CALGARY, March 18, 2020 /CNW/ - (TSX:PMT) -
Perpetual Energy Inc. ("Perpetual", or the "Company") is pleased to
release its fourth quarter and year-end 2019 financial and
operating results and a summary of the Company's year-end 2019
reserves as reported by the independent engineering firm McDaniel
and Associates Consultants Ltd. ("McDaniel"). A complete copy of
Perpetual's audited consolidated financial statements, Management's
Discussion and Analysis ("MD&A") and Annual Information Form
for the year ended December 31, 2019
are available through the Company's website at
www.perpetualenergyinc.com and SEDAR at www.sedar.com.
FOURTH QUARTER 2019 HIGHLIGHTS
Capital Spending, Production and Operations
- Fourth quarter exploration and development expenditures of
$2.0 million were directed towards
the Eastern Alberta core area, and
included acquisition of additional undeveloped crown lands focused
on the Clearwater play and initial
costs to drill two (2.0 net) multi-lateral horizontal heavy oil
wells targeting the Clearwater
formation at Ukalta that were spud in late December. These two
wells were brought on production in late January, with an
additional two (2.0 net) wells drilled, completed, and put on
production in late-February.
- Preliminary results to date for the Ukalta Clearwater play are
positive. Heavy oil production for the four (4.0 net) first quarter
2020 drills has been ramping up, and is currently averaging an
aggregate of 540 bbl/d. Combined with the Company's two (2.0 net)
initial Clearwater discovery wells
drilled in the third quarter of 2019, the Ukalta Clearwater play is
currently contributing approximately 730 bbl/d to the Company's
heavy oil sales volumes.
- Production averaged 7,991 boe/d (24% oil and natural gas
liquids ("NGL")) in the fourth quarter, down 392 boe/d, or 5%, from
the prior quarter (Q3 2019 – 8,383 boe/d; 24% oil and NGL) due to
natural declines at East Edson.
Production at the Company's Panny property in Eastern Alberta of 1.8 MMcf/d (300 boe/d) was
shut-in during the third quarter and is expected to remain offline
indefinitely, or until excessive property tax assessments are
reduced.
Financial Highlights
- Realized revenue was $14.3
million in the fourth quarter, down 37% from the prior year
period, due to a 16% decrease in production combined with a 25%
decrease in realized revenue per boe related to lower NYMEX natural
gas prices and hedging losses.
- The net loss for the fourth quarter of 2019 was $32.5 million ($0.54/share) compared to $0.3 million ($0.01/share) in the prior year period. Net loss
was impacted by impairment charges of $24.5
million recognized during the fourth quarter of 2019.
- Net cash flows used in operating activities were $1.3 million, compared to $5.2 million of cash flows from operating
activities in the prior year period. The decrease was due to the
16% decrease in production combined with realized natural gas
prices which were 54% lower than the prior year.
- In December 2019, Perpetual sold
656,773 shares of Tourmaline Oil Corp. ("TOU") at a weighted
average price of $14.78 per share and
used the proceeds of $9.7 million to
partially repay the TOU share margin demand loan. The Company's
remaining 1.0 million TOU shares were sold in January 2020 for additional proceeds of
$14.3 million.
YEAR-END 2019 FINANCIAL AND OPERATING RESULTS
Capital Spending, Production and Operations
- Perpetual's 2019 exploration and development capital program of
$12.9 million was funded from
adjusted funds flow, with investment weighted to heavy oil drilling
in Eastern Alberta.
-
- Spending in Eastern Alberta in
2019 was $11.7 million, and consisted
primarily of a five well (5.0 net) heavy oil horizontal drilling
program. At Mannville, three (3.0
net) wells were drilled in the second quarter of 2019, along with a
re-entry to add two additional laterals to an existing oil well.
Capital was also directed towards the Ukalta area of Eastern Alberta, where two (2.0 net)
exploratory multi-lateral wells were drilled targeting the
Clearwater formation. Positive
results were followed up by the four (4.0 net) well drilling
program initiated late in the fourth quarter. Exploration and
development expenditures also included funds to acquire additional
undeveloped crown lands focused on the Clearwater play in its Eastern Alberta core area.
- In response to low natural gas prices, spending in West Central
in 2019 was just $1.2 million, and
was primarily directed towards the installation of field
compression equipment and a sweetening tower to restore several
higher liquids ratio natural gas wells back to production.
- For the year ended December 31,
2019, Perpetual spent $1.7
million (2018 – $2.0 million)
on abandonment and reclamation projects under the AER's area-based
closure approach and has received 20 reclamation certificates to
date (2018 – 18 reclamation certificates). Asset retirement
obligation expenditures of $1.5
million are forecast in 2020, focused in Eastern Alberta.
- Production in 2019 averaged 8,988 boe/d (22% oil and NGL), a
decrease of 15% from 10,594 boe/d (17% oil and NGL) in 2018.
Production peaked during the first quarter of 2019 and then
declined for the remainder of the year, as drilling activity at
East Edson was deferred pending
higher natural gas prices. With capital spending focused on heavy
oil drilling activities in Eastern
Alberta, heavy oil production grew 17% to average 1,224
bbl/d in 2019 (2018 - 1,050 bbl/d).
- Perpetual's operating netback of $37.7
million ($11.50/boe) decreased
29% from $53.3 million ($13.79/boe) in 2018. The decrease was due to a
15% decline in production combined with the 18% decrease in
realized revenue, which was the result of lower realized natural
gas and NGL prices of 9% and 23%, respectively.
Financial Highlights
- Realized revenue was $73.6
million, down 18% from the prior year as a result of the 15%
decrease in production combined with a 3% decrease in realized
revenue per boe. The market diversification contract added
$0.64/Mcf (2018 - $1.02/Mcf) on the relative strength of daily
index prices at the five downstream markets compared to the AECO
Daily Index. In response to TC Energy's changes to maintenance
operating protocols that were implemented early in the fourth
quarter, Perpetual modified its market diversification contract to
shift the pricing point back to AECO for the December 2019 to October
2020 period, and recorded a realized gain of $2.7 million ($0.17/Mcf). For the year ended December 31, 2019, Perpetual recorded
$0.8 million of realized losses on
derivatives, comprised of $3.4
million of gains on natural gas hedges which were more than
offset by losses of $4.2 million from
crude oil and NGL hedges.
- Net loss for 2019 was $94.0
million ($1.56/share), up from
$20.4 million in 2018 ($0.34/share). The net loss was negatively
impacted by the $21.9 million
unrealized loss on derivatives (2018 – unrealized gain of
$5.7 million) in addition to
impairment losses of $47.1 million
which were recognized in 2019 (2018 - $7.2
million), reflecting the decrease in forward natural gas
pricing during 2019. These changes were partially offset by an
unrealized loss of $3.2 million
recognized in 2019 related to the change in fair value of the TOU
share investment, compared to an unrealized loss of $9.6 million recognized in the prior year.
- Net cash flow from operating activities was $17.8 million compared to $31.5 million in 2018. The decrease was driven by
lower production of 15%, as total Company realized revenue per boe
of $22.43/boe was only 3% lower than
the prior year (2018 - $23.07/boe)
with the increased weighting of oil and NGL in the production
mix.
- For the year ended December 31,
2019, adjusted funds flow was $14.5
million ($0.24/share), down
$15.6 million (52%) from $30.2 million ($0.50/share) in 2018 as the impact of the 15%
year-over-year decrease in production combined with lower natural
gas and NGL prices outweighed the 2% decrease in cash costs and
increased heavy oil production.
- At December 31, 2019, Perpetual
had total net debt of $118.1 million,
up $5.5 million (5%) from
December 31, 2018. The increase was
due primarily to a $3.2 million
decrease in the fair value of the TOU share investment during 2019,
combined with an incremental $1.1
million of 2022 Senior Notes that were issued in connection
with the early redemption of the 2019 Senior Notes in the second
quarter. Revolving bank debt increased by $5.0 million during 2019 to $47.6 million at December
31, 2019 due to a $5.0 million
repayment of the TOU share margin demand loan during the year.
SEQUOIA LITIGATION
The Court of Queen's Bench issued its decision related to the
Statement of Claim filed on August 3,
2018 against Perpetual and its President and Chief Executive
Officer ("CEO") with respect to the Company's disposition of
shallow gas assets in Eastern
Alberta to an unrelated third party on October 1, 2016 (the "Sequoia Litigation"). The
decision dismissed and struck all claims against the Company's CEO
and all but one of the claims filed by PwC in its capacity as
trustee in bankruptcy (the "Trustee") against Perpetual. The Court
did not find that the test for summary dismissal relating to
whether the transaction was an arm's length transfer for purposes
of section 96(1) of the Bankruptcy and Insolvency Act (the "BIA")
was met, on the balance of probabilities. Accordingly, the BIA
claim was not dismissed or struck and only that part of the claim
can continue against Perpetual. The Trustee filed a notice of
appeal with the Court of Appeal of Alberta, contesting the decision, and
Perpetual filed a similar notice of appeal contesting the BIA claim
portion of the decision. The appeal proceedings are scheduled to be
heard in December 2020.
On January 28, 2020, the Court of
Appeal issued its decision with respect to Perpetual's application
for security for costs, requiring the Trustee to post security with
the Court of Appeal in the amount of $0.2
million. Applications have been filed by the Trustee to
appeal the security for costs decision and alter the reasons for
the decision. The Court of Appeal is scheduled to hear these
applications in June 2020.
On February 25, 2020, Perpetual
filed a new application to strike and summarily dismiss the BIA
claim on the basis that there was no transfer at undervalue, and
Sequoia was not insolvent at the time of the transaction nor caused
to be insolvent by the transaction. The Court is scheduled to hear
this application in June 2020.
Management expects that the Company is more likely than not to
be successful in defending against the Sequoia Litigation such that
no damages will be awarded against it, and therefore, no amounts
have been accrued as a liability in Perpetual's financial
statements.
2020 GUIDANCE
The Company's Board of Directors approved a capital spending
program of $6 million for the first
quarter of 2020 to drill four (4.0 net) multi-lateral horizontal
wells at Ukalta. Perpetual's reserve-based credit facility is
currently undergoing its borrowing limit redetermination which is
likely to reduce the current $45
million borrowing limit effective March 31, 2020 due to reductions in bank lending
commodity price forecasts. Any reductions in the credit facility
borrowing limit will reduce the Company's available liquidity. To
preserve liquidity, the Company will defer further capital spending
until the credit facility borrowing limit redetermination has been
completed. The Company will issue its 2020 Guidance once the
borrowing limit redetermination is known and capital spending plans
have been determined.
YEAR-END 2019 RESERVES
To preserve value during the low natural gas price environment
in 2019, Perpetual limited capital spending on natural gas assets,
executing a capital program funded through 2019 adjusted funds flow
with investment weighted to heavy oil drilling and waterflood
activities. Strong performance of the base assets resulted in 4%
growth in proved and probable reserves year-over-year excluding
production. Proved and probable reserves in the Company's Eastern
Alberta Heavy Oil properties grew 10% excluding production, while
East Edson natural gas and NGL
reserves grew 2% excluding production bringing Perpetual's year-end
reserves just one percent lower to 67.1 MMboe, comprised of 17% oil
and NGL (2018 – 67.9 MMboe, 15% oil and NGL).
The quality of Perpetual's assets and positive momentum to drive
operational and execution excellence in its core operating areas
are demonstrated by the highlights below:
- Total proved plus probable reserves were 67.1 MMboe at
December 31, 2019, adding proved plus
probable reserves of 2.4 MMboe to replace 74% of 2019 production of
3.3 MMboe with total net capital spending of $12.9 million. The increase in proved plus
probable reserves was driven by strong well performance at
East Edson combined with positive
waterflood response and additions from successful heavy oil
drilling programs.
- Total proved producing reserves were 16.0 MMboe at December 31, 2019, down 7% from year-end 2018 and
proved plus probable producing reserves were 19.8 MMboe at
December 31, 2019, down 9% from
year-end 2018 and represented 30% of total proved plus probable
reserves. Proved reserves represented 60% of the Company's total
proved plus probable reserves.
- East Edson represents 89%
(2018 – 90%) of total proved plus probable reserves at year-end
2019. The drilling program at East
Edson was suspended in 2019 due to low forward natural gas
prices at AECO, however, technical reserve additions related to
stronger than forecast well performance and improved liquids
recovery drove reserve additions that partially offset
production.
- Drilling of 2.0 net exploratory wells in the new Ukalta area
resulted in additions of 549 Mboe on a total proved basis and 736
Mboe on a total proved plus probable basis.
- Production from heavy oil wells at Mannville of 0.45 MMboe was offset by
increases of 0.45 MMboe to proved plus probable reserves mainly
related to the positive results of development drilling in 2019.
While Mannville heavy oil reserves
account for just 7% of the Company's total proved plus probable
reserves, these higher netback reserves at forecast commodity
prices represent 18% of the NPV10 value of Perpetual's proved plus
probable reserves.
- Exploration and development capital spending of $12.9 million in 2019, largely focused on heavy
oil projects, resulted in finding and development ("F&D") costs
of $10.54/boe on a proved plus
probable basis, including changes in future development capital
("FDC").
- Based on an equal weighting of three consultant average price
(McDaniel, GLJ, Sproule) forecasts (the "Consultant Average Price
Forecast") used by McDaniel, the net present value ("NPV") of
Perpetual's total proved plus probable reserves (discounted at 10%)
before income tax, was $297.3 million
(2018 – $361.3 million). The decrease
related primarily to a decrease in the independent reserve
evaluators' forecast for natural gas prices at year-end 2019 as
compared to the prior year. The inclusion this year of all
abandonment, decommissioning and reclamation obligations had an
impact of reducing value by $11.9
million, which reflects the additional obligations for
non-reserve well costs and facility and pipeline costs that had not
been included in the reserve report in prior years.
- Based on the Consultant Average Price Forecast, Perpetual's
reserve-based net asset value ("NAV") (discounted at 10%) at
year-end 2019 is estimated at $200.5
million ($3.27 per share) as
compared to $276.6 million
($4.59 per share) at year-end 2018,
primarily due to lower forecast natural gas prices.
Reserves Disclosure
Working interest reserves included herein refer to working
interest reserves before royalty deductions. Reserves information
is based on an independent reserves evaluation report prepared by
McDaniel with an effective date of December
31, 2019 (the "McDaniel Report"), and has been prepared in
accordance with National Instrument 51-101 ("NI 51-101") using the
Consultant Average Price Forecast. Complete NI 51-101 reserves
disclosure including after-tax reserve values, reserves by major
property and abandonment costs will be included in Perpetual's
Annual Information Form ("AIF"), which, when filed, will be
available on the Company's website at www.perpetualenergyinc.com
and SEDAR at www.sedar.com. Perpetual's reserves at
December 31, 2019 are summarized
below:
Working Interest
Reserves at December 31, 2019(1)
|
|
Light and
Medium
Crude Oil
(Mbbl)
|
Heavy
Oil
(Mbbl)
|
Conventional
Natural Gas
(MMcf)
|
Natural Gas
Liquids
(Mbbl)
|
Oil
Equivalent
(Mboe)
|
Proved
Producing
|
16
|
2,177
|
75,183
|
1,324
|
16,047
|
Proved
Non-Producing
|
–
|
106
|
2,035
|
8
|
453
|
Proved
Undeveloped
|
–
|
1,177
|
124,331
|
1,898
|
23,797
|
Total
Proved
|
16
|
3,460
|
201,549
|
3,230
|
40,298
|
Probable
Producing
|
4
|
586
|
17,219
|
305
|
3,765
|
Probable
Non-Producing
|
–
|
21
|
6,838
|
83
|
1,244
|
Probable
Undeveloped
|
–
|
1,046
|
109,652
|
2,429
|
21,750
|
Total
Probable
|
4
|
1,653
|
133,710
|
2,817
|
26,759
|
Total Proved plus
Probable
|
21
|
5,113
|
335,259
|
6,047
|
67,057
|
(1) May not add due to
rounding.
|
Total proved reserves at December 31,
2019 account for 60% (2018 – 63%) of total proved plus
probable reserves. Proved producing reserves of 16.0 MMboe comprise
40% (2018 – 41%) of total proved reserves. Proved plus probable
producing reserves of 19.8 MMboe represent 30% (2018 – 32%) of
total proved plus probable reserves.
Reserves Reconciliation
Working Interest
Reserves(1)
|
|
|
|
Barrels of Oil
Equivalent (Mboe)
|
Proved
|
Probable
|
Proved and
Probable
|
Opening Balance,
December 31, 2018
|
42,461
|
25,439
|
67,899
|
Extensions and
Improved Recovery
|
191
|
392
|
584
|
Discoveries
|
550
|
187
|
737
|
Technical
Revisions
|
707
|
801
|
1,508
|
Acquisitions
|
–
|
–
|
–
|
Dispositions
|
–
|
–
|
–
|
Production
|
(3,277)
|
–
|
(3,277)
|
Economic
Factors
|
(334)
|
(60)
|
(394)
|
Closing Balance,
December 31, 2019
|
40,298
|
26,759
|
67,057
|
(1) May not add due to
rounding.
|
McDaniel recorded net positive technical revisions of 1.5 MMboe
related to performance on a proved plus probable basis in 2019.
Positive technical revisions of 1.1 MMboe were attributed to
improved performance of existing wells in both West Central and
Eastern areas and 0.4 MMboe were related to increases in reserve
assignments relating to drilling locations in the East Edson area.
The table below summarizes the FDC estimated by McDaniel by play
type to bring non-producing and undeveloped reserves to
production.
Future Development
Capital(1)
|
|
|
|
|
|
|
|
($
millions)
|
2020
|
2021
|
2022
|
2023
|
2024
|
Remainder
|
Total
|
Eastern Alberta
Shallow Gas
|
–
|
0.5
|
0.7
|
–
|
–
|
–
|
1.1
|
Mannville Heavy
Oil
|
5.3
|
4.5
|
6.6
|
5.8
|
0
|
–
|
22.3
|
Ukalta
|
6.7
|
–
|
–
|
–
|
–
|
–
|
6.7
|
East Edson
Wilrich
|
22.9
|
44.3
|
33.8
|
38.8
|
37.4
|
151.5
|
328.6
|
Total
|
34.9
|
49.3
|
41.1
|
44.6
|
37.4
|
151.5
|
358.8
|
(1)
May not add due to rounding.
|
McDaniel estimates the FDC required to convert proved plus
probable non-producing and undeveloped reserves to proved producing
reserves, to be $358.8 million at
December 31, 2019, up $12.8 million from year-end 2018. On a proved
plus probable basis, FDC decreased by $0.8
million related to the future development of reserves at
East Edson and increased
$7.0 million in the Mannville heavy oil area and by $6.7 million in the new Ukalta area. The
East Edson development plan has 66
(63.3 net) undeveloped locations (2018 – 63.3 net locations) in the
total proved plus probable eight-year development plan. The
Mannville Heavy Oil area has 19 (19.0 net) undeveloped locations in
the total proved plus probable category, an increase of 3 from
year-end 2018. The Ukalta Oil area has 5 (5.0 net) undeveloped
locations in the total proved plus probable category. The projects
are forecast by McDaniel to generate annual operating cash flow in
excess of the annual FDC, making the projects self-funding.
RESERVE LIFE INDEX
Perpetual's proved plus probable reserves to production ratio,
also referred to as reserve life index ("RLI"), was 21.5 years at
year-end 2019, while the proved RLI was 13.5 years, based upon the
2020 production estimates in the McDaniel Report. The following
table summarizes Perpetual's historical calculated RLI.
Reserve Life
Index(1)
|
|
|
|
|
|
Year-end
|
2019
|
2018
|
2017
|
2016
|
2015
|
Total
Proved
|
13.4
|
13.1
|
9.1
|
9.3
|
7.3
|
Total Proved plus
Probable
|
21.5
|
19.9
|
13.2
|
15.1
|
11.9
|
(1) Calculated as year-end
reserves divided by year one production estimate from the McDaniel
Report.
|
NET PRESENT VALUE OF RESERVES SUMMARY
Perpetual's oil, natural gas and NGL reserves were evaluated by
McDaniel using the Consultant Average Price Forecast effective
January 1, 2020 and include the
forecast impact of the Company's market diversification contract,
but prior to provision for financial oil and natural gas price
hedges, foreign exchange contracts, income taxes, interest, debt
service charges and general and administrative expenses. The
following table summarizes the NPV of future revenue from reserves
at January 1, 2020, assuming various
discount rates:
NPV of Reserves,
before income tax(1)(2)
|
|
|
|
|
|
|
($ millions except as
noted)
|
Undiscounted
|
5%
|
10%
|
15%
|
Discounted
at
20%
|
Unit Value
Discounted
at
10%/Year
($/boe)(3)
|
Proved
Producing
|
81
|
82
|
75
|
68
|
62
|
6.92
|
Proved
Non-Producing
|
2
|
2
|
2
|
1
|
1
|
3.96
|
Proved
Undeveloped
|
231
|
148
|
98
|
67
|
47
|
4.55
|
Total
Proved
|
314
|
231
|
175
|
137
|
110
|
5.32
|
Probable
Producing
|
58
|
39
|
28
|
21
|
17
|
8.26
|
Probable
Non-Producing
|
9
|
6
|
4
|
3
|
2
|
3.43
|
Probable
Undeveloped
|
290
|
156
|
91
|
57
|
38
|
4.61
|
Total
Probable
|
358
|
201
|
123
|
81
|
56
|
5.07
|
Total Proved plus
Probable
|
671
|
432
|
297
|
217
|
167
|
5.22
|
(1)
|
January 1, 2020
Consultant Average price forecast and including market
diversification contract.
|
(2)
|
May not add due to
rounding.
|
(3)
|
The unit values are
based on net reserve volumes.
|
McDaniel's NPV10 estimate of Perpetual's total proved plus
probable reserves at year-end 2019 was $ 297
million, down 18% from $361.3
million at year-end 2018. The decrease in NPV10 reflected
the impact of lower forecast commodity prices, offset by an
increase in weighting to higher netback heavy oil reserves. At a
10% discount factor, total proved reserves account for 59% (2018 –
65%) of the proved plus probable value. Proved plus probable
producing reserves represent 34% (2018 – 45%) of the total proved
plus probable value (discounted at 10%).
FAIR MARKET VALUE OF UNDEVELOPED LAND
Perpetual's independent third-party estimate of the fair market
value of its undeveloped acreage by region for purposes of the NAV
calculation is based on past Crown land sale activity, adjusted for
tenure and other considerations. In West Central Alberta, no
undeveloped land value was assigned where proved and/or probable
undeveloped reserves have been booked.
Fair Market Value
of Undeveloped Land
|
|
|
|
|
Net
Acres
|
Value ($
millions)
|
$/Acre
|
Eastern and
other
|
101,441
|
6.3
|
62.18
|
West
Central
|
19,173
|
15.6
|
815.57
|
Oil Sands
|
96,640
|
14.0
|
145.27
|
Total
|
217,255
|
36.0
|
165.63
|
The fair market value of Perpetual's undeveloped land at
year-end 2019, adjusted to remove the value of undeveloped lands
with reserves assigned in West Central Alberta, is estimated by an
external land consultant at $36.0
million, a decrease of 9% from $39.4
million relative to year-end 2018. The fair market value of
undeveloped oil sands leases incorporates the absolute investment
to date in the ongoing bitumen extraction pilot project at Panny,
with the remaining undeveloped land valued by historical land sale
activity, adjusted for tenure.
NET ASSET VALUE
The following NAV table shows what is normally referred to as a
"produce-out" NAV calculation under which the Company's reserves
would be produced at forecast future prices and costs. The value is
a snapshot in time and is based on various assumptions including
commodity prices and foreign exchange rates that vary over time. It
should not be assumed that the NAV represents the fair market value
of Perpetual's shares. The calculations below do not reflect the
value of the Company's prospect inventory to the extent that the
prospects are not recognized within the NI 51-101 compliant reserve
assessment, except as they are valued through the estimate of the
fair market value of undeveloped land.
Pre-tax NAV at
December 31, 2019(1)
|
|
|
|
|
Discounted
at
|
($ millions, except
as noted)
|
Undiscounted
|
5%
|
10%
|
15%
|
Total Proved plus
Probable Reserves(2)
|
671.4
|
432.0
|
297.3
|
217.3
|
TOU share
investment(3)
|
15.2
|
15.2
|
15.2
|
15.2
|
Fair market value of
undeveloped land(4)
|
36.0
|
36.0
|
36.0
|
36.0
|
Bank debt, net of
working capital(1)
|
(54.6)
|
(54.6)
|
(54.6)
|
(54.6)
|
TOU share margin
loan(1)(3)(5)
|
(0.1)
|
(0.1)
|
(0.1)
|
(0.1)
|
Term
loan(5)
|
(45.0)
|
(45.0)
|
(45.0)
|
(45.0)
|
Senior
notes(5)
|
(33.6)
|
(33.6)
|
(33.6)
|
(33.6)
|
Estimate of
Additional Future Abandonment and Reclamation
Costs(6)
|
(0.0)
|
(0.0)
|
(0.0)
|
(0.0)
|
Derivatives(7)
|
(14.7)
|
(14.7)
|
(14.7)
|
(14.7)
|
NAV
|
574.6
|
335.2
|
200.5
|
120.5
|
Common shares
outstanding (million)
|
61.31
|
61.31
|
61.31
|
61.31
|
NAV per share
($/share)
|
9.37
|
5.47
|
3.27
|
1.97
|
(1)
|
Financial information
is per Perpetual's 2019 audited consolidated financial
statements.
|
(2)
|
Reserve values per
McDaniel Report as at December 31, 2019.
|
(3)
|
Tourmaline Oil Corp.
("TOU") share value based on 1.0 million shares at December 31,
2019 closing price ($15.22 per share).
|
(4)
|
Independent
third-party estimate; excludes undeveloped land in West Central
Alberta with reserves assigned.
|
(5)
|
Measured at principal
amount.
|
(6)
|
All abandonment
obligations including future abandonment and reclamation costs for
pipelines and facilities and non-reserve wells are included in the
McDaniel Report.
|
(7)
|
Value as at December
31, 2019, relative to the Consultant Average Price Forecast.
Excludes market diversification contract which is included in total
proved plus probable reserves.
|
The above evaluation includes FDC expectations required to bring
undeveloped reserves on production, as recognized by McDaniel, that
meet the criteria for booking under NI 51-101. The fair market
value of undeveloped land does not reflect the value of the
Company's extensive prospect inventory which is anticipated to be
converted into reserves and production over time through future
capital investment.
FINDING AND DEVELOPMENT COSTS
Under NI 51-101, the methodology to be used to calculate F&D
costs includes incorporating changes in FDC required to bring the
proved and probable undeveloped reserves to production. Changes in
forecast FDC occur annually as a result of development activities,
acquisitions and disposition activities, undeveloped reserve
revisions and capital cost estimates that reflect the independent
evaluator's best estimate of what it will cost to bring the proved
plus probable undeveloped reserves on production.
2019 F&D
Costs(1)
|
|
|
|
|
($ millions except as
noted)
|
|
Proved
|
|
Proved &
Probable
|
F&D Costs,
including FDC
|
|
|
|
|
Exploration and
development capital expenditures(2)
|
$
|
12.87
|
|
$
|
12.87
|
Total change in
FDC
|
$
|
(2.43)
|
|
$
|
12.78
|
Total F&D
capital, including change in FDC
|
$
|
10.44
|
|
$
|
25.65
|
Reserve additions,
including revisions (MMboe)
|
|
1.11
|
|
|
2.43
|
F&D Costs,
including FDC ($/boe)
|
$
|
9.37
|
|
$
|
10.54
|
|
|
|
|
|
FD&A Costs,
including FDC
|
|
|
|
|
Exploration and
development capital expenditures(2)
|
$
|
12.87
|
|
$
|
12.87
|
Proceeds on
dispositions, net of acquisitions
|
$
|
0.0
|
|
$
|
0.0
|
Total change in
FDC
|
$
|
(2.43)
|
|
$
|
12.78
|
Total FD&A
capital, including change in FDC
|
$
|
10.44
|
|
$
|
25.65
|
Reserve additions,
including net acquisitions (MMboe)
|
|
1.11
|
|
|
2.43
|
FD&A Costs,
including FDC ($/boe)
|
$
|
9.37
|
|
$
|
10.54
|
(1)
|
Financial information
is per Perpetual's 2019 preliminary unaudited consolidated
financial statements.
|
(2)
|
Excludes corporate
assets and expenditures on decommissioning obligations.
|
Financial and
Operating Highlights
|
Three Months
ended
December
31
|
Year
ended
December
31
|
($Cdn
thousands,
except
volume and per share amounts)
|
2019
|
2018
|
Change
|
2019
|
2018
|
Change
|
Financial
|
|
|
|
|
|
|
Oil and natural gas
revenue
|
15,830
|
21,510
|
(26%)
|
74,361
|
86,128
|
(14%)
|
Net loss
|
(32,498)
|
(331)
|
(9,718%)
|
(94,015)
|
(20,380)
|
(361%)
|
Per share – basic and
diluted(2)
|
(0.54)
|
(0.01)
|
(5,300%)
|
(1.56)
|
(0.34)
|
(359%)
|
Cash flow from (used
in) operating activities
|
(1,290)
|
5,163
|
(125%)
|
17,806
|
31,525
|
(44%)
|
Per
share(1)(2)
|
(0.02)
|
0.09
|
(122%)
|
0.30
|
0.53
|
(43%)
|
Adjusted funds
flow(1)
|
340
|
8,052
|
(96%)
|
14,534
|
30,155
|
(52%)
|
Per
share(2)
|
0.01
|
0.13
|
(92%)
|
0.24
|
0.50
|
(52%)
|
Revolving bank
debt
|
47,552
|
42,561
|
12%
|
47,552
|
42,561
|
12%
|
Senior notes,
principal amount
|
33,580
|
32,490
|
3%
|
33,580
|
32,490
|
3%
|
Term loan, principal
amount
|
45,000
|
45,000
|
–
|
45,000
|
45,000
|
–
|
TOU share margin
demand loan, principal amount
|
100
|
14,144
|
(99%)
|
100
|
14,144
|
(99%)
|
TOU share
investment
|
(15,220)
|
(28,132)
|
(46%)
|
(15,220)
|
(28,132)
|
(46%)
|
Net working capital
deficiency(1)
|
7,068
|
6,543
|
8%
|
7,068
|
6,543
|
8%
|
Total net
debt(1)
|
118,080
|
112,606
|
5%
|
118,080
|
112,606
|
5%
|
Net capital
expenditures
|
|
|
|
|
|
|
Capital
expenditures
|
1,995
|
5,617
|
(64%)
|
12,939
|
26,888
|
(52%)
|
Net proceeds on
acquisitions and dispositions
|
–
|
(1,285)
|
(100%)
|
–
|
(3,030)
|
(100%)
|
Net capital
expenditures
|
1,995
|
4,332
|
(54%)
|
12,939
|
23,858
|
(46%)
|
Common shares
outstanding (thousands)
|
|
|
|
|
|
|
End of
period(3)
|
60,513
|
60,240
|
–
|
60,513
|
60,240
|
–
|
Weighted average –
basic and diluted
|
60,444
|
60,448
|
–
|
60,258
|
60,039
|
–
|
Operating
|
|
|
|
|
|
|
Average
production
|
|
|
|
|
|
|
Natural gas
(MMcf/d)
|
36.6
|
44.9
|
(18%)
|
42.3
|
52.6
|
(20%)
|
Oil
(bbl/d)
|
1,275
|
1,301
|
(2%)
|
1,224
|
1,050
|
17%
|
NGL
(bbl/d)
|
606
|
715
|
(15%)
|
719
|
774
|
(7%)
|
Total
(boe/d)
|
7,991
|
9,491
|
(16%)
|
8,988
|
10,594
|
(15%)
|
Average
prices
|
|
|
|
|
|
|
Realized natural gas
price ($/Mcf)
|
2.00
|
4.38
|
(54%)
|
2.77
|
3.05
|
(9%)
|
Realized oil price
($/bbl)
|
43.85
|
19.83
|
121%
|
44.87
|
40.62
|
10%
|
Realized NGL price
($/bbl)
|
43.93
|
35.73
|
23%
|
41.01
|
52.96
|
(23%)
|
Wells
drilled
|
|
|
|
|
|
|
Natural gas – gross
(net)
|
–
(–)
|
– (–)
|
|
–
(–)
|
1 (1.0)
|
|
Oil – gross
(net)
|
–
(–)
|
– (–)
|
|
5
(5.0)
|
6 (6.0)
|
|
Total – gross
(net)
|
–
(–)
|
– (–)
|
|
5
(5.0)
|
7 (7.0)
|
|
(1)
|
These are non-GAAP
measures. Please refer to "Non-GAAP Measures" at the end of this
press release.
|
(2)
|
Based on weighted
average basic common shares outstanding for the period.
|
(3)
|
All common shares are
net of shares held in trust (2019 – 801; 2018 – 661). See "Note 17
to the Audited Consolidated Financial
Statements".
|
ADDITIONAL INFORMATION
Oil and Gas Advisories
The reserves estimates contained in this news release
represent gross reserves as at December 31,
2019 as estimated by McDaniel and Associates Consultants
Ltd. ("McDaniel") and are defined under National Instrument 51-101
as interest before deduction of royalties and without including any
royalty interests. The recovery and reserves estimates of crude
oil, NGL 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 NGL reserves may be
greater than or less than the estimates provided herein.
To provide a single unit-of-production for analytical
purposes, natural gas production and reserves volumes are converted
mathematically to equivalent barrels of oil (boe), using the
industry-accepted standard conversion of six thousand cubic feet of
natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio
is based on an energy equivalency conversion method primarily
applicable at the burner tip. It does not represent a value
equivalency at the wellhead and is not based on either energy
content or current prices. While the boe ratio is useful for
comparative measures and observing trends, it does not accurately
reflect individual product values and might be misleading,
particularly if used in isolation. As well, given that the value
ratio, based on the current price of crude oil to natural gas, is
significantly different from the 6:1 energy equivalency ratio,
using a 6:1 conversion ratio may be misleading as an indication of
value.
This news release contains metrics commonly used in the oil
and natural gas industry, such as "finding and development" costs
or "F&D" costs and "F&D recycle ratio". These oil and gas
metrics have been prepared by management and do not have
standardized meanings or standard methods of calculation and
therefore, such measures may not be comparable to similar measures
used by other companies and should not be used to make comparisons.
Such metrics have been included in this news release to provide
readers with additional measures to evaluate Perpetual's
performance, however, such measures are not reliable indicators of
Perpetual's future performance and future performance may not
compare to Perpetual's performance in previous periods and
therefore, such metrics should not be unduly relied upon.
Management uses these oil and gas metrics for its own performance
measurements and to provide shareholders and investors with
measures to compare Perpetual's operations over time. Readers
are cautioned that the information provided by these metrics, or
that can be derived from the metrics presented in this news
release, should not be relied upon for investment or other
purposes.
F&D costs are calculated on a per boe basis by dividing
the aggregate of the change in future development capital ("FDC")
from the prior year for the particular reserve category and the
costs incurred on development and exploration activities in the
year by the change in reserves from the prior year for the reserve
category. F&D costs take into account reserves revisions during
the year on a per boe basis. The aggregate of the F&D costs
incurred in the financial year and changes during that year in
estimated FDC generally will not reflect total F&D costs
related to reserves additions for that year.
F&D recycle ratio is calculated by dividing the operating
netback for the period by the F&D costs per boe for the
particular reserve category.
The following abbreviations used in this news release have
the meanings set forth below:
bbls
|
barrels
|
boe
|
barrels of oil
equivalent
|
Mcf
|
thousand cubic
feet
|
MMcf
|
million cubic
feet
|
MMBtu
|
million British
Thermal Units
|
GJ
|
gigajoules
|
Forward-Looking Information
Certain information regarding Perpetual in this news release
including management's assessment of future plans and operations
may constitute forward-looking information or statements under
applicable securities laws. The forward looking information
includes, without limitation, anticipated amounts and allocation of
capital spending; statements pertaining to adjusted funds flow
levels, statements regarding estimated production and timing
thereof; statements pertaining to type curves being exceeded,
forecast average production; completions and development
activities; infrastructure expansion and construction; estimated
FDC required to convert proved plus probable non-producing and
undeveloped reserves to proved producing reserves; prospective oil
and natural gas liquids production capability; projected realized
natural gas prices and adjusted funds flow; estimated
decommissioning obligations; commodity prices and foreign exchange
rates; and commodity price management. Various assumptions were
used in drawing the conclusions or making the forecasts and
projections contained in the forward-looking information contained
in this news release, which assumptions are based on management's
analysis of historical trends, experience, current conditions and
expected future developments pertaining to Perpetual and the
industry in which it operates as well as certain assumptions
regarding the matters outlined above. Forward-looking information
is based on current expectations, estimates and projections that
involve a number of risks, which could cause actual results to vary
and in some instances to differ materially from those anticipated
by Perpetual and described in the forward-looking information
contained in this news release. Undue reliance should not be placed
on forward-looking information, which is not a guarantee of
performance and is subject to a number of risks or uncertainties,
including without limitation those described under "Risk Factors"
in Perpetual's Annual Information Form and MD&A for the year
ended December 31, 2019 and those
included in other reports on file with Canadian securities
regulatory authorities which may be accessed through the SEDAR
website (www.sedar.com) and at Perpetual's website
(www.perpetualenergyinc.com). Readers are cautioned
that the foregoing list of risk factors is not exhaustive.
Forward-looking information is based on the estimates and opinions
of Perpetual's management at the time the information is released,
and Perpetual disclaims any intent or obligation to update publicly
any such forward-looking information, whether as a result of new
information, future events or otherwise, other than as expressly
required by applicable securities law.
Non-GAAP Measures
This news release contains the terms "adjusted funds flow",
"adjusted funds flow per share", "adjusted funds flow per boe",
"available liquidity", "cash costs", "net working capital
deficiency (surplus)", "net debt", "net bank debt", "net debt to
adjusted funds flow ratio", "operating netback", "realized revenue"
and "enterprise value" which do not have standardized meanings
prescribed by GAAP. Management believes that in addition to net
income (loss) and net cash flows from operating activities as
defined by GAAP, these terms are useful supplemental measures to
evaluate operating performance. Users are cautioned however that
these measures should not be construed as an alternative to net
income (loss) or net cash flows from operating activities
determined in accordance with GAAP as an indication of Perpetual's
performance and may not be comparable with the calculation of
similar measurements by other entities.
Adjusted funds flow: Management uses adjusted funds flow and
adjusted funds flow per boe as key measures to assess the ability
of the Company to generate the funds necessary to finance capital
expenditures, expenditures on decommissioning obligations and meet
its financial obligations. Adjusted funds flow is calculated based
on cash flows from (used in) operating activities, excluding
changes in non-cash working capital and expenditures on
decommissioning obligations since Perpetual believes the timing of
collection, payment or incurrence of these items is variable.
Expenditures on decommissioning obligations may vary from period to
period depending on capital programs and the maturity of the
Company's operating areas. Expenditures on decommissioning
obligations are managed through the capital budgeting process which
considers available adjusted funds flow. The Company has also
deducted the change in gas over bitumen royalty financing from
adjusted funds flow to present these payments net of gas over
bitumen royalty credits received. These payments are indexed to gas
over bitumen royalty credits and are recorded as a reduction to the
Corporation's gas over bitumen royalty financing obligation in
accordance with IFRS. Additionally, the Company has excluded
payment of restructuring costs associated with employee downsizing
costs, which management considers to not be related to cash flow
from operating activities.
Adjusted funds flow per share is calculated using the same
weighted average number of shares outstanding used in calculating
net income (loss) per share. Adjusted funds flow is not intended to
represent net cash flows from (used in) operating activities
calculated in accordance with IFRS.
Adjusted funds flow per boe is calculated as adjusted funds
flow divided by total production sold in the period.
Available Liquidity: Available Liquidity is defined as
Perpetual's reserve-based credit facility borrowing limit (the
"Borrowing Limit"), plus the fair value of the Tourmaline Oil Corp.
("TOU") share investment, less borrowings and letters of credit
issued under the reserve-based credit facility (the "Credit
Facility") and the TOU share margin demand loan. Management uses
available liquidity to assess the ability of the Company to finance
capital expenditures and expenditures on decommissioning
obligations, and to meet its financial obligations.
Cash costs: Cash costs are comprised of royalties, production
and operating, transportation, general and administrative, and cash
finance expense. Cash costs per boe is calculated by dividing cash
costs by total production sold in the period. Management believes
that cash costs assist management and investors in assessing
Perpetual's efficiency and overall cost structure.
Realized revenue: Realized revenue is the sum of realized
natural gas revenue, realized oil revenue and realized natural gas
liquids ("NGL") revenue which includes realized gains (losses) on
financial natural gas, crude oil, NGL and foreign exchange
contracts but excludes any realized gains (losses) resulting from
marketing contracts associated with the disposition of the shallow
gas assets on October 1, 2016 (the
"Shallow Gas Disposition") to Sequoia Resources Corp. ("Sequoia").
Realized revenue, including foreign exchange and the market
diversification contract, is used by management to calculate the
Corporation's net realized commodity prices, taking into account
monthly settlements of financial crude oil and natural gas forward
sales, collars, basis differentials, and forward foreign exchange
sales. These contracts are put in place to protect Perpetual's
adjusted funds flow from potential volatility in commodity prices
and foreign exchange rates. Any related realized gains or losses
are considered part of the Corporation's realized commodity
price.
Operating netback: Operating netback is calculated by
deducting royalties, production and operating expenses, and
transportation costs from realized revenue. Operating netback is
also calculated on a per boe basis using production sold for the
period. Operating netback on a per boe basis can vary significantly
for each of the Company's operating areas. Perpetual considers
operating netback to be an important performance measure as it
demonstrates its profitability relative to current commodity
prices.
Net working capital deficiency (surplus): Net working capital
deficiency (surplus) includes total current assets and current
liabilities excluding short-term derivative assets and liabilities
related to the Corporation's risk management activities, TOU share
investment, TOU share margin demand loan, revolving bank debt,
current portion of gas over bitumen royalty financing, current
portion of lease liabilities, and current portion of
provisions.
Net bank debt, net debt and net debt to adjusted funds flow
ratio: Net bank debt is measured as current and long-term revolving
bank debt including net working capital deficiency (surplus). Net
debt includes the carrying value of net bank debt, the principal
amount of the term loan, the principal amount of the TOU share
margin demand loan and the principal amount of senior notes,
reduced for the fair value of the TOU share investment. Net debt,
net bank debt, and net debt to adjusted funds flow ratios are used
by management to assess the Corporation's overall debt position and
borrowing capacity. Net debt to adjusted funds flow ratios are
calculated on a trailing twelve-month basis.
Enterprise value: Enterprise value is equal to net debt plus
the market value of issued equity, and is used by management to
analyze leverage. Enterprise value is not intended to represent the
total funds from equity and debt received by the Corporation upon
issuance.
For additional reader advisories in regards to non-GAAP
financial measures, including Perpetual's method of calculation and
reconciliation of these terms to their corresponding GAAP measures,
see the section entitled "Non-GAAP Measures" within the Company's
MD&A filed on SEDAR.
SOURCE Perpetual Energy Inc.