Obsidian Energy Announces Fourth Quarter and Full Year 2021 Results

  • Funds flow from operations increased by $100 million to $218 million in 2021
  • Net debt reduced by 12 percent to $413.5 million in 2021
  • Recent four well Peace River program achieved peak oil production of over 2,700 boe/d

Calgary, Alberta--(Newsfile Corp. - February 24, 2022) - 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 2021.



Three Months Ended
December 31

Year Ended
December 31



2021

2020

2021

2020 
FINANCIAL1
(millions, except per share amounts)












Cash flow from operating activities
62.6

11.1

198.7

79.4
Basic per share ($/share)2
0.81

0.15

2.65

1.08
Diluted per share ($/share)2
0.78

0.15

2.56

1.08
Funds flow from operations3
80.0

26.4

217.9

117.8
Basic per share ($/share)4
1.04

0.36

2.90

1.61
Diluted per share ($/share)4
1.00

0.36

2.81

1.61
Net income (loss)
21.7

0.2

414.0

(771.7)
Basic per share ($/share)
0.28

0.01

5.52

(10.53)
Diluted per share ($/share)
0.27

0.01

5.34

(10.53)
Capital expenditures
44.8

11.6

140.9

57.2
Decommissioning expenditures
2.7

2.3

8.1

11.1
Long-term debt
391.0

451.8

391.0

451.8
Net debt3
413.5

467.8

413.5

467.8


 

 

 

 
OPERATIONS
 

 

 

 
Daily Production
 

 

 

 
Light oil (bbl/d)
11,155

10,055

10,583

11,574
Heavy oil (bbl/d)
3,237

2,895

2,844

2,832
NGL (bbl/d)
2,310

2,087

2,186

2,212
Natural gas (mmcf/d)
58

52

54

53 
Total production5 (boe/d)
26,352

23,644

24,605

25,404 
Average sales price6
 

 

 

 
Light oil ($/bbl)
92.55

50.76

80.65

44.81
Heavy oil ($/bbl)
51.76

30.00

50.46

22.56
NGL ($/bbl)
59.46

24.61

47.86

20.13
Natural gas ($/mcf)
5.05

2.81

3.88

2.39
             
Netback ($/boe)
 

 

 

 
Sales price
61.84

33.57

53.28

29.63
Risk management gain (loss)
(1.55)
(0.14)
(1.34)
2.25 
Net sales price
60.29

33.43

51.94

31.88
Royalties
(7.71)
(1.42)
(5.41)
(1.47)
Net operating costs4
(11.79)
(12.77)
(13.04)
(11.15)
Transportation
(2.16)
(1.60)
(2.08)
(1.91)
Netback4 ($/boe)
38.63

17.64

31.41

17.35 

 

(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, net debt, netback, net operating costs and free cash flow. 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 (loss) 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 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, 2021 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.

KEY 2021 RESULTS

A strong development program with solid technical execution combined with favourable commodity prices resulted in higher funds flow from operations ("FFO"), free cash flow ("FCF") generation and further debt reduction in 2021 compared to 2020. Our development program was extremely active with 35 operated wells (33.8 net) rig released during the year. We exited 2021 with higher production levels than at the end of 2020, supported by a combination of our 2021 development program and continued outperformance of our base assets. While continuing to drill in Willesden Green, we also resumed development in Pembina and Peace River to further unlock the potential of our extensive asset base. We began initial appraisal of the Clearwater formation within our Peace River area in late 2021 following our November 2021 acquisition of the remaining 45 percent ownership in the Peace River Oil Partnership ("PROP") through a wholly owned subsidiary, with follow on activity in the first quarter of 2022.

Increased production from our development program and our continued attention to managing expenses in an increasing cost environment allowed us to meet our production and cost targets for the year. These results, combined with higher commodity prices, resulted in FFO of $217.9 million and FCF of $68.9 million. Our 2021 results compared to guidance disclosed with our third quarter results was as follows:




2021
Guidance


2021
Results
 
Production1boe/d
24,600 - 24,800

24,605
% Oil and NGLs%
64%

64%
Capital Expenditures2$ millions
141 - 143

140.9
Decommissioning Expenditures3$ millions
8

8.1
Net Operating Costs4$/boe
12.95 - 13.15

13.04
General & Administrative Costs5$/boe
1.70 - 1.80

1.69 
     
Based on midpoint of above guidance

 
WTI Range (Q4)US$/bbl
75.00 - 80.00

77.19
Funds Flow from Operations6, 7, 8, 9$ millions
223 - 228

217.9
Free Cash Flow2, 6, 7, 8, 9$ millions
72 - 77

68.9
Net Debt9$ millions
404 - 409

413.5 

 

(1) Mid-point of guidance range:10,660 bbl/d light oil, 2,900 bbl/d heavy oil, 2,205 bbl/d NGLs and 53.6 mmcf/d natural gas.
(2) Includes capital cost updates for Peace River fourth quarter drilling at 100 percent to Obsidian Energy and otherwise excludes acquisitions.
(3) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the Alberta Site Rehabilitation Program ("ASRP").
(4) Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures".
(5) Supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(6) Guidance estimate includes approximately $15 million of estimated charges for full year 2021 related to the deferred share units, preferred 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.
(7) Guidance estimate 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.
(9) Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures".

2021 Fourth Quarter and Full Year Financial Highlights

  • Strong Funds Flow - FFO increased by 85 percent to $217.9 million ($2.90 per share) for the year compared to $117.8 million ($1.61 per share) in 2020. Fourth quarter 2021 FFO totaled $80.0 million ($1.04 per share), compared to $26.4 million ($0.36 per share) for the fourth quarter of 2020. Higher commodity prices lead to significantly improved netbacks, which primarily drove the increase.

  • Capital Development Growth - Improved commodity prices supported higher investment; as a result, 2021 capital expenditures totaled $140.9 million (2020 - $57.2 million) and decommissioning expenditures totaled $8.1 million (2020 - $11.1 million). Fourth quarter capital expenditures were $44.8 million (2020 - $11.6 million) and decommissioning expenditures were $2.7 million (2020 - $2.3 million). In 2021, the majority of 2021 capital expenditures were spent in the second half of the year within our Willesden Green, Pembina and Peace River assets.

  • Continued Debt Reduction - Continued strong FCF generation resulted in a decrease in net debt to $413.5 million at December 31, 2021, compared to $467.8 million at December 31, 2020. This included $321.5 million drawn on our syndicated credit facility (down from $395.0 million at December 31, 2020), $54.9 million of senior notes, $16.0 PROP limited recourse loan and $21.1 million working capital deficiency.

  • Solid G&A Costs - General and administrative ("G&A") costs were $1.69 per boe in 2021 compared to $1.51 per boe in 2020, and $1.57 per boe in the fourth quarter of 2021 compared to $1.63 per boe for the quarter in 2020. The 2020 annual result was lower due to temporary measures taken during that period related to the reduced commodity price environment.

  • Managed Operating Costs - Net operating costs were $13.04 per boe in 2021 compared to $11.15 per boe in 2020. Operating costs reflect the return to normal activity levels in 2021 with improved commodity prices, as well as the impact of higher power costs. For the fourth quarter of 2021, net operating costs decreased to $11.79 per boe compared to $12.77 per boe in the fourth quarter of 2020 and reflect lower cost production brought on in the second half of 2021.

  • Higher Net Income - The higher commodity price environment combined with asset impairment reversals in 2021 resulted in net income of $414.0 million ($5.52 per share) compared to the net loss of $771.7 million ($10.53 per share) in 2020. In 2020, the net loss was mainly due to asset impairment charges due to lower forecasted commodity prices. For the fourth quarter of 2021, the Company recorded net income $21.7 million ($0.28 per share), benefiting from the higher FFO. This compared to net income of $0.2 million ($0.01 per share) in the fourth quarter of 2020, largely due to a lower commodity price environment at that time.

  • Acquired Remaining Interest in Peace River - In November 2021, we acquired the remaining 45 percent partnership interest in the PROP asset for $35.2 million after closing adjustments through a wholly-owned subsidiary. This allows the Company to have full operating and funding control over the asset, which includes a significant Bluesky heavy oil resource and extensive potential Clearwater position. Please review our release dated November 2, 2021 for more details about the PROP acquisition.

2021 Fourth Quarter and Full Year Operational Highlights

  • Strong Asset Performance - We achieved strong 2021 reserves results with replacement, additional locations, and valuation.

    • Our year-end reserves before-tax net present value discounted at 10 percent ("NPV10") value increased by over 50 percent across all categories over 2020 levels:

      • Proved developed producing ("PDP"): 54 percent increase to $1.1 billion.

      • Total proved ("1P"): 54 percent increase to $1.4 billion.

      • Total proved plus probable ("2P"): 52 percent increase to $1.8 billion.

    • We replaced 214 percent of 2021 production on a PDP basis, 310 percent on a 1P basis and 317 percent on a 2P basis.1

    • Finding and development costs are reflective of our strong results for our capital activity of $10.27 per boe on a 2P basis.1

    • Our total undeveloped 2P reserve locations remain conservatively booked and highly achievable with 231 total net locations (including 170 net Cardium, 26 net Bluesky and 1.5 net Clearwater locations) and total future development capital of $736 million (approximately $147 million per year).2

  • Robust Development Well Results - Strong execution by our team in developing our assets resulted in considerable success in replacing production with new reserves and continued outstanding results with our Cardium areas, delivering strong initial production ("IP") and ongoing rates, resulting in strong technical reserve additions.

  • Return to Peace River Area - In conjunction with our PROP acquisition combined with the strong commodity price environment, the Company resumed development drilling in our Peace River asset. Four infill development wells were drilled in the fourth quarter, which were brought on production in the first quarter of 2022 and have achieved peak production rates in excess of 2,700 boe/d.

  • Reduction in Decommissioning Liabilities - We successfully abandoned a combined total of 292 net wells and 184 kilometres of pipeline (net) in 2021 through participation in the ASRP and the Area Based Closure programs.

2021 DEVELOPMENT PROGRAM

We completed the last of our activity related to the 2021 development program with 7 wells (6.8 net) now on production. Our 2021 program included drilling 35 high working interest wells across our broad, high quality asset base in the Cardium (Willesden Green and Pembina) and Peace River areas.



Operated Wells
Rig Released
Gross (net)


Operated Wells
On Production
Gross (net)
 
Q1 2021
6 (6.0)

3 (3.0)1
Q2 2021
3 (3.0)

6 (6.0)
Q3 2021
11 (10.2)

3 (3.0)
Q4 2021
15 (14.6)

17 (16.0) 
TOTAL
35 (33.8)2

29 (28.0)2 
(1) On stream count includes one well rig released in 2020.
(2) Seven wells (6.8 net) drilled in 2021 are expected to be on production in the first quarter of 2022.

 

Detailed results on our 2021 program can be found in our operational update of January 6, 2022. The current status and initial production rates of the remaining wells in our 2021 program can be found below.

2022 DEVELOPMENT PROGRAM UPDATE

We had a strong start to our first half 2022 development program with activity in Willesden Green, Pembina, and Peace River areas remaining on schedule. An update on our activities from our 2022 guidance release is as follows:

  • Willesden Green: Extending the success of our 2021 horizontal drilling program in our Crimson and Faraway assets, we have drilled and rig released 4 wells (4.0 net) of the 10 wells (10.0 net) planned in the first half of 2022. Obsidian currently has two rigs actively drilling in the field. Shown below are the initial production updates for our recent wells that closed out the 2021 drilling program on an average per well, gross basis.

    • Faraway 4-17 pad (two wells):
      • On production early February
      • Average IP10 of 262 boe/d (87 percent light oil) per well
    • Faraway 1-25 existing pad (one additional well):
      • On production early February
      • IP10 of 424 boe/d (80 percent light oil)
  • Pembina: Offsetting our successful 2021 program wells, three wells (2.7 net) of the six wells (5.5 net) planned for the first half of 2022 have been rig released. We are currently drilling on the 8-27 pad in South Pembina with one active rig in the field. The three wells shown below were brought on production in mid-February and we anticipate early production data later in February.

    • PCU#9 16-9 pad (two wells)
    • LNU 12-17 pad (one well)
  • Peace River: Results from the four well program (4.0 net) targeting the Bluesky formation that was drilled in 2021 have fully cleaned up and are producing above expectations. These new wells are exhibiting very strong initial total production rates of over 2,000 boe/d (99 percent heavy oil) with peak oil production over 2,700 boe/d. Updated results for the Bluesky wells are shown on an average per well, gross basis:

    • 6-31 pad (three wells):
      • Average last 30 days of 474 boe/d (greater than 99 percent heavy oil) per well
    • 14-25 pad (one well):
      • Average last 14 days of 608 boe/d (greater than 99 percent heavy oil)

We drilled one well to date of the six Bluesky locations planned in 2022 and began drilling the second well in mid-February.

ASRP UPDATE

Early in 2022, we received an additional $2 million of ASRP funds with the expansion of Period 5, bringing total support to over $37 million (on a gross basis). Including the impact from our $14 million in planned decommissioning expenses in 2022, we anticipate successfully abandoning over 300 net wells and over 500 km of pipelines (net) during the year, further demonstrating our commitment to reducing our impact on the environment.

2022 OUTLOOK AND GUIDANCE

As outlined in our 2022 drilling program and guidance release, we expect to grow average production to 29,100 to 30,100 boe/d in 2022. Should commodity prices remain favourable, we are positioned for additional development in the second half of 2022.

Net operating costs per boe are expected to be lower than 2021 levels due to increased production volumes and continued operational cost controls, despite current inflationary pressures on the industry. Increases in both FCF and FFO are expected due to the continued strong performance of our high netback assets, the higher commodity price environment and a diverse development program. FCF generated in 2022 will initially be directed toward further debt reduction and is expected to result in a 2022 net debt to funds flow from operations of below 1.0 times. In the first half of 2022, we plan to refinance our debt facilities to consist of senior debt to provide operating liquidity and junior debt to provide a longer-term maturity profile. Our full year 2022 guidance is presented below.








2022 Guidance 
Production1boe/d
 

 29,100 - 30,100
% Oil and NGLs%
 

 

66
Capital expenditures$ millions
 

 

143 - 149
Decommissioning Expenditures2$ millions
 

 

14
Net operating costs3$/boe
 

 

12.00 - 12.90
General & administrative costs4$/boe
 

 

1.55 - 1.65 
   
Based on midpoint of above guidance

WTI RangeUS$/bbl
70.00

75.00

80.00
Funds flow from operations5, 6$ millions
309

326

345
Free cash flow 5, 6$ millions
149

166

185
Net debt5, 7$ millions
271

254

235
Net debt to FFO3, 7times
0.9

0.8

0.7 

 

(1) Mid-point of guidance range: 11,800 bbl/d light oil, 5,175 bbl/d heavy oil, 2,450 bbl/d NGLs and 61.1 mmcf/d natural gas. Average production volumes do not include any forecasted production associated with Clearwater exploratory capital expenditures.
(2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(3) Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures".
(4) Supplementary financial measure. See "Non-GAAP and Other Financial Measures".
(5) Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures".
(6) Pricing assumptions outlined are forecasted for the full year of 2022 and includes AECO forward strip pricing and risk management (hedging) adjustments as of January 21, 2022. Guidance FFO and FCF includes approximately $19 million of estimated charges for full year 2022 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on a share price of $8.00 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.
(7) Net debt figures estimated as at December 31, 2022.

HEDGING UPDATE

The Company has the following financial oil and gas contracts in place on a weighted average basis:

Term
Notional Volume

Pricing (CAD) 
Oil - WTI





January 2022
8,016 bbl/d
$98.82/bbl
February 2022
8,634 bbl/d
$102.50/bbl
March 2022
7,500 bbl/d
$108.72/bbl
April 2022
500 bbl/d
$115.00/bbl 

 

Natural Gas - AECO




 
January - March 2022
25,591 mcf/d
$4.63/mcf
April - October 2022
11,848 mcf/d
$4.31/mcf 

 

Additionally, the Company has the following physical contracts in place:



Notional Volume

Pricing (USD) 
Heavy Oil Differential1 - USD



January 2022
1,350 bbl/d

($31.50)/bbl
February - March 2022
1,150 bbl/d

($31.50)/bbl 

 

(1) Hedged on a USD basis and inclusive of WCS differential, quality, and transportation charges.

In addition, PROP Energy 45 Limited Partnership, our wholly owned limited recourse subsidiary that purchased 45 percent of the PROP units from a third party on November 24, 2021, entered into the following financial hedges in conjunction with the acquisition financing:

Term
Notional Volume

Pricing (USD) 
Oil - WTI





Q1 2022
1,502 bbl/d
$66.24/bbl
Q2 2022
1,121 bbl/d
$65.11/bbl
Q3 2022
593 bbl/d
$63.26/bbl
Q4 2022
606 bbl/d
$62.30/bbl 

 

Heavy Oil - WCS Differential




 
Q1 2022
939 bbl/d

($17.45)/bbl
Q2 2022
801 bbl/d

($15.43)/bbl 

 

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.

This news release contains a number of oil and gas metrics, including "finding and development costs", 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.

"Finding and development costs" are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period. F&D costs exclude the impact of acquisitions and divestitures.

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.

DRILLING LOCATIONS

This press release discloses our total undeveloped proved plus probable drilling inventory. Proved locations and probable locations are derived from Sproule Associates Limited's reserves evaluation effective December 31, 2021, 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 management's discussion and analysis ("MD&A") as at and for the year ended December 31, 2021 are available on the Company's website at www.obsidianenergy.com and under our SEDAR profile at www.sedar.com. 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: funds flow from operations; net debt; net operating costs; netback; and free cash flow. 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, 2021, 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 funds flow from operations 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 free cash flow to cash flow from operating activities, being our nearest measure prescribed by IFRS, see "Non-GAAP Measures Reconciliations" below.

Non-GAAP Ratios

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; 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, 2021, 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: cash flow from operating activities (basic per share and diluted per share); and general and administrative costs ($/boe). See the disclosure under the section "Non-GAAP and Other Financial Measures" in our MD&A for the year-ended December 31, 2021, for an explanation of the composition of these measures.

Non-GAAP Measures Reconciliations

2021 and 2020 Cash Flow from Operating Activities, Funds Flow from Operations and Free Cash Flow


Three Months Ended
December 31

Year Ended
December 31
 
(millions)2021
2020
2021
2020 
Cash flow from operating activities$62.6
$11.1
$198.7
$79.4
Change in non-cash working capital
6.2

7.6

5.1

6.6
Decommissioning expenditures
2.7

2.3

8.1

11.1
Onerous office lease settlements
2.1

2.3

9.1

9.7
Deferred financing costs
(1.1)
(2.8)
(5.5)
(2.8)
Financing fees paid
0.3

5.6

4.7

5.6
Restructuring charges1
-

0.9

(1.8)
0.6
Transaction costs
3.4

-

3.5

3.5
Other expenses1
0.1

(0.6)
(7.7)
4.1
Commodities purchased from third parties
3.7

-

3.7

- 
Funds flow from operations
80.0

26.4

217.9

117.8
Capital expenditures
(44.8)
(11.6)
(140.9)
(57.2)
Decommissioning expenditures
(2.7)
(2.3)
(8.1)
(11.1)
Free Cash Flow$32.5
$12.5
$68.9
$49.5 

 

(1) Excludes the non-cash portion of restructuring and other expenses.

2021 and 2020 Netback to Sales Price


Three Months Ended
December 31

Year Ended
December 31
 
(millions)2021
2020
2021
2020 













Sales price$150.0
$73.1
$478.5
$275.6
Risk management (loss) gain
(3.7)
(0.3)
(12.0)
20.9
Net sales price
146.3

72.8

466.5

296.5
Royalties
(18.7)
(3.1)
(48.6)
(13.7)
Net operating costs1
(28.6)
(27.8)
(117.1)
(103.7)
Transportation
(5.2)
(3.4)
(18.7)
(17.7)
Netback$93.8
$38.5
$282.1
$161.4 

 

(1) Non-GAAP financial measure.

2021 and 2020 Net Operating Costs to Operating Costs


Three months ended
December 31

Year ended
December 31
 
(millions)2021
2020
2021
2020 
Operating costs$32.4
$31.5
$129.5
$115.4
Less processing fees
(1.5)
(1.7)
(6.4)
(6.3)
Less road use recoveries
(2.3)
(2.0)
(6.0)
(5.4)
Net Operating costs $28.6
$27.8
$117.1
$103.7 

 

2021 and 2020 Net Debt to Long-Term Debt


Year ended December 31  
(millions)2021
2020 







Long-term debt





Syndicated credit facility$321.5
$395.0
PROP Limited recourse loan
16.0

-
Senior secured notes
54.9

60.3
Deferred interest
1.3

-
Deferred financing costs
(2.7)
(3.5)
Total
391.0

451.8


 

 
Working capital deficiency
 

 
Cash
(7.3)
(8.1)
Accounts receivable
(68.9)
(40.8)
Prepaid expenses and other
(9.1)
(9.2)
Accounts payable and accrued liabilities
107.8

74.1 
Total
22.5

16.0


 

  
Net debt $413.5
$467.8 

 

ABBREVIATIONS

Oil Natural Gas
bblbarrel or barrelsmcf thousand cubic feet
bbl/dbarrels per daymmcfmillion cubic feet
boebarrel of oil equivalentmmcf/d million cubic feet per day
boe/dbarrels of oil equivalent per dayAECOAlberta benchmark price for natural gas
MSWMixed Sweet Blend NGLnatural gas liquids
WTIWest 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, FCF, net operating costs, net debt and net debt to FFO, 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.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: that we will file the audited consolidated financial statements and MD&A on our website, SEDAR and EDGAR in due course; our expected 2022 development program, locations and on production dates; our 2022 expectations for the ASRP and decommissioning program; our 2022 outlook and guidance including production, capital and decommissioning expenditures, net operating costs, general & administrative costs, FFO, FCF, net debt and net debt to FFO; our expected use of FCF in 2022; our hedges; our ability to refinance our debt facilities and in the first half of 2022; and our expectations for an updated corporate presentation.

With respect to forward-looking statements and FOFI contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements and FOFI contained herein (including our guidance set out under "2022 Outlook and Guidance") do not assume the completion of any transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company's operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the continued ability of members of OPEC, Russia and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the ASRP) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future operating costs and general & administrative costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices; future exchange rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, wild fires, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our senior notes and our wholly-owned subsidiaries limited-recourse loan on maturity; and our ability to add production and reserves through our development and exploitation activities.

Although the Company believes that the expectations reflected in the forward-looking statements and FOFI contained in this document, and the assumptions on which such forward-looking statements and FOFI are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements and FOFI included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements and FOFI involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements and FOFI contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements and FOFI. These risks and uncertainties include, among other things: the possibility that we change our 2022 budget in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and the decrease in confidence in the oil and natural gas industry generally whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the COVID-19 and/or other factors pandemic adversely affects the financial capacity of the Company's contractual counterparties and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our senior notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes and limited recourse debt in connection with the PROP acquisition when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or all of our credit facilities, limited recourse debt and senior notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our senior notes; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or other factors; the risk that OPEC, Russia and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to the ongoing COVID-19 pandemic. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) which may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) or Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

Unless otherwise specified, the forward-looking statements and FOFI contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements and FOFI contained in this document are expressly qualified by this cautionary statement.

Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol "OBE".

All figures are in Canadian dollars unless otherwise stated.

CONTACT

OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com


1 Please refer to the "Oil and Gas Information Advisory" section below for information regarding production replacement and finding and development costs.
2 Please refer to the "Drilling Locations" section below.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/114681

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