2022 Financial and Operations Highlights:
- Achieved record average annual production of 9,105 boe/d(1) (57% light crude oil and NGLs), an increase of 51% on a debt adjusted per share basis compared to 5,768 boe/d(1) (65% light crude oil and NGLs) in 2021.
- Implemented a monthly base cash dividend of $0.015/share in November 2022 representing only 11% to 13% of forecasted 2023 annual adjusted funds flow (“AFF”)(3) and is forecast to be sustainable at WTI pricing of US$55/bbl through 2025. InPlay also instituted a Normal Course Issuer Bid (“NCIB”) in October 2022, further enhancing our return to shareholder commitment.
- Generated record annual AFF(3) of $131 million ($1.51 per weighted average basic share(4)), an increase of 178% (125% on a per share basis) compared to $47 million ($0.67 per weighted average basic share) in 2021.
- Reduced net debt(3) to $32.9 million, a 59% reduction compared to December 31, 2021 ($80.2 million) and a 28% reduction compared to September 30, 2022 ($45.6 million).
- Exited 2022 at 0.2x net debt to earnings before interest, taxes and depletion (“EBITDA”)(2) achieving the lowest annual leverage ratio in corporate history.
- Generated record free adjusted funds flow (“FAFF”)(2) of $53 million.
- Increased operating netbacks(2) by 33% to an annual record $45.90/boe from $34.63/boe in 2021.
- Realized annual record operating income(2) and operating income profit margin(2) of $153 million and 64% respectively compared to $73 million and 64% in 2021.
- Recognized net income of $83.9 million ($0.97 per basic share; $0.92 per diluted share).
- Renegotiated our Senior Credit Facility to a fully conforming revolving credit facility with an increased total lending capacity and borrowing base of $110 million, providing significant liquidity to be used for tactical capital investment and strategic acquisitions.
- Released our inaugural Sustainability Report highlighting the Company’s significant environmental successes and reaffirming the Company’s commitment to environmental stewardship while safely and efficiently developing our assets.
2022 Reserve Highlights:
- Reserves increased across all categories with organic reserves growth, more than offsetting production, in a year without acquisition/disposition (“A&D”) activity.
- Proved developed producing (“PDP”) reserves increased 31% on a debt adjusted per share basis(2) to 17,653 mboe (57% light and medium crude oil & NGLs)
- Total proved (“TP”) reserves increased 20% on a debt adjusted per share basis to 46,464 mboe (61% light and medium crude oil & NGLs)
- Total proved plus probable (“TPP”) reserves increased 20% on a debt adjusted per share basis to 61,842 mboe (63% light and medium crude oil & NGLs)
- Achieved record NPV BT10 reserve and net asset values (“NAV”)(5):
- NPV BT10:
- PDP: $282 million (37% increase from 2021)
- TP: $631 million (34% increase from 2021)
- TPP: $884 million (29% increase from 2021)
- NAV per share:
- PDP: $3.18 per basic share (72% increase from 2021)
- TP: $7.20 per basic share (46% increase from 2021)
- TPP: $10.11 per basic share (36% increase from 2021)
- NPV BT10:
- InPlay added new light oil weighted production at a capital efficiency(6) of $16,529 per boe/d in a high inflationary environment tracking the three year average of $15,418 per boe/d.
- Successful organic development resulted in strong reserve replacement:
- PDP replacement(6) of 153%
- TP replacement of 117%
- TPP replacement of 136%
- Net Abandonment and Reclamation Obligations spending was $4.5 million, reducing our liability by 4% through the successful abandonment of 31 wellbores and the reclamation of 97 well sites.
Message to Shareholders:
InPlay had a successful year executing our strategy by delivering top-tier production growth, significant debt reduction and meaningful returns to shareholders. Efficient operations and our high quality asset base allowed the Company to generate 51% organic debt adjusted production per share growth. A record $131 million of AFF and $53 million of FAFF was generated during the year and was utilized to reduce net debt 59% from year end 2021 reducing our leverage ratio to 0.2x net debt to EBITDA for 2022. This positioned the Company to implement a return to shareholder strategy commencing with our base monthly dividend and the initiation of a share buyback program. The $0.015 monthly dividend is estimated to be only 11% to 13% of forecasted 2023 AFF based on our 2023 guidance. The Company has maintained one of the lowest debt levels across our industry and peer group, allowing the dividend to be sustainable in a scenario where WTI dropped to US$55/bbl through to the end of 2025. The Company’s significant reserve value and FAFF generation capabilities place InPlay in an advantageous position to capitalize on tactical investment opportunities. InPlay’s 2023 capital program has shifted towards higher oil weighted properties to allow InPlay to capitalize on the positive outlook for crude oil prices compared to the uncertainty surrounding natural gas prices in the upcoming year.
InPlay had a strong year in 2022 replacing reserves and increasing per share net asset value solely through organic growth in a year where InPlay had no significant A&D activity. This was highlighted by a 31% growth in debt adjusted PDP reserves and 72% growth in PDP NAV ($3.18 per share) demonstrating the Company’s ability to create value. InPlay also exited the year with a TP NAV per share of $7.20 and a TPP NAV per share of $10.11 highlighting the compelling value of our assets.
Outlook and Operations Update:
InPlay’s capital program for the first quarter of 2023 was initiated late in December 2022 with the drilling of the first of two (1.6 net) Extended Reach Horizontal (“ERH”) Willesden Green wells on a single pad to take advantage of the availability of services and get ahead of what is expected to be the busiest quarter of activity for the industry in years. These wells were brought on production in early February and the average initial production (“IP”) rates over the first 30 days for these flowing wells were 579 boe/d (73% light crude oil and NGLs).
The Company also drilled another two (1.6 net) ERH Willesden Green wells which were recently brought on production in early March. The average initial production (“IP”) rates for these wells over the first 11 days has been 968 boe/d (85% light crude oil and NGLs).
These four wells were drilled in close proximity and have delivered initial production rates significantly above internal expectations despite being somewhat curtailed due to the high fluid rates and high back pressure in the gathering system in the area, which has also backed out production from older lower pressured offsetting wells. Our first of two upgraded gas facilities in the area is expected to come online in late March which will alleviate back pressure on the gas gathering system. This new facility coupled with natural declines and lower fluid rates as water cuts drop are expected to allow all wells to flow at more optimal levels. This is expected to reduce decline rates throughout the second quarter.
Two (0.3 net) non-operated ERH wells in Willesden Green were brought on production in February. Drilling operations have begun on an additional two (2.0 net) ERH well pad in Pembina which is expected to be brought on production in early April.
InPlay’s capital program for the first half of 2023 includes plans to upgrade two operated gas facilities in Willesden Green, including the first project discussed above, providing InPlay with operated facility capacity that it controls to facilitate production growth and reduce field pressures in the current and upcoming years.
In the first quarter of 2023, the Company had natural gas production curtailments of approximately 4.5 mmcf/d starting February 15th from a third party natural gas facility due to capacity constraints. The impact of this curtailment is not expected to be significant to InPlay as the Company had previously shifted drilling plans away from this area in 2023 due to its higher gas weighted production and the high gas processing fees being charged compared to other regions. The Company responded by shutting in wells with the highest gas weighting, maximizing oil production and AFF in the strong oil pricing environment. Natural decline of production in this field, limited drilling plans from the Company and other operators in the area as well as alternative options currently being finalized are expected to alleviate the impact of this production curtailment. Our estimates of impacted production due to this curtailment is approximately 475 boe/d (68% natural gas) in the first quarter of 2023.
InPlay anticipates that the exceptional well results to date in 2023 and its upcoming drilling program will fully offset the impact of the temporary gas production curtailments and as a result, InPlay continues to reiterate its 2023 annual average production guidance of 9,500 – 10,500 boe/d(1). When considering the impacted production is predominantly gas, and the outperforming new drills have a high oil weighting, the net impact to AFF is anticipated to be minimal. With the continued value add from our high return asset base, a pristine balance sheet and a very low leverage ratio, the Company is optimistic about the potential for continued value add opportunities and increasing returns to shareholders in the upcoming year and beyond.
Financial and Operating Results:
(CDN) ($000’s) |
Three months ended |
Year ended December 31 |
||
2022 |
2021 |
2022 |
2021 |
|
Financial |
||||
Oil and natural gas sales |
58,161 |
37,255 |
238,590 |
113,854 |
Adjusted funds flow(3) |
30,271 |
17,149 |
130,805 |
47,028 |
Per share – basic(4) |
0.35 |
0.23 |
1.51 |
0.67 |
Per share – diluted(4) |
0.33 |
0.22 |
1.44 |
0.66 |
Per boe(4) |
34.19 |
27.87 |
39.36 |
22.34 |
Comprehensive income |
20,736 |
55,191 |
83,896 |
115,071 |
Per share – basic |
0.24 |
0.74 |
0.97 |
1.65 |
Per share – diluted |
0.23 |
0.71 |
0.92 |
1.61 |
Capital expenditures – PP&E and E&E |
13,647 |
6,024 |
77,603 |
33,434 |
Property (dispositions) |
– |
– |
(2) |
(84) |
Net Corporate acquisitions(2) |
(321) |
38,287 |
180 |
38,287 |
Net debt(3) |
(32,963) |
(80,196) |
(32,963) |
(80,196) |
Shares outstanding |
86,952,601 |
86,214,751 |
86,952,601 |
86,214,751 |
Basic weighted-average shares |
87,106,339 |
74,338,118 |
86,895,314 |
69,798,836 |
Diluted weighted-average shares |
91,229,513 |
77,669,551 |
91,137,173 |
71,681,264 |
Operational |
||||
Daily production volumes |
||||
Light and medium crude oil (bbls/d) |
3,909 |
3,156 |
3,766 |
2,981 |
Natural gas liquids (boe/d) |
1,532 |
933 |
1,402 |
782 |
Conventional natural gas (Mcf/d) |
25,090 |
15,590 |
23,623 |
12,030 |
Total (boe/d) |
9,623 |
6,687 |
9,105 |
5,768 |
Realized prices(4) |
||||
Light and medium crude oil & NGLs ($/bbls) |
90.21 |
79.83 |
100.26 |
70.08 |
Conventional natural gas ($/Mcf) |
5.63 |
5.04 |
5.74 |
4.01 |
Total ($/boe) |
65.69 |
60.56 |
71.79 |
54.08 |
Operating netbacks ($/boe)(2) |
||||
Oil and natural gas sales |
65.69 |
60.56 |
71.79 |
54.08 |
Royalties |
(11.72) |
(7.53) |
(11.55) |
(5.51) |
Transportation expense |
(1.26) |
(1.09) |
(1.18) |
(1.11) |
Operating costs |
(14.78) |
(12.51) |
(13.16) |
(12.83) |
Operating netback(2) |
37.93 |
39.43 |
45.90 |
34.63 |
Realized gain (loss) on derivative contracts |
0.17 |
(5.67) |
(1.97) |
(6.20) |
Operating netback (including realized derivative contracts)(2) |
38.10 |
33.76 |
43.93 |
28.43 |
2022 Financial & Operations Overview:
Production averaged 9,105 boe/d (57% light crude oil & NGLs) in 2022, an annual record for the Company and a 58% increase compared to our previous record of 5,768 boe/d (65% light crude oil & NGLs) in 2021. Production averaged 9,623 boe/d (57% light crude oil & NGLs) in the fourth quarter of 2022, a quarterly record for the Company and a 44% increase in comparison to the fourth quarter of 2021. There was a build of 6,100 barrels of oil inventory at year end compared to the end of the third quarter.
InPlay’s capital program for 2022 consisted of $77.6 million of development capital. The Company drilled, completed and brought on production six (6.0 net) ERH wells in Pembina, ten (9.3 net) operated ERH wells and one (0.2 net) non-operated ERH well in Willesden Green and two (2.0 net) Belly River wells. This activity amounted to the drilling of 19 gross (17.5 net) wells for an equivalent of 29.0 gross horizontal miles (26.7 net horizontal miles), our most active year to date. Other capital activity for the year consisted of construction of a modular multi-well oil production facility in Willesden Green to accommodate current and future drilling in the area and construction of two Vapor Recovery Units to increase gas conservation and reduce greenhouse gas emissions. InPlay accelerated the start of its 2023 capital program at the end of 2022 initiating drilling operations on a two well pad in Willesden Green and proactively starting facility and pipeline construction in the fourth quarter of 2022 to bring on production promptly after the completion of wells drilled in the first quarter.
The Company continues to focus on operational efficiency and is proactive in reducing the impact of the inflationary pressures and supply chain disruptions that are impacting the oil and gas industry. Despite the rising costs of services, steel and fuel costs, in addition to third party facility disruptions and processing fee increases, InPlay kept operating costs flat on a boe/d basis year over year even through this significant inflationary period, achieving an annual operating income profit margin(2) record of 64% throughout 2022. Our record production levels and operating netbacks of $45.90/boe resulting in annual record AFF of $131 million ($1.51 per weighted average basic share) during 2022, an increase of 178% compared to 2021. This significant AFF generation was used in lowering net debt by 59% to $32.6 million compared to December 31, 2021 and achieved the lowest annual leverage ratio in our corporate history of 0.2 net debt to EBITDA. In addition, InPlay recognized net income of $83.9 million during 2022, which equates to $0.97 per basic share and $0.92 per diluted share. The record setting financial results in 2022 dramatically improved InPlay’s financial situation, allowing for the implementation of our return to shareholder strategy highlighted by the base monthly dividend, and places the Company in a strong position to capitalize on strategic opportunities going forward.
Notes: |
|
1. |
See “Production Breakdown by Product Type” at the end of this press release. |
2. |
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release. |
3. |
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. |
4. |
Supplementary financial measure. See “Non-GAAP and Other Financial Measures” contained within this press release. |
5. |
See “Corporate Reserves Information” and “Net Asset Value” for detailed information from the Reserve Report and associated NPV and NAV calculations. |
6. |
“FD&A”, “recycle ratio”, “reserve replacement”, “reserve life index” and “capital efficiency” do not have standardized meanings and therefore may not be comparable to similar measures presented for other entities. Refer to section “Performance Measures” for the determination and calculation of these measures. |
2022 Reserves Overview:
As a result of the Company’s continued efficient operational execution and deployment of development capital combined with the high quality of our asset base, InPlay generated reserve growth in all reserve categories compared to 2021. PDP reserves per debt adjusted share increased by 31% in 2022 to 17,653 mboe, TP reserves increased by 20% per debt adjusted share to 46,464 mboe and TPP reserves increased by 20% per debt adjusted share to 61,842 mboe. This reserve based growth more than replaced our 2022 production, with 153% of production being replaced on a PDP basis, 117% on a TP basis and 136% on a TPP basis. This reserve replacement is a strong achievement in a year without A&D activity and hyperinflation, evidencing the long-term sustainability of our current asset base.
This significant reserve growth and improvements to commodity prices resulted in record setting reserve net present values of future net revenues before tax (“NPV BT”) and net asset values per basic share (“NAVPS”) at December 31, 2022. The Company improved NPV BT10 reserve values to $282 million (PDP), $631 million (TP) and $884 million (TPP) using a three independent reserve evaluators average pricing and cost forecast and foreign exchange rates as at December 31, 2022 as used in the Reserve Report. This equates to Net Asset Values of $276 million and $3.18 NAVPS (PDP), $626 million and $7.20 NAVPS (TP) and $879 million and $10.11 NAVPS (TPP)(1), representing 72% (PDP), 46% (TP) and 36% (TPP) growth for each category respectively on a per share basis over 2021.
Note: |
|
1. |
See “Net Asset Value” below for detailed calculations. |
Corporate Reserves Information:
The following summarizes certain information contained in the Reserve Report. The Reserve Report was prepared 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”). Additional reserve information as required under NI 51-101 will be included in the Company’s Annual Information Form (“AIF”) which will be filed on SEDAR by the end of March 2023.
December 31, 2022 |
Light and |
Conventional |
Oil |
BTAX NPV |
Future |
Net Undeveloped |
|
Reserves |
Crude Oil |
NGLs |
Natural Gas |
Equivalent |
10 % |
Capital |
Wells |
Mbbl |
Mbbl |
MMcf |
MBOE |
($000’s) |
($000’s) |
Booked |
|
Proved developed |
6,883.0 |
3,210.5 |
45,354 |
17,652.5 |
281,527 |
347 |
– |
Proved developed non- |
208.4 |
53.1 |
844 |
402.1 |
6,614 |
602 |
– |
Proved undeveloped |
14,369.0 |
3,836.5 |
61,225 |
28,409.6 |
342,759 |
433,398 |
173.8 |
Total proved |
21,460.4 |
7,100.1 |
107,423 |
46,464.2 |
630,900 |
434,347 |
173.8 |
Probable developed |
1,877.9 |
829.3 |
12,065 |
4,717.9 |
61,418 |
355 |
– |
Probable developed |
51.1 |
12.8 |
229 |
102.1 |
983 |
602 |
– |
Probable undeveloped |
6,254.6 |
1,194.6 |
18,649 |
10,557.2 |
190,810 |
85,084 |
26.6 |
Total probable |
8,183.6 |
2,036.7 |
30,943 |
15,377.2 |
253,211 |
86,040 |
26.6 |
Total proved plus |
29,644.0 |
9,136.8 |
138,366 |
61,841.5 |
884,110 |
520,387 |
200.4 |
Notes: |
|
1. |
Reserves have been presented on a gross basis which are the Company’s total working interest (operating and non-operating) share before the deduction of any royalties and without including any royalty interests of the Company. |
2. |
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2022, as outlined in the table herein entitled “Pricing Assumptions”. |
3. |
It should not be assumed that the NPV amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of InPlay’s light and medium crude oil, natural gas liquids and conventional natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual light and medium crude oil, conventional natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. |
4. |
All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment, decommissioning and reclamation costs and estimated future capital expenditures. Future net revenues have been presented on a before tax basis. |
5. |
The Company has included abandonment, decommissioning and reclamation costs for all active and inactive assets including non-producing and suspended wells, facilities and pipelines. December 31, 2022 reserve NPV values are also inclusive of currently enacted carbon taxes. |
6. |
Totals may not add due to rounding. |
Net Asset Value:
December 31, 2022 |
BTAX NPV 5% |
BTAX NPV 10% |
||
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
PDP NPV(1)(2) |
318,050 |
3.66 |
281,527 |
3.24 |
Undeveloped acreage(3) |
27,881 |
0.32 |
27,881 |
0.32 |
Net debt(4)(5) |
(32,963) |
(0.38) |
(32,963) |
(0.38) |
Net Asset Value (basic) |
312,968 |
3.60 |
276,445 |
3.18 |
December 31, 2022 |
BTAX NPV 5% |
BTAX NPV 10% |
||
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
TP NPV(1)(2) |
817,148 |
9.40 |
630,900 |
7.26 |
Undeveloped acreage(3) |
27,881 |
0.32 |
27,881 |
0.32 |
Net debt(4)(5) |
(32,963) |
(0.38) |
(32,963) |
(0.38) |
Net Asset Value (basic) |
812,066 |
9.34 |
625,818 |
7.20 |
December 31, 2022 |
BTAX NPV 5% |
BTAX NPV 10% |
||
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
TPP NPV(1)(2) |
1,171,941 |
13.48 |
884,110 |
10.17 |
Undeveloped acreage(3) |
27,881 |
0.32 |
27,881 |
0.32 |
Net debt(4)(5) |
(32,963) |
(0.38) |
(32,963) |
(0.38) |
Net Asset Value (basic) |
1,166,859 |
13.42 |
879,028 |
10.11 |
Notes: |
|
1. |
Evaluated by Sproule as at December 31, 2022. The estimated NPV does not represent fair market value of the reserves. |
2. |
Based on an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule Associates Limited, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at December 31, 2022. |
3. |
Duvernay land holdings attributed a value of $14.5 million ($1,000/acre) for 14,480 net acres based on internal valuations. The remaining undeveloped acreage is based on an internal valuation of $13.4 million ($258/acre) for 51,795 net acres. These internal valuations are based on land sales in the area. |
4. |
Net debt as at December 31, 2022. |
5. |
Capital management measure. See “Non-GAAP and Other Financial Measures” contained within this press release. |
6. |
Based upon 86,952,601 common shares outstanding as at December 31, 2022. |
Future Development Costs (“FDCs”):
FDCs increased by $18 million on a TP basis and $46 million on a TPP basis compared to the 2021 Reserve Report.
($millions) |
TP |
TPP |
||
2023 |
80.6 |
82.3 |
||
2024 |
100.5 |
106.3 |
||
2025 |
91.9 |
99.8 |
||
2026 |
98.3 |
113.7 |
||
Remainder |
63.0 |
118.3 |
||
Total undiscounted FDC |
434.3 |
520.4 |
||
Total discounted FDC at 10% per year |
350.1 |
410.0 |
Note: FDC as per Reserve Report based on forecast pricing as outlined in the table herein entitled “Pricing Assumptions” |
Performance Measures:
2020 |
2021 |
2022 |
3 Year Avg |
|
Average WTI crude oil price (US$/bbl) |
39.40 |
67.91 |
94.23 |
67.18 |
Capital expenditures – PP&E and E&E ($000’s)(1) |
22,213 |
33,434 |
77,603 |
– |
Production boe/d – FY(3) |
3,985 |
5,768 |
9,105 |
6,286 |
Production boe/d – Q4(3) |
4,259 |
6,687 |
9,623 |
6,856 |
Operating netback $/boe – FY(2) |
11.45 |
34.63 |
45.90 |
35.16 |
Proved Developed Producing |
||||
Total Reserves mboe |
9,677 |
15,890 |
17,653 |
14,407 |
Reserves additions mboe |
2,418 |
8,318 |
5,086 |
15,822 |
FD&A (including FDCs) $/boe(1) |
9.85 |
8.47 |
14.96 |
10.77 |
FD&A (excluding FDCs) $/boe(1) |
9.85 |
8.47 |
14.96 |
10.77 |
Recycle Ratio(4) |
1.2 |
4.1 |
3.1 |
3.3 |
Reserves Replacement(5) |
166 % |
395 % |
153 % |
230 % |
RLI (years)(6) |
6.6 |
7.5 |
5.3 |
6.3 |
Total Proved |
||||
Total Reserves mboe |
21,624 |
45,891 |
46,464 |
37,993 |
Reserves additions mboe |
4,509 |
26,372 |
3,897 |
34,778 |
FD&A (including FDCs) $/boe(1) |
5.86 |
12.03 |
24.04 |
12.58 |
FD&A (excluding FDCs) $/boe(1) |
5.28 |
2.67 |
19.52 |
4.90 |
Recycle Ratio(4) |
2.0 |
2.9 |
1.9 |
2.8 |
Reserves Replacement(5) |
309 % |
1,253 % |
117 % |
505 % |
RLI (years)(6) |
14.8 |
21.8 |
14.0 |
16.5 |
Proved Plus Probable |
||||
Total Reserves mboe |
32,816 |
60,640 |
61,842 |
51,776 |
Reserves additions mboe |
6,980 |
29,929 |
4,525 |
41,434 |
FD&A (including FDCs) $/boe(1) |
8.21 |
9.56 |
27.02 |
11.24 |
FD&A (excluding FDCs) $/boe(1) |
3.41 |
2.36 |
16.81 |
4.11 |
Recycle Ratio(4) |
1.4 |
3.6 |
1.7 |
3.1 |
Reserves Replacement(5) |
479 % |
1,422 % |
136 % |
602 % |
RLI (years)(6) |
22.5 |
28.8 |
18.6 |
22.5 |
In 2022, InPlay’s successful exploration, development and acquisition/disposition capital program achieved a capital efficiency of $16,529 per boe/d and a three year average of $15,418 per boe/d.(7)
Notes: |
|
1. |
Finding, Development & Acquisition (“FD&A”) costs are used as a measure of capital efficiency. The calculation includes the period’s capital expenditures, including Exploration and Development (“E&D”) and Acquisition and Disposition (“A&D”) expended in the year, less capitalized G&A expenses and undeveloped land expenditures acquired with no reserves. This total of capital expenditures, including the change in the FDC over the period, is then divided by the change in reserves, other than from production, for the period incorporating additions/reductions from extensions, infill drilling, technical revisions, acquisitions/dispositions and economic factors. For example: 2022 TPP = ($77.6 million capital expenditures – PP&E and E&E – $1.7 million capitalized G&A – $nil of land acquisitions + $nil property (dispositions) + $0.2 million net corporate acquisitions + $46.2 million change in FDCs) / (61,842 mboe – 60,640 mboe + 3,323 mboe) = $27.02 per boe. Finding and Development Costs (“F&D”) are calculated the same as FD&A costs, however adjusted to exclude the capital expenditures and reserve additions/reductions from acquisition/disposition activity. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
2. |
Non-GAAP financial measure or ratio that does not have a standardized meaning under International Financial Reporting Standards (IFRS) and GAAP and therefore may not be comparable with the calculations of similar measures for other companies. Please refer to “Non-GAAP and Other Financial Measures” contained within this press release. |
3. |
See “Reader Advisories – Production Breakdown by Product Type” |
4. |
Recycle Ratio is calculated by dividing the year’s operating netback per boe by the FD&A costs for that period. For example: 2022 TPP = ($45.90/$27.02) = 1.7. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
5. |
The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year. For example: 2022 TPP = (61,842 mboe – 60,640 mboe + 3,323 mboe) / 3,323 mboe = 136%, which reflects the extent to which the Company was able to replace production and add reserves throughout the year. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
6. |
RLI is calculated by dividing the reserves in each category by the 2022 average annual production. For example 2022 TPP = (61,842 mboe) / (9,105 boe/day) = 18.6 years. See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
7. |
Capital Efficiency is calculated as the total annual exploration & development and acquisition and disposition capital expended in the year, less capitalized G&A and land acquisition costs divided by production additions comparing the fourth quarter of the previous year using a decline rate over the course of the year, calculated as follows: ($77.6 million capital expenditures (PP&E and E&E) – $1.7 million capitalized G&A – $nil of land acquisitions + $nil property (dispositions) + $3.0 million of 2021 capital adding reserves in 2022 – $nil of capital not adding reserves in 2022) / (Q4/2022 production of 9,623boe/d – Q4/2021 production of 6,687 boe/d + 2022 declined production at 28% of 1,839 boe/d). See Information Regarding Disclosure on Oil and Gas Reserves and Operational Information in the Reader Advisories. |
Pricing Assumptions:
The following tables set forth the benchmark reference prices, as at December 31, 2022, reflected in the Reserve Report. These price and cost assumptions were an arithmetic average of the price forecasts of three independent reserve evaluator’s (Sproule, McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then current forecast at the effective date of the Reserve Report.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS (1)
as of December 31, 2022
FORECAST PRICES AND COSTS
Year |
WTI Cushing Oklahoma ($US/Bbl) |
Canadian Light 40o API ($Cdn/Bbl) |
Cromer LSB 35o ($Cdn/Bbl) |
Natural ($Cdn/ MMBtu) |
NGLs Edmonton ($Cdn/Bbl) |
NGLs ($Cdn/Bbl) |
Edmonton Pentanes Plus ($Cdn/Bbl) |
Operating %/Year |
Capital %/Year |
Exchange ($Cdn/$US) |
Forecast(3) |
||||||||||
2023 |
80.33 |
103.77 |
104.27 |
4.23 |
39.80 |
53.88 |
106.22 |
0.0 % |
0.0 % |
0.75 |
2024 |
78.50 |
97.74 |
98.21 |
4.40 |
39.13 |
52.67 |
101.35 |
2.3 % |
2.3 % |
0.77 |
2025 |
76.95 |
95.27 |
95.73 |
4.21 |
39.74 |
51.42 |
98.94 |
2.0 % |
2.0 % |
0.77 |
2026 |
77.61 |
95.58 |
96.03 |
4.27 |
39.86 |
51.61 |
100.19 |
2.0 % |
2.0 % |
0.77 |
2027 |
79.16 |
97.07 |
97.53 |
4.34 |
40.47 |
52.39 |
101.74 |
2.0 % |
2.0 % |
0.78 |
2028 |
80.75 |
99.01 |
99.47 |
4.43 |
41.28 |
53.44 |
103.78 |
2.0 % |
2.0 % |
0.78 |
2029 |
82.36 |
100.99 |
101.46 |
4.51 |
42.11 |
54.51 |
105.85 |
2.0 % |
2.0 % |
0.78 |
2030 |
84.01 |
103.01 |
103.49 |
4.60 |
42.95 |
55.60 |
107.97 |
2.0 % |
2.0 % |
0.78 |
2031 |
85.69 |
105.07 |
105.57 |
4.69 |
43.81 |
56.71 |
110.13 |
2.0 % |
2.0 % |
0.78 |
2032 |
87.40 |
106.69 |
107.19 |
4.79 |
44.47 |
57.56 |
112.33 |
2.0 % |
2.0 % |
0.78 |
2033 |
89.15 |
108.83 |
109.33 |
4.89 |
45.35 |
58.71 |
114.58 |
2.0 % |
2.0 % |
0.78 |
Thereafter Escalation rate of 2.0% |
Notes: |
|
1. |
This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer. |
2. |
The exchange rate used to generate the benchmark reference prices in this table. |
3. |
As at December 31, 2022. |
InPlay would like to thank our employees, board members, lenders and shareholders for their support and contributions in achieving another record setting financial and operational year for the Company. InPlay is proud of the progress made to further strengthen the Company’s financial position and asset base and we look forward delivering on our 2023 budget which is forecast to provide record setting financial and operational results and strong returns to shareholders.
For further information please contact:
Doug Bartole |
Darren Dittmer |
Reader Advisories
Non-GAAP and Other Financial Measures
Throughout this press release and other materials disclosed by the Company, InPlay uses 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 under GAAP and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with GAAP as indicators of the Company performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency and the ability to better analyze InPlay’s business performance against prior periods on a comparable basis.
Non-GAAP Financial Measures and Ratios
Included in this document are references to the terms “free adjusted funds flow”, “operating income”, “operating netback per boe”, “operating income profit margin”, “Net Debt to EBITDA”, “Net Corporate Acquisitions”, “Debt adjusted production per share” and “EV / DAAFF”. Management believes these measures and ratios are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil and natural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than “profit (loss) before taxes”, “profit (loss) and comprehensive income (loss)”, “adjusted funds flow”, “capital expenditures”, “corporate acquisitions, net of cash acquired”, “net debt”, “weighted average number of common shares (basic)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position.
Free Adjusted Funds Flow
Management considers FAFF an important measure to identify the Company’s ability to improve its financial condition through debt repayment and its ability to provide returns to shareholders. FAFF should not be considered as an alternative to or more meaningful than AFF as determined in accordance with GAAP as an indicator of the Company’s performance. FAFF is calculated by the Company as AFF less exploration and development capital expenditures and property dispositions (acquisitions) and is a measure of the cashflow remaining after capital expenditures before corporate acquisitions that can be used for additional capital activity, corporate acquisitions, repayment of debt or decommissioning expenditures or potentially return of capital to shareholders. Refer below for a calculation of historical FAFF and to the “Forward Looking Information and Statements” section for a calculation of forecast FAFF.
(thousands of dollars) |
Three Months Ended December 31 |
Year Ended December 31 |
||
2022 |
2021 |
2022 |
2021 |
|
Adjusted funds flow |
30,271 |
17,149 |
130,805 |
47,028 |
Exploration and dev. capital expenditures |
(13,647) |
(6,024) |
(77,603) |
(33,434) |
Property dispositions (acquisitions) |
– |
– |
2 |
84 |
Free adjusted funds flow |
16,624 |
11,125 |
53,204 |
13,678 |
Operating Income/Operating Netback per boe/Operating Income Profit Margin
InPlay uses “operating income”, “operating netback per boe” and “operating income profit margin” as key performance indicators. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measure of the profitability of operations before administrative, share-based compensation, financing and other non-cash items. Management considers operating income an important measure to evaluate its operational performance as it demonstrates its field level profitability. Operating income should not be considered as an alternative to or more meaningful than net income as determined in accordance with GAAP as an indicator of the Company’s performance. Operating netback per boe is calculated by the Company as operating income divided by average production for the respective period. Management considers operating netback per boe an important measure to evaluate its operational performance as it demonstrates its field level profitability per unit of production. Operating income profit margin is calculated by the Company as operating income as a percentage of oil and natural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its sales revenue. Refer below for a calculation of operating income, operating netback per boe and operating income profit margin.
(thousands of dollars) |
Three Months Ended December 31 |
Year Ended December 31 |
||
2022 |
2021 |
2022 |
2021 |
|
Revenue |
58,161 |
37,255 |
238,590 |
113,854 |
Royalties |
(10,375) |
(4,632) |
(38,392) |
(11,595) |
Operating expenses |
(13,081) |
(7,695) |
(43,740) |
(27,009) |
Transportation expenses |
(1,118) |
(673) |
(3,920) |
(2,346) |
Operating income |
33,587 |
24,255 |
152,538 |
72,904 |
Sales volume (Mboe) |
885.3 |
615.2 |
3,323.4 |
2,105.1 |
Per boe |
||||
Revenue |
65.69 |
60.56 |
71.79 |
54.08 |
Royalties |
(11.72) |
(7.53) |
(11.55) |
(5.51) |
Operating expenses |
(14.78) |
(12.51) |
(13.16) |
(12.83) |
Transportation expenses |
(1.26) |
(1.09) |
(1.18) |
(1.11) |
Operating netback per boe |
37.93 |
39.43 |
45.90 |
34.63 |
Operating income profit margin |
58 % |
65 % |
64 % |
64 % |
Net Debt to EBITDA
Management considers Net Debt to EBITDA an important measure as it is a key metric to identify the Company’s ability to fund financing expenses, net debt reductions and other obligations. EBITDA is calculated by the Company as adjusted funds flow before interest expense. When this measure is presented quarterly, EBITDA is annualized by multiplying by four. When this measure is presented on a trailing twelve month basis, EBITDA for the twelve months preceding the net debt date is used in the calculation. This measure is consistent with the EBITDA formula prescribed under the Company’s Senior Credit Facility. Net Debt to EBITDA is calculated as Net Debt divided by EBITDA. Refer below for a calculation of Net Debt to EBITDA and to the “Forward Looking Information and Statements” section for a calculation of forecast Net Debt to EBITDA.
(thousands of dollars) |
Year Ended December 31 |
|
2022 |
2021 |
|
Adjusted Funds Flow |
130,805 |
47,028 |
Interest expense (Credit Facility and other) |
4,918 |
5,594 |
Interest expense (Lease liabilities) |
25 |
20 |
EBITDA |
135,748 |
52,642 |
Net Debt |
32,963 |
80,196 |
Net Debt to EBITDA |
0.2 |
1.5 |
Net Corporate Acquisitions
Management considers Net corporate acquisitions an important measure as it is a key metric to evaluate the corporate acquisition in comparison to other transactions using the negotiated consideration value and ignoring changes to the fair value of the share consideration between the signing of the definitive agreement and the closing of the transaction. Net corporate acquisitions should not be considered as an alternative to or more meaningful than “Corporate acquisitions, net of cash acquired” as determined in accordance with GAAP as an indicator of the Company’s performance. Net corporate acquisitions is calculated as total consideration with share consideration adjusted to the value negotiated with the counterparty, less working capital balances assumed on the corporate acquisition. Refer below for a calculation of Net corporate acquisitions and reconciliation to the nearest GAAP measure, “Corporate acquisitions, net of cash acquired”.
(thousands of dollars) |
Three Months Ended December 31 |
Year Ended December 31 |
||||
2022 |
2021 |
2022 |
2021 |
|||
Corporate acquisitions, net of cash acquired |
(321) |
29,277 |
180 |
29,277 |
||
Share consideration(1) |
– |
9,985 |
– |
9,985 |
||
Non-cash working capital acquired |
(321) |
(1,156) |
180 |
(1,156) |
||
Derivative contracts |
– |
181 |
– |
181 |
||
Net Corporate acquisitions |
(321)(3) |
38,287 |
180(3) |
38,287 |
(1) |
For purposes of the corporate acquisition, the share consideration had a negotiated value of $1.20 per share. For accounting purposes in accordance with IFRS 3, the shares issued as consideration have been valued at $2.07 per share, based on the closing price of InPlay shares on November 29, 2021. |
(2) |
Net working capital acquired equals the fair value of cash and cash equivalents, accounts receivable and accrued liabilities, prepaid expenses and deposits, inventory, accounts payable and accrued liabilities and derivative contracts acquired as disclosed in note 5 of the Company’s financial statements. |
(3) |
During the year ended December 31, 2022, the acquired amount of Property, plant and equipment was adjusted by $0.2 million as a result of adjustments relating to the acquisition, with a corresponding increase in the recognized amounts of Accounts payable and accrued liabilities. |
Production per Debt Adjusted Share
InPlay uses “Production per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Production per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share is a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Management considers Production per debt adjusted share is a key performance indicator as it adjusts for the effects of changes in annual production in relation to the Company’s capital structure. Refer below for a calculation of Production per debt adjusted share and to the “Forward Looking Information and Statements” section for a calculation of forecast Production per debt adjusted share.
Year Ended December 31 |
||
2022 |
2021 |
|
Production (boe/d) |
9,105 |
5,768 |
Net Debt ($millions) |
32.9 |
80.2 |
Weighted average outstanding shares |
86.9 |
69.8 |
Assumed share price(2) |
3.39 |
|
Production per debt adjusted share growth(1) |
51 % |
(1) |
Production per debt adjusted share is calculated by the Company as production divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. |
(2) |
Weighted average share price throughout 2022. |
EV / DAAFF
InPlay uses “enterprise value to debt adjusted AFF” or “EV/DAAFF” as a key performance indicator. EV/DAAFF is calculated by the Company as enterprise value divided by debt adjusted AFF for the relevant period. Debt adjusted AFF (“DAAFF”) is calculated by the Company as adjusted funds flow plus financing costs. Enterprise value is a capital management measures that is used in the calculation of EV/DAAFF. Enterprise value is calculated as the Company’s market capitalization plus working capital (net debt). Management considers enterprise value a key performance indicator as it identifies the total capital structure of the Company. Management considers EV/DAAFF a key performance indicator as it is a key metric used to evaluate the sustainability of the Company relative to other companies while incorporating the impact of differing capital structures. Refer to the “Forward Looking Information and Statements” section for a calculation of forecast EV/DAAFF.
Reserves per Debt Adjusted Share
InPlay uses “Reserves per debt adjusted share” as a key performance indicator. Debt adjusted shares should not be considered as an alternative to or more meaningful than common shares as determined in accordance with GAAP as an indicator of the Company’s performance. Debt adjusted shares is a non-GAAP measure used in the calculation of Reserves per debt adjusted share and is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. Debt adjusted shares should not be considered as an alternative to or more meaningful than weighted average number of common shares (basic) as determined in accordance with GAAP as an indicator of the Company’s performance. Management considers Debt adjusted share is a key performance indicator as it adjusts for the effects of capital structure in relation to the Company’s peers. Reserves per debt adjusted share is calculated by the Company as reserves divided by debt adjusted shares. Management considers Reserves per debt adjusted share is a key performance indicator as it adjusts for the effects of changes in annual reserves in relation to the Company’s capital structure. Refer below for a calculation of Reserves per debt adjusted share.
Year Ended December 31 |
||||||
PDP |
TP |
TPP |
||||
2022 |
2021 |
2022 |
2021 |
2022 |
2021 |
|
Reserves (mboe) |
17,653 |
15,890 |
46,464 |
45,891 |
61,842 |
60,640 |
Net Debt ($millions) |
32.9 |
80.2 |
32.9 |
80.2 |
32.9 |
80.2 |
Year end shares outstanding |
87.0 |
86.2 |
87.0 |
86.2 |
87.0 |
86.2 |
Assumed share price(2) |
3.39 |
3.39 |
3.39 |
|||
Reserves per debt adjusted share growth(1) |
31 % |
20 % |
20 % |
(1) |
Reserves per debt adjusted share is calculated by the Company as reserves divided by debt adjusted shares. Debt adjusted shares is calculated by the Company as common shares outstanding plus the change in net debt divided by the Company’s current trading price on the TSX, converting net debt to equity. |
(2) |
Weighted average share price throughout 2022. |
Capital Management Measures
Adjusted Funds Flow
Management considers adjusted funds flow to be an important measure of InPlay’s ability to generate the funds necessary to finance capital expenditures. Adjusted funds flow is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2022. All references to adjusted funds flow throughout this document are calculated as funds flow adjusting for decommissioning expenditures and transaction and integration costs. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets and transaction costs are non-recurring costs for the purposes of an acquisition, making the exclusion of these items relevant in Management’s view to the reader in the evaluation of InPlay’s operating performance. The Company also presents adjusted funds flow per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of profit (loss) per common share.
Net Debt / Working Capital
Net debt / working capital is a GAAP measure and is disclosed in the notes to the Company’s consolidated financial statements for the year ending December 31, 2022, and the most recently filed quarterly financial statements. The Company closely monitors its capital structure with a goal of maintaining a strong balance sheet to fund the future growth of the Company. The Company monitors net debt / working capital as part of its capital structure. The Company uses net debt / working capital (bank debt plus accounts payable and accrued liabilities less accounts receivables and accrued receivables, prepaid expenses and deposits and inventory) as an alternative measure of outstanding debt. Management considers net debt / working capital an important measure to assist in assessing the liquidity of the Company.
Supplementary Measures
“Average realized crude oil price” is comprised of crude oil commodity sales from production, as determined in accordance with IFRS, divided by the Company’s crude oil production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized NGL price” is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company’s NGL production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized natural gas price” is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company’s natural gas production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Average realized commodity price” is comprised of commodity sales from production, as determined in accordance with IFRS, divided by the Company’s production. Average prices are before deduction of transportation costs and do not include gains and losses on financial instruments.
“Adjusted funds flow per weighted average basic share” is comprised of adjusted funds flow divided by the basic weighted average common shares.
“Adjusted funds flow per weighted average diluted share” is comprised of adjusted funds flow divided by the diluted weighted average common shares.
“Adjusted funds flow per boe” is comprised of adjusted funds flow divided by total production.