Baytex Energy Corp. ("Baytex") (TSX: BTE) reports its operating and
financial results for the three months and year ended December 31,
2020 (all amounts are in Canadian dollars unless otherwise noted).
“In 2020, we responded aggressively to the
downturn brought on by Covid-19, improved our cost structure and
capital efficiencies, exceeded our GHG emissions intensity target,
and enhanced our overall sustainability. The strong recovery in
commodity prices in early 2021 has us on track to deliver over $250
million ($0.45 per basic share) of free cash flow in 2021. We
resumed drilling activity late last year and are building
significant operational momentum with current production over
78,000 boe/d. We are executing our plan to maximize free cash flow
and accelerate our debt reduction strategy,” commented Ed LaFehr,
President and Chief Executive Officer.
2020 Highlights
- Production in
line with guidance at 70,475 boe/d (82% oil and NGL) in Q4/2020 and
79,781 boe/d (82% oil and NGL) for the full-year 2020.
- Exploration and
development expenditures totaled $78 million in Q4/2020, bringing
aggregate spending for 2020 to $280 million, in line with
guidance.
- Delivered
adjusted funds flow of $82 million ($0.15 per basic share) in
Q4/2020 and $312 million ($0.56 per basic share) for 2020.
- Generated free
cash flow of $2 million in Q4/2020 and $18 million ($0.03 per basic
share) for 2020.
- Refinanced
US$500 million of long-term notes to 2027 and extended credit
facility to 2024.
- Maintained
undrawn credit capacity of $367 million and liquidity, net of
working capital, of $319 million.
- Achieved a 46%
reduction in our GHG emissions intensity through year-end 2020,
relative to our 2018 baseline. This represents an annual reduction
of 1.5 million tonnes of CO2e and is equivalent to taking 330,000
cars off the road annually.
- Our net asset
value at year-end 2020, discounted at 10%, is estimated to be $2.78
per share. This is based on the estimated reserves value plus a
value for undeveloped acreage, net of long-term debt and working
capital.
Our 2020 reserves report reflects the impact of
a materially lower commodity price forecast being utilized by our
reserves evaluator, which has WTI averaging US$56/bbl over the next
ten years, down 20% from one year ago. At year-end 2020, proved
developed producing reserves total 120 mmboe, proved reserves total
271 mmboe and our proved plus probable reserves total 462 mmboe. We
removed 29 million barrels of proved reserves (65% heavy oil and
bitumen) and 41 million barrels of proved plus probable reserves
(80% heavy oil and bitumen), which are uneconomic using this
commodity price forecast.
2021 Outlook
In 2021, we will benefit from a disciplined
approach to capital allocation as well as our continued drive to
improve our cost structure and capital efficiencies. Our high
graded capital program is focused largely on our high netback light
oil assets in the Viking and Eagle Ford. At current commodity
prices, we intend to implement a heavy oil program in the second
half of the year.
Our 2021 guidance remains unchanged as we target
production of 73,000 to 77,000 boe/d with exploration and
development expenditures of $225 to $275 million. During Q4/2020,
we resumed drilling activity, which is leading to operational
momentum early in 2021 with current production over 78,000
boe/d.
Based on the forward strip(1), we expect to
generate over $250 million of free cash flow in 2021 and increase
our financial liquidity to over $550 million. We have entered into
hedges on approximately 48% of our net crude oil exposure for 2021,
largely utilizing a 3-way option structure that provides WTI price
protection at US$45/bbl with upside participation to US$52/bbl.
|
(1) |
2021 pricing assumptions: WTI - US$58/bbl; WCS differential -
US$12/bbl; MSW differential – US$4/bbl, NYMEX Gas - US$3.00/mcf;
AECO Gas - $3.05/mcf and Exchange Rate (CAD/USD) - 1.27. |
| |
Three Months Ended |
Twelve Months Ended |
|
|
December 31,2020 |
September 30,2020 |
December 31,2019 |
December 31,2020 |
December 31,2019 |
|
FINANCIAL (thousands of Canadian dollars, except
per common share amounts) |
|
|
|
|
|
|
Petroleum and natural gas sales |
$ |
233,636 |
|
$ |
252,538 |
|
$ |
445,895 |
|
$ |
975,477 |
|
$ |
1,805,919 |
|
|
Adjusted funds flow (1) |
82,176 |
|
78,508 |
|
232,147 |
|
311,506 |
|
902,426 |
|
|
Per share – basic |
0.15 |
|
0.14 |
|
0.42 |
|
0.56 |
|
1.62 |
|
|
Per share – diluted |
0.15 |
|
0.14 |
|
0.42 |
|
0.56 |
|
1.62 |
|
|
Net income (loss) |
221,160 |
|
(23,444 |
) |
(117,772 |
) |
(2,438,964 |
) |
(12,459 |
) |
|
Per share – basic |
0.39 |
|
(0.04 |
) |
(0.21 |
) |
(4.35 |
) |
(0.02 |
) |
|
Per share – diluted |
0.39 |
|
(0.04 |
) |
(0.21 |
) |
(4.35 |
) |
(0.02 |
) |
| |
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
Exploration and development expenditures (1) |
$ |
77,809 |
|
$ |
15,902 |
|
$ |
153,117 |
|
$ |
280,340 |
|
$ |
552,291 |
|
|
Acquisitions, net of divestitures |
(33 |
) |
(98 |
) |
563 |
|
(182 |
) |
2,180 |
|
|
Total oil and natural gas capital expenditures |
$ |
77,776 |
|
$ |
15,804 |
|
$ |
153,680 |
|
$ |
280,158 |
|
$ |
554,471 |
|
| |
|
|
|
|
|
|
Net Debt |
|
|
|
|
|
|
Credit facilities |
$ |
651,173 |
|
$ |
624,826 |
|
$ |
506,471 |
|
$ |
651,173 |
|
$ |
506,471 |
|
|
Long-term notes |
1,147,950 |
|
1,199,160 |
|
1,337,200 |
|
1,147,950 |
|
1,337,200 |
|
|
Long-term debt |
1,799,123 |
|
1,823,986 |
|
1,843,671 |
|
1,799,123 |
|
1,843,671 |
|
|
Working capital deficiency |
48,478 |
|
82,093 |
|
28,120 |
|
48,478 |
|
28,120 |
|
|
Net debt (1) |
$ |
1,847,601 |
|
$ |
1,906,079 |
|
$ |
1,871,791 |
|
$ |
1,847,601 |
|
$ |
1,871,791 |
|
|
|
|
|
|
|
|
|
Shares Outstanding - basic (thousands) |
|
|
|
|
|
|
Weighted average |
561,173 |
|
561,128 |
|
558,228 |
|
560,657 |
|
557,048 |
|
|
End of period |
561,227 |
|
561,163 |
|
558,305 |
|
561,227 |
|
558,305 |
|
|
|
|
|
|
|
|
|
BENCHMARK PRICES |
|
|
|
|
|
|
Crude oil |
|
|
|
|
|
|
WTI (US$/bbl) |
$ |
42.66 |
|
$ |
40.93 |
|
$ |
56.96 |
|
$ |
39.40 |
|
$ |
57.03 |
|
|
MEH oil (US$/bbl) |
43.05 |
|
41.63 |
|
60.73 |
|
40.15 |
|
62.84 |
|
|
MEH oil differential to WTI (US$/bbl) |
0.39 |
|
0.70 |
|
3.77 |
|
0.75 |
|
5.81 |
|
|
Edmonton par ($/bbl) |
50.24 |
|
49.83 |
|
68.10 |
|
45.34 |
|
69.22 |
|
|
Edmonton par differential to WTI (US$/bbl) |
(4.11 |
) |
(3.51 |
) |
(5.37 |
) |
(5.60 |
) |
(4.86 |
) |
|
WCS heavy oil ($/bbl) |
43.46 |
|
42.40 |
|
54.29 |
|
35.95 |
|
58.75 |
|
|
WCS differential to WTI (US$/bbl) |
(9.31 |
) |
(9.09 |
) |
(15.83 |
) |
(12.60 |
) |
(12.75 |
) |
|
Natural gas |
|
|
|
|
|
|
NYMEX (US$/mmbtu) |
$ |
2.66 |
|
$ |
1.98 |
|
$ |
2.50 |
|
$ |
2.08 |
|
$ |
2.63 |
|
|
AECO ($/mcf) |
2.77 |
|
2.18 |
|
2.34 |
|
2.24 |
|
1.62 |
|
| |
|
|
|
|
|
|
CAD/USD average exchange rate |
1.3031 |
|
1.3316 |
|
1.3201 |
|
1.3413 |
|
1.3269 |
|
| |
Three Months Ended |
Twelve Months Ended |
|
|
December 31,2020 |
September 30,2020 |
December 31,2019 |
December 31,2020 |
December 31,2019 |
|
OPERATING |
|
|
|
|
|
| Daily
Production |
|
|
|
|
|
|
Light oil and condensate (bbl/d) |
29,568 |
|
34,101 |
|
43,906 |
|
37,056 |
|
43,587 |
|
|
Heavy oil (bbl/d) |
21,725 |
|
22,138 |
|
27,050 |
|
21,142 |
|
26,741 |
|
|
NGL (bbl/d) |
6,495 |
|
7,417 |
|
8,699 |
|
7,340 |
|
10,229 |
|
|
Total liquids (bbl/d) |
57,788 |
|
63,656 |
|
79,655 |
|
65,538 |
|
80,557 |
|
|
Natural gas (mcf/d) |
76,116 |
|
84,945 |
|
100,235 |
|
85,464 |
|
102,742 |
|
|
Oil equivalent (boe/d @ 6:1) (2) |
70,475 |
|
77,814 |
|
96,360 |
|
79,781 |
|
97,680 |
|
|
|
|
|
|
|
|
| Netback
(thousands of Canadian dollars) |
|
|
|
|
|
|
Total sales, net of blending and other expense (3) |
$ |
222,745 |
|
$ |
241,865 |
|
$ |
427,728 |
|
$ |
927,096 |
|
$ |
1,737,124 |
|
|
Royalties |
(37,807 |
) |
(40,052 |
) |
(77,282 |
) |
(163,735 |
) |
(320,241 |
) |
|
Operating expense |
(79,748 |
) |
(73,447 |
) |
(99,573 |
) |
(331,345 |
) |
(397,716 |
) |
|
Transportation expense |
(6,692 |
) |
(6,372 |
) |
(8,840 |
) |
(28,437 |
) |
(43,942 |
) |
|
Operating netback (1) |
$ |
98,498 |
|
$ |
121,994 |
|
$ |
242,033 |
|
$ |
403,579 |
|
$ |
975,225 |
|
|
General and administrative |
(9,313 |
) |
(7,741 |
) |
(9,893 |
) |
(34,268 |
) |
(45,469 |
) |
|
Cash financing and interest |
(25,194 |
) |
(25,418 |
) |
(24,389 |
) |
(106,534 |
) |
(107,417 |
) |
|
Realized financial derivatives gain (loss) |
17,105 |
|
(9,743 |
) |
22,956 |
|
47,836 |
|
75,620 |
|
|
Other (4) |
1,081 |
|
(584 |
) |
1,440 |
|
893 |
|
4,467 |
|
|
Adjusted funds flow (1) |
$ |
82,176 |
|
$ |
78,508 |
|
$ |
232,147 |
|
$ |
311,506 |
|
$ |
902,426 |
|
|
|
|
|
|
|
|
| Netback (per
boe) |
|
|
|
|
|
|
Total sales, net of blending and other expense (3) |
$ |
34.35 |
|
$ |
33.79 |
|
$ |
48.25 |
|
$ |
31.75 |
|
$ |
48.72 |
|
|
Royalties |
(5.83 |
) |
(5.59 |
) |
(8.72 |
) |
(5.61 |
) |
(8.98 |
) |
|
Operating expense |
(12.30 |
) |
(10.26 |
) |
(11.23 |
) |
(11.35 |
) |
(11.16 |
) |
|
Transportation expense |
(1.03 |
) |
(0.89 |
) |
(1.00 |
) |
(0.97 |
) |
(1.23 |
) |
|
Operating netback (1) |
$ |
15.19 |
|
$ |
17.05 |
|
$ |
27.30 |
|
$ |
13.82 |
|
$ |
27.35 |
|
|
General and administrative |
(1.44 |
) |
(1.08 |
) |
(1.12 |
) |
(1.17 |
) |
(1.28 |
) |
|
Cash financing and interest |
(3.89 |
) |
(3.55 |
) |
(2.75 |
) |
(3.65 |
) |
(3.01 |
) |
|
Realized financial derivatives gain (loss) |
2.64 |
|
(1.36 |
) |
2.59 |
|
1.64 |
|
2.12 |
|
|
Other (4) |
0.17 |
|
(0.09 |
) |
0.16 |
|
0.03 |
|
0.13 |
|
|
Adjusted funds flow (1) |
$ |
12.67 |
|
$ |
10.97 |
|
$ |
26.18 |
|
$ |
10.67 |
|
$ |
25.31 |
|
|
Notes: |
|
|
|
|
(1) |
The terms “adjusted funds flow”, “exploration and development
expenditures”, “net debt” and “operating netback” do not have any
standardized meaning as prescribed by Canadian Generally Accepted
Accounting Principles (“GAAP”) and therefore may not be comparable
to similar measures presented by other companies where similar
terminology is used. See the advisory on non-GAAP measures at the
end of this press release. |
|
(2) |
Barrel of oil equivalent ("boe") amounts have been calculated using
a conversion rate of six thousand cubic feet of natural gas to one
barrel of oil. The use of boe amounts may be misleading,
particularly if used in isolation. A boe conversion ratio of six
thousand cubic feet of natural gas to one barrel of oil is based on
an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the
wellhead. |
|
(3) |
Realized heavy oil prices are calculated based on sales dollars,
net of blending and other expense. We include the cost of blending
diluent in our realized heavy oil sales price in order to compare
the realized pricing on our produced volumes to the WCS
benchmark. |
|
(4) |
Other is comprised of realized foreign exchange gain or loss, other
income or expense, current income tax expense or recovery and
share-based compensation. Refer to the 2020 MD&A for further
information on these amounts. |
|
|
|
2020 Results
In one of the most challenging years experienced
by our industry, we delivered on our commitment to preserve
financial liquidity, capture cost savings, generate free cash flow
and keep our operations safe. We also re-set our business in
response to the volatile crude oil market and improved our capital
efficiencies and overall sustainability.
Production during the fourth quarter averaged
70,475 boe/d (82% oil and NGL), as compared to 77,814 boe/d (82%
oil and NGL) in Q3/2020. The reduced volumes reflect a lower level
of completion activity in the Viking and Eagle Ford from March
through November, and the carry-over of drilled and uncompleted
wells into 2021. As we execute our plans for 2021, production has
increased to over 78,000 boe/d, consistent with our full-year
guidance.
Production in 2020 averaged 79,781 boe/d as
compared to 97,680 boe/d in 2019. The lower volumes reflect the
approximate 50% reduction in capital spending and the impact of
voluntary shut-ins earlier in the year. Exploration and development
expenditures totaled $78 million in Q4/2020 and $280 million for
full-year 2020. We participated in the completion of 217 (152.4
net) wells with a 100% success rate during the year.
We delivered adjusted funds flow of $82 million
($0.15 per basic share) in Q4/2020 and $312 million ($0.56 per
basic share) in 2020. This resulted in free cash flow of $18
million in 2020, which, along with the Canadian dollar
strengthening relative to the U.S. dollar, contributed to a $24
million reduction in our net debt this year.
We recorded net income of $221 million ($0.39
per basic share) in Q4/2020 and a net loss of $2.4 billion ($4.35
per basic share) in 2020. In March 2020, due to the sharp decline
in forecasted commodity prices, we recorded total impairments of
$2.7 billion as the carrying value of our oil and gas properties
exceeded the estimated recoverable amounts. At December 31, 2020
with updated development plans and changes in commodity prices, we
recorded an impairment reversal of $356 million. Revisions to
forecast crude oil prices could result in reversals or additional
impairment charges in the future.
The following table compares our 2020 results to
our 2020 guidance.
|
|
2020 Guidance |
|
|
|
Original (1) |
Revised (2) |
2020 Results |
|
Exploration and development expenditures |
$500 - $575 million |
$260 - $290 million |
$280 million |
| Production (boe/d) |
93,000 - 97,000 |
78,000 - 82,000 |
79,781 |
| |
|
|
|
| Expenses: |
|
|
|
|
Royalty rate |
18.0% - 18.5% |
18.5% |
17.7% |
|
Operating |
$11.25 - $12.00/boe |
$11.75 - $12.50/boe |
$11.35/boe |
|
Transportation |
$1.20 - $1.30/boe |
$0.95 - $1.05/boe |
$0.97/boe |
|
General and administrative |
$45 million ($1.30/boe) |
$38 million ($1.30/boe) |
$34.3 million ($1.17/boe) |
|
Interest |
$112 million ($3.23/boe) |
$112 million ($3.84/boe) |
$106.5 million ($3.65/boe) |
| |
|
|
|
| Leasing expenditures |
$7 million |
$7 million |
$6 million |
| Asset
retirement obligations |
$19 million |
$10 million |
$7 million |
|
Note: |
|
|
|
|
(1) |
As announced on December 4, 2019, prior to Covid-19. |
|
(2) |
As announced on June 25, 2020. This guidance reference date
included a corporate update announcing the resumption of previously
shut-in crude oil production. |
|
|
|
2021 Guidance
In 2021, we expect to benefit from our
diversified oil weighted portfolio and our commitment to allocate
capital effectively. Our priority is to generate stable production,
maximize free cash flow and further strengthen our balance
sheet.
There is no change to our 2021 annual guidance
as announced on December 2, 2020.
|
|
2021 Guidance |
|
|
Exploration and development expenditures |
$225 - $275 million |
|
| Production (boe/d) |
73,000 – 77,000 |
|
| |
|
|
| Expenses: |
|
|
|
Royalty rate |
18.0% - 18.5% |
|
|
Operating |
$11.50 - $12.25/boe |
|
|
Transportation |
$1.00 - $1.10 /boe |
|
|
General and administrative |
$42 million ($1.53/boe) |
|
|
Interest |
$105 million ($3.84/boe) |
|
| |
|
|
| Leasing expenditures |
$4 million |
|
| Asset
retirement obligations |
$6 million |
|
Operating Results
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 25,154
boe/d (77% oil and NGL) during Q4/2020, as compared to 28,650 boe/d
in Q3/2020. Production for the full-year 2020 averaged 31,179
boe/d, as compared to 39,055 boe/d in 2019. The lower volumes
reflect reduced completion activity as we adjusted our development
plan in response to volatile commodity prices. In 2020, we invested
$105 million on exploration and development in the Eagle Ford and
generated an operating netback of $202 million.
Activity in the Eagle Ford resumed during the
fourth quarter with 26 (7.1 net) wells drilled and 9 (2.7 net
wells) brought onstream. The remainder of the wells drilled during
the fourth quarter are expected to be onstream in Q1/2021. We
expect to bring approximately 18 net wells on production in the
Eagle Ford in 2021.
Production in the Viking averaged 15,326 boe/d
(89% oil and NGL) during Q4/2020, as compared to 18,774 boe/d in
Q3/2020. Full-year 2020 production averaged 19,614 boe/d, as
compared to 22,546 boe/d in 2019. In 2020, we invested
$105 million on exploration and development in the Viking and
generated an operating netback of $163 million.
We had previously suspended all drilling in the
Viking, and as such, there was limited activity from March through
October. We resumed drilling in November with two rigs mobilized to
execute a 30-well drilling program. In 2021, we expect to bring
approximately 120 net wells onstream, including 43 net wells during
the first quarter.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 24,228 boe/d (90% oil and NGL)
during the fourth quarter, as compared to 24,791 boe/d in Q3/2020.
Production for the full-year 2020 averaged 23,335 boe/d, as
compared to 29,378 boe/d in 2019. The impact of voluntary shut-ins
for the full-year 2020 was approximately 6,000 boe/d. In addition,
we had previously suspended all heavy oil drilling, and as such,
there was limited activity during the year. In 2020, we invested
$41 million on exploration and development on our heavy oil assets
and generated an operating netback of $27 million.
We have scheduled minimal heavy oil development
for the first half of 2021. At current commodity prices, we intend
to implement a drilling program in the second half of the year,
which could see us drill upwards of 30 net wells at Lloydminster
and 6 net wells at Peace River.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged
2,031 boe/d (84% oil and NGL) during Q4/2020, as compared to 1,474
boe/d in Q3/2020. Production for the full-year 2020 averaged 1,507
boe/d, as compared to 1,688 boe/d in 2019.
We continue to prudently advance our
Pembina Duvernay Shale light oil play. Our most recent two wells
were completed in October. The 10-16 well was brought on-stream
November 2 and generated a 30-day initial production rate of 1,300
boe/d (69% oil). The 11-16 well was brought on-stream November 17
and generated a facility constrained 30-day initial production rate
of 900 boe/d (68% oil). Based on early flowback results, these two
wells demonstrate repeatability of our 11-30 pad completed in 2019.
We have the flexibility in 2021 to drill up to 4 net wells in the
second half of the year.
Financial
Liquidity
Our credit facilities total approximately $1.03
billion and have a maturity date of April 2, 2024. These are not
borrowing base facilities and do not require annual or semi-annual
reviews. As of December 31, 2020, we had $367 million of undrawn
capacity on our credit facilities, resulting in liquidity, net of
working capital, of $319 million. We are well within our financial
covenants and our first long-term note maturity of US$400 million
is not until June 2024.
Our net debt, which includes our credit
facilities, long-term notes and working capital, totaled $1.85
billion at December 31, 2020, down from $1.91 billion at September
30, 2020. Based on the forward strip, we expect to increase our
financial liquidity to over $550 million in 2021.
Risk Management
To manage commodity price movements, we utilize
various financial derivative contracts and crude-by-rail to reduce
the volatility of our adjusted funds flow.
For 2021, we have entered into hedges on
approximately 48% of our net crude oil exposure utilizing a
combination of fixed price swaps at US$45/bbl and a 3-way option
structure that provides price protection
at US$44.71/bbl with upside participation to
US$52.42/bbl.
We also have WTI-MSW differential hedges on
approximately 50% of our expected 2021 Canadian light oil
production at US$5.05/bbl and WCS differential hedges on
approximately 50% of our expected 2021 heavy oil production at a
WTI-WCS differential of approximately US$13.31/bbl.
For 2021, we are contracted to deliver 5,500
bbl/d of our heavy oil volumes to market by rail.
A complete listing of our financial derivative
contracts can be found in Note 18 to our 2020 financial
statements.
Board Renewal and Governance
Naveen Dargan, a long-standing board member, has
announced his intent to retire from the Baytex Board at the 2021
Annual Meeting of Shareholders to be held in April 2021. Baytex
thanks Mr. Dargan for his valued contribution during his tenure on
the Board. His hard work and dedication for the benefit of all
stakeholders is greatly appreciated.
Baytex has an ongoing board renewal process led
by the Nominating and Governance Committee of the Board. Since
September 2019, Baytex has added three independent Board members
from various professional backgrounds. Following Mr. Dargan’s
retirement, the Board will be comprised of eight directors with
seven of eight being independent, including the Chair of the Board
and all committee members. In addition, two of eight directors are
women.
ESG – Update on GHG Emissions Reduction
In 2019, Baytex established for the first time a
GHG emissions reduction target. Our objective was to reduce our
corporate GHG emission intensity (tonnes of CO2e per boe) by 30% by
2021, relative to our 2018 baseline. We are pleased to announce
that we have exceeded this target in scope and timing, achieving a
46% reduction in our GHG emissions intensity through year-end 2020.
This represents an annual reduction of 1.6 million tonnes of CO2e
and is equivalent to taking 340,000 cars off the road
annually. To achieve our goal, we completed our Peace River
gas plant in mid-2018 and significantly advanced our Viking
emissions reduction project.
Continual improvement is an important element of
our corporate culture and we are setting the bar higher. We have
established a new target with an objective to reduce our corporate
GHG emission intensity (tonnes of CO2 per boe) by a further 33%
from current levels by 2025. This equates to an approximate 65%
reduction by 2025, relative to our 2018 baseline. Our emissions
reduction strategy includes increased gas conservation and
combustion, reusing associated gas as fuel for field activities,
reduced emissions from storage tanks, along with monitoring and
preventing fugitive emissions.
GHG Emissions Intensity (Scope 1 and
Scope 2)
|
|
2018 Baseline |
2019 |
2020 |
2025 Target |
|
Tonnes CO2e/boe |
0.112 |
0.095 |
0.061 |
0.041 |
| |
|
|
|
|
We look forward to publishing our fifth
corporate sustainability report later this year as we continue to
demonstrate our commitment to transparency and accountability,
along with our progress in managing the environmental and social
aspects of our business.
Year-end 2020 Reserves
Baytex's year-end 2020 proved and probable
reserves were evaluated by McDaniel & Associates Consultants
Ltd. (“McDaniel”), an independent qualified reserves evaluator. All
of our oil and gas properties were evaluated in accordance with
National Instrument 51-101 “Standards of Disclosure for Oil and Gas
Activities” (“NI 51-101”) and the Canadian Oil and Gas Evaluation
Handbook (the “COGE Handbook”) using the average commodity price
forecasts and inflation rates of McDaniel, GLJ Petroleum
Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as
of January 1, 2021.
Reserves associated with our thermal heavy oil
projects at Gemini (Cold Lake) and Kerrobert have been classified
as bitumen. Complete reserves disclosure will be included in our
Annual Information Form for the year ended
December 31, 2020, which will be filed on or before March
31, 2021.
Our 2020 reserves report reflects the impact of
a materially lower commodity price forecast being utilized by our
reserves evaluator, which was brought on by Covid-19 and the
extremely volatile crude oil market. We highlight the updated
commodity price forecast on page 11 which has WTI averaging
US$56/bbl over the next ten years, down 20% from one year ago.
Consistent with the $2.4 billion impairment we recorded in 2020, we
removed 29 million barrels of proved reserves (65% heavy oil and
bitumen) and 41 million barrels of proved plus probable reserves
(80% heavy oil and bitumen), which are uneconomic under the
commodity price forecast.
Reserves Highlights
- Our proved
developed producing ("PDP") reserves total 120 mmboe, proved
reserves (“1P”) total 271 mmboe and our proved plus probable
reserves (“2P”) total 462 mmboe.
- Reserves on a 1P
basis are comprised of 81% oil and NGL (48% light oil, 33% NGL’s,
16% heavy oil and 3% bitumen) and 19% natural gas. PDP reserves
represent 44% of 1P reserves (45% at year-end 2019) and 1P reserves
represent 59% of 2P reserves (59% at year-end 2019).
- Baytex maintains a strong reserves
life index of 4.7 years based on PDP reserves, 10.5 years based on
1P reserves and 17.9 years based on 2P reserves.
- Future
development costs have been reduced by $464 million on a 1P basis
and $709 million on a 2P basis.
- Our net asset
value at year-end 2020, discounted at 10%, is estimated to be $2.78
per share. This is based on the estimated reserves value plus a
value for undeveloped acreage, net of long-term debt and working
capital.
The following table sets forth our gross and net
reserves volumes at December 31, 2020 by product type and
reserves category. Please note that the data in the table may not
add due to rounding.
Reserves Summary
|
|
Light andMedium Oil |
Tight Oil |
HeavyOil |
Bitumen |
Total Oil |
Natural GasLiquids (3) |
ConventionalNatural Gas (4) |
ShaleGas |
Total (5) |
|
Reserves Summary |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mmcf) |
(mmcf) |
(mboe) |
|
Gross (1) |
|
|
|
|
|
|
|
|
|
|
Proved producing |
20,404 |
23,473 |
19,917 |
1,144 |
64,938 |
31,669 |
43,384 |
97,321 |
120,057 |
|
Proved developed non-producing |
61 |
38 |
1,997 |
160 |
2,255 |
639 |
15,072 |
473 |
5,485 |
|
Proved undeveloped |
31,601 |
29,805 |
13,499 |
4,433 |
79,339 |
40,167 |
29,438 |
128,541 |
145,835 |
|
Total proved |
52,067 |
53,316 |
35,412 |
5,737 |
146,532 |
72,475 |
87,894 |
226,334 |
271,378 |
|
Total probable |
25,688 |
24,642 |
30,544 |
46,093 |
126,967 |
32,760 |
86,778 |
96,852 |
190,332 |
|
Proved plus probable |
77,755 |
77,958 |
65,956 |
51,830 |
273,499 |
105,235 |
174,671 |
323,186 |
461,710 |
|
Net (2) |
|
|
|
|
|
|
|
|
|
|
Proved producing |
19,106 |
17,445 |
18,404 |
1,027 |
55,983 |
23,635 |
40,568 |
72,440 |
98,452 |
|
Proved developed non-producing |
59 |
28 |
1,895 |
152 |
2,135 |
504 |
13,080 |
350 |
4,877 |
|
Proved undeveloped |
29,630 |
22,371 |
12,385 |
4,213 |
68,598 |
29,865 |
26,071 |
95,639 |
118,748 |
|
Total proved |
48,795 |
39,844 |
32,684 |
5,393 |
126,716 |
54,003 |
79,270 |
168,429 |
222,077 |
|
Total probable |
23,461 |
18,777 |
27,640 |
40,064 |
109,941 |
24,853 |
80,679 |
73,061 |
160,417 |
|
Proved plus probable |
72,256 |
58,621 |
60,324 |
45,456 |
236,657 |
78,856 |
160,398 |
241,490 |
382,495 |
|
Notes: |
|
|
|
|
(1) |
“Gross” reserves means the total working interest share of
remaining recoverable reserves owned by Baytex before deductions of
royalties payable to others. |
|
(2) |
“Net” reserves means Baytex's gross reserves less all royalties
payable to others plus royalty interest reserves. |
|
(3) |
Natural Gas Liquids includes condensate. |
|
(4) |
Conventional Natural Gas includes associated, non-associated and
solution gas. |
|
(5) |
Oil equivalent amounts have been calculated using a conversion rate
of six thousand cubic feet of natural gas to one barrel of oil.
BOEs may be misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. |
|
|
|
Reserves Reconciliation
The following table reconciles the
year-over-year changes in our gross reserves volumes by product
type and reserves category. Please note that the data in the table
may not add due to rounding.
Proved Reserves – Gross Volumes
(1) (Forecast Prices)
|
|
Light andMedium Oil |
Tight Oil |
HeavyOil |
Bitumen |
Total Oil |
Natural GasLiquids
(3) |
ConventionalNatural Gas
(4) |
ShaleGas |
Total
(5) |
|
|
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mmcf) |
(mmcf) |
(mboe) |
|
December 31, 2019 |
60,619 |
|
55,562 |
|
51,311 |
|
11,799 |
|
179,291 |
|
77,939 |
|
104,506 |
|
234,162 |
|
313,674 |
|
| Extensions |
2,840 |
|
1,618 |
|
160 |
|
3,027 |
|
7,645 |
|
1,541 |
|
12,937 |
|
4,038 |
|
12,015 |
|
| Technical Revisions (2) |
(1,275 |
) |
1,780 |
|
2,462 |
|
(1,224 |
) |
1,743 |
|
(758 |
) |
9,360 |
|
7,225 |
|
3,749 |
|
| Acquisitions |
16 |
|
— |
|
— |
|
— |
|
16 |
|
1 |
|
19 |
|
— |
|
20 |
|
| Dispositions |
(15 |
) |
— |
|
(5 |
) |
— |
|
(20 |
) |
— |
|
(38 |
) |
— |
|
(26 |
) |
| Economic Factors |
(3,421 |
) |
(592 |
) |
(11,698 |
) |
(6,945 |
) |
(22,655 |
) |
(1,748 |
) |
(23,824 |
) |
(2,877 |
) |
(28,854 |
) |
|
Production |
(6,698 |
) |
(5,052 |
) |
(6,818 |
) |
(920 |
) |
(19,488 |
) |
(4,499 |
) |
(15,066 |
) |
(16,213 |
) |
(29,200 |
) |
|
December 31, 2020 |
52,067 |
|
53,316 |
|
35,412 |
|
5,737 |
|
146,532 |
|
72,475 |
|
87,894 |
|
226,334 |
|
271,378 |
|
Probable Reserves – Gross
Volumes (1) (Forecast
Prices)
|
|
Light andMedium Oil |
Tight Oil |
HeavyOil |
Bitumen |
TotalOil |
Natural GasLiquids
(3) |
ConventionalNatural Gas
(4) |
ShaleGas |
Total
(5) |
|
|
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mmcf) |
(mmcf) |
(mboe) |
|
December 31, 2019 |
31,218 |
|
24,139 |
|
37,805 |
|
53,743 |
|
146,905 |
|
35,654 |
|
99,816 |
|
99,739 |
|
215,818 |
|
| Extensions |
(1,937 |
) |
1,291 |
|
244 |
|
696 |
|
294 |
|
908 |
|
(11,371 |
) |
5,283 |
|
187 |
|
| Technical Revisions (2) |
(3,643 |
) |
(648 |
) |
(1,634 |
) |
(366 |
) |
(6,291 |
) |
(3,954 |
) |
(10,854 |
) |
(6,929 |
) |
(13,208 |
) |
| Acquisitions |
3 |
|
— |
|
— |
|
— |
|
3 |
|
— |
|
3 |
|
— |
|
4 |
|
| Dispositions |
(92 |
) |
— |
|
(4 |
) |
— |
|
(96 |
) |
(4 |
) |
(348 |
) |
— |
|
(158 |
) |
| Economic Factors |
139 |
|
(141 |
) |
(5,867 |
) |
(7,980 |
) |
(13,849 |
) |
157 |
|
9,531 |
|
(1,240 |
) |
(12,311 |
) |
|
Production |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
|
December 31, 2020 |
25,688 |
|
24,642 |
|
30,544 |
|
46,093 |
|
126,967 |
|
32,760 |
|
86,778 |
|
96,852 |
|
190,332 |
|
Proved Plus Probable Reserves – Gross
Volumes (1)
(Forecast Prices)
|
|
Light andMedium Oil |
Tight Oil |
HeavyOil |
Bitumen |
Total Oil |
Natural GasLiquids
(3) |
ConventionalNatural Gas
(4) |
ShaleGas |
Total
(5) |
|
|
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mbbls) |
(mmcf) |
(mmcf) |
(mboe) |
|
December 31, 2019 |
91,837 |
|
79,701 |
|
89,116 |
|
65,542 |
|
326,196 |
|
113,592 |
|
204,323 |
|
333,901 |
|
529,492 |
|
| Extensions |
903 |
|
2,909 |
|
404 |
|
3,723 |
|
7,939 |
|
2,449 |
|
1,565 |
|
9,320 |
|
12,202 |
|
| Technical Revisions (2) |
(4,917 |
) |
1,132 |
|
827 |
|
(1,590 |
) |
(4,548 |
) |
(4,712 |
) |
(1,494 |
) |
296 |
|
(9,460 |
) |
| Acquisitions |
19 |
|
— |
|
— |
|
— |
|
19 |
|
1 |
|
22 |
|
— |
|
24 |
|
| Dispositions |
(107 |
) |
— |
|
(8 |
) |
— |
|
(116 |
) |
(4 |
) |
(386 |
) |
— |
|
(184 |
) |
| Economic Factors |
(3,282 |
) |
(733 |
) |
(17,565 |
) |
(14,925 |
) |
(36,505 |
) |
(1,592 |
) |
(14,293 |
) |
(4,118 |
) |
(41,165 |
) |
|
Production |
(6,698 |
) |
(5,052 |
) |
(6,818 |
) |
(920 |
) |
(19,488 |
) |
(4,499 |
) |
(15,066 |
) |
(16,213 |
) |
(29,200 |
) |
|
December 31, 2020 |
77,755 |
|
77,958 |
|
65,956 |
|
51,830 |
|
273,499 |
|
105,235 |
|
174,671 |
|
323,186 |
|
461,710 |
|
|
Notes: |
|
|
|
|
(1) |
“Gross” reserves means the total working interest share of
remaining recoverable reserves owned by Baytex before deductions of
royalties payable to others. |
|
(2) |
Positive and negative revisions in heavy oil, bitumen, light and
medium oil and tight oil are due to variations in performance
versus previous forecasts in our Viking, Eagle Ford, Peace River
and Lloydminster assets. Technical revisions for conventional
natural gas are a combination of performance revisions in our Deep
Basin assets and performance revisions for solution gas (classified
as conventional natural gas) from our light and heavy oil
properties. Positive revisions for shale gas are attributed to
improved performance in the Duvernay and Eagle Ford assets. |
|
(3) |
Natural gas liquids include condensate. |
|
(4) |
Conventional natural gas includes associated, non-associated and
solution gas. |
|
(5) |
Oil equivalent amounts have been calculated using a conversion rate
of six thousand cubic feet of natural gas to one barrel of oil.
BOEs may be misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. |
|
|
|
Future Development Costs
The following table sets forth future
development costs deducted in the estimation of the future net
revenue attributable to the reserves categories noted below.
|
Future Development Costs ($ millions) |
ProvedReserves |
Proved Plus Probable
Reserves |
|
|
2021 |
276 |
283 |
|
| 2022 |
439 |
491 |
|
| 2023 |
477 |
560 |
|
| 2024 |
432 |
538 |
|
| 2025 |
420 |
580 |
|
|
Remainder |
50 |
1,153 |
|
|
Total FDC undiscounted |
2,094 |
3,606 |
|
F&D and FD&A Costs – including future
development costs
Based on the evaluation of our petroleum and
natural gas reserves prepared by McDaniel, the efficiency of our
capital program is summarized in the following table.
|
millions except for per boe amounts |
2020 |
|
2019 |
|
2018 |
3 Year |
|
|
Proved plus Probable Reserves |
|
|
|
|
| Finding &
Development Costs |
|
|
|
|
| Exploration and development
expenditures |
$280.3 |
|
$552.3 |
|
$495.7 |
$1,328.3 |
|
| Net change in Future
Development Costs |
($705.9 |
) |
$96.7 |
|
$132.3 |
($476.8 |
) |
| Gross Reserves additions
(mmboe) |
(38.4 |
) |
39.8 |
|
31.2 |
32.6 |
|
| F&D Costs ($/boe) |
$11.08 |
|
$16.30 |
|
$20.11 |
$26.09 |
|
| |
|
|
|
|
| Finding, Development
& Acquisition (“FD&A”) Costs |
|
|
|
|
| Exploration and development
expenditures and net acquisitions |
$280.2 |
|
$554.5 |
|
$2,099.6 |
$2,934.2 |
|
| Net change in Future
Development Costs |
($709.3 |
) |
$79.9 |
|
$1,064.5 |
$435.1 |
|
| Gross Reserves additions
(mmboe) |
(38.6 |
) |
38.6 |
|
123.9 |
123.9 |
|
|
FD&A Costs ($/boe) |
$11.12 |
|
$16.42 |
|
$25.55 |
$27.19 |
|
|
|
|
|
|
|
| Proved
Reserves |
|
|
|
|
| Finding &
Development Costs |
|
|
|
|
| Exploration and development
expenditures |
$280.3 |
|
$552.3 |
|
$495.7 |
$1,328.3 |
|
| Net change in Future
Development Costs |
($464.4 |
) |
($90.4 |
) |
$117.4 |
($437.4 |
) |
| Gross Reserves additions
(mmboe) |
(13.1 |
) |
35.8 |
|
17.5 |
40.2 |
|
| F&D Costs ($/boe) |
$14.06 |
|
$12.92 |
|
$35.05 |
$22.18 |
|
| |
|
|
|
|
| Finding, Development
& Acquisition Costs |
|
|
|
|
| Exploration and development
expenditures and net acquisitions |
$280.2 |
|
$554.5 |
|
$2,099.6 |
$2,934.2 |
|
| Net change in Future
Development Costs |
($464.4 |
) |
($107.2 |
) |
$987.4 |
$415.8 |
|
| Gross Reserves additions
(mmboe) |
(13.1 |
) |
34.7 |
|
88.4 |
110.0 |
|
|
FD&A Costs ($/boe) |
$14.07 |
|
$12.88 |
|
$34.91 |
$30.44 |
|
|
|
|
|
|
|
| Proved Developed
Producing Reserves |
|
|
|
|
| Finding &
Development Costs |
|
|
|
|
| Exploration and development
expenditures |
$280.3 |
|
$552.3 |
|
$495.7 |
$1,328.3 |
|
| Gross Reserves additions
(mmboe) |
7.7 |
|
42.5 |
|
31.3 |
81.3 |
|
| F&D Costs ($/boe) |
$36.63 |
|
$13.04 |
|
$15.82 |
$16.33 |
|
| |
|
|
|
|
| Finding, Development
& Acquisition Costs |
|
|
|
|
| Exploration and development
expenditures and net acquisitions |
$280.2 |
|
$554.5 |
|
$2,099.6 |
$2,934.2 |
|
| Gross Reserves additions
(mmboe) |
7.6 |
|
42.5 |
|
63.7 |
113.9 |
|
|
FD&A Costs ($/boe) |
$36.64 |
|
$13.04 |
|
$32.95 |
$25.76 |
|
Reserves Life Index
The following table sets forth our reserves life
index, which is calculated by dividing our proved and proved plus
probable reserves at year-end 2020 by annualized Q4/2020
production.
|
|
|
Reserves Life Index (years) |
|
|
|
Q4/2020Production |
Proved |
Proved Plus Probable |
|
|
Crude Oil and NGL (bbl/d) |
57,788 |
10.4 |
18.0 |
|
| Natural
Gas (mcf/d) |
76,116 |
11.3 |
17.9 |
|
|
Oil Equivalent (boe/d) |
70,475 |
10.5 |
17.9 |
|
Forecast Prices and Costs
The following table summarizes the forecast
prices used in preparing the estimated reserves volumes and the net
present values of future net revenues at December 31, 2020.
The estimated future net revenue to be derived from the production
of the reserves is based on the following average of the price
forecasts of McDaniel, GLJ and Sproule as of January 1, 2020.
|
Year |
WTI Crude OilUS$/bbl |
Edmonton LightCrude Oil
$/bbl |
WesternCanadian Select$/bbl |
Henry HubUS$/MMbtu |
AECO Spot$/MMbtu |
Inflation Rate %/Yr |
Exchange Rate$US/$Cdn |
|
2020 act. |
39.20 |
45.00 |
35.35 |
2.05 |
2.25 |
0.2 |
0.745 |
|
2021 |
47.17 |
55.76 |
44.63 |
2.83 |
2.78 |
0.0 |
0.768 |
|
2022 |
50.17 |
59.89 |
48.18 |
2.87 |
2.70 |
1.3 |
0.765 |
|
2023 |
53.17 |
63.48 |
52.10 |
2.90 |
2.61 |
2.0 |
0.763 |
|
2024 |
54.97 |
65.76 |
54.10 |
2.96 |
2.65 |
2.0 |
0.763 |
|
2025 |
56.07 |
67.13 |
55.19 |
3.02 |
2.70 |
2.0 |
0.763 |
|
2026 |
57.19 |
68.53 |
56.29 |
3.08 |
2.76 |
2.0 |
0.763 |
|
2027 |
58.34 |
69.95 |
57.42 |
3.14 |
2.81 |
2.0 |
0.763 |
|
2028 |
59.50 |
71.40 |
58.57 |
3.20 |
2.87 |
2.0 |
0.763 |
|
2029 |
60.69 |
72.88 |
59.74 |
3.26 |
2.92 |
2.0 |
0.763 |
|
2030 |
61.91 |
74.34 |
60.93 |
3.33 |
2.98 |
2.0 |
0.763 |
|
Thereafter |
Escalation rate of 2.0% |
2.0 |
0.763 |
Net Present Value of Reserves
(1) (Forecast Prices and
Costs)
The following table summarizes the McDaniel
estimate of the net present value before income taxes of the future
net revenue attributable to our reserves.
|
Reserves at December 31, 2020 ($ millions, discounted at) |
0% |
5% |
10% |
15% |
|
Proved developed producing |
1,089 |
1,203 |
1,118 |
1,018 |
| Proved developed
non-producing |
69 |
59 |
51 |
46 |
| Proved
undeveloped |
2,221 |
1,443 |
972 |
671 |
|
Total proved |
3,379 |
2,704 |
2,141 |
1,735 |
|
Probable |
3,374 |
1,837 |
1,138 |
771 |
|
Total Proved Plus Probable (before tax) |
6,753 |
4,542 |
3,279 |
2,505 |
|
Note: |
|
|
|
|
(1) |
Includes abandonment, decommissioning and reclamation costs for all
producing and nonproducing wells and facilities. |
|
|
|
Net Asset Value (Forecast Prices and Costs)
Our estimated net asset value is based on the
estimated net present value of all future net revenue from our
reserves, before income taxes, as estimated by McDaniel at
year-end, plus the estimated value of our undeveloped land
holdings, less net debt. This calculation can vary significantly
depending on the oil and natural gas price assumptions. In
addition, this calculation does not consider "going concern" value
and assumes only the reserves identified in the reserves reports
with no further acquisitions or incremental development.
The following table sets forth our net asset
value as at December 31, 2020.
|
($ millions, except per share amounts, discounted at) |
5% |
|
10% |
|
15% |
|
|
Net present value of proved plus probable reserves (1) |
4,542 |
|
3,279 |
|
2,505 |
|
| Undeveloped land holdings
(2) |
130 |
|
130 |
|
130 |
|
| Net
Debt |
(1,848 |
) |
(1,848 |
) |
(1,848 |
) |
|
Net Asset Value |
2,824 |
|
1,561 |
|
787 |
|
| Net
Asset Value per Share (3) |
5.03 |
|
2.78 |
|
1.40 |
|
|
Notes: |
|
|
|
|
(1) |
Includes abandonment, decommissioning and reclamation costs for all
producing and nonproducing wells and facilities. |
|
(2) |
The value of undeveloped land holdings generally represents the
estimated replacement cost of our undeveloped land. |
|
(3) |
Based on 561.2 million common shares outstanding as at December 31,
2020. |
|
|
|
Additional Information
Our audited consolidated financial statements
for the year ended December 31, 2020 and the related Management's
Discussion and Analysis of the operating and financial results can
be accessed on our website at www.baytexenergy.com and will be
available shortly through SEDAR at www.sedar.com and EDGAR at
www.sec.gov/edgar.shtml.
|
Conference Call Tomorrow9:00 a.m. MST
(11:00 a.m. EST) |
|
Baytex will host a conference call tomorrow, February 25, 2021,
starting at 9:00am MST (11:00am EST). To participate, please dial
toll free in North America 1-800-319-4610 or international
1-416-915-3239. Alternatively, to listen to the conference call
online, please enter
http://services.choruscall.ca/links/baytex20210225.html in your web
browser.An archived recording of the conference call will be
available shortly after the event by accessing the webcast link
above. The conference call will also be archived on the Baytex
website at www.baytexenergy.com. |
Advisory Regarding Forward-Looking
Statements
In the interest of providing Baytex's
shareholders and potential investors with information regarding
Baytex, including management's assessment of Baytex's future plans
and operations, certain statements in this press release are
"forward-looking statements" within the meaning of the United
States Private Securities Litigation Reform Act of 1995 and
"forward-looking information" within the meaning of applicable
Canadian securities legislation (collectively, "forward-looking
statements"). In some cases, forward-looking statements can be
identified by terminology such as "believe", "continue",
""estimate", "expect", "forecast", "intend", "may", "objective",
"ongoing", "outlook", "potential", "project", "plan", "should",
"target", "would", "will" or similar words suggesting future
outcomes, events or performance. The forward-looking statements
contained in this press release speak only as of the date thereof
and are expressly qualified by this cautionary statement.
Specifically, this press release contains
forward-looking statements relating to but not limited to: our
business strategies, plans and objectives; that we are on track to
deliver $250 million ($0.45 per basic share) of free cash flow in
2021, are building operational momentum and executing our plan to
maximize free cash flow and accelerate our debt reduction strategy;
in 2021 that: we will benefit from a disciplined approach to
capital allocation and a continued drive to improve our cost
structure and capital efficiencies, our high graded capital program
is focused on high netback light oil assets in the Viking and Eagle
Ford and that, at current commodity prices, we intend to implement
a heavy oil program in the second half of the year; our guidance
for 2021 exploration and development expenditures, production,
royalty rate, operating, transportation, general and administration
and interest expense and leasing expenditures and asset retirement
obligations; that 48% of our net crude oil exposure for 2021 is
hedged; In 2021, we expect to benefit from our diversified oil
weighted portfolio and our commitment to allocate capital
effectively and that our priority is to generate stable production,
maximize free cash flow and further strengthen our balance sheet;
for 2021 in the Eagle Ford: we expect to bring wells drilled in
Q4/2020 on stream in Q1/2021 and bring 18 net wells on production;
in the Viking: that we expect to bring 43 net wells on stream in
Q1/2020 and 120 net wells on stream in 2021; we have minimal heavy
oil development scheduled in H1/2021 and, at current commodity
prices, we intend to implement a drilling program in H2/2021 with
upwards of 30 net wells drilled at Lloydminster and 6 net wells
drilled at Peace River; in Pembina Duvernay we have
flexibility to drill up to 4 net wells in H2/2021; based on the
forward strip, we expect to increase our financial liquidity to
approximately $500 million in 2021; that we use financial
derivative contracts and crude-by-rail to reduce adjusted funds
flow volatility and the percentage of our expected production in
2021 of Canadian light oil and heavy oil for which we have hedged
the differential to WTI; our 2025 GHG emissions intensity reduction
target and our strategy to reach the target; that we plan to
publish our fifth corporate sustainability report this year; future
development costs, F&D and FD&A; our reserves life index;
forecast prices for oil and natural gas; forecast inflation and
exchange rates; the net present value before income taxes of the
future net revenue attributable to our reserves; the value of our
undeveloped land holdings and our estimated net asset value. In
addition, information and statements relating to reserves are
deemed to be forward-looking statements, as they involve implied
assessment, based on certain estimates and assumptions, that the
reserves described exist in quantities predicted or estimated, and
that they can be profitably produced in the future.
These forward-looking statements are based on
certain key assumptions regarding, among other things: petroleum
and natural gas prices and differentials between light, medium and
heavy oil prices; well production rates and reserve volumes; our
ability to add production and reserves through our exploration and
development activities; capital expenditure levels; our ability to
borrow under our credit agreements; the receipt, in a timely
manner, of regulatory and other required approvals for our
operating activities; the availability and cost of labour and other
industry services; interest and foreign exchange rates; the
continuance of existing and, in certain circumstances, proposed tax
and royalty regimes; our ability to develop our crude oil and
natural gas properties in the manner currently contemplated; and
current industry conditions, laws and regulations continuing in
effect (or, where changes are proposed, such changes being adopted
as anticipated). Readers are cautioned that such assumptions,
although considered reasonable by Baytex at the time of
preparation, may prove to be incorrect.
Actual results achieved will vary from the
information provided herein as a result of numerous known and
unknown risks and uncertainties and other factors. Such factors
include, but are not limited to: the volatility of oil and natural
gas prices and price differentials (including the impacts of
Covid-19); the availability and cost of capital or borrowing; risks
associated with our ability to exploit our properties and add
reserves; availability and cost of gathering, processing and
pipeline systems; that our credit facilities may not provide
sufficient liquidity or may not be renewed; failure to comply with
the covenants in our debt agreements; risks associated with a
third-party operating our Eagle Ford properties; public perception
and its influence on the regulatory regime; restrictions or costs
imposed by climate change initiatives and the physical risks of
climate change; new regulations on hydraulic fracturing;
restrictions on or access to water or other fluids; changes in
government regulations that affect the oil and gas industry;
regulations regarding the disposal of fluids; changes in
environmental, health and safety regulations; costs to develop and
operate our properties; variations in interest rates and foreign
exchange rates; risks associated with our hedging activities;
retaining or replacing our leadership and key personnel; changes in
income tax or other laws or government incentive programs;
uncertainties associated with estimating oil and natural gas
reserves; our inability to fully insure against all risks; risks of
counterparty default; risks related to our thermal heavy oil
projects; alternatives to and changing demand for petroleum
products; risks associated with our use of information technology
systems; results of litigation; risks associated with large
projects; risks associated with the ownership of our securities,
including changes in market-based factors; risks for United States
and other non-resident shareholders, including the ability to
enforce civil remedies, differing practices for reporting reserves
and production, additional taxation applicable to non-residents and
foreign exchange risk; and other factors, many of which are beyond
our control.
These and additional risk factors are discussed
in our Annual Information Form, Annual Report on Form 40-F and
Management's Discussion and Analysis for the year ended December
31, 2020, to be filed with Canadian securities regulatory
authorities and the U.S. Securities and Exchange Commission not
later than March 31, 2021 and in our other public filings
The above summary of assumptions and risks
related to forward-looking statements has been provided in order to
provide shareholders and potential investors with a more complete
perspective on Baytex’s current and future operations and such
information may not be appropriate for other purposes.
There is no representation by Baytex that actual
results achieved will be the same in whole or in part as those
referenced in the forward-looking statements and Baytex does not
undertake any obligation to update publicly or to revise any of the
included forward-looking statements, whether as a result of new
information, future events or otherwise, except as may be required
by applicable securities law.
All amounts in this press release are stated in
Canadian dollars unless otherwise specified.
Non-GAAP Financial and Capital
Management Measures
In this press release, we refer to certain
financial measures (such as adjusted funds flow, exploration and
development expenditures, free cash flow, net debt and operating
netback) which do not have any standardized meaning prescribed by
Canadian GAAP (“non-GAAP measures”) and are considered non-GAAP
measures. While adjusted funds flow, exploration and development
expenditures, free cash flow, net debt and operating netback are
commonly used in the oil and gas industry, our determination of
these measures may not be comparable with calculations of similar
measures for other issuers.
Adjusted funds flow is not a measurement based
on generally accepted accounting principles ("GAAP") in Canada, but
is a financial term commonly used in the oil and gas industry. We
define adjusted funds flow as cash flow from operating activities
adjusted for changes in non-cash operating working capital and
asset retirement obligations settled. Our determination of adjusted
funds flow may not be comparable to other issuers. We consider
adjusted funds flow a key measure that provides a more complete
understanding of operating performance and our ability to generate
funds for exploration and development expenditures, debt repayment,
settlement of our abandonment obligations and potential future
dividends.
In addition, we use a ratio of net debt to
adjusted funds flow to manage our capital structure. We eliminate
settlements of abandonment obligations from cash flow from
operations as the amounts can be discretionary and may vary from
period to period depending on our capital programs and the maturity
of our operating areas. The settlement of abandonment obligations
are managed with our capital budgeting process which considers
available adjusted funds flow. Changes in non-cash working capital
are eliminated in the determination of adjusted funds flow as the
timing of collection, payment and incurrence is variable and by
excluding them from the calculation we are able to provide a more
meaningful measure of our cash flow on a continuing basis. For a
reconciliation of adjusted funds flow to cash flow from operating
activities, see Management's Discussion and Analysis of the
operating and financial results for the year ended December 31,
2020.
Exploration and development expenditures is not
a measurement based on GAAP in Canada. We define exploration and
development expenditures as additions to exploration and evaluation
assets combined with additions to oil and gas properties. Our
definition of exploration and development expenditures may not be
comparable to other issuers. We use exploration and development
expenditures to measure and evaluate the performance of our capital
programs. The total amount of exploration and development
expenditures is managed as part of our budgeting process and can
vary from period to period depending on the availability of
adjusted funds flow and other sources of liquidity.
Free cash flow is not a measurement based on
GAAP in Canada. We define free cash flow as adjusted funds flow
less exploration and development expenditures (both non-GAAP
measures discussed above), payments on lease obligations, and asset
retirement obligations settled. Our determination of free cash flow
may not be comparable to other issuers. We use free cash flow to
evaluate funds available for debt repayment, common share
repurchases, potential future dividends and acquisition and
disposition opportunities.
Net debt is not a measurement based on GAAP in
Canada. We define net debt to be the sum of cash, trade and other
accounts receivable, trade and other accounts payable, and the
principal amount of both the long-term notes and the credit
facilities. Our definition of net debt may not be comparable to
other issuers. We believe that this measure assists in providing a
more complete understanding of our cash liabilities and provides a
key measure to assess our liquidity. We use the principal amounts
of the credit facilities and long-term notes outstanding in the
calculation of net debt as these amounts represent our ultimate
repayment obligation at maturity. The carrying amount of debt issue
costs associated with the credit facilities and long-term notes is
excluded on the basis that these amounts have already been paid by
Baytex at inception of the contract and do not represent an
additional source of capital or repayment obligation.
Operating netback is not a measurement based on
GAAP in Canada, but is a financial term commonly used in the oil
and gas industry. Operating netback is equal to petroleum and
natural gas sales less blending expense, royalties, production and
operating expense and transportation expense divided by barrels of
oil equivalent sales volume for the applicable period. Our
determination of operating netback may not be comparable with the
calculation of similar measures for other entities. We believe that
this measure assists in characterizing our ability to generate cash
margin on a unit of production basis and is a key measure used to
evaluate our operating performance.
Advisory Regarding Oil and Gas Information
The reserves information contained in this press
release has been prepared in accordance with NI 51-101. Complete NI
51-101 reserves disclosure will be included in our Annual
Information Form for the year ended December 31, 2020, which will
be filed on or before March 31, 2021. Listed below are
cautionary statements that are specifically required by NI
51-101:
- The term barrels of oil equivalent
(“boe”) may be misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet of natural gas to one
boe (6 mcf/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 from the energy equivalency of 6:1,
utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
- With respect to finding and
development costs, the aggregate of the exploration and development
costs incurred in the most recent financial year and the change
during that year in estimated future development costs generally
will not reflect total finding and development costs related to
reserves additions for that year.
- This press release contains
estimates of the net present value of our future net revenue from
our reserves. Such amounts do not represent the fair market value
of our reserves.
Throughout this press release, “oil and NGL”
refers to heavy oil, bitumen, light and medium oil, tight oil,
condensate and natural gas liquids (“NGL”) product types as defined
by NI 51-101. The following table shows Baytex’s disaggregated
production volumes for the three and twelve months ended December
31, 2020. The NI 51-101 product types are included as follows:
“Heavy Oil” - heavy oil and bitumen, “Light and Medium Oil” - light
and medium oil, tight oil and condensate, “NGL” - natural gas
liquids and “Natural Gas” - shale gas and conventional natural
gas.
|
|
Three Months Ended December 31, 2020 |
|
Twelve Months Ended December 31, 2020 |
|
|
Heavy Oil (bbl/d) |
Light andMedium Oil (bbl/d) |
NGL (bbl/d) |
Natural Gas (Mcf/d) |
OilEquivalent (boe/d) |
|
Heavy Oil (bbl/d) |
Light andMedium Oil (bbl/d) |
NGL (bbl/d) |
Natural Gas (Mcf/d) |
OilEquivalent (boe/d) |
|
Canada – Heavy |
|
|
|
|
|
|
|
|
|
|
|
|
Peace River |
10,918 |
9 |
14 |
13,295 |
13,157 |
|
9,853 |
7 |
12 |
11,630 |
11,810 |
|
Lloydminster |
10,807 |
8 |
— |
1,541 |
11,072 |
|
11,289 |
12 |
— |
1,346 |
11,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada - Light |
|
|
|
|
|
|
|
|
|
|
|
|
Viking |
— |
13,524 |
127 |
10,044 |
15,326 |
|
— |
17,658 |
113 |
11,058 |
19,614 |
|
Duvernay |
— |
1,138 |
572 |
1,929 |
2,031 |
|
— |
803 |
432 |
1,634 |
1,507 |
|
Remaining Properties |
— |
533 |
651 |
15,309 |
3,736 |
|
— |
623 |
668 |
17,131 |
4,147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
— |
14,356 |
5,131 |
33,999 |
25,154 |
|
— |
17,953 |
6,116 |
42,665 |
31,179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
21,725 |
29,568 |
6,495 |
76,116 |
70,475 |
|
21,142 |
37,056 |
7,340 |
85,463 |
79,781 |
This press release discloses per boe 30-day
initial production volumes for two wells drilled in the Pembina
Duvernay. The disaggregated 30-day initial production volumes for
the 10-16 well were 885 bbl/d Light and Medium Oil, 279 bbl/d NGL
and 750 Mcf/d Natural Gas and for the 11-16 well were 601 bbl/d
Light and Medium Oil, 195 bbl/d NGL and 522 Mcf/d Natural Gas.
This press release contains metrics commonly
used in the oil and natural gas industry, such as “finding and
development costs”, “finding, development and acquisition costs”,
“net asset value”, and “reserves life index.” These terms do not
have a standardized meaning and 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 in
this press release to provide readers with additional measures to
evaluate Baytex’s performance, however, such measures are not
reliable indicators of Baytex’s future performance and future
performance may not compare to Baytex’s performance in previous
periods and therefore such metrics should not be unduly relied
upon.
Finding and development costs are calculated on
a per boe basis by dividing the aggregate of the change in future
development costs from the prior year for the particular reserve
category and the costs incurred on exploration and development
activities in the year by the change in reserves from the prior
year for the reserve category.
Finding, development and acquisition costs are
calculated on a per boe basis by dividing the aggregate of the
change in future development costs from the prior year for the
particular reserve category and the costs incurred on development
and exploration activities and property acquisitions (net of
dispositions) in the year by the change in reserves from the year
for the reserve category
Net asset value has been calculated based on the
estimated net present value of all future net revenue from our
reserves, before income taxes, as estimated by McDaniel effective
December 31, 2020, plus the estimated value of our undeveloped land
holdings, less net debt.
Reserve life index means the reserves for the
particular reserve category divided by annualized 2020 fourth
quarter production.
Notice to United States Readers
The petroleum and natural gas reserves contained
in this press release have generally been prepared in accordance
with Canadian disclosure standards, which are not comparable in all
respects to United States or other foreign disclosure standards.
For example, the United States Securities and Exchange
Commission (the "SEC") requires oil and gas issuers, in their
filings with the SEC, to disclose only "proved reserves", but
permits the optional disclosure of "probable reserves" (each as
defined in SEC rules). Canadian securities laws require oil and gas
issuers disclose their reserves in accordance with NI 51-101, which
requires disclosure of not only "proved reserves" but also
"probable reserves". Additionally, NI 51-101 defines "proved
reserves" and "probable reserves" differently from the SEC rules.
Accordingly, proved and probable reserves disclosed in this press
release may not be comparable to United States standards. Probable
reserves are higher risk and are generally believed to be less
likely to be accurately estimated or recovered than proved
reserves.
In addition, under Canadian disclosure
requirements and industry practice, reserves and production are
reported using gross volumes, which are volumes prior to deduction
of royalty and similar payments. The SEC rules require
reserves and production to be presented using net volumes, after
deduction of applicable royalties and similar payments.
Moreover, Baytex has determined and disclosed
estimated future net revenue from its reserves using forecast
prices and costs, whereas the SEC rules require that reserves be
estimated using a 12-month average price, calculated as the
arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting
period. As a consequence of the foregoing, Baytex's reserve
estimates and production volumes in this press release may not be
comparable to those made by companies utilizing United States
reporting and disclosure standards.
Baytex Energy Corp.
Baytex Energy Corp. is an oil and gas
corporation based in Calgary, Alberta. The company is engaged in
the acquisition, development and production of crude oil and
natural gas in the Western Canadian Sedimentary Basin and in the
Eagle Ford in the United States. Approximately 81% of Baytex’s
production is weighted toward crude oil and natural gas liquids.
Baytex’s common shares trade on the Toronto Stock Exchange under
the symbol BTE.
For further information about Baytex, please
visit our website at www.baytexenergy.com or contact:
Brian Ector, Vice President, Capital
Markets
Toll Free Number: 1-800-524-5521Email:
investor@baytexenergy.com
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