Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its
operating and financial results for the three months and year ended
December 31, 2019 (all amounts are in Canadian dollars unless
otherwise noted).
“2019 was an exceptional year with $1 billion
EBITDA, $329 million of free cash flow and a 17% reduction in net
debt. During the first quarter of 2020, we enhanced our long-term
note maturity schedule and extended the term of our revolving
credit facilities to 2024. Our operations continue to perform well
with strong capital efficiencies in each of our core properties
(Eagle Ford, Viking and Heavy Oil). Together, these measures give
us confidence and significant flexibility to execute our business
plan to continue driving free cash flow and strengthening our
balance sheet,” commented Ed LaFehr, President and Chief Executive
Officer.
2019 Highlights
We released preliminary unaudited financial and
operating results on January 20, 2020 in conjunction with the
release of our 2019 reserves. Our audited financial and operating
results for the three months and year ended December 31, 2019 are
unchanged from the preliminary results.
- Generated production of 96,360
boe/d (83% oil and NGL) during Q4/2019 and 97,680 boe/d for
full-year 2019, exceeding the high end of guidance.
- Exploration and development
expenditures totaled $153 million in Q4/2019, bringing aggregate
spending for 2019 to $552 million, which is at the low end of our
original guidance.
- Delivered adjusted funds flow of
$232 million ($0.42 per basic share) in Q4/2019 and $902 million
($1.62 per basic share) for 2019.
- Generated EBITDA of $256 million in
Q4/2019 and $1.01 billion for 2019.
- Reduced net debt by $100 million in
Q4/2019 and by $393 million in 2019 with free cash flow along with
a strengthening of the Canadian dollar relative to the U.S. dollar.
Net debt totaled $1.87 billion at December 31, 2019.
- Achieved a strong year of reserves
development with proved developed producing reserves increasing 5%
with finding & development costs of $13.04/boe and a recycle
ratio of 2.3x.
Bond Refinancing and Bank Credit
Extension
- On February 6, 2020, we issued
US$500 million principal amount of 8.75% senior unsecured notes due
April 1, 2027. Net proceeds have been used to redeem US$400 million
principal amount of 5.125% senior unsecured notes due 2021. We also
called for redemption $300 million principal amount of 6.625%
senior unsecured notes due 2022 on March 6, 2020.
- On March 3, 2020, we extended the
maturity of our revolving credit facilities and term loan to April
2, 2024 (from June 4, 2021). The credit facilities total
approximately $1,046 million and do not require annual or
semi-annual reviews.
2020 Outlook
Our 2020 guidance remains unchanged as we target
production of 93,000 to 97,000 boe/d with exploration and
development expenditures of $500 to $575 million. Our exploration
and development program is expected to be fully funded from
adjusted funds flow at the forward strip(1) and we have the
operational flexibility to adjust our spending plans based on
changes in commodity prices. For 2020, we have entered into hedges
on approximately 48% of our net crude oil exposure, largely
utilizing a 3-way option structure that provides WTI price
protection at US$58.04/bbl.
(1) 2020 full-year pricing assumptions:
WTI - US$48.64/bbl; LLS - US$51.39/bbl; WCS differential -
US$16.15/bbl; MSW differential – US$5.51/bbl, NYMEX Gas -
US$1.97/mcf; AECO Gas - $1.79/mcf and Exchange Rate (CAD/USD) -
1.336.
|
|
Three Months Ended |
Years Ended |
|
|
|
December 31,2019 |
September 30,2019 |
|
December 31,2018 |
December 31,2019 |
December 31,2018 |
|
|
FINANCIAL (thousands of Canadian dollars,
except per common share amounts) |
|
|
|
|
|
|
|
Petroleum and natural gas sales |
$ |
445,895 |
|
$ |
424,600 |
|
$ |
358,437 |
|
$ |
1,805,919 |
|
$ |
1,428,870 |
|
|
Adjusted funds flow (1) |
232,147 |
|
213,379 |
|
110,828 |
|
902,426 |
|
472,983 |
|
|
Per share - basic |
0.42 |
|
0.38 |
|
0.20 |
|
1.62 |
|
1.35 |
|
|
Per share - diluted |
0.42 |
|
0.38 |
|
0.20 |
|
1.62 |
|
1.35 |
|
|
Net income (loss) |
(117,772 |
) |
15,151 |
|
(231,238 |
) |
(12,459 |
) |
(325,309 |
) |
|
Per share - basic |
(0.21 |
) |
0.03 |
|
(0.42 |
) |
(0.02 |
) |
(0.93 |
) |
|
Per share - diluted |
(0.21 |
) |
0.03 |
|
(0.42 |
) |
(0.02 |
) |
(0.93 |
) |
| |
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
|
Exploration and development expenditures (1) |
$ |
153,117 |
|
$ |
139,085 |
|
$ |
184,162 |
|
$ |
552,291 |
|
$ |
495,721 |
|
|
Acquisitions, net of divestitures |
563 |
|
(30 |
) |
229 |
|
2,180 |
|
1,603,850 |
|
|
Total oil and natural gas capital expenditures |
$ |
153,680 |
|
$ |
139,055 |
|
$ |
184,391 |
|
$ |
554,471 |
|
$ |
2,099,571 |
|
| |
|
|
|
|
|
|
|
Net Debt |
|
|
|
|
|
|
|
Bank loan (2) |
$ |
506,471 |
|
$ |
570,792 |
|
$ |
522,294 |
|
$ |
506,471 |
|
$ |
522,294 |
|
|
Long-term notes (2) |
1,337,200 |
|
1,359,480 |
|
1,596,323 |
|
1,337,200 |
|
1,596,323 |
|
|
Long-term debt |
1,843,671 |
|
1,930,272 |
|
2,118,617 |
|
1,843,671 |
|
2,118,617 |
|
|
Working capital deficiency |
28,120 |
|
41,067 |
|
146,550 |
|
28,120 |
|
146,550 |
|
|
Net debt (1) |
$ |
1,871,791 |
|
$ |
1,971,339 |
|
$ |
2,265,167 |
|
$ |
1,871,791 |
|
$ |
2,265,167 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Outstanding - basic (thousands) |
|
|
|
|
|
|
|
Weighted average |
558,228 |
|
557,888 |
|
554,036 |
|
557,048 |
|
351,542 |
|
|
End of period |
558,305 |
|
557,972 |
|
554,060 |
|
558,305 |
|
554,060 |
|
|
BENCHMARK PRICES |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US$/bbl) |
$ |
56.96 |
|
$ |
56.45 |
|
$ |
58.81 |
|
$ |
57.03 |
|
$ |
64.77 |
|
|
LLS (US$/bbl) |
60.73 |
|
61.88 |
|
66.64 |
|
62.84 |
|
|
70.09 |
|
|
LLS differential to WTI (US$/bbl) |
3.77 |
|
5.43 |
|
7.83 |
|
5.81 |
|
|
5.32 |
|
|
Edmonton par ($/bbl) |
68.10 |
|
68.41 |
|
42.68 |
|
69.22 |
|
|
69.31 |
|
|
Edmonton par differential to WTI (US$/bbl) |
(5.37 |
) |
(4.66 |
) |
(26.51 |
) |
(4.86 |
) |
|
(11.30 |
) |
|
WCS heavy oil ($/bbl) |
54.29 |
|
58.39 |
|
25.62 |
|
58.75 |
|
|
49.85 |
|
|
WCS differential to WTI (US$/bbl) |
(15.83 |
) |
(12.24 |
) |
(39.42 |
) |
(12.75 |
) |
|
(26.31 |
) |
|
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX (US$/mmbtu) |
$ |
2.50 |
|
$ |
2.23 |
|
$ |
3.64 |
|
$ |
2.63 |
|
$ |
3.09 |
|
|
AECO ($/mcf) |
2.34 |
|
1.04 |
|
1.94 |
|
1.62 |
|
|
1.54 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAD/USD average exchange rate |
1.3201 |
|
1.3207 |
|
1.3215 |
|
1.3269 |
|
|
1.2962 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
Three Months Ended |
Years Ended |
|
|
|
December 31,2019 |
|
September 30,2019 |
|
December 31,2018 |
|
December 31,2019 |
|
December 31,2018 |
|
|
OPERATING |
|
|
|
|
|
|
|
Daily Production |
|
|
|
|
|
|
|
Light oil and condensate (bbl/d) |
43,906 |
42,829 |
|
44,987 |
|
43,587 |
|
29,264 |
|
|
Heavy oil (bbl/d) |
27,050 |
25,712 |
|
26,339 |
|
26,741 |
|
25,954 |
|
|
NGL (bbl/d) |
8,699 |
9,543 |
|
10,327 |
|
10,229 |
|
9,745 |
|
|
Total liquids (bbl/d) |
79,655 |
78,084 |
|
81,653 |
|
80,557 |
|
64,963 |
|
|
Natural gas (mcf/d) |
100,235 |
101,054 |
|
103,424 |
|
102,742 |
|
92,971 |
|
|
Oil equivalent (boe/d @ 6:1) (3) |
96,360 |
94,927 |
|
98,890 |
|
97,680 |
|
80,458 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netback (thousands of Canadian dollars) |
|
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
427,728 |
|
$ |
411,650 |
|
$ |
344,682 |
|
$ |
1,737,124 |
|
$ |
1,360,038 |
|
|
Royalties |
(77,282 |
) |
(75,017 |
) |
(79,765 |
) |
(320,241 |
) |
(313,754 |
) |
|
Operating expense |
(99,573 |
) |
(97,377 |
) |
(97,857 |
) |
(397,716 |
) |
(311,592 |
) |
|
Transportation expense |
(8,840 |
) |
(9,903 |
) |
(10,994 |
) |
(43,942 |
) |
(36,869 |
) |
|
Operating netback (1) |
$ |
242,033 |
|
$ |
229,353 |
|
$ |
156,066 |
|
$ |
975,225 |
|
$ |
697,823 |
|
|
General and administrative |
(9,893 |
) |
(9,934 |
) |
(14,096 |
) |
(45,469 |
) |
(45,825 |
) |
|
Cash financing and interest |
(24,389 |
) |
(26,752 |
) |
(27,933 |
) |
(107,417 |
) |
(104,318 |
) |
|
Realized financial derivatives gain (loss) |
22,956 |
|
20,857 |
|
(3,063 |
) |
75,620 |
|
(73,165 |
) |
|
Other (5) |
1,440 |
|
(145 |
) |
(146 |
) |
4,467 |
|
(1,532 |
) |
|
Adjusted funds flow (1) |
$ |
232,147 |
|
$ |
213,379 |
|
$ |
110,828 |
|
$ |
902,426 |
|
$ |
472,983 |
|
| |
|
|
|
|
|
|
|
Netback (per boe) |
|
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
48.25 |
|
$ |
47.14 |
|
$ |
37.89 |
|
$ |
48.72 |
|
$ |
46.31 |
|
|
Royalties |
(8.72 |
) |
(8.59 |
) |
(8.77 |
) |
(8.98 |
) |
(10.68 |
) |
|
Operating expense |
(11.23 |
) |
(11.15 |
) |
(10.76 |
) |
(11.16 |
) |
(10.61 |
) |
|
Transportation expense |
(1.00 |
) |
(1.13 |
) |
(1.21 |
) |
(1.23 |
) |
(1.26 |
) |
|
Operating netback (1) |
$ |
27.30 |
|
$ |
26.27 |
|
$ |
17.15 |
|
$ |
27.35 |
|
$ |
23.76 |
|
|
General and administrative |
(1.12 |
) |
(1.14 |
) |
(1.55 |
) |
(1.28 |
) |
(1.56 |
) |
|
Cash financing and interest |
(2.75 |
) |
(3.06 |
) |
(3.07 |
) |
(3.01 |
) |
(3.55 |
) |
|
Realized financial derivatives gain (loss) |
2.59 |
|
2.39 |
|
(0.34 |
) |
2.12 |
|
(2.49 |
) |
|
Other (5) |
0.16 |
|
(0.03 |
) |
(0.02 |
) |
0.13 |
|
(0.05 |
) |
|
Adjusted funds flow (1) |
$ |
26.18 |
|
$ |
24.43 |
|
$ |
12.17 |
|
$ |
25.31 |
|
$ |
16.11 |
|
Notes:
- 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.
- Principal amount of instruments.
The carrying amount of debt issue costs associated with the bank
loan 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.
- 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.
- 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.
- Other is comprised of realized
foreign exchange gain or loss, other income or expense, current
income tax expense or recovery and payments on onerous contracts.
Refer to the 2019 MD&A for further information on these
amounts.
Operating Results
Our 2019 operating and financial results
demonstrate the benefits of our diversified oil weighted portfolio
and our commitment to allocate capital effectively, generate free
cash flow and further strengthen our balance sheet.
Our production exceeded the high end of our
annual guidance with outstanding capital efficiencies in our
development program and each of our core properties (Eagle Ford,
Viking and Heavy Oil) generated an operating netback in excess of
exploration and development expenditures. We also achieved a strong
year of reserves development with proved developed producing
reserves increasing 5% with finding & development costs of
$13.04/boe and a recycle ratio of 2.3x.
Production during the fourth quarter averaged
96,360 boe/d (83% oil and NGL), as compared to 94,927 boe/d (82%
oil and NGL) in Q3/2019. Production in 2019 averaged 97,680 boe/d
as compared to 80,458 boe/d in 2018. Exploration and development
expenditures totaled $153 million in Q4/2019 and $552 million for
full-year 2019. We participated in the completion of 417 (313.9
net) wells with a 99% success rate during the year.
The following table compares our 2019 results to
our 2019 original budget guidance.
|
|
2019 Original Guidance (1) |
|
2019 Results |
|
Exploration and development expenditures |
$550 - $650 million |
|
$552.3 million |
| Production (boe/d) |
93,000 - 97,000 |
|
97,680 |
| |
|
|
|
| Expenses: |
|
|
|
| Royalty rate |
20.0% |
|
18.4% |
| Operating |
$10.75 - $11.25/boe |
|
$11.16/boe |
| Transportation |
$1.25 - $1.35/boe |
|
$1.23/boe |
| General and
administrative |
~ $46 million ($1.30/boe) |
|
$45.5 million ($1.28/boe) |
| Interest |
~ $112 million ($3.23/boe) |
|
$107.4 million ($3.01/boe) |
| |
|
|
|
| Leasing expenditures |
$5 million |
|
$6 million |
| Asset
retirement obligations |
$17 million |
|
$15 million |
Note:
- As announced on December 17, 2018.
Includes updated guidance on May 2, 2019 for general and
administrative expenses and leasing expenditures to reflect a
change associated with the adoption of IFRS 16.
Eagle Ford and Viking Light Oil
Production in the Eagle Ford averaged 38,567
boe/d (78% oil and NGL) during Q4/2019, as compared to 36,793 boe/d
in Q3/2019. Production for 2019 averaged 39,055 boe/d, as compared
to 37,076 boe/d in 2018. In 2019, we invested $178 million on
exploration and development in the Eagle Ford and generated an
operating netback of $416 million.
In the Eagle Ford, we continued to see strong
well performance driven by enhanced completions across our acreage
position. In 2019, we participated in the drilling of 96 (20.2 net)
wells and commenced production from 109 (25.1 net) wells. The wells
brought on-stream during 2019 generated an average 30-day initial
production rate of approximately 1,900 boe/d per well, which
represents an approximate 8% improvement over wells brought
on-stream in 2018.
Production in the Viking averaged 22,050 boe/d
(91% oil and NGL) during Q4/2019, as compared to 22,198 boe/d in
Q3/2019. Production for the full-year 2019 averaged 22,546 boe/d.
In 2019, we invested $266 million on exploration and development in
the Viking and generated an operating netback of $349 million.
In the Viking, we maintained an active pace of
development in 2019, drilling 275 (243.6 net) wells and commencing
production from 271 (239.7 net) wells. In 2019, over 90% of our
drilling program was extended reach horizontal wells. We also added
229 net high quality drilling opportunities through multiple deals
and asset swaps.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 29,707 boe/d (91% oil and NGL)
during the fourth quarter, as compared to 28,483 boe/d in Q3/2019.
We drilled 40 (40.0 net) heavy oil wells in 2019, including 34 net
wells at Lloydminster and six net wells at Peace River. In 2019, we
invested $80 million on exploration and development on our heavy
oil assets and generated an operating netback of $188 million.
East Duvernay Shale Light Oil
We continue to advance the delineation of the
East Duvernay Shale, an early stage, high operating netback light
oil resource play. As of December 31, 2019, we have drilled seven
wells at Pembina, confirming the prospectivity of our acreage. Two
wells brought on-stream in 2019 generated an average 30-day initial
production rate of approximately 1,050 boe/d per well (75% oil and
NGL) and are in the top 15% of all wells drilled to date in the
play.
In Q1/2020, we drilled two wells at Pembina and
completion activities are scheduled for Q2/2020. The success of our
drilling program in the Pembina area has significantly de-risked
our approximately 38 kilometer long acreage fairway, where we hold
275 sections (100% working interest) of Duvernay land.
Financial Review
We delivered adjusted funds flow of $232 million
($0.42 per basic share) in Q4/2019 and $902 million ($1.62 per
basic share) in 2019. This resulted in free cash flow of $73
million in Q4/2019 and $329 million in 2019. This strong free cash
flow, along with the Canadian dollar strengthening relative to the
U.S. dollar, contributed to a 17% reduction in our net debt this
year.
We recorded a net loss of $118 million ($0.21
per basic share) in Q4/2019 and $12 million ($0.02 per basic share)
in 2019. The net loss is attributable to a non-cash impairment
charge of $188 million on our heavy oil assets and reflects lower
heavy oil prices and a change in development plan for our thermal
projects at Peace River.
We realized an operating netback of $27.30/boe
in Q4/2019, as compared to $26.27/boe in Q3/2019 and $17.15/boe in
Q4/2018. Including financial derivatives, our operating netback
improved to $29.89/boe, as compared to $16.81/boe in Q4/2018. Our
Canadian operations generated an operating netback of $24.72/boe
during Q4/2019 while our Eagle Ford asset generated an operating
netback of $31.17/boe.
The following table summarizes our operating
netbacks for the periods noted.
| |
Three Months Ended December 31 |
|
|
2019 |
2018 |
|
($ per boe except for production) |
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
Canada |
|
|
U.S. |
|
|
Total |
|
|
Production (boe/d) |
57,794 |
|
38,566 |
|
96,360 |
|
60,453 |
|
38,437 |
|
98,890 |
|
| |
|
|
|
|
|
|
|
Total sales, net of blending and other (1) |
$ |
45.52 |
|
$ |
52.33 |
|
$ |
48.25 |
|
$ |
24.04 |
|
$ |
59.66 |
|
$ |
37,89 |
|
|
Royalties |
(4.73 |
) |
(14.69 |
) |
(8.72 |
) |
(3.10 |
) |
(17.68 |
) |
(8.77 |
) |
|
Operating expense |
(14.41 |
) |
(6.47 |
) |
(11.23 |
) |
(13.42 |
) |
(6.56 |
) |
(10.76 |
) |
|
Transportation expense |
(1.66 |
) |
— |
|
(1.00 |
) |
(1.98 |
) |
— |
|
(1.21 |
) |
|
Operating netback (2) |
$ |
24.72 |
|
$ |
31.17 |
|
$ |
27.30 |
|
$ |
5.54 |
|
$ |
35.42 |
|
$ |
17.15 |
|
|
Realized financial derivatives gain (loss) |
— |
|
— |
|
2.59 |
|
— |
|
— |
|
(0.34 |
) |
|
Operating netback after financial derivatives |
$ |
24.72 |
|
$ |
31.17 |
|
$ |
29.89 |
|
$ |
5.54 |
|
$ |
35.42 |
|
$ |
16.81 |
|
Notes:
- 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.
- The term “operating netback” does 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.
Balance Sheet and Liquidity
In 2019, we set a priority to further deleverage
and strengthen our balance sheet. We delivered on this commitment
as highlighted by the following key milestones:
- We generated free cash flow of $73 million in Q4/2019 and $329
million in 2019.
- We reduced net debt by $100 million in Q4/2019 and by $393
million in 2019 due to the strong free cash flow and a
strengthening of the Canadian dollar relative to the U.S.
dollar.
- We completed the early redemption of US$150 million principal
amount of 6.75% senior unsecured notes due February 17, 2021
at par on September 13, 2019.
Subsequent to year-end, we further improved our
financial position:
- We enhanced our long-term note maturity schedule which provides
us significant flexibility and liquidity to execute our business
plan.
- On February 5, 2020, we issued US$500 million principal amount
of 8.75% senior unsecured notes, which mature on April 1, 2027.
These notes are redeemable at our option, in whole or in part, at
specified redemption prices after April 1, 2023.
- On February 20, 2020, we redeemed US$400 million principal
amount of 5.125% senior unsecured notes due June 1, 2021
at par.
- We issued a redemption notice for $300 million principal amount
of 6.625% senior unsecured notes due July 19, 2022 for
redemption on March 6, 2020 at 101.104% of the principal
amount.
- Following these redemptions, our next long-term note maturity
will be June 2024.
- We amended our credit facilities to extend the maturities of
our revolving facilities and term loan to April 2, 2024. The credit
facilities are not borrowing base facilities and do not require
annual or semi-annual reviews. Our facilities total approximately
$1,046 million and include US$575 million of revolving credit
facilities and a $300 million term loan.
Our net debt, which includes our bank loan,
long-term notes and working capital, totaled $1,872 million at
December 31, 2019, down 17% from $2,265 million at December
31, 2018. Following the US$500 million note issue and the
redemption of the US$400 million and $300 million notes, our credit
facilities are approximately one-third undrawn, we retain over $300
million of liquidity and the weighted average interest rate on our
long-term debt is approximately
6%.
Risk Management
To manage commodity price movements we utilize
various financial derivative contracts and crude-by-rail to reduce
the volatility in our adjusted funds flow. We realized a
financial derivatives gain of $76 million in 2019, as compared to a
loss of $73 million in 2018.
For 2020, we have entered into hedges on
approximately 48% of our net crude oil exposure, largely utilizing
a 3-way option structure on 24,500 bbl/d that provides WTI price
protection at US$58.04/bbl with upside participation to
US$63.06/bbl. The 3-way contracts are structured as follows:
|
WTI |
Baytex Receives (1) |
| At or below US$50.44/bbl |
WTI + US$7.60/bbl |
| Between US$50.44/bbl and
US$58.04/bbl |
US$58.04/bbl |
| Between US$58.04/bbl and
US$63.06/bbl |
WTI |
| Above
US$63.06/bbl |
US$63.06/bbl |
Note:
- The price Baytex receives
represents an average of all contracts entered into.
In addition to the 3-way options, we have
WTI-based fixed price swaps on 3,500 bbl/d at US$57.40/bbl for
2020. We also have WTI-MSW basis differential swaps for 4,250
bbl/d of our light oil production in Canada at US$6.19/bbl.
Crude-by-rail is an integral part of our egress
and marketing strategy for our heavy oil production. For 2020, we
are contracted to deliver approximately 11,500 bbl/d of our heavy
oil volumes to market by rail. In addition, we have WCS
differential hedges on 5,500 bbl/d at a WTI-WCS differential of
US$16.25/bbl.
A complete listing of our financial derivative
contracts can be found in Note 20 to our 2019 financial
statements.
2020 Outlook
We have a high quality and diversified oil
portfolio with a strong drilling inventory of approximately 10 or
more years in each of our core areas (Viking, Eagle Ford and Heavy
Oil). Our commitment remains to deliver stable production, generate
free cash flow and further strengthen our balance sheet.
Our 2020 annual guidance remains unchanged as we
target production of 93,000 to 97,000 boe/d with exploration and
development expenditures of $500 to $575 million. For Q1/2020,
production is trending above 97,000 boe/d with exploration and
development expenditures of approximately $200 million, consistent
with our plan and capital guidance range.
Our exploration and development program is
expected to be fully funded from adjusted funds flow at the forward
strip(1) and we have the operational flexibility to adjust our
spending plans based on changes in commodity prices.
(1) 2020 full-year
pricing assumptions: WTI - US$48.64/bbl; LLS - US$51.39/bbl; WCS
differential - US$16.15/bbl; MSW differential – US$5.51/bbl, NYMEX
Gas - US$1.97/mcf; AECO Gas - $1.79/mcf and Exchange Rate (CAD/USD)
- 1.336.
The following table summarizes our 2020 annual
guidance.
|
Exploration and development expenditures |
$500 - $575 million |
|
Production (boe/d) |
93,000 to 97,000 |
|
|
|
|
Expenses: |
|
|
Royalty rate |
18.0% - 18.5% |
|
Operating |
$11.25 - $12.00/boe |
|
Transportation |
$1.20 - $1.30/boe |
|
General and administrative |
$45 million ($1.30/boe) |
|
Interest |
$112 million ($3.23/boe) |
|
|
|
|
Leasing expenditures |
$7 million |
|
Asset retirement obligations |
$19 million |
Board Appointment
The Board of Directors is pleased to announce
the appointment of Don Hrap as a director of Baytex.
“We are very pleased that Don has joined the
Baytex board. His business knowledge, strategic perspective and
tremendous breadth of experience across U.S. and Canadian energy
will serve the board and Baytex well in the years ahead,” commented
Mark Bly, Chairman of Baytex.
Mr. Hrap has spent 35 years in the upstream oil
and gas business, primarily holding executive positions in North
America. From 2009-2018, he served as President, Lower 48 at
ConocoPhillips with strong breadth and depth of experience across
several U.S. oil resource plays. Prior to this at ConocoPhillips,
Mr. Hrap was senior vice president of Western Canada Gas. He joined
ConocoPhillips in 2006 through the merger with Burlington
Resources, serving as senior vice president of operations for
Burlington Canada. Earlier, he was vice president for the North
American Division at Gulf Canada Resources, where he worked for 17
years. Mr. Hrap previously served as chairman of the API Upstream
Committee, a Board member of the Independent Petroleum Association
of America (IPAA) and a member of the U.S. Oil & Gas
Association. He is also a Director of Tall City III Exploration LLC
and WildFire Energy I LLC, and also serves as an Industry Advisor
to Warburg Pincus. Mr. Hrap graduated from the University of
Manitoba with a Bachelor of Science in Mechanical Engineering in
1982. In 1995, he graduated from the University of Calgary with a
Master in Business Administration.
Baytex has an ongoing board renewal process led
by its Nominating and Governance Committee. In the last year, we
have significantly restructured our board. Throughout this renewal
process, our intent has been to create an efficient board with
complementary skill sets suited to our business, ensure
independence and increase diversity.
|
|
Conference Call Today9:00 a.m. MST (11:00
a.m. EST) |
|
|
|
Baytex will host a conference call today, March 4, 2020, 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/baytexq4ye20200304.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. |
|
Additional Information
Our audited consolidated financial statements
for the year ended December 31, 2019 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.
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 "anticipate", "believe",
"continue", "could", "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 have flexibility
to execute our business plan driving free cash flow and
strengthening our balance sheet; our 2020 production and capital
expenditure guidance; that our exploration and development program
is expended to be fully funded by adjusted funds flow at a WTI
price US$50/bbl; the percentage of our net crude oil exposure that
is hedged for 2020; that we continue to advance the delineation of
East Duvernay shale; our plan to complete two wells at Pembina in
Q2/2020; that we have de-risked our 38 kilometer acreage fairway in
Pembina; that our long-term note maturity schedule provides us
significant flexibility and liquidity to execute our business plan;
that after completing the announced redemption of long-term notes
our credit facilities will be one-third undrawn, we will have over
$300 million of liquidity and the weighted average cost of our debt
will be approximately 6%; that we have a strong drilling inventory
of approximately 10 or more years in each core area (Viking, Eagle
Ford and Heavy Oil); we are committed to stable production,
generating free cash flow and strengthening our balance sheet; our
expected Q1/2020 production volumes and exploration and development
expenditures; that we remain well positioned to generate free cash
flow in 2020; our guidance for 2020 exploration and
development expenditures, production, royalty rate, operating,
transportation, general and administration and interest expense and
leasing expenditures and asset retirement obligations.
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; availability and cost of
gathering, processing and pipeline systems; failure to comply with
the covenants in our debt agreements; the availability and cost of
capital or borrowing; that our credit facilities may not provide
sufficient liquidity or may not be renewed; risks associated with a
third-party operating our Eagle Ford properties; the cost of
developing and operating our assets; depletion of our reserves;
risks associated with the exploitation of our properties and our
ability to acquire reserves; 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; public perception and
its influence on the regulatory regime; restrictions or costs
imposed by climate change initiatives; variations in interest rates
and foreign exchange rates; risks associated with our hedging
activities; 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 associated with
acquiring, developing and exploring for oil and natural gas and
other aspects of our operations; risks associated with large
projects; 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; 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, 2019, to be filed with Canadian securities regulatory
authorities and the U.S. Securities and Exchange Commission not
later than March 31, 2020 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, EBITDA,
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, EBITDA,
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,
2019.
EBITDA is not a measurement based on GAAP in
Canada. EBITDA is defined as net income or loss adjusted for
financing and interest expenses, unrealized gains and losses on
financial derivatives, income tax, non-recurring losses, payments
on lease obligations, certain specific unrealized and non-cash
transactions (including depletion, exploration and evaluation
expenses, unrealized gains and losses on financial derivatives and
foreign exchange and share-based compensation).
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 bank loan. 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 bank loan
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 bank loan 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 National Instrument
51-101 "Standards of Disclosure for Oil and Gas Activities" of the
Canadian Securities Administrators ("NI 51-101"). Complete NI
51-101 reserves disclosure will be included in our Annual
Information Form for the year ended December 31, 2019, which will
be filed on or before March 31, 2020. Listed below are
cautionary statements that are specifically required by NI
51-101:
- 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.
- 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.
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 year ended December 31, 2019. 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.
|
|
|
HeavyOil(bbl/d) |
|
LightandMediumOil(bbl/d) |
|
NGL(bbl/d) |
|
NaturalGas(Mcf/d) |
|
OilEquivalent(boe/d) |
|
Canada - Heavy |
|
|
|
|
|
|
|
|
|
|
|
Peace River |
|
14,334 |
|
14 |
|
45 |
|
14,503 |
|
16,810 |
|
Lloydminster |
|
12,407 |
|
— |
|
— |
|
964 |
|
12,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada - Light |
|
|
|
|
|
|
|
|
|
|
|
Viking |
|
— |
|
20,527 |
|
125 |
|
11,361 |
|
22,546 |
|
Duvernay |
|
— |
|
928 |
|
491 |
|
1,613 |
|
1,688 |
|
Remaining properties |
|
— |
|
889 |
|
703 |
|
20,528 |
|
5,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
|
— |
|
21,229 |
|
8,865 |
|
53,773 |
|
39,055 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
26,741 |
|
43,587 |
|
10,229 |
|
102,742 |
|
97,680 |
Capital efficiency means the cost to drill,
complete, equip and tie-in a well divided by the initial production
rate of the well on a boe basis over its initial 365 days of
production.
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.
Recycle ratio means operating netback divided by
finding and development costs for the particular reserves
category.
This press release discloses drilling inventory.
Drilling inventory refers to Baytex’s total proved, probable and
unbooked locations. Proved locations and probable locations account
for drilling locations in our inventory that have associated proved
and/or probable reserves. Unbooked locations are internal estimates
based on our prospective acreage and an assumption as to the number
of wells that can be drilled per section based on industry practice
and internal review. Unbooked locations do not have attributed
reserves. Unbooked locations are farther away from existing wells
and, therefore, there is more uncertainty whether wells will be
drilled in such locations and if drilled there is more uncertainty
whether such wells will result in additional oil and gas reserves,
resources or production. In the Eagle Ford, Baytex’s net drilling
locations include 140 proved and 83 probable locations as at
December 31, 2019 and 52 unbooked locations. In the Viking,
Baytex’s net drilling locations include 1,080 proved and 319
probable locations as at December 31, 2019 and 636 unbooked
locations. In Peace River, Baytex’s net drilling locations include
77 proved and 75 probable locations as at December 31, 2019 and 100
unbooked locations. In Lloydminster, Baytex’s net drilling
locations include 178 proved and 63 probable locations as at
December 31, 2019 and 361 unbooked locations. In the Duvernay,
Baytex’s net drilling locations include 11 proved and 10 probable
locations as at December 31, 2019 and 295 unbooked locations.
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.
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 83% of Baytex’s
production is weighted toward crude oil and natural gas liquids.
Baytex’s common shares trade on the Toronto Stock Exchange and the
New York 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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