InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the
“Company”) is pleased to announce its financial and operating
results for the three and twelve months ended December 31, 2019,
and the results of its independent oil and gas reserves evaluation
effective December 31, 2019 (the “Sproule 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, 2019 will be available at “www.sedar.com” and our website at
“www.inplayoil.com”.
Message to Shareholders:
InPlay’s strategy has always been to operate a
smart, prudent, and well run junior light oil focused Company that
has the ability to provide growth through its strong technical
expertise and generate top tier efficiencies in finding reserves
and adding production. This has been done while being
flexible in executing our capital program and in operations where
we have continually been reacting to the extremely volatile
commodity price environment that our industry has endured over the
last six plus years.
The Company continued to deliver exceptional
operational and financial results, delivering 7% production per
share growth in 2019 over 2018, achieving our annual average
production guidance of 5,000 – 5,200 boe/d, notwithstanding the
sale of 250 boe/d in the fourth quarter of 2018. This average
production was achieved while reducing our planned capital
expenditures by 11% in the fourth quarter of 2019 which resulted in
spending less than adjusted funds flow (“AFF”)(1) for 2019,
adhering to our approach of being adaptable and maintaining
financial flexibility. A 10% reduction in operating costs per
boe and an increased operating income profit margin(1) of 6% in
2019 over 2018 was achieved, generating a 20% increase in AFF for
the year over 2018 to $32.5 million in 2019. These results
were achieved within a reduced pricing environment resulting in a
corporate realized price of $41.11/boe in 2019 compared to
$45.00/boe in 2018, due to lower West Texas Intermediate (“WTI”)
and natural gas liquids (“NGL”) pricing in the year.
InPlay continued to leverage our proven track
record of drilling efficiency and operational expertise, setting
industry pacesetting drilling times for horizontal wells in our
Willesden Green and Pembina core areas. Production results and
costs continued to be better than our expectations. The Company is
focused on project economics where we drill, complete and equip
wells, and build adaptable, fit for purpose, modular infrastructure
for the full development of a specific area. The results of our
project based economics combined with our technical expertise and
focused execution of our capital projects provided expected top
tier efficiencies including finding and development costs of
$13.98, $7.92 and $7.82 in proved developed producing (“PDP”),
total proved (“TP”) and total proved plus probable (“TPP”) reserve
categories respectively. This equates to recycle ratios of 1.6, 2.9
and 2.9 in all three respective categories and achieves capital
efficiencies in adding producing barrels of $18,387 per boe/d in
2019 which matches our three year average of $18,390 per boe/d.
These are all expected to be competitive with top tier
efficiencies amongst our light oil peers. The beginning
of 2020 was looking very promising for the energy industry with
stability in world oil prices and several industry agencies
predicting that demand would outpace supply at some point during
the upcoming year. These are unprecedented times and conditions
have changed quickly with concerns of demand destruction due to the
COVID – 19 outbreak. In addition, a crude oil price war was
initiated between certain OPEC+ members resulting in a quick and
severe drop in world oil prices. InPlay’s response to these events
will be to continue its approach of maintaining prudence and
financial flexibility with a focus on preserving value and the
balance sheet. Refer to the Outlook section for further details of
our reaction and plans, to address the current economic
situation.
InPlay is a nimble, focused Company that has
always reacted quickly to volatility in challenging environments.
The current situation we are facing is no exception. The Company
will be diligent and responsive to react quickly and resume our
capital program once the pricing environment improves. As we face
these difficult circumstances we would especially like to thank our
many dedicated shareholders, our dedicated staff and our strong and
vested Board of Directors for their guidance and
support.
2019 Highlights:
- Generated AFF(1) of $32.5 million ($0.48 per basic and diluted
share) during 2019, an increase of 20% compared to $27.0 million
($0.40 per basic and diluted share) in 2018.
- InPlay has always been focused on the prudent and efficient
deployment of capital. This is evident in the exceptional
finding and development costs incurred, and associated recycle
ratios, in developing new reserves, and the strong capital
efficiencies in adding new producing barrels. These metrics
are expected to be top tier amongst our light oil peers:
° Finding and development (“F&D”)(2) and finding,
development and acquisition (“FD&A”)(2) costs of $13.98/boe,
$7.92/boe, and $7.82/boe for PDP, TP and TPP reserve categories
respectively. ° Strong recycle ratios(2) of 1.6 (PDP),
2.9 (TP) and 2.9 (TPP) ° Generated capital
efficiency(2) of $18,387 per boe/d in 2019 which substantially
equals our average of $18,390 over the last three years.
- Averaged annual 2019 production of 5,000 boe/d, an increase of
7% compared to 4,653 boe/d in 2018, achieving our annual production
guidance of 5,000 – 5,200 boe/d which was increased in August 2019
due to the excellent drilling results during the year which
exceeded our expectations.
- Production growth was achieved notwithstanding the sale of
approximately 250 boe/d of non-core producing assets late in 2018
and an 11% reduction to originally forecasted 2019 capital
spending.
- Continued focus on efficiencies resulted in operating cost
rates decreasing 10% to $14.36/boe in 2019 compared to $16.02/boe
in 2018.
- Operating income profit margin(1) of 55% was generated in 2019
compared to 52% in 2018, an increase of 6% which was achieved even
with a 9% decrease in our overall realized prices per boe received
over the same respective periods.
- Achieved PDP reserve growth of 4% and TPP reserve growth of 1%
resulting in 120% and 113% replacement of production
respectively.
- Returns on the reduced capital program resulted in 15%
reduction in the Company’s annual Net Debt / AFF(2) ratio of to 1.7
times for 2019 compared to 2.0 times in 2018.
Notes:
- “Adjusted funds flow”,”operating income profit margin” and “net
debt / adjusted funds flow” do 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
Financial Measures” and “BOE equivalent” at the end of this news
release and to the section entitled “Non-GAAP Measures” in our
MD&A for details of calculations, rationale for use and
applicable reconciliation to the nearest IFRS measure.
- Refer to section “Performance Measures” for the determination
of these measures’ calculations
Financial and Operating Results:
(CDN) ($000’s) |
Three months endedDecember
31 |
Year endedDecember 31 |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
Financial (CDN$) |
|
|
|
|
Oil and natural gas sales |
18,425 |
|
12,716 |
|
75,025 |
|
76,419 |
|
Funds flow |
7,592 |
|
1,441 |
|
30,984 |
|
25,800 |
|
Per share – basic and diluted |
0.11 |
|
0.02 |
|
0.45 |
|
0.38 |
|
Per boe |
16.51 |
|
3.12 |
|
16.98 |
|
15.19 |
|
Adjusted funds flow(1) |
7,846 |
|
1,721 |
|
32,541 |
|
27,040 |
|
Per share – basic and diluted(1) |
0.11 |
|
0.03 |
|
0.48 |
|
0.40 |
|
Per boe(1) |
17.06 |
|
3.73 |
|
17.83 |
|
15.92 |
|
Comprehensive income (loss) |
(18,892 |
) |
(7,887 |
) |
(26,842 |
) |
(8,598 |
) |
Per share – basic and diluted |
(0.28 |
) |
(0.12 |
) |
(0.39 |
) |
(0.13 |
) |
Exploration and development capital expenditures |
4,574 |
|
6,954 |
|
32,106 |
|
50,206 |
|
Property acquisitions/(dispositions) |
14 |
|
(17,305 |
) |
93 |
|
(21,470 |
) |
Net debt |
(55,170 |
) |
(53,670 |
) |
(55,170 |
) |
(53,670 |
) |
Shares outstanding |
68,256,616 |
|
68,256,616 |
|
68,256,616 |
|
68,256,616 |
|
Basic & diluted weighted-average shares |
68,256,616 |
|
67,987,162 |
|
68,256,616 |
|
67,911,962 |
|
|
|
|
|
|
Operational |
|
|
|
|
Daily production volumes |
|
|
|
|
Light and medium crude oil (bbls/d) |
2,466 |
|
2,937 |
|
2,626 |
|
2,756 |
|
Natural gas liquids (boe/d) |
869 |
|
573 |
|
697 |
|
492 |
|
Natural gas (Mcf/d) |
9,978 |
|
9,065 |
|
10,058 |
|
8,431 |
|
Total (boe/d) |
4,998 |
|
5,021 |
|
5,000 |
|
4,653 |
|
Realized prices |
|
|
|
|
Light and medium crude oil & NGLs ($/bbls) |
52.54 |
|
35.09 |
|
56.59 |
|
60.49 |
|
Natural gas ($/Mcf) |
2.51 |
|
1.66 |
|
1.74 |
|
1.53 |
|
Total ($/boe) |
40.07 |
|
27.53 |
|
41.11 |
|
45.00 |
|
Operating netbacks ($/boe)(1) |
|
|
|
|
Oil and natural gas sales |
40.07 |
|
27.53 |
|
41.11 |
|
45.00 |
|
Royalties |
(2.32 |
) |
(2.43 |
) |
(3.19 |
) |
(4.72 |
) |
Transportation expense |
(0.67 |
) |
(1.00 |
) |
(0.81 |
) |
(0.83 |
) |
Operating costs |
(15.38 |
) |
(15.26 |
) |
(14.36 |
) |
(16.02 |
) |
Operating netback |
21.70 |
|
8.84 |
|
22.75 |
|
23.43 |
|
Realized gain (loss) on derivative contracts |
0.00 |
|
(0.66 |
) |
0.01 |
|
(2.42 |
) |
Operating netback (including realized derivative contracts) |
21.70 |
|
8.18 |
|
22.76 |
|
21.01 |
|
|
(1) “Adjusted funds flow”, “adjusted funds flow per share,
basic and diluted”, “adjusted funds flow per boe”, “operating
income”, “operating netback per boe” and “operating income profit
margin” do 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. “Adjusted funds flow” adjusts for decommissioning
expenditures from funds flow. Please refer to “Non-GAAP
Financial Measures” and “BOE equivalent” at the end of this news
release and to the section entitled “Non-GAAP Measures” in our
MD&A for details of calculations, rationale for use and
applicable reconciliation to the nearest IFRS measure. |
2019 Financial & Operations
Overview
InPlay delivered another year of exceptional
operational results while successfully responding to commodity
price challenges facing the industry. InPlay achieved organic drill
bit production growth of 7% over 2018 despite an 11% reduction in
originally planned capital spending to accommodate lower commodity
prices than originally forecasted. The Company continues to focus
on operational efficiencies which resulted in a 10% reduction to
operating costs to $14.36/boe in 2019 from $16.02/boe in 2018 and a
6% increase in operating income profit margin to 55% in 2019 from
52% in 2018 (which had higher realized prices). Prudent
decision making on the timing of capital expenditures, continued
drilling proficiency in our Willesden Green and Pembina core areas
and a strong focus on operational efficiencies allowed InPlay to
generate AFF in excess of capital spending and increased AFF by 20%
to $32.5 million in 2019 from $27.0 million in 2018. This growth in
the year was achieved without any share dilution and positioned the
Company with a solid net debt / adjusted funds flow ratio of 1.7
for 2019 compared to 2.0 in 2018.
InPlay’s 2019 capital program consisted of $32.1
million of development capital, focused on drilling wells in our
Willesden Green and Pembina Cardium areas, and was less than AFF
for the year. The Company drilled 10 (5.2 net) extended reach
horizontal (“ERH”) wells and three (3.0 net) one-mile horizontal
wells during the year ended December 31, 2019, amounting to an
equivalent of 22 gross horizontal miles (11.8 net horizontal miles)
and completed two (2.0 net) ERH wells that were drilled in the
fourth quarter of 2018. Eight (4.8 net) ERH wells were drilled in
Willesden Green and three (3.0 net) horizontal wells were drilled
in Pembina.
The results noted above were achieved in light
of negative market factors that affected Natural Gas Liquids
(“NGLs”) prices during 2019. Revenues were impacted by
multi-year lows in NGL prices beginning at the start of the second
quarter of 2019 which caused a 50% reduction in realized NGL prices
to $19.02/boe in 2019 from $38.27/boe in 2018, following continued
propane and butane price reductions. These lower NGL prices in
addition to lower WTI prices resulted in a 9% reduction in total
realized prices in 2019 compared to 2018. InPlay prudently
reacted to these deteriorating prices by reducing 2019 capital
expenditures by 11% compared to our initial forecast in order to
generate AFF that was in line with total capital expenditures.
2019 Reserve Highlights:
The strong performance of the Company’s assets,
specifically in the Willesden Green and Pembina areas is
highlighted by increased PDP year-end reserves by 4% to 8,718 mboe.
Following are the 2019 year-end reserve highlights derived from the
Sproule Report:
Reserves:
- PDP increased 4% to 8,718 mboe (63% light crude oil &
NGLs)
- TP decreased 2% to 18,573 mboe (69% light crude oil &
NGLs)
- TPP increased 1% to 27,295 mboe (71% light crude oil &
NGLs)
F&D and FD&A Costs per boe(1):
- PDP F&D and FD&A costs were $13.98
- TP F&D and FD&A costs were $7.92
- TPP F&D and FD&A costs were $7.82
Recycle Ratios(1):
- PDP was 1.6 times
- TP was 2.9 times
- TPP was 2.9 times
Reserve Replacement(1):
- PDP replacement was 120%
- TP replacement was 84%
- TPP replacement was 113%
Sustainability(1):
- PDP reserve life index of 4.8 years
- TP reserve life index of 10.2 years
- TPP reserve life index of 15.0 years
Growth was achieved in year-end reserves,
however decreases in WTI, natural gas and NGL pricing combined with
additional Abandonment, Decommissioning and Reclamation (“ADR”)
costs recognized as a result of changes to the Canadian Oil and Gas
Evaluation Handbook (“COGEH”) resulted in reductions to 2019
year-end reserve net present values (“NPV”) of future net revenues
and year-end net asset values (“NAV”)(2):
NAV based on NPV before tax discounted at 10%
(“NPV 10 BT”)(3):
- PDP NAV of $116 mm equating to $1.70 per basic share
- TP NAV of $196 mm equating to $2.87 per basic share
- TPP NAV of $311 mm equating to $4.56 per basic share
These results were accomplished despite the
following changes in Sproule’s year over year price
assumptions:
- WTI prices dropping 9%, and 7% in years 1 and 2 respectively
and 6% for the remaining years.
- Propane prices dropping 27% and 17% in years 1 and 2
respectively and 18% for the remaining years.
- Butane prices dropping 25% and 23% in years 1 and 2
respectively and 18% for the remaining years.
- AECO spot gas prices dropping 16% and 24% in years 1 and 2
respectively and 12% for the remaining years.
- NPV 10 BT in all reserve categories includes approximately $4.3
million ($0.06 per share) of additional future ARO compared to 2018
as recommended in COGEH's 2019 industry guidelines.
Notes:
- Refer to section “Performance Measures” for the determination
of these measures’ calculations
- Refer to section “Net Asset Value” for the determination of
these values.
- It should not be assumed that the net present value of
estimated future net revenue (“NPV”) presented 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 crude oil, natural gas liquids and natural gas reserves
provided herein are estimates only and there is no guarantee that
the estimated reserves will be recovered. Actual crude oil, natural
gas and natural gas liquids reserves may be greater than or less
than the estimates provided herein.
Corporate Reserves Information:
The following summarizes certain information
contained in the Sproule Report. The Sproule Report was
prepared in accordance with the definitions, standards and
procedures contained in the Canadian Oil and Gas Evaluation
Handbook (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 2020.
December 31, 2019 |
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 |
4,002.8 |
1,486.7 |
19,370 |
8,717.8 |
108,937 |
- |
- |
Proved developed
non-producing |
165.9 |
16.8 |
289 |
230.9 |
3,743 |
560 |
- |
Proved undeveloped |
6,082.3 |
1,042.8 |
14,998 |
9,624.7 |
76,427 |
166,649 |
81.7 |
Total proved |
10,251.0 |
2,546.3 |
34,657 |
18,573.4 |
189,108 |
167,209 |
81.7 |
Probable developed
producing |
1,041.1 |
370.6 |
4,839 |
2,218.4 |
21,159 |
- |
- |
Probable developed
non-producing |
157.6 |
26.2 |
410 |
252.1 |
5,142 |
102 |
- |
Probable undeveloped |
4,235.2 |
621.6 |
8,366 |
6,251.2 |
88,880 |
57,723 |
26.6 |
Total probable |
5,434.0 |
1,018.5 |
13,616 |
8,721.7 |
115,182 |
57,825 |
26.6 |
Total proved plus probable(6) |
15,684.9 |
3,564.7 |
48,273 |
27,295.1 |
304,289 |
225,034 |
108.3 |
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 Sproule’s December 31, 2019, escalated price forecast
as outlined in the table herein entitled “Pricing
Assumptions”.
- It should not be assumed that the net present value of
estimated future net revenue (“NPV”) 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 crude oil, natural gas liquids and natural
gas reserves provided herein are estimates only and there is no
guarantee that the estimated reserves will be recovered. Actual
crude oil, 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 and
reclamation costs and estimated future capital expenditures. Future
net revenues have been presented on a before tax basis.
- In 2018, the InPlay reserve report included abandonment and
reclamation costs for active wells and locations only. As
recommended in the October 2019 COGEH updated guidance, the Company
has now also included abandonment, decommissioning and reclamation
costs for all inactive assets including non-producing and suspended
wells, facilities and pipelines. The impact on the Sproule Report
from these additional burdens on total Proved plus Probable
reserves is estimated at $4.3 million of value discounted at 10%,
which will differ from the discounted values carried in our
financial reporting, due to differences in abandonment activity
timing and different inflation and discount values
- Totals may not add due to rounding.
Net Asset Value:
December 31, 2019 |
|
|
|
|
|
BTAX NPV
5% |
BTAX NPV
10% |
|
($000’s) |
$/share(5) |
($000’s) |
$/share(5) |
PDP NPV(1)(2) |
110,235 |
|
1.62 |
|
108,937 |
|
1.60 |
|
Undeveloped acreage(3) |
62,155 |
|
0.91 |
|
62,155 |
|
0.91 |
|
Net debt(4) |
(55,170 |
) |
(0.81 |
) |
(55,170 |
) |
(0.81 |
) |
|
|
|
|
|
Net Asset Value (basic) |
117,220 |
|
1.72 |
|
115,922 |
|
1.70 |
|
December 31, 2019 |
|
|
|
|
|
BTAX NPV
5% |
BTAX NPV
10% |
|
($000’s) |
$/share(5) |
($000’s) |
$/share(5) |
TP NPV(1)(2) |
226,373 |
|
3.32 |
|
189,108 |
|
2.77 |
|
Undeveloped acreage(3) |
62,155 |
|
0.91 |
|
62,155 |
|
0.91 |
|
Net debt(4) |
(55,170 |
) |
(0.81 |
) |
(55,170 |
) |
(0.81 |
) |
|
|
|
|
|
Net Asset Value (basic) |
233,358 |
|
3.42 |
|
196,093 |
|
2.87 |
|
December 31, 2019 |
|
|
|
|
|
BTAX NPV
5% |
BTAX NPV
10% |
|
($000’s) |
$/share(5) |
($000’s) |
$/share(5) |
TPP NPV(1)(2) |
385,824 |
|
5.65 |
|
304,289 |
|
4.46 |
|
Undeveloped acreage(3) |
62,155 |
|
0.91 |
|
62,155 |
|
0.91 |
|
Net debt(4) |
(55,170 |
) |
(0.81 |
) |
(55,170 |
) |
(0.81 |
) |
|
|
|
|
|
Net Asset Value (basic) |
392,809 |
|
5.75 |
|
311,274 |
|
4.56 |
|
Notes:
- Evaluated by Sproule as at December 31, 2019. The
estimated net present value of future net revenue (“NPV”) does not
represent fair market value of the reserves.
- Based on Sproule’s forecast prices and costs as of December 31,
2019.
- Duvernay land holdings evaluated by independent third party
firm Seaton-Jordan Partners effective December 31, 2018 attributed
a value of $49.6 mm ($1,627/acre) for 30,480 net acres. The
remaining undeveloped acreage is based on an internal valuation
totaling $12.6 mm ($344/acre) for 36,550 net acres.
- Net debt as at December 31, 2019.
- Based upon 68,256,616 common shares outstanding as at December
31, 2019.
Future Development Costs (“FDCs”):
FDCs decreased by $18.5 million on a Total
Proved basis and $14.6 million on a Proved plus Probable basis.
Future
Development Capital Costs (amounts in $000,000’s) |
|
Total Proved |
Total Proved + Probable |
2020 |
36.6 |
41.2 |
2021 |
45.5 |
55.6 |
2022 |
43.4 |
55.7 |
2023 |
41.7 |
51.8 |
Remainder |
- |
50.7 |
Total undiscounted FDC |
167.2 |
255.0 |
Total discounted FDC at 10% per year |
139.1 |
182.8 |
Note: FDC as per Sproule Report based on Sproule
forecast pricing as at December 31, 2019
Performance Measures:
|
2017 |
|
2018 |
|
2019 |
|
3 Year Avg |
|
Average crude
oil price WTI US$/bbl |
50.95 |
|
64.76 |
|
57.02 |
|
57.58 |
|
E&D Capital ($000’s)(1) |
40,679 |
|
20,251 |
|
30,689 |
|
- |
|
Production boe/day – Full Year |
3,972 |
|
4,653 |
|
5,000 |
|
4,542 |
|
Production boe/day – Q4 |
4,185 |
|
5,021 |
|
4,998 |
|
4,735 |
|
Operating netback $/boe – FY(2) |
21.89 |
|
23.43 |
|
22.75 |
|
22.69 |
|
Proved Developed
Producing |
|
|
|
|
Total Reserves mboe |
7,911 |
|
8,348 |
|
8,718 |
|
8,326 |
|
Reserves additions mboe |
2,057 |
|
2,135 |
|
2,195 |
|
2,129 |
|
FD&A (including FDCs) $/boe(2) |
19.77 |
|
9.49 |
|
13.98 |
|
14.34 |
|
FD&A (excluding FDCs) $/boe(2) |
19.77 |
|
9.49 |
|
13.98 |
|
14.34 |
|
Recycle Ratio(3) |
1.1 |
|
2.5 |
|
1.6 |
|
1.6 |
|
Reserves Replacement(4) |
142 |
% |
126 |
% |
120 |
% |
128 |
% |
RLI (years)(5) |
5.2 |
|
4.9 |
|
4.8 |
|
4.9 |
|
Total Proved |
|
|
|
|
Total Reserves mboe |
17,473 |
|
18,859 |
|
18,573 |
|
18,302 |
|
Reserves additions mboe |
2,345 |
|
3,084 |
|
1,540 |
|
2,323 |
|
FD&A (including FDCs) $/boe(2) |
27.88 |
|
16.94 |
|
7.92 |
|
18.63 |
|
FD&A (excluding FDCs) $/boe(2) |
17.35 |
|
6.57 |
|
19.93 |
|
13.15 |
|
Recycle Ratio(3) |
0.8 |
|
1.4 |
|
2.9 |
|
1.2 |
|
Reserves Replacement(4) |
162 |
% |
182 |
% |
84 |
% |
140 |
% |
RLI (years)(5) |
11.4 |
|
11.1 |
|
10.2 |
|
11.3 |
|
Proved Plus Probable |
|
|
|
|
Total Reserves mboe |
26,084 |
|
27,063 |
|
27,295 |
|
26,814 |
|
Reserves additions mboe |
3,048 |
|
2,678 |
|
2,057 |
|
2,594 |
|
FD&A (including FDCs) $/boe(2) |
26.17 |
|
15.96 |
|
7.82 |
|
17.81 |
|
FD&A (excluding FDCs) $/boe(2) |
13.35 |
|
7.56 |
|
14.92 |
|
11.77 |
|
Recycle Ratio(3) |
0.8 |
|
1.5 |
|
2.9 |
|
1.3 |
|
Reserves Replacement(4) |
210 |
% |
158 |
% |
113 |
% |
156 |
% |
RLI (years)(5) |
17.1 |
|
15.9 |
|
15.0 |
|
15.9 |
|
In 2019, InPlay’s successful exploration, development and
acquisition/disposition capital program achieved a capital
efficiency of $18,387 per boe/d and a three year average of $18,390
per boe/d.(6)
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:
2019 TPP = ($32.2 mm E&D - $1.5 mm capitalized G&A - $nil
mm of land acquisitions – $nil mm net acquisition/disposition
capital - $14.6 mm FDC) / (27,295 mboe – 27,063 mboe + 1,825
mboe) = $7.82 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 section.
- “Operating netback per boe” 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
Financial Measures” and “BOE equivalent” at the end of this news
release and to the section entitled “Non-GAAP Measures” in our
MD&A for details of calculations, rationale for use and
applicable reconciliation to the nearest IFRS measure.
- Recycle Ratio is calculated by dividing the year’s operating
netback per boe by the FD&A costs for that period. For example:
2019 TPP = ($22.75/$7.82) = 2.9. 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 section.
- 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: 2019 TPP = (27,295 mboe –
27,063 mboe + 1,825 mboe) / 1,825 mboe = 113%, 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
section.
- RLI is calculated by dividing the reserves in each category by
the 2019 average annual production. For example 2019 TPP = (27,295
mboe) / (5,000 boeday) = 15.0 years. See Information Regarding
Disclosure on Oil and Gas Reserves and Operational Information
section.
- 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 34%
over the course of the year, calculated as follows: ($32.2 mm
E&D capital - $nil mm acquisition/disposition capital - $1.5mm
capitalized G&A - $nil mm land acquisitions) / (Q4/2019
production of 4,998 boe/d – Q4/2018 production of 5,021 boe/d +
2019 declined production at 34% of 1,692 boe/d). See Information
Regarding Disclosure on Oil and Gas Reserves and Operational
Information section.
Pricing Assumptions:
The following tables set forth the benchmark
reference prices, as at December 31, 2019, reflected in the Sproule
Report. These price assumptions were provided to InPlay by Sproule
and were Sproule's then current forecast at the effective date of
the Sproule Report.
SUMMARY OF PRICING AND INFLATION RATE
ASSUMPTIONS (1) as of December 31, 2019 FORECAST PRICES AND
COSTS
Year |
WTICushingOklahoma($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) |
|
|
|
|
|
|
|
|
|
|
2020 |
61.00 |
73.84 |
73.84 |
2.04 |
25.07 |
37.72 |
76.32 |
0.0% |
0.0% |
0.76 |
2021 |
65.00 |
78.51 |
77.51 |
2.27 |
31.84 |
43.90 |
80.52 |
1.0% |
1.0% |
0.77 |
2022 |
67.00 |
78.73 |
77.73 |
2.81 |
32.43 |
47.74 |
80.00 |
2.0% |
2.0% |
0.80 |
2023 |
68.34 |
80.30 |
79.30 |
2.89 |
33.26 |
48.69 |
81.68 |
2.0% |
2.0% |
0.80 |
2024 |
69.71 |
81.91 |
80.91 |
2.98 |
34.12 |
49.67 |
83.38 |
2.0% |
2.0% |
0.80 |
2025 |
71.10 |
83.54 |
82.54 |
3.06 |
34.99 |
50.66 |
85.13 |
2.0% |
2.0% |
0.80 |
2026 |
72.52 |
85.21 |
84.21 |
3.15 |
35.88 |
51.67 |
86.90 |
2.0% |
2.0% |
0.80 |
2027 |
73.97 |
86.92 |
85.92 |
3.24 |
36.78 |
52.71 |
88.72 |
2.0% |
2.0% |
0.80 |
2028 |
75.45 |
88.66 |
87.66 |
3.33 |
37.71 |
53.76 |
90.57 |
2.0% |
2.0% |
0.80 |
2029 |
76.96 |
90.43 |
89.43 |
3.42 |
38.65 |
54.84 |
92.45 |
2.0% |
2.0% |
0.80 |
2030 |
78.50 |
92.24 |
91.24 |
3.51 |
39.61 |
55.93 |
94.38 |
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, 2019.
Outlook:
InPlay began the 2020 capital program drilling
one (1.0 net) ERH horizontal Willesden Green well and three (3.0
net) horizontal Pembina wells in the first quarter of 2020.
The Company also recompleted and commissioned a water disposal well
in Pembina which is expected to provide long term savings in the
area. All wells drilled in the first quarter have been
completed and placed on production albeit at lower ramp up rates
than would normally occur, as a result of the current low oil
price.
In January of 2020, the Company’s Board of
Directors had approved a 2020 capital program of $35 million which
was less than projected AFF on WTI futures pricing of $57
USD/bbl. With the significant drop and volatility in world
crude oil prices as a result of the COVID – 19 outbreak and the
corresponding oil price war, consistent with past practices the
Company will manage its spending and adjust the capital program
accordingly throughout 2020 and no longer has plans for capital
spending of $35 million. InPlay has completed its first quarter
capital program and only minimal capital spending is expected over
the second quarter during spring break-up. As such, no major
capital spending decisions are being made at this time. Capital
planning decisions for the second half of 2020 and any updated
forecasts will be made in due course in consideration of forecasted
AFF reflecting the prevailing commodity prices at that
time.
The Company’s low decline rate, strong operating
netbacks, top-tier capital efficiencies, lack of drilling
commitments and primarily operated capital program provide
flexibility in this volatile market. Efforts have been initiated to
optimize operations in order to minimize costs and preserve value
for the Company. All operations will be thoroughly vetted to
optimize corporate cash flows which may include shutting in any
wells that that will not generate positive cash flow under current
prices (net of fixed cost considerations). Further operating
and corporate cost efficiencies will also be pursued in
consideration of the current pricing environment.
For further information please contact:
Doug Bartole President and Chief Executive Officer InPlay Oil Corp.
Telephone: (587) 955-0632 |
Darren Dittmer Chief Financial Officer InPlay Oil Corp. Telephone:
(587) 955-0634 |
Reader Advisories
Non-GAAP Financial
MeasuresIncluded in this press release are references to
the terms “adjusted funds flow”, “adjusted funds flow per share,
basic and diluted”, “adjusted funds flow per boe”, “operating
income”, “operating netback per boe” and “operating income profit
margin”. 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, “funds flow”, “profit (loss) before
taxes”, “profit (loss) and comprehensive income (loss)” or assets
and liabilities as determined in accordance with GAAP as a measure
of the Company’s performance and financial position.
InPlay uses “adjusted funds flow”, “adjusted funds flow per
share, basic and diluted” and “adjusted funds flow per boe” as key
performance indicators. Adjusted funds flow should not be
considered as an alternative to or more meaningful than funds flow
as determined in accordance with GAAP as an indicator of the
Company’s performance. InPlay’s determination of adjusted
funds flow may not be comparable to that reported by other
companies. Adjusted funds flow is calculated by adjusting for
decommissioning expenditures from funds flow. 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, making the exclusion of this
item relevant in Management’s view to the reader in the evaluation
of InPlay’s operating performance. Adjusted funds flow per share,
basic and diluted is calculated by the Company as adjusted funds
flow divided by the weighted average number of common shares
outstanding for the respective period. Management considers
adjusted funds flow per share, basic and diluted an important
measure to evaluate its operational performance as it demonstrates
its recurring operating cash flow generated attributable to each
share. Adjusted funds flow per boe is calculated by the
Company as adjusted funds flow divided by production for the
respective period. Management considers adjusted funds flow per boe
an important measure to evaluate its operational performance as it
demonstrates its recurring operating cash flow generated per unit
of production. For a detailed description of InPlay’s method of
calculating adjusted funds flow, adjusted funds flow per share,
basic and diluted and adjusted funds flow per boe and their
reconciliation to the nearest GAAP term, refer to the section
“Non-GAAP Measures” in the Company’s MD&A filed on
SEDAR.
InPlay also uses “operating income”, “operating netback per boe”
and “operating income profit margin” as key performance indicators.
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
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 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. For a
detailed description of InPlay’s method of the calculation of
operating income, operating netback per boe and operating income
profit margin and their reconciliation to the nearest GAAP term,
refer to the section “Non-GAAP Measures” in the Company’s MD&A
filed on SEDAR.
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 value ascribed to undeveloped acreage; production
estimates including 2020 annualized forecasts; targeted 2020 annual
organic production growth; light oil and liquids weighting
estimates; future oil and natural gas prices; the assumption that
adjusted funds flow will equal or be less than capital
expenditures; 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 2020 capital program,
suspension thereof and future updates thereto the number of wells
to be drilled, completed and tied-in and the timing thereof; the
amount and timing of capital projects; forecasted spending on
decommissioning; our belief that we will deliver top tier returns,
capital efficiencies, production growth and production per share
growth; the potential for long-term savings resulting from our
water disposal well at Pembina; the potential of our Duvernay
project and extension of our land holdings; 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;
expectations regarding the potential impact of COVID-19 and oil
price wars including planned reductions or suspension of our 2020
capital program; 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: changes in our planned 2020 capital program;
changes in commodity prices; 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 of InPlay or by third party operators of our
properties; increased debt levels or debt service requirements;
inaccurate estimation of our oil and 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 disclosure documents.
The internal projections, expectation or beliefs
underlying InPlay's 2020 capital program and associated guidance
for 2020 is subject to change based on ongoing results, prevailing
economic circumstances, commodity prices and industry
conditions. InPlay's outlook for 2020 and beyond provides
shareholders with relevant information on management's expectations
for results of operations, excluding any potential acquisitions,
dispositions or other strategic transactions that may be completed
in 2020 or beyond. Accordingly, readers are cautioned that
events or circumstances could cause results to differ materially
from those predicted and InPlay's guidance may not be appropriate
for other purposes.
In early 2020, the Company disclosed guidance
for 2020 including its forecast capital program, net wells planned
to be drilled, forecast annual average production, AFF and
operating income profit margin. Given the planned suspension of the
capital program for the second quarter (which may be extended
further), the Company has elected to withdraw this FLI as this
forecast is no longer applicable given the significant declines and
volatility in the spot price for oil for various reasons linked to
the Coronavirus pandemic and other conditions impacting
worldwide oil prices.
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.
Information Regarding Disclosure on Oil
and Gas Reserves and Operational InformationOur oil and
gas reserves statement for the year ended December 31, 2019, 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, 2020. 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 below
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” and “recycle ratio”, “reserve replacement” and
"reserve life index or “RLI”. Each of these terms are
calculated by InPlay as described 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 and
exploration costs incurred acquiring Duvernay lands with no
reserves assigned 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.
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.
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.
Inplay Oil (TSX:IPO)
Historical Stock Chart
From Mar 2024 to Apr 2024
Inplay Oil (TSX:IPO)
Historical Stock Chart
From Apr 2023 to Apr 2024