Calgary, Alberta – 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 2022. The Company is also pleased to announce the appointment of Stephen Loukas as President and Chief Executive Officer of the Company, effective immediately.
“Steve has served as Interim President and Chief Executive Officer since December 2019,” said Gordon Ritchie, Chair of Obsidian Energy’s Board of Directors. “Steve’s performance in an interim role has been exemplary in terms of leadership, operational performance, financial stewardship and value creation – all in an extremely challenging period for Obsidian Energy. The Board looks forward to working with Steve for many more years; we are highly confident in his ability to create significant shareholder value as he guides the future strategic direction of Obsidian Energy.”
|Three Months Ended
(millions, except per share amounts)
|Cash flow from operating activities||126.5||62.6||456.8||198.7|
|Basic per share ($/share)2||1.54||0.81||5.57||2.65|
|Diluted per share ($/share)2||1.50||0.78||5.41||2.56|
|Funds flow from operations3||110.5||80.0||450.7||217.9|
|Basic per share ($/share)4||1.34||1.04||5.50||2.90|
|Diluted per share ($/share)4||1.31||1.00||5.34||2.81|
|Adjusted Funds flow from operations3||108.6||83.4||474.1||235.0|
|Basic per share ($/share)4||1.32||1.08||5.78||3.13|
|Diluted per share ($/share)4||1.28||1.04||5.62||3.03|
|Net income (loss)||631.7||21.7||810.1||414.0|
|Basic per share ($/share)||7.69||0.28||9.88||5.52|
|Diluted per share ($/share)||7.47||0.27||9.60||5.34|
|Three Months Ended
|Light oil (bbl/d)||12,105||11,155||11,636||10,583|
|Heavy oil (bbl/d)||5,983||3,237||5,950||2,844|
|Natural gas (mmcf/d)||67||58||64||54|
|Total production5 (boe/d)||31,742||26,352||30,682||24,605|
|Average sales price6|
|Light oil ($/bbl)||110.45||92.55||121.92||80.65|
|Heavy oil ($/bbl)||62.19||51.76||83.84||50.46|
|Natural gas ($/mcf)||5.66||5.05||5.84||3.88|
|Risk management gain (loss)||0.18||(1.55||)||(2.85||)||(1.34||)|
|Net sales price||71.05||60.29||77.46||51.94|
|Net operating costs4||(14.63||)||(11.79||)||(14.29||)||(13.04||)|
(1) We adhere to generally accepted accounting principles (“GAAP“); however, we also employ certain non-GAAP measures to analyze financial performance, financial position, and cash flow, including funds flow from operations, adjusted funds flow from operations, net debt, netback and net operating costs. Additionally, other financial measures are also used to analyze performance. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS“) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income 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 consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the year ended December 31, 2022 on our website at www.obsidianenergy.com, which will also be filed on SEDAR and EDGAR in due course.
Building on the success of 2021 combined with stronger commodity prices in 2022, we more than doubled our capital program which contributed to a 25 percent increase in annual production year over year, over 100 percent reserve replacement and more than doubling funds flow from operations (“FFO“) to $450.7 million. We successfully refinanced our debt capital structure in July, providing the Company with more operational flexibility, and repaid debt with our free cash flow (“FCF“) of $117.1 million, improving our Net Debt to FFO leverage to 0.7 times.
2022 Fourth Quarter and Full Year Financial Highlights
- Strong Funds Flow – FFO increased by 107 percent to $450.7 million ($5.50 per basic share) for 2022 compared to $217.9 million ($2.90 per basic share) in 2021. Fourth quarter 2022 FFO totaled $110.5 million ($1.34 per basic share), compared to $80.0 million ($1.04 per basic share) for the fourth quarter of 2021. Increased production combined with improved netbacks due to higher commodity prices primarily drove the change over 2021.
- Capital Development Growth – In 2022, we undertook the largest development program we have executed in several years: capital expenditures ($314.8 million) and property acquisitions ($4.6 million) totaled $319.4 million (2021 – $141.0 million), while decommissioning expenditures totaled $18.8 million (2021 – $8.1 million). Fourth quarter capital expenditures were $97.1 million (2021 – $44.8 million) and decommissioning expenditures were $3.0 million (2021 – $2.7 million). The increase in capital expenditures provided the Company with the opportunity to be active across all our areas in 2022 (Peace River, Willesden Green, Pembina and Viking), with a larger portion spent in the second half of the year.
- Continued Debt Reduction – Continued strong FCF generation resulted in a significant decrease in net debt to $316.8 million at December 31, 2022, compared to $413.5 million at December 31, 2021. This included $105.0 million drawn on our $175.0 million syndicated credit facility, $127.6 million of senior unsecured notes outstanding under our new capital structure and a $91.5 million working capital deficiency.
- Stringent G&A Costs – General and administrative (“G&A“) costs were $1.64 per boe in 2022 compared to $1.69 per boe in 2021, and $1.64 per boe in the fourth quarter of 2021 compared to $1.57 per boe for the quarter in 2021.
- Managed Net Operating Costs – Net operating costs were higher at $14.29 per boe in 2022 compared to $13.04 per boe in 2021. Operating costs reflect the impact of higher power costs, increased activity levels in 2022 and the inflationary environment. For the fourth quarter of 2022, net operating costs increased to $14.63 per boe compared to $11.79 per boe in the fourth quarter of 2021 also due to higher power costs as well as the impact of cold weather during the month of December which disrupted operations and production.
- Higher Net Income – Strong operating results combined with an asset impairment reversal (due to our significantly higher reserve value and higher commodity prices) and recognition of our strong tax pool position through a deferred income tax asset generated net income of $810.1 million ($9.88 per basic share) in 2022 compared to $414.0 million ($5.52 per basic share) in 2021, which also included asset impairment reversals. For the fourth quarter of 2022, the Company recorded net income of $631.7 million ($7.69 per basic share), compared to net income of $21.7 million ($0.28 per share) in the fourth quarter of 2021. The substantially higher net income in the fourth quarter of 2022 was due to continued strong FFO, the asset impairment reversal and recording the deferred income tax asset.
2022 Fourth Quarter and Full Year Operational Highlights
- Strong Asset Performance – We achieved strong 2022 reserve results through replacing production, adding new locations, and increasing our valuation.
- Our year-end reserves before-tax net present value discounted at 10 percent value increased across all categories over 2021 levels:
- Proved developed producing (“PDP“): 38 percent increase to $1.6 billion.
- Total proved (“1P“): 49 percent increase to $2.1 billion.
- Total proved plus probable (“2P“): 54 percent increase to $2.8 billion.
- We replaced 144 percent of 2022 production on a PDP basis, 214 percent on a 1P basis and 393 percent on a 2P basis.1
- Our total undeveloped 2P reserve locations increased by over 80 new net locations to 311 total net locations booked (including 236 net locations in the Cardium, 22 net locations in the Bluesky, 2 net locations in the Clearwater, 49 in the Viking, one Devonian and one Mannville).2
- These locations are booked with a highly achievable total future development capital (“FDC“) of $1.26 billion (approximately $250 million per year).
- Our year-end reserves before-tax net present value discounted at 10 percent value increased across all categories over 2021 levels:
- Achieved Robust Development Well Results – Execution by our team resulted in considerable success in replacing production with new reserve additions. Also, continued solid results within our Cardium, Peace River and Viking areas have resulted in strong initial production (“IP“) rates, which have continued, across our areas.
- Commenced Clearwater Formation Exploration/Appraisal – We furthered the development of the multi-zone potential in our Peace River asset with the spud of two wells (2.0 net) targeting the Clearwater play in the second half of 2022. One well was drilled in the Seal area and the second well in our Dawson area. We are encouraged by the reservoir and fluid quality results from these wells, which are supportive of continued exploration/appraisal as part of our 2023 plans.
- Returned to Viking Area – The Company resumed development drilling in our Viking asset in 2022 with eight wells (8.0 net) brought on production adding a peak total rate of over 1,000 boe/d to the Esther field. A step-out well drilled to test the western extent of the play was one of the most prolific Viking wells drilled in the area, providing an outstanding economic return and displaying peak rates of 242 boe/d (88 percent oil) and an IP 90-day rate of 201 boe/d (86 percent oil).
- Expanded Peace River Ownership – Recognizing the multi-zone potential and strong returns of our Peace River asset, we increased our ownership position in the area to approximately 500 sections through land acquisitions. In 2022, we purchased an additional 36 sections (approximately 23,000 acres) of prospective Clearwater and Bluesky rights in the Peace River region for a consideration of $18.4 million. We also purchased the Seal 9-15 gas plant, contributing to our dominant infrastructure position in the area (70 percent of the total area gas processing capacity).
- Reduction in Decommissioning Liabilities – We successfully abandoned a combined total of 257 net wells and 599 kilometres of pipeline (net) in 2022 through participation in the Alberta Site Rehabilitation Program (“ASRP“) as well as our own decommissioning spend.
Highlights Subsequent to 2022
- Approval of Normal Course Issuer Bid to Facilitate Share Buyback – In January 2023, the Board of Directors authorized a normal course issuer bid (“NCIB“) to provide a return of capital to shareholders as we believe the intrinsic value of our shares far exceeds our current trading price. In February, the Company’s application with the Toronto Stock Exchange (“TSX“) for the NCIB was approved. This allows the Company to initiate a share buyback program over the next 12 months beginning February 27, 2023, on the TSX, NYSE American and other marketplaces of up to 10 percent of the Company’s “public float”, as defined by the TSX: a maximum of 8,073,847 common shares, with a daily purchase limit on the TSX of 85,192 common shares, subject to certain exceptions for block purposes. Purchases under the NCIB are subject to maintaining at least $65 million of liquidity and otherwise complying with our debt agreements. To enhance our liquidity, we continue discussions with credit providers to expand our debt capacity. Additional details regarding the NCIB can be found in a separate news release issued today.
2022 DEVELOPMENT PROGRAM
The largest development program that the Company has undertaken in several years, our 2022 program included drilling 61 wells (59.5) across all three areas to further develop and delineate our broad, high quality asset base, which contributed to significant reserve additions. With extreme cold weather in December hampering operations and production, three wells (2.9 net) from our 2022 development program were rig released in 2023, and eight wells (7.8 net) drilled and rig released in 2022 were not on production into permanent facilities until 2023. Of these 11 (10.7 net) wells, eight wells (7.8 net) are currently on production with the remainder expected in early 2023.
|Q1 2022||19 (18.5)||12 (11.6)1|
|Q2 2022||11 (11.0)||16 (15.7)|
|Q3 2022||13 (12.8)||11 (11.0)|
|Q4 2022||18 (17.2)||19 (18.2)|
|TOTAL||61 (59.5)2||58 (56.5)2|
|(1) Three wells (2.9 net) were spud in 2022 and rig released in 2023; they are not included in these totals.|
|(2) Eight wells (7.8 net) were spud and rig released in 2022, of which six (5.8 net) wells are currently on production.|
2022 REVISED GUIDANCE AND RESULTS
FFO, FCF, G&A costs, net debt, and leverage ratios all met or were better than our ranges despite WTI and AECO prices being slightly below our forecast. Delays and cold weather impacted production, resulting in both production and capital expenditures to be just below our guidance. Similarly, net operating costs were slightly above guidance due to the same factors as well as cost pressures, particularly with power.
|Production1||boe/d||30,800 – 31,200||30,682|
|% Oil and NGLs||%||65%||65%|
|Capital expenditures2||$ millions||320 – 330||319.4|
|Decommissioning expenditures3||$ millions||18||18.8|
|Net operating costs||$/boe||13.50 – 14.00||14.29|
|General & administrative||$/boe||1.55 – 1.65||1.64|
Based on midpoint of above guidance
|WTI Range (Nov and Dec)4||US$/bbl||85.00 – 95.00||80.39|
|AECO Range (Nov and Dec)4||CAD$/GJ||5.80||5.73|
|FFO||$ millions||441 – 456||450.7|
|Adjusted FFO5||$ millions||487 – 502||474.1|
|FCF 5||$ millions||98 – 113||117.1|
|Net debt6||$ millions||335 – 320||316.8|
|Net debt to FFO5,6||times||0.8x – 0.7x||0.7|
(1) Mid-point of 2022 guidance range: 11,715 bbl/d light oil, 6,065 bbl/d heavy oil, 2,475 bbl/d NGLs and 64.5 mmcf/d natural gas. Average production volumes in 2022 do not include any forecasted production associated with Clearwater exploratory capital expenditures.
(2) 2022 actuals include capital expenditures ($314.8 million) and property acquisitions ($4.6 million).
(3) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(4) 2022 guidance pricing assumptions are for November to December. Mid-point pricing assumptions for our 2022 guidance include WTI at US$90.00/bbl and AECO at $5.80/GJ from November to December.
(5) Pricing assumptions for our 2022 guidance outlined are forecasted for November and December 2022 and includes risk management (hedging) adjustments as of November 4, 2022. Guidance FFO and FCF includes approximately $46 million of estimated charges for 2022 related to the deferred share units, performance share units and non-treasury incentive plan awards share-based compensation amounts which are based on a share price of $15.00 per share. The charge is primarily due to the Company’s increased share price in 2022 compared to the closing price on December 31, 2021, of $5.21 per share. Adjusted FFO excludes the estimated non-cash share-based compensation amounts for 2022.
(6) Net debt figures estimated as at December 31, 2022.
DEVELOPMENT PROGRAM UPDATE
We had a strong start to our first half 2023 development program with activity in Willesden Green, Pembina, and Peace River areas. An update on our activities from our 2022 development program and January 2023 guidance releases are as follows:
The remaining four (4.0 net) Bluesky wells from our 2022 development program are now completed with two wells on the 2-05 Pad producing into permanent facilities, and two wells on the 6-04 Pad expected to be on production in late February. The five Bluesky wells (5.0 net) producing through temporary production facilities from the fourth quarter of 2022 at our Seal property were tied-in to permanent facilities through December and early January, increasing our production volumes in the area.
Two of the three Bluesky development wells (3.0 net) planned for our first half 2023 program have been rig released (one at the 14-05 Pad and the third well on the 02-05 Pad) and are in the process of being put on production. The third well is in the process of being drilled at the Harmon Valley South 4-32 Pad, offsetting very strong well results from early 2022. In early February, both 2023 Bluesky exploration/appraisal wells came on production and are in the process of cleaning up at the Walrus 16-20 Pad and the Walrus 13-19 Pad.
The first of our Clearwater 2023 exploration/appraisal wells, the Dawson 12-33 Pad well (1.0 net) is on production through temporary facilities. Early results are encouraging with a peak production rate of 123 bbl/d and current production at approximately 96 bbl/d with a 15 percent water-cut and a high oil quality of 12.4o API. Drilling results from the well indicated superior reservoir quality in the final three of eight legs that are approximately one mile each in length. We will use the results of this well and our upcoming vertical oilsands exploration well to optimize future well design and placement in our Dawson property. Preliminary well results in combination with future optimization has validated our continued investment in the emerging northwest extension of the Clearwater play. In 2023, we will continue to appraise and evaluate our future development opportunities as part of our broader aspirations for our Peace River asset.
Four wells rig released in December have now been placed on production, completing our 2022 development program in Willesden Green. Two wells (2.0 net) on the Crimson 8-36 Pad were placed on production in February with average IP 10-day rates of 259 boe/d (65 percent light oil). The Crimson 9-02 Pad well (1.0 net) was on production in January with an average 10-day IP rate of 166 boe/d (90 percent light oil); rates continue to increase as the well progresses. The Crimson 8-19 was on production in late December with an average 30-day IP rate of 667 boe/d (84 percent light oil).
Extending the success of our 2022 program, we drilled and rig released four wells (4.0 net) of the five wells (5.0 net) planned for the first half of 2023. The Crimson 12-26 Pad well (1.0 net) was rig released in early January and is showing average 10-day IP rate of 397 boe/d (69 percent oil). In addition, two wells (2.0 net) on the Crimson 8-36 Pad were spud with one of the wells rig released in mid-February, and we are currently drilling two wells (2.0 net) on the Crimson 8-09 Pad. All five wells are expected to be placed on production in March and April 2023.
We completed our 2022 program in early 2023, placing all remaining wells on production. The three wells (2.9 net) at the South Pembina 14-6 Pad went on production in late December, averaging IP 30-day rates of 292 boe/d (59 percent light oil). Rig released in December, the two wells (2.0 net) from the PCU#9 6-33 Pad were placed on production in February.
We also rig released the two wells (1.8 net) in our 2023 program at the Lodgepole 3-14 Pad, completing our first half 2023 drilling in Pembina. The wells have been completed and are expected to be on production by April 2023.
Accelerating our Viking development early into 2023, all 11 wells (11.0 net) from our 2023 Viking program are expected to be rig released by the end of February. Located near the successful step-out well drilled in 2022, we expect the wells to come on production in March and April 2023, providing strong economic returns while further delineating the western side of our acreage.
The Alberta Government’s ASRP program ended in 2022 with all work completed by February 14, 2023. Total support received from the province over the three-year period was $30.5 million (on a gross basis), helping us successfully abandon a combined total of 796 net wells and 1,121 kilometres of pipeline (net) when combined with our decommissioning expenditures from 2020 to 2022.
Obsidian Energy will continue to advance our program in 2023 with $26 to $28 million in planned decommissioning expenses to target inactive inventory.
The Company has focused our hedging program on AECO positions across 2023 and into early 2024 given our concerns on natural gas storage levels. As at February 22, 2023, the following financial oil and natural gas contracts are in place on a weighted average basis:
AECO Natural Gas Contracts
|AECO Swap||January 2023 – February 2023||14,976||23%||6.18|
|AECO Swap||March 2023||31,562||48%||4.58|
|AECO Swap||April 2023 – October 2023||47,391||72%||3.55|
|AECO Swap||November 2023 – March 2024||16,587||25%||3.57|
(1) Percentage calculated based on annual expected natural gas production of 65.8 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.
Under NI 51-101, proved 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 proved plus probable 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.
This news release contains a number of oil and gas metrics, including “future development capital”, 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.
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 our total undeveloped proved plus probable drilling inventory. Proved locations and probable locations are derived from GLJ Ltd.’s reserves evaluation effective December 31, 2022, and account for drilling locations that have associated proved and/or probable reserves, as applicable. There is no certainty that we will drill all drilling 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 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 drilling locations have been de-risked by drilling existing wells in relative close proximity to such drilling locations, other 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, resources 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 (loss) and cash flow from operating activities as indicators of our performance. The Company’s audited consolidated financial statements and notes and MD&A as at and for the year ended December 31, 2022 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; adjusted FFO; net debt; net operating costs; netback; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the year-ended December 31, 2022, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
For a reconciliation of FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of adjusted FFO to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of net debt to long-term debt, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of net operating costs to operating costs, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of netback to sales price, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
For a reconciliation of FCF to cash flow from operating activities, being our nearest measure prescribed by IFRS, see “Non-GAAP Measures Reconciliations” below.
The following measures are non-GAAP ratios: funds flow from operations (basic per share ($/share) and diluted per share ($/share)), which use funds flow from operations as a component; net operating costs ($/boe), which uses net operating costs as a component; netback ($/boe), which uses netback as a component; and net debt to FFO (funds flow from operations), which uses net debt and funds flow from operations as components. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the year-ended December 31, 2022, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measures are supplementary financial measures: average sales price; cash flow from operating activities (basic per share and diluted per share); and G&A costs ($/boe). See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the year-ended December 31, 2022, for an explanation of the composition of these measures.
Non-GAAP Measures Reconciliations
2022 and 2021 Cash Flow from Operating Activities, Funds Flow from Operations and Free Cash Flow
|Three months ended
|(millions, except per share amounts)||2022||2021||2022||2021|
|Cash flow from operating activities||$||126.5||$||62.6||$||456.8||$||198.7|
|Change in non-cash working capital||(20.9||)||6.2||(34.8||)||5.1|
|Onerous office lease settlements||2.3||2.1||9.2||9.1|
|Deferred financing costs||(0.4||)||(1.1||)||(2.5||)||(5.5||)|
|Financing fees paid||–||0.3||–||4.7|
|Commodities purchased from third parties||–||3.7||–||3.7|
|Funds flow from operations||110.5||80.0||450.7||217.9|
|Share based compensation2||(1.9||)||3.4||23.4||17.1|
|Adjusted funds flow from operations||108.6||83.4||474.1||235.0|
|Share based compensation2||1.9||(3.4||)||(23.4||)||(17.11||)|
|Free Cash Flow||$||10.4||$||32.5||$||117.1||$||68.9|
(1) Excludes the non-cash portion of restructuring and other expenses.
(2) Includes expenses associated with our cash settled share-based incentive plans, being the Deferred Share Unit Plan, Performance Share Units granted under the Restricted and Performance Share Unit Plan and the Non-Treasury Incentive Award Plan.
2022 and 2021 Netback to Sales Price
|Three Months Ended||Year Ended|
|December 31||December 31|
|Risk management loss||0.5||(3.7||)||(31.9||)||(12.0||)|
|Net sales price||207.5||146.3||867.5||466.5|
|Net operating costs||(42.7||)||(28.6||)||(160.0||)||(117.1||)|
2022 and 2021 Net Operating Costs to Operating Costs
|Three Months Ended||Year Ended|
|December 31||December 31|
|Less processing fees||(2.9||)||(1.5||)||(8.4||)||(6.4||)|
|Less road use recoveries||(2.0||)||(2.3||)||(6.9||)||(6.0||)|
|Net operating costs||$||42.7||$||28.6||$||160.0||$||117.1|
2022 and 2021 Net Debt to Long-Term Debt
|As at December 31|
|Syndicated credit facility||$||105.0||$||321.5|
|Senior unsecured notes||127.6||–|
|Senior secured notes||–||54.9|
|PROP Limited recourse loan||–||16.0|
|Unamortized discount of senior unsecured notes||(2.3||)||–|
|Deferred financing costs||(5.0||)||(2.7||)|
|Working capital deficiency|
|Prepaid expenses and other||(10.7||)||(9.1||)|
|Accounts payable and accrued liabilities||185.6||107.8|
|API||American Petroleum Institute||AECO||Alberta benchmark price for natural gas|
|bbl||barrel or barrels||mcf||thousand cubic feet|
|bbl/d||barrels per day||mmcf||million cubic feet|
|boe||barrel of oil equivalent||bcf||billion cubic feet|
|boe/d||barrels of oil equivalent per day||mmcf/d||million cubic feet per day|
|mmbbls||million barrels||NGL||natural gas liquids|
|mmboe||million barrels of oil equivalent||GJ||gigajoule|
|WTI||West Texas Intermediate|
FUTURE-ORIENTED FINANCIAL INFORMATION
This release contains future-oriented financial information (“FOFI“) and financial outlook information relating to the Company’s prospective results of operations, operating costs, expenditures, production, FFO, adjusted FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under “Forward-Looking Statements“. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company’s business as of the date hereof and such information may not be appropriate for other purposes.