March 6, 2018 - 6:30 AM EST
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Baytex Reports 2017 Results With 26% Increase in Adjusted Funds Flow, 6% Increase in Reserves and Strong Eagle Ford Performance

CALGARY, Alberta, March 06, 2018 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex") (TSX:BTE) (NYSE:BTE) reports its operating and financial results for the three months and year ended December 31, 2017 (all amounts are in Canadian dollars unless otherwise noted).

“Our fourth quarter results demonstrate the impressive cash generating capability of our assets as commodity prices improve. With WTI averaging US$55/bbl, we realized our strongest operating netback in three years and generated adjusted funds flow of $106 million, a level we have not seen since mid-2015. We are delivering outstanding drilling results across our portfolio, including some of our best ever new well production rates in the Eagle Ford. In 2017, we continued to drive cost and capital efficiency in our business and I am pleased that we increased our production, reserves and adjusted funds flow. Our plans for 2018 build on this operational momentum,” commented Ed LaFehr, President and Chief Executive Officer.

Highlights

  • Generated production of 69,556 boe/d (81% oil and NGL) during Q4/2017, an increase of 7% over Q4/2016, and 70,242 boe/d for full-year 2017, exceeding the high end of guidance, with capital expenditures of $326 million, in line with annual guidance;  
     
  • Delivered adjusted funds flow of $106 million ($0.45 per basic share) in Q4/2017, an increase of 37% over Q4/2016, and $348 million ($1.48 per basic share) for the full-year 2017, an increase of 26% over 2016;
     
  • Decreased cash costs (operating, transportation and general and administrative expenses) by 7.5% on a boe basis as compared to the mid-point of original guidance;
     
  • Realized an operating netback in Q4/2017 of $21.78/boe ($22.08/boe including financial derivative gains);
     
  • Reduced net debt to $1.73 billion; adjusted funds flow exceeded capital expenditures by $21 million;
     
  • Continued strong performance in the Eagle Ford with wells that commenced production during Q4/2017 representing some of the highest productivity wells drilled to-date with 30-day initial gross production rates of approximately 1,700 boe/d per well. Two wells in our new northern Austin Chalk fracture trend demonstrated 30-day initial gross production rates of approximately 2,400 boe/d per well (89% liquids);
     
  • Increased proved plus probable reserves by 6% to 432 mmboe (201% production replacement). Year-end 2017 proved plus probable reserves are comprised of 80% oil and NGL and 20% natural gas;
     
  • Recorded finding and development (“F&D”) costs for proved plus probable reserves, including changes in future development costs, of $7.26/boe and generated a recycle ratio of 2.7x. Recorded finding, development and acquisition (“FD&A”) costs of $9.11/boe with a recycle ratio of 2.2x;
     
  • In the Eagle Ford, replaced 225% of production and increased proved plus probable reserves by 8% to 233 mmboe. From the time of acquisition in June 2014, proved plus probable reserves in the Eagle Ford have increased by 40%. Prior to deducting total production of 49 mmboe over this period, reserves growth is approximately 70%;  
     
  • In Canada, replaced 175% of production and increased proved plus probable reserves by 5% to 199 mmboe, as we returned to active development, including the integration of the heavy oil assets acquired in the Peace River region in January 2017; and         
     
  • Net asset value at year-end 2017 increased 11% to $10.08 per share (before tax and discounted at 10%).
 Three Months EndedYears Ended
 December 31,
2017

  September 30,
2017
  December 31,
2016
  December 31,
2017

 December 31,
2016
 
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
     
Petroleum and natural gas sales$302,186  $254,430  $233,116  $1,091,534 $780,095 
Adjusted funds flow (1)105,796  77,340  77,239  347,641 276,251 
Per share – basic0.45  0.33  0.36  1.48 1.30 
Per share – diluted0.44  0.33  0.36  1.47 1.30 
Net income (loss)76,038  (9,228) (359,424) 87,174 (485,184)
Per share – basic0.32  (0.04) (1.66) 0.37 (2.29)
Per share – diluted0.32  (0.04) (1.66) 0.37 (2.29)
Exploration and development90,156  61,544  68,029  326,266 224,783 
Acquisitions, net of divestitures(3,937) (7,436) (322) 59,857 (63,120)
Total oil and natural gas capital expenditures$86,219  $54,108  $67,707  $386,123 $161,663 
      
Bank loan (2)$213,376  $226,249  $191,286  $213,376 $191,286 
Long-term notes (2)1,489,210  1,488,450  1,584,158  1,489,210 1,584,158 
Long-term debt1,702,586  1,714,699  1,775,444  1,702,586 1,775,444 
Working capital (surplus) deficiency31,698  34,106  (1,903) 31,698 (1,903)
Net debt (3)$1,734,284  $1,748,805  $1,773,541  $1,734,284 $1,773,541 


   
 Three Months EndedYears Ended
 December 31,
2017
 September 30,
2017
 December 31,
2016
 December 31,
2017
 December 31,
2016
 
OPERATING     
Daily production     
Heavy oil (bbl/d)24,945 26,161 22,982 25,326 23,586 
Light oil and condensate (bbl/d)21,229 20,041 20,163 21,314 21,377 
NGL (bbl/d)9,872 8,940 8,319 9,206 9,349 
Total oil and NGL (bbl/d)56,046 55,142 51,464 55,846 54,312 
Natural gas (mcf/d)81,063 85,006 82,032 86,375 91,182 
Oil equivalent (boe/d @ 6:1) (4)69,556 69,310 65,136 70,242 69,509 
      
Benchmark prices     
WTI oil (US$/bbl)55.40 48.20 49.29 50.95 43.33 
WCS heavy oil (US$/bbl)43.14 38.26 34.97 38.97 29.49 
Edmonton par oil ($/bbl)69.02 56.74 61.58 62.92 53.01 
LLS oil (US$/bbl)60.50 50.27 49.95 53.26 43.82 
      
Baytex average prices (before hedging)     
Heavy oil ($/bbl) (5)42.03 38.18 34.33 38.46 26.46 
Light oil and condensate ($/bbl)72.64 58.22 60.12 63.74 50.32 
NGL ($/bbl)29.14 25.18 22.64 25.86 17.16 
Total oil and NGL ($/bbl)51.35 43.36 42.55 46.03 34.25 
Natural gas ($/mcf)2.89 2.89 3.61 3.24 2.69 
Oil equivalent ($/boe)44.75 38.04 38.16 40.58 30.29 
      
CAD/USD noon rate at period end1.2518 1.2510 1.3427 1.2518 1.3427 
CAD/USD average rate for period1.2717 1.2524 1.3339 1.2979 1.3256 


   
 Three Months EndedYears Ended
 December 31,
2017
September 30,
2017
December 31,
2016
December 31,
2017
December 31,
2016
COMMON SHARE INFORMATION     
TSX     
Share price (Cdn$)     
High4.594.137.356.979.04
Low2.952.764.852.761.57
Close3.773.766.563.776.56
Volume traded (thousands)195,013156,562351,040823,5911,677,986
      
NYSE     
Share price (US$)     
High3.063.165.615.207.14
Low2.302.133.602.131.08
Close2.763.014.482.764.48
Volume traded (thousands)25,50481,848186,423356,263707,973
Common shares outstanding (thousands)235,451235,451233,449235,451233,449

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 year ended December 31, 2017.
  2. Principal amount of instruments.
  3. Net debt is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. We define net debt to be the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives and onerous contracts)) and the principal amount of both the long-term notes and the bank loan.
  4. Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. The use of boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
  5. Heavy oil prices exclude condensate blending.


Operating Results

2017 was a year about delivering on our commitments in a challenging commodity price environment. We delivered on our operational and financial targets, reduced our overall debt and acquired a strategic asset in Peace River. In addition, we continued to drive cost and capital efficiency in our business and increased our production, reserves and adjusted funds flow.   

Production averaged 69,556 boe/d (81% oil and NGL) in Q4/2017, as compared to 69,310 boe/d (80% oil and NGL) in Q3/2017 and 65,136 boe/d in Q4/2016. For the full-year 2017, production averaged 70,242 boe/d (80% oil and NGL), exceeding the high end of our production guidance range of 66,000 to 70,000 boe/d announced in December 2016 and subsequently tightened to 69,500 to 70,000 boe/d.

Capital expenditures for exploration and development activities totaled $90 million in Q4/2017 and $326 million for full-year 2017, in line with our guidance range of $300-$350 million announced in December 2016 and subsequently tightened to $310‑$330 million. We participated in the drilling of 226 (86.6 net) wells with a 100% success rate during the year.

We generated adjusted funds flow of $348 million during 2017, exceeding capital expenditures by $21 million. We employ a flexible approach to prudently manage our capital program as we target exploration and development capital expenditures at a level that approximates our adjusted funds flow.

Eagle Ford

Our Eagle Ford asset in South Texas is one of the premier oil resource plays in North America. The assets generate the highest cash netbacks in our portfolio and contain a significant inventory of development prospects. In 2017, we allocated 65% of our exploration and development expenditures to these assets.

Production averaged 37,362 (78% liquids) during the fourth quarter, as compared to 34,750 boe/d in Q3/2017. Production for the full-year 2017 averaged 36,678 boe/d.

We continue to see strong well performance driven by enhanced completions in the oil window of our acreage. In 2017, we participated in the drilling of 140 (32.8 net) wells and commenced production from 115 (28.7 net) wells. The wells that have been on production for more than 30 days during 2017 established 30-day initial production rates of approximately 1,450 boe/d, which represents an approximate 12% improvement over 2016.

During the fourth quarter, we participated in the completion of five pads (total of 25 gross wells), including two in Longhorn and three in Sugarloaf. These pads were completed with approximately 30 effective frac stages per well and proppant per completed foot of approximately 2,000 pounds, which is more than double the frac intensity of wells previously drilled in the area. The wells that commenced production during the fourth quarter represent some of the highest productivity wells drilled to-date on our lands and, on average, established 30-day initial gross production rates of approximately 1,700 boe/d per well. Two of these wells in our new northern Austin Chalk fracture trend demonstrated 30-day initial gross production rates of approximately 2,400 boe/d per well.

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. In addition, through detailed re-mapping of the Bluesky formation, we have been able to effectively increase our exposure to pay in the laterals of new wells, achieving 97% in zone performance.

Production averaged 16,700 boe/d (93% heavy oil) during the fourth quarter and 17,550 boe/d for the full-year 2017. After limited activity on these lands in 2016, we drilled 8 (8.0 net) wells in 2017. These wells established an average 30-day initial production rate of approximately 400 bbl/d per well with our highest productivity well averaging over 600 bbl/d.

Lloydminster

Our Lloydminster region, which straddles the Alberta and Saskatchewan border, is characterized by multiple stacked pay formations at relatively shallow depths, which we have successfully developed through vertical and horizontal drilling, water flood and steam-assisted gravity drainage operations. We have also adopted, where applicable, the multi-lateral well design and geosteering capability that we have successfully utilized at Peace River.

Production averaged 9,600 boe/d (99% heavy oil) during the fourth quarter and 9,100 boe/d for the full-year 2017. We drilled 24 (11.4 net) wells during the fourth quarter and 65 (32.8 net) wells in 2017. During the fourth quarter, seven operated wells (including four multi-lateral horizontal wells) established an average 30-day initial production rate of approximately 180 bbl/d per well.

Financial Review

We generated adjusted funds flow of $106 million ($0.45 per basic share) in Q4/2017, compared to $77 million ($0.33 per basic share) in Q3/2017. Full-year adjusted funds flow was $348 million ($1.48 per basic share), compared to $276 million ($1.30 basic per share) in 2016. Excluding financial derivatives gains, adjusted funds flow in 2017 was $340 million, compared to $179 million in 2016, an increase of 90% due primarily to higher commodity prices. This illustrates the sensitivity of our operations to improvements in commodity prices.  

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.    

Our revolving credit facilities, which currently mature in June 2019, are covenant-based and do not require annual or semi-annual reviews. We are well within our financial covenants on these facilities as our Senior Secured Debt to Bank EBITDA ratio as at December 31, 2017 was 0.5:1.0, compared to a maximum permitted ratio of 5.0:1.0 (which steps down to 3.5:1.0 after December 31, 2018) and our interest coverage ratio was 4.5:1.0, compared to a minimum required ratio of 1.25:1.0 (which steps up to 2.0:1.0 after December 31, 2018).

Our net debt totaled $1.73 billion at December 31, 2017, which is down $39 million from December 31, 2016.

Operating Netback

Our fourth quarter operating netback of $21.78/boe (excluding financial derivatives) is the strongest we have realized since 2014 and demonstrates the cash generating ability of our assets in an improved commodity price environment. The Eagle Ford generated an operating netback of $30.19/boe during Q4/2017 while our Canadian operations generated an operating netback of $12.01/boe.

In Q4/2017, the price for West Texas Intermediate light oil (“WTI”) averaged US$55.40/bbl, as compared to US$49.29/bbl in Q4/2016. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, improved slightly during Q4/2017, averaging US$12.26/bbl, as compared to US$14.32/bbl in Q4/2016.

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. As a result, we benefited during the fourth quarter from a widening of the Brent-WTI spread. In addition, increased competition for physical field supplies has resulted in improved price realizations relative to LLS. During the fourth quarter, our light oil and condensate price in the Eagle Ford of US$57.47/bbl (or $73.08/bbl), which represented a US$3.03/bbl discount to LLS, as compared to a historical discount of approximately US$6.00/bbl.    

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

 Three Months Ended December 31
 20172016
($ per boe except for sales volume)CanadaU.S.TotalCanadaU.S.Total
Sales volume (boe/d)32,194 37,362 69,556 31,704 33,432 65,136 
       
Realized sales price$36.89 $51.53 $44.75 $31.10 $44.84 $38.16 
Less:      
Royalties5.72 15.30 10.86 4.82 13.52 9.28 
Operating expense16.57 6.04 10.91 13.10 6.98 9.96 
Transportation expense2.59  1.20 2.67  1.30 
Operating netback$12.01 $30.19 $21.78 $10.51 $24.34 $17.62 
Realized financial derivatives gain     0.30      1.62 
Operating netback after financial derivatives gain$12.01 $30.19 $22.08 $10.51 $24.34 $19.24 

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 gain of $8 million in 2017, as compared to a gain of $97 million in 2016.

For 2018, we have entered into hedges on approximately 54% of our net crude oil exposure. This includes 43% of our net WTI exposure with 38% fixed at US$52.26/bbl and 5% hedged utilizing a 3-way option structure that provides us with downside price protection at US$54.40/bbl and upside participation to US$60.00/bbl. 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 33% of our net WCS differential exposure at a price differential to WTI of US$14.19/bbl and 28% 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.

As part of our risk management program, we also transport crude oil to markets by rail when economics warrant. In 2017, we delivered 5,000 bbl/d (approximately 20%) of our heavy oil volumes to market by rail. We expect our oil volumes delivered to market by rail to increase to approximately 6,000-7,000 bbl/d during the first quarter of 2018.  

A complete listing of our financial derivative contracts can be found in Note 18 to our 2017 financial statements.

Outlook for 2018

Commodity prices remain volatile with WTI currently above US$60/bbl and Canadian heavy oil differentials averaging US$24/bbl for Q1/2018 due to transportation challenges. We see these wide differentials as temporary as the industry works to alleviate the bottlenecks through crude by rail and existing pipeline optimization and reconfigurations. We remain supporters of pipeline expansion as our medium term solutions to market access. We have the operational flexibility to adjust our spending plans based on changes in the commodity price environment.

We are encouraged by our operating results in the Eagle Ford and the strong cash generating capability of this asset as the prices for Brent and LLS are above US$63/bbl. During the fourth quarter, our netback in the Eagle Ford of $30.19/bbl was the strongest we have realized since 2014. At current crude oil prices, we expect the Eagle Ford to generate significant free cash flow in 2018.

In Canada, we are executing our first quarter drilling and development program as planned with improved WTI pricing partially offsetting the widening of the WCS differential. We continue to manage our heavy oil sales portfolio, including operational optimization, crude-by rail and the use of financial and physical hedges to optimize our heavy oil netbacks.

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.

The following table summarizes our 2018 annual guidance.

Exploration and development capital$325 - $375 million
Production68,000 - 72,000 boe/d
  
Expenses: 
  Royalty rate~ 23%
  Operating$10.50 - $11.25/boe
  Transportation$1.35 - $1.45/boe
  General and administrative~$44 million, $1.72/boe
  Interest~ $100 million, $3.95/boe

Year-end 2017 Reserves

Baytex's year-end 2017 proved and probable reserves were evaluated by Sproule Unconventional Limited (“Sproule”) and Ryder Scott Company, L.P. (“Ryder Scott”), both independent qualified reserves evaluators. Sproule prepared our reserves report by consolidating the Canadian properties evaluated by Sproule with the United States properties evaluated by Ryder Scott, in each case using Sproule's December 31, 2017 forecast price and cost assumptions. Ryder Scott also evaluated the possible reserves associated with our Eagle Ford assets.

All of our oil and gas properties were evaluated or audited in accordance with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). Reserves associated with our thermal heavy oil projects at Peace River, Gemini (Cold Lake) and Kerrobert have been classified as bitumen.  Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2017, which will be filed on or before March 31, 2018.

2017 Highlights

Highlights of the evaluation of our Total Proved plus Probable (“2P”), Total Proved (“1P”) and Proved Developed Producing (“PDP”) reserves are provided below.  Finding and development (“F&D”) and finding, development and acquisition (“FD&A”) costs are all reported inclusive of future development costs (“FDC”).

  • Active Development in the U.S. and Canada Drives Reserves Growth: Continued strong performance and capital investment levels in the Eagle Ford along with a resumption of activity in Canada delivered reserves and value growth. Relative to year-end 2016, total company 2P reserves increased 6% to 432 mmboe (201% production replacement) while 1P reserves increased 1% to 256 mmboe (111% production replacement).  As a percentage of 2P reserves, oil and NGL reserves represented 80%.
     
  • Strong Recycle Ratios:  Total company 2P F&D of $7.26/boe and 2P FD&A of $9.11/boe improved relative to our three-year averages of $10.45/boe and $10.51/boe, respectively. Based on our 2017 operating netback of $19.62/boe (including financial derivatives gain), we generated strong recycle ratios of 2.7x for F&D and 2.2x for FD&A in 2017. 1P and PDP F&D recycle ratios improved to 2.2x and 1.4x, respectively.
     
  • Growth in Value: The net present value (before income taxes) of the future net revenue attributable to our reserves, discounted at 10%, is estimated to be $4.1 billion ($3.9 billion at year-end 2016). This led to a net asset value(1), discounted at 10%, of $10.08 per share (11% higher than year-end 2016). We maintained a strong reserves life index (“RLI”), excluding thermal reserves, of 9.5 years on a proved basis and 14.3 years on a proved plus probable basis, which is calculated using annualized Q4/2017 production.
     
  • Continued Outperformance in the Eagle Ford: Eagle Ford 2P reserves increased 8% to 233.3 mmboe, replacing 225% of production. Since acquiring the assets in June 2014, 2P reserves in the Eagle Ford have grown 40%. Positive technical revisions of 20.8 mmboe were realized in the Eagle Ford, reflecting enhanced type well profiles. We have also booked an initial 5.7 mmboe in our new fractured Austin Chalk play in the northern part of our acreage.
     
  • Resumption of Activity in Canada: Canada 2P reserves increased 5% to 198.7 mmboe, replacing 175% of production due to a return to active development in Canada, including the integration of the heavy oil assets acquired in the Peace River region in January 2017.           

Note:

  1. Based on the estimated reserves value of $4.1 billion plus a value for undeveloped land holdings, net of long-term debt, asset retirement obligations and working capital. See “Net Asset Value”.

The following table reconciles the change in reserves during 2017 by reserves category and operating area.

(gross reserves, mmboe)Eagle Ford  Heavy Oil Canada
Conventional
 Thermal   Total 
           
Proved Developed Producing          
  December 31, 201660.8 28.3 9.0 0.4 98.5 
  Additions, net of revisions16.7 9.6 1.2 0.0 27.5 
  Production(13.4)(9.4)(2.5)(0.3)(25.6)
  December 31, 201764.1 28.5 7.7 0.1 100.4 
  % Change5%1%(14%) 2%
           
Proved           
  December 31, 2016168.1 55.2 15.9 13.5 252.7 
  Additions, net of revisions17.0 9.0 2.3 0.1 28.5 
  Production(13.4)(9.4)(2.5)(0.3)(25.6)
  December 31, 2017171.7 54.8 15.7 13.3 255.6 
  % Change2%(1%)(1%)(1%)1%
           
Proved Plus Probable           
  December 31, 2016216.5 85.0 35.3 69.3 406.1 
  Additions, net of revisions30.2 20.1 1.2 0.0 51.5 
  Production(13.4)(9.4)(2.5)(0.3)(25.6)
  December 31, 2017233.3 95.7 34.0 69.0 432.0 
  % Change8%13%(4%)0%6%


Petroleum and Natural Gas Reserves as at December 31, 2017

The following table sets forth our gross and net reserves volumes at December 31, 2017 by product type and reserves category using Sproule's forecast prices and costs. Please note that the data in the table may not add due to rounding.

CANADA Forecast Prices and Costs
  Heavy Oil Bitumen Light and Medium Oil
    Gross(1)   Net(2)   Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mbbl) (mbbl)  (mbbl) (mbbl)  (mbbl) (mbbl) 
Proved         
  Developed Producing 26,276 20,748  94 92  1,482 1,441 
  Developed Non-Producing 1,750 1,498  7,744 7,072  1 1 
  Undeveloped 18,680 16,608  5,428 4,546  125 122 
Total Proved 46,706 38,854  13,266 11,709  1,608 1,564 
Probable 39,757 33,563  55,726 43,833  1,225 1,090 
Total Proved Plus Probable 86,463 72,417  68,992 55,542  2,833 2,654 
          
          
CANADA Forecast Prices and Costs
  Natural Gas Liquids(3) Conventional
Natural Gas(4)
 Oil Equivalent(5)
    Gross(1)   Net(2)   Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mbbl) (mbbl)    (mmcf)   (mmcf)  (mboe) (mboe) 
Proved         
  Developed Producing 1,075 761  43,929 37,680  36,249 29,322 
  Developed Non-Producing 21 12  27,034 25,309  14,021 12,801 
  Undeveloped 1,522 1,228  46,856 41,080  33,564 29,351 
Total Proved 2,618 2,002  117,819 104,069  83,834 71,474 
Probable 3,132 2,428  89,963 77,782  114,834 93,878 
Total Proved Plus Probable 5,750 4,430  207,782 181,853  198,667 165,352 


UNITED STATES Forecast Prices and Costs
  Tight Oil Natural Gas Liquids(3) Shale Gas
    Gross(1)   Net(2)   Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mbbl) (mbbl)    (mbbl)   (mbbl)  (mmcf) (mmcf) 
Proved         
  Developed Producing 20,191 14,809  28,052 20,742  61,139 45,273 
  Developed Non-Producing 32 23  111 81  209 152 
  Undeveloped 30,074 22,022  53,784 39,590  111,506 82,186 
Total Proved 50,296 36,854  81,947 60,413  172,855 127,611 
Probable 11,390 8,361  35,830 26,333  75,686 55,607 
Total Proved Plus Probable 61,686 45,215  117,777 86,745  248,541 183,218 
Possible(6) 19,992 14,679  41,964 30,862  89,370 65,736 
Total Proved Plus Probable Plus Possible 81,679 59,894  159,741 117,607  337,910 248,954 


UNITED STATES Forecast Prices and Costs
  Conventional
Natural Gas(4)
 Oil Equivalent(5)
    Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mmcf) (mmcf)  (mboe)   (mbbl) 
Proved      
  Developed Producing 34,115 25,076  64,119 47,276 
  Developed Non-Producing 91 65  193 140 
  Undeveloped 29,812 21,794  107,410 78,942 
Total Proved 64,018 46,935  171,722 126,358 
Probable 10,761 7,900  61,628 45,278 
Total Proved Plus Probable 74,778 54,835  233,349 171,635 
Possible(6) 19,577 14,372  80,115 58,892 
Total Proved Plus Probable Plus Possible 94,356 69,207  313,464 230,528 


TOTAL Forecast Prices and Costs
  Heavy Oil Bitumen Light and Medium Oil
    Gross(1)   Net(2)   Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mbbl) (mbbl)  (mbbl) (mbbl)  (mbbl) (mbbl) 
Proved         
  Developed Producing 26,276 20,748  94 92  1,482 1,441 
  Developed Non-Producing 1,750 1,498  7,744 7,072  1 1 
  Undeveloped 18,680 16,608  5,428 4,546  125 122 
Total Proved 46,706 38,854  13,266 11,709  1,608 1,564 
Probable 39,757 33,563  55,726 43,833  1,225 1,090 
Total Proved Plus Probable 86,463 72,417  68,992 55,542  2,833 2,654 
Possible(6)(7)         
Total Proved Plus Probable Plus Possible 86,463 72,417  68,992 55,542  2,833 2,654 
          
          
TOTAL Forecast Prices and Costs
  Tight Oil Natural Gas Liquids(3) Shale Gas
    Gross(1)   Net(2)   Gross(1)   Net(2)    Gross(1)   Net(2) 
Reserves Category (mbbl) (mbbl)    (mbbl)   (mbbl)  (mmcf) (mmcf) 
Proved         
  Developed Producing 20,191 14,809  29,128 21,503  61,139 45,273 
  Developed Non-Producing 32 23  131 93  209 152 
  Undeveloped 30,074 22,022  55,306 40,818  111,506 82,186 
Total Proved 50,296 36,854  84,564 62,414  172,855 127,611 
Probable 11,390 8,361  38,962 28,760  75,686 55,607 
Total Proved Plus Probable 61,686 45,215  123,526 91,175  248,541 183,218 
Possible(6)(7) 19,992 14,679  41,964 30,862  89,370 65,736 
Total Proved Plus Probable Plus Possible 81,679 59,894  165,491 122,037  337,910 248,954 


TOTAL Forecast Prices and Costs
  Conventional
Natural Gas(4)
 Oil Equivalent(5)
    Gross(1)   Net(2)   Gross(1)   Net(2) 
Reserves Category (mmcf) (mmcf)    (mboe)   (mboe) 
Proved      
  Developed Producing 78,045 62,756  100,368 76,598 
  Developed Non-Producing 27,125 25,374  14,214 12,941 
  Undeveloped 76,668 62,874  140,974 108,293 
Total Proved 181,837 151,004  255,556 197,831 
Probable 100,723 85,683  176,461 139,155 
Total Proved Plus Probable 282,561 236,687  432,017 336,987 
Possible(6)(7) 19,577 14,372  80,115 58,892 
Total Proved Plus Probable Plus Possible 302,138 251,059  512,131 395,879 

Notes:

  1. “Gross” reserves means the total working and royalty interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
  2. “Net” reserves means Baytex's gross reserves less all royalties payable to others.
  3. Natural Gas Liquids includes condensate.
  4. Conventional Natural Gas includes associated, non-associated and solution gas.
  5. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.  BOEs 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.
  6. Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
  7. The total possible reserves include only possible reserves from the Eagle Ford assets. The possible reserves associated with the Canadian properties have not been evaluated.

Reserves Reconciliation  

The following table reconciles the year-over-year changes in our gross reserves volumes by product type and reserves category using Sproule's forecast prices and costs.  Please note that the data in table may not add due to rounding.

  Reconciliation of Gross Reserves (1)(2)
By Principal Product Type
Forecast Prices and Costs
  Heavy Oil Bitumen
  Proved Probable Proved +
Probable
  Proved Probable Proved +
Probable
 
Gross Reserves Category (mbbl) (mbbl) (mbbl)  (mbbl) (mbbl) (mbbl) 
December 31, 2016 46,875 29,325 76,199  13,465 55,835 69,300 
Extensions 638 500 1,138     
Infill Drilling 369 364 732     
Improved Recoveries  1,997 1,997     
Technical Revisions 1,121 (2,861)(1,740) 197 (142)55 
Discoveries        
Acquisitions (3) 7,941 11,334 19,275     
Dispositions (1,221)(974)(2,195)    
Economic Factors (89)73 (16) (80)33 (47)
Production (8,927) (8,927) (317) (317)
December 31, 2017 46,706 39,757 86,463  13,266 55,726 68,992 
     
     
  Light and Medium Crude Oil Tight Oil
  Proved Probable Proved +
Probable
  Proved Probable Proved +
Probable
 
Gross Reserves Category (mbbl) (mbbl) (mbbl)  (mbbl) (mbbl) (mbbl) 
December 31, 2016 2,293 1,794 4,087  49,714 8,399 58,113 
Extensions        
Infill Drilling     1,307 2,252 3,559 
Improved Recoveries        
Technical Revisions (4) 422 31 453  3,821 736 4,557 
Discoveries        
Acquisitions        
Dispositions (720)(559)(1,279)    
Economic Factors 38 (41)(3) 8 3 11 
Production (425) (425) (4,553) (4,553)
December 31, 2017 1,608 1,225 2,833  50,296 11,390 61,686 
     
     
  Natural Gas Liquids(5) Shale Gas
  Proved Probable Proved +
Probable
  Proved Probable Proved +
Probable
 
Gross Reserves Category (mbbl) (mbbl) (mbbl)  (mmcf) (mmcf) (mmcf) 
December 31, 2016 82,692 31,825 114,516  173,828 59,075 232,903 
Extensions 90 224 314     
Infill Drilling 1,393 1,095 2,488  2,096 6,464 8,560 
Improved Recoveries        
Technical Revisions (4) 6,487 5,758 12,245  7,590 10,190 17,781 
Discoveries        
Acquisitions 115 81 196     
Dispositions        
Economic Factors (50)(21)(71) (133)(43)(177)
Production (6,162) (6,162) (10,526) (10,526)
December 31, 2017 84,564 38,962 123,526  172,855 75,686 248,541 
     
     
  Conventional Natural Gas(6)  Oil Equivalent(7)
  Proved Probable Proved +
Probable
  Proved Probable Proved +
Probable
 
Gross Reserves Category (mmcf) (mmcf) (mmcf)  (mboe) (mboe) (mboe) 
December 31, 2016 172,016 98,112 270,127  252,679 153,375 406,053 
Extensions 2,067 5,042 7,109  1,073 1,564 2,637 
Infill Drilling 3,421 845 4,266  3,987 4,929 8,916 
Improved Recoveries      1,997 1,997 
Technical Revisions (4) 21,703 (6,086)15,617  16,931 4,206 21,137 
Discoveries        
Acquisitions (3) 4,241 3,008 7,249  8,763 11,916 20,679 
Dispositions (2)(2)(4) (1,942)(1,534)(3,475)
Economic Factors (608)(195)(803) (296)8 (289)
Production (21,001) (21,001) (25,639) (25,639)
December 31, 2017 181,837 100,724 282,560  255,556 176,461 432,017 

Notes:

  1. “Gross” reserves means the total working and royalty interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
  2. Reserves information as at December 31, 2017 and 2016 is prepared in accordance with NI 51-101.
  3. Heavy oil and conventional natural gas acquisitions are principally attributable to reserves associated with the Peace River assets acquired on January 20, 2017.
  4. Positive technical revisions for tight oil, natural gas liquids and shale gas are largely the result of enhanced type well profiles on our Eagle Ford acreage. 
  5. Natural gas liquids include condensate.
  6. Conventional natural gas includes associated, non-associated and solution gas.
  7. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.  BOEs 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.

Reserves Life Index

The following table sets forth our reserves life index, which is calculated by dividing our proved and proved plus probable reserves (excluding thermal reserves) at year-end 2017 by annualized Q4/2017 production.

 Q4/2017 Actual   Reserves Life Index (years)
 Production Proved Proved Plus Probable
Oil and NGL (bbl/d)56,046 9.0 13.4
Natural Gas (mcf/d)81,063 12.0 17.9
Oil Equivalent (boe/d)69,556 9.5 14.3


Capital Program Efficiency

Based on the evaluation of our petroleum and natural gas reserves prepared in accordance with NI 51-101 by our independent qualified reserves evaluators, the efficiency of our capital programs (including FDC) is summarized in the following table.

  2017  2016  2015  Three-Year
Total / Average
2015 - 2017 
Capital Expenditures ($ millions)      
Exploration and development $326.3  $224.8  $521.0  $1,072.1 
Acquisitions (net of dispositions) 59.9  (63.6) 1.6  (2.1)
Total $386.1  $161.2  $522.7  $1,070.0 
         
Change in Future Development Costs – Proved ($ millions)        
Exploration and development $(132.6) $(219.4) $(397.9) $(749.9)
Acquisitions (net of dispositions)  35.5   7.6   6.0   49.1 
Total $(97.1) $(211.8) $(391.9) $(700.8)
         
Change in Future Development Costs – Proved plus Probable ($ millions)          
Exploration and Development $(76.4) $108.8  $(399.9) $(367.5)
Acquisitions (net of dispositions) 160.6  1.9  0.5  163.0 
Total $84.2  $110.7  $(399.4) $(204.5)
         
Proved Reserves Additions (mboe)        
Exploration and development 21,695  5,041  21,729  48,465 
Acquisitions (net of dispositions) 6,821  (1,564) 537  5,794 
Total 28,516  3,477  22,266  54,259 
         
Proved plus Probable Reserves Additions (mboe)        
Exploration and development 34,398  17,253  15,782  67,433 
Acquisitions (net of dispositions) 17,204  (2,408) 126  14,922 
Total 51,602  14,845  15,908  82,355 
         
F&D costs ($/boe) (1)        
Proved $8.93  $1.07  $5.67  $6.65 
Proved plus probable $7.26  $19.33  $7.68  $10.45 
         
FD&A costs ($/boe) (2)        
Proved $10.13  $  (5)  $5.88  $6.80 
Proved plus probable $9.11  $18.33  $7.75  $10.51 
         
Ratios (based on proved plus probable reserves)        
Production replacement ratio (3)  201%  58%  52%  100%
Recycle ratio (4)  2.7x  0.9x  2.9x  2.2x

Notes:

  1. F&D costs are calculated as total exploration and development expenditures (excluding acquisition and divestitures and including the change in FDC) divided by reserves additions from exploration and development activity.
  2. FD&A costs are calculated as total capital expenditures (including acquisition and divestitures and the change in FDC) divided by total reserves additions.
  3. Production Replacement Ratio is calculated as total reserves additions (including acquisitions and divestitures) divided by annual production.
  4. Recycle Ratio is calculated as operating netback divided by F&D costs (proved plus probable). Operating netback is calculated as revenue (including realized financial derivatives gains and losses) less royalties, operating expenses and transportation expenses.
  5. 2016 FD&A costs (proved) were negative due to the reduction in estimated Future Development Costs.


Net Present Value of Reserves (Forecast Prices and Costs)

The following table summarizes Sproule and Ryder Scott's estimate of the net present value before income taxes of the future net revenue attributable to our reserves using Sproule's forecast prices and costs (and excluding the impact of any hedging activities). Please note that the data in the table may not add due to rounding.

  Summary of Net Present Value of Future Net Revenue
As at December 31, 2017
Forecast Prices and Costs
Before Income Taxes and Discounted at (%/year)
CANADA  
  0% 5% 10% 15% 20%
Reserves Category  ($000s)  ($000s)  ($000s)  ($000s)  ($000s)
Proved          
  Developed Producing $394,678  $392,339  $359,063  $327,713  $300,965 
  Developed Non-Producing 322,386  195,869  135,648  98,310  73,393 
  Undeveloped 475,480  362,040  278,773  216,443  168,923 
Total Proved 1,192,544  950,248  773,484  642,465  543,281 
Probable 2,428,609  1,326,481  806,284  526,528  360,482 
Total Proved Plus Probable $3,621,153  $2,276,730  $1,579,768  $1,168,994  $903,763 
   
   
UNITED STATES  
  0% 5% 10% 15% 20%
Reserve Category  ($000s)  ($000s)  ($000s)  ($000s)  ($000s)
Proved          
  Developed Producing $1,771,167  $1,311,579  $1,045,543  $875,040  $757,316 
  Developed Non-Producing 4,334  3,227  2,537  2,080  1,763 
  Undeveloped 2,492,733  1,523,326  1,009,941  705,898  510,856 
Total Proved 4,268,233  2,838,131  2,058,020  1,583,018  1,269,934 
Probable 1,679,658  812,362  452,804  276,144  178,484 
Total Proved Plus Probable  5,947,892   3,650,494   2,510,824   1,859,162   1,448,419 
Possible (1)  2,750,546   1,581,035   1,046,186   752,174   570,766 
Total Proved Plus Probable Plus Possible (1) $8,698,438  $5,231,529  $3,557,009  $2,611,337  $2,019,185 


TOTAL  
  0% 5% 10% 15% 20%
Reserve Category  ($000s)  ($000s)  ($000s)  ($000s)  ($000s)
Proved          
  Developed Producing $2,165,845  $1,703,918  $1,404,606  $1,202,752  $1,058,281 
  Developed Non-Producing 326,719  199,096  138,185  100,390  75,156 
  Undeveloped 2,968,213  1,885,366  1,288,713  922,341  679,779 
Total Proved 5,460,777  3,788,380  2,831,504  2,225,483  1,813,216 
Probable 4,108,268  2,138,844  1,259,087  802,673  538,966 
Total Proved Plus Probable  9,569,045   5,927,224   4,090,592   3,028,156   2,352,182 
Possible (1)(2)  2,750,546   1,581,035   1,046,186   752,174   570,766 
Total Proved Plus Probable Plus Possible (1)(2) $12,319,591  $7,508,259  $5,136,777  $3,780,330  $2,922,948 

Notes:

  1. Possible reserves are those reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
  2. The total possible reserves include only possible reserves from the Eagle Ford assets. The possible reserves associated with the Canadian properties have not been evaluated.

Sproule Forecast Prices and Costs

The following table summarizes the forecast prices used by Sproule in preparing the estimated reserves volumes and the net present values of future net revenues at December 31, 2017.

YearWTI Cushing
US$/bbl
Canadian Light
Sweet
C$/bbl
Western
Canada Select

C$/bbl
Henry Hub
US$/MMbtu
AECO-C Spot
C$/MMbtu
Operating Cost
Inflation Rate
%/Yr
Capital Cost
Inflation Rate
%/Yr
Exchange Rate
$US/$Cdn
2017 act.50.9561.8448.783.022.202.2(3.4)0.771
201855.0065.4451.053.252.850.00.00.790
201965.0074.5159.613.503.112.02.00.820
202070.0078.2464.944.003.652.02.00.850
202173.0082.4568.434.083.802.02.00.850
202274.4684.1069.804.163.952.02.00.850
202375.9585.7871.204.244.052.02.00.850
202477.4787.4972.624.334.152.02.00.850
202579.0289.2474.074.424.252.02.00.850
202680.6091.0375.554.504.362.02.00.850
202782.2192.8577.064.594.462.02.00.850
202883.8694.7178.614.694.572.02.00.850
ThereafterEscalation rate of 2.0%

Future Development Costs

The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the reserves categories noted below.

  Future Development Costs
As of December 31, 2017
Forecast Prices and Costs
($000s)
   
  CANADA  UNITED STATES  TOTAL
  Proved
Reserves
 Proved plus
Probable
Reserves
  Proved
Reserves
 Proved plus
Probable
Reserves
  Proved
Reserves
 Proved plus
Probable
Reserves
               
2018 98,043 126,225  136,837 149,937  234,879 276,163
2019 155,071 188,546  311,259 315,979  466,330 504,524
2020 133,323 357,593  302,301 316,986  435,624 674,579
2021 6,348 263,674  232,243 297,916  238,591 561,590
2022 12,401 122,321  146,451 249,786  158,852 372,107
Remaining 1,734 309,933  141,785 471,862  143,519 781,794
Total (undiscounted) 406,921 1,368,291  1,270,875 1,802,465  1,677,796 3,170,757

Properties with No Attributed Reserves

The following table sets forth our undeveloped land holdings as at December 31, 2017.

  Undeveloped Acres
  Gross Net
Canada    
Alberta 748,920 688,166
Saskatchewan 111,360 105,901
Total Canada 860,280 794,067
     
United States    
Texas 117 102
     
Total Company 860,397 794,169

Undeveloped land holdings are lands that have not been assigned reserves as at December 31, 2017.  We estimate the value of our net undeveloped land holdings at December 31, 2017 to be approximately $75.9 million, as compared to $67.1 million as at December 31, 2016.  This internal evaluation generally represents the estimated replacement cost of our undeveloped land.  In determining replacement cost, we analyzed land sale prices paid at Provincial Crown and State land sales for properties in the vicinity of our undeveloped land holdings, less an allowance for near-term expiries, net of undeveloped acreage that has reserves value attributed.

Net Asset Value

Our estimated net asset value is based on the estimated net present value of all future net revenue from our reserves, before income taxes, as estimated by the Company's independent reserves engineers, Sproule and Ryder Scott, at year-end, plus the estimated value of our undeveloped land holdings, less asset retirement obligations, long-term debt and net working capital. This calculation can vary significantly depending on the oil and natural gas price assumptions used by the independent reserves evaluators.

In addition, this calculation does not consider "going concern" value and assumes only the reserves identified in the reserves reports with no further acquisitions or incremental development, including development of possible reserves or contingent resources. As we execute our capital programs, we expect to convert possible reserves and contingent resources to reserves which may result in an increase in booked proved plus probable reserves.

The following table sets forth our net asset value as at December 31, 2017.

 Net Asset Value
Forecast Prices and Costs
Before Income Taxes and Discounted at (%/year)
($ millions except per share amounts)5% 10% 15%
      
Total net present value of proved plus probable reserves (before tax)$5,927  $4,091  $3,028 
Undeveloped land holdings (1)76  76  76 
Asset retirement obligations (2)(122) (59) (42)
Net debt(1,734 (1,734 (1,734)
Net Asset Value$4,147  $2,374  $1,328 
Net Asset Value per Share (3)$17.61  $10.08  $5.64 

Notes:

  1. The value of undeveloped land holdings generally represents the estimated replacement cost of our undeveloped land. 
  2. Asset retirement obligations may not equal the amount shown on the statement of financial position as a portion of these costs are already reflected in the present value of proved plus probable reserves and the discount rates applied differ.
  3. Based on 235.5 million common shares outstanding as at December 31, 2017.

Contingent Resources Assessment

We commissioned Sproule to conduct an evaluation of our contingent resources in the Lloydminster, Peace River, North East Alberta and Pembina areas in Canada. We commissioned Ryder Scott to audit our internal evaluation of our contingent resources in the Eagle Ford area of Texas. Both assessments were effective December 31, 2017, and were prepared in accordance with the Canadian definitions, standards and procedures contained in the COGE Handbook and NI 51-101. 

Contingent resources represent the quantity of oil and natural gas estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of our contingent resources or that we will produce any portion of the volumes currently classified as contingent resources. The recovery and resource estimates provided are estimates. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided.

The contingent resources described below represent our gross interests (unless otherwise indicated) and are a best estimate. A “best estimate” is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources identified in the best estimate have a 50% probability that the actual quantities recovered will equal or exceed the estimate. The contingent resources herein are presented as deterministic cumulative best estimate volumes.

Our contingent resources fall within the development pending and development unclarified sub-classes, which are defined as follows:

  • Development Pending – are economic contingent resources that have a high chance of development. Contingencies are directly influenced by the developer, are actively being pursued and resolution is expected in a reasonable time period.
  • Development Unclarified – are contingent resources that have a chance of development which is difficult to assess, and have an economic status which is undetermined. Projects are currently under evaluation and therefore contingencies are not clearly defined. Progress is expected within a reasonable time period.

 Development Pending

The following table summarizes the status of our development pending contingent resources.

Development Pending - Project Status
Area Product Type Project Status Future
Development Costs
($ millions)(1)
 Timing of First
Commercial
Production
 Recovery Technology
Peace River Bitumen Pre-Development $127 2019-2021 Cyclic steam stimulation (“CSS”)
           
Peace River,
Lloydminster and
North East Alberta
 Heavy Oil Pre-Development $227 2018-2023 Horizontal, vertical and multilateral well
and polymer flood development
           
Pembina Light &
Medium Oil,
Natural Gas
 Pre-Development $5 2022 Horizontal well development with
multi-stage fracturing completion
           
Eagle Ford Tight Oil, Shale
Gas and NGL
 Pre-Development $128 2018-2028 Horizontal well development with
multi-stage fracturing completion

Note:

  1. Undiscounted and unrisked. 

The following table presents a summary of the quantitative risk of the chance of development we have applied to our development pending contingent resources.

Development Pending - Chance of Development Risk (1)
Area Product Type Unrisked
(MMboe)
 Chance of
Development
 Risked
(MMboe)
 Risked NPV (2)
Discounted at 10%
(before tax)
($ millions)
Peace River Bitumen 19 81% 16 86
           
Peace River,
Lloydminster and
North East
Alberta
 Heavy Oil 15 88% 13 46
           
Pembina Light & Medium
Oil and Natural
Gas
 1 90% 1 4
           
Eagle Ford Tight Oil, Shale
Gas and NGL
 14 80% 11 100
           
Total   49   41 236

Notes:

  1. Numbers may not add due to rounding.
  2. An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the company proceeding with the required investment.  It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves.  There is no certainty that the estimate of risked net present value of future net revenue will be realized.

The principal risks that would influence the development of the Lloydminster, North East Alberta, Peace River and Pembina development pending contingent resources are: the timing of regulatory approvals to expand the project areas; the results of delineation drilling and seismic activity necessary for project development; the ability of these projects to compete for capital against our other projects; our corporate commitment to the timing of development; and the commodity price levels affecting the economic viability of bitumen and heavy oil production in Alberta. The principal risks specific to the development of the Eagle Ford development pending contingent resources are: our reliance on the operator’s capital commitment and development timing; the ability of these projects to compete for capital against our other projects; and the possibility of inter-well communication from infill drilling.
  
Development Unclarified

Our development unclarified contingent resources are conceptual project scenarios with no specific company defined development plan in the near-term. The following table presents a summary of the quantitative risk of the chance of development we have applied to our development unclarified contingent resources.

Development Unclarified - Chance of Development Risk (1)
Area Product Type Unrisked
(MMboe)
 Chance of Development Risked
(MMboe)
Peace River and North East
Alberta
 Bitumen 944 58% 552
         
Peace River, Lloydminster
and North East Alberta
 Heavy Oil 32 57% 18
         
Pembina Light & Medium
Oil and Natural
Gas
 12 55% 7
         
Eagle Ford Tight Oil, Shale
Gas and NGL
 135 50% 67
         
Total   1,123   644

Note:

  1. Numbers may not add due to rounding.

In addition to the risks identified for the development pending sub-class, the projects in the Lloydminster, North East Alberta, Peace River and Pembina areas development unclarified sub-class are also subject to risks pertaining to commercial productivity of the reservoirs. The geological complexity and variability in these reservoirs may require the implementation of pilot projects to test the viability of CSS and steam-assisted gravity drainage thermal recovery technologies. The risks outlined for the contingent resources in the Eagle Ford development pending sub-class also apply to the development unclarified sub-class but are greater in magnitude.

Additional disclosures related to our contingent resources will be included in Appendix A to our Annual Information Form for the year ended December 31, 2017, which will be filed on or before March 31, 2018.

Additional Information

Our audited consolidated financial statements for the year ended December 31, 2017 and the related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Today
9:00 a.m. MST (11:00 a.m. EST)
Baytex will host a conference call today, March 6, 2018, starting at 9:00am MST (11:00am EST). 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/baytex20180306.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; our 2018 plan to build on operational momentum; our strategy to target capital expenditures at a level that approximates our adjusted funds flow; 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; that we can generate some of the strongest capital efficiencies in the oil and gas industry at our Peace River assets; the sensitivity of our operations to improvements in commodity prices; that we expect our liquidity position to be stable; 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; the volume of oil that we expect to deliver to market by railways in Q1/2018; that we view the current price differential between WTI and Canadian heavy oil as temporary; that we have operational flexibility to adjust our spending plans based on commodity prices; that we expect the Eagle Ford assets to generate significant free cash flow in 2018; our 2018 production and capital expenditure guidance; our expected royalty rate and operating, transportation, general and administration and interest expenses for 2018; our reserves life index; the net present value before income taxes of the future net revenue attributable to our reserves; forecast prices for petroleum and natural gas; forecast inflation and exchange rates; future development costs; the value of our undeveloped land holdings; our estimated net asset value; that we expect to convert possible reserves and contingent resources to reserves; our development pending contingent resources, including future development costs, timing of first commercial production, risked and unrisked volumes, chance of development and the net present value before income taxes of the future net revenue; and our development unclarified contingent resources, including risked and unrisked volumes and chance of development.  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, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission not later than March 31, 2018 and in our other public filings.

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.

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 year ended December 31, 2017.

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

The reserves information contained in this press release has been prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101").  Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2017, which will be filed on or before March 31, 2018.  Listed below are cautionary statements that are specifically required by NI 51-101:

  • 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.  BOEs 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.
     
  • With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
     
  • This press release contains estimates of the net present value of our future net revenue from our reserves.  Such amounts do not represent the fair market value of our reserves.

This press release contains metrics commonly used in the oil and natural gas industry, such as “recycle ratio,” “operating netback,” and “reserves life index.” These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included in this press release to provide readers with additional measures to evaluate Baytex’s performance, however, such measures are not reliable indicators of Baytex’s future performance and future performance may not compare to Baytex’s performance in previous periods and therefore such metrics should not be unduly relied upon.

This press release contains estimates as of December 31, 2017 of the volumes of "contingent resources" attributable to our properties. These estimates were prepared by independent qualified reserves evaluators.

"Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook as: "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage."

There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that we will produce any portion of the volumes currently classified as contingent resources.  The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future.

The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

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.

Notice to United States Readers

The petroleum and natural gas reserves contained in this press release have generally been prepared in accordance with Canadian disclosure standards, which are not comparable in all respects to United States or other foreign disclosure standards.  For example, the United States Securities and Exchange Commission (the "SEC") requires oil and gas issuers, in their filings with the SEC, to disclose only "proved reserves", but permits the optional disclosure of "probable reserves" and "possible reserves" (each as defined in SEC rules).  Canadian securities laws require oil and gas issuers disclose their reserves in accordance with NI 51-101, which requires disclosure of not only "proved reserves" but also "probable reserves" and permits the optional disclosure of "possible reserves".  Additionally, NI 51-101 defines "proved reserves", "probable reserves" and "possible reserves" differently from the SEC rules.  Accordingly, proved, probable and possible reserves disclosed in this press release may not be comparable to United States standards.  Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves.  Possible reserves are higher risk than probable reserves and are generally believed to be less likely to be accurately estimated or recovered than probable reserves.

In addition, under Canadian disclosure requirements and industry practice, reserves and production are reported using gross volumes, which are volumes prior to deduction of royalty and similar payments.  The SEC rules require reserves and production to be presented using net volumes, after deduction of applicable royalties and similar payments.

Moreover, Baytex has determined and disclosed estimated future net revenue from its reserves using forecast prices and costs, whereas the SEC rules require that reserves be estimated using a 12-month average price, calculated as the arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.  As a consequence of the foregoing, Baytex's reserve estimates and production volumes in this press release may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

We also included in this press release estimates of contingent resources.  Contingent resources represent the quantity of petroleum and natural gas estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies.  Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets.  The SEC does not permit the inclusion of estimates of resource in reports filed with it by United States companies.

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

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: [email protected]

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Source: GlobeNewswire (March 6, 2018 - 6:30 AM EST)

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