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CALGARY, Alberta – Cardinal Energy Ltd. (“Cardinal” or the “Company“) (TSX:CJ) is pleased to present the results of its independent reserve report effective December 31, 2019. Cardinal’s year-end 2019 reserves were evaluated by independent reserves evaluator GLJ Petroleum Consultants (“GLJ”) as at December 31, 2019 (the “2019 Reserve Report”). The 2019 financial and operating information in this press release is based on estimates and is unaudited and accordingly, such financial information is subject to change based on the results of the Company’s year-end audit.
SUSTAINABILITY
2019 was a year of focus on long term sustainability for Cardinal with government imposed oil production curtailments limiting our ability to grow production. As a result of this environment, Cardinal focused on debt repayment, share buybacks, operating cost reduction projects, including power generation and infrastructure upgrades, as well as testing of new play concepts. Of our $63 million capital budget in 2019, approximately 45% was spent on drilling and completions. During 2019, Cardinal drilled 26 (25.5 net) wells including ten (10.0 net) stratigraphic tests, seven (7.0 net) wells targeting our legacy Glauc Channel activity and nine (8.5 net) wells across new play types/areas for Cardinal.
OPERATIONAL HIGHLIGHTS
In the operation of our business, we have several areas in which to allocate our capital budget every year. In determining where our spending will occur we take into account various factors beyond oil, natural gas, differentials and electricity pricing. We also allocate our budget dollars into areas that require facility enhancement or improvements, projects which will reduce future operating costs such as self-generation of electricity, and abandonments and reclamation activities. We focus our efforts on projects which offer the greatest return on capital for short and long term returns. Due to the long life nature of our assets, drilling is not always the highest or best return within our capital budget.
As we designed our 2019 budget we were subject to regulated production curtailments and saw this as an opportunity to enhance shareholder return in ways other than production growth. Our 2019 budget focused on per share value creation through a combination of production maintenance, debt repayment, share buybacks and reduction in long term operating costs.
Overall we saw an increase in net asset value per debt adjusted diluted share of 6% while still spending part of our capital budget improving our business for the future. We have derisked drilling plays on our lands through stratigraphic tests and drilled wells into new plays which had not been previously tried on Cardinal lands to derisk further drilling inventory for the future. One of the plays which we tried in 2019 for the first time was the Regional Glauc sand in the Medicine Hat area. The best well Cardinal drilled into the Regional Glauc is currently producing in excess of 500 Boe/d (85% light and medium crude oil, 15% conventional natural gas) with offsetting wells expected to commence production in the first quarter.
Power generation projects in our 2019 capital program reduce our reliance on the Alberta power grid by approximately 2.5 megawatts which we forecast will lower our annual power costs by approximately $2.3 million. We will continue to pursue additional power projects every year as part of our long term operating cost reduction strategy.
In 2019, we repurchased a total of 1.7 million shares under our common share normal course issuer bid (“NCIB”) and funded the acquisition of 2.3 million shares under our independent trust for potential future settlement of awards under our bonus reward incentive plan saving Cardinal approximately $0.7 million/year in dividend distribution and minimizing further share dilution.
In addition, Cardinal repaid $22 million of net debt in 2019.
RESERVE REPORT HIGHLIGHTS
All reserves information contained in this press release is based on the 2019 Reserve Report.
- Proved Plus Probable (“TPP”), Total Proved (“TP”) and Proved Developed Producing (“PDP”) reserves were added through exploration and development activities and performance improvements, totaling 5.8 Mmboe, 5.7 Mmboe and 4.4 Mmboe, respectively, while spending less than 55% of our adjusted funds flow.
- Increased PDP and TPP reserves per debt adjusted diluted share by 8% and 11%, respectively.
- Increased PDP and TPP net present value before income tax discounted at 10% (“NPV10”) per debt adjusted diluted share by 6%.
- Cardinal continues to maintain a long producing reserve life index(1) (“RLI”) of 9.6 years PDP and 12.1 years Proved Plus Probable Producing (“PPDP”) based on fourth quarter 2019 production which reflects the low risk predictable nature of our asset base.
- Cardinal’s PPDP reserves account for 83% of the Company’s total reserves.
- 2019 PDP finding, development and acquisition(2) (“FDA”) cost including the change in future development costs (“FDC”) was $18.01/boe, resulting in a recycle ratio(3) of 1.24 times in a year focused on sustainability with capital being directed to operating cost reduction projects, new plays and infrastructure. A reduction in natural gas reserves was realized in areas where natural gas is now utilized for power generation and will result in future operating cost savings.
- 3 year average PDP, TP and TPP FDA of $11.85, $12.35 and $11.05 per boe, respectively.
- Based on the 2019 Reserve Report, the debt adjusted, net asset value(4) of the Company’s PDP reserves was $6.17 per basic share.
- 90% of Cardinal’s TPP reserves are associated with oil and natural gas liquids.
Notes:
(1) RLI is calculated by dividing the reserves by the annualized fourth quarter production of 20,227 boe per day, consisting of 11,214 bbl/d of light and medium crude oil, 5,540 bbl/d of heavy crude oil, 890 bbl/d of natural gas liquids and 15.5 mmcf/d of conventional natural gas.
(2) FDA costs are used as a measure of capital efficiency and are calculated by dividing the unaudited development capital expenditures for the period, including the change in undiscounted FDC, by the change in reserves, incorporating revisions and production for the same period.
(3) The recycle ratio is calculated by dividing the average 2019 operating netback of $22.31/boe (unaudited), by the FDA costs for the period. See “Oil and Gas Metrics” below.
(4) PDP net asset value is based on the before tax NPV10 of the PDP reserves less net debt of $247.6 million (unaudited) divided by the Company’s basic shares at December 31, 2019 of 113.6 million.
OIL AND GAS RESERVES
The 2019 Reserve Report encompasses 100% of Cardinal’s oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook(“COGEH”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).
Reserves Detail
In our Central area, Cardinal saw a reduction in our natural gas reserves as some of these reserves will now be used for Company owned power generation at select sites, providing Cardinal with long term operating cost reductions and extending the economic life of these assets.
Cardinal has increased the FDC from the prior year with the inclusion of additional maintenance capital and CO2 purchases. FDC included at year-end 2019 for CO2 purchases, maintenance and facility capital in PDP, TP and TPP were $77 million, $84 million and $98 million, respectively. This represents 36% of Cardinal’s TPP FDC of $270 million.
In the 2019 Reserve Report, Cardinal has included all abandonment, decommissioning and reclamation (“ADR”) costs for active and inactive wells, pipelines and facilities in the TP and TPP reserves category. The ADR costs for the active assets are recognized in the PDP reserves category. This change has resulted in a small decrease in value relative to 2018 and was made based on new recommendations added to the COGEH in 2019. This is a change to the prior years’ report, where ADR costs were included only for those wells assigned reserves. At year-end 2019, the 2019 Reserve Report included ADR costs discounted at 10% in PDP, TP and TPP of $24.6 million, $77.3 million and $77.3 million, respectively.
Consistent with prior years and in accordance with COGEH recommendations, Cardinal has included all operating costs, for active and inactive assets. The Company also includes the consideration of future maintenance costs which is included as part of the operating costs or as FDC.
Summary of Oil and Gas Reserves (1)
The following tables summarize certain information contained in the 2019 Reserve Report. Reserves included below are the Company’s estimated gross reserves as at December 31, 2019, as evaluated in the 2019 Reserve Report.
| Reserves Category | Light and Medium Oil (Mbbl) |
Heavy Oil (Mbbl) |
Natural Gas Liquids (Mbbl) |
Conventional Natural Gas(2) (MMcf) |
Total BOE (Mboe) |
||||||
| Proved Developed Producing | 38,370 | 23,280 | 2,877 | 38,390 | 70,926 | ||||||
| Proved Developed Non-Producing | 650 | 744 | 139 | 5,065 | 2,377 | ||||||
| Proved Undeveloped | 4,941 | 2,840 | 260 | 3,249 | 8,583 | ||||||
| Total Proved | 43,962 | 26,864 | 3,276 | 46,704 | 81,886 | ||||||
| Probable | 14,317 | 8,023 | 1,079 | 16,312 | 26,138 | ||||||
| Total Proved Plus Probable | 58,279 | 34,887 | 4,355 | 63,016 | 108,024 |
Notes:
(1) Total values may not add due to rounding.
(2) Includes non-associated gas, associated gas and solution gas.
(3) In addition to the gross reserves indicated in the above table, the Company has 174 mboe TPP royalty interest reserves comprised of 132 mbbl light and medium crude oil and 244 mmcf of conventional natural gas.
Summary of Net Present Values of Future Net Revenue (Before Tax)
(Based on forecast price and costs)
As at December 31, 2019 (1)(2)(3)
| Discounted at: | ||||||||||
| Reserves Category | 0.0% (M$) |
5.0% (M$) |
10.0% (M$) |
15.0% (M$) |
20.0% (M$) |
|||||
| Proved Developed Producing | 1,655,951 | 1,242,756 | 948,665 | 766,119 | 645,503 | |||||
| Proved Developed Non-Producing(4) | (127,896 | ) | (52,774 | ) | (30,554 | ) | (21,726 | ) | (17,498 | ) |
| Proved Undeveloped | 232,973 | 140,985 | 96,332 | 69,050 | 50,603 | |||||
| Total Proved | 1,761,028 | 1,330,968 | 1,014,444 | 813,443 | 678,609 | |||||
| Probable | 1,005,334 | 453,588 | 269,930 | 185,443 | 138,195 | |||||
| Total Proved Plus Probable | 2,766,362 | 1,784,556 | 1,284,374 | 998,886 | 816,804 | |||||
Notes:
(1) Total values may not add due to rounding.
(2) Based on three consultant’s average, as defined below, December 31, 2019 forecast prices and costs. See below for “Price Forecast”.
(3) Future net reserves are reduced for future abandonment costs and estimated capital for future development associated with the reserves.
(4) The Proved Developed Non-Producing net present value includes the consideration of the inactive ADR costs of the Company. Excluding these costs the NPV10 of these reserves would be $22.2 million.
Reconciliations of Changes in Reserves
The following table sets out a reconciliation of the changes in the Corporation’s reserves as at December 31, 2019 against such reserves at December 31, 2018 based on forecast prices and cost assumptions in effect at the applicable reserve evaluation date:
| Total Proved | ||||||||||
| Light and Medium Crude Oil (Mbbl) |
Heavy Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) |
MBOE (Mboe) |
||||||
| December 31, 2018 | 43,873 | 27,749 | 54,160 | 2,909 | 83,558 | |||||
| Technical Revisions (1) | 1,975 | 999 | (1,338 | ) | 632 | 3,383 | ||||
| Improved Recovery | 65 | 129 | 226 | 3 | 235 | |||||
| Extensions and Infill Drilling | 2,501 | 244 | 942 | 157 | 3,058 | |||||
| Dispositions (2) | – | (24 | ) | – | – | (24 | ) | |||
| Economic Factors | (430 | ) | (146 | ) | (1,619 | ) | (84 | ) | (930 | ) |
| Production | (4,022 | ) | (2,087 | ) | (5,667 | ) | (339 | ) | (7,392 | ) |
| December 31, 2019 | 43,962 | 26,864 | 46,704 | 3,276 | 81,886 | |||||
| Total Proved Plus Probable | ||||||||||
| Light and Medium Crude Oil (Mbbl) |
Heavy Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Natural Gas Liquids (Mbbl) |
MBOE (Mboe) |
||||||
| December 31, 2018 | 58,048 | 35,926 | 71,468 | 3,779 | 109,664 | |||||
| Technical Revisions (1) | 944 | (110 | ) | (2,794 | ) | 762 | 1,129 | |||
| Improved Recovery | 88 | 189 | 436 | 5 | 355 | |||||
| Extensions and Infill Drilling | 3,751 | 1,232 | 1,789 | 252 | 5,533 | |||||
| Dispositions (2) | – | (31 | ) | – | – | (31 | ) | |||
| Economic Factors | (530 | ) | (231 | ) | (2,217 | ) | (104 | ) | (1,234 | ) |
| Production | (4,022 | ) | (2,087 | ) | (5,667 | ) | (339 | ) | (7,392 | ) |
| December 31, 2019 | 58,279 | 34,887 | 63,016 | 4,355 | 108,024 | |||||
Notes:
(1) Technical revisions include a negative revision of 5 bcf of natural gas due to reserves utilized for power generation; for solution gas-oil ratio changes; and other minor revisions.
(2) There were no reserve acquisitions in 2019.
Price Forecast
The following table summarizes Consultant’s average (an arithmetic average of the price forecasts of GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd.) commodity price forecast and foreign exchange rate assumptions as at December 31, 2019, as applied in the 2019 Reserve Report, for the next five years.
| Consultants Average Price Forecast(1) | ||||||||||||
| Exchange Rate |
WTI @ Cushing |
Canadian Light Sweet 40° API |
Western Canada Select 20.5° API |
Medium at Cromer 29° API |
Natural gas AECO – C spot |
|||||||
| Year | ($US/$C) | ($US/bbl) | ($C/bbl) | $C/bbl) | ($C/bbl) | ($C/MMbtu) | ||||||
| 2020 | 0.760 | 61.00 | 72.64 | 57.57 | 70.22 | 2.04 | ||||||
| 2021 | 0.770 | 63.75 | 76.06 | 62.35 | 73.15 | 2.32 | ||||||
| 2022 | 0.785 | 66.18 | 78.35 | 64.33 | 74.95 | 2.62 | ||||||
| 2023 | 0.785 | 67.91 | 80.71 | 66.23 | 77.19 | 2.71 | ||||||
| 2024 | 0.785 | 69.48 | 82.64 | 67.96 | 79.05 | 2.81 | ||||||
Note:
(1) Inflation is accounted for at 0% for 2020, and 2% thereafter.
Future Development Costs
FDC reflects the best estimate of the capital cost required to produce the reserves. The FDC associated with the TPP reserves at yearend 2019 is $270 million undiscounted ($189 million discounted at 10%).
| millions $ | PDP | Total Proved | Total Proved plus Probable |
|||
| Total FDC, Undiscounted | 77.7 | 219.8 | 270.3 | |||
| Total FDC, Discounted at 10% | 44.0 | 156.3 | 189.4 |
FDC included at year-end 2019 for CO2 purchases, maintenance and facility capital in PDP, TP and TPP were $77 million, $84 million and $98 million, respectively. This represents 36% of Cardinal’s TPP FDC of $270 million. There are 92 net future locations included in the 2019 Reserve Report (including future CO2 injectors).
Performance Metrics (1)(2)
Cardinal’s FDA costs for 2019, 2018 and the three-year average are presented in the table below. The costs used in the FDA calculation are the capital costs related to: land acquisition and retention, drilling and completions, tangible well site tie-ins and facilities, plus the change in estimated FDC as per the 2019 Reserve Report. Acquisition costs are net of any proceeds from dispositions of properties. The reserves used in this calculation are Company reserve additions, including revisions.
| 2019 FD&A $/boe |
2018 FD&A $/boe |
3 Year Average FD&A $/boe |
||||
| PDP | $18.01 | $4.12 | $11.85 | |||
| TP | $19.57 | $6.86 | $12.35 | |||
| TPP | $20.06 | $7.99 | $11.05 |
Note:
(1) FDA costs are used as a measure of capital efficiency and are calculated by dividing the unaudited development capital expenditures, net of acquisitions and dispositions for the period, including the change in undiscounted inflated FDC, by the change in reserves, incorporating revisions and production for the same period.
(2) FDA calculations are based on Company gross reserves and any royalty interest reserves.
| Debt Adjusted Performance Per Share (1)(2) | ||||||||||||
| Year End 2019 | Year End 2018 | % Change | ||||||||||
| Reserves/Share (boe/debt adjusted share) |
Basic | Diluted | Basic | Diluted | % Change Basic |
% Change Diluted |
||||||
| Proved Producing | 0.34 | 0.33 | 0.31 | 0.31 | 9 | % | 8 | % | ||||
| Total Proved | 0.39 | 0.38 | 0.35 | 0.35 | 11 | % | 11 | % | ||||
| Total Proved and Probable | 0.52 | 0.51 | 0.46 | 0.46 | 12 | % | 11 | % | ||||
| NPV10/Share ($/debt adjusted share) | ||||||||||||
| Proved Producing | 4.54 | 4.44 | 4.27 | 4.21 | 6 | % | 6 | % | ||||
| Total Proved | 4.86 | 4.75 | 4.69 | 4.62 | 4 | % | 3 | % | ||||
| Total Proved and Probable | 6.15 | 6.02 | 5.78 | 5.69 | 6 | % | 6 | % | ||||
| Debt Adjusted Shares | 208,887,632 | 213,501,127 | 237,637,627 | 241,135,537 | ||||||||
Notes:
(1) Debt adjusted shares are based on the closing share price at December 31, 2019 of $2.60/share and December 31, 2018 of $2.22/share and unaudited net debt of $247.6 million at December 31, 2019 and net debt of $269.7 million at December 31, 2018.
(2) Diluted shares include outstanding Restricted Awards,
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (“ESG”)
Since Cardinal’s inception in 2013, we have remained committed to managing and operating our business in a safe, efficient and environmentally responsible manner and we are pleased to illustrate this progress in our inaugural ESG Report.
The ESG Report outlines environmental, safety and social responsibilities that we are committed to as well as our initiatives that support this commitment. In this first report we do not reference any select standards but comment generally on these topics. We plan to expand this reporting in 2020 and beyond.
The ESG Report was approved by our executive team and Board of Directors and is intended to assist our stakeholders to better understand our commitment to operating in a responsible and sustainable manner.
The focus of our ESG Report is on sustainability and stewardship of our assets. Canada is a leader in carbon intensity reduction and Cardinal operates one of the largest carbon storage projects in Canada. Our excellent safety record (zero recordable injury frequency and zero lost time injury frequency) demonstrates that our emphasis on processes and planning is working and reinforces all of our internal ESG focused initiatives.
We hope you will view our full ESG Report on our updated website at: www.cardinalenergy.ca
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