Calgary, Alberta – OBSIDIAN ENERGY LTD. (TSX: OBE) (OTCQX: OBELF) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to provide an update on our continued strong second half development program with two drilling rigs active in our Cardium asset, acceleration of three drills from our 2022 program into 2021, and an increase to our 2021 production guidance. In addition, we expect third quarter production to average approximately 24,150 boe/d based on preliminary estimates.
“With ten new wells on production from late September to the end of October, we are well on our way to achieving our strategic objective of restoring our production to pre-COVID levels by the end of 2021,” commented Stephen Loukas, Obsidian Energy’s Interim President and CEO. “This significant number of new wells added to our program in the second half of 2021 displays our team’s ability to quickly scale our program and access our deep and diverse inventory across our land base with improved commodity prices.”
We have increased our full-year 2021 production guidance to between 24,300 and 24,500 boe/d due to strong results from our development program and continued outperformance of our base production. Continuing strong commodity prices combined with our drilling performance has allowed the Company to accelerate its development program with the addition of three 2022 Cardium development wells into December 2021. The early start to our 2022 program allows for continuous and cost-efficient drilling through late 2021 into 2022. With these wells, we anticipate capital spending to be at the upper end of our guidance range.
2021 DEVELOPMENT PROGRAM UPDATE
We are on track to successfully drill our second half development program, including the addition of the three wells (2.8 net) in December, which will be brought on production early in 2022. Accelerating the drilling of these three wells into 2021 will allow our activity to continue uninterrupted into 2022, securing access to the drilling rigs and minimizing mobilization costs. As a result of this additional late year activity, 12 wells (9.8 net) are expected to come on stream in early 2022. Updates to our recent drilling results and planned activity are as follows:
- Willesden Green: Since the beginning of our second-half program, we have rig-released eight Cardium wells (8.0 net) and, in order to capitalize on strong AECO natural gas pricing, one liquids-rich Spirit River gas well (1.0 net). Five of the eight Cardium wells along with the Spirit River well are now on production. After cleanup, these five Cardium wells averaged 400 boe/d (81 percent light oil) over their first ten days of production. The Spirit River well flowed at an average rate of 937 boe/d (including 168 bbl/d field condensate) for its first ten days. This rate increased to 1,144 boe/d (including 212 bbl/d field condensate) on its twelfth producing day upon removal of its downhole choke.The ninth Cardium drill in this program is the final of four wells at the Faraway 6-22 Pad. This pad is expected to be fractured and on stream by the end of 2021. Drilling will continue through December with two gross/net additional wells at our Faraway 4-17 Pad, which are expected to be brought on production in late January 2022, and one accelerated 2022 well in Crimson Lake.
- Pembina: We rig-released four gross Cardium wells (3.6 net) as part of our second half program, with the first three 7-17 Pad wells now on production. The first well produced at 256 boe/d (80 percent light oil) over the past six days after a brief cleanup period. The other two wells are not yet producing at their capability due to minor pump issues; updated production results will be provided as part of our third quarter release as the wells continue cleanup. Additionally, we drilled and completed two low-cost vertical wells as part of a focused opportunity that leverages our knowledge of deeper formations. Both wells are on production: the first well averaged 326 boe/d (96 percent light oil) over its first ten days of production; and the second well produced 206 boe/d (94 percent light oil) on its third day and is improving as cleanup continues. The four remaining Cardium wells from the 2021 program are expected to be completed and brought on production in January 2022. In December 2021, we will begin the drilling of two wells from our 2022 development program.
ALBERTA SITE REHABILITATION PROGRAM
The additional $6.9 million of Alberta Site Rehabilitation Program (“ASRP“) support we received through Periods 7 and 8 allocations brings total support from the ASRP to over $35 million of grants and allocations. Total grant support will be determined by final project costs. To date, nearly $12 million of grants and allocations have been successfully invested on decommissioning activities.
In the third quarter of 2021, we abandoned 80 wells and 27 km of pipelines (net), and we remain on pace to decommission a total of approximately 600 net wells and 700 net km of pipelines during 2021 and 2022.
2021 UPDATED GUIDANCE
With solid results from our base production and our 2021 development program to date, we are revising our 2021 production guidance. Additionally, we have added three incremental gross drills (2.8 net) in late 2021, representing an acceleration of our 2022 program to deliver continuous and cost-efficient drilling into next year. In aggregate, we believe our capital spending will be near the upper range of our guidance. Production performance to date, combined with our fourth quarter capital plan and higher commodity prices contribute to the increase in our forecasted production and funds flow from operations. Our current and previous full year guidance 2021 is presented below:
(Guidance – July 29, 2021)
|Production 1||boe/d||24,000 – 24,400||24,300 – 24,500|
|Net Operating Costs2||$/boe||$12.80 – $13.20||$12.95 – $13.15|
|General & Administrative||$/boe||$1.65 – $1.85||$1.70 – $1.80|
|Capital Expenditures3||$ millions||$133 – $138||$136 – $138|
|Decommissioning Expenditures4||$ millions||$8||$8|
|Based on midpoint of above guidance|
| Funds Flow from
|$ millions||$180 – $2005,6||$220 – $2256,7|
| Funds Flow from
|per share||$2.37 – $2.675,6||$2.95 – $3.006,7|
|Free Cash Flow 2,5||$ millions||$35 – $555,6||$75 – $806,7|
|WTI Range||US$/bbl||$60.00 – $70.00||$75.00 – $80.00|
(1) Mid-point of guidance range: 10,650 bbl/d light oil, 2,650 bbl/d heavy oil, 2,200 bbl/d NGLs and 53.4 mmcf/d natural gas.
(2) See “Non-GAAP Measures’ below.
(3) Capital expenditures exclude acquisitions.
(4) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(5) Includes approximately $15 million of estimated charges for full year 2021 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on the Company’s closing share price on September 30, 2021 of $4.51 per share. The charge is primarily due to the Company’s increased share price in 2021 compared to the closing price on December 31, 2020 of $0.87 per share.
(6) Includes actual WTI and natural gas prices for the first half of 2021. Risk management (hedging) adjustments incorporated into 2021 guidance as at July 28, 2021.
(7) Includes actual WTI and natural gas prices for the first nine months of 2021. Pricing assumptions outlined are forecasted for the fourth quarter of 2021. Risk management (hedging) adjustments incorporated into 2021 guidance as at October 26, 2021.
(8) Includes actual AECO prices for the first nine months of 2021 and AECO forward strip pricing as of October 26, 2021.
The Company has the following financial oil and gas contracts in place on a weighted average basis:
|Term||Notional Volume||Pricing (CAD)|
|Oil – WTI|
|October 2021||7,750 bbl/d||$92.59/bbl|
|November 2021||6,250 bbl/d||$100.26/bbl|
|December 2021||500 bbl/d||$100.00/bbl|
|Natural Gas – AECO|
|October 2021||23,695 mcf/d||$2.70/mcf|
|November 2021 – March 2022||25,951 mcf/d||$4.63/mcf|
Additionally, the Company has the following physical contracts in place:
|Notional Volume||Term||Pricing (CAD)|
|Heavy Oil Differential1 – USD|
|550 bbl/d||Jul – Dec 2021||US$26.00/bbl|
(1) Hedged on a USD basis and inclusive of WCS differential, quality, and transportation charges.
INTERIM PRESIDENT AND CEO EXTENTION
The Company is also pleased to announce that is has also extended Stephen Loukas’s employment contract as Interim President and CEO to December 31, 2022, subject to the option to terminate, if mutually agreeable to both parties, on July 1, 2022.
“We are pleased to extend Stephen’s contract through this phase of the Company’s evolution,” said Gordon Ritchie, Chair of the Obsidian Energy Board of Directors. “Steve and the entire Obsidian Energy team have done an exceptional job to transform the Company, addressing the challenges and opportunities over the last number of years. We’re extremely pleased to have Steve guiding the future direction of Obsidian Energy.”
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. Boe/d means barrels of oil equivalent per day.
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 to be preliminary until such analysis or interpretation has been completed.
|bbl||barrel or barrels||mcf||thousand cubic feet|
|bbl/d||Barrels per day||mcf/d||thousand cubic feet per day|
|boe||barrel of oil equivalent||mmcf/d||million cubic feet per day|
|boe/d||barrels of oil equivalent per day||AECO||Alberta benchmark price for natural gas|
|WCS||Western Canadian Select|
|WTI||West Texas Intermediate|
Included in this press release are references to terms “Funds Flow from Operations”, “Free Cash Flow” and “Net Operating Costs”, which do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS“) and therefore may not be comparable with the calculation of similar measures by other companies. These non-GAAP measures are described and defined in the management’s discussion and analysis dated July 29, 2021 for the three and six months ended June 30, 2021 (the “Interim MD&A“), as summarized below. See the Interim MD&A for additional information including rationale for use of such measure and reconciliations to the nearest IFRS measure, as applicable.
“Funds Flow from Operations” is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges, transaction costs and certain other expenses and is representative of cash related to continuing operations. Funds flow from operations is used to assess the Company’s ability to fund its planned capital programs.
“Free Cash Flow” is calculated as funds flow from operations less both capital and decommissioning expenditures.
“Net Operating Costs” are calculated by deducting processing income and road use recoveries from operating costs and is used to assess the Company’s cost position.
FUTURE-ORIENTED FINANCIAL INFORMATION
This news release contains future-oriented financial information (“FOFI“) and financial outlook information relating to the Company’s prospective results of operations, operating costs, expenditures, production, Funds Flow from Operations, Free Cash Flow and Net Operating Costs, 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 in order 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.