Financial Summary
Three months ended |
Twelve months ended |
|||||
(Cdn$ thousands, except per share, share and per |
Dec 31, |
Dec 31, |
Sep 30, |
Dec 31, |
Dec 31, |
|
FINANCIAL |
||||||
Funds from operations (1) |
8,253 |
13,738 |
10,848 |
33,429 |
61,842 |
|
Per boe |
15.41 |
21.68 |
20.09 |
17.24 |
24.34 |
|
Per weighted average basic share |
0.04 |
0.06 |
0.05 |
0.15 |
0.28 |
|
Cash flows from operating activities |
8,016 |
11,401 |
8,864 |
30,217 |
49,876 |
|
Net income (loss) |
39,349 |
(8,045) |
(1,157) |
(77,324) |
(5,680) |
|
Per weighted average basic share |
0.18 |
(0.04) |
(0.01) |
(0.36) |
(0.03) |
|
Capital expenditures |
386 |
12,603 |
715 |
12,441 |
36,989 |
|
Decommissioning liabilities settled (2) |
726 |
889 |
87 |
1,505 |
2,932 |
|
Net acquisitions (dispositions) (3) |
– |
109 |
– |
3 |
(976) |
|
Net debt (1) |
52,864 |
69,752 |
60,544 |
52,864 |
69,752 |
|
Weighted average shares, basic (thousands) |
216,490 |
218,365 |
216,490 |
216,545 |
218,887 |
|
Shares outstanding, end of period (thousands) |
216,490 |
217,610 |
216,490 |
216,490 |
217,610 |
|
OPERATING |
||||||
Production |
||||||
Heavy oil (bbl/d) |
3,236 |
4,034 |
3,321 |
2,985 |
4,053 |
|
Light and medium oil (bbl/d) |
1,657 |
1,763 |
1,746 |
1,507 |
1,963 |
|
Natural gas liquids (bbl/d) |
182 |
269 |
174 |
169 |
238 |
|
Natural gas (mcf/d) |
4,477 |
4,935 |
3,761 |
3,825 |
4,252 |
|
Total (boe/d) |
5,821 |
6,888 |
5,868 |
5,298 |
6,962 |
|
Average prices |
||||||
Heavy oil ($/bbl) |
36.16 |
49.17 |
40.27 |
32.64 |
53.87 |
|
Light and medium oil ($/bbl) |
48.10 |
64.82 |
47.61 |
45.41 |
66.69 |
|
Natural gas liquids ($/bbl) |
26.02 |
22.79 |
20.30 |
19.56 |
22.26 |
|
Natural gas ($/mcf) |
2.69 |
2.36 |
2.25 |
2.24 |
1.63 |
|
Netback ($/boe) |
||||||
Commodity and other sales |
36.68 |
47.97 |
39.00 |
33.55 |
51.94 |
|
Royalties |
(4.38) |
(5.52) |
(3.48) |
(3.51) |
(5.71) |
|
Transportation costs |
(1.96) |
(2.16) |
(2.71) |
(2.20) |
(2.20) |
|
Operating costs |
(14.83) |
(15.77) |
(13.60) |
(14.80) |
(15.78) |
|
Operating netback (1) |
15.51 |
24.52 |
19.21 |
13.04 |
28.25 |
|
Realized risk management gain (loss) |
4.67 |
0.58 |
5.35 |
8.85 |
(0.12) |
|
General and administrative |
(2.41) |
(2.13) |
(2.28) |
(2.67) |
(2.17) |
|
Interest |
(2.25) |
(1.30) |
(2.19) |
(2.00) |
(1.65) |
|
Realized (loss) gain on foreign exchange |
(0.11) |
0.01 |
– |
0.02 |
0.03 |
|
TRADING STATISTICS ($ based on intra-day trading) |
||||||
High |
0.31 |
0.48 |
0.25 |
0.50 |
0.88 |
|
Low |
0.15 |
0.26 |
0.14 |
0.08 |
0.26 |
|
Close |
0.29 |
0.46 |
0.16 |
0.29 |
0.46 |
|
Average daily volume (thousands) |
320 |
529 |
275 |
510 |
418 |
|
(1) |
Funds from operations, net debt and operating netback are non-GAAP measures and are reconciled to the nearest GAAP measures under the heading “Non-GAAP Measures” in Gear’s MD&A. |
(2) |
Decommissioning liabilities settled includes expenditures made by both Gear and the Federal Site Rehabilitation Program. |
(3) |
Net acquisitions (dispositions) exclude non-cash items for decommissioning liability and deferred taxes and is net of post-closing adjustments. |
MESSAGE TO SHAREHOLDERS
The fourth quarter of 2020 provided continued recovery from the setbacks experienced earlier in the year as the result of an oil price war and a Covid-induced global economic downturn. After coming into the year with strong oil prices and an ambitious $50 million capital budget, the Gear team was quick to respond to the commodity price downturn by deferring both production and capital spending while waiting out the uncertainty. With a solid commodity price recovery having recently occurred, the Company is now well positioned to resume its strategies and planned activities to capitalize on its depth of opportunities.
Gear halted its drilling program in early March 2020 after only 9 wells, and in April, Gear materially reduced costs and was well on the way to shutting in and storing oil to preserve value through the low oil price period. Through these defensive moves, Gear was able to not only preserve, but also improve the economic foundation of the company. By the end of 2020, the Company restarted the majority of its shut-in production, sold stored oil at significantly higher prices and reduced outstanding net debt by over 24 per cent from year end 2019. In addition, Gear completed the semi-annual borrowing base redetermination of its syndicated credit facilities with a maturity extension to May 2022 and negotiated the extension of the outstanding convertible debentures to 2023. The drilling activity that was completed during 2020 included a combination of low-risk infill drilling, core area step-out drilling and the exciting first-well discovery of a new medium oil play in Provost, Alberta . with multi-well potential.
Gear’s current $20 million capital budget for 2021 builds on the recent sector recovery and includes multiple follow up drilling and waterflooding activities to further advance upon prior year’s success. Underpinning these operational activities, oil prices have increased significantly, with WTI moving up from US$35.79 per barrel on October 30, 2020 to today’s price of over US$60 per barrel, a level not seen in well over a year. Heavy oil differentials also continue to narrow with the forward curve approaching a Western Canadian Select heavy oil differential of US$11 per barrel this summer. All of this has translated into a forecast of 2021 funds from operations (“FFO”) that is more than twice the current guided 2021 capital expenditures.
Whereas 2020 was dominantly a defensive year of survival for many junior oil weighted producers, 2021 is shaping up to be a year of opportunity, where Gear should again have the option of balancing excess FFO towards multiple strategic directions including continued debt reduction, accelerated capital investment and associated growth or other returns to shareholders. Although the price recovery is still relatively recent (and we will continue to monitor it diligently), the Gear team is very excited and poised for the opportunity to refocus efforts again towards creating value for its shareholders in 2021 and beyond.
FOURTH QUARTER HIGHLIGHTS
2020 HIGHLIGHTS
2021 OUTLOOK
2021 |
Strip pricing as |
WTI US$50 |
WTI US$55 |
WTI US$60 |
WTI US$65 |
Forecasted FFO |
46 |
34 |
42 |
48 |
53 |
Forecasted Net |
26 |
38 |
30 |
24 |
19 |
Forecasted Net |
0.6 |
1.1 |
0.7 |
0.5 |
0.4 |
WTI sensitivities are run from February to December 2021 and assume a WCS diff of US$12, an MSW and LSB diff of US$4, an FX of $0.79US/Cdn, and AECO of C$2.80/GJ. |
Q1 2021 |
Q2 2021 |
Q3 2021 |
Q4 2021 |
|
Commodity |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
Price ($/bbl) |
U$35x42x50 |
C$45x55x70.50 |
C$45x55x74 |
C$45x55x74 |
Volume (bbl/d) |
1,300 |
1,100 |
800 |
800 |
Commodity |
WTI Oil Enhanced |
WTI Oil Enhanced |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
Price ($/bbl) |
U$46.50 w/ U$35 sold |
C$65.85 w/ $C50 sold |
C$45x55x71 |
C$45x55x71 |
Volume (bbl/d) |
800 |
1,200 |
800 |
800 |
Commodity |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
WTI Oil 3-way collar |
|
Price ($/bbl) |
C$45x55x83 |
C$45x55x83 |
C$45x55x83 |
|
Volume (bbl/d) |
300 |
400 |
400 |
|
Commodity |
AECO Swap |
AECO Swap |
AECO Swap |
AECO Swap |
Price ($/GJ) |
2.75 |
2.75 |
2.75 |
2.75 |
Volume (GJ/d) |
2,400 |
2,400 |
2,400 |
2,400 |
Total (boe/d) |
2,479 |
2,979 |
2,379 |
2,379 |
YEAR END RESERVES EVALUATION
During 2020, Gear responded to the unprecedented commodity price weakness and volatility by curtailing its planned $50 million budget in early March. Gear generated $33.4 million of funds from operations in 2020 and reinvested only $13.4 million, or 40 per cent, consisting of $12.4 million of development capital and $1.0 million directed towards abandonment and reclamation activities (not including any government funding provided during the year). The limited capital investment resulted in a 24 per cent reduction in outstanding net debt at the expense of a decrease in annual production and reserves year-over-year.
Compounding the reduction in reserves as a result of declines, was a significant reduction in the evaluator average price forecast that negatively impacted net present values and reserves amounts due to economic limit cut-offs. New Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) recommendations state that evaluator’s price forecasts should now be within 20 per cent of the strip price forecast at year end. In this case, the average evaluator forecast for the WTI oil price was 2.4 per cent lower than the strip price for 2021, 7.3 per cent higher for 2022 and16 per cent higher for 2023. Although this evaluator forecast could have been considered reasonable at the time, the forecast for WTI is disjointed from prevailing market realities and is now over US$10 per barrel lower than the current forward strip for 2021 and does not achieve current spot price levels of approximately US$60 per barrel until the year 2029.
Consistent with 2019, and as per guidance in the COGE Handbook, the independent reserves report includes the full corporate abandonment and reclamation costs (‘ARO’), including all of the ARO associated with both active and inactive wells regardless of whether such wells had any attributed reserves.
For details on the annual operating results please see the Management’s Discussion and Analysis (“MD&A”) dated February 17, 2021, which is available on SEDAR at www.sedar.com.
RESERVES SUMMARY
Year-end 2020 reserves were evaluated by independent reserves evaluator Sproule Associates Ltd. (“Sproule”) in accordance with the definitions, standards and procedures contained in the COGE Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). A reserves committee, comprised of independent board members, reviews the qualifications and appointment of the independent reserves evaluator and reviews the procedures for providing information to the evaluators. The reserves evaluation was based on an average of price forecasts prepared by Sproule, GLJ Petroleum Consultants Ltd. and McDaniel & Associates Consulting Ltd. effective at January 1, 2021. Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without inclusion of any royalty interests) unless noted otherwise. Additional reserves information required under NI 51-101 will be included in Gear’s Annual Information Form to be filed on SEDAR on or before March 31, 2021.
The following tables outline Gear’s reserves as at December 31, 2020. No provision for interest, risk management contracts, debt service charges and general and administrative expenses have been made and it should not be assumed that the net present values of the reserves estimated by Sproule represents the fair market value of the reserves.
Reserves Summary at Dec 31, 2020 Using Sproule Costs and Jan 1, 2021 Evaluator Average Forecast Prices
Company Gross |
Light & (Mbbl) |
Heavy Oil (Mbbl) |
NGL’s (Mbbl) |
Natural (MMcf) |
Equivalent (Mboe) |
Liquids (%) |
Proved Developed Producing5 |
3,406 |
2,483 |
302 |
6,085 |
7,205 |
86 |
Proved Non-Producing & Undeveloped |
2,310 |
2,950 |
142 |
2,342 |
5,793 |
93 |
Total Proved |
5,716 |
5,433 |
444 |
8,427 |
12,998 |
89 |
Probable Developed Producing |
1,397 |
937 |
110 |
2,204 |
2811 |
87 |
Probable Non-Producing & Undeveloped |
3,258 |
3,744 |
142 |
3,270 |
7,689 |
93 |
Total Probable |
4,655 |
4,681 |
252 |
5,474 |
10,500 |
91 |
Total Proved plus Probable |
10,371 |
10,114 |
696 |
13,901 |
23,498 |
90 |
Net Present Value of Future Revenues Including Full ARO Before Income Taxes Under Forecast Prices and Costs
Company Gross |
Undiscounted |
Discounted |
Discounted |
Discounted |
Discounted |
($ thousands) |
@ 5% |
@ 10% |
@ 15% |
@ 20% |
|
Proved Developed Producing |
15,014 |
66,883 |
73,787 |
71,463 |
67,414 |
Proved Non-Producing & Undeveloped |
72,993 |
50,602 |
35,528 |
25,158 |
17,802 |
Total Proved |
88,007 |
117,485 |
109,315 |
96,621 |
85,216 |
Probable Developed Producing |
60,632 |
55,057 |
41,548 |
32,591 |
26,745 |
Probable Non-Producing & |
135,894 |
95,536 |
69,402 |
51,810 |
39,478 |
Total Probable |
196,526 |
150,593 |
110,950 |
84,401 |
66,223 |
Total Proved plus Probable |
284,533 |
268,079 |
220,265 |
181,022 |
151,439 |
Net Future Development Costs (“FDC”) Under Forecast Prices and Costs
($ thousands) |
Proved |
Probable |
Total |
2021 |
13,545 |
4,954 |
18,499 |
2022 |
26,498 |
39,125 |
65,623 |
2023 |
29,915 |
31,297 |
61,212 |
2024 |
27,858 |
18,817 |
46,675 |
2025 |
12,405 |
7,254 |
19,659 |
Subsequent Years |
0 |
8,186 |
8,186 |
Undiscounted Total |
110,221 |
109,633 |
219,854 |
Discounted at 10% |
87,553 |
86,256 |
173,809 |
EFFICIENCY RATIOS
2020 |
2019 |
||||
Reserves (mboes), Capital ($ thousands) |
Proved |
Proved plus |
Proved |
Proved plus |
|
Development Reserves Additions |
(1,186) |
(1,732) |
1,659 |
981 |
|
Net Acquisition Reserves Additions |
(127) |
(346) |
1 |
40 |
|
Total Reserves Additions |
(1,313) |
(2,078) |
1,660 |
1,021 |
|
Development capital |
11,775 |
11,775 |
36,948 |
36,984 |
|
Development change in FDC |
(41,825) |
(41,082) |
(2,385) |
(4,880) |
|
Total development capital including FDC |
(30,050) |
(29,307) |
34,563 |
32,068 |
|
Net acquisition capital |
3 |
3 |
(937) |
(937) |
|
Net acquisition change in FDC |
0 |
0 |
0 |
0 |
|
Total net acquisition capital including FDC |
3 |
3 |
(937) |
(937) |
|
Total capital |
11,778 |
11,778 |
36,012 |
36,012 |
|
Total change in FDC |
(41,825) |
(41,082) |
(2,385) |
(4,880) |
|
Total capital including FDC |
(30,047) |
(29,304) |
33,627 |
31,131 |
|
Estimated Future Finding and Development Costs
Proved |
Proved plus |
|
Future Development Costs ($ thousands) |
110,221 |
219,854 |
Undeveloped and Non-producing Reserves (Mboe) |
5,793 |
13,482 |
Future Finding and Development Costs ($/boe) |
19.03 |
16.31 |
Reserves Life Index (“RLI”)
(years) |
2020 |
2019 |
2018 |
Proved Developed Producing |
4.3 |
4.2 |
3.9 |
Total Proved |
6.9 |
6.6 |
5.4 |
Total Proved plus Probable |
10.7 |
9.4 |
7.7 |
RESERVES RECONCILIATION
Reserves Reconciliation Company Gross |
Heavy Oil |
Light & (Mbbl) |
Natural |
Natural |
Oil |
||
Proved Producing |
|||||||
Opening Balance, January 1, 2020 |
3,348 |
3,913 |
6,827 |
464 |
8,861 |
||
Technical Revisions |
336 |
92 |
1,001 |
(81) |
513 |
||
Drilling Extensions |
125 |
94 |
59 |
– |
229 |
||
Infill Drilling |
– |
– |
– |
– |
– |
||
Improved Recovery |
– |
43 |
41 |
– |
51 |
||
Acquisitions |
– |
12 |
16 |
1 |
16 |
||
Dispositions |
– |
(14) |
(14) |
(2) |
(19) |
||
Economic Factors |
(233) |
(183) |
(451) |
(18) |
(508) |
||
Production |
(1,093) |
(551) |
(1,394) |
(62) |
(1,938) |
||
Closing Balance, December 31, 2020 |
2,483 |
3,406 |
6,085 |
302 |
7,205 |
||
Total Proved |
|||||||
Opening Balance, January 1, 2020 |
6,906 |
6,882 |
10,540 |
705 |
16,249 |
||
Technical Revisions |
47 |
516 |
378 |
(142) |
485 |
||
Drilling Extensions |
328 |
183 |
216 |
2 |
549 |
||
Infill Drilling |
– |
16 |
19 |
2 |
21 |
||
Improved Recovery |
– |
43 |
41 |
1 |
51 |
||
Acquisitions |
– |
12 |
16 |
1 |
16 |
||
Dispositions |
(109) |
(25) |
(26) |
(4) |
(143) |
||
Economic Factors |
(646) |
(1,360) |
(1,363) |
(59) |
(2,292) |
||
Production |
(1,093) |
(551) |
(1,394) |
(62) |
(1,938) |
||
Closing Balance, December 31, 2020 |
5,433 |
5,716 |
8,427 |
444 |
12,998 |
||
Proved plus Probable |
|||||||
Opening Balance, January 1, 2020 |
12,705 |
11,242 |
15,201 |
1,033 |
27,515 |
||
Technical Revisions |
(631) |
149 |
620 |
(232) |
(611) |
||
Drilling Extensions |
497 |
307 |
212 |
1 |
841 |
||
Infill Drilling |
– |
– |
– |
– |
0 |
||
Improved Recovery |
– |
72 |
62 |
1 |
83 |
||
Acquisitions |
– |
16 |
22 |
2 |
22 |
||
Dispositions |
(321)- |
(35) |
(36) |
(5) |
(368) |
||
Economic Factors |
(1,043) |
(829) |
(786) |
(42) |
(2,046) |
||
Production |
(1,093) |
(551) |
(1,394) |
(62) |
(1,938) |
||
Closing Balance, December 31, 2020 |
10,114 |
10,371 |
13,901 |
696 |
23,498 |
FORECAST PRICES AND COSTS
Sproule has adopted changes to the COGE Handbook that are expected to come into effect in April 2021. This updated pricing guidance recommends that forecasting not deviate more than 20% from the current strip pricing for the first two years of the forecast. Discretion can be incorporated for the third year based upon the judgement of the issuer. Pricing beyond the third year should be adjusted by forecasted inflation in the given year.
The evaluator average crude oil and natural gas benchmark reference pricing, inflation, and exchange rates was utilized again this year by Sproule. Gear’s main product components under Sproule’s evaluator average forecast are down 26 to 28 per cent from the previous year’s price forecast. The Sproule evaluator average forecast at December 31, 2020 is as follows:
Year |
Inflation (%) |
Exchange (USD/CAD) |
WTI Cushing (40 API) (USD/bbl) |
Edmonton (40 API) (CAD/bbl) |
WCS (21 API) (CAD/bbl) |
AECO/NIT (CAD/mmbtu) |
2021 |
0.00 |
0.77 |
47.17 |
55.76 |
44.63 |
2.78 |
2022 |
1.33 |
0.77 |
50.17 |
59.89 |
48.18 |
2.70 |
2023 |
2.00 |
0.76 |
53.17 |
63.48 |
52.10 |
2.61 |
2024 |
2.00 |
0.76 |
54.97 |
65.76 |
54.10 |
2.65 |
2025 |
2.00 |
0.76 |
56.07 |
67.13 |
55.19 |
2.70 |
2026 |
2.00 |
0.76 |
57.19 |
68.53 |
56.29 |
2.76 |
2027 |
2.00 |
0.76 |
58.34 |
69.95 |
57.42 |
2.81 |
2028 |
2.00 |
0.76 |
59.50 |
71.40 |
58.57 |
2.87 |
2029 |
2.00 |
0.76 |
60.69 |
72.88 |
59.74 |
2.92 |
2030 |
2.00 |
0.76 |
61.91 |
74.34 |
60.93 |
2.98 |
2031+ |
2.00 |
0.76 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
[/expand]