Obsidian Energy Fourth Quarter, Full Year 2020 Results

Obsidian Energy detailed its Q4 and full year 2020 results.

Key 2020 Results

In response to the challenges faced in 2020, we took immediate action to manage our underlying asset base, drive continued cost efficiencies, and protect our balance sheet without sacrificing our safety or environmental performance. We implemented a series of decisions to help preserve liquidity including significant cost reduction initiatives, rapidly shut-in volumes deemed temporarily uneconomic, deferred our second half development program and reduced debt levels.

As a result, the Company met all key performance targets in 2020. In conjunction with increased oil prices, capital expenditures were expanded in December to accommodate an early start to our 2021 development program.

(1) Adjusted for January 2020 Carrot Creek Disposition of 115 boe/d (85% light oil).
(2) Mid-point of Updated 2020 Guidance Range: 11,600 bbl/d light oil, 2,850 bbl/d heavy oil, 2,200 bbl/d NGLs and 52.5 mmcf/d natural gas.

2020 Q4 and Full Year Financial Highlights

• Debt Reduction – Cash flow from operations exceeded capital expenditures, which contributed to net debt decreasing five percent to $467.8 million at December 31, 2020, compared to $494.2 million from the prior year. This included $395 million drawn on our syndicated credit facility, $60.3 million of senior notes and a $12.5 million working capital deficiency at December 31, 2020.
• Resilient Funds Flow – FFO was $117.8 million ($1.61 per share) for the year compared to $159.1 million ($2.18 per share) in 2019. Fourth quarter 2020 FFO totaled $26.4 million ($0.36 per share), compared to $54.2 million ($0.74 per share) for the fourth quarter of 2019. The decrease to FFO was a result of lower commodity prices and lower production due to our deferred capital program, which was partially offset by cost reductions.
• Increased Operating Efficiencies – Net operating costs improved 17 percent to $11.15 per boe in 2020 compared to $13.42 per boe in 2019, as the Company continued to benefit from efficiency improvements despite lower production volumes. For the fourth quarter of 2020, net operating expenses remained consistent on a per boe basis at $12.77 per boe compared to $12.75 per boe in the fourth quarter of 2019.
• Reduced G&A Costs – Cost saving initiatives improved G&A costs significantly in 2020, decreasing 26 percent to $1.51 per boe in 2020 compared to $2.03 per boe in 2019. In the fourth quarter, G&A decreased three percent to $1.63 per boe in 2020 compared to $1.68 per boe in 2019.
• Capital Discipline – Capital expenditures in 2020 totaled $57.2 million (a decrease of 45 percent over 2019) and decommissioning expenditures totaled $11.1 million. Fourth quarter capital expenditures were $11.6 million (a decrease of 66 percent from the fourth quarter of 2019) and decommissioning expenditures were $2.3 million in the fourth quarter of 2020 compared to $6.4 million in the same period in 2019.
  • The majority of 2020 capital expenditures were spent in the first half with the drilling of 10 net wells. Fourth quarter 2020 capital expenditures were primarily in December and relate to the start of our 2021 development program.
• Net Income/Loss – The significantly lower oil price environment resulted in the Company recording non-cash asset impairments in the first quarter of 2020, which predominately contributed to the net loss of $771.7 million ($10.53 per share) in 2020. For the fourth quarter of 2020, the Company recorded net income of $0.2 million ($0.01 per share).

2020 Q4 and Full Year Operational Highlights

• Strong Asset Performance – We achieved strong 2020 reserves replacement, increases in reserve life indices and additional future drilling locations despite challenges of global commodity prices.
  • Total proved (“1P“) and total proved plus probable (“2P“) reserves increased 113 percent and 125 percent, respectively in 2020 over 2019 levels. Our 2020 development program replaced 96% of production on a proved developed producing (“PDP“) basis prior to economic impacts from the lower commodity price forecast. Including economic factors, we replaced 64 percent of production on a PDP basis.
  • Finding and development costs are reflective of our strong results with operated development costs for our capital activity in 2020 of $9.44 per boe on a 2P basis.
  • Consistent positive technical revisions combined with drilling results and new future drilling locations increased our reserve life indices to approximately 8.5, 11.4 and 14.3 years for PDP, 1P and 2P reserves respectively.
• Outstanding Development Well Results – We achieved considerable success in replacing production and added 37.3 net Cardium locations to our 2P reserves, net of our 2020 drilling program. Our 10 net well drilling program resulted in some of the best wells in the history of our Cardium area, delivering strong initial production (“IP“) and ongoing rates.
• Extended Reach Drilling at Lower Well Capital Costs – We successfully reduced our costs per well to $3.2 million for the year with an increased average horizontal length of 2,797 meters. These costs are inclusive of all construction, drilling, completions, equipping and gathering system expenditures, and represent a six percent reduction from 2019 costs despite an increase in the average horizontal length by five percent.
• Continued Reduction in Decommissioning Liabilities – On a full year basis, we successfully abandoned a combined total of 247 net wells and 338 net kilometres of pipeline in 2020 through participation in the Alberta Site Rehabilitation Program (“ASRP“) and the Area Based Closure (“ABC“) programs. Our undiscounted decommissioning liability at year-end 2020 decreased by four percent to $596.6 million from $621.2 million. ABC eligible spending of $10 million as conducted prior to the suspension of ABC spend targets in 2020 is fully creditable against our 2021 ABC spend requirements.

2021 Development Program Update

We began drilling our first half 2021 program in our high economic return Willesden Green Cardium area in December 2020. With continued strong commodity prices in 2021, Obsidian Energy expanded our planned first half drilling program from seven to nine wells. To date, seven wells have been successfully rig-released, and the remaining wells are expected to be rig-released prior to the third week of April, subject to ground conditions. We have also successfully completed five of the new Willesden Green wells. The remaining four wells are progressing on schedule and will be completed as soon as ground conditions allow, giving the Company a head start on our second half capital program. All activity to date has been completed on schedule and within budget estimates.

The three wells on the 4-35 pad are the first wells to be brought on production in our 2021 development program. The 4-35 pad sits adjacent to the 12-26 and 1-27 pads that delivered strong results from our first half 2020 program; IP10 rates for two of the new wells averaged 801 boe/d (89 percent oil). We are also very pleased with our 2021 drilling performance thus far. The first well reached a measured depth of 5,576 metres (3,503 metres horizontal length), which is the longest well drilled for the Company since 2018. Additionally, a second well in the program became a new Company pacesetter for wells with intermediate casing, drilling to a measured depth of 5,349 metres in 11.1 days (spud to rig release) – saving over $0.2 million and finishing 1.5 days quicker than our internal estimate.

2021 Outlook & Guidance

The COVID-19 pandemic created a very challenging environment in 2020. We acted quickly with the support of our employees, board and stakeholders, and are positioned to take advantage of the improving economic environment in 2021. 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. With a continued constructive pricing environment, our program further positions us for additional production growth that generates even greater free cash flow in 2022.

The Company is replacing our previous guidance for first half 2021 to full year 2021 as our longer-term bank and senior note extensions, coupled with improved commodity prices provide added stability. A total budget of $127 million in capital expenditures plus an additional $8 million in decommissioning expenditures is planned for our development and environmental programs in 2021. We intend to utilize a two-rig continuous drilling program in the second half of 2021 with plans to drill 23 wells (19.3 net), predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine net wells drilled in the first half of the year, 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. In addition, our successful optimization program continues with $8 million allocated for 2021 (included in the capital expenditure figures above) to capture further highly attractive capital efficiencies. The Company has significant capability to scale our development drilling in response to changes in commodity prices.

Net operating expenses per boe are expected to be higher than 2020 levels largely due to reduced production volumes, higher staff costs due to the full reinstatement of salaries, minimal benefit from the Canadian Wage Subsidy program and a forecasted increase to well repairs and maintenance given the recent improvement in commodity prices. Increases in both cash flow and funds flow from operations are expected due to the continued strong performance of our high netback Willesden Green focused development program and the higher pricing environment.

We are continuing our participation in the ASRP and ABC programs, focusing on fields in Northern Alberta in the first quarter of 2021 where we’ve abandoned 106 net wells and 154 net kilometres of pipelines year to date. Decommissioning activity will be expanded over the next two years with an anticipated 485 net wells and 647 net kilometres of pipelines abandoned prior to the end of 2022 with the support of nearly $30 million of ASRP grants.

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. We expect to generate approximately $45 million of free cash flow in 2021 (net of non-recurring transaction expenses associated with our bank facility and senior note extensions, using the midpoint of our guidance and WTI US$60 per barrel), which will be directed toward debt reduction. This is expected to result in an annualized fourth quarter 2021 net debt to EBITDA ratio of 2:1. We anticipate 2022 free cash of approximately $100 million (at WTI US$60 per barrel and the mid-point of the 2021 production forecast) driven by higher production and the absence of transaction expenses. Our full year 2021 guidance is presented below.

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