Senior unsecured notes		117.4			127.6
Unamortized discount of senior unsecured notes		(1.6	)		(2.3	)
Deferred financing costs		(3.3	)		(5.0	)
Total		220.0			225.3
Working capital deficiency
Cash		(0.5	)		(0.8	)
Accounts receivable		(70.0	)		(82.6	)
Prepaid expenses and other		(12.8	)		(10.7	)
Accounts payable and accrued liabilities		193.5			185.6
Total		110.2			91.5
Net debt	$	330.2		$	316.8

 

ABBREVIATIONS

Oil		Natural Gas
bbl	barrel or barrels	AECO	Alberta benchmark price for natural gas
bbl/d	barrels per day	GJ	gigajoule
boe	barrel of oil equivalent	mcf	thousand cubic feet
boe/d	barrels of oil equivalent per day	mcf/d	thousand cubic feet per day
MSW	Mixed Sweet Blend	mmcf/d	million cubic feet per day
WTI	West Texas Intermediate
WCS	Western Canadian Select	Electricity
		MWh	Megawatt hour
		MWh/d	Megawatt hour per day

 

FORWARD-LOOKING STATEMENTS

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 audited consolidated financial statements and MD&A on our website, SEDAR+ and EDGAR in due course; our expectations for the Growth Plan including but not limited to production, production growth, development, FFO, and FCF; how we plan to fund our Growth Plan; expected timing for drilling, rig releases, and on-production and onstream dates; the renewal of the NCIB; our expectations regarding the Notes repurchase; our development locations; our hedges and hedging focuses in 2023; our expected cash savings in connection with the lease extension; our expectations for an updated corporate presentation; our attendance at the Scotia Howard Weil Energy & Power Conference.

With respect to forward-looking statements 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 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; 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, 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; our ability to execute our plans as described herein and in our other disclosure documents, including our Growth Plan, and the impact that the successful execution of such plans will have on our Company and our stakeholders including our ability to return capital to shareholders and/or further reduce debt levels; expectations and assumptions concerning applicable laws and regulations, including with respect to environmental, safety and tax matters; 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; the ability of the Company's contractual counterparties to perform their contractual obligations; 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; the accuracy of our estimated reserve volumes; 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 contained in this document, and the assumptions on which such forward-looking statements 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 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 involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements 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. These risks and uncertainties include, among other things: 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 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 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 (such as our inability to return capital to shareholder and/or reduce our debt levels to the extent anticipated or at all); 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 (such as the COVID-19 pandemic), and the responses of governments and the public to any pandemic, including the risk of energy demand destruction; 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 regional and/or global health related events, 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 repurchase 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, drought or extreme warm weather in the spring or summer); the inability to access our properties due to blockades or other activism; 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 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 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.

CONTACT

OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com

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¹ Please refer to the "Oil and Gas Information Advisory" section below for information regarding production replacement.
² Please refer to the "Drilling Locations" section below.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/198863