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Baytex Announces Closing of Strategic Combination With Raging River, Updated 2018 Guidance and Confirmation of Preliminary 2019 Plans

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CALGARY, Alberta, Aug. 22, 2018 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex")((TSX, NYSE:BTE) is pleased to announce the closing of the strategic combination with Raging River Exploration Inc. ("Raging River")(TSX:RRX).  

Baytex has emerged through this transaction as a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile provided by its world class assets focused across North America. Current production is approximately 94,000 boe/d (83% liquids) from a diversified asset portfolio, including Viking, Peace River, Lloydminster and East Duvernay properties in Canada and the Eagle Ford in Texas. Baytex has a deep inventory of drilling prospects that generate top tier returns on invested capital with the capability to deliver meaningful organic production growth.

Neil Roszell, Chairman of the Board, commented "Today we have united two strong oil companies with exceptional people and assets. Our new board of directors and leadership team have laid out a detailed integration plan as we come together to create a diversified, well-capitalized oil producer with an impressive suite of high quality assets. Combined we have a platform for value creation and operational excellence and are ideally positioned to grow production and cash flow."

Ed LaFehr, President and Chief Executive Officer, said "I am thrilled that we have repositioned Baytex to deliver industry leading returns, attractive production growth and free cash flow, with a strengthened balance sheet. Our vision is to create a self-funded North American oil producer focused on per share value creation with a target of 10 to 15 percent total annual returns. We look forward to rapidly integrating our talented teams and growing our 2018 production exit rate with strong new well performance in our core areas."

Company Highlights (2019 Annual Estimates)             

  • Average annual production of 100,000 to 105,000 boe/d (85% oil and NGLs)
  • Debt adjusted production per share growth of approximately 12%
  • Exploration and development capital program of $750 to $850 million
  • Adjusted funds flow of approximately $900 million
  • Net debt to adjusted funds flow ratio of 2.2x
  • Operating netback of approximately $28/boe

Notes:

  1. Forward strip pricing assumptions as at August 20, 2018: WTI - US$63/bbl; LLS - US$67/bbl; WCS differential - US$23/bbl; MSW differential – US$8/bbl; NYMEX Gas - US$2.80/mcf; and Exchange Rate (CAD/USD) - 1.30.
  2. Net debt to adjusted funds flow ratio based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow.
  3. Certain terms referenced above are non-GAAP measures. See advisory regarding Non-GAAP Financial and Capital Management Measures at the end of the press release.

With the closing of the transaction, we have established a new $300 million term loan facility that is due June 2020 and is secured by the assets of Raging River. This additional facility, combined with our existing facilities of US$575 million, increases our credit capacity to approximately $1.05 billion with approximately $500 million undrawn. 

Operations Update

Our assets are characterized by high margins and strong capital efficiencies, resulting in industry-leading returns. With a diversified asset base and product pricing mix, we have the capability to optimize capital allocation and activity based on commodity prices and economic returns by area. In addition, we have a well-defined, low-risk drilling inventory that represents over 10 years of development opportunities in each core play.

Eagle Ford and Viking Light Oil

Our Eagle Ford and Viking light oil assets generate combined production of approximately 60,000 boe/d, representing 64% of total company volumes. These two assets are expected to generate significant cash flow in excess of their exploration and development capital.

In the Eagle Ford, we continue to see strong well performance driven by enhanced completions. During the second quarter, we commenced production from 32 gross wells and established 30-day initial production rates of approximately 1,850 boe/d per well (65% light oil and condensate) which represents an approximate 25% improvement over wells brought on production in 2017. In the Viking, 51.5 net wells were drilled during the second quarter. We currently have four drilling rigs and one frac crew executing our development program.   

Heavy Oil

Our heavy oil production at Peace River and Lloydminster totals approximately 27,000 boe/d, representing 29% of total company volumes. In the northern Seal area of Peace River, our first three wells have established 30-day initial production rates of approximately 800 boe/d per well. In Lloydminster, we have recommenced our Soda Lake multi-lateral drilling program. In addition, we continue to advance our Kerrobert thermal project with first oil from the new wells anticipated in October.  We currently have four heavy oil rigs running, two each in Peace River and Lloydminster. 

East Duvernay Shale Light Oil

We continue to prudently advance the evaluation of the emerging Duvernay light oil play in central Alberta. As previously disclosed, the Ferrybank (02-20) and Gilby (01-20) wells are both in early stages of flow back. Two follow up delineation wells in the Pembina area have been drilled, with completions operations commencing in the next two weeks. Given the encouraging performance of the 14-36 Pembina location, we anticipate spudding the first of two development wells from the 14-36 surface pad before the end of August. Additional follow up locations are currently being licensed in both the Pembina and Ferrybank areas to allow for potential expanded activities later in the fourth quarter.

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 also have strong oil price diversification with 30% of liquids production commanding WTI-based pricing and 26% of liquids production (light oil and condensate in the Eagle Ford) commanding premium Louisiana Light Sweet ("LLS") based pricing. Approximately 34% of liquids production is based on the WCS heavy oil benchmark with the balance being NGLs that are priced relative to WTI.

For Q4/2018, we have entered into hedges on approximately 37% of our net crude oil exposure. This includes 30% of our net WTI exposure with 27% fixed at US$52.27/bbl and 3% 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. In addition, we have entered into a Brent-based hedge for 4,000 bbl/d at US$61.31/bbl. We have also entered into hedges on approximately 27% of our net WCS differential exposure at a price differential to WTI of US$14.18/bbl and 29% of our net natural gas exposure through a combination of AECO swaps at C$2.82/mcf and NYMEX swaps at US$3.01/mmbtu.

For 2019, we have entered into hedges on approximately 19% of our net crude oil exposure. This includes 8% of our net WTI exposure with 5% fixed at US$61.99/bbl and 3% hedged utilizing a 3-way option structure that provides us with downside price protection at US$60.00/bbl and upside participation to US$70.00/bbl. In addition, we have entered into a Brent-based 3-way option structure for 3,000 bbl/d that provides us with downside price protection at US$69.50/bbl and upside participation to US$78.68/bbl.

With respect to heavy oil, we transport crude oil to market by rail when economics warrant. In Q2/2018, we delivered 8,300 bbl/d (approximately 33%) of our heavy oil volumes to market by rail, up from 6,500 bbl/d in Q1/2018. We have secured additional rail capacity, which will see our crude oil volumes delivered to market by rail increase to approximately 9,500 bbl/d in Q3/2018 and 10,500 bbl/d in Q4/2018. We have also successfully commenced the re-contracting of future crude by rail commitments, which to date total 7,500 bbl/d for 2019 and 5,000 bbl/d for 2020. 

Growth Plans and Guidance Update

We are forecasting a Q4/2018 production rate of approximately 97,000 to 99,000 boe/d, based on exploration and development expenditures of $275 to $325 million in the second half of 2018. The following table summarizes our updated 2018 annual guidance.

Summary of 2018 Guidance

  Original Guidance (1) Updated Guidance (2) Q4 2018
Exploration and development capital ($ millions) 325 - 375 450 - 500  
Production (boe/d) 68,000 - 72,000 79,000 - 81,000 97,000 - 99,000
       
Expenses:      
  Royalty rate (%) ~ 23.0 ~ 21.0  
  Operating ($/boe) 10.50 - 11.25 10.75 - 11.25  
  Transportation ($/boe) 1.35 - 1.45 1.35 - 1.45  
  General and administrative ($ millions) ~ 44 (1.72/boe) ~ 48 (1.64/boe)  
  Interest ($ millions) ~ 100 (3.95/boe) ~ 105 (3.60/boe)  

Note:

  1. As announced on December 7, 2017.
  2. Includes Raging River from the closing date of the transaction (August 22, 2018).

Our preliminary 2019 plans are unchanged. With a diversified asset base and product pricing mix, we have the capability to optimize capital allocation and activity based on commodity prices and economic returns by area.

For 2019, total exploration and development expenditures are expected to be $750 to $850 million, which is designed to generate average annual production of 100,000 to 105,000 boe/d. At the mid-point, this represents debt adjusted production per share growth of approximately 12% over 2018 pro forma average annual production.

Preliminary development plans for 2019 include a heavy oil program in Canada with two drilling rigs running in each of Peace River (32 net wells) and Lloydminster (100 net wells), along with a consistent activity set in the Viking (275 net wells) and the Eagle Ford (30 net wells) which are expected to generate significant free cash flow. In addition, we will continue to delineate the East Duvernay Shale oil play with an increased pace of activity (12-20 net wells).

Summary of Preliminary 2019 Plans

Exploration and Development Capital $750 - $850 million
   
Production 100,000 - 105,000 boe/d
Oil and NGLs ~ 85%
   
Operating Netback (1) $28/boe
Adjusted Funds Flow (1) $900 million
Adjusted Funds Flow per Share (2) $ 1.60
   
Net Debt to Adjusted Funds Flow (3) 2.2x

Notes:

  1. Pricing assumptions: WTI - US$63/bbl; LLS - US$67/bbl; WCS differential - US$23/bbl; MSW differential – US$8/bbl, NYMEX Gas - US$2.80/mcf; and Exchange Rate (CAD/USD) - 1.30.
  2. Based on 555 million common shares outstanding.
  3. Net debt ratio based on forecast net debt at year-end 2019 and forecast 2019 adjusted funds flow.
  4. Certain terms referenced above are non-GAAP measures. See advisory regarding Non-GAAP Financial and Capital Management Measures at the end of the press release.

We expect to generate adjusted funds flow in 2019 of approximately $900 million and free cash flow (net of $575 million sustaining capital) of approximately $325 million. Each US$5/bbl increase in WTI above US$63/bbl provides an additional $130 million of adjusted funds flow on an unhedged basis. Given the significant free cash flow, we will be well-positioned to pursue organic growth, reduce debt, pursue strategic acquisitions in core areas, and consider the reinstatement of a dividend and/or share buybacks.

We will provide 2019 guidance in late 2018 upon approval by the board of directors.

Advisory Regarding Forward-Looking Statements

Any "financial outlook" or "future oriented financial information" in this press release, as defined by applicable securities laws, has been approved by management of Baytex. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other circumstances.

In the interest of providing the shareholders of Baytex and potential investors with information regarding Baytex, including management's assessment of 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 hereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to but not limited to: our expectation that Baytex will be a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile with world class assets across North America; expectations as to Baytex's inventory of drilling prospects and ability to deliver top tier returns on invested capital and meaningful organic production growth; the expectation that Baytex will deliver industry leading returns, attractive production growth and free cash flow, with a strong balance sheet; our target of 10 to 15 percent total annual returns; the anticipated successful integration of the Baytex and Raging River teams; expectations of growing 2018 production exit rate and new well performance; our estimates for Baytex's 2019 annual average production, exploration and development capital, debt adjusted per share growth, adjusted funds flow, adjusted funds flow per share, net debt to adjusted funds flow, operating netback, free cash flow and the percentage of production that will be oil and NGLs; expectations as to the capability of Baytex to optimize capital allocation and activity based on commodity prices and economic returns by area; the drilling inventory of Baytex; that the Eagle For and Viking assets will generate significant free cash flow in excess of their exploration and development capital; anticipated first oil from the Kerrobert thermal project in October 2018; the ability of Baytex to advance the East Duvernay Shale light oil opportunity, including completions operations commencing in the next two weeks and spudding the first of two development wells later in Q4 2018; the percentage of exposure to various benchmark prices for crude oil and the percentage of our net production that is hedged; expected increases in crude oil volumes delivered by rail in Q3 and Q4 2018; forecasted production rate in Q4/2018 and exploration and development expenditures for the second half of 2018; our revised guidance for full year 2018 exploration and development capital, production, royalty rate, operating expense, transportation expense, general and administrative expenses and interest expense; planned 2019 exploration and development expenditures and resulting annual production; that we will provide board approved guidance for 2019 in late 2018; preliminary development plans for 2019 that is expected to generate significant free cash flow; our estimates for Baytex's 2019 adjusted funds flow per share; the impact of each US$5/bbl increase in the price of WTI above US$63/bbl on Baytex's adjusted funds flow; and expectations that Baytex will be well-positioned to pursue organic growth, reduce debt, pursue strategic acquisitions and consider the reinstatement of a dividend and/or share buybacks in 2019.  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: the ability of Baytex to realize the anticipated benefits of the strategic combination with Raging River; petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; the ability to add production and reserves through exploration and development activities; capital expenditure levels; the ability to borrow under credit agreements; the receipt, in a timely manner, of regulatory and other required approvals for 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; the ability to develop 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.

Baytex has disclosed certain expected details relating to Baytex's 2019 capital program and expected guidance; however, the board of directors of Baytex has not approved a budget for 2019 and as such the details relating to the 2019 capital program and guidance are intended only to illustrate Baytex's current expectations based on information and conditions known as of the date hereof. Baytex's actual 2019 capital budget once approved may differ from the details disclosed herein for a variety of reasons including as a result of any change in conditions and information known to Baytex prior to the date the 2019 budget is approved and/or as a result of Baytex's management and board of directors allocating capital differently than currently expected. The actual 2019 capital budget will impact the 2019 guidance provided herein as well. The actual 2019 capital program and the guidance set out herein may also differ from the expectations as set out herein due to the other risk factors identified herein.

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 credit facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in 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 hedging activities; the cost of developing and operating assets; depletion of reserves; risks associated with the exploitation of properties and ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating oil and natural gas reserves; 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 operations; risks associated with large projects; risks related to thermal heavy oil projects; risks associated with use of information technology systems; risks associated with the ownership of Baytex, 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 control. These and additional risk factors are discussed in Baytex's Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2017, 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 laws.

All amounts in this press release are stated in Canadian dollars unless otherwise specified.

Non-GAAP Financial and Capital Management Measures

This press release contains certain financial measures that do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore are considered non-GAAP measures. These non-GAAP measures may not be comparable to similar measures presented by other issuers. "Adjusted funds flow", "debt adjusted production per share growth", "free cash flow", "net debt" and "operating netback" are not recognized measures under IFRS, but are presented in this press release.

"Adjusted funds flow" is defined as cash flow from operating activities adjusted for changes in non-cash operating working capital and asset retirement obligations settled. Management of Baytex considers adjusted funds flow a key measure of performance as it demonstrates Baytex's ability to generate the cash flow necessary to fund capital investments, debt repayment, settlement of abandonment obligations and potential future dividends. In addition, the ratio of net debt to adjusted funds flow is used to manage Baytex's capital structure.

"Debt adjusted production per share growth" is defined as growth in production over the period on a per share basis with the number of shares adjusted based on debt outstanding. Baytex's 2019 debt adjusted production per share growth is calculated based on the forecast of 2019 production per debt-adjusted share divided by the combined production of Baytex and Raging River for Q2/2018 per debt-adjusted share as at closing of the transaction. Debt-adjusted share count is calculated as total shares outstanding plus incremental shares issued at current market price ($3.91) to eliminate net debt (i.e., full equitization of net debt). Management of Baytex believes that debt adjusted production per share growth is useful in determining the production growth on a per share basis as if all debt was extinguished by the issuance of shares.

"Free cash flow" is defined as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production volumes.

"Net debt" is defined as the sum of monetary working capital (which is current liabilities, excluding current financial derivatives and onerous contracts) and the principal amount of both the long-term notes and bank loans of Baytex. Management of Baytex believes that net debt assists in providing a more complete understanding of Baytex's cash liabilities.

"Operating netback" is defined as 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. Management of Baytex believes that operating netback assists in characterizing Baytex's 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.

This press release discloses drilling inventory and potential drilling locations. Drilling inventory and drilling locations refers 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. Unbooked locations 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 Eagle Ford, Baytex's net drilling locations include 187 proved, 69 probable and 263 unbooked locations. In the Viking, Baytex's net drilling locations include 1,109 proved, 51 probable and 1,340 unbooked locations. In Peace River, Baytex's net drilling locations include 73 proved, 91 probable and 204 unbooked locations.  In Lloydminster, Baytex's net drilling locations include 213 proved, 47 probable and 690 unbooked locations. In the East Duvernay Shale, Baytex's net drilling locations include 2 proved, 2 probable and 746 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.

Baytex Energy Corp.

Baytex is an oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Eagle Ford in the United States. Approximately 85% of Baytex's production is weighted toward crude oil and natural gas liquids. Baytex's common shares trade on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE.

For further information about Baytex, please visit the company 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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