CALGARY, Alberta, Dec. 17, 2018 (GLOBE NEWSWIRE) -- Baytex Energy Corp. (“Baytex”) (TSX, NYSE: BTE) announces that
its Board of Directors has approved a 2019 capital budget of $550 to $650 million, which is designed to generate average annual
production of 93,000 to 97,000 boe/d.
Commenting on the announcement, Ed LaFehr, President and Chief Executive Officer, said: “As we enter 2019, our
top priority is disciplined capital allocation across our strong portfolio of assets. We will focus activity on our high return,
high netback light oil assets in the Viking and Eagle Ford and we will continue to prudently advance the East Duvernay Shale.
Importantly, we have the operational flexibility to adjust our spending plans based on changes in the commodity price
environment.”
Highlights of the 2019 Budget
- Funding of Capital Program. We are targeting 2019 capital expenditures to approximate adjusted funds
flow (assumes a WTI price of US$52/bbl).
- Capital Allocation. Approximately 80% of our capital development program will be directed to our high
netback light oil assets in the Eagle Ford and Viking. Approximately 10% of our capital will be directed to the East Duvernay
Shale as we build on our success in this light oil resource play.
- Stable Production. With a deep inventory of development projects, we target a long-term production
growth rate of 5-10%. In the current commodity price environment, we believe it is prudent to deliver a cash flow budget that is
designed to deliver stable production.
- Oil Price Diversification. Over 90% of our operating netback is expected to come from our light oil
assets in the Eagle Ford and Viking. Our light oil and condensate production in the Eagle Ford commands premium Louisiana Light
Sweet (“LLS”) based pricing.
- Free Cash Flow. Adjusted funds flow in excess of capital expenditures, lease payments and asset
retirement obligations will be allocated to debt repayment. A US$1.00/bbl change in the price of WTI impacts our annual adjusted
funds flow by approximately $30 million on an unhedged basis ($24 million on a hedged basis).
The 2019 program is approximately 45% weighted to the first half of the year and we have the operational
flexibility to adjust our spending plans based on changes in commodity prices. The budget is 90% weighted to drilling and
completion activities.
Based on the mid-point of our guidance range of 95,000 boe/d, approximately 62% of our production is in Canada
with the remaining 38% in the Eagle Ford. Our production mix is forecast to be 83% liquids (46% light oil and condensate, 27% heavy
oil and 10% natural gas liquids) and 17% natural gas, based on a 6:1 natural gas-to-oil equivalency.
Canada
In Canada, our development activity will largely be focused on the Viking, where we expect to invest
approximately 45% of our capital in this shallow, light oil resource play (approximately 36° API) where we control 460 net sections
of prospective lands. Our program anticipates drilling approximately 245 net wells (85% extended reach horizontals) in 2019.
We will continue to prudently advance the evaluation of the East Duvernay Shale, an early stage, high netback
light oil resource play where we have amassed over 430 sections of land. Our initial focus has been to delineate and evaluate the
potential depth of this light oil resource. We now have five producing wells in the Pembina area. The two most recent wells brought
on-stream in late November are currently producing in excess of 400 bbl/d of light oil per well. These new wells are consistent
with the strong results achieved from our first three wells in the Pembina area. Approximately 10% of our planned capital
investment in 2019 will be directed to the Pembina area where we expect to drill 6-8 net wells.
We expect a modest heavy oil development program through the first half of 2019, with the potential to scale
activity higher should crude oil prices improve. At Peace River, we will drill several stratigraphic wells as we continue to
delineate our lands and expand our future drilling inventory. Our 2019 guidance assumes the curtailment of approximately 1,000
bbl/d of heavy oil for the first six months of the year.
Eagle Ford
Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. The asset
generates a strong operating netback and free cash flow and contains a significant inventory of development prospects.
Approximately 33% of our planned capital investment will be directed to the Eagle Ford where we expect to bring
approximately 30 net wells on production. Development will be concentrated in the Lower Eagle Ford formation across our four areas
of mutual interest.
2019 Guidance
Exploration and development capital ($ millions) |
$550 - $650 |
Production (boe/d) |
93,000 - 97,000 |
|
|
Adjusted Funds Flow ($ millions) (1) |
$605 |
Adjusted Funds Flow per Share (2) |
$1.08 |
|
|
Operating Netback (per boe) (1)(3) |
$22.00 |
|
|
Expenses: |
|
Royalty rate (%) |
|
20.0% |
Operating ($/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 |
- Pricing assumptions: WTI - US$52/bbl; LLS - US$57/bbl; WCS differential - US$22/bbl; MSW differential – US$10/bbl, NYMEX Gas
- US$3.00/mcf; AECO Gas - $1.30/mcf and Exchange Rate (CAD/USD) - 1.32.
- Based on weighted average common shares outstanding of 562 million.
- Includes financial derivatives gains (losses).
2019 Adjusted Funds Flow Sensitivities
|
Excluding
Hedges
($ millions) |
Including
Hedges
($ 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 $0.01 in the C$/US$ exchange rate |
$8.1 |
$8.1 |
2019 Capital Budget and Wells On-Stream by Operating Area
Operating Area |
Amount (1)
($ millions) |
Wells
On-stream
(net) |
Canada |
$400 |
300 |
United States (2) |
$200 |
30 |
Total |
$600 |
330 |
- Reflects mid-point of capital budget guidance range.
- Based on a Canadian-U.S. exchange rate of 1.32 CAD/USD.
2019 Capital Budget Breakdown
Classification |
Amount (1)
($ millions) |
|
|
Drilling, completion and equipping |
$545 |
Facilities |
$45 |
Land and seismic |
$10 |
Total |
$ 600 |
- Reflects mid-point of capital budget guidance range.
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.
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$56.02/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 21% of our net
natural gas exposure through a combination of AECO swaps at C$2.37/mcf and NYMEX swaps at US$3.09/mmbtu.
Crude-by-rail is an integral part of our egress and marketing strategy. For 2019, we expect to deliver 11,000
bbl/d (approximately 40%) of our heavy oil volumes to market by rail, up from approximately 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.
Corporate Restructuring
After completing the merger with Raging River Exploration, we have recently streamlined our executive team with
a reduction of three executive officers. In addition, we have consolidated our Peace River and Lloydminster operations into one
heavy oil business unit, resulting in an approximate 10% reduction in head office staff and contractors.
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 capital budget for 2019; our average annual production rate for 2019; our top
priority being disciplined capital allocation; that we will focus on our Eagle Ford and Viking assets and prudently advance the
East Duvernay Shale; that we have operational flexibility to adjust our plans based on commodity prices; our target of funding 2019
capital expenditures with adjusted funds flow; that our 2019 capital budget assumes a WTI price of $52/bbl; our capital allocations
as between assets for 2019; our long term target of 5-10% production growth; that we expect 90% of our operating netback to come
from Eagle Ford and Viking; that excess funds will be spent on debt repayment; the impact of a $1.00 change in WTI on our adjusted
funds flow; the timing and flexibility of our capital spending; the percentage of our capital expenditures to be spent on drilling
and completions; the product mix for 2019 production; the breakdown of our 2019 capital budget by geographic area, expenditure type
and number of wells to be drilled or brought on production; the geographic breakdown and product mix for 2019 production; in
Canada, the number and type of wells to be drilled in the Duvernay and in Peace River, our expectation that we will expand our
future drilling inventory in Peace River and the amount of production we expect to curtail in the first six months of the year; our
expected adjusted funds flow, adjusted funds flow per share, operating netback, royalty rate and operating, transportation, general
and administrative, interest costs, leasing expenditures and asset retirement obligations for 2019; the sensitivity of our 2019
Adjusted Funds Flow to changes in WTI, WCS, MSW and NYMEX prices and the C$/US$ exchange rate; the expected capital budget and
wells on-stream by operating area in 2019 and capital budget by spending type for 2019; the existence, operation and strategy of
our risk management program for commodity prices; and 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.
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 the reserves can be profitably produced in the future. Although Baytex believes that the
expectations and assumptions upon which the forward-looking statements are based are reasonable, undue reliance should not be
placed on the forward-looking statements because Baytex can give no assurance that they will prove to be correct.
These forward-looking statements are based on certain key assumptions regarding, among other things:
petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve
volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels;
our ability to borrow under our credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for
our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the
continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and
natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in
effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions,
although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and
unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the volatility of oil and natural
gas prices and price differentials; the availability and cost of capital or borrowing; that our credit facilities may not
provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated
with a third-party operating our Eagle Ford properties; availability and cost of gathering, processing and pipeline systems; public
perception and its influence on the regulatory regime; changes in government regulations that affect the oil and gas industry;
changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in
interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our
assets; depletion of our reserves; risks associated with the exploitation of our properties and our ability to acquire reserves;
changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas
reserves; our inability to fully insure against all risks; risks of counterparty default; risks associated with acquiring,
developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks
related to our thermal heavy oil projects; risks associated with our use of information technology systems; risks associated with
the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident
shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production,
additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control.
These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's
Discussion and Analysis for the year ended December 31, 2017, as filed with Canadian securities regulatory authorities and the U.S.
Securities and Exchange Commission.
The above summary of assumptions and risks related to forward-looking statements has been provided in order
to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future
operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as
those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any
of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be
required by applicable securities law.
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
Non-GAAP Financial 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 and asset retirement obligations settled. Our
determination of adjusted funds flow may not be comparable to other issuers. We consider adjusted funds flow a key measure of
performance as it demonstrates our ability to generate the cash flow necessary to fund capital investments, debt repayment,
payments on our lease obligations, settlement of our abandonment obligations and potential future dividends. In addition, we use
the ratio of net debt to adjusted funds flow to manage our capital structure. We eliminate changes in non-cash working capital and
settlements of abandonment obligations from cash flow from operations as the amounts can be discretionary and may vary from period
to period depending on our capital programs and the maturity of our operating areas. The settlement of
abandonment obligations are managed with our capital budgeting process which considers available adjusted funds flow. The
most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net
income.
Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as adjusted funds flow
less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset
production declines on an annual basis and maintain flat production volumes.
Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the
oil and gas industry. Operating netback is equal to petroleum and natural gas sales less blending expense, royalties, production
and operating expense and transportation expense divided by barrels of oil equivalent sales volume for the applicable period.
Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We
believe that this measure assists in characterizing our ability to generate cash margin on a unit of production
basis.
Advisory Regarding Oil and Gas Information
Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic
feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation.
A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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: 1-800-524-5521
Email: investor@baytexenergy.com