Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its
operating and financial results for the three and six months ended
June 30, 2020 (all amounts are in Canadian dollars unless otherwise
noted).
“During the second quarter we took decisive
steps to adjust our business model in the face of extremely
volatile crude oil markets. We are now starting to benefit from the
actions we have taken as we generated positive free cash flow
during the quarter and maintained approximately $300 million of
financial liquidity. We restarted approximately 80% of the
previously announced shut-in volumes, which we expect will
positively impact our adjusted funds flow for the remainder of the
year,” commented Ed LaFehr, President and Chief Executive
Officer.
Q2 2020 Highlights
- Generated production of 72,508
boe/d (81% oil and NGL), consistent with our previously announced
guidance range for the second quarter of 72,000 to 73,000
boe/d.
- Delivered adjusted funds flow of
$18 million ($0.03 per basic share).
- Realized an operating netback
(inclusive of realized financial derivatives gain) of
$8.02/boe.
- Reduced net debt by $57 million as
the Canadian dollar strengthened relative to the U.S. dollar and we
generated positive free cash flow of $6 million.
- Maintained undrawn credit capacity
of $363 million and liquidity, net of working capital, of
approximately $300 million.
- Achieved a 15% reduction in our GHG
emissions intensity in 2019 and remain committed to our 30% target
by the end of 2021.
2020 Outlook
We continue to forecast annual capital spending
of $260 to $290 million, an approximate 50% reduction from our
original plan of $500 to $575 million. With this revised
capital program, we suspended drilling operations in Canada and
moderated the pace of activity in the Eagle Ford.
We previously announced voluntary production
shut-ins of approximately 25,000 boe/d. These volumes remained
off-line for April and May. As operating netbacks improved in June,
we initiated plans to bring approximately 80% of these volumes back
on-line. At current commodity prices, the resumption of production
from these previously shut-in barrels is expected to have a
positive impact on our adjusted funds flow and improve our
financial liquidity. For the second half of 2020, we currently
project about 5,000 boe/d of heavy oil production to remain
shut-in.
On June 25, we revised our production guidance
range for 2020 to 78,000 to 82,000 boe/d, from 70,000 to 74,000
boe/d previously, taking into account the production brought back
on-line. Should operating netbacks change, we have the ability to
shut-in additional volumes or restart wells in short order.
We remain intensely focused on driving further
efficiencies to capture or sustain cost reductions identified
during this downturn, while protecting the health and safety of our
personnel.
| |
Three Months Ended |
Six Months Ended |
|
|
June 30,2020 |
|
March 31,2020 |
|
June 30,2019 |
|
June 30,2020 |
|
June 30,2019 |
|
|
FINANCIAL (thousands of Canadian dollars,
except per common share amounts) |
|
|
|
|
|
|
Petroleum and natural gas sales |
$ |
152,689 |
|
|
$ |
336,614 |
|
|
$ |
482,000 |
|
|
$ |
489,303 |
|
|
$ |
935,424 |
|
|
| Adjusted funds
flow (1) |
17,887 |
|
|
132,935 |
|
|
236,130 |
|
|
150,822 |
|
|
456,900 |
|
|
|
Per share - basic |
0.03 |
|
|
0.24 |
|
|
0.42 |
|
|
0.27 |
|
|
0.82 |
|
|
|
Per share - diluted |
0.03 |
|
|
0.24 |
|
|
0.42 |
|
|
0.27 |
|
|
0.82 |
|
|
| Net income
(loss) |
(138,463 |
) |
|
(2,498,217 |
) |
|
78,826 |
|
|
(2,636,680 |
) |
|
90,162 |
|
|
|
Per share - basic |
(0.25 |
) |
|
(4.46 |
) |
|
0.14 |
|
|
(4.71 |
) |
|
0.16 |
|
|
|
Per share - diluted |
(0.25 |
) |
|
(4.46 |
) |
|
0.14 |
|
|
(4.71 |
) |
|
0.16 |
|
|
| |
|
|
|
|
|
| Capital
Expenditures |
|
|
|
|
|
| Exploration and development
expenditures (1) |
$ |
9,852 |
|
|
$ |
176,777 |
|
|
$ |
106,246 |
|
|
$ |
186,629 |
|
|
$ |
260,089 |
|
|
|
Acquisitions, net of divestitures |
(11 |
) |
|
(40 |
) |
|
1,647 |
|
|
(51 |
) |
|
1,647 |
|
|
|
Total oil and natural gas capital expenditures |
$ |
9,841 |
|
|
$ |
176,737 |
|
|
$ |
107,893 |
|
|
$ |
186,578 |
|
|
$ |
261,736 |
|
|
| |
|
|
|
|
|
| Net Debt |
|
|
|
|
|
| Bank loan (2) |
$ |
704,135 |
|
|
$ |
678,740 |
|
|
$ |
414,691 |
|
|
$ |
704,135 |
|
|
$ |
414,691 |
|
|
| Long-term notes (2) |
1,225,395 |
|
|
1,270,800 |
|
|
1,543,645 |
|
|
1,225,395 |
|
|
1,543,645 |
|
|
|
Long-term debt |
1,929,530 |
|
|
1,949,540 |
|
|
1,958,336 |
|
|
1,929,530 |
|
|
1,958,336 |
|
|
|
Working capital deficiency |
65,423 |
|
|
102,077 |
|
|
70,350 |
|
|
65,423 |
|
|
70,350 |
|
|
|
Net debt (1) |
$ |
1,994,953 |
|
|
$ |
2,051,617 |
|
|
$ |
2,028,686 |
|
|
$ |
1,994,953 |
|
|
$ |
2,028,686 |
|
|
|
|
|
|
|
|
|
| Shares Outstanding -
basic (thousands) |
|
|
|
|
|
|
Weighted average |
560,512 |
|
|
559,804 |
|
|
556,599 |
|
|
560,158 |
|
|
556,022 |
|
|
|
End of period |
560,545 |
|
|
560,483 |
|
|
556,798 |
|
|
560,545 |
|
|
556,798 |
|
|
|
|
|
|
|
|
|
| BENCHMARK
PRICES |
|
|
|
|
|
| Crude
oil |
|
|
|
|
|
|
WTI (US$/bbl) |
$ |
27.85 |
|
|
$ |
46.17 |
|
|
$ |
59.81 |
|
|
$ |
37.01 |
|
|
$ |
57.36 |
|
|
|
MEH oil (US$/bbl) |
26.40 |
|
|
49.54 |
|
|
66.37 |
|
|
37.97 |
|
|
63.42 |
|
|
|
MEH oil differential to WTI (US$/bbl) |
(1.45 |
) |
|
3.37 |
|
|
6.56 |
|
|
0.96 |
|
|
6.06 |
|
|
|
Edmonton par ($/bbl) |
29.85 |
|
|
51.43 |
|
|
73.84 |
|
|
40.64 |
|
|
70.19 |
|
|
|
Edmonton par differential to WTI (US$/bbl) |
(6.31 |
) |
|
(7.92 |
) |
|
(4.61 |
) |
|
(7.24 |
) |
|
(4.72 |
) |
|
|
WCS heavy oil ($/bbl) |
22.70 |
|
|
34.48 |
|
|
65.73 |
|
|
28.68 |
|
|
61.17 |
|
|
|
WCS differential to WTI (US$/bbl) |
(11.47 |
) |
|
(20.53 |
) |
|
(10.68 |
) |
|
(16.00 |
) |
|
(11.48 |
) |
|
| Natural
gas |
|
|
|
|
|
|
NYMEX (US$/mmbtu) |
$ |
1.72 |
|
|
$ |
1.95 |
|
|
$ |
2.64 |
|
|
$ |
1.83 |
|
|
$ |
2.89 |
|
|
|
AECO ($/mcf) |
1.91 |
|
|
2.14 |
|
|
1.17 |
|
|
2.03 |
|
|
1.56 |
|
|
| |
|
|
|
|
|
|
CAD/USD average exchange rate |
1.3860 |
|
|
1.3445 |
|
|
1.3376 |
|
|
1.3653 |
|
|
1.3334 |
|
|
| |
Three Months Ended |
Six Months Ended |
|
|
June 30,2020 |
|
March 31,2020 |
|
June 30,2019 |
|
June 30,2020 |
|
June 30,2019 |
|
|
OPERATING |
|
|
|
|
|
| Daily
Production |
|
|
|
|
|
|
Light oil and condensate (bbl/d) |
38,951 |
|
|
45,717 |
|
|
42,585 |
|
|
42,333 |
|
|
43,809 |
|
|
|
Heavy oil (bbl/d) |
11,832 |
|
|
28,854 |
|
|
27,320 |
|
|
20,343 |
|
|
27,107 |
|
|
|
NGL (bbl/d) |
7,634 |
|
|
7,822 |
|
|
10,986 |
|
|
7,728 |
|
|
11,356 |
|
|
|
Total liquids (bbl/d) |
58,417 |
|
|
82,393 |
|
|
80,891 |
|
|
70,404 |
|
|
82,272 |
|
|
|
Natural gas (mcf/d) |
84,546 |
|
|
96,356 |
|
|
105,065 |
|
|
90,451 |
|
|
104,874 |
|
|
|
Oil equivalent (boe/d @ 6:1) (3) |
72,508 |
|
|
98,452 |
|
|
98,402 |
|
|
85,479 |
|
|
99,751 |
|
|
|
|
|
|
|
|
|
| Netback
(thousands of Canadian dollars) |
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
147,229 |
|
|
$ |
315,257 |
|
|
$ |
461,110 |
|
|
$ |
462,486 |
|
|
$ |
897,746 |
|
|
|
Royalties |
(29,156 |
) |
|
(56,720 |
) |
|
(86,617 |
) |
|
(85,876 |
) |
|
(167,942 |
) |
|
|
Operating expense |
(73,680 |
) |
|
(104,470 |
) |
|
(100,474 |
) |
|
(178,150 |
) |
|
(200,766 |
) |
|
|
Transportation expense |
(5,031 |
) |
|
(10,342 |
) |
|
(11,869 |
) |
|
(15,373 |
) |
|
(25,199 |
) |
|
|
Operating netback (1) |
$ |
39,362 |
|
|
$ |
143,725 |
|
|
$ |
262,150 |
|
|
$ |
183,087 |
|
|
$ |
503,839 |
|
|
|
General and administrative |
(7,438 |
) |
|
(9,775 |
) |
|
(11,506 |
) |
|
(17,213 |
) |
|
(25,642 |
) |
|
|
Cash financing and interest |
(27,387 |
) |
|
(28,535 |
) |
|
(28,092 |
) |
|
(55,922 |
) |
|
(56,276 |
) |
|
|
Realized financial derivatives gain |
13,624 |
|
|
26,850 |
|
|
12,993 |
|
|
40,474 |
|
|
31,807 |
|
|
|
Other (5) |
(274 |
) |
|
670 |
|
|
585 |
|
|
396 |
|
|
3,172 |
|
|
|
Adjusted funds flow (1) |
$ |
17,887 |
|
|
$ |
132,935 |
|
|
$ |
236,130 |
|
|
$ |
150,822 |
|
|
$ |
456,900 |
|
|
|
|
|
|
|
|
|
| Netback (per
boe) |
|
|
|
|
|
|
Total sales, net of blending and other expense (4) |
$ |
22.31 |
|
|
$ |
35.19 |
|
|
$ |
51.49 |
|
|
$ |
29.73 |
|
|
$ |
49.72 |
|
|
|
Royalties |
(4.42 |
) |
|
(6.33 |
) |
|
(9.67 |
) |
|
(5.52 |
) |
|
(9.30 |
) |
|
|
Operating expense |
(11.17 |
) |
|
(11.66 |
) |
|
(11.22 |
) |
|
(11.45 |
) |
|
(11.12 |
) |
|
|
Transportation expense |
(0.76 |
) |
|
(1.15 |
) |
|
(1.33 |
) |
|
(0.99 |
) |
|
(1.40 |
) |
|
|
Operating netback (1) |
$ |
5.96 |
|
|
$ |
16.05 |
|
|
$ |
29.27 |
|
|
$ |
11.77 |
|
|
$ |
27.90 |
|
|
|
General and administrative |
(1.13 |
) |
|
(1.09 |
) |
|
(1.28 |
) |
|
(1.11 |
) |
|
(1.42 |
) |
|
|
Cash financing and interest |
(4.15 |
) |
|
(3.19 |
) |
|
(3.14 |
) |
|
(3.59 |
) |
|
(3.12 |
) |
|
|
Realized financial derivatives gain |
2.06 |
|
|
3.00 |
|
|
1.45 |
|
|
2.60 |
|
|
1.76 |
|
|
|
Other (5) |
(0.03 |
) |
|
0.07 |
|
|
0.07 |
|
|
0.02 |
|
|
0.19 |
|
|
|
Adjusted funds flow (1) |
$ |
2.71 |
|
|
$ |
14.84 |
|
|
$ |
26.37 |
|
|
$ |
9.69 |
|
|
$ |
25.31 |
|
|
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, and current
income tax expense or recovery. Refer to the Q2/2020 MD&A for
further information on these amounts.
Q2/2020 Results
During the second quarter we took decisive steps
to adjust our business plan in the face of extremely volatile crude
oil markets. In addition to voluntarily shutting-in production, we
suspended drilling operations in Canada and moderated our pace of
activity in the Eagle Ford. As a result, exploration and
development spending totaled a modest $10 million during the second
quarter.
Production during the second quarter averaged
72,508 boe/d (81% oil and NGL), as compared to 98,452 boe/d (83%
oil and NGL) in Q1/2020. Production in Canada averaged 37,691 boe/d
(83% oil and NGL), as compared to 62,262 boe/d in Q1/2020, while
production in the Eagle Ford averaged 34,817 boe/d (77% oil and
NGL), as compared to 36,190 boe/d in Q1/2020. Our second quarter
production was reduced by approximately 20,000 boe/d due to the
voluntary shut-ins.
We delivered adjusted funds flow of $18 million
($0.03 per basic share) in Q2/2020 and generated an operating
netback of $5.96/boe ($8.02/boe inclusive of realized financial
derivatives gain). The Eagle Ford generated an operating netback of
$10.05/boe and our Canadian operations generated an operating
netback of $2.19/boe.
We continue to emphasize cost reductions across
all facets of our organization. We have identified approximately
$98 million of cost reductions for 2020 (operating, transportation
and general & administrative expenses). During the second
quarter, our operating expense of $11.17/boe compared favorably to
$11.66/boe in Q1/2020 as we strive to mitigate the costs associated
with our field operations. In addition, we realized an approximate
35% reduction in our per boe transportation expense due to reduced
volumes. General and administrative expense totaled $7.4 million
($1.13/boe) in Q2/2020, down from $9.8 million ($1.09/boe) in
Q1/2020 as we implemented reductions to salaries and annual
retainers and benefited from the Canadian Emergency Wage
Subsidy.
Eagle Ford and Viking Light Oil
In the Eagle Ford, strong well performance
continued across our acreage position. In Q2/2020, we commenced
production from 17 (4.6 net) wells. These wells were brought
on-stream in April and generated an average 30-day initial
production rate of approximately 1,550 boe/d per well. We expect to
bring approximately 16 to 18 net wells on production in the Eagle
Ford in 2020, down from our original guidance of 22 net
wells.
Production in the Viking averaged 19,717 boe/d
(90% oil and NGL) during Q2/2020, as compared to 24,696 boe/d in
Q1/2020. The quarterly impact of voluntary shut-ins in the Viking
was approximately 2,000 boe/d. As operating netbacks improved in
June, these volumes were brought back on-line. We suspended all
drilling in the Viking, and as such, there was limited activity
during the second quarter. In the first half of 2020, we invested
$79 million on exploration and development in the Viking and
commenced production from 83 (78.5 net) wells.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 13,082 boe/d (91% oil and NGL)
during the second quarter, as compared to 31,211 boe/d in Q1/2020.
The quarterly impact of voluntary shut-ins for heavy oil was
approximately 17,000 boe/d. We suspended all heavy oil drilling,
and as such, there was limited activity during the second quarter.
In the first half of 2020, we invested $40 million on exploration
and development and drilled 33 (33.0 net) wells. For the second
half of 2020, we currently project about 5,000 boe/d of heavy oil
production to remain shut-in.
Pembina Area Duvernay Light Oil
Production in the Pembina Duvernay averaged 717
boe/d (85% oil and NGL) during Q2/2020, as compared to 1,717 boe/d
in Q1/2020. The quarterly impact of voluntary shut-ins for the
Pembina Duvernay was approximately 1,000 boe/d. As operating
netbacks improved in June, these volumes were brought back
on-line.
In Q1/2020, we drilled two wells in the core of
our Pembina acreage, bringing total wells drilled to nine in this
area. Completion activities, originally scheduled for Q2/2020 have
been deferred.
Financial Liquidity
Our credit facilities total approximately $1.1
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, 2020, we had $363 million of undrawn
capacity on our credit facilities, resulting in liquidity, net of
working capital, of approximately $300 million. In addition, our
first long-term note maturity of US$400 million is not until June
2024.
Our net debt, which includes our bank loan,
long-term notes and working capital, totaled $2.0 billion at June
30, 2020. Based on the forward strip(1), we expect to maintain our
financial liquidity and remain onside with our financial covenants
through 2021.
Note:
- 2020 full year pricing assumptions:
WTI - US$39/bbl; WCS differential - US$14/bbl; MSW differential –
US$6/bbl, NYMEX Gas - US$1.90/mcf; AECO Gas - $2.05/mcf and
Exchange Rate (CAD/USD) - 1.36. 2021 full year pricing assumptions:
WTI - US$41/bbl; WCS differential - US$15/bbl; MSW differential –
US$7/bbl, NYMEX Gas - US$2.60/mcf; AECO Gas - $2.35/mcf and
Exchange Rate (CAD/USD) - 1.36.
Financial Covenants
The following table summarizes the financial
covenants applicable to the credit facilities and Baytex's
compliance therewith as at June 30, 2020.
|
Covenant Description |
Position as atJune 30, 2020 |
Covenant |
|
Senior Secured Debt(1) to Bank EBITDA(2) (Maximum Ratio) |
1.0:1.0 |
3.5:1.0 |
|
Interest Coverage(3) (Minimum Ratio) |
6.6:1.0 |
2.0:1.0 |
Notes:
- Senior Secured Debt is defined as
the principal amount of the credit facilities and other secured
obligations identified in the credit agreement. As at June 30,
2020, the Company's Senior Secured Debt totaled $719.9 million
which includes $704.1 million of principal amounts outstanding and
$15.8 million of letters of credit.
- Bank EBITDA is calculated based on
terms and definitions set out in the credit agreement which adjusts
net income or loss for financing and interest expense, income tax,
non-recurring losses, certain specific unrealized and non-cash
transactions (including depletion, depreciation, exploration and
evaluation expense, impairment, deferred income tax expense or
recovery, unrealized gains and losses on financial derivatives and
foreign exchange and share-based compensation) and is calculated
based on a trailing twelve month basis including the impact of
material acquisitions as if they had occurred at the beginning of
the twelve month period. Bank EBITDA for the twelve months ended
June 30, 2020 was $704.4 million.
- Interest coverage is computed as
the ratio of Bank EBITDA to financing and interest expense,
excluding accretion of debt issue costs and asset retirement
obligations, and is calculated on a trailing twelve month basis.
Financing and interest expense, excluding accretion of debt issue
costs and asset retirement obligations, for the twelve months ended
June 30, 2020 was $106.5 million.
Risk Management
To manage commodity price movements, we utilize
various financial derivative contracts and crude-by-rail to reduce
the volatility of our adjusted funds flow. The following table
summarizes our crude oil hedges in place.
|
|
Q3/2020 |
Q4/2020 |
2021 |
|
|
|
|
|
|
|
|
WTI Fixed Hedges |
|
|
|
|
|
Volumes (bbl/d) |
|
23,732 |
|
8,000 |
--- |
|
|
Fixed Price (US$/bbl) |
$36.41 |
$42.78 |
--- |
|
|
|
|
|
|
|
|
WTI 3-Way Option (1) |
|
|
|
|
|
Volumes (bbl/d) |
|
24,500 |
|
24,500 |
5,000 |
|
|
Baytex Receives (2) (3) (4) |
WTI plus US$7.60 |
WTI plus US$7.60 |
US$45/bbl |
|
|
|
|
|
|
|
|
Total Volumes (bbl/d) |
|
48,232 |
|
32,500 |
5,000 |
|
|
|
|
|
|
|
Notes:
- WTI 3-way options consist of a sold
put, a bought put and a sold call. Baytex’s average sold put,
bought put and sold call for Q3/2020 and Q4/2020 are US$50.44/bbl,
US$58.04/bbl and US$63.06/bbl, respectively. Baytex’s average sold
put, bought put and sold call for 2021 are US$35/bbl, US$45/bbl and
US$55/bbl, respectively.
- For Q3/2020 and Q4/2020, Baytex
receives WTI plus US$7.60/bbl when WTI is at or below US$50.44/bbl;
Baytex receives US$58.04/bbl when WTI is between US$50.44/bbl and
US$58.04/bbl; Baytex receives WTI when WTI is between US$58.04/bbl
and US$63.06/bbl; and Baytex receives US$63.06/bbl when WTI is
above US$63.06/bbl.
- For 2021, Baytex receives WTI plus
US$10/bbl when WTI is at or below US$35/bbl; Baytex receives
US$45/bbl when WTI is between US$35/bbl and US$45/bbl; Baytex
receives WTI when WTI is between US$45/bbl and US$55/bbl; and
Baytex receives US$55/bbl when WTI is above US$55/bbl.
- Based on the forward strip for the
balance of 2020, Baytex will receive WTI plus US$7.60/bbl. Based on
the forward strip for 2021, Baytex will receive US$45/bbl.
For the remainder of 2020, we also have WTI-MSW
basis differential swaps for 7,783 bbl/d of our light oil
production in Canada at US$5.80/bbl and WCS differential hedges on
8,667 bbl/d at a WTI-WCS differential of US$14.57/bbl.
Crude-by-rail is an integral part of our egress
and marketing strategy for our heavy oil production. For Q2/2020,
we delivered approximately 5,250 bbl/d of our heavy oil volumes to
market by rail.
A complete listing of our financial derivative
contracts can be found in Note 17 to our Q2/2020 financial
statements.
Sustainability
We are committed to managing the environmental
and social impacts of our business and continual improvement is an
important element of this commitment. In 2019, Baytex established
for the first time a GHG emissions reduction target. Our objective
is to reduce our corporate GHG emission intensity (tonnes of CO2
per boe) by 30% by 2021, relative to our 2018 baseline.
In 2019, we made significant improvements in our
emissions profile, achieving a 15% reduction in our GHG emissions
intensity as we commissioned our Peace River gas plant in mid-2018
and progressed our Viking gas conservation project. We remain
committed to achieving our 30% target by the end of 2021.
2020 Guidance
There is no change to our guidance announced
June 25, 2020.
|
|
2020 Guidance |
|
|
Exploration and development expenditures |
$260 - $290 million |
|
| Production (boe/d) |
78,000 - 82,000 |
|
| |
|
|
| Expenses: |
|
|
|
Royalty rate |
~ 18.5% |
|
|
Operating |
$11.75 - $12.50/boe |
|
|
Transportation |
$0.95 - $1.05/boe |
|
|
General and administrative |
$38 million ($1.30/boe) |
|
|
Interest |
$112 million ($3.84/boe) |
|
| |
|
|
| Leasing expenditures |
$7 million |
|
| Asset
retirement obligations |
$10 million |
|
Additional Information
Our condensed consolidated interim unaudited
financial statements for the three and six months ended June 30,
2020 and the related Management's Discussion and Analysis of the
operating and financial results can be accessed on our website at
www.baytexenergy.com and will be available shortly through SEDAR at
www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.
|
|
Conference Call Tomorrow9:00 a.m. MDT
(11:00 a.m. EDT) |
|
|
|
Baytex will host a conference call tomorrow, July 30, 2020,
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/baytexq220200730.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; restarted shut-in
volumes will have a positive impact on our adjusted funds flow;
that the resumption of production from shut-in barrels is expected
to positively impact adjusted funds flow and improve financial
liquidity; our ability to re-start shut in wells or shut-in
additional volumes; we expect 5,000 boe/d of heavy oil to remain
shut-in for H2/2020; we are focused on further efficiencies to
capture or sustain cost reduction while protecting the health and
safety of our personnel; that we have identified $98 million of
cost reductions for 2020 and continue to emphasize cost reductions;
the number of Eagle Ford wells we expect to bring online in 2020;
that we expect to maintain our financial liquidity and remain
onside our financial covenants through 2021; that we use financial
derivative contracts and crude-by-rail to reduce adjusted funds
flow volatility; that we are committed to managing the
environmental and social impacts of our business; that we are
committed to achieving our 30% emissions intensity target; and 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.
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); 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, 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, 2020.
Exploration and development expenditures is not
a measurement based on GAAP in Canada. We define exploration and
development expenditures as additions to exploration and evaluation
assets combined with additions to oil and gas properties. Our
definition of exploration and development expenditures may not be
comparable to other issuers. We use exploration and development
expenditures to measure and evaluate the performance of our capital
programs. The total amount of exploration and development
expenditures is managed as part of our budgeting process and can
vary from period to period depending on the availability of
adjusted funds flow and other sources of liquidity.
Free cash flow is not a measurement based on
GAAP in Canada. We define free cash flow as adjusted funds flow
less exploration and development expenditures (both non-GAAP
measures discussed above), payments on lease obligations, and asset
retirement obligations settled. Our determination of free cash flow
may not be comparable to other issuers. We use free cash flow to
evaluate funds available for debt repayment, common share
repurchases, potential future dividends and acquisition and
disposition opportunities.
Net debt is not a measurement based on GAAP in
Canada. We define net debt to be the sum of cash, trade and other
accounts receivable, trade and other accounts payable, and the
principal amount of both the long-term notes and the 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
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,
2020. The NI 51-101 product types are included as follows: “Heavy
Oil” - heavy oil and bitumen, “Light and Medium Oil” - light and
medium oil, tight oil and condensate, “NGL” - natural gas liquids
and “Natural Gas” - shale gas and conventional natural gas.
|
|
Three Months Ended June 30, 2020 |
|
Six Months Ended June 30, 2020 |
|
|
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 |
4,735 |
6 |
15 |
6,278 |
5,802 |
|
9,377 |
7 |
14 |
9,450 |
10,973 |
|
Lloydminster |
7,098 |
10 |
— |
1,039 |
7,281 |
|
10,966 |
14 |
— |
1,160 |
11,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada - Light |
|
|
|
|
|
|
|
|
|
|
|
|
Viking |
— |
17,735 |
105 |
11,267 |
19,717 |
|
— |
20,110 |
109 |
11,925 |
22,206 |
|
Duvernay |
— |
430 |
176 |
670 |
717 |
|
— |
680 |
348 |
1,381 |
1,258 |
|
Remaining Properties |
— |
581 |
638 |
17,728 |
4,174 |
|
— |
690 |
654 |
18,124 |
4,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Eagle Ford |
— |
20,189 |
6,701 |
47,564 |
34,817 |
|
— |
20,832 |
6,603 |
48,410 |
35,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
11,832 |
38,951 |
7,634 |
84,546 |
72,508 |
|
20,343 |
42,333 |
7,728 |
90,451 |
85,479 |
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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