InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the
“Company”) announces its record setting financial and operating
results for the three and twelve months ended December 31, 2021,
and the results of its independent oil and gas reserves evaluation
effective December 31, 2021 (the “Reserve Report”) prepared by
Sproule Associates Limited (“Sproule”). InPlay’s audited annual
financial statements and notes, as well as Management’s Discussion
and Analysis (“MD&A”) for the year ended December 31, 2021 will
be available at “www.sedar.com” and our website at
“www.inplayoil.com”.
2021 Highlights:
- Completed the
acquisition of Prairie Storm Resources Corp. on November 30,
2022 at attractive transaction metrics which enhances InPlay’s
position as a sizable producer and acreage holder with a deep and
highly economic drilling inventory in the light oil window of
Central Alberta's Cardium fairway.
- Achieved record
average annual production of 5,768 boe/d(1) (65% light crude oil
and NGLs), an increase of 45% from 2020 at 3,985 boe/d(1) (68%
light crude oil and NGLs) and an increase of 15% compared to
pre-COVID levels of 5,000 boe/d(1) (66% light crude oil and NGLs)
in 2019. Annual average production per weighted average basic share
increased 31% compared to 2020.
- Generated record
annual adjusted funds flow (“AFF”)(2) of $47.0 million ($0.67 per
weighted average basic share(3)), an increase of 532% compared to
$7.4 million ($0.11 per weighted average basic share) in 2020 and
an increase of 45% compared to $32.5 million ($0.48 per weighted
average basic share) in 2019, our prior record year. Excluding the
impact of realized hedging losses, AFF for 2021 would have been
$59.9 million.
- Increased
operating netbacks(4) by 203% to $34.63/boe from $11.45/boe in 2020
and 52% from $22.75/boe in 2019.
- Realized annual
record operating income(4) and operating income profit margin(4) of
$72.9 million and 64% respectively compared to $16.7 million and
40% in 2020; $41.5 million and 55% in 2019.
- Reduced
operating expenses to an annual record $12.83/boe compared to
$14.43/boe in 2020 and $14.36/boe in 2019, despite rising costs of
services in the industry.
- Generated annual
free adjusted funds flow (“FAFF”)(4) of $13.6 million.
- Lowered annual
net debt(2) to earnings before interest, taxes and depletion
(“EBITDA”)(4) ratio to 1.5, compared to 6.7 in 2020 and 1.6 in
2019. Fourth quarter 2021 annualized net debt to EBITDA ratio was
1.1 compared to 4.0 in 2020 and 1.6 in 2019 achieving the lowest
leverage ratios in our corporate history.
- Achieved
significant growth in reserves and reserves per weighted average
basic share:
- Proved developed
producing (“PDP”) reserves increased 64% (61% per weighted average
basic share) to 15,890 mboe (58% light and medium crude oil &
NGLs)
- Total proved
(“TP”) reserves increased 112% (106% per weighted average basic
share) to 45,891 mboe (62% light and medium crude oil &
NGLs)
- Total proved
plus probable (“TPP”) reserves increased 85% (81% per weighted
average basic share) to 60,640 mboe (63% light and medium crude oil
& NGLs)
- Achieved record
NPV BT10 reserve and net asset values (“NAV”)(6):
- NPV BT10: $206
million (PDP), $471 million (TP) and $686 million (TPP)
- NAV: $1.85 per
weighted average basic share (PDP), $4.92 per weighted average
basic share (TP) and $7.41 per weighted average basic share
(TPP)
- West Texas
Intermediate (“WTI”) prices used in the Reserve Report to value the
Company’s reserves are approximately 22% and 15% less than current
strip pricing for 2022 (US $72.83 vs. approximately US $89.00) and
2023 (US $68.78 vs. approximately US $79.00) respectively.
- Finding,
Development and Acquisition (“FD&A”)(5) costs, associated
recycle ratios and capital efficiencies which are top tier amongst
light oil weighted peers.
- FD&A(5)
costs of $8.47/boe (PDP), $12.03/boe (TP) and $9.56/boe (TPP),
consistent with three year averages of $9.67/boe (PDP), $10.98/boe
(TP) and $9.23 (TPP).
- Recycle
ratios(5) of 4.1 (PDP), 2.9 (TP) and 3.6 (TPP) compared to 1.2
(PDP), 2.0 (TP) and 1.4 (TPP) in 2020.
- InPlay added new
light oil weighted production at a capital efficiency(5) of $12,583
per boe/d.
- Materially
increased the reserve life index of our assets which in turn
improves the long term sustainability of the Company:
- PDP reserve life
index(5) of 7.5 years compared to 6.6 years in 2020
- TP reserve life
index of 21.8 years compared to 14.8 years in 2020
- TPP reserve life
index of 28.8 years compared to 22.5 years in 2020
- Successful
development and A&D activity resulting in top-tier reserve
replacement(5):
- PDP replacement
of 395% (2020 – 166%)
- TP replacement
of 1,253% (2020 – 309%)
- TPP replacement
of 1,422% (2020 – 479%)
- Increased
liquidity through an increased capacity within our Senior Credit
Facility from $65.0 million to $85.0 million and total debt
capacity of $111 million.
- Abandonment and
Reclamation Obligations spending of $2.3 million, reducing our
liability by 3% through the successful abandonment of 75 wellbores
and the reclamation of 22 well sites.
- Achieved a 20%
reduction to the Company’s emissions (Scope 1 and 2) on a per boe
basis compared to 2020.
Notes:
- See “Reader
Advisories - Production Breakdown by Product Type”
- Capital
management measure. See “Non-GAAP and Other Financial Measures”
contained within this press release.
- Supplementary
financial measure. See “Non-GAAP and Other Financial Measures”
contained within this press release.
- 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”.
- “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.
- See “Corporate
Reserves Information” and “Net Asset Value” for detailed
information from the Reserve Report and associated
calculations.
Message to Shareholders:
The Company exited 2021 in its best operational
and financial position to date. The disciplined and measured steps
taken during 2020 and 2021, allowed us to implement a strategy
focused on measured growth combined with generating strong
free adjusted funds flow once oil prices began to recover in
mid-2021. InPlay initially directed its free adjusted funds flow to
debt reduction ensuring a strong and sustainable balance sheet from
which to grow the Company. The strategy led to record annual AFF of
$47.0 million and record annual FAFF of $13.6 million for the year
while also reducing net debt, resulting in InPlay’s lowest historic
leverage ratios. As the Company solidified its financial position,
the strategy evolved to the point where InPlay was able to evaluate
and execute upon accretive acquisition opportunities. Following up
on a small but highly successful tuck-in acquisition during Q4 2020
(where InPlay grew production from 300 boe/d to 2,900 boe/d(2) in
Q4 2021), InPlay closed the highly accretive corporate
acquisition of Prairie Storm Resources Corp. on November 30, 2022.
This acquisition enhanced the Company’s sustainability by adding
low decline production, sizeable economic drilling inventory that
complements InPlay’s own high internal rate of return, quick
payout inventory, and increased reserve life while also adding
material scale to the Company. All of these attributes enhance
InPlay’s ability to grow and to continue to generate sustained long
term FAFF per share(1). Immediately post closing, InPlay started
drilling two wells on the Prairie Storm lands with results
exceeding our expectations, confirming our technical evaluation of
the assets. InPlay management is proud to be able to consistently
deliver top tier reserve, production and AFF per share growth while
also generating significant FAFF per share growth.
The Company’s sustainability has improved
significantly with a very strong weighting of PDP reserves relative
to TP and TPP reserves which now represent approximately 35% and
26% of the Company’s TP and TPP reserves respectively, with
long-life reserves providing RLI’s of 7.5 years (PDP), 21.8 years
(TP) and 28.8 years (TPP). InPlay’s long life reserves combined
with the expected 2022 PDP base production decline rate of 23.2%
(compared to 25.9% in 2021) puts the Company in a solid position to
sustainably deliver long term per share growth and shareholder
returns.
InPlay continued to deliver on our track record
of drilling efficiency, operational expertise and accretive
strategic acquisition activity, driving attractive light oil
reserve addition metrics. FD&A costs per boe were $8.47, $12.03
and $9.56 in PDP, TP and TPP reserve categories respectively. These
costs were consistent with InPlay’s three year FD&A averages of
$9.67/boe (PDP), $10.98/boe (TP) and $9.23 (TPP). The Prairie Storm
acquisition provided highly accretive and economic reserve
additions that are expected to generate strong production and FAFF
growth. The 2021 capital program continued to convert the Company’s
high quality drilling inventory into reliable cash flow capital
efficiencies of $12,583 per boe/d, representing a new record for
the Company.
Notes:
- 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”.
- See “Production
Breakdown by Product Type” at the end of this press release.
2022 Outlook Update
InPlay’s focus has been concentrated on reducing
debt and improving leverage ratios. Execution of this focus is
significantly ahead of schedule with the increased commodity
prices. With our sound financial footing and projected liquidity
capacity, InPlay is expected to be able to deliver measured
production per share growth and strong free adjusted funds flow
which positions the Company to execute on strategic accretive
opportunities with the ultimate goal of maximizing returns to
shareholders.
InPlay is forecasting 2022 to be another record
year for the Company, and reiterates its previously announced
January 12, 2022 average production guidance of 8,900 to 9,400
boe/d(1). With the recent sustained increase in commodity prices,
we are updating our price forecast using USD $90/bbl WTI, $4.30/mcf
AECO and a CAD/USD exchange rate of 0.80. Based on this
revised commodity price forecast, InPlay is now expected to
generate 2022 AFF of $141 to $150 million and 2022 FAFF of $83 to
$92 million which would result in InPlay being in a positive
working capital position, in excess of debt, by year end.
The table below outlines InPlay’s financial
results of the board approved capital budget based on several
WTI pricing scenarios for the remainder of 2022 (assuming an
average Q1/22 WTI price of US$91.50/bbl):
|
2022 |
US$70WTI |
US$80WTI |
US$90WTI |
US$100WTI |
US$110WTI |
|
Production (boe/d)(1)(2) |
9,150 |
9,150 |
9,150 |
9,150 |
9,150 |
|
Debt adjusted prod. per share growth (%)(3) |
67% |
79% |
90% |
102% |
109% |
|
AFF ($ millions)(4) |
$121 |
$134 |
$146 |
$156 |
$162 |
|
FAFF ($ millions)(3) |
$63 |
$76 |
$88 |
$98 |
$104 |
|
FAFF Yield (%)(3)(6) |
24% |
29% |
33% |
37% |
40% |
|
Year-end Working Capital / (Net Debt) ($ millions)(4) |
($19) |
($6) |
$6 |
$16 |
$22 |
|
Annual Net Debt / EBITDA(3) |
0.2 |
0.0 |
0.0 |
(0.1) |
(0.1) |
|
EV / DAAFF(3)(6) |
2.2 |
1.9 |
1.7 |
1.5 |
1.4 |
Notes:
-
See “Production Breakdown by Product Type” at the end of this press
release.
-
This reflects the mid-point of the Company’s 2022 production
guidance range of 8,900 to 9,400 boe/d.
-
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”.
-
Capital management measure. See “Non-GAAP and Other Financial
Measures” contained within this press release. .
-
See “Reader Advisories – Forward Looking Information and
Statements” for key budget and underlying assumptions related to
our 2022 capital program and associated guidance.
-
Assumes a share price of $3.06.
Operations Update
InPlay’s capital program for the first quarter
of 2022 was initiated in mid December 2021 due to the availability
of services and the desire to take advantage of strong commodity
prices, including winter natural gas prices. The two (1.6 net)
wells that were drilled in December 2021 on the Prairie Storm lands
were brought on production in the second half of January and are
currently exceeding forecasts. The average initial production
(“IP”) rates from these wells are as follows:
|
|
IP 30 (% light crude oil and
NGLs) |
Current(% light crude oil and
NGLs) |
|
1.5 mile well |
593 boe/d (80%) |
368 boe/d (77%) |
|
1.0 mile well |
203 boe/d (83%) |
165 boe/d (78%) |
An additional three (3.0 net) Extended Reach Horizontal (“ERH”)
wells were drilled in Pembina during January and February and were
brought on production ahead of schedule in late February. These
wells are in the early clean up stage and are also currently
producing above forecasts. The average combined IP rates from these
wells are as follows:
|
IP 15 (% light crude oil and
NGLs) |
Current(% light crude oil and
NGLs) |
|
1,022 boe/d (79%) |
1,354 boe/d (71%) |
Current corporate production is approximately 9,050 boe/d(1)
(62% light crude oil and NGLs), based on field estimates.
Plans for the remainder of the first quarter of
2022 consist of completing two (1.7 net) wells that were drilled on
our recently acquired Prairie Storm lands. These wells are expected
to be on production before the end of the first quarter. In
addition, InPlay will bring on production one (0.2 net)
non-operated Cardium ERH well.
Looking forward, the Company has started capital
preparations for the second quarter of 2022. Due to strong
commodity prices and access to our preferred service providers, the
Company expects to start the second quarter drilling program early,
with certain operations including lease construction already
completed. It is expected that drilling operations will commence
approximately six weeks ahead of schedule.
Notes:
-
See “Production Breakdown by Product Type” at the end of this press
release.
-
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”.
Financial and Operating Results:
|
(CDN) ($000’s) |
Three months endedDecember
31 |
Year endedDecember 31 |
|
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
|
Financial |
|
|
|
|
|
Oil and natural gas sales |
37,255 |
|
12,829 |
|
113,854 |
|
41,934 |
|
|
Adjusted funds flow(1) |
17,149 |
|
3,291 |
|
47,028 |
|
7,436 |
|
|
Per share – basic(2) |
0.23 |
|
0.05 |
|
0.67 |
|
0.11 |
|
|
Per share – diluted(2) |
0.22 |
|
0.05 |
|
0.66 |
|
0.11 |
|
|
Per boe(2) |
27.87 |
|
8.40 |
|
22.34 |
|
5.10 |
|
|
Comprehensive income (loss) |
55,191 |
|
(3,227 |
) |
115,071 |
|
(112,629 |
) |
|
Per share – basic |
0.74 |
|
(0.05 |
) |
1.65 |
|
(1.65 |
) |
|
Per share –diluted |
0.71 |
|
(0.05 |
) |
1.61 |
|
(1.65 |
) |
|
Capital expenditures – PP&E and E&E |
6,024 |
|
10,633 |
|
33,434 |
|
23,134 |
|
|
Property acquisitions (dispositions) |
- |
|
1,875 |
|
(84 |
) |
1,610 |
|
|
Net Corporate acquisitions(3)(4) |
38,287 |
|
- |
|
38,287 |
|
- |
|
|
Net debt(1) |
(80,196 |
) |
(73,681 |
) |
(80,196 |
) |
(73,681 |
) |
|
Shares outstanding |
86,214,751 |
|
68,256,616 |
|
86,214,751 |
|
68,256,616 |
|
|
Basic weighted-average shares |
74,338,118 |
|
68,256,616 |
|
69,798,836 |
|
68,256,616 |
|
|
Diluted weighted-average shares |
77,669,551 |
|
68,256,616 |
|
71,681,264 |
|
68,256,616 |
|
|
|
|
|
|
|
|
Operational |
|
|
|
|
|
Daily production volumes |
|
|
|
|
|
Light and medium crude oil (bbls/d) |
3,156 |
|
2,194 |
|
2,981 |
|
2,031 |
|
|
Natural gas liquids (boe/d) |
932 |
|
708 |
|
782 |
|
668 |
|
|
Conventional natural gas (Mcf/d) |
15,589 |
|
8,141 |
|
12,030 |
|
7,715 |
|
|
Total (boe/d) |
6,687 |
|
4,259 |
|
5,768 |
|
3,985 |
|
|
Realized prices(2) |
|
|
|
|
|
Light and medium crude oil & NGLs ($/bbls) |
79.83 |
|
40.41 |
|
70.08 |
|
35.90 |
|
|
Conventional natural gas ($/Mcf) |
5.04 |
|
2.72 |
|
4.01 |
|
2.29 |
|
|
Total ($/boe) |
60.56 |
|
32.74 |
|
54.08 |
|
28.75 |
|
|
Operating netbacks ($/boe)(4) |
|
|
|
|
|
Oil and natural gas sales |
60.56 |
|
32.74 |
|
54.08 |
|
28.75 |
|
|
Royalties |
(7.53 |
) |
(1.78 |
) |
(5.51 |
) |
(2.00 |
) |
|
Transportation expense |
(1.09 |
) |
(0.80 |
) |
(1.11 |
) |
(0.87 |
) |
|
Operating costs |
(12.51 |
) |
(14.35 |
) |
(12.83 |
) |
(14.43 |
) |
|
Operating netback(4) |
39.43 |
|
15.81 |
|
34.63 |
|
11.45 |
|
|
Realized (loss) on derivative contracts |
(5.67 |
) |
(0.38 |
) |
(6.20 |
) |
(0.82 |
) |
|
Operating netback (including realized derivative contracts)(4) |
33.76 |
|
15.43 |
|
28.43 |
|
10.63 |
|
|
(1) |
|
Capital management measure. See “Non-GAAP and Other Financial
Measures” contained within this press release. |
| (2) |
|
Supplementary financial measure. See “Non-GAAP and Other Financial
Measures” contained within this press release. |
| (3) |
|
This amount consists of total gross consideration of $49.9, net of
$11.6 million in working capital balances assumed on closing of the
Prairie Storm acquisition. |
| (4) |
|
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” |
2021 Financial & Operations
Overview:
Production averaged 5,768 boe/d (65% light crude
oil & NGLs) (1) in 2021, a 45% increase compared to 3,985 boe/d
(68% light crude oil & NGLs)(1) in 2020 and a 15% increase
compared to 5,000 boe/d (66% light crude oil & NGLs)(1) in
2019. The four quarter sales volumes were slightly affected due to
the following factors; operational downtime caused by extreme cold,
third party processing facility shut downs and a larger build in
period ending oil inventories of approximately 9,000 barrels.
InPlay’s 2021 capital program consisted of $33.4
million of development capital. The Company drilled eight (8.0 net)
ERH wells in Pembina, and two (1.6) Willesden Green ERH wells on
our newly acquired Prairie Storm assets during the year, for a
total of 12 (10.0 net) wells drilled during the year. The
Company also participated in one (0.2 net) Nisku ERH well and one
(0.2 net) Willesden Green ERH well in 2021. This activity amounted
to the drilling of an equivalent of 20.5 gross horizontal miles
(15.4 net horizontal miles). This capital spending also included
the construction of a multi-well battery in Pembina, which is
anticipated to accommodate future development in the area over the
next three years. InPlay also accelerated the start of its 2022
capital program at the end of 2021, initiating construction
operations and the start of drilling activities on a three well pad
in Pembina due to optimal timing and availability of services.
Efficient field operations resulted in the
Company achieving record low operating costs of $12.83/boe. This
result was achieved despite rising power costs throughout the year
and in services in the second half of the year. The resulting
operating income(2) and operating income profit margin(2) for 2021
were also annual records for the Company at $72.9 million and 64%
respectively.
Note:
- See “Reader
Advisories - Production Breakdown by Product Type”
- 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”.
2021 Reserves Overview:
As a result of the Company’s efficient execution
of development capital in 2021, strategic A&D activity and the
quality of our asset base, significant reserve growth was generated
in all reserve categories compared to 2020. PDP reserves increased
by 64% in 2021 to 15,890 mboe, TP reserves increased by 112% to
45,891 mboe and TPP reserves increased by 85% to 60,640 mboe. This
reserve based growth easily replaced our 2021 production, with 395%
of production being replaced on a PDP basis, 1,253% on a TP basis
and 1,422% on a TPP basis.
This significant reserve growth and improvements
to commodity prices resulted in strong 2021 year-end reserve net
present values of future net revenues before tax (“NPV BT”) and net
asset values per basic share (“NAVPS”). This resulted in reserve
values of NPV BT10 of $206 million (PDP), $471 million (TP) and
$686 million (TPP) using a three independent reserve evaluators
average pricing forecast and foreign exchange rates as at December
31, 2021 as used in the Reserve Report. This equates to Net Asset
Values of $160 million and $1.85 NAVPS (PDP), $424 million and
$4.92 NAVPS (TP) and $639 million and $7.41 NAVPS (TPP)(1),
representing 81% (PDP), 154% (TP) and 112% (TPP) growth for each
category respectively on a per weighted average basic share basis
over 2020.
Note:
- See “Net Asset
Value” 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 2022.
| December 31,
2021 |
Light and Medium |
|
Conventional |
Oil |
BTAX NPV |
Future Development |
NetUndeveloped |
| Reserves
Category(1)(2)(3)(4)(5) |
Crude Oil |
NGLs |
Natural Gas |
Equivalent |
10% |
Capital |
Wells |
|
Mbbl |
Mbbl |
MMcf |
MBOE |
($000's) |
($000's) |
Booked |
| |
|
|
|
|
|
|
|
|
Proved developed producing |
6,224.8 |
2,972.1 |
40,156 |
15,889.6 |
206,481 |
287 |
- |
| Proved developed
non-producing |
595.9 |
254.1 |
3,191 |
1,381.9 |
19,464 |
3,617 |
- |
| Proved undeveloped |
14,151.6 |
4,028.9 |
62,633 |
28,619.3 |
245,156 |
412,786 |
179.2 |
| Total proved |
20,972.4 |
7,255.2 |
105,979 |
45,890.7 |
471,100 |
416,690 |
179.2 |
| Probable developed
producing |
1,467.2 |
713.3 |
9,611 |
3,782.3 |
39,024 |
8 |
- |
| Probable developed
non-producing |
153.9 |
74.1 |
867 |
372.6 |
4,298 |
- |
- |
| Probable undeveloped |
6,159.6 |
1,260.0 |
19,048 |
10,594.3 |
171,090 |
57,533 |
25.8 |
| Total probable |
7,780.6 |
2,047.5 |
29,526 |
14,749.2 |
214,412 |
57,541 |
25.8 |
| Total proved plus
probable(6) |
28,753.0 |
9,302.6 |
135,505 |
60,639.9 |
685,513 |
474,232 |
205.0 |
Notes:
- 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.
- 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, 2021, as outlined in the table herein entitled
“Pricing Assumptions”.
- 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.
- 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.
- 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, 2021 reserve NPV
values are also inclusive of currently enacted carbon taxes.
- Totals may not
add due to rounding.
Net Asset Value:
| |
|
|
|
|
| December 31,
2021 |
BTAX NPV 5% |
BTAX NPV 10% |
|
|
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
PDP NPV(1)(2) |
226,629 |
|
2.63 |
|
206,481 |
|
2.39 |
|
| Undeveloped acreage(3) |
33,474 |
|
0.39 |
|
33,474 |
|
0.39 |
|
| Net debt(4)(5) |
(80,196 |
) |
(0.93 |
) |
(80,196 |
) |
(0.93 |
) |
| Net Asset Value (basic) |
179,907 |
|
2.09 |
|
159,759 |
|
1.85 |
|
| |
|
|
|
|
| December 31,
2021 |
BTAX NPV 5% |
BTAX NPV 10% |
|
|
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
TP NPV(1)(2) |
608,756 |
|
7.06 |
|
471,100 |
|
5.46 |
|
| Undeveloped acreage(3) |
33,474 |
|
0.39 |
|
33,474 |
|
0.39 |
|
| Net debt(4)(5) |
(80,196 |
) |
(0.93 |
) |
(80,196 |
) |
(0.93 |
) |
| Net Asset Value (basic) |
562,034 |
|
6.52 |
|
424,378 |
|
4.92 |
|
| |
|
|
|
|
| December 31,
2021 |
BTAX NPV 5% |
BTAX NPV 10% |
|
|
($000’s) |
$/share(6) |
($000’s) |
$/share(6) |
|
TPP NPV(1)(2) |
904,526 |
|
10.49 |
|
685,513 |
|
7.95 |
|
| Undeveloped acreage(3) |
33,474 |
|
0.39 |
|
33,474 |
|
0.39 |
|
| Net debt(4)(5) |
(80,196 |
) |
(0.93 |
) |
(80,196 |
) |
(0.93 |
) |
| Net Asset Value (basic) |
857,804 |
|
9.95 |
|
638,791 |
|
7.41 |
|
Notes:
- Evaluated by Sproule as at December 31, 2021. The estimated NPV
does not represent fair market value of the reserves.
- 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, 2021.
- Duvernay land
holdings attributed a value of $19.9 million ($847/acre) for 23,440
net acres based on internal valuations. The remaining undeveloped
acreage is based on an internal valuation totaling $13.6 million
($256/acre) for 53,159 net acres. These internal valuations are
based on land sale results in the area.
- Net debt as at
December 31, 2021.
- Capital
management measure. See “Non-GAAP and Other Financial Measures”
contained within this press release.
- Based upon
86,214,751 common shares outstanding as at December 31, 2021.
Future Development Costs (“FDCs”):
FDCs increased by $246.9 million on a Total Proved basis and
$215.7 million on a Total Proved plus Probable basis.
|
Future Development Capital Costs (amounts in
$million) |
|
|
Total Proved |
Total Proved + Probable |
|
2022 |
58.9 |
66.6 |
|
2023 |
99.2 |
111.7 |
|
2024 |
100.5 |
114.0 |
|
2025 |
95.3 |
110.5 |
|
Remainder |
62.7 |
71.4 |
|
Total undiscounted FDC |
416.7 |
474.2 |
|
Total discounted FDC at 10% per year |
332.4 |
377.8 |
Note: FDC as per Reserve Report based on
forecast pricing as outlined in the table herein entitled “Pricing
Assumptions”
Performance Measures:
|
|
2019 |
2020 |
2021 |
3 Year Avg |
| Average WTI crude oil price (US$/bbl) |
57.02 |
39.40 |
67.91 |
54.78 |
| Capital expenditures – PP&E and E&E ($000’s)(1) |
30,689 |
22,213 |
33,434 |
- |
| Production boe/d – FY(3) |
5,000 |
3,985 |
5,768 |
4,918 |
| Production boe/d – Q4(3) |
4,998 |
4,259 |
6,687 |
5,315 |
| Operating netback $/boe – FY(2) |
22.75 |
11.45 |
34.63 |
24.32 |
| Proved Developed
Producing |
|
|
|
|
|
Total Reserves mboe |
8,718 |
9,677 |
15,890 |
11,428 |
|
Reserves additions mboe |
2,195 |
2,418 |
8,318 |
12,930 |
|
FD&A (including FDCs) $/boe(1) |
13.98 |
9.85 |
8.47 |
9.67 |
|
FD&A (excluding FDCs) $/boe(1) |
13.98 |
9.85 |
8.47 |
9.67 |
|
Recycle Ratio(4) |
1.6 |
1.2 |
4.1 |
2.5 |
|
Reserves Replacement(5) |
120% |
166% |
395% |
240% |
|
RLI (years)(6) |
4.8 |
6.6 |
7.5 |
6.4 |
| Total Proved |
|
|
|
|
|
Total Reserves mboe |
18,573 |
21,624 |
45,891 |
28,696 |
|
Reserves additions mboe |
1,540 |
4,509 |
26,372 |
32,421 |
|
FD&A (including FDCs) $/boe(1) |
7.92 |
5.86 |
12.03 |
10.98 |
|
FD&A (excluding FDCs) $/boe(1) |
19.93 |
5.28 |
2.67 |
3.86 |
|
Recycle Ratio(4) |
2.9 |
2.0 |
2.9 |
2.2 |
|
Reserves Replacement(5) |
84% |
309% |
1,253% |
602% |
|
RLI (years)(6) |
10.2 |
14.8 |
21.8 |
16.0 |
| Proved Plus Probable |
|
|
|
|
|
Total Reserves mboe |
27,295 |
32,816 |
60,640 |
40,250 |
|
Reserves additions mboe |
2,057 |
6,980 |
29,929 |
38,965 |
|
FD&A (including FDCs) $/boe(1) |
7.82 |
8.21 |
9.56 |
9.23 |
|
FD&A (excluding FDCs) $/boe(1) |
14.92 |
3.41 |
2.36 |
3.21 |
|
Recycle Ratio(4) |
2.9 |
1.4 |
3.6 |
2.6 |
|
Reserves Replacement(5) |
113% |
479% |
1,422% |
723% |
|
RLI (years)(6) |
15.0 |
22.5 |
28.8 |
22.4 |
In 2021, InPlay’s successful exploration, development and
acquisition/disposition capital program achieved a capital
efficiency of $12,583 per boe/d and a three year average of $15,354
per boe/d.(7)
Notes:
- 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: 2021
TPP = ($33.4 million E&D - $1.2 million capitalized G&A -
$nil million of land acquisitions + $38.2 million net
acquisition/disposition capital + $215.8 million FDC) / (60,640
mboe – 32,816 mboe + 2,105 mboe) = $9.56 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.
- 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”
- See “Reader
Advisories - Production Breakdown by Product Type”
- Recycle Ratio is
calculated by dividing the year’s operating netback per boe by the
FD&A costs for that period. For example: 2021 TPP =
($34.63/$9.56) = 3.6. 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.
- 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: 2021 TPP = (60,640 mboe – 32,816 mboe + 2,105
mboe) / 2,105 mboe = 1422%, 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.
- RLI is
calculated by dividing the reserves in each category by the 2021
average annual production. For example 2021 TPP = (60,640 mboe) /
(5,768 boe/day) = 28.8 years. See Information Regarding Disclosure
on Oil and Gas Reserves and Operational Information in the Reader
Advisories.
- 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 of 29% over the course of the
year, calculated as follows: ($33.4 million E&D - $1.2 million
capitalized G&A - $nil million of land acquisitions - $0.1
million net acquisition/disposition capital + $9.2 million of 2020
capital adding reserves in 2021 - $3.0 million of capital not
adding reserves in 2021) / (Q4/2021 production of 6,687 boe/d –
Q4/2020 production of 4,259 boe/d + 2021 declined production at 29%
of 1,218 boe/d – Q4/2021 Prairie Storm production of 600 boe/d).
See Information Regarding Disclosure on Oil and Gas Reserves and
Operational Information in the Reader Advisories.
Pricing Assumptions:
The following tables set forth the benchmark
reference prices, as at December 31, 2021, reflected in the Reserve
Report. These price assumptions were an arithmetic average of the
price forecasts of three independent reserve evaluator’s (Sproule,
McDaniel & Associates Consultants Ltd. and GLJ Ltd.) then
current forecast at the effective date of the Reserve Report.
SUMMARY OF PRICING AND INFLATION RATE
ASSUMPTIONS (1) as of December 31, 2021 FORECAST PRICES AND
COSTS
|
Year |
WTICushingOklahoma($US/Bbl) |
CanadianLight Sweet 40o
API($Cdn/Bbl) |
CromerLSB
35o API($Cdn/Bbl) |
Natural Gas AECO-C
Spot($Cdn/MMBtu) |
NGLsEdmonton
Propane($Cdn/Bbl) |
NGLs Edmonton
Butanes($Cdn/Bbl) |
EdmontonPentanesPlus($Cdn/Bbl) |
Operating Cost Inflation
Rates%/Year |
Capital Cost Inflation
Rates%/Year |
Exchange Rate (2)($Cdn/$US) |
|
Forecast(3) |
|
|
|
|
|
|
|
|
|
|
|
2022 |
72.83 |
86.82 |
87.30 |
3.56 |
43.38 |
57.49 |
91.85 |
0.0% |
0.0% |
0.80 |
|
2023 |
68.78 |
80.73 |
82.30 |
3.21 |
35.92 |
50.17 |
85.53 |
2.3% |
2.3% |
0.80 |
|
2024 |
66.76 |
78.01 |
79.69 |
3.05 |
34.62 |
48.53 |
82.98 |
2.0% |
2.0% |
0.80 |
|
2025 |
68.09 |
79.57 |
81.29 |
3.11 |
35.31 |
49.50 |
84.63 |
2.0% |
2.0% |
0.80 |
|
2026 |
69.45 |
81.16 |
82.92 |
3.17 |
36.02 |
50.49 |
86.33 |
2.0% |
2.0% |
0.80 |
|
2027 |
70.84 |
82.78 |
84.50 |
3.23 |
36.74 |
51.50 |
88.05 |
2.0% |
2.0% |
0.80 |
|
2028 |
72.26 |
84.44 |
86.27 |
3.30 |
37.47 |
52.53 |
89.82 |
2.0% |
2.0% |
0.80 |
|
2029 |
73.70 |
86.13 |
87.99 |
3.36 |
38.22 |
53.58 |
91.61 |
2.0% |
2.0% |
0.80 |
|
2030 |
75.18 |
87.85 |
89.75 |
3.43 |
38.99 |
54.65 |
93.44 |
2.0% |
2.0% |
0.80 |
|
2031 |
76.68 |
89.61 |
91.55 |
3.50 |
39.77 |
55.74 |
95.32 |
2.0% |
2.0% |
0.80 |
|
2032 |
78.21 |
91.40 |
93.38 |
3.57 |
40.56 |
56.86 |
97.22 |
2.0% |
2.0% |
0.80 |
| |
Thereafter
Escalation rate of 2.0% |
|
|
|
|
|
|
Notes:
- This summary
table identifies benchmark reference pricing schedules that might
apply to a reporting issuer.
- The exchange
rate used to generate the benchmark reference prices in this
table.
- As at December
31, 2021.
Environmental, Social and Governance (“ESG”)
Update
InPlay’s commitment to ESG is evident through
its operational track record, corporate culture and strong
governance. The Company is pleased to announce that it expects to
release its inaugural sustainability report this summer. InPlay
looks forward to sharing the Company’s strategy and governance
related to ESG and reporting ESG related metrics with
shareholders.
The Company completed an active abandonment and
reclamation program throughout 2021, spending $2.3 million on the
abandonment of 75 wellbores and the reclamation of 22 well sites.
This resulted in a reduction to our Abandonment and Reclamation
obligation of 3% during 2021. Efficient field operations resulted
in a 20% reduction to the Company’s emissions (Scope 1 and 2) on a
per boe basis compared to 2020.
Included in our 2022 forecast is a commitment to
materially reducing the Company’s abandonment and reclamation
obligations. Approximately 30 abandonment operations and 20
reclamations are currently planned for 2022, which is estimated to
result in a $3 million or 3% reduction to our ARO and a projected
improvement in our Liability Management Rating (“LMR”) to 2.85.
We look forward to continuing to deliver returns
to our shareholders and thank all of those that have supported
InPlay since the Company’s inception. The future for InPlay and the
industry are very promising and we will continue to operate the
Company in a prudent, sustainable and responsible manner.
For further information please contact:
| Doug Bartole |
|
Darren Dittmer |
| President and Chief Executive Officer |
|
Chief Financial Officer |
| InPlay Oil Corp. |
|
InPlay Oil Corp. |
| Telephone: (587) 955-0632 |
|
Telephone: (587) 955-0634 |
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”, “free adjusted funds flow per
share”, “FAFF Yield”, “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 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 / FAFF per share
Management considers free adjusted funds flow
and free adjusted funds flow per share important measures to
identify the Company’s ability to improve its financial condition
through debt repayment, which has become more important recently
with the introduction of second lien lenders, on an absolute and
weighted average per share basis. Free adjusted funds flow should
not be considered as an alternative to or more meaningful than
adjusted funds flow as determined in accordance with GAAP as an
indicator of the Company’s performance. Free adjusted funds flow is
calculated by the Company as adjusted funds flow 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. Free adjusted funds flow
per share is calculated by the Company as free adjusted funds flow
divided by weighted average outstanding shares. Refer below for a
calculation of free adjusted funds flow, free adjusted funds flow
per share and a reconciliation of free adjusted funds flow to the
nearest GAAP measure, adjusted funds flow.
|
(thousands of dollars) |
Three Months Ended December 31 |
Year Ended December 31 |
|
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
| Adjusted funds flow |
17,149 |
|
3,291 |
|
47,028 |
|
7,436 |
|
| Exploration and dev. capital expenditures |
(6,024 |
) |
(10,633 |
) |
(33,434 |
) |
(23,134 |
) |
| Property dispositions
(acquisitions) |
- |
|
(1,875 |
) |
84 |
|
(1,610 |
) |
| Free adjusted funds flow |
11,125 |
|
(9,217 |
) |
13,678 |
|
(17,308 |
) |
| Weighted average
outstanding shares |
74.3 |
|
68.3 |
|
69.8 |
|
68.3 |
|
| FAFF per share |
0.15 |
|
(0.14 |
) |
0.20 |
|
(0.25 |
) |
Free Adjusted Funds Flow Yield
InPlay uses “free adjusted funds flow yield” as
a key performance indicator. Free adjusted funds flow is calculated
by the Company as free adjusted funds flow divided by the market
capitalization of the Company. Management considers FAFF yield to
be an important performance indicator as it demonstrates a
Company’s ability to generate cash to pay down debt and provide
funds for potential distributions to shareholders. Refer to the
“Forward Looking Information and Statements” section for a
calculation of forecast 2022 free adjusted funds flow yield.
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 EndedDecember 31 |
Year EndedDecember 31 |
|
|
2021 |
|
2020 |
|
2021 |
|
2020 |
|
| Revenue |
37,255 |
|
12,829 |
|
113,854 |
|
41,934 |
|
| Royalties |
(4,632 |
) |
(697 |
) |
(11,595 |
) |
(2,924 |
) |
| Operating expenses |
(7,695 |
) |
(5,622 |
) |
(27,009 |
) |
(21,043 |
) |
| Transportation
expenses |
(673 |
) |
(314 |
) |
(2,346 |
) |
(1,271 |
) |
| Operating income |
24,255 |
|
6,196 |
|
72,904 |
|
16,696 |
|
| |
|
|
|
|
|
|
|
|
| Sales volume (Mboe) |
615.2 |
|
391.8 |
|
2,105.1 |
|
1,458.5 |
|
| Per boe |
|
|
|
|
|
|
|
|
|
Revenue |
60.56 |
|
32.74 |
|
54.08 |
|
28.75 |
|
|
Royalties |
(7.53 |
) |
(1.78 |
) |
(5.51 |
) |
(2.00 |
) |
|
Operating expenses |
(12.51 |
) |
(14.35 |
) |
(12.83 |
) |
(14.43 |
) |
|
Transportation expenses |
(1.09 |
) |
(0.80 |
) |
(1.11 |
) |
(0.87 |
) |
|
Operating netback per boe |
39.43 |
|
15.81 |
|
34.63 |
|
11.45 |
|
|
Operating income profit margin |
65 |
% |
48 |
% |
64 |
% |
40 |
% |
Net Debt to EBITDAManagement 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. 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 / EBITDA.
|
(thousands of dollars) |
Year EndedDecember 31 |
|
|
2021 |
2020 |
| Net debt |
80,196 |
73,681 |
| Adjusted funds flow |
47,028 |
7,436 |
| Interest expense (Credit Facility and other) |
5,594 |
3,523 |
| Interest expense
(Lease liabilities) |
20 |
47 |
| Earnings before interest, taxes and depletion (“EBITDA”) |
52,642 |
11,006 |
|
Net Debt to EBITDA |
1.5 |
6.7 |
Net Corporate AcquisitionsManagement 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 EndedDecember 31 |
Year EndedDecember 31 |
|
|
2021 |
|
2020 |
2021 |
|
2020 |
| Corporate acquisitions, net of cash acquired |
29,277 |
|
- |
29,277 |
|
- |
| Share
consideration(1) |
9,985 |
|
- |
9,985 |
|
- |
| Non-cash working capital acquired |
(1,156 |
) |
- |
(1,156 |
) |
- |
| Derivative
contracts |
181 |
|
- |
181 |
|
- |
| Net Corporate
acquisitions |
38,287 |
|
- |
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
consolidated financial statements. |
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 to the “Forward Looking
Information and Statements” section for a calculation of forecast
Production per debt adjusted share.
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 net
debt. Enterprise value is calculated as market capitalization plus
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
2022 EV/DAAFF.
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,
2021. 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
Net debt is a GAAP measure and is disclosed in
the notes to the Company’s consolidated financial statements for
the year ending December 31, 2021. 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 as part of its capital structure. The Company uses net debt
(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 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.
Forward-Looking Information and
Statements This news release contains certain
forward–looking information and statements within the meaning of
applicable securities laws. The use of any of the words "expect",
"anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends", “forecast” and similar
expressions are intended to identify forward-looking information or
statements. In particular, but without limiting the foregoing, this
news release contains forward-looking information and statements
pertaining to the following: the recognition of significant
additional reserves under the heading "Corporate Reserves
Information", the future net value of InPlay's reserves, the future
development capital and costs, the life of InPlay's reserves and
the net asset values disclosed under the heading "Net Asset Value"
including the internal value ascribed to undeveloped acreage; the
Company’s planned 2022 capital program including wells to be
drilled and completed and the timing of the same; 2022 guidance
based on the planned capital program including forecasts of 2022
annual average production levels, debt adjusted production levels,
adjusted funds flow, free adjusted funds flow, Net Debt/EBITDA
ratio, operating income profit margin, and Management’s belief that
the Company can grow some or all of these attributes and specified
measures; light crude oil and NGLs weighting estimates;
expectations regarding future commodity prices; future oil and
natural gas prices; future liquidity and financial capacity; future
results from operations and operating metrics; future costs,
expenses and royalty rates; future interest costs; the exchange
rate between the $US and $Cdn; future development, exploration,
acquisition, development and infrastructure activities and related
capital expenditures, including our planned 2022 capital program;
the amount and timing of capital projects; forecasted spending on
decommissioning; the expectation that the reserve additions from
the Prairie Storm acquisition will generate strong production and
FAFF growth; the expectation that InPlay will be in a positive net
cash position in the fourth quarter of 2022 using a pricing
scenario of US $90 WTI and positive working capital position by
2022 year end; that 2022 will be another record year for the
Company; the expectation that the Company will experience
inflationary cost pressures in the second half of 2022; the
expectation that costs will begin to normalize later in 2022; the
Company’s planned 2022 abandonment and reclamation program,
including the abandonments and reclamations to be completed,
forecasted spending on these activities, reduction to our ARO and
forecasted LMR rating; the expectation that the Company will start
the second quarter capital program early; the planned release of
InPlay’s inaugural sustainability report prior to June 30, 2022 and
methods of funding our capital program.
Forward-looking statements or information are
based on a number of material factors, expectations or assumptions
of InPlay which have been used to develop such statements and
information but which may prove to be incorrect. Although InPlay
believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not
be placed on forward-looking statements because InPlay can give no
assurance that such expectations will prove to be correct. In
addition to other factors and assumptions which may be identified
herein, assumptions have been made regarding, among other things:
the impact of increasing competition; the general stability of the
economic and political environment in which InPlay operates; the
timely receipt of any required regulatory approvals; the ability of
InPlay to obtain qualified staff, equipment and services in a
timely and cost efficient manner; drilling results; the ability of
the operator of the projects in which InPlay has an interest in to
operate the field in a safe, efficient and effective manner; the
ability of InPlay to obtain financing on acceptable terms; field
production rates and decline rates; the ability to replace and
expand oil and natural gas reserves through acquisition,
development and exploration; the timing and cost of pipeline,
storage and facility construction and the ability of InPlay to
secure adequate product transportation; future commodity prices;
that various conditions to a shareholder return strategy can be
satisfied; expectations regarding the potential impact of COVID-19;
currency, exchange and interest rates; regulatory framework
regarding royalties, taxes and environmental matters in the
jurisdictions in which InPlay operates; and the ability of InPlay
to successfully market its oil and natural gas products.
The forward-looking information and statements
included herein are not guarantees of future performance and should
not be unduly relied upon. Such information and statements,
including the assumptions made in respect thereof, involve known
and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated
in such forward-looking information or statements including,
without limitation: the continuing impact of the COVID-19 pandemic;
changes in our planned 2022 capital program; changes in commodity
prices and other assumptions outlined herein; the potential for
variation in the quality of the reservoirs in which we operate;
changes in the demand for or supply of our products; unanticipated
operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters;
changes in development plans or strategies of InPlay or by third
party operators of our properties; increased debt levels or debt
service requirements; inaccurate estimation of our light crude oil
and natural gas reserve and resource volumes; limited, unfavorable
or a lack of access to capital markets; increased costs; a lack of
adequate insurance coverage; the impact of competitors; and certain
other risks detailed from time-to-time in InPlay's continuous
disclosure documents filed on SEDAR including our Annual
Information Form.
The internal projections, expectations or
beliefs underlying the Company's 2022 capital budget, associated
guidance and corporate outlook for 2022 and beyond are subject to
change in light of ongoing results, prevailing economic
circumstances, commodity prices and industry conditions and
regulations. InPlay's outlook for 2022 and beyond provides
shareholders with relevant information on management's expectations
for results of operations, excluding any potential acquisitions,
dispositions or strategic transactions that may be completed in
2022 and beyond including, without limitation, the potential impact
of any shareholder return strategy that may be implemented in the
future. Accordingly, readers are cautioned that events or
circumstances could cause results to differ materially from those
predicted and InPlay's 2022 guidance and outlook may not be
appropriate for other purposes.
This press release contains future-oriented
financial information and financial outlook information
(collectively, "FOFI") about InPlay’s prospective capital
expenditures, all of which are subject to the same assumptions,
risk factors, limitations, and qualifications as set forth in the
above paragraphs. The actual results of operations of InPlay and
the resulting financial results will likely vary from the amounts
set forth in this press release and such variation may be material.
InPlay and its management believe that the FOFI has been prepared
on a reasonable basis, reflecting management's best estimates and
judgments. However, because this information is subjective and
subject to numerous risks, it should not be relied on as
necessarily indicative of future results. Except as required by
applicable securities laws, InPlay undertakes no obligation to
update such FOFI. FOFI contained in this press release was made as
of the date of this press release and was provided for the purpose
of providing further information about InPlay's anticipated future
business operations. Readers are cautioned that the FOFI contained
in this press release should not be used for purposes other than
for which it is disclosed herein.
The forward-looking information and statements
contained in this news release speak only as of the date hereof and
InPlay does not assume any obligation to publicly update or revise
any of the included forward-looking statements or information,
whether as a result of new information, future events or otherwise,
except as may be required by applicable securities laws.
InPlay’s 2021 annual guidance and a comparison
to 2021 actual results are outlined below.
|
|
|
|
2021 Guidance(1) |
2021 Actual |
Variance |
Variance (%) |
|
Production(6) |
Boe/d |
|
5,750 – 6,000 |
5,768 |
- |
- |
| Adjusted
Funds Flow(7) |
$ millions |
|
$51.0 - $54.0 |
$47.0 |
($5)(3) |
(7%) |
| Capital
Expenditures |
$ millions |
|
$32.5(2) |
$33.4 |
$1(4) |
3% |
| Free
Adjusted Funds Flow(8) |
$ millions |
|
$17.5 - $20.5 |
$13.6 |
($4)(3)(4) |
(20%) |
|
Net Debt(6) |
$ millions |
|
$76.5 - $79.5 |
$80.2 |
$1(3)(4)(5) |
1% |
Notes:
- As previously
released September 28, 2021.
- As previously
released November 30, 2021 (previously $32.5 - $34.5 million on
September 28, 2021).
- This variance is
due to the following:
- Lower fourth
quarter sales volumes due to operational downtime caused by extreme
cold, third party processing facility mechanical shut downs, a
larger build in period ending oil inventories of approximately
9,000 barrels, and the later than initially expected drilling of
the two well pad drilled in the fourth quarter of 2021. In
addition, new production from the 2021 drilling program had a
slightly higher gas weighting and lower NGL yield than
forecasted.
- The effect of
shorter royalty incentive periods for recently drilled wells in the
improved pricing environment and higher trucking costs on new
wells.
- Significant
improvements in the Company’s share price in the later portion of
2021, resulting in additional expenses incurred from the vesting
and revaluation of deferred share units, and the accelerated
vesting of certain DSUs.
- Increased
hedging losses as a result of higher annual average WTI prices of
US $1.06/bbl.
- This variance is
due to the acceleration of the start of the 2022 capital program at
the end of 2021 through the initiation of lease construction and
starting drilling activities on a three well pad in Pembina due to
optimal conditions and availability of services.
- This net debt
variance is due to the higher positive net debt assumed on the
Prairie Storm acquisition in addition to additional proceeds from
the over-allotment option being exercised on the bought deal
financing which both contributed to an additional $3 million
positive net debt impact, net of the $4 million reduction to free
adjusted funds flow.
- See “Reader
Advisories - Production Breakdown by Product Type”
- Capital
management measure. See “Non-GAAP and Other Financial Measures”
contained within this press release.
- Non-GAAP
financial measure or ratio that does not have a standardized
meaning under International Financial Reporting Standards (IFRS)
and GAAP and therefore may not be comparable with the calculations
of similar measures for other companies. Please refer to “Non-GAAP
and Other Financial Measures”
The key budget and underlying material
assumptions used by the Company in the development of its 2022
guidance including forecasted production, operating income, capital
expenditures, adjusted funds flow, free adjusted funds flow, FAFF
yield, Net Debt, Net Debt/EBITDA, EV/DAAFF, production per debt
adjusted share growth are as follows:
|
|
|
ActualsFY 2021 |
Previous GuidanceFY 2022(1) |
Updated GuidanceFY 2022 |
| WTI |
US$/bbl |
$67.91 |
$72.50 |
$90.00 |
| NGL
Price |
$/boe |
$37.79 |
$42.75 |
$52.35 |
| AECO |
$/GJ |
$3.44 |
$3.30 |
$4.30 |
| Foreign
Exchange Rate |
CDN$/US$ |
0.80 |
0.78 |
0.80 |
| MSW
Differential |
US$/bbl |
$3.88 |
$3.50 |
$3.00 |
|
Production |
Boe/d |
5,768 |
8,900 –
9,400 |
8,900 –
9,400 |
|
Royalties |
$/boe |
5.51 |
5.25 –
5.75 |
9.80 – 10.60 |
| Operating
Expenses |
$/boe |
12.83 |
10.00 –
13.00 |
10.00 –
13.00 |
|
Transportation |
$/boe |
1.11 |
0.85 –
1.10 |
0.85 –
1.10 |
|
Interest |
$/boe |
2.67 |
0.85 –
1.25 |
0.75 –
1.15 |
| General
and Administrative |
$/boe |
2.83 |
2.00 –
2.60 |
2.00 –
2.60 |
| Hedging
loss |
$/boe |
6.20 |
0.00 –
0.20 |
0.35 –
0.65 |
|
Decommissioning Expenditures |
$
millions |
$1.4 |
$2.0 -
$2.5 |
$2.0 -
$2.5 |
|
Adjusted Funds Flow |
$ millions |
$47.0 |
$111.0 - $117.0 |
$141 - $150 |
|
Weighted average outstanding shares |
# millions |
69.8 |
86.2 |
86.2 |
|
Adjusted Funds Flow per share |
$/share |
0.67 |
1.28 – 1.36 |
1.64 – 1.75 |
|
|
|
ActualsFY 2021 |
Previous GuidanceFY 2022 |
Updated GuidanceFY 2022 |
| Adjusted
Funds Flow |
$
millions |
$47.0 |
$111.0 - $117.0 |
$141 -
$150 |
|
Capital Expenditures |
$ millions |
$33.3 |
$58.0 |
$58.0 |
|
Free Adjusted Funds Flow |
$ millions |
$13.6 |
$53.5 - $59.5 |
$83 - $92 |
| Share
outstanding, end of year |
#
millions |
86.2 |
|
86.2 |
|
Assumed Share price |
$ |
2.18(3) |
|
3.06 |
|
Market capitalization |
$ millions |
$188 |
|
$264 |
|
FAFF Yield |
% |
7% |
N/A(5) |
31% - $35% |
|
|
|
ActualsFY 2021 |
Previous GuidanceFY 2022(1) |
Updated GuidanceFY 2022 |
| Adjusted
Funds Flow |
$
millions |
$47.0 |
$111.0 -
$117.0 |
$141 -
$150 |
|
Interest |
$/boe |
2.67 |
0.85 – 1.25 |
0.75 – 1.15 |
|
EBITDA |
$
millions |
$52.6 |
$115.0 -
$120.0 |
$144 -
$153 |
|
Net Debt/(Positive working capital, in excess of debt) |
$ millions |
$80.2 |
$22.0 - $28.0 |
($1) – ($10) |
|
Net Debt/EBITDA |
|
1.5 |
0.2 – 0.3 |
0.0 – 0.1 |
|
|
|
ActualsFY 2021 |
Previous GuidanceFY 2022(1) |
Updated GuidanceFY 2022 |
|
Production |
Boe/d |
5,768 |
8,900 –
9,400 |
8,900 –
9,400 |
| Opening
Net Debt |
$
millions |
$73.7 |
$76.5 -
$79.5 |
$80.2 |
| Ending
Net Debt/(Pos. working capital, in excess of debt) |
$
millions |
$80.2 |
$22.0 -
$28.0 |
($1) –
($10) |
| Weighted
average outstanding shares |
#
millions |
69.8 |
86.2 |
86.2 |
|
Assumed Share price |
$ |
1.16(4) |
2.18 |
3.06 |
|
Production per debt adjusted share growth(2) |
|
31% |
76% - 86% |
85% - 95% |
|
|
|
ActualsFY 2021 |
Previous GuidanceFY 2022 |
Updated GuidanceFY 2022 |
| Share
outstanding, end of year |
#
millions |
86.2 |
|
86.2 |
|
Assumed Share price |
$ |
2.18(3) |
|
3.06 |
| Market
capitalization |
$
millions |
$188 |
|
$264 |
|
Net Debt/(Positive working capital, in excess of debt) |
$ millions |
$80.2 |
|
($1) – ($10) |
|
Enterprise value |
$millions |
$268.2 |
|
$253 -
$261 |
| Adjusted
Funds Flow |
$
millions |
$44.1 |
|
$141 -
$150 |
|
Interest |
$/boe |
2.67 |
|
0.75 – 1.15 |
|
Debt Adjusted AFF |
$ millions |
$49.7 |
|
$144 – $153 |
|
EV/DAAFF |
|
5.4 |
N/A(5) |
1.6 – 1.8 |
| (1) |
|
As previously released January 12, 2022. |
| (2) |
|
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. Share price at December
31, 2022 is assumed to be consistent with the share price at
December 31, 2021. |
| (3) |
|
Ending share price at December 31, 2021. |
| (4) |
|
Weighted average share price throughout 2021. |
| (5) |
|
Guidance had not been previously released for this
measure. |
-
See “Production Breakdown by Product Type” below
- Quality and
pipeline transmission adjustments may impact realized oil prices in
addition to the MSW Differential provided above
- Changes in
working capital are not assumed to have a material impact between
Dec 31, 2021 and Dec 31, 2022.
Information Regarding Disclosure on Oil
and Gas Reserves and Operational InformationOur oil and
gas reserves statement for the year ended December 31, 2021, which
will include complete disclosure of our oil and gas reserves and
other oil and gas information in accordance with NI 51-101, will be
contained within our Annual Information Form which will be
available on our SEDAR profile at www.sedar.com on or before March
31, 2022. The recovery and reserve estimates contained herein are
estimates only and there is no guarantee that the estimated
reserves will be recovered. In relation to the disclosure of
estimates for individual properties, such estimates may not reflect
the same confidence level as estimates of reserves and future net
revenue for all properties, due to the effects of aggregation. The
Company's belief that it will establish additional reserves over
time with conversion of probable undeveloped reserves into proved
reserves is a forward-looking statement and is based on certain
assumptions and is subject to certain risks, as discussed above
under the heading "Forward-Looking Information and Statements".
This press release contains metrics commonly
used in the oil and natural gas industry, such as "finding,
development and acquisition costs", “finding and development
costs”, "operating netbacks", “recycle ratios”, “reserve
replacement” and "reserve life index” or “RLI”. Each of these terms
are calculated by InPlay as described in the section “Performance
Measures” in this press release. These terms do not have
standardized meanings or standardized methods of calculation and
therefore may not be comparable to similar measures presented by
other companies, and therefore should not be used to make such
comparisons. Such metrics have been included herein to provide
readers with additional information to evaluate the Company’s
performance, however such metrics should not be unduly relied
upon.
Finding, development and acquisition
(“FD&A”) and finding and development (“F&D”) costs take
into account reserves revisions during the year on a per boe basis.
The aggregate of the costs incurred in the financial year and
changes during that year in estimated future development costs may
not reflect total finding and development costs related to reserves
additions for that year. Finding, development and acquisition costs
have been presented in this press release because acquisitions and
dispositions can have a significant impact on our ongoing reserves
replacement costs and excluding these amounts could result in an
inaccurate portrayal of our cost structure. Exploration &
development capital means the aggregate exploration and development
costs incurred in the financial year on exploration and on reserves
that are categorized as development. Exploration & development
capital excludes capitalized administration costs. Acquisition
capital amounts to the total amount of cash and share consideration
net of any working capital balances assumed with an acquisition on
closing.
Management uses these oil and gas metrics for
its own performance measurements and to provide shareholders with
measures to compare InPlay's operations over time, however such
measures are not reliable indicators of InPlay’s future performance
and future performance may not be comparable to the performance in
prior periods. Readers are cautioned that the information provided
by these metrics, or that can be derived from the metrics presented
in this press release, should not be relied upon for investment or
other purposes, however such measures are not reliable indicators
on InPlay’s future performance and future performance may not be
comparable to the performance in prior periods.
References to light crude oil, NGLs or natural
gas production in this press release refer to the light and medium
crude oil, natural gas liquids and conventional natural gas product
types, respectively, as defined in National Instrument 51-101,
Standards of Disclosure for Oil and Gas Activities ("Nl
51-101").
Test Results and Initial Production
RatesTest 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. 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 to be preliminary until such analysis
or interpretation has been completed.
Production Breakdown by Product
TypeDisclosure of production on a per boe basis in this
press release consists of the constituent product types as defined
in NI 51-101 and their respective quantities disclosed in the
table below:
|
|
Light and MediumCrude
oil(bbls/d) |
NGLS(boe/d) |
Conventional Natural
gas(Mcf/d) |
Total(boe/d) |
|
Q4 2019 Average Production |
2,466 |
869 |
9,978 |
4,998 |
|
2019 Average Production |
2,626 |
697 |
10,058 |
5,000 |
|
Q4 2020 Average Production |
2,194 |
708 |
8,141 |
4,259 |
|
2020 Average Production |
2,031 |
668 |
7,715 |
3,985 |
|
Q4 2021 Average Production |
3,156 |
933 |
15,590 |
6,687 |
|
2021 Average Production |
2,981 |
782 |
12,030 |
5,768 |
|
2022 Annual Guidance |
4,332 |
1,312 |
21,035 |
9,150(1) |
|
Tuck-in Acquisition Q4 2021 Avg. Prod |
1,452 |
302 |
6,815 |
2,900 |
|
Current Corporate Average Production |
4,019 |
1,455 |
21,464 |
9,050 |
Note:
- This reflects
the mid-point of the Company’s 2022 production guidance range of
8,900 to 9,400 boe/d.
- With respect to
forward-looking production guidance, product type breakdown is
based upon management's expectations based on reasonable
assumptions but are subject to variability based on actual well
results.
References to crude oil, NGLs or natural gas
production in this press release refer to the light and medium
crude oil, natural gas liquids and conventional natural gas product
types, respectively, as defined in National Instrument 51-101,
Standards of Disclosure for Oil and Gas Activities ("Nl
51-101").
BOE equivalent Barrel of oil
equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl 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
than the energy equivalency of 6:1, utilizing a 6:1 conversion
basis may be misleading as an indication of value.
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