InPlay Oil Corp. (TSX: IPO) (OTCQX: IPOOF) (“InPlay” or the
“Company”) is pleased to announce its financial and operating
results for the three and nine months ended September 30,
2019. InPlay’s condensed unaudited interim financial
statements and notes, as well as management’s discussion and
analysis (“MD&A”) for the three and nine months ended September
30, 2019 will be available at “www.sedar.com” and our website at
“www.inplayoil.com”.
Third Quarter 2019 Financial &
Operating Highlights
- Achieved average quarterly production of 5,080 boe/d (66% light
oil and liquids) in the third quarter of 2019, an increase of 6%
compared to 4,773 boe/d (69% light oil and liquids) in the third
quarter of 2018.
- Year to date production growth of 10% was attained with average
production of 5,000 boe/d (66% light oil and liquids) in the first
nine months of 2019 compared to 4,529 boe/d (70% light oil and
liquids) in the first nine months of 2018. Production growth was
achieved notwithstanding the sale of approximately 250 boe/d of
non-core producing assets in October 2018.
- Generated adjusted funds flow (“AFF”)(1) of $24.7 million
($0.36 per basic and diluted share) during the first nine
months of 2019 compared to $25.3 million ($0.37 per basic and
diluted share) generated in the first nine months of 2018. These
results were achieved despite a 15% decrease in West Texas
Intermediate (“WTI”) prices as well as a 52% decrease in the
Company’s realized Natural Gas Liquids (“NGLs”) prices over the
same respective periods.
- Continued focus on efficiencies resulted in operating costs
decreasing 14% to $13.47/boe in the third quarter of 2019 compared
to $15.62/boe in the third quarter of 2018 and decreasing 6%
compared to $14.31 in the second quarter of 2019. This decrease,
combined with lower royalty rates largely from lower Alberta par
prices, resulted in operating netbacks(1) of $23.11/boe for the
first nine months of 2019.
- Operating income profit margin(1) of 56% was generated in the
first nine months of 2019 compared to 56% in the first nine months
of 2018, even with significantly lower realized light oil, natural
gas and NGL prices received over the same respective periods.
- The Company has improved its net debt position by 12% over the
past year, to $58.1 million at September 30, 2019 compared to $66.0
million at September 30, 2018, despite significantly lower realized
light oil, natural gas and NGL prices received during the period
and while maintaining an active drilling program resulting in top
tier production growth amongst light oil weighted peers.
Fourth Quarter 2019 Update
- The Company is on pace to meet its annual average production
guidance while reducing its 2019 capital expenditure program by
approximately 11 percent to $32 million (from $36 million).
- Current production based on field estimates is approximately
5,560 boe/d.
- Production growth per basic share is expected to be 8 – 10%
year over year with capital spending approximating adjusted funds
flow for the year.
- Continued improvement in capital efficiencies were driven by
strong well results and lower drilling costs. InPlay recently
drilled and completed a three well pad (1.0 mile horizontal
lengths) in Pembina which delivered record setting total drilling
days for Pembina (as low as 4.1 days/well) leading to average well
costs of $1.8 million (drill, complete, equip and tie-in), a 25
percent reduction from $2.4 million spent on our last Pembina
program.
- Operating income profit margins(1) are forecasted to remain in
the 55 – 56% range for 2019 in light of volatile and lower
commodity prices.
Financial and Operating Results:
(CDN) ($000’s) |
Three months endedSeptember
30 |
Nine months endedSeptember
30 |
|
2019 |
|
2018 |
|
2019 |
|
2018 |
|
Financial (CDN$) |
|
|
|
|
Oil and natural gas sales |
17,395 |
|
22,801 |
|
56,600 |
|
63,703 |
|
Funds flow |
6,397 |
|
9,962 |
|
23,391 |
|
24,360 |
|
Per share – basic and diluted |
0.09 |
|
0.15 |
|
0.34 |
|
0.36 |
|
Per boe |
13.69 |
|
22.69 |
|
17.14 |
|
19.70 |
|
Adjusted funds flow(1) |
6,886 |
|
10,006 |
|
24,694 |
|
25,320 |
|
Per share – basic and diluted(1) |
0.10 |
|
0.15 |
|
0.36 |
|
0.37 |
|
Per boe(1) |
14.73 |
|
22.79 |
|
18.09 |
|
20.48 |
|
Comprehensive (loss) |
(1,355 |
) |
(1,775 |
) |
(7,949 |
) |
(710 |
) |
Per share – basic and diluted |
(0.02 |
) |
(0.03 |
) |
(0.12 |
) |
(0.01 |
) |
Exploration and development capital expenditures |
8,082 |
|
17,376 |
|
27,533 |
|
43,252 |
|
Property acquisitions/(dispositions) |
- |
|
(26 |
) |
78 |
|
(4,164 |
) |
Net debt |
(58,053 |
) |
(66,005 |
) |
(58,053 |
) |
(66,005 |
) |
Shares outstanding |
68,256,616 |
|
67,886,619 |
|
68,256,616 |
|
67,886,619 |
|
Basic & diluted weighted-average shares |
68,256,616 |
|
67,886,619 |
|
68,256,616 |
|
67,886,619 |
|
|
|
|
|
|
Operational |
|
|
|
|
Daily production volumes |
|
|
|
|
Crude oil (bbls/d) |
2,580 |
|
2,775 |
|
2,680 |
|
2,695 |
|
Natural gas liquids (bbls/d) |
748 |
|
541 |
|
639 |
|
465 |
|
Natural gas (Mcf/d) |
10,509 |
|
8,738 |
|
10,085 |
|
8,218 |
|
Total (boe/d) |
5,080 |
|
4,773 |
|
5,000 |
|
4,529 |
|
Realized prices |
|
|
|
|
Crude oil & NGLs ($/bbls) |
54.17 |
|
71.48 |
|
57.96 |
|
70.00 |
|
Natural gas ($/Mcf) |
0.84 |
|
1.23 |
|
1.48 |
|
1.48 |
|
Total ($/boe) |
37.22 |
|
51.93 |
|
41.47 |
|
51.52 |
|
Operating netbacks ($/boe)(1) |
|
|
|
|
Oil and natural gas sales |
37.22 |
|
51.93 |
|
41.47 |
|
51.52 |
|
Royalties |
(3.55 |
) |
(6.03 |
) |
(3.49 |
) |
(5.57 |
) |
Transportation expense |
(0.76 |
) |
(0.77 |
) |
(0.85 |
) |
(0.77 |
) |
Operating costs |
(13.47 |
) |
(15.62 |
) |
(14.02 |
) |
(16.30 |
) |
Operating netback |
19.44 |
|
29.51 |
|
23.11 |
|
28.88 |
|
Realized gain (loss) on derivative contracts |
0.00 |
|
(1.75 |
) |
0.02 |
|
(3.08 |
) |
Operating netback (including realized derivative
contracts) |
19.44 |
|
27.76 |
|
23.13 |
|
25.80 |
|
(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.
Third Quarter 2019 Financial &
Operations Overview
InPlay’s capital program of $8.0 million for the
third quarter of 2019 consisted of completing and bringing on
production at the end of July two (2.0 net) ERH Cardium wells that
were drilled in the second quarter of 2019. Two (0.3 net)
non-operated ERH Cardium wells were drilled and completed and were
placed on production in September, and one (0.2 net) non-operated
ERH Nisku Pembina well was drilled and completed in the third
quarter and placed on production early in the fourth quarter.
The two (2.0 net) Willesden Green 1.5 mile ERH wells that
were drilled in June and brought on production in late July were
among the top five producing Cardium oil wells in Alberta during
the quarter with cumulative oil production of 28,876 bbls over the
first 65 days and 26,171 bbls over 66 days respectively. Total
average drilling, completion and equipping costs of $3.25 million
amounted to our lowest realized costs to date. Given recent
advances in drilling and completion efficiencies in the Pembina
area, a portion of the Company’s capital program in the third
quarter of 2019 was allocated to our Central Pembina Cardium
assets. The Company drilled three (3.0 net) one mile Pembina
Cardium wells during the third quarter of 2019, setting industry
pacesetting drill times of 4.2, 4.1 and 4.8 days
respectively. The first two of these wells were the fastest
horizontal Pembina Cardium wells drilled to date. More
importantly, approximately $750,000 was spent per well on drilling
operations, which was significantly lower than the Company’s
internal expectations and budget. These wells were completed and
brought on production in the third week of October 2019.
Production for the quarter of 5,080 boe/d (66%
light oil and liquids) resulted in average production for the first
nine months of 2019 of 5,000 boe/d (66% light oil and liquids).
This results in ten percent production growth for the nine months
ended 2019 over 2018. With current production of 5,560 boe/d
(field estimates) and three new Pembina wells in their initial
clean-up phase, the Company is well positioned to meet its 2019
annual production guidance of 5,000 – 5,200 boe/d (67% - 70% light
oil and liquids).
Reduced commodity prices weighed on financial
results in the third quarter of 2019. Oil prices were
significantly lower over the third quarter with WTI prices
averaging $56.45 USD/bbl, compared to $69.46 USD/bbl for the third
quarter of 2018. Natural gas and NGL prices were also significantly
lower over the third quarter with natural gas AECO daily index
prices averaging $0.82 CDN/mcf compared to $1.07 CDN/mcf for the
third quarter of 2018. Natural Gas Liquids prices currently are at
multi-year lows as the Company’s realized NGL prices averaged
$14.60 CDN/bbl in the third quarter of 2019 compared to $42.18
CDN/bbl over the same respective period in 2018 following continued
reduced propane and butane pricing. Offsetting the weakness
in commodity prices is a 14% reduction in operating costs
($13.47/boe for the third quarter of 2019 compared to $15.62/boe in
the third quarter of 2018). AFF for the third quarter of 2019
decreased to $6.9 million ($0.10 per basic share) compared to $10.0
million ($0.15 per basic share) for the third quarter of 2018
following the reduced commodity prices over the respective periods.
To put things in perspective, had third quarter Q3 2019 realized
prices remained the same as third quarter 2018 prices, AFF for the
quarter would have been approximately $12.0 million ($0.18 per
basic share), 73% higher than the $6.9 million realized in the
third quarter of 2019.
Outlook
InPlay continues to outperform operationally
with production from our drilling results to date exceeding our
internal forecasted type curves. Given the strong results achieved
year to date, the Company is on pace to achieve its annual average
production guidance without drilling any additional wells.
Accordingly, InPlay does not plan to drill any additional wells in
2019 thereby reducing its annual capital budget by 11% to $32
million (from $36 million).
The three 100% Pembina wells which were placed
on production the third week of October are currently meeting
expectations and are still in an early clean up stage. Over
the first seventeen days of production they are averaging 183 boed
(96% light oil) per well. More importantly are the capital
efficiencies being achieved at Pembina as we transferred our
refined completion operations from Willesden Green and are also
utilizing fundamentally refined changes in drilling and equipping
practices in Pembina. This has resulted in costs to drill,
complete, equip and tie-in these wells of approximately $1.8
million per well compared to the $2.4 million we previously spent
on a drilling operation in Pembina two years ago. InPlay
believes the encouraging initial production results combined with
the 25% reduction in capital costs makes Pembina development
economically competitive with its industry leading Willesden Green
economics. The Company has
achieved its exit production guidance of 5,500 – 5,700 boe/d (67 -
70% light oil and liquids) early as current production, based on
field estimates, is approximately 5,560 boe/d (66% light oil and
liquids).
InPlay now plans to drill 8.2 net horizontal
wells in 2019 compared to the 9.0 – 10.0 net horizontal wells
originally forecasted. This results in an 11% reduction in
total forecasted 2019 capital expenditures to approximately $32
million compared to our previous forecast of $36 million and
production is anticipated to be in the lower half of our annual
average production guidance of 5,000 – 5,200 boe/d (66% - 70% light
oil and liquids) generating annual average production growth of
between 8% - 10%. This program is forecast to result in 2019
AFF of $31 - $34 million in line with total capital
expenditures. These results are anticipated to result in top
tier organic light oil and liquids growth among our light oil peers
for 2019.
Volatility in commodity prices continues into
the fourth quarter of 2019 with forward WTI prices fluctuating
between US$54.00/bbl and US$57.00/bbl with a strong improvement in
AECO pricing ranging between $2.25 - $3.00/Mcf. Edmonton
light sweet differentials had returned to historically normal
levels over the first nine months of 2019 and started the fourth
quarter between a $4.00 - $4.50 USD/bbl discount to WTI but has
currently increased to over an $8.00 USD/bbl discount to WTI for
December of 2019 with the current shut-in of the Keystone XL
pipeline. InPlay continues to forecast depressed NGL pricing
for the remainder of 2019, however we expect to see improved prices
in the new year.
InPlay’s strategy is to leverage management’s
strong technical and operational capabilities to deliver top tier
production growth, capital efficiencies and returns relative to our
light oil peers. We are focused on running a sustainable
junior oil company with a long term view to ensure we maintain a
strong financial position during volatile commodity prices and
during periods with limited access to capital. InPlay has
reacted to these market factors as we see widening differentials
into year-end by reducing development capital while still providing
8 – 10% production growth over 2018. Our financial and
operational flexibility will allow us to react quickly and expand
activity as market factors
improve.
We thank our employees and directors for their
ongoing commitment and dedication and we thank all of our
shareholders for their continued interest and support. We are
excited about the strong operational results we have achieved to
date and will continue to adhere to our prudent strategy when
facing volatile commodity pricing. We look forward to issuing
our 2020 capital budget in January 2020 which we expect will
initially, similar to 2019, approximate AFF based on future
commodity pricing at that time.
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: production estimates including current
2019 annualized and exit forecasts; targeted production growth;
light oil and liquids weighting estimates; future oil and natural
gas prices; forecasted 2019 adjusted funds flow; forecasted 2019
operating income profit margins; 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 2019 capital
program, the number of wells to be drilled, completed and tied-in
and the timing thereof; the amount and timing of capital projects;
our belief that we will deliver top tier returns and capital
efficiencies; that our Pembina development has the potential to be
competitive with our Willesden Green economics; and the resource
potential of our Duvernay play; 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;
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 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 2019 capital budget and guidance for 2019 is
subject to change based on ongoing results, prevailing economic
circumstances, commodity prices and industry conditions.
InPlay's outlook for 2019 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 2019 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.
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.
The assumptions used by the Company in the
development of forecasted 2019 adjusted funds flow and 2019
operating income profit margin are as follows:
WTI |
US$/bbl |
$56.70 |
|
|
|
|
NGL
Price |
$/boe |
$19.00 |
|
|
|
|
AECO |
$/GJ |
$1.75 |
|
|
|
|
Foreign
Exchange rate |
(US$/CDN$) |
0.75 |
|
|
|
|
MSW
Differential |
US$/bbl |
$5.00 |
|
|
|
|
Production |
Boe/d |
5,000 – 5,200 |
|
|
|
|
Royalties |
$/boe |
3.25 – 3.75 |
|
|
|
|
Operating
expenses |
$/boe |
13.75 – 14.50 |
|
|
|
|
Transportation |
$/boe |
0.75 – 0.95 |
|
|
|
|
Interest |
$/boe |
1.25 – 1.50 |
|
|
|
|
General
and administrative |
$/boe |
3.25 – 3.95 |
|
|
|
|
Decommissioning Expenditures |
$ millions |
1.1 – 1.5 |
|
|
|
|
- NGLs estimated to represent approximately 19% - 21% of total
oil and liquids production
- Quality and pipeline transmission adjustments may impact
realized oil prices in addition to the MSW Differential provided
above
Forecasted full year 2019 commodity price
reductions including a USD $0.50/bbl decrease in WTI and $4.00/boe
decrease in realized NGL prices are the main factors causing a $2
million decrease in 2019 funds flow and adjusted funds flow from
that previously forecasted.
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.
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