- Successful completion of first half and an early start to the second half 2021 drilling program
- Continued debt paydown and higher funds flow from operations
Calgary, Alberta – OBSIDIAN ENERGY LTD. (TSX: OBE) (OTCQX: OBELF) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to report strong operating and financial results for the second quarter 2021.
|Three Months Ended June 30||Six Months Ended June 30|
(millions, except per share amounts)
|Cash flow from operations||42.2||2.1||70.3||33.5|
|Basic per share ($/share)||0.57||0.03||0.95||0.46|
|Diluted per share ($/share)||0.55||0.03||0.93||0.46|
|Funds flow from operations1||42.3||24.7||78.6||61.0|
|Basic per share ($/share)1||0.57||0.34||1.06||0.84|
|Diluted per share ($/share)1||0.55||0.34||1.04||0.84|
|Net income (loss)||322.5||(21.1||)||345.7||(768.7||)|
|Basic per share ($/share)||4.33||(0.29||)||4.67||(10.53||)|
|Diluted per share ($/share)||4.23||(0.29||)||4.57||(10.53||)|
|Light oil (bbl/d)||10,836||12,800||10,427||12,656|
|Heavy oil (bbl/d)||2,660||1,966||2,723||2,805|
|Natural gas (mmcf/d)||54||53||52||53|
|Total production2 (boe/d)||24,651||25,872||23,942||26,482|
|Average sales price3|
|Light oil ($/bbl)||76.97||29.20||72.37||39.78|
|Heavy oil ($/bbl)||48.58||5.98||44.46||15.13|
|Natural gas ($/mcf)||3.21||2.14||3.21||2.17|
|Risk management gain (loss)||(0.52||)||4.75||(1.44||)||4.61|
|Net sales price||49.04||25.05||45.54||30.98|
|Net operating expenses1||(13.71||)||(8.51||)||(13.62||)||(10.32||)|
(1) The terms funds flow from operations (“FFO“) and their applicable per share amounts, “net debt”, “netback” and “net operating expenses” are non-GAAP measures. Please refer to the “Non-GAAP Measures” advisory section below for further details.
(2) Please refer to the “Oil and Gas Information Advisory” section below for information regarding the term “boe”.
(3) Before risk management gains/(losses).
Detailed information can be found in Obsidian Energy’s unaudited interim consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the three and six months ended June 30, 2021 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.
KEY SECOND QUARTER 2021 RESULTS
The economic environment continued to improve in the second quarter, resulting in higher FFO and further debt reduction. Favourable weather and ground conditions allowed us to accelerate all aspects of our development program including the rig release of three wells from our second half 2021 program.
2021 Second Quarter Financial Highlights
- Strong Funds Flow – FFO was $42.3 million ($0.57 per share) for the second quarter of 2021, an increase from the first quarter of 2021 ($36.3 million; $0.49 per share) and the second quarter of 2020 ($24.7 million; $0.34 per share). Higher commodity prices were partially offset by higher royalty rates and share-based compensation charges of $8.9 million, which was predominately due to the more than doubling of the Company’s share price between March 31, 2021 to June 30, 2021. Adjusting for the share-based compensation charges, FFO would have been $51.2 million ($0.69 per share), representing a 107 percent increase when compared to the second quarter of 2020.
- Capital Acceleration – Capital expenditures in the second quarter of 2021 totaled $21.5 million (2020: $0.4 million) and were predominately spent on completing the remaining wells in the nine-well first half development program as well as pad construction costs for the second half program. We began our second half 2021 drilling operations earlier than anticipated and accelerated certain optimization projects due to favourable spring ground conditions.
- Debt Reduction – Continued strong financial results and our focus on debt reduction resulted in a decrease in net debt of 12 percent to $435.7 million at June 30, 2021, compared to $495.7 million at June 30, 2020. This included $370.0 million drawn on our syndicated credit facility (down from $420.0 million at June 30, 2020), $57.3 million of senior notes and $8.4 million of a working capital deficiency.
- Continued Low G&A Costs – Second quarter 2021 general and administrative (“G&A“) costs were consistent with the first quarter of 2021 at $1.69 per boe compared to $1.36 per boe in 2020. Lower production volumes in 2021 combined with several temporary measures taken in 2020 in response to the low commodity price environment reduced costs in the comparable period in 2020.
- Operating Cost Management – Net operating costs of $13.71 per boe during the second quarter of 2021 were higher than $8.51 per boe in the second quarter of 2020 and $13.52 per boe in the first quarter of 2021. Similar to G&A, operating costs were impacted by the return to normal activity levels in 2021 compared to 2020, where the Company restricted discretionary spending and shut-in production as a result of the low commodity price environment in this period. During the second quarter of 2021, the Company was impacted by high power prices, mostly due to extreme heat in several parts of North America that increased natural gas demand and prices, and completed more 2021 scheduled maintenance activity than originally planned in the quarter.
- Net Income – Net income of $322.5 million ($4.33 per share) in the second quarter of 2021 benefitted from higher FFO and a $311.5 million impairment reversal within the Company’s Cardium asset due to higher forecasted commodity prices and strong drilling results. This compared to a net loss of $21.1 million ($0.29 per share) in 2020, largely due to the lower commodity price environment at that time.
2021 Second Quarter Operational Highlights
- Improved Production Levels – Performance from our first half 2021 drilling program and our base resulted in average production of 24,651 boe/d in the second quarter of 2021, a six percent increase over the first quarter of 2021 and ahead of internal estimates. As a result, we have increased our average production guidance for the year to between 24,000 and 24,400 boe/d from 23,300 to 23,800 boe/d.
- Accelerated Development Program – We completed the first half development program with nine wells on production by mid-June. Careful pad design and facility planning allowed for extended operations into break up, accelerating drilling of the four-well East Crimson 6-21 pad into the first half of 2021.
- Continued Strong Drilling Performance – We continued to demonstrate drilling efficiencies with estimated first half 2021 per well costs of $3.3 million (inclusive of construction, drilling, completions, equipping and tie-in costs to lease edge), representing a two percent decrease from our 2020 program average while increasing lateral length by 10 percent as compared to our first half 2020 program. Our 2021 drilling results include a new Company pacesetter for wells with intermediate casing and a new Company-best well lateral length.
- Increased 2021 Development Program – With the continuation of a higher commodity price environment and base production improvements, we added three incremental wells (gross) to our second half 2021 development program and expanded our optimization activities by $2.6 million.
- Reduction in Decommissioning Liabilities – We abandoned a total of 51 net wells during the second quarter of 2021 through participation in the Area Based Closure (“ABC“) program and the Alberta Site Rehabilitation Program (“ASRP“), where we utilized $1.1 million of net grants. As a result of these efforts, our undiscounted, uninflated decommissioning liability was reduced by an estimated $4 million in the second quarter.
|Production Volumes by Product and Producing Region
Three Months Ended June 30, 2021
|Area||Production (boe/d)||Light Oil (bbl/d)||Heavy Oil (bbl/d)||NGLs
|Key Development Areas||24,097||10,672||2,585||2,131||53|
|Key Development & Legacy Areas||24,651||10,836||2,660
2021 DEVELOPMENT PROGRAM UPDATE
In addition to completing our first half 2021 development program, we finished construction of several pad sites in our second half 2021 program in June, allowing for an early start to our program.
Our second half two-rig continuous drilling program is well underway with the rig release of both wells at the East Crimson 1-33 two-well pad in July. Fracture stimulation for these wells is complete, and the wells are expected to be on stream by the end of August. This rig also successfully drilled a third well at the existing 3-29 pad in East Crimson, with completion anticipated in mid-August, and has spud a fourth well at our 3-03 two-well pad in Crimson Lake.
In July, we started drilling in our Central Pembina region, and are currently drilling the first well on the 7-17 Pembina Cardium Unit #9 three-well pad. With the remaining wells on this pad to be drilled in August, we expect completion of all wells by mid-September.
With an improved economic environment and higher FFO, we have modestly increased our 2021 capital plan with the addition of three gross wells to our second half program and expanded optimization activities by $2.6 million. We plan to drill 25 wells (22.0 net), up from 23 wells (20.3 net) in our second half 2021 program, predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine wells brought on production in the first half of the year (one of which was rig released in 2020), we expect to bring 28 wells (25.0 net), up from 25 wells (22.8 net), on production in 2021. Consistent with previous guidance, the remaining seven wells (7.0 net) are expected on production early in the first quarter of 2022. Our successful optimization program continued with $3.9 million invested in the second quarter (first quarter 2021: $2.9 million) out of a total of $10.6 million now allocated to capture highly attractive capital efficiencies in 2021.
During the first half of 2021, we successfully abandoned a combined total of 158 net wells and 155 net kilometres of pipeline through participation in the ASRP, where we utilized $5.9 million of grants, and the ABC program. Our second-half decommissioning program is fully underway with four service rigs working on decommissioning well activity. With the support of approximately $28 million (gross) of ASRP grants and allocations from the program, we anticipate 589 net wells and 702 net kilometres of pipelines will be abandoned in 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 and increasing our capital expenditures for the remainder of the year, adding three incremental gross wells to our second half program and expanding our optimization activities. A minor change in 2021 guidance for net operating expenses was also made due to higher than expected power prices. Our revised 2021 guidance includes $8.9 million of share-based compensation recorded in the second quarter (not included in our original 2021 guidance), which is reflected in the FFO and FCF metrics. We continue to meaningfully reduce debt levels, which is expected to result in an improved annualized fourth quarter 2021 net debt to EBITDA ratio of 1.8:1 (assuming mid-point of operational guidance and WTI of US$65/bbl).
|Production 1||boe/d||23,300 – 23,800||24,000 – 24,400|
|Net Operating Expense||$/boe||$12.70 – $13.10||$12.80 – $13.20|
|General & Administrative||$/boe||$1.65 – $1.85||$1.65 – $1.85|
|Capital Expenditures||$ millions||$125 – $130||$133 – $138|
|Decommissioning Expenditures 2||$ millions||$8||$8|
|Based on midpoint of above guidance|
|Funds Flow from Operations3||$ millions||$160 – $1954||$180 – $2005|
|Funds Flow from Operations3||per share||$2.18 – $2.654||$2.37 – $2.675|
|Free Cash Flow3||$ millions||$25 – $604||$35 – $555|
|WTI Range||US$/bbl||$55.00 – $65.00||$60.00 – $70.00|
(1) Mid-point of guidance range: 10,600 bbl/d light oil, 2,650 bbl/d heavy oil, 2,150 bbl/d NGLs and 52.6 mmcf/d natural gas.
(2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(3) Includes the $11.3 million charge related to the DSU, PSU and NTIP cash compensation plans, which increased largely due to the Company’s significant increase in our share price which closed at $4.24 per share at June 30, 2021 compared to $0.87 at December 31, 2020.
(4) Includes actual WTI and natural gas prices for the first quarter of 2021 Risk management (hedging) adjustments incorporated into 2021 guidance as at May 6, 2021.
(5) Includes actual WTI and natural gas prices for the first half of 2021. Risk management (hedging) adjustments incorporated into 2021 guidance as at July 28, 2021.
The Company has the following financial oil and gas contracts in place on a weighted average basis:
|Term||Notional Volume||Pricing (CAD)|
|Oil – WTI|
|April 2021||5,525 bbl/d||$||77.90/bbl|
|May 2021||5,956 bbl/d||$||79.67/bbl|
|June 2021||6,350 bbl/d||$||81.27/bbl|
|July 2021||6,419 bbl/d||$||88.07/bbl|
|August 2021||3,000 bbl/d||$||90.33/bbl|
|Natural Gas – AECO|
|April 2021||26,065 mcf/d||$||2.83/mcf|
|May 2021||21,326 mcf/d||$||2.68/mcf|
|June 2021||21,326 mcf/d||$||2.67/mcf|
|July 2021||21,326 mcf/d||$||2.57/mcf|
|August – October 2021||23,695 mcf/d||$||2.70/mcf|
|November 2021 – March 2022||4,739 mcf/d||$||4.18/mcf|
Additionally, the Company has the following physical contracts in place:
|Notional Volume||Term||Pricing (CAD)|
|Physical Oil Contracts1|
|WTI||571 bbl/d||Apr – Jun 2021||$||59.04/bbl|
|Light Oil Differential2 3|
|1,245 bbl/d||Apr – Jun 2021||$||5.51/bbl|
|1,230 bbl/d||Jul – Sep 2021||$||5.82/bbl|
|Light Oil Differential – USD2|
|1,556 bbl/d||Apr – Jun 2021||US$4.00/bbl|
|1,539 bbl/d||Jul – Sep 2021||US$4.42/bbl|
|Heavy Oil Differential4|
|564 bbl/d||Jul – Sep 2021||$||14.85/bbl|
|Heavy Oil Differential5 – USD|
|550 bbl/d||Jul – Dec 2021||US$26.00/bbl|
(1) WTI, differentials and foreign exchange hedged to lock-in positive net operating income on certain heavy oil properties.
(2) Differentials completed on a WTI – MSW basis.
(3) USD transactions completed on a US$ WTI – US$ MSW basis and converted to Canadian dollars using a fixed foreign exchange ratio of CAD/USD $1.281 in the second quarter of 2021 and $1.279 in the third quarter of 2021.
(4) Differentials completed on a WTI – WCS basis.
(5) Hedged on a USD basis and inclusive of WCS differential, quality and transportation charges.
UPDATED CORPORATE PRESENTATION
For further information on these and other matters, Obsidian Energy will post an updated quarterly corporate presentation today on our website, www.obsidianenergy.com.