Baytex Energy Corp. ("Baytex")(TSX: BTE) reports its operating and
financial results for the three and six months ended June 30, 2021
(all amounts are in Canadian dollars unless otherwise noted).
"During the second quarter, we delivered strong
operating results and substantial free cash flow. Our free cash
flow profile continues to improve resulting in accelerated debt
reduction. We are taking proactive measures to reduce our net debt
with the repurchase and cancellation of US$106 million of our
outstanding long-term notes due 2024 during and subsequent to the
quarter. At current commodity prices, we now expect to generate
over $350 million of free cash flow in 2021. In addition, we are
drilling our fourth follow up well as we continue to advance our
exciting, new, oil discovery in the Clearwater play in Peace
River," commented Ed LaFehr, President and Chief Executive
Officer.
Q2 2021 Highlights
- Generated production of 81,162
boe/d (81% oil and NGL), a 3% increase over Q1/2021.
- Delivered adjusted funds flow of
$176 million ($0.31 per basic share), a 12% increase compared
to $157 million ($0.28 per basic share) in Q1/2021.
- Generated free cash flow of $112
million ($0.20 per basic share).
- Realized an operating netback of
$33.92/boe, up from $29.80/boe in Q1/2021.
- Repurchased and cancelled US$5.8
million principal amount of 5.625% long-term notes. Subsequent to
quarter-end, repurchased and cancelled an additional US$100 million
principal amount of 5.625% long-term notes.
- Reduced net debt by $129 million
through a combination of free cash flow and the Canadian dollar
strengthening relative to the U.S. dollar.
2021 Outlook
As a result of our strong operating performance
through the first half of 2021, we are increasing our production
guidance to 79,000 to 80,000 boe/d, up from 77,000 to 79,000 boe/d,
previously. We continue to forecast 2021 exploration and
development expenditures of $285 to $315 million. Our free cash
flow profile continues to improve as we benefit from our
diversified oil weighted portfolio and our commitment to allocate
capital effectively. At current commodity prices, we now expect to
deliver over $350 million ($0.62 per basic share) of free cash flow
this year, which will accelerate 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 and returns based capital allocation philosophy.
We have updated year one of our five-year
outlook (2021) to reflect year-to-date commodity prices and the
forward strip for the balance of the year. The remaining years
(2022 to 2025) continue to be based on a constant US$55/bbl WTI
price. Under the plan, we expect to generate over $1 billion of
cumulative free cash flow as we target capital expenditures at less
than 70% of our adjusted funds flow, while optimizing production in
the 80,000 to 85,000 boe/d range. Under constant US$60/bbl and
$65/bbl WTI pricing scenarios, we expect to generate in excess of
$1.5 billion and $2.0 billion of cumulative free cash flow,
respectively.
Based on the strong pricing environment and free
cash flow forecast for 2021, we have accelerated our debt repayment
strategy by approximately one year over the base plan presented
last quarter. We now anticipate hitting our net debt target of $1.0
to $1.2 billion in 2023 at US$55/bbl. Throughout the plan period we
will continue to 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.
|
|
Three Months Ended |
Six Months Ended |
|
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
June 30, 2021 |
|
June 30, 2020 |
|
|
FINANCIAL (thousands of Canadian dollars, except
per common share amounts) |
|
|
|
|
|
|
Petroleum and natural gas sales |
$ |
442,354 |
|
$ |
384,702 |
|
$ |
152,689 |
|
$ |
827,056 |
|
$ |
489,303 |
|
| Adjusted funds
flow (1) |
175,883 |
|
156,582 |
|
17,887 |
|
332,465 |
|
150,822 |
|
|
Per share - basic |
0.31 |
|
0.28 |
|
0.03 |
|
0.59 |
|
0.27 |
|
|
Per share - diluted |
0.31 |
|
0.28 |
|
0.03 |
|
0.59 |
|
0.27 |
|
| Net income
(loss) |
1,052,999 |
|
(35,352 |
) |
(138,463 |
) |
1,017,647 |
|
(2,636,680 |
) |
|
Per share - basic |
1.87 |
|
(0.06 |
) |
(0.25 |
) |
1.81 |
|
(4.71 |
) |
|
Per share - diluted |
1.85 |
|
(0.06 |
) |
(0.25 |
) |
1.79 |
|
(4.71 |
) |
| |
|
|
|
|
|
| Capital
Expenditures |
|
|
|
|
|
|
Exploration and development expenditures (1) |
$ |
61,485 |
|
$ |
83,588 |
|
$ |
9,852 |
|
$ |
145,073 |
|
$ |
186,629 |
|
|
Acquisitions, net of divestitures |
(18 |
) |
(203 |
) |
(11 |
) |
(221 |
) |
(51 |
) |
|
Total oil and natural gas capital expenditures |
$ |
61,467 |
|
$ |
83,385 |
|
$ |
9,841 |
|
$ |
144,852 |
|
$ |
186,578 |
|
| |
|
|
|
|
|
| Net Debt |
|
|
|
|
|
|
Credit facilities (2) |
$ |
486,623 |
|
$ |
606,637 |
|
$ |
704,135 |
|
$ |
486,623 |
|
$ |
704,135 |
|
|
Long-term notes (2) |
1,109,211 |
|
1,131,480 |
|
1,225,395 |
|
1,109,211 |
|
1,225,395 |
|
|
Long-term debt |
1,595,834 |
|
1,738,117 |
|
1,929,530 |
|
1,595,834 |
|
1,929,530 |
|
|
Working capital deficiency |
33,795 |
|
20,777 |
|
65,423 |
|
33,795 |
|
65,423 |
|
|
Net debt (1) |
$ |
1,629,629 |
|
$ |
1,758,894 |
|
$ |
1,994,953 |
|
$ |
1,629,629 |
|
$ |
1,994,953 |
|
|
|
|
|
|
|
|
| Shares Outstanding -
basic (thousands) |
|
|
|
|
|
|
Weighted average |
564,156 |
|
562,085 |
|
560,512 |
|
563,126 |
|
560,158 |
|
|
End of period |
564,182 |
|
564,111 |
|
560,545 |
|
564,182 |
|
560,545 |
|
|
|
|
|
|
|
|
| BENCHMARK
PRICES |
|
|
|
|
|
| Crude
oil |
|
|
|
|
|
|
WTI (US$/bbl) |
$ |
66.07 |
|
$ |
57.84 |
|
$ |
27.85 |
|
$ |
61.96 |
|
$ |
37.01 |
|
|
MEH oil (US$/bbl) |
67.15 |
|
59.36 |
|
26.40 |
|
63.26 |
|
37.97 |
|
|
MEH oil differential to WTI (US$/bbl) |
1.08 |
|
1.52 |
|
(1.45 |
) |
1.30 |
|
0.96 |
|
|
Edmonton par ($/bbl) |
77.28 |
|
66.58 |
|
29.85 |
|
71.93 |
|
40.64 |
|
|
Edmonton par differential to WTI (US$/bbl) |
(3.13 |
) |
(5.27 |
) |
(6.31 |
) |
(4.28 |
) |
(7.24 |
) |
|
WCS heavy oil ($/bbl) |
67.03 |
|
57.46 |
|
22.70 |
|
62.33 |
|
28.68 |
|
|
WCS differential to WTI (US$/bbl) |
(11.48 |
) |
(12.46 |
) |
(11.47 |
) |
(11.98 |
) |
(16.00 |
) |
| Natural
gas |
|
|
|
|
|
|
NYMEX (US$/mmbtu) |
$ |
2.83 |
|
$ |
2.69 |
|
$ |
1.72 |
|
$ |
2.76 |
|
$ |
1.83 |
|
|
AECO ($/mcf) |
2.85 |
|
2.93 |
|
1.91 |
|
2.89 |
|
2.03 |
|
| |
|
|
|
|
|
|
CAD/USD average exchange rate |
1.2279 |
|
1.2663 |
|
1.3860 |
|
1.2471 |
|
1.3653 |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
June 30, 2021 |
|
March 31, 2021 |
|
June 30, 2020 |
|
June 30, 2021 |
|
June 30, 2020 |
|
|
OPERATING |
|
|
|
|
|
| Daily
Production |
|
|
|
|
|
|
Light oil and condensate (bbl/d) |
37,134 |
|
35,430 |
|
38,951 |
|
36,286 |
|
42,333 |
|
|
Heavy oil (bbl/d) |
21,269 |
|
21,989 |
|
11,832 |
|
21,627 |
|
20,343 |
|
|
NGL (bbl/d) |
7,563 |
|
6,238 |
|
7,634 |
|
6,904 |
|
7,728 |
|
|
Total liquids (bbl/d) |
65,966 |
|
63,657 |
|
58,417 |
|
64,817 |
|
70,404 |
|
|
Natural gas (mcf/d) |
91,172 |
|
90,739 |
|
84,546 |
|
90,957 |
|
90,451 |
|
|
Oil equivalent (boe/d @ 6:1) (3) |
81,162 |
|
78,780 |
|
72,508 |
|
79,978 |
|
85,479 |
|
|
|
|
|
|
|
|
| Netback
(thousands of Canadian dollars) |
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
422,387 |
|
$ |
367,582 |
|
$ |
147,229 |
|
$ |
789,969 |
|
$ |
462,486 |
|
|
Royalties |
(81,531 |
) |
(66,950 |
) |
(29,156 |
) |
(148,481 |
) |
(85,876 |
) |
|
Operating expense |
(82,901 |
) |
(80,548 |
) |
(73,680 |
) |
(163,449 |
) |
(178,150 |
) |
|
Transportation expense |
(7,486 |
) |
(8,788 |
) |
(5,031 |
) |
(16,274 |
) |
(15,373 |
) |
|
Operating netback (1) |
$ |
250,469 |
|
$ |
211,296 |
|
$ |
39,362 |
|
$ |
461,765 |
|
$ |
183,087 |
|
|
General and administrative |
(10,610 |
) |
(8,733 |
) |
(7,438 |
) |
(19,343 |
) |
(17,213 |
) |
|
Cash financing and interest |
(23,554 |
) |
(24,403 |
) |
(27,387 |
) |
(47,957 |
) |
(55,922 |
) |
|
Realized financial derivatives (loss) gain |
(39,024 |
) |
(20,768 |
) |
13,624 |
|
(59,792 |
) |
40,474 |
|
|
Other (5) |
(1,398 |
) |
(810 |
) |
(274 |
) |
(2,208 |
) |
396 |
|
|
Adjusted funds flow (1) |
$ |
175,883 |
|
$ |
156,582 |
|
$ |
17,887 |
|
$ |
332,465 |
|
$ |
150,822 |
|
|
|
|
|
|
|
|
| Netback (per
boe) |
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
57.19 |
|
$ |
51.84 |
|
$ |
22.31 |
|
$ |
54.57 |
|
$ |
29.73 |
|
|
Royalties |
(11.04 |
) |
(9.44 |
) |
(4.42 |
) |
(10.26 |
) |
(5.52 |
) |
|
Operating expense |
(11.22 |
) |
(11.36 |
) |
(11.17 |
) |
(11.29 |
) |
(11.45 |
) |
|
Transportation expense |
(1.01 |
) |
(1.24 |
) |
(0.76 |
) |
(1.12 |
) |
(0.99 |
) |
|
Operating netback (1) |
$ |
33.92 |
|
$ |
29.80 |
|
$ |
5.96 |
|
$ |
31.90 |
|
$ |
11.77 |
|
|
General and administrative |
(1.44 |
) |
(1.23 |
) |
(1.13 |
) |
(1.34 |
) |
(1.11 |
) |
|
Cash financing and interest |
(3.19 |
) |
(3.44 |
) |
(4.15 |
) |
(3.31 |
) |
(3.59 |
) |
|
Realized financial derivatives (loss) gain |
(5.28 |
) |
(2.93 |
) |
2.06 |
|
(4.13 |
) |
2.60 |
|
|
Other (5) |
(0.20 |
) |
(0.12 |
) |
(0.03 |
) |
(0.15 |
) |
0.02 |
|
|
Adjusted funds flow (1) |
$ |
23.81 |
|
$ |
22.08 |
|
$ |
2.71 |
|
$ |
22.97 |
|
$ |
9.69 |
|
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 share-based
compensation. Refer to the Q2/2021 MD&A for further information
on these amounts.
Q2/2021 Results
During Q2/2021, we delivered strong operating
and financial results as we executed on our plan to maximize free
cash flow and reduce debt. During the quarter, we delivered
adjusted funds flow of $176 million ($0.31 per basic share). This
resulted in substantial quarterly free cash flow of $112 million,
which along with the Canadian dollar strengthening relative to the
U.S. dollar, contributed to a $129 million reduction in our net
debt.
Production during the second quarter averaged
81,162 boe/d (81% oil and NGL), up 3% as compared to 78,780 boe/d
(81% oil and NGL) in Q1/2021. The increased production reflects the
timing of completion activity in the Eagle Ford and and strong
performance across our light and heavy oil assets in Canada.
Exploration and development expenditures totaled $61 million in
Q2/2021 that included the drilling of 34 (19.7 net) wells with a
100% success rate.
During Q2/2021, we reported net income of $1.1
billion ($1.85 per diluted share). At June 30, 2021, we identified
indicators of impairment reversal for our oil and gas properties
due to the increase in forecasted commodity prices. As a result, we
recorded an impairment reversal of $1.1 billion during the second
quarter as the estimated recoverable amounts exceeded the carrying
value of our oil and gas properties.
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 $350 million of free cash flow in 2021.
As a result of our strong operating performance
through the first half of 2021, we are increasing our production
guidance to 79,000 to 80,000 boe/d, up from 77,000 to 79,000 boe/d,
previously. We continue to forecast 2021 exploration and
development expenditures of $285 to $315 million.
Our interest expense guidance is 3% lower due to
reduced net debt and the repurchase and cancellation of US$106
million principal amount of 5.625% long-term notes.
The following table highlights our updated 2021
annual guidance.
|
|
2021 Guidance (2) |
2021 Revised Guidance |
|
Exploration and development expenditures |
$285 - $315 million |
no change |
| Production (boe/d) |
77,000 - 79,000 |
79,000 - 80,000 |
| |
|
|
| Expenses: |
|
|
|
Royalty rate |
18.0% - 18.5% |
no change |
|
Operating |
$11.25 - $12.00/boe |
no change |
|
Transportation |
$1.15 - $1.25/boe |
no change |
|
General and administrative |
$42 million ($1.48/boe) |
$42 million ($1.45/boe) |
|
Interest |
$98 million ($3.46/boe) |
$95 million ($3.27/boe) |
| |
|
|
| Leasing expenditures |
$4 million |
no change |
|
Asset retirement obligations |
$6 million |
no change |
Operating Results
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 33,957
boe/d (80% oil and NGL) during Q2/2021, as compared to 26,741 boe/d
in Q1/2021. The higher volumes reflect an increased pace of
completions and continued strong operating performance. During the
second quarter we commenced production from 38 (10.2 net) wells, up
from 24 (7.0 net) wells in Q1/2021. In Q2/2021, we invested $31
million on exploration and development in the Eagle Ford and
generated an operating netback of $112 million. We expect to
bring approximately 22 net wells on production in the Eagle Ford in
2021.
Notes:
(1) 2021 full-year pricing assumptions: WTI - US$64/bbl; WCS
differential - US$13/bbl; MSW differential – US$4/bbl, NYMEX Gas -
US$3.30/mcf; AECO Gas - $3.45/mcf and Exchange Rate (CAD/USD) -
1.26.(2) As announced on April 29, 2021.
Production in the Viking averaged 16,301 boe/d
(88% oil and NGL) during Q2/2021, as compared to 19,403 boe/d in
Q1/2021. Our capital program in the second quarter included the
seasonal slowdown, which resulted in the completion of 14 (14.0
net) wells, as compared to 44 (43.2 net) wells during the first
quarter. In Q2/2021, we invested $17 million on exploration and
development in the Viking and generated an operating netback of $72
million. We expect to bring approximately 120 net wells on
production in the Viking during 2021.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 23,304 boe/d (91% oil and NGL)
during the Q2/2021, as compared to 24,395 boe/d in Q1/2021. We
scheduled minimal heavy oil development for the first half of 2021.
Our heavy oil program kicked off in June with approximately 35 net
wells planned for the year, including up to seven net wells in our
Spirit River (Clearwater equivalent) play.
Peace River Clearwater
Across all of our core assets, inventory
enhancement continues to be a priority. We are also 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 covers 60 sections of land directly to the south of our
existing Seal operations. At the time, we identified significant
potential for this early stage exploratory play targeting the
Spirit River formation, a Clearwater formation equivalent.
Our appraisal program continues to yield
encouraging results and pending continued success, sets the stage
for a potential increase in activity in 2022. We plan to drill up
to seven net appraisal wells in 2021, of which five net appraisal
wells will occur on our Peavine lands. Across our acreage position
in northwest Alberta, we estimate that over 100 sections are
prospective for Clearwater development. The following table
summarizes our Peavine appraisal program for 2021.
|
Area |
Well |
Spud |
Rig Release |
# of Laterals |
30-Day Initial Production Rate (bbl/d) |
|
Peavine |
100/04-34-078-16W5 |
January 6 |
January 19 |
2 |
175 |
|
Peavine |
102/04-34-078-16W5 |
June 15 |
June 21 |
2 |
175 |
|
Peavine |
100/13-27-078-16W5 |
June 22 |
July 6 |
8 |
On Production July 10 |
|
Peavine |
100/05-34-078-16W5 |
July 8 |
July 18 |
8 |
On Production July 22 |
|
Peavine |
100/11-31-078-15W5 |
July 20 |
|
8 |
|
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged
1,698 boe/d (80% oil and NGL) during Q2/2021, as compared to 2,138
boe/d in Q1/2021. We now have nine producing wells in the Pembina
area and have significantly de-risked our approximately
38-kilometre long acreage fairway, where we hold 232 sections (100%
working interest) of Duvernay land. We expect to bring two
additional 100% working interest wells on production during the
third quarter.
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 June 30, 2021, we had $511 million of undrawn
capacity on our credit facilities, resulting in liquidity, net of
working capital, of $477 million.
Our net debt, which includes our credit
facilities, long-term notes and working capital, totaled $1.63
billion at June 30, 2021, down from $1.76 billion at March 31,
2021.
On May 4, 2021, we repurchased and cancelled
US$5.8 million principal amount of 5.625% long-term notes.
Subsequent to the quarter, we used free cash flow generated in the
first half of 2021 to repurchase and cancel US$100 million
principal amount of the 5.625% long-term notes at the call price of
100.938% plus accrued interest effective July 28, 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 the second half of 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 50% 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 swaptions at US$53.50/bbl and a 3-way option
structure that provides price protection at US$57.76/bbl with
upside participation to US$67.51/bbl. We also have WTI-MSW
differential hedges on approximately 13% of our expected net
Canadian light oil exposure at US$4.63/bbl and WCS differential
hedges on approximately 39% of our expected net heavy oil exposure
at a WTI-WCS differential of approximately US$12.53/bbl.
A complete listing of our financial derivative
contracts can be found in Note 16 to our Q2/2021 financial
statements.
Additional Information
Our condensed consolidated interim unaudited
financial statements for the three and six months ended June 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, July 29, 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/baytex20210729.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 over $350 million of free cash flow ($0.62 per basic
share) in 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 for that period, the cumulative free cash flow it will
generate at certain WTI oil prices and that we are targeting
capital expenditures at less than 70% of adjusted funds flow; we
anticipate hitting our debt target of $1.0 to $1.2 billion in 2023
at US$55 WTI; 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; 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 22 net
wells in the Eagle Ford and 120 in the Viking and plan to drill 35
net wells in Heavy Oil, including 6 in our Spirit River (Clearwater
equivalent); that we are committed to building and maintaining
respectful relationships with Indigenous communities and creating
opportunities for meaningful economic participation and inclusion;
the potential for increased activity in 2022 pending success in
Peace River Clearwater; our drilling plans for the Clearwater lands
for the remainder of 2021; that we have 100 sections of highly
prospective Clearwater lands; that we expect to bring two 100%
working Duvernay wells on Production in Q3/2021; and drill 2 net
wells in the Duvernay; and that we have de-risked our approximately
38-kilometer acreage fairway in the Pembina 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 H2/2021 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 six months ended
June 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 six months ended June 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 June 30, 2021 |
|
Six Months Ended June 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 |
11,293 |
7 |
25 |
10,722 |
13,112 |
|
11,729 |
7 |
25 |
11,697 |
13,711 |
|
Lloydminster |
9,976 |
5 |
— |
1,268 |
10,192 |
|
9,898 |
5 |
— |
1,398 |
10,136 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
Canada - Light |
|
|
|
|
|
|
|
|
|
|
|
|
Viking |
— |
14,284 |
140 |
11,262 |
16,301 |
|
— |
15,866 |
136 |
11,044 |
17,843 |
|
Duvernay |
— |
791 |
568 |
2,033 |
1,698 |
|
— |
969 |
612 |
2,015 |
1,917 |
|
Remaining Properties |
— |
574 |
1,046 |
25,689 |
5,902 |
|
— |
587 |
1,101 |
25,882 |
6,002 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
— |
21,473 |
5,784 |
40,198 |
33,957 |
|
— |
18,852 |
5,030 |
38,921 |
30,369 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
21,269 |
37,134 |
7,563 |
91,172 |
81,162 |
|
21,627 |
36,286 |
6,904 |
90,957 |
79,978 |
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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