Baytex Energy Corp. ("Baytex") (TSX: BTE) reports its operating and
financial results for the three and nine months ended September 30,
2021 (all amounts are in Canadian dollars unless otherwise noted).
“During the third quarter, we remain focused on
strong capital discipline, generating free cash flow and reducing
debt. We have already repurchased and cancelled US$200 million of
our 2024 bonds this year and at current commodity prices we now
expect to generate record levels of free cash flow in excess of
$400 million. Our operating results continue to build momentum as
we appraise and develop our Clearwater oil play at Peace River. We
have some of the best results in all of the Clearwater, and will
now drill four additional wells during the fourth quarter, which
will enable us to accelerate our development plans in 2022,”
commented Ed LaFehr, President and Chief Executive Officer.
Q3 2021 Highlights
- Generated production of 79,872
boe/d (82% oil and NGL) in Q3/2021 and 79,942 boe/d (81% oil and
NGL) for the first nine months of 2021.
- Delivered adjusted funds flow of
$198 million ($0.35 per basic share) in Q3/2021 and $531
million ($0.94 per basic share) for the first nine months of
2021.
- Generated free cash flow of $101
million ($0.18 per basic share) in Q3/2021 and $284 million ($0.50
per basic share) for the first nine months of 2021.
- Reduced net debt by $65 million
during the third quarter and by $283 million through the first nine
months of 2021.
- Subsequent to quarter-end,
repurchased and cancelled US$85 million principal amount of 5.625%
long-term notes, bringing the total repurchased and cancelled to
US$200 million (50% of the original principal amount
outstanding).
2021 Outlook
As a result of our strong operating performance
through the first nine months of 2021, we are tightening our
production guidance to 79,500 to 80,000 boe/d, up from 79,000 to
80,000 boe/d, previously.
We are intensely focused on maintaining capital
discipline. The Clearwater has emerged as one of the most
profitable plays in Canada and our 2021 appraisal program has
delivered exceptional results. As a result, we will drill four
additional Clearwater wells during the fourth quarter which are
expected to be on-stream in late 2021. Accordingly, we are
tightening our forecast 2021 exploration and development
expenditures range to $300 to $315 million, as compared to $285 to
$315 million, previously.
At current commodity prices, we expect to
deliver over $400 million ($0.71 per basic share) of free cash flow
this year, which has accelerated our debt reduction efforts.
Five-Year Outlook
Our five-year outlook (2021 to 2025) highlights
our financial and operational sustainability and meaningful free
cash flow generation. Through this plan period, we are committed to
a disciplined, returns based capital allocation philosophy. Under
constant US$65/bbl and US$75/bbl WTI pricing scenarios, we expect
to generate cumulative free cash flow of approximately $2.0 billion
and $2.6 billion, respectively.
Based on the strong pricing environment and
continued capital discipline, we now anticipate hitting our initial
net debt target of $1.2 billion during Q2/2022. Throughout the plan
period we will monitor our leverage position and assess market
conditions to determine the best methods or combination thereof to
enhance shareholder returns. These could include share buy-backs, a
dividend and/or reinvestment for organic growth.
Our 2022 capital budget is expected to be
released in early December following approval by our Board of
Directors. We will also update our five-year plan to include
drilling opportunities on our Clearwater lands.
|
Three Months Ended |
Nine Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
September 30, 2021 |
|
September 30, 2020 |
|
FINANCIAL (thousands of Canadian dollars, except
per common share amounts) |
|
|
|
|
|
Petroleum and natural gas sales |
$ |
488,736 |
|
$ |
442,354 |
|
$ |
252,538 |
|
$ |
1,315,792 |
|
$ |
741,841 |
|
Adjusted funds flow (1) |
198,397 |
|
175,883 |
|
78,508 |
|
530,862 |
|
229,330 |
|
Per share - basic |
0.35 |
|
0.31 |
|
0.14 |
|
0.94 |
|
0.41 |
|
Per share - diluted |
0.35 |
|
0.31 |
|
0.14 |
|
0.93 |
|
0.41 |
|
Net income (loss) |
32,713 |
|
1,052,999 |
|
(23,444 |
) |
1,050,361 |
|
(2,660,124 |
) |
Per share - basic |
0.06 |
|
1.87 |
|
(0.04 |
) |
1.86 |
|
(4.75 |
) |
Per share - diluted |
0.06 |
|
1.85 |
|
(0.04 |
) |
1.84 |
|
(4.75 |
) |
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
Exploration and development expenditures (1) |
$ |
94,235 |
|
$ |
61,485 |
|
$ |
15,902 |
|
$ |
239,308 |
|
$ |
202,531 |
|
Acquisitions, net of divestitures |
(612 |
) |
(18 |
) |
(98 |
) |
(833 |
) |
(149 |
) |
Total oil and natural gas capital expenditures |
$ |
93,623 |
|
$ |
61,467 |
|
$ |
15,804 |
|
$ |
238,475 |
|
$ |
202,382 |
|
|
|
|
|
|
|
Net Debt |
|
|
|
|
|
Credit facilities (2) |
$ |
546,803 |
|
$ |
486,623 |
|
$ |
624,826 |
|
$ |
546,803 |
|
$ |
624,826 |
|
Long-term notes (2) |
1,000,171 |
|
1,109,211 |
|
1,199,160 |
|
1,000,171 |
|
1,199,160 |
|
Long-term debt |
1,546,974 |
|
1,595,834 |
|
1,823,986 |
|
1,546,974 |
|
1,823,986 |
|
Working capital deficiency |
17,684 |
|
33,795 |
|
82,093 |
|
17,684 |
|
82,093 |
|
Net debt (1) |
$ |
1,564,658 |
|
$ |
1,629,629 |
|
$ |
1,906,079 |
|
$ |
1,564,658 |
|
$ |
1,906,079 |
|
|
|
|
|
|
|
Shares Outstanding - basic (thousands) |
|
|
|
|
|
Weighted average |
564,211 |
|
564,156 |
|
561,128 |
|
563,492 |
|
560,484 |
|
End of period |
564,213 |
|
564,182 |
|
561,163 |
|
564,213 |
|
561,163 |
|
|
|
|
|
|
|
BENCHMARK PRICES |
|
|
|
|
|
Crude oil |
|
|
|
|
|
WTI (US$/bbl) |
$ |
70.56 |
|
$ |
66.07 |
|
$ |
40.93 |
|
$ |
64.82 |
|
$ |
38.32 |
|
MEH oil (US$/bbl) |
71.64 |
|
67.15 |
|
41.63 |
|
66.05 |
|
39.19 |
|
MEH oil differential to WTI (US$/bbl) |
1.08 |
|
1.08 |
|
0.70 |
|
1.23 |
|
0.87 |
|
Edmonton par ($/bbl) |
83.78 |
|
77.28 |
|
49.83 |
|
75.88 |
|
43.70 |
|
Edmonton par differential to WTI (US$/bbl) |
(4.07 |
) |
(3.13 |
) |
(3.51 |
) |
(4.19 |
) |
(6.04 |
) |
WCS heavy oil ($/bbl) |
71.81 |
|
67.03 |
|
42.40 |
|
65.47 |
|
33.34 |
|
WCS differential to WTI (US$/bbl) |
(13.57 |
) |
(11.48 |
) |
(9.09 |
) |
(12.51 |
) |
(13.70 |
) |
Natural gas |
|
|
|
|
|
NYMEX (US$/mmbtu) |
$ |
4.01 |
|
$ |
2.83 |
|
$ |
1.98 |
|
$ |
3.18 |
|
$ |
1.88 |
|
AECO ($/mcf) |
3.54 |
|
2.85 |
|
2.18 |
|
3.11 |
|
2.08 |
|
|
|
|
|
|
|
CAD/USD average exchange rate |
1.2601 |
|
1.2279 |
|
1.3316 |
|
1.2515 |
|
1.3541 |
|
|
Three Months Ended |
Nine Months Ended |
|
September 30, 2021 |
|
June 30, 2021 |
|
September 30, 2020 |
|
September 30, 2021 |
|
|
September 30, 2020 |
|
OPERATING |
|
|
|
|
|
Daily
Production |
|
|
|
|
|
Light oil and condensate (bbl/d) |
35,614 |
|
37,134 |
|
34,101 |
|
36,060 |
|
|
39,570 |
|
Heavy oil (bbl/d) |
21,996 |
|
21,269 |
|
22,138 |
|
21,752 |
|
|
20,946 |
|
NGL (bbl/d) |
7,174 |
|
7,563 |
|
7,417 |
|
6,995 |
|
|
7,624 |
|
Total liquids (bbl/d) |
64,784 |
|
65,966 |
|
63,656 |
|
64,807 |
|
|
68,140 |
|
Natural gas (mcf/d) |
90,528 |
|
91,172 |
|
84,945 |
|
90,812 |
|
|
88,602 |
|
Oil equivalent (boe/d @ 6:1) (3) |
79,872 |
|
81,162 |
|
77,814 |
|
79,942 |
|
|
82,907 |
|
|
|
|
|
|
|
Netback
(thousands of Canadian dollars) |
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
469,155 |
|
$ |
422,387 |
|
$ |
241,865 |
|
$ |
1,259,124 |
|
|
$ |
704,351 |
|
Royalties |
(90,523 |
) |
(81,531 |
) |
(40,052 |
) |
(239,004 |
) |
|
(125,928 |
) |
Operating expense |
(84,196 |
) |
(82,901 |
) |
(73,447 |
) |
(247,645 |
) |
|
(251,597 |
) |
Transportation expense |
(7,818 |
) |
(7,486 |
) |
(6,372 |
) |
(24,092 |
) |
|
(21,745 |
) |
Operating netback (1) |
$ |
286,618 |
|
$ |
250,469 |
|
$ |
121,994 |
|
$ |
748,383 |
|
|
$ |
305,081 |
|
General and administrative |
(9,980 |
) |
(10,610 |
) |
(7,741 |
) |
(29,323 |
) |
|
(24,954 |
) |
Cash financing and interest |
(22,793 |
) |
(23,554 |
) |
(25,418 |
) |
(70,750 |
) |
|
(81,340 |
) |
Realized financial derivatives (loss) gain |
(53,905 |
) |
(39,024 |
) |
(9,743 |
) |
(113,697 |
) |
|
30,731 |
|
Other (5) |
(1,543 |
) |
(1,398 |
) |
(584 |
) |
(3,751 |
) |
|
(188 |
) |
Adjusted funds flow (1) |
$ |
198,397 |
|
$ |
175,883 |
|
$ |
78,508 |
|
$ |
530,862 |
|
|
$ |
229,330 |
|
|
|
|
|
|
|
Netback (per
boe) |
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
63.85 |
|
$ |
57.19 |
|
$ |
33.79 |
|
$ |
57.69 |
|
|
$ |
31.01 |
|
Royalties |
(12.32 |
) |
(11.04 |
) |
(5.59 |
) |
(10.95 |
) |
|
(5.54 |
) |
Operating expense |
(11.46 |
) |
(11.22 |
) |
(10.26 |
) |
(11.35 |
) |
|
(11.08 |
) |
Transportation expense |
(1.06 |
) |
(1.01 |
) |
(0.89 |
) |
(1.10 |
) |
|
(0.96 |
) |
Operating netback (1) |
$ |
39.01 |
|
$ |
33.92 |
|
$ |
17.05 |
|
$ |
34.29 |
|
|
$ |
13.43 |
|
General and administrative |
(1.36 |
) |
(1.44 |
) |
(1.08 |
) |
(1.34 |
) |
|
(1.10 |
) |
Cash financing and interest |
(3.10 |
) |
(3.19 |
) |
(3.55 |
) |
(3.24 |
) |
|
(3.58 |
) |
Realized financial derivatives (loss) gain |
(7.34 |
) |
(5.28 |
) |
(1.36 |
) |
(5.21 |
) |
|
1.35 |
|
Other (5) |
(0.21 |
) |
(0.20 |
) |
(0.09 |
) |
(0.18 |
) |
|
— |
|
Adjusted funds flow (1) |
$ |
27.00 |
|
$ |
23.81 |
|
$ |
10.97 |
|
$ |
24.32 |
|
|
$ |
10.10 |
|
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) Principal amount of instruments. The carrying amount of
debt issue costs associated with the credit facilities and
long-term notes are excluded on the basis that these amounts have
been paid by Baytex and do not represent an additional source of
capital or repayment obligations.(3) 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. (4) 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.(5) Other is
comprised of realized foreign exchange gain or loss, other income
or expense, current income tax expense or recovery and cash
share-based compensation. Refer to the Q3/2021 MD&A for further
information on these amounts.
Q3/2021 Results
During Q3/2021, we delivered strong operating
and financial results and continued to advance our exciting new
Clearwater play in northwest Alberta with the two strongest initial
rate wells drilled to date in the play.
During the quarter, we delivered adjusted funds
flow of $198 million ($0.35 per basic share) and net income of $33
million ($0.06 per basic share). We generated free cash flow of
$101 million ($0.18 per basic share), which brings our year-to-date
free cash flow to $284 million ($0.50 per basic share). We have
directed 100% of our free cash flow this year to reduce our net
debt, which now sits at $1.56 billion, down from $1.85 billion at
the beginning of the year.
Production during the third quarter averaged
79,872 boe/d (82% oil and NGL), as compared to 81,162 boe/d (81%
oil and NGL) in Q2/2021. Our operating results reflect strong
performance across our light and heavy oil assets in Canada with
volumes up 2% over the second quarter, while Eagle Ford volumes
were lower due to the number of wells brought on-stream.
Exploration and development expenditures totaled $94 million in
Q3/2021 that included the drilling of 57 (46.7 net) wells with a
100% success rate.
2021 Guidance
In 2021, we are benefiting from our diversified
oil weighted portfolio and our commitment to allocate capital
effectively. Based on the forward strip(1), we expect to generate
over $400 million of free cash flow in 2021.
We are intensely focused on maintaining capital
discipline. The Clearwater has emerged as one of the most
profitable plays in Canada and our 2021 appraisal program has
delivered production results beyond our initial expectations. As a
result, we have committed to drill four additional Clearwater wells
during the fourth quarter with the wells expected to be on-stream
in late 2021. Accordingly, we are tightening our forecast 2021
exploration and development expenditures range to $300 to $315
million, as compared to $285 to $315 million, previously.
As a result of our continued strong operating
performance through the first nine months of 2021, we are also
tightening our production guidance range to 79,500 to 80,000 boe/d,
up from 79,000 to 80,000 boe/d, previously.
We have also fine-tuned several of our cost
assumptions. Our interest expense guidance is 3% lower due to
reduced net debt and the repurchase and cancellation of a portion
of the 5.625% long-term notes due 2024.
The following table highlights our updated 2021
annual guidance.
|
2021 Guidance (2) |
2021 Revised Guidance |
Exploration and development expenditures |
$285 - $315 million |
$300 - $315 million |
Production (boe/d) |
79,000 - 80,000 |
79,500 - 80,000 |
|
|
|
Expenses: |
|
|
Royalty rate |
18.0% - 18.5% |
18.5% - 19.0% |
Operating |
$11.25 - $12.00/boe |
$11.25 - $11.75/boe |
Transportation |
$1.15 - $1.25/boe |
$1.10 - $1.15/boe |
General and administrative |
$42 million ($1.45/boe) |
$42 million ($1.44/boe) |
Interest |
$95 million ($3.27/boe) |
$92 million ($3.16/boe) |
|
|
|
Leasing expenditures |
$4 million |
no change |
Asset retirement obligations |
$6 million |
no change |
Notes:
(1) 2021 full-year pricing assumptions: WTI - US$68/bbl; WCS
differential - US$12/bbl; MSW differential – US$4/bbl, NYMEX Gas -
US$3.85/mcf; AECO Gas - $3.50/mcf and Exchange Rate (CAD/USD) -
1.25.(2) As announced on July 28, 2021.
Operating Results
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 31,748
boe/d (79% oil and NGL) during Q3/2021, as compared to 33,957 boe/d
in Q2/2021. The lower volumes reflect level of completion activity
during the quarter. We commenced production from 17 (3.4 net) wells
during the third quarter, as compared to 62 (17.2 net) wells in the
first half of 2021. In Q3/2021, we invested $19 million on
exploration and development in the Eagle Ford and generated an
operating netback of $117 million. We expect to bring
approximately 23 net wells on production in the Eagle Ford in
2021.
Production in the Viking averaged 17,132 boe/d
(90% oil and NGL) during Q3/2021, as compared to 16,301 boe/d in
Q2/2021. We maintained an active pace of development during the
third quarter with 23.0 net wells drilled and 37.0 net wells
brought on production. In Q3/2021, we invested $29 million on
exploration and development and generated an operating netback of
$88 million. We expect to bring approximately 115 net wells on
production in the Viking during 2021.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster (excluding our Clearwater development) produced a
combined 22,577 boe/d (91% oil and NGL) during the Q3/2021, as
compared to 23,304 boe/d in Q2/2021. After a quiet first half of
the year, our heavy oil program kicked off during the third quarter
and included drilling 2 net Bluesky wells at Peace River and 14 net
wells at Lloydminster. In Q3/2021, we invested $18 million on
exploration and development in Peace River and Lloydminster and
generated an operating netback of $60 million.
Peace River Clearwater
We are committed to building and maintaining
respectful relationships with Indigenous communities and creating
opportunities for meaningful economic participation and inclusion.
In early 2020, we executed a strategic agreement with the Peavine
Métis Settlement in the Peace River area that covered 60 sections
of land directly to the south of our existing Seal operations. At
the time, we identified significant potential for an early stage
exploratory play targeting the Spirit River formation, a Clearwater
formation equivalent. In August 2021, we executed a second
strategic agreement with the Peavine Métis Settlement that covers
an additional 20 sections, bringing our total Peavine acreage to 80
contiguous sections. When combined with our legacy acreage position
in northwest Alberta, we estimate that over 120 sections are
prospective for Clearwater development.
Production in the Clearwater averaged 1,540
bbl/d during Q3/2021. We currently have five producing wells on our
Peavine acreage and production has increased from zero at the
beginning of this year to approximately 1,900 bbl/d, currently. Our
three eight-lateral wells continue to outperform type curve
assumptions and two of our wells rank as the top initial rate wells
drilled to-date across the play.
The following table summarizes the results of
our 2021 appraisal program.
Area |
Well |
Spud |
Rig Release |
# of Laterals |
30-Day Initial Production Rate
(bbl/d) (1) |
Current Production Rate (bbl/d) |
Peavine |
100/04-34-078-16W5 |
January 7 |
January 15 |
2 |
175 |
100 |
Peavine |
102/04-34-078-16W5 |
June 15 |
June 21 |
2 |
175 |
170 |
Peavine |
100/13-27-078-16W5 |
June 22 |
July 6 |
8 |
695 |
700 |
Peavine |
100/05-34-078-16W5 |
July 8 |
July 18 |
8 |
412 |
300 |
Peavine |
102/11-31-078-15W5 |
July 20 |
August 4 |
8 |
930 |
645 |
(1) 30-Day Initial Production Rate (bbl/d) is
defined as the average oil rate over the first 720 hours of
production following drilling fluid recovery.
As we continue to progress our development plan,
we have committed to drill four additional Clearwater wells during
the fourth quarter. In addition, as part of our 2022 plan, which is
to be confirmed and released in early December 2021, we are working
with the Peavine Métis Settlement and are preparing to execute an
expanded program of up to 18 wells. To-date, we have de-risked 20
sections of land and pending further success, the play holds the
potential for greater than 200 locations. At current commodity
prices, the Clearwater generates among the strongest economics
within our portfolio with payouts of less than six months and has
the ability to grow organically while enhancing our free cash flow
profile.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged
1,528 boe/d (79% oil and NGL) during Q3/2021, as compared to 1,698
boe/d in Q2/2021. During the third quarter, we drilled two 100%
working interest wells and initial flow back rates are very
encouraging. The first well (7-8) was brought on-stream October 18
and is currently producing 1,010 boe/d (756 bbl/d oil, 162 bbl/d
NGLs and 0.6 mmcf/d of natural gas). The second well (6-8) was
brought on-stream October 30 and is currently producing 1,500 boe/d
(1,270 bbl/d oil, 147 bbl/d NGLs and 0.5 mmcf/d of natural gas). We
now have eleven producing wells in the Pembina area and have
significantly de-risked our approximately 38-kilometre long acreage
fairway, where we hold approximately 200 sections (100% working
interest) of Duvernay land.
Financial Liquidity
Our credit facilities total approximately $1.0
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 September 30, 2021, we had $471 million of
undrawn capacity on our credit facilities, resulting in liquidity,
net of working capital, of $454 million.
Our net debt, which includes our credit
facilities, long-term notes and working capital, totaled $1.56
billion at September 30, 2021, down from $1.63 billion at June 30,
2021.
During 2021, we have repurchased and cancelled
US$200 million of the 5.625% long term notes due June 2024. This
represents 50% of the original US$400 million outstanding and
includes US$84.5 million repurchased and cancelled subsequent to
quarter end.
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 Q4/2021, we have entered into hedges on
approximately 45% 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 net
Canadian light oil exposure at US$5.03/bbl and WCS differential
hedges on approximately 45% of our net expected heavy oil exposure
at a WTI-WCS differential of approximately US$13.23/bbl.
For 2022, we have entered into hedges on
approximately 42% of our net crude oil exposure utilizing a
combination of a 3-way option structure that provides price
protection at US$57.76/bbl with upside participation to
US$67.51/bbl and swaptions at US$53.50/bbl. We also have WTI-MSW
differential hedges on approximately 25% of our expected net
Canadian light oil exposure at US$4.43/bbl and WCS differential
hedges on approximately 70% of our expected net heavy oil exposure
at a WTI-WCS differential of approximately US$12.28/bbl.
A complete listing of our financial derivative
contracts can be found in Note 16 to our Q3/2021 financial
statements.
Additional Information
Our condensed consolidated interim unaudited
financial statements for the three and nine months ended September
30, 2021 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. MDT
(11:00 a.m. EDT) |
Baytex will host a conference call tomorrow, November 5, 2021,
starting at 9:00am MDT (11:00am EDT). 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/baytex20211105.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 expect to
generate in excess of $400 million of free cash flow in 2021; our
plan to drill and bring on-stream four additional wells in the
Clearwater in Q4/2021; that our debt reduction will accelerate; our
five-year outlook: including that it demonstrates financial and
operational sustainability, meaningful free cash flow generation
and that we are committed to disciplined and returns based
philosophy , the cumulative free cash flow it will generate at
certain WTI oil prices and that we anticipate hitting our debt
target of $1.2 billion by mid-2022; that we will monitor our
leverage position and market conditions to enhance shareholder
returns which could be share buy-backs, a dividend or reinvestment
for organic growth; that we expect to release our 2022 budget in
early December 2021 with an updated five-year plan; we expect to
benefit from our diversified oil weighted portfolio and our
commitment to allocate capital effectively; our updated 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; in 2021 that we expect to: bring on production 23 net
wells in the Eagle Ford and 115 in the Viking; that we are
committed to building and maintaining respectful relationships with
Indigenous communities and creating opportunities for meaningful
economic participation and inclusion; that we have 120 sections of
prospective Clearwater lands; that we are preparing to drill up to
18 Clearwater wells in 2022 and believe the play holds the
potential for greater than 200 locations; that the Clearwater
generates among the strongest economics in our portfolio with
payouts of less than six months and has the ability to grow
organically while enhancing our free cash flow profile; that we
have de-risked our approximately 38-kilometer acreage fairway in
the Duvernay; that we use financial derivative contracts and
crude-by-rail to reduce adjusted funds flow volatility; the
percentage of our net exposure to crude oil, the MTI-MSW
differential and WCS differential that we have hedged for Q4/2021
and 2022.
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, filed with Canadian securities regulatory authorities and
the U.S. Securities and Exchange Commission 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 news 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 three and nine months ended
September 30, 2021.
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
Where applicable, 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.
References herein to average 30-day initial
production rates and other short-term production rates are useful
in confirming the presence of hydrocarbons, however, such rates are
not determinative of the rates at which such wells will commence
production and decline thereafter and are not indicative of long
term performance or of ultimate recovery. While encouraging,
readers are cautioned not to place reliance on such rates in
calculating aggregate production for us or the assets for which
such rates are provided. A pressure transient analysis or well-test
interpretation has not been carried out in respect of all wells.
Accordingly, we caution that the test results should be considered
to be preliminary.
Throughout this news 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 nine months ended September
30, 2021. 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 September 30, 2021 |
|
Nine Months Ended September 30, 2021 |
|
Heavy Oil
(bbl/d) |
Light and Medium
Oil (bbl/d) |
NGL (bbl/d) |
Natural Gas
(Mcf/d) |
Oil Equivalent
(boe/d) |
|
Heavy Oil
(bbl/d) |
Light and Medium
Oil (bbl/d) |
NGL (bbl/d) |
Natural Gas
(Mcf/d) |
Oil Equivalent
(boe/d) |
Canada – Heavy |
|
|
|
|
|
|
|
|
|
|
|
Peace River |
10,020 |
7 |
21 |
11,220 |
11,918 |
|
11,099 |
8 |
22 |
11,536 |
13,052 |
Lloydminster |
10,436 |
3 |
— |
1,319 |
10,659 |
|
10,079 |
4 |
— |
1,371 |
10,312 |
Peavine |
1,540 |
— |
— |
— |
1,540 |
|
574 |
— |
— |
— |
574 |
|
|
|
|
|
|
|
|
|
|
|
|
Canada - Light |
|
|
|
|
|
|
|
|
|
|
|
Viking |
— |
15,193 |
145 |
10,762 |
17,132 |
|
— |
15,639 |
140 |
10,949 |
17,603 |
Duvernay |
— |
774 |
436 |
1,908 |
1,528 |
|
— |
903 |
553 |
1,979 |
1,786 |
Remaining Properties |
— |
555 |
628 |
24,988 |
5,347 |
|
— |
576 |
942 |
25,581 |
5,781 |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
— |
19,082 |
5,944 |
40,331 |
31,748 |
|
— |
18,930 |
5,338 |
39,396 |
30,834 |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
21,996 |
35,614 |
7,174 |
90,528 |
79,872 |
|
21,752 |
36,060 |
6,995 |
90,812 |
79,942 |
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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