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 first quarter 2021.
|Three Months Ended March 31|
(millions, except per share amounts)
|Cash flow from operations||28.1||31.4|
|Basic per share ($/share)||0.38||0.43|
|Diluted per share ($/share)||0.37||0.43|
|Funds flow from operations1||36.3||36.3|
|Basic per share ($/share)1||0.49||0.50|
|Diluted per share ($/share)1||0.48||0.50|
|Net income (loss)||23.2||(747.6||)|
|Basic per share ($/share)||0.32||(10.24||)|
|Diluted per share ($/share)||0.31||(10.24||)|
|Light oil (bbls/d)||10,014||12,512|
|Heavy oil (bbls/d)||2,788||3,644|
|Natural gas (mmcf/d)||50||52|
|Total production2 (boe/d)||23,225||27,092|
|Average sales price3|
|Light oil ($/bbl)||67.34||50.59|
|Heavy oil ($/bbl)||40.48||20.07|
|Natural gas ($/mcf)||3.21||2.20|
|Risk management gain (loss)||(2.44||)||4.47|
|Net sales price||41.77||36.64|
|Net operating expenses1||(13.52||)||(12.04||)|
|(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 months ended March 31, 2021 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.
KEY FIRST QUARTER 2021 RESULTS
Commodity prices continued to improve during the first quarter, generating the highest funds flow from operations over the last four quarters and free cash flow that allowed for the pay down of debt. Net debt is now $62.0 million lower at $455.0 million at March 31, 2021 compared to the same period in 2020. Following suspension of our capital program through the majority of 2020, the Company successfully executed our expanded 2021 first half development program with the drilling of nine Cardium wells (including one well rig released in December 2020). Three of the wells were on production in March and two in April; initial production rates have been at internal expectations while costs came in below our budget. Completion operations have begun on the remaining four wells. We remain committed to restoring COVID-19 related production declines experienced in 2020 through our active development program and continuing to further reduce debt levels through free cash flow generation.
2021 First Quarter Financial Highlights
- Strong Funds Flow – FFO was $36.3 million ($0.49 per share) for the first quarter of 2021, in line with the first quarter of 2020. Higher oil prices in 2021 offset realized hedging gains and higher production volumes in 2020.
- Capital Discipline – Capital expenditures in the first quarter of 2021 totaled $29.5 million (2020: $40.6 million). First quarter 2021 capital expenditures were predominately spent on drilling six wells with three wells completed and on stream (2020: 10 wells drilled; three wells completed and on stream). Decommissioning expenditures totaled $3.3 million compared to $8.0 million in the same period in 2020.
- Debt Reduction – Our continued focus on debt reduction resulted in a decrease in net debt of 12 percent to $455.0 million at March 31, 2021, compared to $517.0 million at March 31, 2020. This included $386.0 million drawn on our syndicated credit facility (down from $407.0 million at March 31, 2020), $58.2 million of senior notes and $10.8 million of a working capital deficiency.
- Continued Low G&A Costs – G&A costs remained relatively consistent at $1.69 per boe in the first quarter of 2021 compared to $1.63 per boe in 2020, despite lower production volumes in 2021. On an absolute basis, G&A costs were $0.5 million lower at $3.5 million in the first quarter of 2021 compared to the same period in 2020.
- Operating Cost Management – Net operating costs of $13.52 per boe were under budget during the first quarter of 2021 but higher than $12.04 per boe in the first quarter of 2020. Lower production volumes and increased power costs, in part due to cold weather in February, impacted per boe results during the first quarter of 2021. In addition, the reduction of discretionary repair and maintenance activities, beginning in March 2020, due to decreasing oil prices as a result of the COVID-19 pandemic contributed to lower operating costs in 2020.
- Net Income – Net income of $23.2 million ($0.32 per share) in the first quarter of 2021 benefitted from higher oil prices and the Company’s overall lower cost structure. This compared to a net loss of $747.6 million ($10.24 per share) in 2020, largely due to the recording of non-cash impairments from the significantly lower forecasted oil price environment at the time.
2021 First Quarter Operational Highlights
- Solid Asset Performance – During 2020, the Company postponed virtually all development activity from late March to early December in response to the COVID-19 pandemic and the low commodity price environment. As a result, production declines led to lower production levels throughout 2020 and into 2021, realizing 23,225 boe/d in average production in the first quarter of 2021 compared to 27,092 boe/d in the first quarter of 2020. We expect to increase production throughout 2021 and into 2022 with an active development program focused on restoring production to pre-COVID-19 levels.
- Robust Development Well Results – Our first half drilling program delivered strong initial production (“IP“) with our three wells on the 4-35 pad achieving top quartile rates compared to our wells drilled in the area since 2017.
- Extended Reach Drilling at Lower Well Capital Costs – We continued to improve drilling and completion efficiency on capital, design and execution over the quarter. The first half development program drilling costs were approximately six percent less with an increase in average drilled horizontal length of eight percent and completed lateral length of 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.
- Continued Reduction in Decommissioning Liabilities – We successfully abandoned a combined total of 107 net wells and 155 net kilometres of pipeline during the first quarter of 2021 through participation in the Area Based Closure (“ABC“) program and the Alberta Site Rehabilitation Program (“ASRP“), where we have utilized $4.8 million of net grants. As a result of these efforts, our undiscounted, uninflated decommissioning liability was reduced $12 million in the first quarter.
|Production Volumes by Product and Producing Region
Three Months Ended March 31, 2021
|Key Development Areas||22,862||9,960||2,737||2,028||48.8|
|Key Development & Legacy Areas||23,225||10,014||2,788||2,056||50.2|
2021 DEVELOPMENT PROGRAM UPDATE
We are pleased with our nine-well first half 2021 program in our high economic return Willesden Green Cardium area. All nine wells have been rig-released with five of the new Willesden Green wells commissioned with well IP rates as outlined below. All activity to date has been completed on schedule or early compared to our plan, and our program has been delivered below our capital budget estimates.
We achieved new levels of drilling accomplishments in our first half program with a new Company pacesetter Cardium well with intermediate casing (11.1 days and 5,349 metres depth from spud to rig release), saving over $0.2 million and finishing 1.5 days quicker than estimated. We also set a new Company record length in the Cardium with a measured depth of 5,576 metres (3,503 metres horizontal length), which is the longest Cardium well drilled for the Company.
In addition, our successful optimization program continues with $3.9 million invested in the first quarter out of a total of $8 million allocated for 2021 to capture highly attractive capital efficiencies.
Production rates for the new 2021 wells on-stream were as follows:
|4-35: Three Well Pad|
|102/12-33-043-08W5||910 boe/d (87% oil)||748 boe/d (74% oil)|
|102/04-33-043-08W5||849 boe/d (80% oil)||662 boe/d (65% oil)|
|100/03-25-043-08W5||690 boe/d (91% oil)||714 boe/d (73% oil)|
|13-19: Two Well Pad|
|102/02-32-043-08W5||57 boe/d (91% oil)*||158 boe/d (76% oil)*|
|102/16-29-043-08W5||460 boe/d (75% oil)||311 boe/d (66% oil)|
|* Early rates depressed by extended frac fluid recovery, recent production rate of 220 boe/d (76% oil).|
Given the current favourable ground conditions, completions activity began in early May on the remaining four wells in the first half program, giving the Company a head start on our second half activity plan. In addition, construction of several pad sites in our second half program has been completed; drilling activity will commence in July dependent upon weather conditions.
We expect to drill 23 wells (19.3 net) in our two-rig continuous drilling program in the second half of 2021, predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine (9.0 net) wells drilled in our first half 2021 program, we expect to bring 25 wells (22.8 net) on production in 2021 with the remaining seven wells (6.8 net) expected on production early in the first quarter of 2022. The Company has significant capability to scale our development drilling in response to changes in commodity prices.
Our proactive management has led to a reduction of our decommissioning liabilities by over 30 percent since December 31, 2018, on an uninflated and undiscounted basis. We remain committed to further reducing this obligation. Decommissioning activity will continue throughout the remainder of 2021 both under the ASRP and ABC programs. With the support of nearly $30 million of ASRP grants, we anticipate 511 net wells and 409 net kilometres of pipelines will be abandoned prior to the end of 2022, which is equivalent to approximately a 90 percent decrease in our Legacy inactive well inventory at year-end 2020.
2021 OUTLOOK AND GUIDANCE; 2022 FORECAST
Our 2021 budget and 2022 forecast are designed to steadily restore average production to approximately 25,400 to 26,400 boe/d in 2022, while also paying down debt. With a strong start to our 2021 development program, we expect to generate higher fourth quarter and exit production rates than achieved in 2020, while still meaningfully reducing debt levels. This is expected to result in an annualized fourth quarter 2021 net debt to EBITDA ratio of 2:1 (assuming mid-point of operational guidance and WTI of US$60/bbl). With first quarter 2021 results at or ahead of our budget, we remain on track to meet our 2021 guidance.
|Production 1||boe/d||23,300 – 23,800||25,400 – 26,400|
|Net Operating Expense||$/boe||$12.70 – $13.10||n/a|
|General & Administrative||$/boe||$1.65 – $1.85||n/a|
|Capital Expenditures||$ millions||$125 – $130||$102 – $117|
|Decommissioning Expenditures 2||$ millions||$8||$13|
|Based on midpoint of above guidance|
|Funds Flow from Operations||$ millions||$160 – $1953||$195 – $255|
|Funds Flow from Operations||per share||$2.18 – $2.653||n/a|
|Free Cash Flow||$ millions||$25 – $603||$60 – $130|
|WTI Range||US$/bbl||$55.00 – $65.00||$55.00 – $65.00|
|(1) Mid-point of guidance range: 10,600 bbl/d light oil, 2,800 bbl/d heavy oil, 1,950 bbl/d NGLs and 49.2 mmcf/d natural gas.
(2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the Alberta Site Rehabilitation program.
(3) Includes actual WTI and natural gas prices for the first quarter of 2021. WTI = US$57.84/bbl; AECO natural gas prices = CAD$3.15/mcf. Risk management (hedging) adjustments incorporated into 2021 guidance as at May 6, 2021.
(4) Forecast 2022 free cash flow and production profiles based on ~$110MM capital program, $13MM decommissioning expenditures and includes a 34 well drilling program. Opex modelled at $12.75/boe and G&A modelled at $1.70/boe.
CLOSURE OF STRATEGIC REVIEW PROCESS
The Company has formally closed our previously announced strategic alternatives process, considering the successful completion of our syndicated credit facility and senior notes maturity extension to November 2022 and our stronger operational and improved financial position. However, we continue to pursue consolidation and merger/acquisition/disposition opportunities as part of our normal course of business to create incremental value for our stakeholders.
The Company has the following oil contracts in place on a weighted average basis:
|Term||Notional Volume||Pricing (CAD)|
|April 2021||5,525 bbl/d||$77.90/bbl|
|May 2021||4,625 bbl/d||$79.64/bbl|
|June 2021||1,000 bbl/d||$79.78/bbl|
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|
|1,280 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||$14.85/bbl|
|(1) WTI, differentials and foreign exchange hedged to lock-in positive net operating income on certain heavy oil properties.
(2) Differentials completed on a WTI – MSW basis.
(3) USD transactions completed on a US$ 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.
The Company has the following natural gas hedges in place on a weighted average basis:
|Term||Notional Volume||Pricing (CAD)|
|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 2021||21,326 mcf/d||$2.57/mcf|
|September 2021||21,326 mcf/d||$2.57/mcf|
|October 2021||21,326 mcf/d||$2.57/mcf|
ANNUAL GENERAL MEETING
The Company is pleased to announce that its Annual General Meeting (“AGM“) will be scheduled for Wednesday, June 16, 2021 at 9:00 am (Mountain Time). It is our intention to hold our AGM in person at the offices of Obsidian Energy depending on the Alberta Health guidelines in place on public gatherings at that time. Further announcements and information regarding the AGM will be made in due course.
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.
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.
Certain financial measures including FFO, FFO per share-basic, FFO per share-diluted, free cash flow, netback, net operating costs, net debt and EBITDA, included in this release do not have a standardized meaning prescribed by IFRS and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. FFO is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments and certain other expenses and is representative of cash related to continuing operations. FFO is used to assess the Company’s ability to fund its planned capital programs. See “Calculation of Funds Flow from Operations” below for a reconciliation of FFO to cash flow from operating activities, being its nearest measure prescribed by IFRS. Free cash flow is funds flow from operations less capital and decommissioning expenditures. Netback is the per unit of production amount of revenue less royalties, net operating expenses, transportation expenses and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. Net operating costs are calculated by deducting processing income and road use recoveries and is used to assess the Company’s cost position. Processing fees are primarily generated by processing third party volumes at the Company’s facilities. In situations where the Company has excess capacity at a facility, it may agree with third parties to process their volumes as a means to reduce the cost of operating/owning the facility. Road use recoveries are a cost recovery for the Company as we operate and maintain roads that are also used by third parties. Net debt is the total of long-term debt and working capital deficiency and is used by the Company to assess its liquidity. EBITDA is cash flow from operations excluding the impact of changes in non-cash working capital, decommissioning expenditures and financing expenses.
CALCULATION OF FUNDS FLOW FROM OPERATIONS
|Three months ended
|(millions, except per share amounts)||2021||2020|
|Cash flow from operating activities||$||28.1||$||31.4|
|Change in non-cash working capital||10.3||(5.1||)|
|Onerous office lease settlements||2.3||(1.2||)|
|Deferred financing costs||(1.0||)||–|
|Financing fees paid||4.1||–|
|Realized foreign exchange loss – debt maturities||0.3||–|
|Funds flow from operations||$||36.3||$||36.3|
|Basic per share||$||0.49||$||0.50|
|Diluted per share||$||0.48||$||0.50|
|(1) Excludes the non-cash portion of restructuring.|
|bbl||barrel or barrels||mmcf||million cubic feet|
|bbl/d||barrels per day||mmcf/d||million cubic feet per day|
|boe||barrel of oil equivalent||AECO||Alberta benchmark price for natural gas|
|boe/d||barrels of oil equivalent per day||NGL||natural gas liquids|
|MSW||Mixed Sweet Blend|
|WTI||West Texas Intermediate|