Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its
operating and financial results for the three and six months ended
June 30, 2017 (all amounts are in Canadian dollars unless otherwise
noted).
“Driven by excellent capital efficiencies across
our portfolio, we have been able to substantially grow production
largely within funds from operations during the first half of the
year at US$50/bbl oil prices. This is due to some of the
strongest well results we have seen to-date in the Eagle Ford and a
safe and highly efficient start-up of our development program in
Canada. Our team is pushing to reposition the business for success
at these low commodity prices with production currently above the
high end of guidance and capital expenditures tracking toward
the low end of guidance,” commented Ed LaFehr, President and Chief
Executive Officer.
Highlights
- Generated production of 72,812 boe/d (79% oil and NGL) during
Q2/2017, an increase of 5% from Q1/2017 and 12% from Q4/2016;
- Delivered funds from operations ("FFO") of $83.1 million ($0.35
per basic share) in Q2/2017 and $164.5 million ($0.70 per
basic share) in H1/2017;
- Produced 38,528 boe/d in the Eagle Ford, an increase of 7% from
Q1/2017 and 15% from Q4/2016, and 34,284 boe/d in Canada, an
increase of 3% from Q1/2017 and 8% from Q4/2016;
- Established average 30-day initial gross production rates of
approximately 2,150 boe/d per well from three recently completed
pads (total of 11 wells) in the oil window of our Eagle Ford
acreage;
- Realized an operating netback (sales price less royalties,
operating and transportation expenses) in Q2/2017 of $18.30/boe
($18.70/boe including financial derivatives gain);
- Reduced annual guidance for operating expenses by 4% (at
mid-point) to $10.75-$11.25/boe, reflecting strong performance in
H1/2017 of $10.50/boe; and
- Tightened our 2017 production guidance range to 69,000 to
70,000 boe/d (previously 68,000 to 70,000 boe/d) and exploration
and development capital expenditures to $310 to $330 million
(previously $325 to $350 million).
|
Three Months Ended |
Six Months Ended |
|
June 30, 2017 |
March 31, 2017 |
June 30, 2016 |
June 30, 2017 |
June 30, 2016 |
FINANCIAL(thousands of Canadian
dollars, except per common share amounts) |
|
|
|
|
|
Petroleum and natural gas sales |
$ |
274,369 |
|
$ |
260,549 |
|
|
$ |
195,733 |
|
$ |
534,918 |
|
$ |
349,331 |
|
Funds from operations (1) |
83,136 |
|
81,369 |
|
81,261 |
|
164,505 |
|
126,906 |
|
Per share - basic |
0.35 |
|
0.35 |
|
0.39 |
|
0.70 |
|
0.60 |
|
Per share - diluted |
0.35 |
|
0.34 |
|
0.39 |
|
0.70 |
|
0.60 |
|
Net
income (loss) |
9,268 |
|
11,096 |
|
(86,937 |
) |
20,364 |
|
(86,330 |
) |
Per share - basic |
0.04 |
|
0.05 |
|
(0.41 |
) |
0.09 |
|
(0.41 |
) |
Per share - diluted |
0.04 |
|
0.05 |
|
(0.41 |
) |
0.09 |
|
(0.41 |
) |
Exploration and development |
78,007 |
|
96,559 |
|
35,490 |
|
174,566 |
|
117,175 |
|
Acquisitions, net of divestitures |
5,226 |
|
66,004 |
|
(37 |
) |
71,230 |
|
(46 |
) |
Total oil and natural gas capital
expenditures |
$ |
83,233 |
|
$ |
162,563 |
|
|
$ |
35,453 |
|
$ |
245,796 |
|
$ |
117,129 |
|
|
|
|
|
|
|
Bank loan (2) |
$ |
264,032 |
|
$ |
259,966 |
|
|
$ |
347,083 |
|
$ |
264,032 |
|
$ |
347,083 |
|
Long-term notes (2) |
1,541,694 |
|
1,574,116 |
|
1,544,181 |
|
1,541,694 |
|
1,544,181 |
|
Long-term debt |
1,805,726 |
|
1,834,082 |
|
1,891,264 |
|
1,805,726 |
|
1,891,264 |
|
Working capital deficiency |
13,661 |
|
16,827 |
|
51,247 |
|
13,661 |
|
51,274 |
|
Net debt (3) |
$ |
1,819,387 |
|
$ |
1,850,909 |
|
|
$ |
1,942,538 |
|
$ |
1,819,387 |
|
$ |
1,942,538 |
|
|
Three Months Ended |
Six Months Ended |
|
|
June 30, 2017 |
March 31, 2017 |
June 30, 2016 |
June 30, 2017 |
June 30, 2016 |
|
OPERATING |
|
|
|
|
|
|
Daily
production |
|
|
|
|
|
|
Heavy oil
(bbl/d) |
25,577 |
|
24,625 |
|
22,423 |
|
25,104 |
|
23,615 |
|
Light oil
and condensate (bbl/d) |
22,370 |
|
21,617 |
|
21,894 |
|
21,996 |
|
23,191 |
|
NGL
(bbl/d) |
9,693 |
|
8,306 |
|
9,834 |
|
9,003 |
|
9,971 |
|
Total oil
and NGL (bbl/d) |
57,640 |
|
54,548 |
|
54,151 |
|
56,103 |
|
56,777 |
|
Natural
gas (mcf/d) |
91,028 |
|
88,502 |
|
95,281 |
|
89,771 |
|
96,750 |
|
Oil
equivalent (boe/d @ 6:1) (4) |
72,812 |
|
69,298 |
|
70,031 |
|
71,065 |
|
72,902 |
|
|
|
|
|
|
|
|
Benchmark
prices |
|
|
|
|
|
|
WTI oil
(US$/bbl) |
48.29 |
|
51.91 |
|
45.60 |
|
50.10 |
|
39.53 |
|
WCS heavy
oil (US$/bbl) |
37.16 |
|
37.34 |
|
32.29 |
|
37.25 |
|
25.76 |
|
Edmonton
par oil ($/bbl) |
61.92 |
|
63.98 |
|
54.78 |
|
62.95 |
|
47.80 |
|
LLS oil
(US$/bbl) |
49.70 |
|
52.50 |
|
46.20 |
|
51.10 |
|
39.73 |
|
|
|
|
|
|
|
|
Baytex average
prices (before hedging) |
|
|
|
|
|
|
Heavy oil
($/bbl) (5) |
37.62 |
|
35.96 |
|
30.09 |
|
36.81 |
|
20.87 |
|
Light oil
and condensate ($/bbl) |
60.68 |
|
63.26 |
|
52.42 |
|
61.94 |
|
44.79 |
|
NGL
($/bbl) |
22.70 |
|
26.35 |
|
13.28 |
|
24.38 |
|
15.86 |
|
Total oil
and NGL ($/bbl) |
44.06 |
|
45.31 |
|
36.07 |
|
44.67 |
|
29.76 |
|
Natural
gas ($/mcf) |
3.62 |
|
3.52 |
|
1.94 |
|
3.57 |
|
2.17 |
|
Oil
equivalent ($/boe) |
39.41 |
|
40.16 |
|
30.52 |
|
39.77 |
|
26.06 |
|
|
|
|
|
|
|
|
CAD/USD noon
rate at period end |
1.2983 |
|
1.3322 |
|
1.3009 |
|
1.2983 |
|
1.3009 |
|
CAD/USD average rate for period |
1.3447 |
|
1.3229 |
|
1.2885 |
|
1.3338 |
|
1.3317 |
|
COMMON SHARE
INFORMATION
|
|
|
|
|
|
TSX |
|
|
|
|
|
Share price (Cdn$) |
|
|
|
|
|
High |
4.81 |
6.97 |
9.04 |
6.97 |
9.04 |
Low |
2.87 |
4.02 |
4.85 |
2.87 |
1.57 |
Close |
3.15 |
4.54 |
7.50 |
3.15 |
7.50 |
Volume traded
(thousands) |
216,383 |
255,645 |
466,201 |
472,026 |
949,511 |
|
|
|
|
|
|
NYSE |
|
|
|
|
|
Share price (US$) |
|
|
|
|
|
High |
3.63 |
5.19 |
7.14 |
5.20 |
7.14 |
Low |
2.15 |
3.01 |
3.67 |
2.15 |
1.08 |
Close |
2.43 |
3.65 |
5.79 |
2.43 |
5.79 |
Volume traded
(thousands) |
109,758 |
136,666 |
198,514 |
248,931 |
352,567 |
Common shares outstanding (thousands)
|
234,204 |
234,203 |
210,715 |
234,204 |
210,715 |
Notes:
(1) Funds from operations 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 funds from operations as cash flow
from operating activities adjusted for changes in non-cash
operating working capital and other operating items. Baytex's
determination of funds from operations may not be comparable to
other issuers. Baytex considers funds from operations a key measure
of performance as it demonstrates its ability to generate the cash
flow necessary to fund capital investments and potential future
dividends. For a reconciliation of funds from operations to cash
flow from operating activities, see Management's Discussion and
Analysis of the operating and financial results for the three and
six months ended June 30, 2017.(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) Heavy oil prices are
calculated based on sales volumes, net of blending costs.
Operating Results
Our operating results for the second quarter
reflect strong drilling results and an increased pace of activity
in the Eagle Ford that began late in Q4/2016, the resumption of
drilling activity in Canada and a full quarter contribution from
the Peace River acquisition, which closed on January 20, 2017.
Production increased 5% to average 72,812 boe/d
(79% oil and NGL) in Q2/2017, as compared to 69,298 boe/d (79% oil
and NGL) in Q1/2017. Production in the first half of 2017 averaged
71,065 boe/d. During the second quarter, exploration and
development capital expenditures totaled $78.0 million, bringing
the aggregate spending in the first half of 2017 to
$174.6 million. We participated in the drilling of 47 (15.3
net) wells with a 100% success rate during the second quarter.
Reflective of our strong operating results in
the first half of the year, we are tightening our 2017 production
guidance range to 69,000 to 70,000 boe/d (previously 68,000 to
70,000 boe/d). We are now forecasting full-year 2017 exploration
and development capital expenditures of $310 to $330 million
(previously $325 to $350 million). We are also reducing our
guidance for operating expenses by 4% (at the mid-point) to
$10.75-$11.25/boe as we continue to drive cost efficiencies in our
business.
We will continue to employ a flexible approach
to prudently manage our capital program as we target exploration
and development capital expenditures at a level that approximates
our funds from operations.
Eagle Ford
Our Eagle Ford asset in South Texas is one of
the premier oil resource plays in North America. The assets
generate the highest cash netbacks in our portfolio and contain a
significant inventory of development prospects. In Q2/2017, we
directed 76% of our exploration and development expenditures toward
these assets.
Production increased 7% during the second
quarter to average 38,528 boe/d (77% liquids), as compared to
36,081 boe/d in Q1/2017. During the second quarter, we averaged 4-5
drilling rigs and 1-2 completion crews on our lands. In Q2/2017, we
participated in the drilling of 38 (9.4 net) wells and commenced
production from 35 (8.1 net) wells. At quarter end, we had
51 (13.0 net) wells waiting on completion.
We continue to see strong well performance
driven by enhanced completions in the oil window of our acreage
with the cost to drill, complete, equip and tie-in a well of
US$4.7‑4.9 million. The wells that commenced production during the
quarter have established 30-day initial gross production rates of
approximately 1,500 boe/d per well. Our three recently completed
Karnes City pads (total of 11 wells) within the oil window of our
Longhorn acreage established 30-day initial gross production rates
of approximately 2,150 boe/d per well. These pads were
completed with approximately 30 effective frac stages per well and
proppant per completed foot of approximately 1,900 pounds, which is
more than double the frac intensity of wells previously drilled in
the area.
Peace River
Our Peace River region, located in northwest
Alberta, has been a core asset for us 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.
Production increased 8% during the second
quarter to average 18,300 boe/d (93% heavy oil), as compared to
17,000 boe/d in Q1/2017. The production increase was driven by an
active drilling program combined with a full quarter contribution
from the Peace River acquisition, which closed on January 20, 2017.
We drilled 4 (4.0 net) wells during the second
quarter and 7 (7.0 net) wells during the first six months of 2017.
Six of the wells have been producing for more than 30 days and have
established an average 30-day initial production rate of
approximately 400 bbl/d per well and two of these wells ranked
among the top oil wells drilled in Alberta during this period.
Lloydminster
Our Lloydminster region, which straddles the
Alberta and Saskatchewan border, is characterized by multiple
stacked pay formations at relatively shallow depths, which we have
successfully developed through vertical and horizontal drilling,
water flood and steam-assisted gravity drainage operations.
Production averaged approximately 8,600 boe/d
(98% heavy oil) during the second quarter, as compared to 9,100
boe/d in Q1/2017. The reduced volumes reflect a lower pace of
development activity during the second quarter due to spring
break-up. We drilled 5 (1.9 net) wells during the second quarter
and 22 (14.9 net) wells during the first six months of
2017.
Financial Review
We generated FFO of $83.1 million ($0.35 per
share) in Q2/2017, compared to $81.4 million ($0.35 per share) in
Q1/2017. The increase in FFO is largely due to higher production
volumes, which more than mitigated the decline in crude oil prices.
FFO in the first half of 2017 totaled $164.5 million ($0.70 per
share), compared to $126.9 million ($0.60 per share) in the first
half of 2016.
Financial Liquidity
We continue to maintain strong financial
liquidity as our US$575 million revolving credit facilities are
approximately two-thirds undrawn and our first meaningful long-term
note maturity is not until 2021. With our strategy to target
exploration and development capital expenditures at a level that
approximates our funds from operations, we expect this liquidity
position to be stable going forward.
Our revolving credit facilities, which currently
mature in June 2019, are covenant-based and do not require annual
or semi-annual reviews. We are well within our financial covenants
on these facilities as our Senior Secured Debt to Bank EBITDA ratio
as at June 30, 2017 was 0.7:1.0, compared to a maximum permitted
ratio of 5.0:1.0, and our interest coverage ratio was 4.0:1.0,
compared to a minimum required ratio of 1.25:1.0.
Our net debt totaled $1.8 billion at June 30,
2017, which is down $123 million from June 30, 2016. Our net debt
is comprised of over 75% U.S. dollar borrowings and with the recent
strengthening of the Canadian dollar relative to the U.S. dollar,
we benefit as our net debt expressed in Canadian dollars is
reduced. We also benefit from more than half of our
operations being based in the U.S. along with approximately
70% of our 2017 exploration and development capital program being
invested in the U.S., which mitigates our exposure to fluctuations
in the Canada-U.S. dollar exchange rate.
Operating Netback
In Q2/2017, the price for West Texas
Intermediate light oil (“WTI”) averaged US$48.29/bbl, as compared
to US$51.91/bbl in Q1/2017. Offsetting a portion of the decline in
WTI was an improved pricing environment for Canadian heavy oil. The
discount for Canadian heavy oil, as measured by the price
differential between Western Canadian Select (“WCS”) and WTI,
averaged US$11.13/bbl, as compared to US$14.57/bbl in Q1/2017.
We generated an operating netback in Q2/2017 of
$18.30/boe ($18.70/boe including financial derivatives gain), as
compared to $19.42/boe ($19.46/boe including financial derivatives
gain) in Q1/2017 and $14.39/boe ($18.13/boe including financial
derivatives gain) in Q2/2016. The Eagle Ford generated an operating
netback of $24.14/boe during Q2/2017 while our Canadian operations
generated an operating netback of $11.71/boe.
The following table summarizes our operating
netbacks for the periods noted.
|
Three Months Ended June 30 |
|
2017 |
2016 |
($ per boe except for sales volume) |
Canada |
U.S. |
Total |
Canada |
U.S. |
Total |
Sales volume
(boe/d) |
34,284 |
|
38,528 |
|
72,812 |
|
31,722 |
|
38,309 |
|
70,031 |
|
|
|
|
|
|
|
|
Realized sales
price |
$ |
33.86 |
|
$ |
44.34 |
|
$ |
39.41 |
|
$ |
25.80 |
|
$ |
34.43 |
|
$ |
30.52 |
|
Less: |
|
|
|
|
|
|
Royalty |
4.53 |
|
13.09 |
|
9.06 |
|
2.74 |
|
9.89 |
|
6.65 |
|
Operating
expense |
14.74 |
|
7.11 |
|
10.70 |
|
10.84 |
|
6.88 |
|
8.67 |
|
Transportation expense |
2.88 |
|
— |
|
1.35 |
|
1.78 |
|
— |
|
0.81 |
|
Operating netback |
$ |
11.71 |
|
$ |
24.14 |
|
$ |
18.30 |
|
$ |
10.44 |
|
$ |
17.66 |
|
$ |
14.39 |
|
Realized
financial derivatives gain |
|
— |
|
|
— |
|
|
0.40 |
|
|
— |
|
|
— |
|
|
3.74 |
|
Operating netback after
financial derivatives gain |
$ |
11.71 |
|
$ |
24.14 |
|
$ |
18.70 |
|
$ |
10.44 |
|
$ |
17.66 |
|
$ |
18.13 |
|
Risk Management
As part of our normal operations, we are exposed
to movements in commodity prices, foreign exchange rates and
interest rates. In an effort to manage these exposures, we utilize
various financial derivative contracts which are intended to
partially reduce the volatility in our FFO. We realized a financial
derivatives gain of $2.6 million in Q2/2017.
For the second half of 2017, we have entered
into hedges on approximately 48% of our net WTI exposure with 9%
fixed at US$54.46/bbl and 39% hedged utilizing a 3-way option
structure that provides us with downside price protection at
US$47.17/bbl and upside participation to US$58.60/bbl. We have also
entered into hedges on approximately 49% of our net WCS
differential exposure at a price differential to WTI of
US$13.73/bbl and 68% of our net natural gas exposure through a
combination of AECO swaps at C$3.00/mcf and NYMEX swaps at
US$2.98/mmbtu.
We are also executing our hedge program for
2018. We have now entered into hedges on approximately 20% of our
net WTI exposure with 15% fixed at US$51.28/bbl and 5% hedged
utilizing a 3-way option structure that provides us with downside
price protection at US$54.40/bbl and upside participation to
US$60.00/bbl. We have also entered into hedges on approximately 20%
of our net WCS differential exposure at a price differential to WTI
of US$14.42/bbl and 19% of our net natural gas exposure through a
combination of AECO swaps at C$2.82/mcf and NYMEX swaps at
US$3.00/mmbtu.
A complete listing of our financial derivative
contracts can be found in Note 17 to our Q2/2017 financial
statements.
2017 Guidance
The following table summarizes our 2017 annual
guidance and compares it to our 2017 year-to-date actual
results.
|
2017 Guidance |
|
|
|
Original (1) |
Revised (2) |
H1/2017 |
Variance |
Exploration and
development capital ($ millions) |
300 -
350 |
310 -
330 |
174.6 |
|
N/A |
Production (boe/d) |
66,000
- 70,000 |
69,000
- 70,000 |
71,065 |
|
2 |
% |
|
|
|
|
|
Expenses: |
|
|
|
|
Royalty
rate (%) |
~23.0 |
~23.0 |
22.8 |
|
(1 |
)% |
Operating
($/boe) |
11.00 -
12.00 |
10.75 -
11.25 |
10.50 |
|
(2 |
)% |
Transportation ($/boe) |
1.10 -
1.30 |
1.10 -
1.30 |
1.32 |
|
2 |
% |
General
and administrative ($/boe) (3) |
~2.00 |
~2.00 |
2.07 |
|
4 |
% |
Interest ($/boe) |
~4.00 |
~4.00 |
3.97 |
(1 |
)% |
Notes:
(1) Original guidance as announced on December
12, 2016.(2) On August 1, 2017, we tightened our exploration and
development capital and production guidance ranges and reduced our
operating expense guidance range by 4% (at the mid-point).
(3) General and administrative expenses in H1/2017
include non-recurring restructuring costs of $0.17/boe associated
with staffing reductions. Excluding these restructuring costs,
general and administrative expenses were $1.90/boe.
Additional
Information
Our condensed consolidated interim unaudited
financial statements for the three and six months ended June 30,
2017 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 – August 1, 20179:00
a.m. MDT (11:00 a.m. EDT) |
Baytex will host a conference call today, August 1, 2017, starting
at 9:00am MDT (11:00am EDT). To participate, please dial toll free
in North America 1-866-226-4099 or international 1-647-427-2258.
Alternatively, to listen to the conference call online, please
enter http://edge.media-server.com/m/p/fb4ofhpe in your web
browser. An archived recording of the conference call will
be available approximately two hours 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; our 2017 production and
capital expenditure guidance; our Eagle Ford assets, including our
assessment that it is a premier oil resource play, the cost to
drill, complete and equip a well and initial production rates from
new wells drilled in Q2/2017; our Peace River assets, including
that the area has some of the strongest capital efficiencies in the
oil and gas industry and initial production rates from wells
drilled in H1/2017; our belief that we have strong financial
liquidity and that our liquidity position will remain stable going
forward; our target for exploration and development capital
expenditures to approximate funds from operations; the effect that
a strengthening Canada-U.S. dollar exchange rate will have on our
U.S. dollar denominated debt; that our U.S. operations mitigate our
exposure to fluctuations in the Canada-U.S. dollar exchange rate;
our ability to partially reduce the volatility in our funds from
operations by utilizing financial derivative contracts for
commodity prices, heavy oil differentials and interest and foreign
exchange rates; the percentage of our anticipated 2017 and 2018 oil
and natural gas production that is hedged; and our expected royalty
rate and per boe operating, transportation, general and
administrative and interest costs for 2017. 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; a decline or an extended period of the currently low
oil and natural gas prices; uncertainties in the capital markets
that may restrict or increase our 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; 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; availability and cost
of gathering, processing and pipeline systems; 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 petroleum 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; we may lose access to our 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, 2016, 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 Measures
Funds from operations 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. Funds from operations represents cash generated
from operating activities adjusted for changes in non-cash
operating working capital and other operating items. Baytex's
determination of funds from operations may not be comparable with
the calculation of similar measures for other entities.
Baytex considers funds from operations a key measure of performance
as it demonstrates its ability to generate the cash flow necessary
to fund capital investments and potential future dividends to
shareholders. The most directly comparable measures
calculated in accordance with GAAP are cash flow from operating
activities and net income.
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 product
revenue less royalties, production and operating expenses and
transportation expenses 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 79% 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, Senior Vice President, Capital Markets and Public Affairs
Toll Free Number: 1-800-524-5521
Email: investor@baytexenergy.com
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