Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its
operating and financial results for the three months and year ended
December 31, 2018 (all amounts are in Canadian dollars unless
otherwise noted).
“In 2018, we repositioned our company through
the Raging River combination which increased our high netback light
oil assets while also deleveraging our balance sheet. Our
operations are performing exceptionally well as we execute our
first quarter program with activity focused on the Viking and Eagle
Ford. We are also benefitting from a meaningful improvement in
crude oil prices in Canada and on the Texas Gulf coast, which is
expected to have a very positive impact to our adjusted funds flow.
We are well positioned to execute our business plan and further
strengthen our balance sheet in 2019,” commented Ed LaFehr,
President and Chief Executive Officer.
2019 Outlook
Global benchmark prices have recently improved
with WTI currently trading at US$57/bbl, as compared to a low of
US$42/bbl in December 2018. In addition, Canadian light and heavy
oil differentials have narrowed substantially. This combination is
expected to have a positive impact to our adjusted funds flow.
As a result of current activity levels,
excellent well performance in the Eagle Ford and outstanding
operating efficiency across all of our assets, Q1/2019 volumes are
ahead of expectations, trending above 97,000 boe/d.
Capital expenditures are on pace for $155
million in Q1/2019, consistent with the mid-point of our capital
guidance range of $600 million. Approximately 80% of our capital
program is directed to our high operating netback light oil assets
in the Eagle Ford and Viking.
Further deleveraging remains a top priority.
Based on the forward strip, our adjusted funds flow forecast has
increased from $605 million in December 2018, to approximately $800
million, which will support up to $200 million of debt repayment
while maintaining production at the mid-point of our guidance of
95,000 boe/d.
2018 Highlights
- Generated production of 98,890 boe/d (83% oil and NGL) during
Q4/2018, an increase of 42% over Q4/2017, and 80,458 boe/d for
full-year 2018, exceeding the high end of guidance, with capital
expenditures of $496 million, in line with annual guidance.
- Delivered adjusted funds flow of $111 million ($0.20 per basic
share) in Q4/2018 and $473 million ($1.35 per basic share) for the
full-year 2018.
- Eagle Ford production increased 3% to 38,437 boe/d (78%
liquids) in Q4/2018, compared to Q3/2018. Wells that commenced
production during the quarter generated 30-day initial gross
production rates of approximately 1,800 boe/d per well.
- Continued to advance the evaluation of the East Duvernay Shale
where we now have five producing wells on our Pembina acreage. In
Q4/2018, production more than doubled from Q3/2018, to average
1,432 boe/d.
- Decreased cash costs (operating, transportation and general and
administrative expenses) for 2018 by 4% on a boe basis as compared
to the mid-point of original guidance.
- Increased proved developed producing ("PDP") reserves by 35%,
from 100 mmboe to 135 mmboe. Proved reserves (“1P”) increased by
23%, from 256 mmboe to 315 mmboe. Proved plus probable (“2P”)
reserves increased by 22%, from 432 mmboe to 527 mmboe.
- Reserves associated with the Raging River assets increased by
4% on a 2P basis to 111 mmboe, as compared to year-end 2017. The
Raging River combination enhanced the quality of Baytex’s reserves
base, adding high value light oil reserves in the Viking and
Duvernay.
- PDP finding and development ("F&D") costs, including
changes in future development capital (“FDC”), were $15.82/boe,
resulting in a 1.5x recycle ratio based on our 2018 operating
netback of $23.76/boe.
- Our net asset value at year-end 2018, discounted at 10%, is
estimated to be $7.27 per share.
|
|
|
|
Three Months Ended |
Years Ended |
|
|
December 31,2018 |
September 30,2018 |
December 31,2017 |
December 31,2018 |
December 31,2017 |
|
FINANCIAL (thousands of Canadian dollars, except
per common share amounts) |
|
|
|
|
|
| Petroleum and
natural gas sales |
$ |
358,437 |
|
$ |
436,761 |
|
$ |
303,163 |
|
$ |
1,428,870 |
|
$ |
1,099,867 |
|
| Adjusted funds
flow (1) |
110,828 |
|
171,210 |
|
105,796 |
|
472,983 |
|
347,641 |
|
| Per share
- basic |
0.20 |
|
0.46 |
|
0.45 |
|
1.35 |
|
1.48 |
|
| Per share
- diluted |
0.20 |
|
0.45 |
|
0.44 |
|
1.35 |
|
1.47 |
|
| Net income
(loss) |
(231,238 |
) |
27,412 |
|
76,038 |
|
(325,309 |
) |
87,174 |
|
| Per share
- basic |
(0.42 |
) |
0.07 |
|
0.32 |
|
(0.93 |
) |
0.37 |
|
| Per share
- diluted |
(0.42 |
) |
0.07 |
|
0.32 |
|
(0.93 |
) |
0.37 |
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
| Exploration and development expenditures (1) |
$ |
184,162 |
|
$ |
139,195 |
|
$ |
90,156 |
|
$ |
495,721 |
|
$ |
326,266 |
|
| Acquisitions, net of divestitures |
183 |
|
46 |
|
(3,937 |
) |
(1,818 |
) |
59,857 |
|
| Total oil and natural gas capital expenditures |
$ |
184,345 |
|
$ |
139,241 |
|
$ |
86,219 |
|
$ |
493,903 |
|
$ |
386,123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Net
Debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Bank loan (2) |
$ |
522,294 |
|
$ |
490,565 |
|
$ |
213,376 |
|
$ |
522,294 |
|
$ |
213,376 |
|
| Long-term notes (2) |
1,596,323 |
|
1,527,733 |
|
1,489,210 |
|
1,596,323 |
|
1,489,210 |
|
| Long-term debt |
2,118,617 |
|
2,018,298 |
|
1,702,586 |
|
2,118,617 |
|
1,702,586 |
|
| Working capital deficiency |
146,550 |
|
93,792 |
|
31,698 |
|
146,550 |
|
31,698 |
|
| Net debt (1) |
$ |
2,265,167 |
|
$ |
2,112,090 |
|
$ |
1,734,284 |
|
$ |
2,265,167 |
|
$ |
1,734,284 |
|
| |
|
|
|
|
|
| Shares
Outstanding - basic (thousands) |
|
|
|
|
|
| Weighted
average |
554,036 |
|
375,435 |
|
235,451 |
|
351,542 |
|
234,787 |
|
|
End of period |
554,060 |
|
553,950 |
|
235,451 |
|
554,060 |
|
235,451 |
|
| |
| |
|
|
Three Months Ended |
Years Ended |
|
|
December 31,2018 |
September 30,2018 |
December 31,2017 |
December 31,2018 |
December 31,2017 |
|
OPERATING |
|
|
|
|
|
| Daily
Production |
|
|
|
|
|
| Light oil
and condensate (bbl/d) |
44,987 |
|
29,731 |
|
21,229 |
|
29,264 |
|
21,314 |
|
| Heavy oil
(bbl/d) |
26,339 |
|
27,036 |
|
24,945 |
|
25,954 |
|
25,326 |
|
|
NGL (bbl/d) |
10,327 |
|
10,076 |
|
9,872 |
|
9,745 |
|
9,206 |
|
| Total
liquids (bbl/d) |
81,653 |
|
66,843 |
|
56,046 |
|
64,963 |
|
55,846 |
|
| Natural
gas (mcf/d) |
103,424 |
|
93,414 |
|
81,063 |
|
92,971 |
|
86,375 |
|
|
Oil equivalent (boe/d @ 6:1) (3) |
98,890 |
|
82,412 |
|
69,556 |
|
80,458 |
|
70,242 |
|
| |
|
|
|
|
|
|
Netback (thousands of Canadian dollars) |
|
|
|
|
|
| Total sales, net of
blending and other expense (4) |
$ |
344,682 |
|
$ |
417,213 |
|
$ |
286,370 |
|
$ |
1,360,038 |
|
$ |
1,040,522 |
|
|
Royalties |
(79,765 |
) |
(91,945 |
) |
(69,525 |
) |
(313,754 |
) |
(241,892 |
) |
| Operating
expense |
(97,857 |
) |
(77,698 |
) |
(69,837 |
) |
(311,592 |
) |
(269,283 |
) |
|
Transportation expense |
(10,994 |
) |
(9,520 |
) |
(7,658 |
) |
(36,869 |
) |
(33,985 |
) |
|
Operating netback |
$ |
156,066 |
|
$ |
238,050 |
|
$ |
139,350 |
|
$ |
697,823 |
|
$ |
495,362 |
|
| General
and administrative |
(14,096 |
) |
(10,158 |
) |
(9,717 |
) |
(45,825 |
) |
(47,389 |
) |
| Cash
financing and interest |
(27,933 |
) |
(26,343 |
) |
(24,849 |
) |
(104,318 |
) |
(100,482 |
) |
| Realized
financial derivatives (loss) gain |
(3,063 |
) |
(30,854 |
) |
1,898 |
|
(73,165 |
) |
7,616 |
|
| Other
(5) |
(146 |
) |
515 |
|
(886 |
) |
(1,532 |
) |
(7,466 |
) |
|
Adjusted funds flow (1) |
$ |
110,828 |
|
$ |
171,210 |
|
$ |
105,796 |
|
$ |
472,983 |
|
$ |
347,641 |
|
| |
|
|
|
|
|
|
Netback (per boe) |
|
|
|
|
|
| Total
sales, net of blending and other expense (4) |
$ |
37.89 |
|
$ |
55.03 |
|
$ |
44.75 |
|
$ |
46.31 |
|
$ |
40.58 |
|
|
Royalties |
(8.77 |
) |
(12.13 |
) |
(10.86 |
) |
(10.68 |
) |
(9.43 |
) |
| Operating
expense |
(10.76 |
) |
(10.25 |
) |
(10.91 |
) |
(10.61 |
) |
(10.50 |
) |
|
Transportation expense |
(1.21 |
) |
(1.26 |
) |
(1.20 |
) |
(1.26 |
) |
(1.33 |
) |
|
Operating netback (1) |
$ |
17.15 |
|
$ |
31.39 |
|
$ |
21.78 |
|
$ |
23.76 |
|
$ |
19.32 |
|
| General
and administrative |
(1.55 |
) |
(1.34 |
) |
(1.52 |
) |
(1.56 |
) |
(1.85 |
) |
| Cash
financing and interest |
(3.07 |
) |
(3.47 |
) |
(3.88 |
) |
(3.55 |
) |
(3.92 |
) |
| Realized
financial derivatives (loss) gain |
(0.34 |
) |
(4.07 |
) |
0.30 |
|
(2.49 |
) |
0.30 |
|
| Other
(5) |
(0.02 |
) |
0.07 |
|
(0.14 |
) |
(0.05 |
) |
(0.29 |
) |
|
Adjusted funds flow (1) |
$ |
12.17 |
|
$ |
22.58 |
|
$ |
16.54 |
|
$ |
16.11 |
|
$ |
13.56 |
|
Notes:
(1) The terms “adjusted funds flow”, “exploration and
development expenditures”, “net debt” and “operating netback” do
not have any standardized meaning as prescribed by Canadian
Generally Accepted Accounting Principles (“GAAP”) and therefore may
not be comparable to similar measures presented by other companies
where similar terminology is used. We refer you to the advisory on
non-GAAP measures at the end of this press release.(2) Principal
amount of instruments. The carrying amount of debt issue costs
associated with the 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 liquidity or repayment
obligations.(3) Barrel of oil equivalent ("boe") amounts have been
calculated using a conversion rate of six thousand cubic feet of
natural gas to one barrel of oil. The use of boe amounts may be
misleading, particularly if used in isolation. A boe conversion
ratio of six thousand cubic feet of natural gas to one barrel of
oil is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead.(4) Realized heavy oil prices are
calculated based on sales dollars, net of blending and other
expense. We include the cost of blending diluent in our realized
heavy oil sales price in order to compare the realized pricing on
our produced volumes to the WCS benchmark.(5) Other is comprised of
realized foreign exchange gain or loss, other income or expense,
current income tax expense or recovery and payments on onerous
contracts. Refer to the 2018 MD&A for further information on
these amounts.
Strategic Combination with Raging River
On August 22, 2018, we completed a strategic
combination with Raging River Exploration Inc. (“Raging River”) by
way of a plan of arrangement in which Baytex acquired all of the
issued and outstanding common shares of Raging River. The strategic
combination increased our light oil exposure and operational
control of our properties while strengthening our balance sheet.
The addition of these operated assets to our portfolio increased
our inventory of drilling prospects and our ability to effectively
allocate capital. Production from Raging River's properties is
approximately 90% light oil from the Viking and Duvernay areas. Our
2018 results include 132 days of operations from the Raging River
assets from August 22 to December 31.
In Q4/2018, production from the Raging River
assets averaged 26,035 boe/d (93% oil and NGL). Reserves associated
with the Raging River assets increased by 4% on a 2P basis to 111
mmboe, as compared to year-end 2017.
Operating Results
2018 was a defining year as we repositioned
Baytex as a North American crude oil producer with strong free cash
flow and an improved balance sheet. 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
operational targets.
Production averaged 98,890 boe/d (83% oil and
NGL) in Q4/2018, as compared to 82,412 boe/d (81% oil and NGL) in
Q3/2018 and 69,556 boe/d in Q4/2017. Production of 80,458 boe/d
(81% oil and NGL) for 2018 exceeded the high end of our production
guidance range of 79,000 to 80,000 boe/d. Production from the
legacy Baytex assets (excluding Raging River) averaged 72,855 boe/d
in Q4/2018 and 71,293 boe/d for 2018.
Exploration and development expenditures totaled
$184 million in Q4/2018 and $496 million for full-year 2018, in
line with our guidance range of $450-$500 million. We participated
in the completion of 353 (198.6 net) wells with a 99% success
rate during the year.
Eagle Ford and Viking Light Oil
Our Eagle Ford assets in South Texas is one of
the premier oil resource plays in North America. These assets
generate a strong operating netback and free cash flow and contain
a significant inventory of development prospects.
In 2018, we allocated 39% of our
exploration and development expenditures to these assets.
Production averaged 38,437 boe/d (78% liquids) during Q4/2018, as
compared to 37,198 boe/d in Q3/2018. Production for 2018 averaged
37,076 boe/d, as compared to 36,678 boe/d in 2017. In 2018, the
Eagle Ford generated an operating netback of $479 million and free
cash flow of $285 million.
We continue to see strong well performance
driven by enhanced completions in the oil window of our acreage. In
2018, we participated in the drilling of 91 (20.8 net) wells and
commenced production from 120 (26.2 net) wells. The wells that have
been on production for more than 30 days during 2018 established
30-day initial production rates of approximately 1,750 boe/d per
well (65% light oil and condensate), which represents an
approximate 20% improvement over 2017. During Q4/2018, we commenced
production from 31 (5.9 net) wells, which averaged 30-day initial
production rates of approximately 1,800 boe/d per well. Six of
these were new appraisal wells in our northern Austin Chalk
fracture trend and demonstrated 30-day initial production rates of
approximately 1,600 boe/d per well.
Our Viking asset is a shallow, light oil
resource play in western Canada. During Q4/2018, production from
the Viking averaged 23,784 boe/d (excluding heavy oil), up from
22,158 boe/d for the period August 22 to September 30. We
maintained a steady pace of development in Q4/2018 with five
drilling rigs and 1.5 frac crews executing our program, resulting
in 83 (65.5 net) wells. The extended reach horizontal results
continue to exceed expectations with multiple, previously untested
sections proving economic.
Heavy Oil
Our heavy oil assets at Peace River and
Lloydminster produced a combined 26,339 bbl/d during the fourth
quarter, as compared to 27,036 bbl/d in Q3/2018. The reduced
volumes reflect the optimization of our heavy oil program during
Q4/2018 due to volatile heavy oil prices, which was mitigated
somewhat by the addition of heavy oil assets acquired as part of
the Raging River combination.
Our Peace River assets are located in northwest
Alberta. 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
2018, we drilled 12 (12.0 net) oil wells with average 30‑day
initial production rates of approximately 500 boe/d per well. This
program included 8 (8.0 net) wells in our northern Seal
area which delivered approximately 25% higher 30-day initial
production rates than our field wide average. We deferred three
completions during Q4/2018 due to low heavy oil prices.
Our Lloydminster assets are 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 86 (61.9
net) oil wells in 2018. In addition, we successfully completed the
expansion of our Kerrobert thermal project with productive
capability increasing to approximately 2,000 bbl/d during
Q4/2018.
East Duvernay Shale Light Oil
We continue to prudently advance the delineation
of the East Duvernay Shale, an early stage, high operating netback
light oil resource play where we have amassed over 450 sections of
land. In 2018, our focus shifted to the Pembina area where we
control over 270 sections of 100% working interest land. With five
wells on production, we have delineated approximately 35 sections
representing 175 potential drilling opportunities. These wells
generated average 30‑day initial production rates of approximately
575 boe/d per well (88% liquids). During Q4/2018, production from
the East Duvernay Shale averaged 1,432 boe/d, up from
650 boe/d for the period August 22 to September 30.
Financial Review
Our financial results for Q4/2018 were
negatively impacted by the sharp decline in global benchmark crude
oil prices and the significant widening of Canadian light and heavy
oil differentials. In Q4/2018, the price for West Texas
Intermediate light oil (“WTI”) averaged US$58.81/bbl, as compared
to US$69.50/bbl in Q3/2018. The discount for Canadian heavy oil, as
measured by the price differential between Western Canadian Select
(“WCS”) and WTI, averaged US$39.42/bbl in Q4/2018 as compared to
US$22.25/bbl in Q3/2018. The discount for Canadian light oil, as
measured by the price differential between Canadian Mixed Sweet
Blend (“MSW”) and WTI, averaged US$26.51/bbl in Q4/2018 as compared
to US$6.82/bbl in Q3/2018.
As a result of the challenging pricing
environment, we generated adjusted funds flow of $111 million
($0.20 per basic share) in Q4/2018, compared to $171 million ($0.46
per basic share) in Q3/2018. Full-year adjusted funds flow was $473
million ($1.35 per basic share), compared to $348 million
($1.48 basic per share) in 2017.
We generated an operating netback $17.15/boe in
Q4/2018, as compared to $31.39/boe in Q3/2018 and $21.78/boe in
Q4/2017. The Eagle Ford generated an operating netback of
$35.42/boe during Q4/2018 while our Canadian operations generated
an operating netback of $5.54/boe.
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 Q4/2018, the price for LLS averaged US$66.64/bbl as
compared to US$75.25/bbl in Q3/2018. During Q4/2018, our light oil
and condensate realized price in the Eagle Ford of US$62.87/bbl (or
$83.28/bbl) represented a US$3.77/bbl discount to LLS.
The following table summarizes our operating
netbacks for the periods noted.
| |
Three Months Ended December 31 |
|
|
2018 |
2017 |
|
($ per boe except for production) |
Canada |
|
U.S. |
|
Total |
|
Canada |
|
U.S. |
|
Total |
|
| Production (boe/d) |
60,453 |
|
38,437 |
|
98,890 |
|
32,194 |
|
37,362 |
|
69,556 |
|
| |
|
|
|
|
|
|
| Total sales, net of
blending and other (1) |
$ |
24.04 |
|
$ |
59.66 |
|
$ |
37.89 |
|
$ |
36.89 |
|
$ |
51.53 |
|
$ |
44.75 |
|
|
Royalties |
(3.10 |
) |
(17.68 |
) |
(8.77 |
) |
(5.72 |
) |
(15.30 |
) |
(10.86 |
) |
| Operating
expense |
(13.42 |
) |
(6.56 |
) |
(10.76 |
) |
(16.57 |
) |
(6.04 |
) |
(10.91 |
) |
|
Transportation expense |
(1.98 |
) |
— |
|
(1.21 |
) |
(2.59 |
) |
— |
|
(1.20 |
) |
|
Operating netback (2) |
$ |
5.54 |
|
$ |
35.42 |
|
$ |
17.15 |
|
$ |
12.01 |
|
$ |
30.19 |
|
$ |
21.78 |
|
|
Realized financial derivatives (loss) gain |
— |
|
— |
|
(0.34 |
) |
— |
|
— |
|
0.30 |
|
|
Operating netback after financial derivatives |
$ |
5.54 |
|
$ |
35.42 |
|
$ |
16.81 |
|
$ |
12.01 |
|
$ |
30.19 |
|
$ |
22.08 |
|
Notes:
(1) 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.(2) 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. We refer you to the advisory on non-GAAP
measures at the end of this press release.
Financial Liquidity
We maintain strong financial liquidity with our
credit facilities approximately 50% undrawn and our first long-term
note maturity not until 2021. Our net debt totaled $2.265 billion
at December 31, 2018, which includes four series of long-term notes
that total $1.6 billion. Our credit facilities total approximately
$1.085 billion, comprised of US$575 million of revolving credit
facilities and a $300 million non-revolving term loan. The credit
facilities, which mature in June 2020, are not borrowing base
facilities and do not require annual or semi-annual reviews. We
expect to request an extension to the credit facilities in 2019.
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 $73 million in 2018, as compared to a gain of
$8 million in 2017.
For 2019, we have entered into hedges on
approximately 30% of our net crude oil exposure. This includes 25%
of our net WTI exposure with 2% fixed at US$62.85/bbl and 23%
hedged utilizing a 3-way option structure that provides a US$10/bbl
premium to WTI when WTI is at or below US$55.64/bbl and allows
upside participation to US$73.65/bbl. In addition, we have entered
into a Brent-based 3-way option structure for 3,000 bbl/d that
provides a US$10/bbl premium to Brent when Brent is at or below
US$59.50/bbl and allows upside participation to US$78.68/bbl. We
have also entered into hedges on approximately 24% of our net
natural gas exposure through a combination of AECO swaps at
C$2.37/mcf and NYMEX swaps at US$3.10/mmbtu.
Crude-by-rail is an integral part of our egress
and marketing strategy for our heavy oil production. For 2019, we
expect to deliver 11,000 bbl/d (approximately 40%) of our heavy oil
volumes to market by rail, up from 9,000 bbl/d in 2018. Commencing
January 1, 2019, approximately 70% of our crude by rail
commitments are WTI based contracts with no WCS pricing exposure.
In addition, we have entered into WCS differential hedges on
approximately 10% of our net heavy oil exposure at a WTI-WCS
differential of US$17.34/bbl.
A complete listing of our financial derivative
contracts can be found in Note 19 to our 2018 financial
statements.
Outlook for 2019
Stronger Commodity Prices
Following the pricing challenges of the fourth
quarter, global benchmark prices have recently improved with WTI
currently trading at US$57/bbl, as compared to a low of US$42/bbl
in December 2018. In addition, following the Government of
Alberta’s announcement on December 2, 2018 of temporary production
curtailments, Canadian light and heavy oil differentials have
narrowed substantially. In Q1/2019, the WTI-WCS price differential
averaged US$12.29/bbl and the WTI-MSW price differential averaged
US$4.85/bbl. This combination of improved WTI prices and the
narrowing of Canadian differentials are expected to have a positive
impact to our adjusted funds flow.
Free cash flow and debt repayment
Further deleveraging remains a top priority. For
2019, adjusted funds flow in excess of exploration and development
expenditures, leasing expenditures and asset retirement
obligations, will be used to reduce our indebtedness.
Based on the forward strip for 2019, our
adjusted funds flow forecast has increased by 32%, from $605
million in December 2018, to approximately $800 million, which will
support our debt reduction initiative. Our plan for year end is to
reduce our net debt to EBITDA ratio to approximately 2.2x. As we
continue to drive debt levels down, we will be positioned to
enhance shareholder returns through a combination of organic growth
through disciplined capital allocation, the reinstatement of a
dividend and/or share buybacks.
Corporate level production volumes are
strong
As a result of current activity levels,
excellent well performance in the Eagle Ford and outstanding
operating efficiency across all of our assets, Q1/2019 volumes are
trending above 97,000 boe/d.
Activity levels are on pace for $155 million
capex in Q1/2019
Approximately 33% of Q1/2019 corporate capital
investment is being directed to the Eagle Ford while 52% is
allocated to the Viking light oil assets. We continue to see
approximately 3 drilling rigs and 1.5 frac crews in the Eagle Ford
and 5 rigs and 1.5 completion crews in the Viking. With our usual
seasonal slowdown in Canada during the second quarter, this puts us
on track for the full year to drill approximately 245 net wells
(85% extended reach horizontals) in the Viking and bring
approximately 30 net wells on production in the Eagle Ford. We are
executing a small heavy oil development program through the first
half of 2019, with the potential to scale activity higher should
oil prices and visibility to egress improve.
East Shale Duvernay appraisal progress
In Q1/2019, we are drilling four wells at
Pembina with completion activities scheduled for Q2/2019.
Successful tests from the four wells will increase total delineated
Pembina acreage to 100 to 125 sections.
Guidance
Our 2019 production guidance range is unchanged
at 93,000 to 97,000 boe/d with budgeted exploration and development
capital expenditures of $550 to $650 million.
The following table summarizes our 2019 annual
guidance.
| Exploration and
development capital ($ millions) |
$550 - $650 |
|
| Production (boe/d) |
93,000 -
97,000 |
|
| |
|
|
| Adjusted Funds Flow ($
millions) (1) |
$800 |
|
| Adjusted Funds Flow per
Share (2) |
$1.42 |
|
| |
|
|
| Operating Netback
($/boe) (1) |
$26.00 |
|
| |
|
|
| Expenses: |
|
|
| Royalty
rate (%) |
20% |
|
| Operating
($/boe) |
$10.75 -
$11.25 |
|
|
Transportation ($/boe) |
$1.25 -
$1.35 |
|
| General
and administrative ($ millions) |
$44
($1.27/boe) |
|
| Interest
($ millions) |
$112
($3.23/boe) |
|
| |
|
|
| Leasing expenditures ($
millions) |
$7 |
|
| Asset
retirement obligations ($ millions) |
$17 |
|
(1) Pricing assumptions: WTI - US$57/bbl; LLS - US$63/bbl; WCS
differential - US$17/bbl; MSW differential – US$8/bbl, NYMEX Gas -
US$2.90/mcf; AECO Gas - $1.60/mcf and Exchange Rate (CAD/USD) -
1.32.(2) Based on weighted average common shares outstanding of 562
million.
The following table summarizes our 2019 adjusted
funds flow sensitivities to changes in commodity prices and the
CAD//USD exchange rate.
| |
ExcludingHedges($ millions) |
IncludingHedges ($ millions) |
|
| Change of US$1.00/bbl WTI crude oil |
$30.1 |
$24.2 |
|
| Change of US$1.00/bbl WCS heavy oil
differential |
$8.3 |
$8.3 |
|
| Change of US$1.00/bbl MSW light oil
differential |
$9.8 |
$9.8 |
|
| Change of US$0.25/mcf NYMEX natural gas |
$9.3 |
$7.4 |
|
| Change of $0.01 in the
CAD//USD exchange rate |
$8.1 |
$8.1 |
|
Board and Management
Changes
Baytex has an ongoing board renewal process led
by the Nominating and Governance Committee of the Board. As part of
this renewal process, Ray Chan and Gary Bugeaud have decided to not
stand for election as directors at our 2019 Annual Meeting of
Shareholders to be held in May 2019.
Mr. Chan has been instrumental in guiding Baytex
over the last twenty plus years, serving numerous executive
positions during this time, including nearly 10 years as Chairman.
Mr. Chan has always operated with the highest integrity. His hard
work, dedication and thoughtful guidance for the benefit of all
stakeholders is greatly appreciated.
Baytex would also like to thank Mr. Bugeaud, who
has been involved with Raging River and its predecessor companies
for the last 15 years.
Rick Ramsay, our Executive Vice President and
Chief Operating Officer, has elected to retire on April 5,
2019. Mr. Ramsay has been with Baytex since January 2010 and
has been a key leader for the organization, managing the successful
development of our Peace River assets and subsequently guiding all
of our North American operations. Baytex would like to thank
Mr. Ramsay for his outstanding contributions and wish him well in
retirement.
Jason Jaskela will assume the role of Executive
Vice President and Chief Operating Officer on April 5, 2019. Mr.
Jaskela is a professional engineer with 19 years of industry
experience. Previously, he was Chief Operating Officer of Raging
River from March 2014 until August 2018 and the Vice President,
Production from March 2012 until March 2014.
Year-end 2018 Reserves
Baytex's year-end 2018 proved and probable
reserves were evaluated by Sproule Associates Limited (“Sproule”),
Ryder Scott Company, L.P. (“Ryder Scott”) and GLJ Petroleum
Consultants (“GLJ”), all independent qualified reserves evaluators.
Sproule evaluated our Canadian reserves, other than the reserves
associated with our Duvernay assets. GLJ evaluated the reserves
associated with our Duvernay assets. Our United States properties
were evaluated by Ryder Scott. Each evaluator used Sproule's
December 31, 2018 forecast price and cost assumptions.
All of our oil and gas properties were evaluated
or audited in accordance with National Instrument 51-101 “Standards
of Disclosure for Oil and Gas Activities” (“NI 51-101”) and the
Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”).
Reserves associated with our thermal heavy oil projects at Peace
River, Gemini (Cold Lake) and Kerrobert have been classified as
bitumen. Complete reserves disclosure will be included in our
Annual Information Form for the year ended
December 31, 2018, which will be filed on or before March
31, 2019.
On August 22, 2018, Baytex and Raging River
completed a strategic combination. Our 2018 reserves report
reflects this strategic combination with a meaningful increase in
our light oil reserves in Canada.
2018 Highlights
- Proved developed producing ("PDP") reserves increased by 35%,
from 100 mmboe to 135 mmboe. Proved reserves (“1P”) increased by
23%, from 256 mmboe to 315 mmboe. Proved plus probable
reserves (“2P”) increased by 22%, from 432 mmboe to 527 mmboe.
- Reserves associated with the Raging River assets increased by
4% on a 2P basis to 111 mmboe, as compared to year-end 2017. The
Raging River combination enhanced the quality of Baytex’s reserves
base, adding high value light oil reserves in the Viking and
Duvernay.
- Replaced 106% of total 2018 production, adding 31 mmboe of 2P
reserves through development activities. Inclusive of the Raging
River transaction, replaced 422% of total 2018 production with 124
mmboe of 2P reserves additions.
- Reserves on a 1P basis are comprised of 83% oil and NGL (40%
light oil, 23% NGL’s, 16% heavy oil and 4% bitumen) and 17% natural
gas.
- PDP reserves represent 43% of 1P reserves (39% at year-end
2017) and 1P reserves represent 60% of 2P reserves (59% at year-end
2016).
- Finding and Development ("F&D") costs, including changes in
future development capital (“FDC”), were $15.82/boe for PDP
reserves and $20.11/boe for 2P reserves. Generated a PDP recycle
ratio of 1.5x based on our 2018 operating netback of
$23.76/boe.
- Finding, development and acquisition costs (“FD&A”) costs,
including changes in FDC, were $25.55/boe for 2P reserves.
- Baytex maintains a strong reserves life index (“RLI”) of 8.7
years based on 1P reserves and 14.6 years based on 2P reserves.
- At year-end, 2018, the present value of our reserves,
discounted at 10% before tax, is estimated to be $6.2 billion (as
compared to $4.1 billion at year-end 2017). The increase is largely
attributable to the Strategic Combination.
- Our net asset value at year-end 2018, discounted at 10%, is
estimated to be $7.27 per share. This is based on the estimated
reserves value of $6.2 billion plus a value for undeveloped
acreage, net of long-term debt, asset retirement obligations and
working capital.
Petroleum and Natural Gas Reserves as at December 31,
2018
The following table sets forth our gross and net
reserves volumes at December 31, 2018 by product type and
reserves category using Sproule's forecast prices and costs. Please
note that the data in the table may not add due to rounding.
|
CANADA |
|
Forecast Prices and Costs |
| |
|
Light and Medium Oil |
|
Tight Oil |
|
Heavy Oil |
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
| Reserves
Category |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
| Proved |
|
|
|
|
|
|
|
|
|
| Developed Producing |
|
30,987 |
29,089 |
|
740 |
652 |
|
24,922 |
20,092 |
| Developed
Non-Producing |
|
263 |
256 |
|
— |
— |
|
1,161 |
1,006 |
|
Undeveloped |
|
40,296 |
37,584 |
|
1,360 |
1,191 |
|
23,530 |
20,668 |
| Total Proved |
|
71,545 |
66,929 |
|
2,099 |
1,843 |
|
49,613 |
41,766 |
| Probable |
|
20,941 |
19,352 |
|
3,254 |
2,730 |
|
42,687 |
35,726 |
| Total Proved Plus
Probable |
|
92,487 |
86,281 |
|
5,353 |
4,572 |
|
92,301 |
77,492 |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
CANADA |
|
Forecast Prices and Costs |
| |
|
Bitumen |
|
Natural Gas Liquids(3) |
|
Conventional Natural Gas(4) |
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
| Reserves
Category |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
|
(mmcf) |
(mmcf) |
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
1,934 |
1,478 |
|
1,401 |
1,070 |
|
55,986 |
50,308 |
| Developed
Non-Producing |
|
7,746 |
7,008 |
|
3 |
3 |
|
1,943 |
1,533 |
|
Undeveloped |
|
3,126 |
2,712 |
|
1,628 |
1,340 |
|
52,628 |
47,699 |
| Total Proved |
|
12,805 |
11,198 |
|
3,032 |
2,412 |
|
110,557 |
99,540 |
| Probable |
|
55,545 |
43,284 |
|
3,848 |
3,013 |
|
98,032 |
87,376 |
| Total Proved Plus
Probable |
|
68,350 |
54,482 |
|
6,880 |
5,425 |
|
208,589 |
186,915 |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CANADA |
|
Forecast Prices and Costs |
|
| |
|
Shale Gas |
|
Oil Equivalent(5) |
|
|
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
|
| Reserves
Category |
|
(mmcf) |
(mmcfl) |
|
(mboe) |
(mboe) |
|
|
| Proved |
|
|
|
|
|
|
|
|
| Developed
Producing |
|
1,432 |
1,310 |
|
69,553 |
60,983 |
|
|
| Developed
Non-Producing |
|
— |
— |
|
9,497 |
8,528 |
|
|
|
Undeveloped |
|
1,890 |
1,724 |
|
79,026 |
71,732 |
|
|
| Total Proved |
|
3,321 |
3,034 |
|
158,075 |
141,243 |
|
|
| Probable |
|
5,506 |
4,968 |
|
143,532 |
119,495 |
|
|
| Total Proved Plus
Probable |
|
8,828 |
8,002 |
|
301,607 |
260,738 |
|
|
|
UNITED STATES |
|
Forecast Prices and Costs |
| |
|
Tight Oil |
|
Natural Gas Liquids(3) |
|
Shale Gas |
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
| Reserves
Category |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
|
(mmcf) |
(mmcf) |
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
18,348 |
13,445 |
|
31,512 |
23,309 |
|
66,901 |
49,572 |
| Developed
Non-Producing |
|
38 |
28 |
|
214 |
158 |
|
566 |
417 |
|
Undeveloped |
|
32,334 |
23,700 |
|
39,856 |
29,312 |
|
80,367 |
59,166 |
| Total Proved |
|
50,720 |
37,174 |
|
71,582 |
52,779 |
|
147,835 |
109,155 |
| Probable |
|
18,625 |
13,680 |
|
34,625 |
25,441 |
|
66,043 |
48,502 |
| Total Proved Plus
Probable |
|
69,345 |
50,854 |
|
106,207 |
78,220 |
|
213,878 |
157,657 |
|
UNITED STATES |
|
Forecast Prices and Costs |
|
| |
|
ConventionalNatural Gas(4) |
|
Oil Equivalent(5) |
|
|
|
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
|
|
| Reserves
Category |
|
(mmcf) |
(mmcf) |
|
(mboe) |
(mbbl) |
|
|
|
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
24,993 |
18,357 |
|
65,176 |
48,076 |
|
|
|
| Developed
Non-Producing |
|
49 |
36 |
|
354 |
261 |
|
|
|
|
Undeveloped |
|
32,506 |
23,803 |
|
91,002 |
66,841 |
|
|
|
| Total Proved |
|
57,548 |
42,197 |
|
156,532 |
115,178 |
|
|
|
| Probable |
|
24,652 |
18,147 |
|
68,366 |
50,229 |
|
|
|
| Total Proved Plus
Probable Possible |
|
82,200 |
60,344 |
|
224,898 |
165,407 |
|
|
|
|
TOTAL |
|
Forecast Prices and Costs |
| |
|
Light and Medium Oil |
|
Tight Oil |
|
Heavy Oil |
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
| Reserves
Category |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
30,987 |
29,089 |
|
19,088 |
14,097 |
|
24,922 |
20,092 |
| Developed
Non-Producing |
|
263 |
256 |
|
38 |
28 |
|
1,161 |
1,006 |
|
Undeveloped |
|
40,296 |
37,584 |
|
33,693 |
24,891 |
|
23,530 |
20,668 |
| Total Proved |
|
71,545 |
66,929 |
|
52,819 |
39,016 |
|
49,613 |
41,766 |
| Probable |
|
20,941 |
19,352 |
|
21,879 |
16,410 |
|
42,687 |
35,726 |
| Total Proved Plus
Probable |
|
92,487 |
86,281 |
|
74,698 |
55,426 |
|
92,301 |
77,492 |
| |
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
TOTAL |
|
Forecast Prices and Costs |
| |
|
Bitumen |
|
Natural Gas Liquids(3) |
|
Shale Gas |
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
| Reserves
Category |
|
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
|
(mmcf) |
(mmcf) |
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
1,934 |
1,478 |
|
32,912 |
24,379 |
|
68,333 |
50,882 |
| Developed
Non-Producing |
|
7,746 |
7,008 |
|
217 |
160 |
|
566 |
417 |
|
Undeveloped |
|
3,126 |
2,712 |
|
41,484 |
30,652 |
|
82,257 |
60,890 |
| Total Proved |
|
12,805 |
11,198 |
|
74,614 |
55,191 |
|
151,156 |
112,188 |
| Probable |
|
55,545 |
43,284 |
|
38,473 |
28,454 |
|
71,550 |
53,471 |
| Total Proved Plus
Probable |
|
68,350 |
54,482 |
|
113,087 |
83,645 |
|
222,706 |
165,659 |
|
TOTAL |
|
Forecast Prices and Costs |
| |
|
Conventional Natural Gas(4) |
|
Oil Equivalent(5) |
|
|
|
| |
|
Gross(1) |
Net(2) |
|
Gross(1) |
Net(2) |
|
|
|
| Reserves
Category |
|
(mmcf) |
(mmcf) |
|
(mboe) |
(mboe) |
|
|
|
| Proved |
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
80,980 |
68,665 |
|
134,729 |
109,059 |
|
|
|
| Developed
Non-Producing |
|
1,991 |
1,569 |
|
9,851 |
8,789 |
|
|
|
|
Undeveloped |
|
85,133 |
71,502 |
|
170,028 |
138,572 |
|
|
|
| Total Proved |
|
168,104 |
141,736 |
|
314,607 |
256,421 |
|
|
|
| Probable |
|
122,685 |
105,523 |
|
211,898 |
169,724 |
|
|
|
| Total Proved Plus
Probable |
|
290,789 |
247,259 |
|
526,505 |
426,145 |
|
|
|
Notes:
(1) “Gross” reserves means the total working and royalty
interest share of remaining recoverable reserves owned by Baytex
before deductions of royalties payable to others.(2) “Net” reserves
means Baytex's gross reserves less all royalties payable to
others.(3) Natural Gas Liquids includes condensate.(4) Conventional
Natural Gas includes associated, non-associated and solution
gas.(5) 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.
Reserves Reconciliation
The following table reconciles the
year-over-year changes in our gross reserves volumes by product
type and reserves category using Sproule's forecast prices and
costs. Please note that the data in table may not add due to
rounding.
| |
|
Reconciliation of Gross Reserves
(1)(2)By Principal Product Type Forecast Prices
and Costs |
| |
|
Heavy Oil |
|
Bitumen |
| |
|
Proved |
Probable |
Proved +Probable |
|
Proved |
Probable |
Proved +Probable |
|
Gross Reserves Category |
|
(mbbl) |
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
(mbbl) |
| December 31,
2017 |
|
46,706 |
|
39,757 |
|
86,463 |
|
|
13,266 |
|
55,726 |
|
68,992 |
|
| Extensions |
|
1,282 |
|
690 |
|
1,972 |
|
|
— |
|
— |
|
— |
|
| Infill Drilling |
|
1,346 |
|
905 |
|
2,251 |
|
|
— |
|
— |
|
— |
|
| Improved
Recoveries |
|
1,952 |
|
4,621 |
|
6,574 |
|
|
— |
|
— |
|
— |
|
| Technical Revisions
(3) |
|
4,315 |
|
(4,922 |
) |
(607 |
) |
|
(205 |
) |
(178 |
) |
(382 |
) |
| Discoveries |
|
2 |
|
2 |
|
4 |
|
|
— |
|
— |
|
— |
|
| Acquisitions (4) |
|
3,080 |
|
1,522 |
|
4,602 |
|
|
— |
|
— |
|
— |
|
| Dispositions |
|
(1 |
) |
(2 |
) |
(2 |
) |
|
— |
|
— |
|
— |
|
| Economic Factors |
|
149 |
|
114 |
|
262 |
|
|
— |
|
(3 |
) |
(3 |
) |
| Production |
|
(9,218 |
) |
— |
|
(9,218 |
) |
|
(256 |
) |
— |
|
(256 |
) |
| December 31,
2018 |
|
49,613 |
|
42,687 |
|
92,301 |
|
|
12,805 |
|
55,545 |
|
68,350 |
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
Light and Medium Crude Oil |
|
Tight Oil |
| |
|
Proved |
Probable |
Proved +Probable |
|
Proved |
Probable |
Proved +Probable |
|
Gross Reserves Category |
|
(mbbl) |
(mbbl) |
(mbbl) |
|
(mbbl) |
(mbbl) |
(mbbl) |
| December 31,
2017 |
|
1,608 |
|
1,225 |
|
2,833 |
|
|
50,296 |
|
11,390 |
|
61,686 |
|
| Extensions (4) |
|
— |
|
— |
|
— |
|
|
1,515 |
|
2,645 |
|
4,160 |
|
| Infill Drilling
(4) |
|
10,823 |
|
2,856 |
|
13,679 |
|
|
1,062 |
|
147 |
|
1,209 |
|
| Improved
Recoveries |
|
— |
|
— |
|
— |
|
|
— |
|
— |
|
— |
|
| Technical Revisions
(3) |
|
273 |
|
(381 |
) |
(109 |
) |
|
5,285 |
|
7,154 |
|
12,438 |
|
| Discoveries |
|
— |
|
— |
|
— |
|
|
65 |
|
15 |
|
80 |
|
| Acquisitions (4) |
|
61,992 |
|
17,234 |
|
79,226 |
|
|
625 |
|
594 |
|
1,219 |
|
| Dispositions |
|
— |
|
— |
|
— |
|
|
— |
|
— |
|
— |
|
| Economic Factors |
|
15 |
|
8 |
|
23 |
|
|
(175 |
) |
(65 |
) |
(240 |
) |
| Production |
|
(3,165 |
) |
— |
|
(3,165 |
) |
|
(5,854 |
) |
— |
|
(5,854 |
) |
| December 31,
2018 |
|
71,545 |
|
20,941 |
|
92,487 |
|
|
52,819 |
|
21,879 |
|
74,698 |
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
Natural Gas Liquids(5) |
|
Shale Gas |
| |
|
Proved |
Probable |
Proved +Probable |
|
Proved |
Probable |
Proved +Probable |
|
Gross Reserves Category |
|
(mbbl) |
(mbbl) |
(mbbl) |
|
(mmcf) |
(mmcf) |
(mmcf) |
| December 31,
2017 |
|
84,564 |
|
38,962 |
|
123,526 |
|
|
172,855 |
|
75,686 |
|
248,541 |
|
| Extensions (4) |
|
644 |
|
1,173 |
|
1,817 |
|
|
2,582 |
|
4,681 |
|
7,262 |
|
| Infill Drilling |
|
534 |
|
109 |
|
643 |
|
|
407 |
|
121 |
|
528 |
|
| Improved
Recoveries |
|
— |
|
— |
|
— |
|
|
— |
|
— |
|
— |
|
| Technical Revisions
(3) |
|
(5,742 |
) |
(1,716 |
) |
(7,458 |
) |
|
(10,715 |
) |
(9,111 |
) |
(19,826 |
) |
| Discoveries |
|
12 |
|
3 |
|
15 |
|
|
73 |
|
17 |
|
90 |
|
| Acquisitions (4) |
|
349 |
|
256 |
|
605 |
|
|
790 |
|
809 |
|
1,599 |
|
| Dispositions |
|
— |
|
— |
|
— |
|
|
— |
|
— |
|
— |
|
| Economic Factors |
|
(528 |
) |
(314 |
) |
(841 |
) |
|
(1,133 |
) |
(652 |
) |
(1,785 |
) |
| Production |
|
(5,220 |
) |
— |
|
(5,220 |
) |
|
(13,702 |
) |
— |
|
(13,702 |
) |
| December 31,
2018 |
|
74,614 |
|
38,473 |
|
113,087 |
|
|
151,156 |
|
71,550 |
|
222,706 |
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
Conventional Natural Gas(6) |
|
Oil Equivalent(7) |
| |
|
Proved |
Probable |
Proved +Probable |
|
Proved |
Probable |
Proved +Probable |
|
Gross Reserves Category |
|
(mmcf) |
(mmcf) |
(mmcf) |
|
(mboe) |
(mboe) |
(mboe) |
| December 31,
2017 |
|
181,837 |
|
100,724 |
|
282,560 |
|
|
255,556 |
|
176,461 |
|
432,017 |
|
| Extensions (4) |
|
66 |
|
185 |
|
251 |
|
|
3,882 |
|
5,319 |
|
9,201 |
|
| Infill Drilling
(4) |
|
6,055 |
|
1,643 |
|
7,699 |
|
|
14,842 |
|
4,311 |
|
19,153 |
|
| Improved
Recoveries |
|
— |
|
— |
|
— |
|
|
1,952 |
|
4,621 |
|
6,574 |
|
| Technical Revisions
(3) |
|
(24,918 |
) |
9,915 |
|
(15,004 |
) |
|
(2,013 |
) |
91 |
|
(1,922 |
) |
| Discoveries |
|
— |
|
— |
|
— |
|
|
92 |
|
22 |
|
114 |
|
| Acquisitions (4) |
|
28,494 |
|
11,812 |
|
40,306 |
|
|
70,926 |
|
21,709 |
|
92,635 |
|
| Dispositions |
|
— |
|
— |
|
— |
|
|
(1 |
) |
(2 |
) |
(2 |
) |
| Economic Factors |
|
(3,197 |
) |
(1,593 |
) |
(4,790 |
) |
|
(1,261 |
) |
(635 |
) |
(1,896 |
) |
| Production |
|
(20,232 |
) |
— |
|
(20,232 |
) |
|
(29,368 |
) |
— |
|
(29,368 |
) |
| December 31,
2018 |
|
168,104 |
|
122,685 |
|
290,789 |
|
|
314,607 |
|
211,898 |
|
526,505 |
|
Notes:
(1) “Gross” reserves means the total working and royalty
interest share of remaining recoverable reserves owned by Baytex
before deductions of royalties payable to others.(2) Reserves
information as at December 31, 2018 and 2017 is prepared in
accordance with NI 51-101.(3) Negative technical revisions for
conventional natural gas are largely the result of adjustments to
our gas conservation bookings in Peace River area and reduced type
well profiles in our Canadian conventional natural gas properties.
Positive technical revisions for tight oil are the result of
enhanced type well profiles on our Eagle Ford acreage, as well as
the reclassification of some natural gas liquids volumes to tight
oil. Negative technical revisions for shale gas and natural gas
liquids are the result of the removal of certain drilling locations
on our Eagle Ford acreage as well as reclassification of shale gas
volumes to solution gas. (4) Acquisitions are principally
attributable to reserves associated with the Raging River
combination. For light and medium crude oil and tight oil, reserves
associated with the Raging River assets are captured within
acquisitions, extensions and infill drilling. Total proved reserves
of 11.5 mmboe and total proved plus probable reserves of 14.6 mmboe
of the infill drilling additions are associated with the Raging
River Acquisition. Total proved reserves of 2.6 mmboe and total
proved plus probable reserves of 7.2 mmboe of the extensions
additions are associated with the Raging River Acquisition.
(5) Natural gas liquids include condensate.(6) Conventional
natural gas includes associated, non-associated and solution
gas.(7) 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.
Reserves Life Index
The following table sets forth our reserves life
index, which is calculated by dividing our proved and proved plus
probable reserves at year-end 2018 by annualized Q4/2018
production.
| |
|
Q4/2018 Actual |
|
Reserves Life Index (years) |
|
| |
|
Production |
|
Proved |
|
Proved
Plus Probable |
|
| |
Oil and NGL
(bbl/d) |
81,653 |
|
8.8 |
|
14.8 |
|
| |
Natural Gas
(mcf/d) |
103,424 |
|
8.5 |
|
13.6 |
|
| |
Oil Equivalent
(boe/d) |
98,890 |
|
8.7 |
|
14.6 |
|
Capital Program Efficiency
Based on the evaluation of our petroleum and
natural gas reserves prepared in accordance with NI 51-101 by our
independent qualified reserves evaluators, the efficiency of our
capital program is summarized in the following table.
| |
2018 |
|
2017 |
|
2016 |
|
Three-Year Total /
Average2016 - 2018 |
| |
|
|
|
|
|
|
|
| Capital Expenditures ($
millions) |
|
|
|
|
|
| Exploration and
development |
$ |
495.7 |
|
$ |
326.3 |
|
$ |
224.8 |
|
$ |
1,046.8 |
|
Acquisitions (net of dispositions) |
1,603.9 |
|
59.9 |
|
(63.6) |
|
1,600.2 |
|
Total |
$ |
2,099.6 |
|
$ |
386.1 |
|
$ |
161.2 |
|
$ |
2,646.9 |
| |
|
|
|
|
|
|
|
| Change in Future
Development Costs – 1P ($ millions) |
|
|
|
|
|
|
|
|
Exploration and development |
$ |
117.4 |
|
$ |
(132.6) |
|
$ |
(219.4) |
|
$ |
(234.6) |
|
Acquisitions (net of dispositions) |
|
870.0 |
|
|
35.5 |
|
|
7.6 |
|
|
913.1 |
|
Total |
$ |
987.4 |
|
$ |
(97.1) |
|
$ |
(211.8) |
|
$ |
678.4 |
| |
|
|
|
|
|
|
|
| Change in
Future Development Costs – 2P ($ millions) |
|
|
|
|
|
|
|
Exploration and Development |
$ |
132.3 |
|
$ |
(76.4) |
|
$ |
108.8 |
|
$ |
164.7 |
|
Acquisitions (net of dispositions) |
932.2 |
|
160.6 |
|
1.9 |
|
1,094.6 |
|
Total |
$ |
1,064.5 |
|
$ |
84.2 |
|
$ |
110.7 |
|
$ |
1,259.4 |
| |
|
|
|
|
|
|
|
| PDP Reserves Additions
(mboe) |
|
|
|
|
|
|
|
|
Exploration and development |
31,330 |
|
23,752 |
|
17,120 |
|
72,202 |
|
Acquisitions (net of dispositions) |
32,398 |
|
3,711 |
|
(1,710) |
|
34,399 |
|
Total |
63,728 |
|
27,463 |
|
15,410 |
|
106,601 |
| |
|
|
|
|
|
|
|
| 1P Reserves Additions
(mboe) |
|
|
|
|
|
|
|
|
Exploration and development |
17,494 |
|
21,695 |
|
5,041 |
|
44,243 |
|
Acquisitions (net of dispositions) |
70,925 |
|
6,821 |
|
(1,564) |
|
76,168 |
|
Total |
88,419 |
|
28,516 |
|
3,477 |
|
120,411 |
| |
|
|
|
|
|
|
|
| 2P Reserves Additions
(mboe) |
|
|
|
|
|
|
|
|
Exploration and development |
31,224 |
|
34,398 |
|
17,253 |
|
82,895 |
|
Acquisitions (net of dispositions) |
92,633 |
|
17,204 |
|
(2,408) |
|
107,409 |
|
Total |
123,857 |
|
51,602 |
|
14,845 |
|
190,304 |
| |
|
|
|
|
|
|
|
| F&D costs ($/boe)
(1) |
|
|
|
|
|
|
|
| PDP |
$ |
15.82 |
|
$ |
13.73 |
|
$ |
13.14 |
|
$ |
14.50 |
| 1P |
$ |
35.05 |
|
$ |
8.93 |
|
$ |
1.07 |
|
$ |
18.36 |
| 2P |
$ |
20.11 |
|
$ |
7.26 |
|
$ |
19.33 |
|
$ |
14.61 |
| |
|
|
|
|
|
|
|
| FD&A costs ($/boe)
(2) |
|
|
|
|
|
|
|
| PDP |
$ |
32.95 |
|
$ |
14.06 |
|
$ |
10.50 |
|
$ |
24.83 |
| 1P |
$ |
34.91 |
|
$ |
10.13 |
|
$ |
—
(5) |
|
$ |
27.62 |
| 2P |
$ |
25.55 |
|
$ |
9.11 |
|
$ |
18.33 |
|
$ |
20.53 |
| |
|
|
|
|
|
|
|
| Ratios (based on 2P
reserves) |
|
|
|
|
|
|
|
|
Production replacement ratio (3) |
422% |
|
201% |
|
58% |
|
237% |
| Recycle
ratio (4) |
1.2x |
|
2.7x |
|
0.9x |
|
1.6x |
Notes:
(1) F&D costs are calculated as total exploration and
development expenditures (excluding acquisition and divestitures
and including the change in FDC) divided by reserves additions from
exploration and development activity.(2) FD&A costs are
calculated as total capital expenditures (including acquisition and
divestitures and the change in FDC) divided by total reserves
additions.(3) Production Replacement Ratio is calculated as total
reserves additions divided by total annual production (including
acquisitions and divestitures).(4) Recycle Ratio is calculated as
operating netback divided by 2P F&D costs. Operating netback is
calculated as revenue less royalties, operating expenses and
transportation expenses.(5) 2016 FD&A costs (1P) were negative
due to the reduction in estimated Future Development Costs.
Net Present Value of Reserves (Forecast Prices and
Costs)
The following table summarizes our independent
reserves evaluators estimates of the net present value before
income taxes of the future net revenue attributable to our reserves
using Sproule's forecast prices and costs (and excluding the impact
of any hedging activities). Please note that the data in the table
may not add due to rounding.
| |
|
Summary of Net Present Value of Future Net
RevenueAs at December 31,
2018Forecast Prices and
CostsBefore Income Taxes and Discounted at
(%/year) |
|
CANADA |
|
|
| |
|
0% |
|
5% |
|
10% |
|
15% |
|
20% |
| Reserves
Category |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
| Proved |
|
|
|
|
|
|
|
|
|
|
| Developed Producing |
|
$ |
1,792,884 |
|
$ |
1,544,771 |
|
$ |
1,355,997 |
|
$ |
1,212,741 |
|
$ |
1,101,425 |
| Developed
Non-Producing |
|
244,486 |
|
172,472 |
|
125,171 |
|
93,194 |
|
70,965 |
|
Undeveloped |
|
1,841,321 |
|
1,279,571 |
|
907,327 |
|
654,251 |
|
476,320 |
| Total Proved |
|
3,878,692 |
|
2,996,814 |
|
2,388,494 |
|
1,960,186 |
|
1,648,709 |
| Probable |
|
3,862,671 |
|
2,304,632 |
|
1,538,566 |
|
1,108,674 |
|
841,887 |
| Total Proved Plus
Probable |
|
$ |
7,741,363 |
|
$ |
5,301,446 |
|
$ |
3,927,060 |
|
$ |
3,068,859 |
|
$ |
2,490,597 |
| |
|
|
| |
|
|
|
UNITED STATES |
|
|
| |
|
0% |
|
5% |
|
10% |
|
15% |
|
20% |
| Reserves
Category |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
| Proved |
|
|
|
|
|
|
|
|
|
|
| Developed
Producing |
|
$ |
1,627,506 |
|
$ |
1,192,348 |
|
$ |
961,733 |
|
$ |
820,072 |
|
$ |
723,542 |
| Developed
Non-Producing |
|
8,652 |
|
6,491 |
|
5,164 |
|
4,286 |
|
3,667 |
|
Undeveloped |
|
1,667,167 |
|
1,099,049 |
|
759,576 |
|
542,510 |
|
396,760 |
| Total Proved |
|
3,303,324 |
|
2,297,888 |
|
1,726,473 |
|
1,366,868 |
|
1,123,969 |
| Probable |
|
1,750,388 |
|
901,795 |
|
531,484 |
|
343,816 |
|
238,512 |
| Total Proved Plus
Probable |
|
|
5,053,712 |
|
|
3,199,683 |
|
|
2,257,957 |
|
|
1,710,684 |
|
|
1,362,481 |
|
TOTAL |
|
|
| |
|
0% |
|
5% |
|
10% |
|
15% |
|
20% |
| Reserves
Category |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
|
($000s) |
| Proved |
|
|
|
|
|
|
|
|
|
|
| Developed Producing |
|
$ |
3,420,390 |
|
$ |
2,737,119 |
|
$ |
2,317,729 |
|
$ |
2,032,813 |
|
$ |
1,824,967 |
| Developed
Non-Producing |
|
253,138 |
|
178,963 |
|
130,335 |
|
97,480 |
|
74,631 |
|
Undeveloped |
|
3,508,488 |
|
2,378,620 |
|
1,666,903 |
|
1,196,760 |
|
873,080 |
| Total Proved |
|
7,182,016 |
|
5,294,702 |
|
4,114,967 |
|
3,327,054 |
|
2,772,678 |
| Probable |
|
5,613,059 |
|
3,206,427 |
|
2,070,050 |
|
1,452,489 |
|
1,080,399 |
| Total Proved Plus
Probable |
|
|
12,795,075 |
|
|
8,501,129 |
|
|
6,185,017 |
|
|
4,779,543 |
|
|
3,853,078 |
|
|
Sproule Forecast Prices and Costs
The following table summarizes the forecast
prices used in preparing the estimated reserves volumes and the net
present values of future net revenues at December 31,
2018.
|
Year |
WTICushingUS$/bbl |
LLSOnshoreUS$/bbl |
CanadianLightSweet$/bbl |
WesternCanada SelectC$/bbl |
Henry
HubUS$/MMbtu |
AECOC SpotC$/MMbtu |
OperatingCost Inflation
Rate%/Yr |
CapitalCostInflation
Rate%/Yr |
ExchangeRate$US/$Cdn |
| 2018
act. |
65.04 |
70.14 |
68.63 |
52.64 |
3.11 |
1.52 |
2.5 |
4.2 |
0.77 |
|
2019 |
63.00 |
68.40 |
75.27 |
59.47 |
3.00 |
1.95 |
0.0 |
0.0 |
0.77 |
|
2020 |
67.00 |
70.37 |
77.89 |
62.31 |
3.25 |
2.44 |
2.0 |
2.0 |
0.80 |
|
2021 |
70.00 |
71.34 |
82.25 |
67.45 |
3.50 |
3.00 |
2.0 |
2.0 |
0.80 |
|
2022 |
71.40 |
72.76 |
84.79 |
69.53 |
3.57 |
3.21 |
2.0 |
2.0 |
0.80 |
|
2023 |
72.83 |
74.22 |
87.39 |
71.66 |
3.64 |
3.30 |
2.0 |
2.0 |
0.80 |
|
2024 |
74.28 |
75.70 |
89.14 |
73.10 |
3.71 |
3.39 |
2.0 |
2.0 |
0.80 |
|
2025 |
75.77 |
77.22 |
90.92 |
74.56 |
3.79 |
3.49 |
2.0 |
2.0 |
0.80 |
|
2026 |
77.29 |
78.76 |
92.74 |
76.05 |
3.86 |
3.58 |
2.0 |
2.0 |
0.80 |
|
2027 |
78.83 |
80.34 |
94.60 |
77.57 |
3.94 |
3.68 |
2.0 |
2.0 |
0.80 |
|
2028 |
80.41 |
81.94 |
96.49 |
79.12 |
4.02 |
3.78 |
2.0 |
2.0 |
0.80 |
|
2029 |
82.02 |
83.58 |
98.42 |
80.70 |
4.10 |
3.88 |
2.0 |
2.0 |
0.80 |
|
Thereafter |
Escalation rate of 2.0% |
Future Development Costs
The following table sets forth future
development costs deducted in the estimation of the future net
revenue attributable to the reserves categories noted below.
| |
|
Future Development CostsAs of
December 31, 2018Forecast Prices and
Costs($000s) |
| |
|
|
| |
|
CANADA |
|
|
UNITED STATES |
|
|
TOTAL |
| |
|
ProvedReserves |
|
Proved
plusProbableReserves |
|
|
ProvedReserves |
|
Proved
plusProbableReserves |
|
|
ProvedReserves |
|
Proved
plusProbableReserves |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 |
|
302,027 |
|
361,583 |
|
|
129,181 |
|
144,727 |
|
|
431,208 |
|
506,309 |
|
2020 |
|
457,359 |
|
633,766 |
|
|
292,260 |
|
292,260 |
|
|
749,619 |
|
926,025 |
|
2021 |
|
400,568 |
|
487,702 |
|
|
264,263 |
|
264,263 |
|
|
664,831 |
|
751,965 |
|
2022 |
|
276,701 |
|
451,347 |
|
|
273,975 |
|
273,975 |
|
|
550,676 |
|
725,323 |
|
2023 |
|
10,499 |
|
216,289 |
|
|
240,502 |
|
241,144 |
|
|
251,002 |
|
457,433 |
|
Remaining |
|
1,414 |
|
308,388 |
|
|
16,398 |
|
559,839 |
|
|
17,812 |
|
868,227 |
| Total
(undiscounted) |
|
1,448,569 |
|
2,459,074 |
|
|
1,216,580 |
|
1,776,209 |
|
|
2,665,148 |
|
4,235,283 |
Properties with No Attributed
Reserves
The following table sets forth our undeveloped
land holdings as at December 31, 2018.
| |
Undeveloped Acres |
|
| |
Gross |
|
Net |
|
|
|
|
|
|
|
|
Alberta |
1,054,743 |
|
964,579 |
|
|
Saskatchewan |
369,366 |
|
329,641 |
|
|
Total |
1,424,109 |
|
1,294,220 |
|
| |
|
|
|
|
Undeveloped land holdings are lands that have not been assigned
reserves as at December 31, 2018. We estimate the value of
our net undeveloped land holdings at December 31, 2018 to be
approximately $164.6 million, as compared to $75.9 million as at
December 31, 2017. This internal evaluation generally represents
the estimated replacement cost of our undeveloped land, excluding
the approximately 98,952 net acres of our undeveloped land that we
expect to expire on or before December 31, 2019. In
determining replacement cost, we analyzed land sale prices paid at
Provincial Crown land sales for properties in the vicinity of our
undeveloped land holdings.
Net Asset Value
Our estimated net asset value is based on the
estimated net present value of all future net revenue from our
reserves, before income taxes, as estimated by the Company's
independent reserves engineers at year-end, plus the estimated
value of our undeveloped land holdings, less asset retirement
obligations, long-term debt and net working capital. This
calculation can vary significantly depending on the oil and natural
gas price assumptions. In addition, this calculation does not
consider "going concern" value and assumes only the reserves
identified in the reserves reports with no further acquisitions or
incremental development.
The following table sets forth our net asset
value as at December 31, 2018.
|
|
Net Asset ValueForecast
Prices and CostsBefore Income Taxes and Discounted
at (%/year) |
|
| ($
millions except per share amounts) |
5% |
|
10% |
|
15% |
|
| |
|
|
|
|
|
|
| Total net present value
of proved plus probable reserves (before tax) |
$ |
8,501 |
|
|
$ |
6,185 |
|
|
$ |
4,780 |
|
|
| Undeveloped land
holdings (1) |
165 |
|
|
165 |
|
|
165 |
|
|
| Asset retirement
obligations (2) |
(147 |
) |
|
(57 |
) |
|
(36 |
) |
|
| Net debt |
(2,265 |
) |
|
(2,265 |
) |
|
(2,265 |
) |
|
| Net Asset Value |
$ |
6,254 |
|
|
$ |
4,028 |
|
|
$ |
2,644 |
|
|
| Net Asset Value per
Share (3) |
$ |
11.29 |
|
|
$ |
7.27 |
|
|
$ |
4.77 |
|
|
Notes:
(1) The value of undeveloped land holdings generally represents
the estimated replacement cost of our undeveloped land. (2) Asset
retirement obligations may not equal the amount shown on the
statement of financial position as a portion of these costs are
already reflected in the present value of proved plus probable
reserves and the discount rates applied differ.(3) Based on 554.1
million common shares outstanding as at December 31, 2018.
Additional Information
Our audited consolidated financial statements
for the year ended December 31, 2018 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 Today9:00 a.m. MST (11:00
a.m. EST) |
|
|
|
Baytex will host a conference call today, March 6, 2019, 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/baytexq420190306.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 current oil prices
will have a very positive impact on our adjusted funds flow; that
we will strengthen our balance sheet in 2019; the trend for our
production volumes; our expected Q1/2019 capital expenditures; that
80% of our capital spending will be directed to high operating
netback assets in the Eagle Ford and Viking; our forecast adjusted
funds flow, debt repayment, production and net debt to EBITDA ratio
for 2019; that 90% of our production is the Viking and Duvernay is
light oil; that 2018 repositioned us to have strong free cash
flow; 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 our extended reach horizontal wells are economic;
that our Peace River assets generate some of the strongest capital
efficiencies in the oil and gas industry; that we continue to
prudently advance the delineation of our East Duvernay Shale
assets; that we expect to request an extension to our credit
facilities in 2019; our ability to partially reduce the volatility
in our adjusted funds flow by utilizing financial derivative
contracts for commodity prices, foreign exchange rates and interest
rates; the percentage of our net crude oil and natural gas exposure
that is hedged for 2019 and the amount and percentage of heavy oil
production we expect to delivery by crude by rail and the
percentage of crude by rail deliveries that do not have WCS
exposure; the expected impact of improved pricing on our adjusted
funds flow; that deleveraging remains a priority and our
planned uses for adjusted funds flow in 2019; for the Eagle Ford
and Viking in Q1/2019: the percentage of our capital spending
directed to the assets and the number of drilling rigs and frac
crews on our lands; the number of wells to be drilled in the
Viking in 2019; the number of wells to be brought on production in
the Eagle Ford in 2019; that we will execute a small heavy oil
program in the first half of 2019 that could move higher if prices
and egress improve; for the East Duvernay Shale in 2019: that we
will continue to prudently advance its evaluation, that we will
drill four wells in Q1/2019 that if successful will delineate 100
to 125 sections of land; our 2019 production, capital
expenditure guidance, adjusted funds flow, adjusted funds flow per
share and operating netback guidance; our expected royalty rate and
operating, transportation, general and administration and interest
expenses for 2019; our expected leasing expenditures and asset
retirement obligation spending for 2019; the sensitivity of our
2019 Adjusted Funds Flow to changes in WTI, WCS, MSW and NYMEX
prices and the C$/US$ exchange rate; our reserves life index; the
net present value before income taxes of the future net revenue
attributable to our reserves; forecast prices for petroleum and
natural gas; forecast inflation and exchange rates; future
development costs; the value of our undeveloped land holdings and
our estimated net asset value. 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 described exist in quantities predicted or estimated, and
that they can be profitably produced in the future.
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, 2018, to be filed with Canadian securities regulatory
authorities and the U.S. Securities and Exchange Commission not
later than March 31, 2019 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
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 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. Transaction costs associated with the Raging
River combination are excluded from adjusted funds flow as we
consider the costs non-recurring and not reflective of our ability
to generate adjusted funds flow on an ongoing 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 months and year ended
December 31, 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 expenditures required to
offset production declines on an annual basis and maintain flat
production volumes.
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. 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.
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 and provides a key measure to
assess our liquidity. The current portion of financial derivatives
is excluded as the valuation of the underlying contracts is subject
to a high degree of volatility prior to the ultimate settlement.
Onerous contracts are excluded from net debt as the underlying
contracts do not represent an available source of 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 liquidity or repayment
obligation.
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 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, 2018, which will
be filed on or before March 31, 2019. 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.
- This press release contains estimates of the net present value
of our future net revenue from our reserves. Such amounts do
not represent the fair market value of our reserves.
This press release contains metrics commonly
used in the oil and natural gas industry, such as “recycle ratio,”
“operating netback,” and “reserves life index.” These terms do not
have a standardized meaning and may not be comparable to similar
measures presented by other companies, and therefore should not be
used to make such comparisons. Such metrics have been included in
this press release to provide readers with additional measures to
evaluate Baytex’s performance, however, such measures are not
reliable indicators of Baytex’s future performance and future
performance may not compare to Baytex’s performance in previous
periods and therefore such metrics should not be unduly relied
upon.
This press release discloses drilling locations
for our East Duvernay Shale assets. Drilling locations refer 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
and are derived from our most recent independent reserves
evaluation dated as at December 31, 2018. Potential drilling
opportunities are unbooked locations that 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 East Duvernay Shale, Baytex’s net
drilling locations for the East Duvernay Shale assets include 6
proved, 9 probable and 160 unbooked locations.
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.
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.
Moreover, Baytex has determined and disclosed
estimated future net revenue from its reserves using forecast
prices and costs, whereas the SEC rules require that reserves be
estimated using a 12-month average price, calculated as the
arithmetic average of the first-day-of-the-month price for each
month within the 12-month period prior to the end of the reporting
period. As a consequence of the foregoing, Baytex's reserve
estimates and production volumes in this press release may not be
comparable to those made by companies utilizing United States
reporting and disclosure standards.
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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