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Baytex Announces Fourth Quarter and Full Year 2018 Financial and Operating Results and 2018 Year End Reserves

Baytex Announces Fourth Quarter and Full Year 2018 Financial and Operating Results and 2018 Year End Reserves

CALGARY, Alberta, March 06, 2019 (GLOBE NEWSWIRE) -- Baytex Energy Corp. ("Baytex")(TSX, NYSE: BTE) reports its operating and financial results for the three months and year ended December 31, 2018 (all amounts are in Canadian dollars unless otherwise noted).

“In 2018, we repositioned our company through the Raging River combination which increased our high netback light oil assets while also deleveraging our balance sheet. Our operations are performing exceptionally well as we execute our first quarter program with activity focused on the Viking and Eagle Ford. We are also benefitting from a meaningful improvement in crude oil prices in Canada and on the Texas Gulf coast, which is expected to have a very positive impact to our adjusted funds flow. We are well positioned to execute our business plan and further strengthen our balance sheet in 2019,” commented Ed LaFehr, President and Chief Executive Officer.

2019 Outlook

Global benchmark prices have recently improved with WTI currently trading at US$57/bbl, as compared to a low of US$42/bbl in December 2018. In addition, Canadian light and heavy oil differentials have narrowed substantially. This combination is expected to have a positive impact to our adjusted funds flow.

As a result of current activity levels, excellent well performance in the Eagle Ford and outstanding operating efficiency across all of our assets, Q1/2019 volumes are ahead of expectations, trending above 97,000 boe/d.

Capital expenditures are on pace for $155 million in Q1/2019, consistent with the mid-point of our capital guidance range of $600 million. Approximately 80% of our capital program is directed to our high operating netback light oil assets in the Eagle Ford and Viking.

Further deleveraging remains a top priority. Based on the forward strip, our adjusted funds flow forecast has increased from $605 million in December 2018, to approximately $800 million, which will support up to $200 million of debt repayment while maintaining production at the mid-point of our guidance of 95,000 boe/d.

2018 Highlights

  • Generated production of 98,890 boe/d (83% oil and NGL) during Q4/2018, an increase of 42% over Q4/2017, and 80,458 boe/d for full-year 2018, exceeding the high end of guidance, with capital expenditures of $496 million, in line with annual guidance.  
  • Delivered adjusted funds flow of $111 million ($0.20 per basic share) in Q4/2018 and $473 million ($1.35 per basic share) for the full-year 2018.
  • Eagle Ford production increased 3% to 38,437 boe/d (78% liquids) in Q4/2018, compared to Q3/2018. Wells that commenced production during the quarter generated 30-day initial gross production rates of approximately 1,800 boe/d per well.
  • Continued to advance the evaluation of the East Duvernay Shale where we now have five producing wells on our Pembina acreage. In Q4/2018, production more than doubled from Q3/2018, to average 1,432 boe/d.
  • Decreased cash costs (operating, transportation and general and administrative expenses) for 2018 by 4% on a boe basis as compared to the mid-point of original guidance.
  • Increased proved developed producing ("PDP") reserves by 35%, from 100 mmboe to 135 mmboe. Proved reserves (“1P”) increased by 23%, from 256 mmboe to 315 mmboe. Proved plus probable (“2P”) reserves increased by 22%, from 432 mmboe to 527 mmboe.
  • Reserves associated with the Raging River assets increased by 4% on a 2P basis to 111 mmboe, as compared to year-end 2017. The Raging River combination enhanced the quality of Baytex’s reserves base, adding high value light oil reserves in the Viking and Duvernay.
  • PDP finding and development ("F&D") costs, including changes in future development capital (“FDC”), were $15.82/boe, resulting in a 1.5x recycle ratio based on our 2018 operating netback of  $23.76/boe.
  • Our net asset value at year-end 2018, discounted at 10%, is estimated to be $7.27 per share.
 
  Three Months Ended Years Ended
  December 31,
2018
September 30,
2018
December 31,
2017
December 31,
2018
December 31,
2017
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
         
Petroleum and natural gas sales $ 358,437   $ 436,761   $ 303,163   $ 1,428,870   $ 1,099,867  
Adjusted funds flow (1) 110,828   171,210   105,796   472,983   347,641  
Per share - basic 0.20   0.46   0.45   1.35   1.48  
Per share - diluted 0.20   0.45   0.44   1.35   1.47  
Net income (loss) (231,238 ) 27,412   76,038   (325,309 ) 87,174  
Per share - basic (0.42 ) 0.07   0.32   (0.93 ) 0.37  
Per share - diluted (0.42 ) 0.07   0.32   (0.93 ) 0.37  
           
Capital Expenditures          
Exploration and development expenditures (1) $ 184,162   $ 139,195   $ 90,156   $ 495,721   $ 326,266  
Acquisitions, net of divestitures 183   46   (3,937 ) (1,818 ) 59,857  
Total oil and natural gas capital expenditures $ 184,345   $ 139,241   $ 86,219   $ 493,903   $ 386,123  
                               
Net Debt                              
Bank loan (2) $ 522,294   $ 490,565   $ 213,376   $ 522,294   $ 213,376  
Long-term notes (2) 1,596,323   1,527,733   1,489,210   1,596,323   1,489,210  
Long-term debt 2,118,617   2,018,298   1,702,586   2,118,617   1,702,586  
Working capital deficiency 146,550   93,792   31,698   146,550   31,698  
Net debt (1) $ 2,265,167   $ 2,112,090   $ 1,734,284   $ 2,265,167   $ 1,734,284  
           
Shares Outstanding - basic (thousands)          
Weighted average 554,036   375,435   235,451   351,542   234,787  
End of period 554,060   553,950   235,451   554,060   235,451  
 


 
  Three Months Ended Years Ended
  December 31,
2018
September 30,
2018
December 31,
2017
December 31,
2018
December 31,
2017
OPERATING          
Daily Production          
Light oil and condensate (bbl/d) 44,987   29,731   21,229   29,264   21,314  
Heavy oil (bbl/d) 26,339   27,036   24,945   25,954   25,326  
NGL (bbl/d) 10,327   10,076   9,872   9,745   9,206  
Total liquids (bbl/d) 81,653   66,843   56,046   64,963   55,846  
Natural gas (mcf/d) 103,424   93,414   81,063   92,971   86,375  
Oil equivalent (boe/d @ 6:1) (3) 98,890   82,412   69,556   80,458   70,242  
           
Netback (thousands of Canadian dollars)          
Total sales, net of blending and other expense (4) $ 344,682   $ 417,213   $ 286,370   $ 1,360,038   $ 1,040,522  
Royalties (79,765 ) (91,945 ) (69,525 ) (313,754 ) (241,892 )
Operating expense (97,857 ) (77,698 ) (69,837 ) (311,592 ) (269,283 )
Transportation expense (10,994 ) (9,520 ) (7,658 ) (36,869 ) (33,985 )
Operating netback $ 156,066   $ 238,050   $ 139,350   $ 697,823   $ 495,362  
General and administrative (14,096 ) (10,158 ) (9,717 ) (45,825 ) (47,389 )
Cash financing and interest (27,933 ) (26,343 ) (24,849 ) (104,318 ) (100,482 )
Realized financial derivatives (loss) gain (3,063 ) (30,854 ) 1,898   (73,165 ) 7,616  
Other (5) (146 ) 515   (886 ) (1,532 ) (7,466 )
Adjusted funds flow (1) $ 110,828   $ 171,210   $ 105,796   $ 472,983   $ 347,641  
           
Netback (per boe)          
Total sales, net of blending and other expense (4) $ 37.89   $ 55.03   $ 44.75   $ 46.31   $ 40.58  
Royalties (8.77 ) (12.13 ) (10.86 ) (10.68 ) (9.43 )
Operating expense (10.76 ) (10.25 ) (10.91 ) (10.61 ) (10.50 )
Transportation expense (1.21 ) (1.26 ) (1.20 ) (1.26 ) (1.33 )
Operating netback (1) $ 17.15   $ 31.39   $ 21.78   $ 23.76   $ 19.32  
General and administrative (1.55 ) (1.34 ) (1.52 ) (1.56 ) (1.85 )
Cash financing and interest (3.07 ) (3.47 ) (3.88 ) (3.55 ) (3.92 )
Realized financial derivatives (loss) gain (0.34 ) (4.07 ) 0.30   (2.49 ) 0.30  
Other (5) (0.02 ) 0.07   (0.14 ) (0.05 ) (0.29 )
Adjusted funds flow (1) $ 12.17   $ 22.58   $ 16.54   $ 16.11   $ 13.56  

Notes:

(1) The terms “adjusted funds flow”, “exploration and development expenditures”, “net debt” and “operating netback” do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to the advisory on non-GAAP measures at the end of this press release.
(2) Principal amount of instruments. The carrying amount of debt issue costs associated with the bank loan and long-term notes are excluded on the basis that these amounts have been paid by Baytex and do not represent an additional source of liquidity or repayment obligations.
(3) 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.
(4) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
(5) Other is comprised of realized foreign exchange gain or loss, other income or expense, current income tax expense or recovery and payments on onerous contracts. Refer to the 2018 MD&A for further information on these amounts.


Strategic Combination with Raging River

On August 22, 2018, we completed a strategic combination with Raging River Exploration Inc. (“Raging River”) by way of a plan of arrangement in which Baytex acquired all of the issued and outstanding common shares of Raging River. The strategic combination increased our light oil exposure and operational control of our properties while strengthening our balance sheet. The addition of these operated assets to our portfolio increased our inventory of drilling prospects and our ability to effectively allocate capital. Production from Raging River's properties is approximately 90% light oil from the Viking and Duvernay areas. Our 2018 results include 132 days of operations from the Raging River assets from August 22 to December 31.  

In Q4/2018, production from the Raging River assets averaged 26,035 boe/d (93% oil and NGL). Reserves associated with the Raging River assets increased by 4% on a 2P basis to 111 mmboe, as compared to year-end 2017.

Operating Results

2018 was a defining year as we repositioned Baytex as a North American crude oil producer with strong free cash flow and an improved balance sheet. We have successfully integrated the two companies, undertaken a detailed strategic review of our operations, confirmed the organic growth opportunities in our diversified portfolio of assets and delivered on our near-term operational targets.

Production averaged 98,890 boe/d (83% oil and NGL) in Q4/2018, as compared to 82,412 boe/d (81% oil and NGL) in Q3/2018 and 69,556 boe/d in Q4/2017. Production of 80,458 boe/d (81% oil and NGL) for 2018 exceeded the high end of our production guidance range of 79,000 to 80,000 boe/d. Production from the legacy Baytex assets (excluding Raging River) averaged 72,855 boe/d in Q4/2018 and 71,293 boe/d for 2018.

Exploration and development expenditures totaled $184 million in Q4/2018 and $496 million for full-year 2018, in line with our guidance range of $450-$500 million. We participated in the completion of 353 (198.6 net) wells with a 99% success rate during the year.

Eagle Ford and Viking Light Oil

Our Eagle Ford assets in South Texas is one of the premier oil resource plays in North America. These assets generate a strong operating netback and free cash flow and contain a significant inventory of development prospects.

In 2018, we allocated 39% of our exploration and development expenditures to these assets. Production averaged 38,437 boe/d (78% liquids) during Q4/2018, as compared to 37,198 boe/d in Q3/2018. Production for 2018 averaged 37,076 boe/d, as compared to 36,678 boe/d in 2017. In 2018, the Eagle Ford generated an operating netback of $479 million and free cash flow of $285 million.

We continue to see strong well performance driven by enhanced completions in the oil window of our acreage. In 2018, we participated in the drilling of 91 (20.8 net) wells and commenced production from 120 (26.2 net) wells. The wells that have been on production for more than 30 days during 2018 established 30-day initial production rates of approximately 1,750 boe/d per well (65% light oil and condensate), which represents an approximate 20% improvement over 2017. During Q4/2018, we commenced production from 31 (5.9 net) wells, which averaged 30-day initial production rates of approximately 1,800 boe/d per well. Six of these were new appraisal wells in our northern Austin Chalk fracture trend and demonstrated 30-day initial production rates of approximately 1,600 boe/d per well.

Our Viking asset is a shallow, light oil resource play in western Canada. During Q4/2018, production from the Viking averaged 23,784 boe/d (excluding heavy oil), up from 22,158 boe/d for the period August 22 to September 30. We maintained a steady pace of development in Q4/2018 with five drilling rigs and 1.5 frac crews executing our program, resulting in 83 (65.5 net) wells. The extended reach horizontal results continue to exceed expectations with multiple, previously untested sections proving economic.

Heavy Oil

Our heavy oil assets at Peace River and Lloydminster produced a combined 26,339 bbl/d during the fourth quarter, as compared to 27,036 bbl/d in Q3/2018. The reduced volumes reflect the optimization of our heavy oil program during Q4/2018 due to volatile heavy oil prices, which was mitigated somewhat by the addition of heavy oil assets acquired as part of the Raging River combination.

Our Peace River assets are located in northwest Alberta. 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 2018, we drilled 12 (12.0 net) oil wells with average 30‑day initial production rates of approximately 500 boe/d per well. This program included 8 (8.0 net) wells in our northern Seal area which delivered approximately 25% higher 30-day initial production rates than our field wide average. We deferred three completions during Q4/2018 due to low heavy oil prices.

Our Lloydminster assets are 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 drilled 86 (61.9 net) oil wells in 2018. In addition, we successfully completed the expansion of our Kerrobert thermal project with productive capability increasing to approximately 2,000 bbl/d during Q4/2018.   

East Duvernay Shale Light Oil

We continue to prudently advance the delineation of the East Duvernay Shale, an early stage, high operating netback light oil resource play where we have amassed over 450 sections of land. In 2018, our focus shifted to the Pembina area where we control over 270 sections of 100% working interest land. With five wells on production, we have delineated approximately 35 sections representing 175 potential drilling opportunities. These wells generated average 30‑day initial production rates of approximately 575 boe/d per well (88% liquids). During Q4/2018, production from the East Duvernay Shale averaged 1,432 boe/d, up from 650 boe/d for the period August 22 to September 30.

Financial Review

Our financial results for Q4/2018 were negatively impacted by the sharp decline in global benchmark crude oil prices and the significant widening of Canadian light and heavy oil differentials. In Q4/2018, the price for West Texas Intermediate light oil (“WTI”) averaged US$58.81/bbl, as compared to US$69.50/bbl in Q3/2018. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$39.42/bbl in Q4/2018 as compared to US$22.25/bbl in Q3/2018. The discount for Canadian light oil, as measured by the price differential between Canadian Mixed Sweet Blend (“MSW”) and WTI, averaged US$26.51/bbl in Q4/2018 as compared to US$6.82/bbl in Q3/2018.

As a result of the challenging pricing environment, we generated adjusted funds flow of $111 million ($0.20 per basic share) in Q4/2018, compared to $171 million ($0.46 per basic share) in Q3/2018. Full-year adjusted funds flow was $473 million ($1.35 per basic share), compared to $348 million ($1.48 basic per share) in 2017.   

We generated an operating netback $17.15/boe in Q4/2018, as compared to $31.39/boe in Q3/2018 and $21.78/boe in Q4/2017. The Eagle Ford generated an operating netback of $35.42/boe during Q4/2018 while our Canadian operations generated an operating netback of $5.54/boe.

In the Eagle Ford, our assets are proximal to Gulf Coast markets with light oil and condensate production priced off the LLS crude oil benchmark, which is a function of the Brent price. In Q4/2018, the price for LLS averaged US$66.64/bbl as compared to US$75.25/bbl in Q3/2018. During Q4/2018, our light oil and condensate realized price in the Eagle Ford of US$62.87/bbl (or $83.28/bbl) represented a US$3.77/bbl discount to LLS.

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

  Three Months Ended December 31
  2018 2017
($ per boe except for production) Canada   U.S.
  Total
  Canada   U.S.   Total  
Production (boe/d) 60,453   38,437   98,890   32,194   37,362   69,556  
             
Total sales, net of blending and other (1) $ 24.04   $ 59.66   $ 37.89   $ 36.89   $ 51.53   $ 44.75  
Royalties (3.10 ) (17.68 ) (8.77 ) (5.72 ) (15.30 ) (10.86 )
Operating expense (13.42 ) (6.56 ) (10.76 ) (16.57 ) (6.04 ) (10.91 )
Transportation expense (1.98 )   (1.21 ) (2.59 )   (1.20 )
Operating netback (2) $ 5.54   $ 35.42   $ 17.15   $ 12.01   $ 30.19   $ 21.78  
Realized financial derivatives (loss) gain     (0.34 )     0.30  
Operating netback after financial derivatives $ 5.54   $ 35.42   $ 16.81   $ 12.01   $ 30.19   $ 22.08  

Notes:

(1) Realized heavy oil prices are calculated based on sales dollars, net of blending and other expense. We include the cost of blending diluent in our realized heavy oil sales price in order to compare the realized pricing on our produced volumes to the WCS benchmark.
(2) The term “operating netback” does not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles (“GAAP”) and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. We refer you to the advisory on non-GAAP measures at the end of this press release.


Financial Liquidity

We maintain strong financial liquidity with our credit facilities approximately 50% undrawn and our first long-term note maturity not until 2021. Our net debt totaled $2.265 billion at December 31, 2018, which includes four series of long-term notes that total $1.6 billion. Our credit facilities total approximately $1.085 billion, comprised of US$575 million of revolving credit facilities and a $300 million non-revolving term loan. The credit facilities, which mature in June 2020, are not borrowing base facilities and do not require annual or semi-annual reviews. We expect to request an extension to the credit facilities in 2019.   

Risk Management

As part of our normal operations, we are exposed to movements in commodity prices. In an effort to manage these exposures, we utilize various financial derivative contracts, crude-by-rail and capital allocation optimization to reduce the volatility in our adjusted funds flow. We realized a financial derivatives loss of $73 million in 2018, as compared to a gain of $8 million in 2017.

For 2019, we have entered into hedges on approximately 30% of our net crude oil exposure. This includes 25% of our net WTI exposure with 2% fixed at US$62.85/bbl and 23% hedged utilizing a 3-way option structure that provides a US$10/bbl premium to WTI when WTI is at or below US$55.64/bbl and allows upside participation to US$73.65/bbl. In addition, we have entered into a Brent-based 3-way option structure for 3,000 bbl/d that provides a US$10/bbl premium to Brent when Brent is at or below US$59.50/bbl and allows upside participation to US$78.68/bbl. We have also entered into hedges on approximately 24% of our net natural gas exposure through a combination of AECO swaps at C$2.37/mcf and NYMEX swaps at US$3.10/mmbtu.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For 2019, we expect to deliver 11,000 bbl/d (approximately 40%) of our heavy oil volumes to market by rail, up from 9,000 bbl/d in 2018. Commencing January 1, 2019, approximately 70% of our crude by rail commitments are WTI based contracts with no WCS pricing exposure. In addition, we have entered into WCS differential hedges on approximately 10% of our net heavy oil exposure at a WTI-WCS differential of US$17.34/bbl.

A complete listing of our financial derivative contracts can be found in Note 19 to our 2018 financial statements.

Outlook for 2019

Stronger Commodity Prices

Following the pricing challenges of the fourth quarter, global benchmark prices have recently improved with WTI currently trading at US$57/bbl, as compared to a low of US$42/bbl in December 2018. In addition, following the Government of Alberta’s announcement on December 2, 2018 of temporary production curtailments, Canadian light and heavy oil differentials have narrowed substantially. In Q1/2019, the WTI-WCS price differential averaged US$12.29/bbl and the WTI-MSW price differential averaged US$4.85/bbl. This combination of improved WTI prices and the narrowing of Canadian differentials are expected to have a positive impact to our adjusted funds flow.

Free cash flow and debt repayment

Further deleveraging remains a top priority. For 2019, adjusted funds flow in excess of exploration and development expenditures, leasing expenditures and asset retirement obligations, will be used to reduce our indebtedness.

Based on the forward strip for 2019, our adjusted funds flow forecast has increased by 32%, from $605 million in December 2018, to approximately $800 million, which will support our debt reduction initiative. Our plan for year end is to reduce our net debt to EBITDA ratio to approximately 2.2x. As we continue to drive debt levels down, we will be positioned to enhance shareholder returns through a combination of organic growth through disciplined capital allocation, the reinstatement of a dividend and/or share buybacks.

Corporate level production volumes are strong

As a result of current activity levels, excellent well performance in the Eagle Ford and outstanding operating efficiency across all of our assets, Q1/2019 volumes are trending above 97,000 boe/d.

Activity levels are on pace for $155 million capex in Q1/2019

Approximately 33% of Q1/2019 corporate capital investment is being directed to the Eagle Ford while 52% is allocated to the Viking light oil assets. We continue to see approximately 3 drilling rigs and 1.5 frac crews in the Eagle Ford and 5 rigs and 1.5 completion crews in the Viking. With our usual seasonal slowdown in Canada during the second quarter, this puts us on track for the full year to drill approximately 245 net wells (85% extended reach horizontals) in the Viking and bring approximately 30 net wells on production in the Eagle Ford. We are executing a small heavy oil development program through the first half of 2019, with the potential to scale activity higher should oil prices and visibility to egress improve.

East Shale Duvernay appraisal progress

In Q1/2019, we are drilling four wells at Pembina with completion activities scheduled for Q2/2019. Successful tests from the four wells will increase total delineated Pembina acreage to 100 to 125 sections.    

Guidance

Our 2019 production guidance range is unchanged at 93,000 to 97,000 boe/d with budgeted exploration and development capital expenditures of $550 to $650 million.

The following table summarizes our 2019 annual guidance.

Exploration and development capital ($ millions) $550 - $650  
Production (boe/d) 93,000 - 97,000  
     
Adjusted Funds Flow ($ millions) (1) $800  
Adjusted Funds Flow per Share (2) $1.42  
     
Operating Netback ($/boe)  (1) $26.00  
     
Expenses:    
Royalty rate (%) 20%  
Operating ($/boe) $10.75 - $11.25  
Transportation ($/boe) $1.25 - $1.35  
General and administrative ($ millions) $44 ($1.27/boe)  
Interest ($ millions) $112 ($3.23/boe)  
     
Leasing expenditures ($ millions) $7  
Asset retirement obligations ($ millions) $17  

(1) Pricing assumptions: WTI - US$57/bbl; LLS - US$63/bbl; WCS differential - US$17/bbl; MSW differential – US$8/bbl, NYMEX Gas - US$2.90/mcf; AECO Gas - $1.60/mcf and Exchange Rate (CAD/USD) - 1.32.
(2) Based on weighted average common shares outstanding of 562 million.

The following table summarizes our 2019 adjusted funds flow sensitivities to changes in commodity prices and the CAD//USD exchange rate.

  Excluding
Hedges

($ millions)
Including
Hedges

($ millions)
 
Change of US$1.00/bbl WTI crude oil $30.1 $24.2  
Change of US$1.00/bbl WCS heavy oil differential $8.3 $8.3  
Change of US$1.00/bbl MSW light oil differential $9.8 $9.8  
Change of US$0.25/mcf NYMEX natural gas $9.3 $7.4  
Change of $0.01 in the CAD//USD exchange rate $8.1 $8.1  

Board and Management Changes

Baytex has an ongoing board renewal process led by the Nominating and Governance Committee of the Board. As part of this renewal process, Ray Chan and Gary Bugeaud have decided to not stand for election as directors at our 2019 Annual Meeting of Shareholders to be held in May 2019.

Mr. Chan has been instrumental in guiding Baytex over the last twenty plus years, serving numerous executive positions during this time, including nearly 10 years as Chairman. Mr. Chan has always operated with the highest integrity. His hard work, dedication and thoughtful guidance for the benefit of all stakeholders is greatly appreciated.  

Baytex would also like to thank Mr. Bugeaud, who has been involved with Raging River and its predecessor companies for the last 15 years.

Rick Ramsay, our Executive Vice President and Chief Operating Officer, has elected to retire on April 5, 2019.  Mr. Ramsay has been with Baytex since January 2010 and has been a key leader for the organization, managing the successful development of our Peace River assets and subsequently guiding all of our North American operations.  Baytex would like to thank Mr. Ramsay for his outstanding contributions and wish him well in retirement.

Jason Jaskela will assume the role of Executive Vice President and Chief Operating Officer on April 5, 2019. Mr. Jaskela is a professional engineer with 19 years of industry experience. Previously, he was Chief Operating Officer of Raging River from March 2014 until August 2018 and the Vice President, Production from March 2012 until March 2014.

Year-end 2018 Reserves

Baytex's year-end 2018 proved and probable reserves were evaluated by Sproule Associates Limited (“Sproule”), Ryder Scott Company, L.P. (“Ryder Scott”) and GLJ Petroleum Consultants (“GLJ”), all independent qualified reserves evaluators. Sproule evaluated our Canadian reserves, other than the reserves associated with our Duvernay assets. GLJ evaluated the reserves associated with our Duvernay assets. Our United States properties were evaluated by Ryder Scott. Each evaluator used Sproule's December 31, 2018 forecast price and cost assumptions.

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, 2018, which will be filed on or before March 31, 2019.

On August 22, 2018, Baytex and Raging River completed a strategic combination. Our 2018 reserves report reflects this strategic combination with a meaningful increase in our light oil reserves in Canada.

2018 Highlights

  • Proved developed producing ("PDP") reserves increased by 35%, from 100 mmboe to 135 mmboe. Proved reserves (“1P”) increased by 23%, from 256 mmboe to 315 mmboe. Proved plus probable reserves (“2P”) increased by 22%, from 432 mmboe to 527 mmboe.
     
  • Reserves associated with the Raging River assets increased by 4% on a 2P basis to 111 mmboe, as compared to year-end 2017. The Raging River combination enhanced the quality of Baytex’s reserves base, adding high value light oil reserves in the Viking and Duvernay.
     
  • Replaced 106% of total 2018 production, adding 31 mmboe of 2P reserves through development activities. Inclusive of the Raging River transaction, replaced 422% of total 2018 production with 124 mmboe of 2P reserves additions.
     
  • Reserves on a 1P basis are comprised of 83% oil and NGL (40% light oil, 23% NGL’s, 16% heavy oil and 4% bitumen) and 17% natural gas.
     
  • PDP reserves represent 43% of 1P reserves (39% at year-end 2017) and 1P reserves represent 60% of 2P reserves (59% at year-end 2016).
     
  • Finding and Development ("F&D") costs, including changes in future development capital (“FDC”), were $15.82/boe for PDP reserves and $20.11/boe for 2P reserves. Generated a PDP recycle ratio of 1.5x based on our 2018 operating netback of $23.76/boe.
     
  • Finding, development and acquisition costs (“FD&A”) costs, including changes in FDC, were $25.55/boe for 2P reserves.
     
  • Baytex maintains a strong reserves life index (“RLI”) of 8.7 years based on 1P reserves and 14.6 years based on 2P reserves.
     
  • At year-end, 2018, the present value of our reserves, discounted at 10% before tax, is estimated to be $6.2 billion (as compared to $4.1 billion at year-end 2017). The increase is largely attributable to the Strategic Combination.
     
  • Our net asset value at year-end 2018, discounted at 10%, is estimated to be $7.27 per share. This is based on the estimated reserves value of $6.2 billion plus a value for undeveloped acreage, net of long-term debt, asset retirement obligations and working capital. 

Petroleum and Natural Gas Reserves as at December 31, 2018

The following table sets forth our gross and net reserves volumes at December 31, 2018 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
    Light and Medium Oil   Tight Oil   Heavy Oil
      Gross(1)   Net(2)    Gross(1)   Net(2)     Gross(1)   Net(2)
Reserves Category   (mbbl) (mbbl)   (mbbl) (mbbl)   (mbbl) (mbbl)
Proved                  
Developed Producing   30,987 29,089   740 652   24,922 20,092
Developed Non-Producing   263 256     1,161 1,006
Undeveloped   40,296 37,584   1,360 1,191   23,530 20,668
Total Proved   71,545 66,929   2,099 1,843   49,613 41,766
Probable   20,941 19,352   3,254 2,730   42,687 35,726
Total Proved Plus Probable   92,487 86,281   5,353 4,572   92,301 77,492
                   
                   
CANADA   Forecast Prices and Costs
    Bitumen   Natural Gas Liquids(3)   Conventional
Natural Gas(4)
      Gross(1)   Net(2)    Gross(1)   Net(2)     Gross(1)   Net(2)
Reserves Category   (mbbl) (mbbl)     (mbbl)   (mbbl)   (mmcf) (mmcf)
Proved                  
Developed Producing   1,934 1,478   1,401 1,070   55,986 50,308
Developed Non-Producing   7,746 7,008   3 3   1,943 1,533
Undeveloped   3,126 2,712   1,628 1,340   52,628 47,699
Total Proved   12,805 11,198   3,032
2,412   110,557 99,540
Probable   55,545 43,284   3,848 3,013   98,032 87,376
Total Proved Plus Probable   68,350 54,482   6,880 5,425   208,589 186,915
                   
     
     
CANADA   Forecast Prices and Costs  
    Shale Gas   Oil Equivalent(5)    
      Gross(1)   Net(2)    Gross(1)   Net(2)    
Reserves Category   (mmcf) (mmcfl)     (mboe)   (mboe)    
Proved                
Developed Producing   1,432 1,310   69,553 60,983    
Developed Non-Producing     9,497 8,528    
Undeveloped   1,890 1,724   79,026 71,732    
Total Proved   3,321 3,034   158,075 141,243    
Probable   5,506 4,968   143,532 119,495    
Total Proved Plus Probable   8,828 8,002   301,607 260,738    


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   18,348 13,445   31,512 23,309   66,901 49,572
Developed Non-Producing   38 28   214 158   566 417
Undeveloped   32,334 23,700   39,856 29,312   80,367 59,166
Total Proved   50,720 37,174   71,582 52,779   147,835 109,155
Probable   18,625 13,680   34,625 25,441   66,043 48,502
Total Proved Plus Probable   69,345 50,854   106,207 78,220   213,878 157,657


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   24,993 18,357   65,176 48,076      
Developed Non-Producing   49 36   354 261      
Undeveloped   32,506 23,803   91,002 66,841      
Total Proved   57,548 42,197   156,532 115,178      
Probable   24,652 18,147   68,366 50,229      
Total Proved Plus Probable Possible   82,200 60,344   224,898 165,407      


TOTAL   Forecast Prices and Costs
    Light and Medium Oil   Tight Oil   Heavy Oil
      Gross(1)   Net(2)    Gross(1)   Net(2)     Gross(1)   Net(2)
Reserves Category   (mbbl) (mbbl)   (mbbl) (mbbl)   (mbbl) (mbbl)
Proved                  
Developed Producing   30,987 29,089   19,088 14,097   24,922 20,092
Developed Non-Producing   263 256   38 28   1,161 1,006
Undeveloped   40,296 37,584   33,693 24,891   23,530 20,668
Total Proved   71,545 66,929   52,819 39,016   49,613 41,766
Probable   20,941 19,352   21,879 16,410   42,687 35,726
Total Proved Plus Probable   92,487 86,281   74,698 55,426   92,301 77,492
                   
                   
TOTAL   Forecast Prices and Costs
    Bitumen   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   1,934 1,478   32,912 24,379   68,333 50,882
Developed Non-Producing   7,746 7,008   217 160   566 417
Undeveloped   3,126 2,712   41,484 30,652   82,257 60,890
Total Proved   12,805 11,198   74,614 55,191   151,156 112,188
Probable   55,545 43,284   38,473 28,454   71,550 53,471
Total Proved Plus Probable   68,350 54,482   113,087 83,645   222,706 165,659


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   80,980 68,665   134,729 109,059      
Developed Non-Producing   1,991 1,569   9,851 8,789      
Undeveloped   85,133 71,502   170,028 138,572      
Total Proved   168,104 141,736   314,607 256,421      
Probable   122,685 105,523   211,898 169,724      
Total Proved Plus Probable

  290,789 247,259   526,505 426,145      

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.

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.

null
    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, 2017   46,706   39,757   86,463     13,266   55,726   68,992  
Extensions   1,282   690   1,972          
Infill Drilling   1,346   905   2,251          
Improved Recoveries   1,952   4,621   6,574          
Technical Revisions (3)   4,315   (4,922 ) (607 )   (205 ) (178 ) (382 )
Discoveries   2   2   4          
Acquisitions (4)   3,080   1,522   4,602