Baytex Announces 2019 Budget

Credit: GlobeNewswire- Published on December 17, 2018
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

1. 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.
2. Based on weighted average common shares outstanding of 562 million.
3. 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

1. Reflects mid-point of capital budget guidance range.
2. 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

1. 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
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