Market Overview

Baytex Reports Q2 2018 Results

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CALGARY, Alberta, July 31, 2018 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex")((TSX, NYSE:BTE) reports its operating and financial results for the three and six months ended June 30, 2018 (all amounts are in Canadian dollars unless otherwise noted).

"We continued to deliver on our operational and financial targets in the second quarter, which included strong drilling results in Canada and the Eagle Ford. In addition, we are excited to be moving forward with the proposed merger with Raging River as we unite two strong oil companies with exceptional people and assets. We believe the combined company will deliver a powerful combination of per share production growth and strong free cash flow. We will be well-positioned to optimize our capital investment across our high rate of return asset base," commented Ed LaFehr, President and Chief Executive Officer.

Highlights

  • Entered into an arrangement agreement with Raging River Exploration Inc. ("Raging River") to create a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile. This strategic combination is expected to close on August 22, 2018.

  • Delivered production of 70,664 boe/d (79% oil and NGL) with exploration and development capital expenditures of $79 million during Q2/2018.

  • Generated adjusted funds flow of $107 million ($0.45 per basic share) or $136 million excluding realized financial derivatives gains and losses.

  • Realized an operating netback of $35.42/boe in the Eagle Ford, the strongest since Q3/2014. Our Eagle Ford light oil and condensate production received a premium sales price of US$67.62/bbl (or $87.38/bbl) given its proximity to Gulf Coast markets.

  • Established average 30-day initial gross production rates of approximately 1,850 boe/d per well from 32 (7.6 net) wells in the Eagle Ford that commenced production in the second quarter. This represents an approximate 25% improvement over wells brought on production in 2017.

  • Executed our Q2/2018 drilling program in Canada as planned with production increasing to 34,042 boe/d. Our first two northern Seal wells at Peace River generated 30-day initial production rates of 918 boe/d and 660 boe/d, respectively.

  • Expanded our crude by rail volumes to 8,300 bbl/d (33% of our heavy oil production) in Q2/2018. 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.

             

    Three Months Ended
Six Months Ended
    June 30, 2018
March 31, 2018 June 30, 2017 June 30, 2018
June 30, 2017
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
           
Petroleum and natural gas sales   $ 347,605  $ 286,067  $ 277,536  $ 633,672  $ 538,085
Adjusted funds flow (1)   106,690 84,255 83,136 190,945 164,505
Per share – basic   0.45 0.36 0.35 0.81 0.70
Per share – diluted   0.45 0.36 0.35 0.81 0.70
Net income (loss)   (58,761) (62,722) 9,268 (121,483) 20,364
Per share – basic   (0.25) (0.27) 0.04 (0.51) 0.09
Per share – diluted   (0.25) (0.27) 0.04 (0.51) 0.09
Exploration and development   78,830 93,534 78,007 172,364 174,566
Acquisitions, net of divestitures   (21) (2,026) 5,226 (2,047) 71,230
Total oil and natural gas capital expenditures   $ 78,809  $ 91,508  $ 83,233  $ 170,317  $ 245,796
             
Bank loan (2)   $ 213,538  $ 212,571 $ 264,032  $ 213,538  $ 264,032
Long-term notes (2)   1,548,490 1,525,595 1,541,694 1,548,490 1,541,694
Long-term debt   1,762,028 1,738,166 1,805,726 1,762,028 1,805,726
Working capital (surplus) deficiency   22,807 45,213 13,661 22,807 13,661
Net debt (3)   $ 1,784,835  $ 1,783,379  $ 1,819,387  $ 1,784,835  $ 1,819,387

             
             
             

  Three Months Ended Six Months Ended
  June 30, 2018 March 31, 2018 June 30, 2017 June 30, 2018 June 30, 2017
OPERATING          
Daily production          
Heavy oil (bbl/d) 25,544   24,868 25,577   25,208 25,104  
Light oil and condensate (bbl/d) 21,100   20,967 22,370   21,034 21,996  
NGL (bbl/d) 9,419   9,143 9,693   9,281 9,003  
Total oil and NGL (bbl/d) 56,063   54,978 57,640   55,523 56,103  
Natural gas (mcf/d) 87,605   87,261 91,028   87,434 89,771  
Oil equivalent (boe/d @ 6:1) (4) 70,664   69,522 72,812   70,095 71,065  
           
Benchmark prices          
WTI oil (US$/bbl) 67.88   62.87 48.28   65.37 50.10  
WCS heavy oil (US$/bbl) 48.61   38.59 37.16   43.60 37.25  
Edmonton par oil ($/bbl) 80.58   72.06 61.92   76.32 62.95  
LLS oil (US$/bbl) 71.37   67.07 49.70   69.24 51.10  
           
Baytex average prices (before hedging)          
Heavy oil ($/bbl) (5) 49.70   33.33 37.62   41.67 36.81  
Light oil and condensate ($/bbl) 86.75   79.20 60.68   83.01 61.94  
NGL ($/bbl) 31.37   26.17 22.70   28.82 24.38  
Total oil and NGL ($/bbl) 60.56   49.63 44.06   55.18 44.67  
Natural gas ($/mcf) 2.56   2.95 3.62   2.75 3.57  
Oil equivalent ($/boe) 51.22   42.96 39.41   47.15 39.77  
           
CAD/USD noon rate at period end 1.3142   1.2901 1.2983   1.3142 1.2983  
CAD/USD average rate for period 1.2911   1.2651 1.3447   1.2781 1.3338  
COMMON SHARE INFORMATION          
TSX          
Share price (Cdn$)          
High 6.23   4.35 4.81   6.23 6.97  
Low 3.34   3.01 2.87   3.01 2.87  
Close 4.37   3.53 3.15   4.37 3.15  
Volume traded (thousands) 391,396   177,572 216,383   568,968 472,026  
           
NYSE          
Share price (US$)          
High 4.85   3.54 3.63   4.85 5.20  
Low 2.59   2.37 2.15   2.37 2.15  
Close 3.33   2.74 2.43   3.33 2.43  
Volume traded (thousands) 175,808   118,236 109,758   294,044 248,931  
Common shares outstanding (thousands) 236,662   236,578 234,204   236,662 234,204  

Notes:

  1. 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, 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.  For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three and six months ended June 30, 2018.
  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. We include the cost of blending diluent when calculating our realized heavy oil price.

Strategic Combination with Raging River

On June 18, 2018, Baytex and Raging River announced that their respective boards of directors had unanimously agreed to a strategic combination of the two companies (the "Transaction"). The combined company, which will operate under the Baytex name, will be a well-capitalized, oil-weighted company with an attractive growth and free cash flow profile provided by its world class assets across North America. 

The combined company is expected to have production of approximately 94,000 boe/d from a diverse portfolio of high quality oil assets, including Viking, Peace River, Lloydminster and East Duvernay Shale properties in Canada and the Eagle Ford in Texas. The combined company will have a deep inventory of high quality drilling prospects that generate top tier returns on invested capital and have the capability to deliver meaningful organic production growth.

The Transaction will result in holders of common shares of Raging River receiving, directly or indirectly, 1.36 common shares of Baytex for each Raging River Share owned. The Transaction is subject to approval by the shareholders of both companies, the Court of Queen's Bench of Alberta and certain regulatory and other authorities, and is subject to the satisfaction or waiver of other customary closing conditions. 

The joint management information circular was mailed to shareholders of each of Baytex and Raging River on July 20, 2018. Baytex and Raging River shareholders will hold their respective shareholder meetings on August 21, 2018 and the Transaction is expected to close on August 22, 2018. For further information on the Transaction, please see the joint management information circular dated July 12, 2018 and the joint press release dated June 18, 2018.

Operating Results

Our operating results for the second quarter were consistent with our expectations as we continued to deliver on our operational and financial targets. We successfully executed our drilling program with strong results realized in the Eagle Ford and Canada.   

Production increased 2% to average 70,664 boe/d (79% oil and NGL) in Q2/2018, as compared to 69,522 boe/d (79% oil and NGL) in Q1/2018. Production in the first half of 2018 averaged 70,095 boe/d. During the second quarter, exploration and development capital expenditures totaled $79 million, bringing the aggregate spending in the first half of 2018 to $172 million. We participated in the drilling of 36 (8.1 net) wells with a 100% success rate during the second quarter.

Our 2018 production guidance range is unchanged at 68,000 to 72,000 boe/d with budgeted exploration and development capital expenditures of $325 to $375 million, and does not include the integration of Raging River, which is expected to close on August 22, 2018. Following closing of the Transaction, Baytex will provide revised guidance for full-year 2018.

Eagle Ford

Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. The asset generates the highest cash netbacks in our portfolio and contains a significant inventory of development prospects. In Q2/2018, we allocated 61% of our exploration and development expenditures to this asset and production averaged 36,622 boe/d (78% oil and NGL) during the second quarter, as compared to 36,017 boe/d in Q1/2018.

We continue to see strong well performance driven by enhanced completions in Karnes County. In addition, early results from Atascosa County are encouraging as we exploit the oil window on the western portion of our lands. In Q2/2018, we participated in the drilling of 18 (2.6 net) wells, commenced production from 32 (7.6 net) wells and at June 30, 2018 had 70 (18.5 net) wells waiting on completion. The wells that have been on production for more than 30 days established 30-day initial production rates of approximately 1,850 boe/d (65% light oil and condensate), which represents an approximate 25% improvement over wells brought on production in 2017. These wells were completed with approximately 28 effective frac stages per well (compared to 23 in 2015) and proppant per completed foot of approximately 2,100 pounds (compared to 1,100 pounds in 2015).

Peace River

Our Peace River region, located in northwest Alberta, has been a core asset 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 averaged 16,800 boe/d (92% heavy oil) during the second quarter, as compared to 16,500 boe/d in Q1/2018. In Q2/2018, we drilled one (1.0 net) well and commenced production from four (4.0 net) wells. Our first two northern Seal wells at Peace River generated 30-day initial production rates of 918 boe/d and 660 boe/d, respectively. Approximately 10 wells are anticipated to be drilled in the northern Seal area in 2018. We expect to have a second rig starting up in August as we continue to build operational momentum heading into 2019.

Lloydminster

Our Lloydminster region is characterized by multiple stacked pay formations at relatively shallow depths. The area has been successfully developed through vertical and horizontal drilling, water flood, steam-assisted gravity drainage operations and, more recently, the implementation of polymer flooding to further enhance reserves recovery. We have also adopted, where applicable, the multi-lateral well design and geosteering capability that we have successfully utilized at Peace River.  

Production averaged 10,300 boe/d (99% heavy oil) during the second quarter as compared to 10,000 boe/d in Q1/2018. We drilled 12 (3.3 net) crude oil wells in Q2/2018. During the second quarter, seven (7.0 net) wells drilled in Q1/2018 established peak 30-day initial production rates of approximately 200 bbl/d per well. In addition, we continued to advance our Kerrobert thermal project. Production at Kerrobert averaged 600 boe/d in H1/2018 and we expect to exit 2018 producing approximately 2,000 boe/d. We recommenced our Soda Lake multi-lateral drilling program in June and expect to have two rigs running in the second half of the year.

Financial Review

We generated adjusted funds flow of $107 million ($0.45 per basic share) in Q2/2018, compared to $84 million ($0.36 per basic share) in Q1/2018 and $83 million ($0.35 per basic share) in Q2/2017. The increase in adjusted funds flow is largely attributable to stronger oil price realizations, partially offset by realized financial derivatives losses.

Excluding realized financial derivatives gains and losses, adjusted funds flow in Q2/2018 was $136 million, compared to $94 million in Q1/2018. This represents the highest quarterly adjusted funds flow (excluding realized financial derivatives gains and losses) since Q4/2014 and demonstrates the strength of our diversified asset portfolio.  

Financial Liquidity

We maintain strong financial liquidity with our US$575 million revolving credit facilities approximately 70% undrawn and our first long-term note maturity not until 2021. With our strategy to target exploration and development capital expenditures at a level that approximates our adjusted funds flow, we expect this liquidity position to be stable going forward. In the first six months of 2018, exploration and development capital expenditures totaled $172 million, as compared to adjusted funds flow of $191 million ($230 million excluding realized financial derivatives losses).

On April 25, 2018, we extended the maturity of our revolving credit facilities by one year to June 2020. These facilities are covenant-based and do not require annual or semi-annual reviews. We are well within the financial covenants on these facilities as our Senior Secured Debt to Bank EBITDA ratio as at June 30, 2018 was 0.6:1.0, compared to a maximum permitted ratio of 3.5:1.0, and our interest coverage ratio was 4.1:1.0, compared to a minimum required ratio of 2.0:1.0.

Our net debt totaled $1.78 billion at June 30, 2018, which is down from $1.82 billion at June 30, 2017.

Operating Netback

Our operating netback (excluding realized financial derivatives gains and losses) improved 48% to $27.08/boe in Q2/2018, as compared to $18.30/boe in Q2/2017. During the second quarter, we benefited from continued strong liquids pricing in the Eagle Ford and improved heavy oil price realizations in Canada. The Eagle Ford generated an operating netback of $35.42/boe during Q2/2018 while our Canadian operations generated an operating netback of $18.12/boe.

In Q2/2018, the price for West Texas Intermediate light oil ("WTI") averaged US$67.88/bbl, as compared to US$48.28/bbl in Q2/2017. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select ("WCS") and WTI, averaged US$19.27/bbl in Q2/2018, as compared to US$11.12/bbl in Q2/2017. 

In the Eagle Ford, our assets are proximal to Gulf Coast markets with light oil and condensate production priced off the Louisiana Light Sweet ("LLS") crude oil benchmark, which is a function of the Brent price. In Q2/2018, the price for LLS averaged US$71.37/bbl, as compared to US$49.70/bbl in Q2/2017. During the second quarter, our light oil and condensate realized price in the Eagle Ford of US$67.62/bbl (or $87.38/bbl) represented a US$3.75/bbl discount to LLS.

The following table summarizes our operating netbacks for the periods noted.


  Three Months Ended June 30
  2018 2017
($ per boe except for sales volume) Canada U.S. Total
Canada U.S. Total
Sales volume (boe/d) 34,042   36,622   70,664 34,284   38,528   72,812  
             
Total sales, net of blending and other expense $ 41.61   $ 60.16   $ 51.22  $ 33.86   $ 44.34   $ 39.41  
Less:            
Royalties 5.81   17.77   12.01 4.53   13.09   9.06  
Operating expense 15.15   6.97   10.91 14.74   7.11   10.70  
Transportation expense 2.53     1.22 2.88     1.35  
Operating netback $ 18.12   $ 35.42   $ 27.08  $ 11.71   $ 24.14   $ 18.30  
Realized financial derivatives (loss) gain           (4.57)           0.40  
Operating netback after financial derivatives (loss) gain $ 18.12   $ 35.42   $ 22.51  $ 11.71   $ 24.14   $ 18.70  

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 adjusted funds flow. We realized a financial derivatives loss of $29 million in Q2/2018 due to the increased price of crude oil relative to the prices set in our contracts. A complete listing of our financial derivative contracts can be found in Note 17 to our Q2/2018 financial statements.

As part of our risk management program, we also transport crude oil to markets 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 year crude by rail commitments, which to-date total 7,500 bbl/d for 2019 and 5,000 bbl/d for 2020.

2018 Guidance

The following table summarizes our 2018 annual guidance and compares it to our 2018 year-to-date actual results. Following closing of the strategic combination with Raging River, we will provide revised guidance for the combined company.

  Guidance (1) H1/2018 Variance  
Exploration and development capital ($ millions) 325 - 375 172.4 - %
Production (boe/d) 68,000 - 72,000 70,095 - %
       
Expenses:      
  Royalty rate (%) ~ 23.0 23.7 1 %
  Operating ($/boe) 10.50 - 11.25 10.72 - %
  Transportation ($/boe) 1.35 - 1.45 1.29 (4) %
  General and administrative ($ millions) ~ 44 (1.72/boe) 21.6 (1.70/boe) (1) %
  Interest ($ millions) ~ 100 (3.95/boe) 50.0 (3.94/boe) - %

Note:

  1. As announced on December 7, 2017.

Additional Information

Our condensed consolidated interim unaudited financial statements for the three and six months ended June 30, 2018 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
9:00 a.m. MDT (11:00 a.m. EDT)

Baytex will host a conference call today, July 31, 2018, starting at 9:00am MDT (11:00am EDT). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq220180731.html in your web browser. 

An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex's shareholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this press release are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements").  In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance.  The forward-looking statements contained in this press release speak only as of the date thereof and are expressly qualified by this cautionary statement.

Specifically, this press release contains forward-looking statements relating to but not limited to: our business strategies, plans and objectives; that the combined enterprise of Baytex and Raging River will deliver per share production growth and strong free cash flow and be able to optimize capital investment; the expected closing date of the strategic combination with Raging River; the amount of crude oil we expect to deliver to market by rail in Q3/2018 and Q4/2018; the anticipated attributes of Baytex and Raging River as a combined company, including its daily production rate; Baytex's standalone 2018 production and capital expenditure guidance; that revised guidance will be provided on closing of the Raging River merger; our Eagle Ford assets, including our assessment that: it is a premier oil resource play, generates our highest cash netbacks and has a significant development inventory; our assessment that we can generate some of the strongest capital efficiencies in the oil and gas industry at our Peace River assets; our drilling plans in Peace River for the balance of 2018; the expected 2018 exit production rate for our Kerrobert thermal project; our drilling plans in Soda Lake for the balance of 2018; our strategy to target capital expenditures at a level that approximates our adjusted funds flow; our belief that we have strong financial liquidity and that our liquidity position will remain stable going forward; our ability to partially reduce the volatility in our adjusted funds flow by utilizing financial derivative contracts for commodity prices, foreign exchange rates and interest rates; and Baytex's standalone expected royalty rate and operating, transportation, general and administration and interest expenses for 2018. 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 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 and Capital Management Measures

Adjusted funds flow is not a measurement based on generally accepted accounting principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. We define adjusted funds flow as cash flow from operating activities adjusted for changes in non-cash operating working capital 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, 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. For a reconciliation of adjusted funds flow to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three and six months ended June 30, 2018.

Free cash flow is not a measurement based on GAAP in Canada. We define free cash flow as adjusted funds flow less sustaining capital. Sustaining capital is an estimate of the amount of exploration and development capital required to offset production declines on an annual basis and maintain flat production volumes.

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 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.

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 80% 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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