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

Source Press Release
Company Baytex Energy Corp. 
Tags Capital Spending, People, Guidance, Strategy - Corporate, Financial & Operating Data
Date March 06, 2019

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      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.

    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            —    —    —   
Acquisitions (4)    3,080    1,522    4,602      —    —    —   
Dispositions    (1  (2  (2    —    —    —   
Economic Factors    149    114    262      —    (3  (3 
Production    (9,218  —    (9,218    (256  —    (256 
December 31, 2018    49,613    42,687    92,301      12,805    55,545    68,350   
         
         
    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, 2017    1,608    1,225    2,833      50,296    11,390    61,686   
Extensions (4)    —    —    —      1,515    2,645    4,160   
Infill Drilling (4)    10,823    2,856    13,679      1,062    147    1,209   
Improved Recoveries    —    —    —      —    —    —   
Technical Revisions (3)    273    (381  (109    5,285    7,154    12,438   
Discoveries    —    —    —      65    15    80   
Acquisitions (4)    61,992    17,234    79,226      625    594    1,219   
Dispositions    —    —    —      —    —    —   
Economic Factors    15      23      (175  (65  (240 
Production    (3,165  —    (3,165    (5,854  —    (5,854 
December 31, 2018    71,545    20,941    92,487      52,819    21,879    74,698   
         
         
    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, 2017    84,564    38,962    123,526      172,855    75,686    248,541   
Extensions (4)    644    1,173    1,817      2,582    4,681    7,262   
Infill Drilling    534    109    643      407    121    528   
Improved Recoveries    —    —    —      —    —    —   
Technical Revisions (3)    (5,742  (1,716  (7,458    (10,715  (9,111  (19,826 
Discoveries    12      15      73    17    90   
Acquisitions (4)    349    256    605      790    809    1,599   
Dispositions    —    —    —      —    —    —   
Economic Factors    (528  (314  (841    (1,133  (652  (1,785 
Production    (5,220  —    (5,220    (13,702  —    (13,702 
December 31, 2018    74,614    38,473    113,087      151,156    71,550    222,706   
         
         
    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, 2017    181,837    100,724    282,560      255,556    176,461    432,017   
Extensions (4)    66    185    251      3,882    5,319    9,201   
Infill Drilling (4)    6,055    1,643    7,699      14,842    4,311    19,153   
Improved Recoveries    —    —    —      1,952    4,621    6,574   
Technical Revisions (3)    (24,918  9,915    (15,004    (2,013  91    (1,922 
Discoveries    —    —    —      92    22    114   
Acquisitions (4)    28,494    11,812    40,306      70,926    21,709    92,635   
Dispositions    —    —    —      (1  (2  (2 
Economic Factors    (3,197  (1,593  (4,790    (1,261  (635  (1,896 
Production    (20,232  —    (20,232    (29,368  —    (29,368 
December 31, 2018    168,104    122,685    290,789      314,607    211,898    526,505   

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, 2018 and 2017 is prepared in accordance with NI 51-101.
(3) Negative technical revisions for conventional natural gas are largely the result of adjustments to our gas conservation bookings in Peace River area and reduced type well profiles in our Canadian conventional natural gas properties. Positive technical revisions for tight oil are the result of enhanced type well profiles on our Eagle Ford acreage, as well as the reclassification of some natural gas liquids volumes to tight oil. Negative technical revisions for shale gas and natural gas liquids are the result of the removal of certain drilling locations on our Eagle Ford acreage as well as reclassification of shale gas volumes to solution gas. 
(4) Acquisitions are principally attributable to reserves associated with the Raging River combination. For light and medium crude oil and tight oil, reserves associated with the Raging River assets are captured within acquisitions, extensions and infill drilling. Total proved reserves of 11.5 mmboe and total proved plus probable reserves of 14.6 mmboe of the infill drilling additions are associated with the Raging River Acquisition. Total proved reserves of 2.6 mmboe and total proved plus probable reserves of 7.2 mmboe of the extensions additions are associated with the Raging River Acquisition.   
(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 at year-end 2018 by annualized Q4/2018 production.

    Q4/2018 Actual    Reserves Life Index (years)   
    Production    Proved    Proved Plus Probable   
  Oil and NGL (bbl/d)  81,653    8.8    14.8   
  Natural Gas (mcf/d)  103,424    8.5    13.6   
  Oil Equivalent (boe/d)  98,890    8.7    14.6   

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 program is summarized in the following table.

  2018    2017    2016    Three-Year 
Total / Average
2016 - 2018 
Capital Expenditures ($ millions)           
Exploration and development  495.7    326.3    224.8    1,046.8 
Acquisitions (net of dispositions)  1,603.9    59.9    (63.6)    1,600.2 
Total  2,099.6    386.1    161.2    2,646.9 
               
Change in Future Development Costs – 1P ($ millions)               
Exploration and development  117.4    (132.6)    (219.4)    (234.6) 
Acquisitions (net of dispositions)    870.0      35.5      7.6      913.1 
Total  987.4    (97.1)    (211.8)    678.4 
               
Change in Future Development Costs – 2P ($ millions)             
Exploration and Development  132.3    (76.4)    108.8    164.7 
Acquisitions (net of dispositions)  932.2    160.6    1.9    1,094.6 
Total  1,064.5    84.2    110.7    1,259.4 
               
PDP Reserves Additions (mboe)               
Exploration and development  31,330    23,752    17,120    72,202 
Acquisitions (net of dispositions)  32,398    3,711    (1,710)    34,399 
Total  63,728    27,463    15,410    106,601 
               
1P Reserves Additions (mboe)               
Exploration and development  17,494    21,695    5,041    44,243 
Acquisitions (net of dispositions)  70,925    6,821    (1,564)    76,168 
Total  88,419    28,516    3,477    120,411 
               
2P Reserves Additions (mboe)               
Exploration and development  31,224    34,398    17,253    82,895 
Acquisitions (net of dispositions)  92,633    17,204    (2,408)    107,409 
Total  123,857    51,602    14,845    190,304 
               
F&D costs ($/boe) (1)               
PDP  15.82    13.73    13.14    14.50 
1P  35.05    8.93    1.07    18.36 
2P  20.11    7.26    19.33    14.61 
               
FD&A costs ($/boe) (2)               
PDP  32.95    14.06    10.50    24.83 
1P  34.91    10.13    —  (5)    27.62 
2P  25.55    9.11    18.33    20.53 
               
Ratios (based on 2P reserves)               
Production replacement ratio (3)  422%    201%    58%    237% 
Recycle ratio (4)  1.2x    2.7x    0.9x    1.6x 

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 divided by total annual production (including acquisitions and divestitures).
(4) Recycle Ratio is calculated as operating netback divided by 2P F&D costs. Operating netback is calculated as revenue less royalties, operating expenses and transportation expenses.
(5) 2016 FD&A costs (1P) were negative due to the reduction in estimated Future Development Costs.

Net Present Value of Reserves (Forecast Prices and Costs)

The following table summarizes our independent reserves evaluators estimates 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, 2018
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    1,792,884    1,544,771    1,355,997    1,212,741    1,101,425 
Developed Non-Producing    244,486    172,472    125,171    93,194    70,965 
Undeveloped    1,841,321    1,279,571    907,327    654,251    476,320 
Total Proved    3,878,692    2,996,814    2,388,494    1,960,186    1,648,709 
Probable    3,862,671    2,304,632    1,538,566    1,108,674    841,887 
Total Proved Plus Probable    7,741,363    5,301,446    3,927,060    3,068,859    2,490,597 
     
     
UNITED STATES     
    0%    5%    10%    15%    20% 
Reserves Category    ($000s)    ($000s)    ($000s)    ($000s)    ($000s) 
Proved                     
Developed Producing    1,627,506    1,192,348    961,733    820,072    723,542 
Developed Non-Producing    8,652    6,491    5,164    4,286    3,667 
Undeveloped    1,667,167    1,099,049    759,576    542,510    396,760 
Total Proved    3,303,324    2,297,888    1,726,473    1,366,868    1,123,969 
Probable    1,750,388    901,795    531,484    343,816    238,512 
Total Proved Plus Probable      5,053,712      3,199,683      2,257,957      1,710,684      1,362,481 
TOTAL     
    0%    5%    10%    15%    20% 
Reserves Category    ($000s)    ($000s)    ($000s)    ($000s)    ($000s) 
Proved                     
Developed Producing    3,420,390    2,737,119    2,317,729    2,032,813    1,824,967 
Developed Non-Producing    253,138    178,963    130,335    97,480    74,631 
Undeveloped    3,508,488    2,378,620    1,666,903    1,196,760    873,080 
Total Proved    7,182,016    5,294,702    4,114,967    3,327,054    2,772,678 
Probable    5,613,059    3,206,427    2,070,050    1,452,489    1,080,399 
Total Proved Plus Probable      12,795,075      8,501,129      6,185,017      4,779,543      3,853,078 
 

Sproule Forecast Prices and Costs

The following table summarizes the forecast prices used in preparing the estimated reserves volumes and the net present values of future net revenues at December 31, 2018.

Year  WTI
Cushing
US$/bbl 
LLS
Onshore
US$/bbl 
Canadian
Light
Sweet
$/bbl 
Western
Canada
 Select
C$/bbl 
Henry Hub
US$/MMbtu 
AECO
C Spot
C$/MMbtu 
Operating
Cost 
Inflation Rate
%/Yr 
Capital
Cost
Inflation Rate
%/Yr 
Exchange
Rate
$US/$Cdn 
2018 act.  65.04  70.14  68.63  52.64  3.11  1.52  2.5  4.2  0.77 
2019  63.00  68.40  75.27  59.47  3.00  1.95  0.0  0.0  0.77 
2020  67.00  70.37  77.89  62.31  3.25  2.44  2.0  2.0  0.80 
2021  70.00  71.34  82.25  67.45  3.50  3.00  2.0  2.0  0.80 
2022  71.40  72.76  84.79  69.53  3.57  3.21  2.0  2.0  0.80 
2023  72.83  74.22  87.39  71.66  3.64  3.30  2.0  2.0  0.80 
2024  74.28  75.70  89.14  73.10  3.71  3.39  2.0  2.0  0.80 
2025  75.77  77.22  90.92  74.56  3.79  3.49  2.0  2.0  0.80 
2026  77.29  78.76  92.74  76.05  3.86  3.58  2.0  2.0  0.80 
2027  78.83  80.34  94.60  77.57  3.94  3.68  2.0  2.0  0.80 
2028  80.41  81.94  96.49  79.12  4.02  3.78  2.0  2.0  0.80 
2029  82.02  83.58  98.42  80.70  4.10  3.88  2.0  2.0  0.80 
Thereafter  Escalation 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, 2018
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 
                             
2019    302,027    361,583      129,181    144,727      431,208    506,309 
2020    457,359    633,766      292,260    292,260      749,619    926,025 
2021    400,568    487,702      264,263    264,263      664,831    751,965 
2022    276,701    451,347      273,975    273,975      550,676    725,323 
2023    10,499    216,289      240,502    241,144      251,002    457,433 
Remaining    1,414    308,388      16,398    559,839      17,812    868,227 
Total (undiscounted)    1,448,569    2,459,074      1,216,580    1,776,209      2,665,148    4,235,283 


Properties with No Attributed Reserves

The following table sets forth our undeveloped land holdings as at December 31, 2018.

  Undeveloped Acres   
  Gross    Net   
         
Alberta  1,054,743    964,579   
Saskatchewan  369,366    329,641   
Total  1,424,109    1,294,220   
         

Undeveloped land holdings are lands that have not been assigned reserves as at December 31, 2018.  We estimate the value of our net undeveloped land holdings at December 31, 2018 to be approximately $164.6 million, as compared to $75.9 million as at December 31, 2017. This internal evaluation generally represents the estimated replacement cost of our undeveloped land, excluding the approximately 98,952 net acres of our undeveloped land that we expect to expire on or before December 31, 2019.  In determining replacement cost, we analyzed land sale prices paid at Provincial Crown land sales for properties in the vicinity of our undeveloped land holdings.

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 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. 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.  

The following table sets forth our net asset value as at December 31, 2018.

  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)  8,501      6,185      4,780     
Undeveloped land holdings (1)  165      165      165     
Asset retirement obligations (2)  (147    (57    (36   
Net debt  (2,265    (2,265    (2,265   
Net Asset Value  6,254      4,028      2,644     
Net Asset Value per Share (3)  11.29      7.27      4.77     

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 554.1 million common shares outstanding as at December 31, 2018.

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd