Baytex Energy Corp. ("Baytex") (TSX, NYSE: BTE) reports its
operating and financial results for the three and nine months ended
September 30, 2018 (all amounts are in Canadian dollars unless
otherwise noted).
“Our strategic combination has repositioned
Baytex as a North American crude oil producer with strong free cash
flow and an improved balance sheet. We have completed the
integration while delivering excellent drilling results,
particularly the oil flow rates from our two new wells in the
Pembina region of our Duvernay light oil play. We are also
benefiting from strong oil price diversification, which includes
light oil production in the Eagle Ford and high netback Viking
light oil production in Canada. As we plan for 2019, our top
priority will be disciplined capital allocation to drive meaningful
free cash flow,” commented Ed LaFehr, President and Chief Executive
Officer.
Highlights
- Completed the strategic combination
with Raging River Exploration Inc. (“Raging River”) on August 22,
2018, creating a well-capitalized, light oil company with an
attractive free cash flow profile and improved balance sheet. Our
light oil assets generate approximately 80% of our operating
netback.
- Generated adjusted funds flow of
$171 million ($0.46 per basic share), $32 million in excess of
exploration and development capital expenditures of $139 million,
which delivered production of 82,412 boe/d (81% oil and NGL) during
Q3/2018. Our results reflect a 40 day contribution from the Raging
River assets.
- Completed two (2.0 net) significant
light oil discovery wells in the Pembina area of the East Duvernay
Shale. These two wells established an average 30-day initial
production rate of approximately 750 boe/d per well (88% oil and
NGLs), further proving the oil window in the Pembina area where we
control 256 prospective sections of 100% interest land.
- Produced approximately 97,000 boe/d
(84% crude oil and NGL) during the month of October, demonstrating
continued strong operating results across our portfolio of oil
assets and the successful integration of Raging River.
- Reduced annual guidance for
operating expenses by 4% (at mid-point) to $10.50-$10.75/boe,
reflecting strong performance year-to-date of $10.54/boe. Continued
to drive efficiency across our business with a 5% reduction in
forecast 2018 general and administrative expenses to
$1.55/boe.
- Implemented plans to optimize our
heavy oil production in the face of volatile heavy oil prices. Our
optimization strategy will reduce our Q4/2018 heavy oil volumes by
approximately 5,000 boe/d (90% oil), which represents 5% of our
total production, and given current pricing, will have a minimal
impact on our adjusted funds flow.
- Secured additional rail capacity,
which increases our crude oil volumes delivered to market by rail
to 11,000 bbl/d (approximately 40% of our heavy oil
production) through 2019. Commencing January 1, 2019, approximately
70% of our crude by rail commitments are WTI based contracts with
no WCS pricing exposure.
- Based on preliminary 2019 plans, we
expect to generate approximately $900 million of adjusted funds
flow, 80% of which is derived from our light oil assets in the
Eagle Ford and Viking. With an updated capital program of $700
million (at the mid-point), we expect to generate $200 million of
cash flow above capital expenditures.
|
|
|
|
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September
30,2018 |
|
June 30, 2018 |
|
September 30,2017 |
|
September 30,2018 |
|
September 30,2017 |
FINANCIAL(thousands of Canadian dollars, except
per common share amounts) |
|
|
|
|
|
|
Petroleum and
natural gas sales |
|
$ |
436,761 |
|
$ |
347,605 |
|
$ |
258,620 |
|
$ |
1,070,433 |
|
$ |
796,706 |
Adjusted funds
flow (1) |
|
171,210 |
|
106,690 |
|
77,340 |
|
362,155 |
|
241,845 |
Per share
– basic |
|
0.46 |
|
0.45 |
|
0.33 |
|
1.28 |
|
1.03 |
Per share
– diluted |
|
0.45 |
|
0.45 |
|
0.33 |
|
1.28 |
|
1.02 |
Net income
(loss) |
|
27,412 |
|
(58,761) |
|
(9,228) |
|
(94,071) |
|
11,136 |
Per share
– basic |
|
0.07 |
|
(0.25) |
|
(0.04) |
|
(0.33) |
|
0.05 |
Per share
– diluted |
|
0.07 |
|
(0.25) |
|
(0.04) |
|
(0.33) |
|
0.05 |
Shares
Outstanding – basic (thousands) |
|
|
|
|
|
|
|
|
|
|
Weighted
average |
|
375,435 |
|
236,628 |
|
235,451 |
|
283,302 |
|
234,563 |
End of period |
|
553,950 |
|
236,662 |
|
235,451 |
|
553,950 |
|
235,451 |
|
|
Three Months Ended |
|
Nine Months Ended |
|
|
September
30,2018 |
|
June 30, 2018 |
|
September 30,2017 |
|
September
30,2018 |
|
September 30,2017 |
FINANCIAL (thousands of Canadian dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration
and development |
|
$ |
139,195 |
|
$ |
78,830 |
|
$ |
61,544 |
|
$ |
311,559 |
|
$ |
236,110 |
Acquisitions, net of divestitures |
|
|
46 |
|
|
(21) |
|
|
(7,436) |
|
|
(2,001) |
|
|
63,794 |
Total oil and natural gas capital expenditures |
|
$ |
139,241 |
|
$ |
78,809 |
|
$ |
54,108 |
|
$ |
309,558 |
|
$ |
299,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bank loan
(2) |
|
$ |
490,565 |
|
$ |
213,538 |
|
$ |
226,249 |
|
$ |
490,565 |
|
$ |
226,249 |
Long-term notes (2) |
|
|
1,527,733 |
|
|
1,548,490 |
|
|
1,488,450 |
|
|
1,527,733 |
|
|
1,488,450 |
Long-term
debt |
|
|
2,018,298 |
|
|
1,762,028 |
|
|
1,714,699 |
|
|
2,018,298 |
|
|
1,714,699 |
Working capital (surplus) deficiency |
|
|
93,792 |
|
|
22,807 |
|
|
34,106 |
|
|
93,792 |
|
|
34,106 |
Net debt (3) |
|
$ |
2,112,090 |
|
$ |
1,784,835 |
|
$ |
1,748,805 |
|
$ |
2,112,090 |
|
$ |
1,748,805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light oil and condensate (bbl/d) |
|
|
29,731 |
|
|
21,100 |
|
|
20,041 |
|
|
23,965 |
|
|
21,343 |
Heavy oil (bbl/d) |
|
|
27,036 |
|
|
25,544 |
|
|
26,161 |
|
|
25,824 |
|
|
25,454 |
NGL (bbl/d) |
|
|
10,076 |
|
|
9,419 |
|
|
8,940 |
|
|
9,549 |
|
|
8,982 |
Total liquids (bbl/d) |
|
|
66,843 |
|
|
56,063 |
|
|
55,142 |
|
|
59,338 |
|
|
55,779 |
Natural gas (mcf/d) |
|
|
93,414 |
|
|
87,605 |
|
|
85,006 |
|
|
89,449 |
|
|
88,166 |
Oil equivalent (boe/d @ 6:1) (4) |
|
|
82,412 |
|
|
70,664 |
|
|
69,310 |
|
|
74,246 |
|
|
70,473 |
|
|
|
|
|
|
Netback (thousands of Canadian
dollars) |
|
|
|
|
|
Total sales, net of blending and other expense |
|
$ |
417,213 |
|
$ |
329,366 |
|
$ |
242,551 |
|
$ |
1,015,356 |
|
$ |
754,152 |
Royalties |
|
|
(91,945) |
|
|
(77,205) |
|
|
(55,176) |
|
|
(233,989) |
|
|
(172,367) |
Operating expense |
|
|
(77,698) |
|
|
(70,149) |
|
|
(64,391) |
|
|
(213,735) |
|
|
(199,446) |
Transportation expense |
|
|
(9,520) |
|
|
(7,836) |
|
|
(9,312) |
|
|
(25,875) |
|
|
(26,327) |
Operating
netback |
|
$ |
238,050 |
|
$ |
174,176 |
|
$ |
113,672 |
|
$ |
541,757 |
|
$ |
356,012 |
General and administrative |
|
|
(10,158) |
|
|
(10,563) |
|
|
(11,074) |
|
|
(31,729) |
|
|
(37,672) |
Cash financing and interest |
|
|
(26,343) |
|
|
(25,530) |
|
|
(24,526) |
|
|
(76,384) |
|
|
(75,632) |
Realized financial derivatives (loss) gain |
|
|
(30,854) |
|
|
(29,408) |
|
|
2,795 |
|
|
(70,103) |
|
|
5,719 |
Other (5) |
|
|
515 |
|
|
(1,985) |
|
|
(3,527) |
|
|
(1,386) |
|
|
(6,582) |
Adjusted funds flow |
|
$ |
171,210 |
|
$ |
106,690 |
|
$ |
77,340 |
|
$ |
362,155 |
|
$ |
241,845 |
|
|
|
|
|
|
|
|
|
|
Netback (per boe) |
|
|
|
|
|
|
|
|
|
Total sales, net of blending and other expense |
|
$ |
55.03 |
|
$ |
51.22 |
|
$ |
38.04 |
|
$ |
50.09 |
|
$ |
39.20 |
Royalties |
|
|
(12.13) |
|
|
(12.01) |
|
|
(8.65) |
|
|
(11.54) |
|
|
(8.96) |
Operating expense |
|
|
(10.25) |
|
|
(10.91) |
|
|
(10.10) |
|
|
(10.54) |
|
|
(10.37) |
Transportation expense |
|
|
(1.26) |
|
|
(1.22) |
|
|
(1.46) |
|
|
(1.28) |
|
|
(1.37) |
Operating
netback |
|
$ |
31.39 |
|
$ |
27.08 |
|
$ |
17.83 |
|
$ |
26.73 |
|
$ |
18.50 |
General and administrative |
|
|
(1.34) |
|
|
(1.64) |
|
|
(1.74) |
|
|
(1.57) |
|
|
(1.96) |
Cash financing and interest |
|
|
(3.47) |
|
|
(3.97) |
|
|
(3.85) |
|
|
(3.77) |
|
|
(3.93) |
Realized financial derivatives (loss) gain |
|
|
(4.07) |
|
|
(4.57) |
|
|
0.44 |
|
|
(3.46) |
|
|
0.30 |
Other (5) |
|
|
0.07 |
|
|
(0.31) |
|
|
(0.55) |
|
|
(0.06) |
|
|
(0.34) |
Adjusted funds flow |
|
$ |
22.58 |
|
$ |
16.59 |
|
$ |
12.13 |
|
$ |
17.87 |
|
$ |
12.57 |
Notes: |
|
(1) |
|
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, asset retirement obligations settled and
transaction costs. Our determination of adjusted funds flow may not
be comparable to other issuers. We consider adjusted funds flow a
key measure of performance as it demonstrates our ability to
generate the cash flow necessary to fund capital investments, debt
repayment, settlement of our abandonment obligations and potential
future dividends. In addition, we use the ratio of net debt to
adjusted funds flow to manage our capital structure. We eliminate
changes in non-cash working capital and 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. In
addition, we have removed transaction costs from the Raging River
combination as we consider these costs non-recurring and not
reflective of our ongoing ability to generate adjusted funds flow.
For a reconciliation of adjusted funds flow to cash flow from
operating activities, see Management's Discussion and Analysis of
the operating and financial results for the three and nine months
ended September 30, 2018. |
(2) |
|
Principal amount of instruments. |
(3) |
|
Net debt
is not a measurement based on GAAP in Canada, but is a financial
term commonly used in the oil and gas industry. We define net debt
to be the sum of monetary working capital (which is current assets
less current liabilities excluding current financial derivatives
and onerous contracts) and the principal amount of both the
long-term notes and the bank loan. |
(4) |
|
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. |
(5) |
|
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 Q3/2018 MD&A for further
information on these amounts. |
|
|
|
Strategic Combination with Raging
River
On August 22, 2018, we completed the strategic
combination with Raging River. The transaction resulted in holders
of common shares of Raging River receiving 1.36 common shares of
Baytex for each Raging River Share owned. Our third quarter results
include 40 days of operations from the Raging River assets
representing the August 22 to September 30 period. During this
period, production from the Raging River assets averaged 23,750
boe/d (Q3/2018 impact of 10,327 boe/d), consistent with our
expectations.
Since closing the transaction, we have
successfully integrated the two companies, undertaken a detailed
strategic review of our operations, confirmed the organic growth
opportunities in our diversified portfolio of assets and delivered
on our near-term targets. Our strategic combination with Raging
River has repositioned Baytex as a self-funding North American
producer focused on per share value creation with a target of
providing investors with a 10% to 15% total annual return.
In October, we produced approximately 97,000
boe/d (84% crude oil and NGL) from our high quality oil assets,
including the Eagle Ford in Texas and the Viking, Peace River,
Lloydminster and East Duvernay Shale properties in Canada. We have
a deep inventory of high quality drilling prospects that generate
top tier returns on invested capital and have the capability to
deliver meaningful organic production growth.
One of the key benefits of the combination with
Raging River is our strong oil price diversification, which
includes light oil and condensate production in the Eagle Ford
which commands premium Louisiana Light Sweet (“LLS”) based pricing
and our high netback Viking light oil production in Canada. At
current prices, approximately 80% of our operating netback is
derived from these two assets. The charts at the following link
summarize our exposure by commodity based on production, revenue
and proved reserves.
http://www.globenewswire.com/NewsRoom/AttachmentNg/dc6e2e3f-000e-463e-abce-ac6b70cc69a7
Operating Results
We continued to deliver on our operational and
financial targets during the third quarter. We successfully
integrated the Raging River assets and executed our drilling
program with strong results realized in the Eagle Ford and
Canada.
Production average 82,412 boe/d (81% oil and
NGL) in Q3/2018, as compared to 70,664 boe/d (79% oil and NGL) in
Q2/2018. Production in the first nine months of 2018 averaged
74,246 boe/d. Production from the legacy Baytex assets (excluding
Raging River) averaged 72,085 boe/d in Q3/2018.
During the third quarter, exploration and
development capital expenditures totaled $139 million, bringing the
aggregate spending in the first nine months of 2018 to $312
million. We participated in the drilling of 116 (74.8 net) wells
with a 98% success rate during the third quarter.
Eagle Ford and Viking Light Oil
Our Eagle Ford asset in South Texas is one of
the premier oil resource plays in North America. The asset
generates a strong operating netback and free cash flow and
contains a significant inventory of development prospects. In
Q3/2018, we allocated 32% of our exploration and development
expenditures to this asset generating production of 37,198 boe/d
(77% oil and NGL), as compared to 36,622 boe/d in Q2/2018. During
the third quarter, the Eagle Ford generated operating netback of
$130 million and free cash flow (after capital expenditures) of $85
million.
We continue to see strong well performance
driven by enhanced completions in the Eagle Ford. In Q3/2018, we
participated in the drilling of 29 (8.0 net) wells and commenced
production from 26 (4.9 net) wells. The wells that have been on
production for more than 30 days in the quarter established 30-day
initial production rates of approximately 1,600 boe/d (54% light
oil and condensate). These wells were completed with approximately
28 effective frac stages per well and proppant per completed foot
of approximately 1,800 pounds.
Our Viking asset is a shallow, light oil
resource play (approximately 36° API) in western Canada with 460
net sections of prospective lands. For the period August 22 to
September 30, production from the Viking averaged 22,158 boe/d
(excluding heavy oil) and we drilled 42 (30.5 net) wells. The
extended reach horizontal results continue to exceed expectations
with multiple, previously untested sections being proven highly
economic. We currently have five drilling rigs and 1.5 frac crews
executing our development program.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 27,036 bbl/d during the third
quarter, as compared to 25,544 bbl/d in Q2/2018. The higher volumes
reflect the continued success of our development program and the
addition of heavy oil assets acquired as part of the Raging River
combination (964 bbl/d for the period August 22 to September
30).
Our Peace River region, located in northwest
Alberta, has been a core asset since we commenced operations in the
area in 2004. Through our innovative multi-lateral horizontal
drilling and production techniques, we are able to generate some of
the strongest capital efficiencies in the oil and gas industry. In
Q3/2018, we drilled five (5.0 net) wells and commenced production
from four (4.0 net) wells. In the northern Seal area of Peace
River, our first six wells have established 30-day initial
production rates of approximately 700 boe/d per well.
Our Lloydminster region is characterized by
multiple stacked pay formations at relatively shallow depths. The
area has been successfully developed through vertical and
horizontal drilling, water flood, steam-assisted gravity drainage
operations and, more recently, the implementation of polymer
flooding to further enhance reserves recovery. We drilled 36 (27.3
net) oil wells during the third quarter. In addition, we
successfully completed the expansion of our Kerrobert thermal
project with productive capability increasing to approximately
2,000 bbl/d during the fourth quarter.
East Duvernay Shale Light Oil – Significant
Pembina Light Oil Discovery
We continue to prudently advance the evaluation
of this emerging light oil play in central Alberta. The East
Duvernay Shale is an early stage, high netback light oil resource
play where we have amassed over 430 sections of land. The early
focus has been to delineate and evaluate the potential depth of
this light oil resource.
Our development has taken an important step
forward with two new light oil discovery wells in the Pembina area
located approximately 5 and 7 miles south of our initial 14-36
discovery well. These two wells established an average 30-day
initial production rate of approximately 750 boe/d per well (88%
oil and NGLs). We are also following up the initial 14-36 discovery
with two additional wells from the original surface pad. Drilling
operations are complete and we anticipate initiating completion
activities in early November.
The two recent discovery wells demonstrate
continuity of the oil window and provide a focus for 2019 pad
development drilling in addition to incremental delineation
drilling to continue to evaluate the commerciality of our lands. We
control 256 sections of 100% interest land in the Pembina area.
During the third quarter, we also completed one
(1.0 net) well at Ferrybank that is currently shut-in for
re-licensing due to encountering H2S in the early phase of flow
back and one (1.0 net) well at Gilby, which is currently on
production at 80 boe/d (77% oil and NGL).
Financial Review
We generated adjusted funds flow of $171 million
($0.46 per basic share) in Q3/2018, compared to $107 million ($0.45
per basic share) in Q2/2018 and $77 million ($0.33 per basic share)
in Q3/2017. Excluding financial derivatives losses, adjusted funds
flow in Q3/2018 was $202 million, compared to $136 million in
Q2/2018. The increase in adjusted funds flow is largely
attributable to an initial contribution from the high netback
Raging River production.
In the first nine months of 2018, we generated
adjusted funds flow of $362 million ($432 million excluding
realized financial derivatives losses), as compared to exploration
and development capital expenditures of $312 million.
Financial Liquidity
Our net debt totaled $2.1 billion at September
30, 2018, which is up from $1.8 billion at June 30, 2018. The
increase in net debt is due to the $364 million of net debt assumed
in conjunction with the Raging River transaction. We maintain
strong financial liquidity with our credit facilities approximately
50% undrawn and our first long-term note maturity not until 2021.
We have established a new $300 million term loan facility that is
due June 2020 and is secured by the assets of Raging River. This
additional facility, combined with our existing facilities of
US$575 million, increased our credit capacity to approximately
$1.04 billion.
Operating Netback
Our operating netback (excluding realized
financial derivatives gains and losses) improved 76% to $31.39/boe
in Q3/2018, as compared to $17.83/boe in Q3/2017. During the third
quarter, we benefited from strong liquids pricing in the Eagle Ford
and an initial contribution from our high netback Viking light oil
production. The Eagle Ford generated an operating netback of
$38.03/boe during Q3/2018 while our Canadian operations generated
an operating netback of $25.94/boe.
In Q3/2018, the price for West Texas
Intermediate light oil (“WTI”) averaged US$69.50/bbl, as compared
to US$48.20/bbl in Q3/2017. The discount for Canadian heavy oil, as
measured by the price differential between Western Canadian Select
(“WCS”) and WTI, averaged US$22.25/bbl in Q3/2018 as compared to
US$9.94/bbl in Q3/2017.
In the Eagle Ford, our assets are proximal to
Gulf Coast markets with light oil and condensate production priced
off the LLS crude oil benchmark, which is a function of the Brent
price. In Q3/2018, the price for LLS averaged US$75.25/bbl as
compared to US$50.27/bbl in Q3/2017. During the third quarter, our
light oil and condensate realized price in the Eagle Ford of
US$71.41/bbl (or $93.37/bbl) represented a US$3.84/bbl discount to
LLS.
The following table summarizes our operating
netbacks for the periods noted.
|
|
|
|
|
Three Months Ended September 30 |
|
|
2018 |
|
2017 |
($ per boe except for volume) |
|
Canada |
|
U.S. |
|
Total |
|
Canada |
|
U.S. |
|
Total |
Total production
(boe/d) |
|
45,214 |
|
37,198 |
|
82,412 |
|
34,560 |
|
34,750 |
|
69,310 |
|
|
|
|
|
|
|
|
Total sales, net of
blending and other expense |
|
$ |
47.66 |
|
$ |
63.98 |
|
$ |
55.03 |
|
$ |
33.41 |
|
$ |
42.64 |
|
$ |
38.04 |
Less: |
|
|
|
|
|
|
|
Royalties |
|
6.28 |
|
19.23 |
|
12.13 |
|
4.71 |
|
12.58 |
|
8.65 |
Operating
expense |
|
13.15 |
|
6.72 |
|
10.25 |
|
13.69 |
|
6.53 |
|
10.10 |
Transportation expense |
|
2.29 |
|
— |
|
1.26 |
|
2.93 |
|
— |
|
1.46 |
Operating netback |
|
$ |
25.94 |
|
$ |
38.03 |
|
$ |
31.39 |
|
$ |
12.08 |
|
$ |
23.53 |
|
$ |
17.83 |
Realized
financial derivatives (loss) gain |
|
|
— |
|
|
— |
|
|
(4.07) |
|
|
— |
|
|
— |
|
|
0.44 |
Operating netback after
financial derivatives |
|
$ |
25.94 |
|
$ |
38.03 |
|
$ |
27.32 |
|
$ |
12.08 |
|
$ |
23.53 |
|
$ |
18.27 |
|
Risk Management
As part of our normal operations, we are exposed
to movements in commodity prices. In an effort to manage these
exposures, we utilize various financial derivative contracts,
crude-by-rail and capital allocation optimization to reduce the
volatility in our adjusted funds flow. We realized a financial
derivatives loss of $31 million in Q3/2018 due to the increased
price of crude oil relative to the prices set in our contracts.
For 2019, we have entered into hedges on
approximately 35% of our net crude oil exposure. This includes 30%
of our net WTI exposure with 11% fixed at US$61.22/bbl and 19%
hedged utilizing a 3-way option structure that provides us with an
average downside price protection at US$66.74/bbl and an average
upside participation to US$73.42/bbl. In addition, we have entered
into a Brent-based 3-way option structure for 3,000 bbl/d that
provides us with average downside price protection at US$69.50/bbl
and average upside participation to US$78.68/bbl.
Crude-by-rail is an integral part of our egress
and marketing strategy. In Q3/2018, we delivered 9,500 bbl/d of our
heavy oil volumes to market by rail, up from 8,500 bbl/d in
Q2/2018. We have secured additional rail capacity, which will see
our heavy oil volumes delivered to market by rail increase to
approximately 11,000 bbl/d (approximately 40%) through 2019.
Commencing January 1, 2019, approximately 70% of our crude by rail
commitments are WTI based contracts with no WCS pricing
exposure.
A complete listing of our financial derivative
contracts can be found in Note 18 to our Q3/2018 financial
statements.
Outlook and Guidance Update
On August 22, 2018, we provided updated 2018
guidance and preliminary plans for 2019. We laid out a plan to
deliver industry leading returns, attractive production growth and
strong free cash flow.
We are currently benefiting from improved WTI
and LLS pricing, which has resulted in record operating netback
being generated in the Eagle Ford. The Eagle Ford, which represents
37% of our production, generates approximately 47% of our operating
netback and approximately $300 million of annual free cash flow.
Likewise, the Viking, which represents 25% of our production,
generates approximately 33% of our operating netback and
approximately $100 million of annual free cash flow.
Offsetting the strong global pricing environment
are weak prices for all grades of Canadian crude oil and in
particular for heavy oil. Over the last two months, price
differentials to WTI have widened due to an increased supply of
crude oil from western Canada, refinery turnarounds in the U.S.
which has temporarily reduced demand and a slower than anticipated
ramp up in crude-by-rail volumes. As a result, based on the forward
curve, the WCS differential to WTI for Q4/2018 is approximately
US$40/bbl and for 2019, is approximately US$30/bbl.
We are committed to making prudent capital
allocation decisions in the face of volatile commodity prices. In
the normal pricing environment, our heavy oil assets generate
exceptional rates of return and provide meaningful organic growth
opportunities. Recognizing the current heavy oil pricing dynamics
and an expectation that the volatility around heavy oil in Canada
is likely to continue into 2019, we are currently optimizing our
heavy oil operations. This includes building crude inventory,
deferring several completions and pro-actively shutting in negative
margin production. In doing so, we will maximize the value of our
resource base and our adjusted funds flow.
Our heavy oil optimization strategy will reduce
our Q4/2018 volumes by approximately 5,000 boe/d (90% oil), which
represents 5% of our total production, and given current pricing,
will have a minimal impact on our adjusted funds flow. The strong
operating performance in our other business units is expected to
mitigate a portion of the reduced heavy oil volumes in the fourth
quarter. As a result, we expect production in Q4/2018 to average
95,000 to 96,000 boe/d (97,000 to 99,000 boe/d, previously). For
the full-year 2018, we have tightened our production guidance range
to 79,000 to 80,000 boe/d (79,000 to 81,000 boe/d, previously) with
an unchanged exploration and development capital expenditure budget
of $450 to $500 million.
The following table compares our 2018 annual
guidance to our YTD 2018 results.
Summary of 2018 Guidance
|
|
|
Original Guidance
(1) |
|
Current Guidance
(2) |
|
YTD Results |
Exploration and development capital ($ millions) |
|
450 – 500 |
|
450 - 500 |
|
312 |
Production (boe/d) |
|
79,000
- 81,000 |
|
79,000
- 80,000 |
|
74,246 |
|
|
|
|
|
|
|
Expenses: |
|
|
|
|
|
|
Royalty
rate (%) |
|
~
21.0 |
|
~
22.0 |
|
23.0 |
Operating
($/boe) |
|
10.75 -
11.25 |
|
10.50 –
10.75 |
|
10.54 |
Transportation ($/boe) |
|
1.35 -
1.45 |
|
1.25 -
1.30 |
|
1.28 |
General
and administrative ($ millions) |
|
~ 48
(1.64/boe) |
|
~ 45
(1.55/boe) |
|
32
(1.57/boe) |
Interest ($ millions) |
|
~ 105 (3.60/boe) |
|
~ 104 (3.58/boe) |
|
76 (3.77/boe) |
Note: |
|
|
|
(1) |
|
As
announced on August 22, 2018 to include Raging River from the
closing date of the transaction. |
(2) |
|
Updated
as at November 2, 2018. |
|
|
|
As we make plans for 2019, our top priority will
be disciplined capital allocation to drive meaningful free cash
flow and a strengthened balance sheet. With a diversified asset
base and product pricing mix, we have the capability to optimize
capital allocation based on commodity prices and economic returns
by area.
In addition to the near-term impact of
optimizing our heavy oil operations, we currently anticipate
moderating our growth expectations in heavy oil over the near term.
As a result, we are making plans for a curtailed heavy oil
development program through the first half of 2019. We believe with
continued growth in crude-by-rail volumes and incremental pipeline
egress scheduled for late 2019, a much stronger pricing environment
for heavy oil will present itself in the second half of 2019. We
will continue to monitor Canadian crude oil pricing dynamics for an
opportunity to re-deploy incremental capital as supported by well
economics and field netbacks.
For our 2019 preliminary plans, exploration and
development expenditures are now expected to total $650 to $750
million ($750 to $850 million previously) which is designed to
generate average annual production of approximately 95,000 to
100,000 boe/d (100,000 to 105,000 boe/d, previously). This 2019
production range contemplates the re-start of shut in heavy oil
volumes by mid-2019.
Preliminary development plans for 2019 include
maintaining a consistent activity set in the Eagle Ford and Viking,
both of which are expected to generate significant free cash flow.
In addition, we will continue to delineate the East Duvernay Shale
oil play with an increased pace of activity. Development plans for
our heavy oil portfolio remain flexible based on an evolving
outlook for heavy oil prices.
Despite the volatility in commodity prices, we
continue to forecast adjusted funds flow for 2019 of approximately
$900 million. With reduced spending on heavy oil, we are positioned
to allocate approximately $200 million of free cash flow toward
debt repayment, up from our original debt reduction plan of
approximately $100 million.
Summary of Preliminary 2019 Plans
|
|
|
|
|
|
|
Original (1) |
|
Current
(2) |
Exploration and Development Capital |
|
$750 - $850 million |
|
$650 - $750 million |
|
|
|
|
|
Production |
|
100,000
- 105,000 boe/d |
|
95,000
- 100,000 boe/d |
Oil and NGLs |
|
~
85% |
|
~
85% |
|
|
|
|
|
Operating Netback |
|
$28/boe |
|
$31/boe |
Adjusted Funds
Flow |
|
$900
million |
|
$900
million |
Adjusted Funds Flow per
Share (3) |
|
$1.60 |
|
$1.60 |
|
|
|
|
|
Free Cash Flow after
Total Capital Spending |
|
$100
million |
|
$200
million |
Net Debt (YE 2019) |
|
$2.0
billion |
|
$1.9
billion |
Net Debt
to Adjusted Funds Flow (4) |
|
2.2x |
|
2.1x |
Notes: |
|
|
|
(1) |
|
As
announced August 22, 2018. Pricing assumptions: WTI - US$63/bbl;
LLS - US$67/bbl; WCS differential - US$23/bbl; MSW differential –
US$8/bbl, NYMEX Gas - US$2.80/mcf; and Exchange Rate (CAD/USD) -
1.30. |
(2) |
|
As
announced November 2, 2018. Pricing assumptions: WTI - US$70/bbl;
LLS - US$75/bbl; WCS differential - US$30/bbl; MSW differential –
US$15/bbl, NYMEX Gas - US$2.90/mcf; and Exchange Rate (CAD/USD) -
1.30. |
(3) |
|
Based on
555 million common shares outstanding. |
(4) |
|
Net debt
ratio based on forecast net debt at year-end 2019 and forecast 2019
adjusted funds flow. |
(5) |
|
Certain
terms referenced above are non-GAAP measures. See advisory
regarding Non-GAAP Financial and Capital Management Measures at the
end of the press release. |
|
|
|
We will provide 2019 guidance in early December
upon approval by the board of directors.
Additional Information
Our condensed consolidated interim unaudited
financial statements for the three and nine months ended September
30, 2018 and the related Management's Discussion and Analysis of
the operating and financial results can be accessed immediately 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 Today |
9:00 a.m. MDT (11:00 a.m.
EDT) |
|
Baytex will host a conference call today,
November 2, 2018, 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/baytexq320181102.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 "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 benefit from oil
price diversification; that our top priority is disciplined capital
allocation to drive meaningful free cash flow; that we are a
well-capitalized, oil-weighted company with an attractive free cash
flow profile and an improved balance sheet; our reduced guidance
for 2018 operating and general and administrative expenses; the
impact of our heavy oil optimization strategy; our plans to
optimize heavy oil prices, including: the volume of oil we expect
to deliver to market by rail and the percentage of our rail
commitments exposed to WCS pricing; our 2019 preliminary plans,
including our expected: adjusted funds flow, percentage of adjusted
funds flow to be derived from our light oil assets, capital
spending plan, cash flow above capital expenditures and free cash
flow yield; that we are a self-funded producer focused on per share
value creation, targeting shareholder returns of 10% to 15%; that
our drilling prospects will generate top tier returns on invested
capital and that we have the ability to deliver meaningful organic
production growth; our commodity exposure on a production, revenue
and proved reserves basis; our Eagle Ford assets, including our
assessment that: it is a premier oil resource play, generates
strong operating netbacks and free cash flow and has a significant
development inventory; that 460 net sections in our Viking asset
are prospective; our assessment that we can generate some of the
strongest capital efficiencies in the oil and gas industry at our
Peace River assets; that polymer flooding will enhance reserves
recovery at our Lloydminster asset; our East Duvernay assets,
including: that we are prudently advancing the evaluation of the
play, our plan to complete two wells in November, that the Pembina
area will be a focus of pad drilling and incremental delineation
drilling in 2019; our belief that we have strong financial
liquidity; our ability to partially reduce the volatility in our
adjusted funds flow by utilizing financial derivative contracts,
crude-by-rail and capital allocation optimization; the percentage
of our net WTI exposure that we have hedged for 2019; the
percentage of production and cash flow and dollar amount of free
cash flow expected from our Eagle Ford and Viking assets in 2019;
that our heavy oil assets generate exceptional rates of return and
provide meaningful growth opportunities in the right pricing
environment; our expectation the heavy oil prices will remain
volatile into 2019; that we are maximizing the value of our heavy
oil resource base and adjusted funds flow by and will: build
inventory, defer completions and shut-in low or negative margin
production; the expected impact of our heavy oil optimization in
Q4/2018 on production and adjusted fuds flow; that strong
performance in other business units will mitigate the a portion of
the heavy oil reduction; our 2018 guidance for exploration and
development capital, production and royalty rate, operating,
transportation, general and administration and interest expenses;
our top priority for 2019 will be disciplined capital allocation to
drive meaningful cash flow and a strengthened balance sheet; that
we have the ability to optimize capital allocation based on
commodity prices and economic returns by area; our preliminary
plans for 2019, including: moderated growth in heavy oil, that
heavy oil prices will be higher in the second half of 2019, 2019
guidance for exploration and development capital and production,
that we will re-start shut in heavy oil volumes by mid-2019, that
we will have a consistent activity set in the Eagle Ford and Viking
that will generate significant free cash flow, that we will
continue to delineate the Duvernay, that our heavy oil development
will be flexible, our forecast adjusted funds flow, the amount of
free cash flow available for debt repayment, our Summary of
Preliminary 2019 Plans and that we will provide 2019 guidance in
early December upon approval by the board of directors.
In addition, information and statements relating
to reserves and contingent resources are deemed to be
forward-looking statements, as they involve implied assessment,
based on certain estimates and assumptions, that the reserves and
contingent resources 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; the availability and cost of
capital or borrowing; 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; availability and
cost of gathering, processing and pipeline systems; public
perception and its influence on the regulatory regime; changes in
government regulations that affect the oil and gas industry;
changes in environmental, health and safety regulations;
restrictions or costs imposed by climate change initiatives;
variations in interest rates and foreign exchange rates; risks
associated with our hedging activities; 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; 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; 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, 2017, as filed with Canadian securities regulatory authorities
and the U.S. Securities and Exchange Commission.
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
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, asset
retirement obligations settled and transaction costs. Our
determination of adjusted funds flow may not be comparable to other
issuers. We consider adjusted funds flow a key measure of
performance as it demonstrates our ability to generate the cash
flow necessary to fund capital investments, debt repayment,
settlement of our abandonment obligations and potential future
dividends. In addition, we use the ratio of net debt to adjusted
funds flow to manage our capital structure. We eliminate changes in
non-cash working capital and 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. In
addition, we have removed transaction costs from the Raging River
combination as we consider these costs non-recurring and not
reflective of our ongoing ability to generate adjusted funds flow.
For a reconciliation of adjusted funds flow to cash flow from
operating activities, see Management's Discussion and Analysis of
the operating and financial results for the three and nine months
ended September 30, 2018.
Free cash flow is not a measurement based on
GAAP in Canada. We define free cash flow as adjusted funds flow
less sustaining capital. Sustaining capital is an estimate of the
amount of exploration and development capital required to offset
production declines on an annual basis and maintain flat production
volumes.
Net debt is not a measurement based on GAAP in
Canada. We define net debt to be the sum of monetary working
capital (which is current assets less current liabilities excluding
current financial derivatives and onerous contracts) and the
principal amount of both the long-term notes and the bank loan. We
believe that this measure assists in providing a more complete
understanding of our cash liabilities.
Bank EBITDA is not a measurement based on GAAP
in Canada. We define Bank EBITDA as our consolidated net income
attributable to shareholders before interest, taxes, depletion and
depreciation, and certain other non-cash items as set out in the
credit agreement governing our revolving credit facilities. Bank
EBITDA is used to measure compliance with certain financial
covenants.
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.
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. 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.
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.
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 85% 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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