Baytex Energy Corp.

TSX : BTE
NYSE : BTE


Baytex Energy Corp.

March 13, 2014 08:00 ET

Baytex Reports Record Production and Funds from Operations and Strong Reserve Growth for 2013

CALGARY, ALBERTA--(Marketwired - March 13, 2014) - Baytex Energy Corp. (TSX:BTE)(NYSE:BTE) ("Baytex") reports its operating and financial results for the three months and year ended December 31, 2013 (all amounts are in Canadian dollars unless otherwise noted).

"2013 was an exceptional year as Baytex delivered its highest level of funds from operations and reached a record level of annual production while growing proved plus probable reserves by 9%, all in a challenging year for heavy oil pricing. We replaced 234% of our production through organic development and generated a strong 1.8x recycle ratio," commented James Bowzer, President and Chief Executive Officer.

Bowzer said, "We look forward to continuing our strong performance with the expansion of our asset portfolio into the Eagle Ford through the pending acquisition of Aurora Oil & Gas Limited. We are committed to a growth-and-income model and its three fundamental principles: delivering organic production growth, paying a meaningful dividend and maintaining capital discipline. Through the combination of an expanded inventory of high capital efficiency projects and an improved outlook for heavy oil differentials, we remain confident in our business plan going forward."

Highlights

  • Generated production of 58,304 boe/d (88% oil and NGL) in Q4/2013, an increase of 6% over Q4/2012, and record annual production of 57,196 boe/d (88% oil and NGL), an increase of 6% over 2012;
  • Delivered funds from operations ("FFO") of $147.5 million ($1.18 per basic share) in Q4/2013, an increase of 16% over Q4/2012, and $604.4 million ($4.88 per share basic) in full-year 2013, an increase of 13% from 2012 and the highest level of annual FFO in company history;
  • Increased proved reserves by 11% to 160 million boe (a 9% increase on a per share basis) and proved plus probable reserves by 9% to 318 million boe (a 7% increase on a per share basis);
  • Replaced 234% of production through organic exploration and development activities. Inclusive of acquisitions and divestitures, replaced 227% of production;
  • Recorded finding, development and acquisition ("FD&A") costs for proved plus probable reserves, including changes in future development costs ("FDC"), of $18.28/boe for 2013 and $15.65/boe for the three-year average (2011-2013);
  • Realized a recycle ratio (operating netback divided by FD&A costs) based on proved plus probable reserves (including changes in FDC) of 1.8x for 2013, and 2.1x for the three-year average;
  • Maintained a conservative payout ratio, net of dividend reinvestment plan ("DRIP") participation, of 40% (56% before DRIP) in Q4/2013 and 39% (54% before DRIP) in full-year 2013;
  • Ended the fourth quarter with total monetary debt of $762.1 million, representing a debt-to-FFO ratio of 1.3x based on FFO over the trailing twelve-month period; and
  • Subsequent to the end of the year, entered into an agreement to acquire 100% of the shares of Aurora Oil & Gas Limited ("Aurora") for total consideration of approximately $2.6 billion.
Three Months Ended Years Ended
December 31, 2013 September 30, 2013 December 31, 2012 December 31, 2013 December 31, 2012
FINANCIAL
(thousands of Canadian dollars, except per common share amounts)
Petroleum and natural gas sales 330,712 422,791 292,095 1,367,459 1,219,484
Funds from operations (1) 147,544 199,318 127,253 604,438 532,725
Per share - basic 1.18 1.61 1.05 4.88 4.44
Per share - diluted 1.17 1.59 1.04 4.82 4.37
Cash dividends declared (2) 59,532 61,354 55,043 237,663 215,184
Dividends declared per share 0.66 0.66 0.66 2.64 2.64
Net income(3) 31,173 87,331 31,620 164,845 258,631
Per share - basic 0.26 0.70 0.26 1.33 2.16
Per share - diluted 0.25 0.70 0.26 1.32 2.12
Exploration and development 85,060 121,484 66,686 550,900 418,625
Acquisitions, net of divestitures 2,258 2,838 131,797 (39,082) (170,936)
Total oil and natural gas capital expenditures 87,318 124,322 198,483 511,818 247,689
Bank loan 223,371 244,651 116,394 223,371 116,394
Long-term debt 459,540 454,275 449,235 459,540 449,235
Working capital deficiency 79,151 57,703 34,197 79,151 34,197
Total monetary debt (4) 762,062 756,629 599,826 762,062 599,826
OPERATING
Daily production
Light oil and NGL (bbl/d) 8,047 8,366 7,739 8,134 7,360
Heavy oil (bbl/d) 43,254 44,908 40,257 42,064 39,447
Total oil and NGL (bbl/d) 51,301 53,274 47,996 50,198 46,807
Natural gas (mcf/d) 42,018 41,460 42,302 41,989 43,076
Oil equivalent (boe/d @ 6:1) (5) 58,304 60,184 55,046 57,196 53,986
Average prices (before hedging)
WTI oil (US$/bbl) 97.46 105.82 88.18 97.97 94.19
WCS heavy oil (US$/bbl) 65.26 88.34 70.07 72.78 73.16
Edmonton par oil ($/bbl) 86.25 105.07 84.28 93.24 86.53
Baytex heavy oil ($/bbl) (6) 61.89 79.29 54.58 65.24 59.44
Baytex light oil and NGL ($/bbl) 74.73 88.63 72.02 79.61 74.07
Baytex total oil and NGL ($/bbl) 63.91 80.75 57.39 67.57 61.74
Baytex natural gas ($/mcf) 3.52 2.72 3.03 3.32 2.45
Baytex oil equivalent ($/boe) 58.75 73.36 52.37 61.74 55.48
CAD/USD noon rate at period end 1.0636 1.0285 0.9949 1.0636 0.9949
CAD/USD average rate for period 1.0494 1.0385 0.9913 1.0299 0.9991
Three Months Ended Years Ended
COMMON SHARE INFORMATION December 31, 2013 September 30, 2013 December 31, 2012 December 31, 2013 December 31, 2012
TSX
Share price (Cdn$)
High 44.26 44.44 48.35 47.60 59.40
Low 40.21 37.65 41.91 36.37 38.54
Close 41.64 42.51 42.87 41.64 42.87
Volume traded (thousands) 22,585 24,658 25,108 105,097 108,327
NYSE
Share price (US$)
High 42.84 43.08 49.25 47.47 59.50
Low 37.78 35.72 42.20 34.75 37.40
Close 39.16 41.27 43.24 39.16 43.24
Volume traded (thousands) 3,657 3,282 3,567 15,071 22,135
Common shares outstanding (thousands) 125,392 124,497 121,868 125,392 121,868
Notes:
(1) Funds from operations is a non-Generally Accepted Accounting Principles ("GAAP") measure that represents cash generated from operating activities adjusted for finance costs, changes in non-cash operating working capital and other operating items. Baytex's funds from operations may not be comparable to other issuers. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends and capital investments. For a reconciliation of funds from operations to cash flow from operating activities, see Management's Discussion and Analysis of the operating and financial results for the three months and year ended December 31, 2013.
(2) Cash dividends declared are net of DRIP participation.
(3) Net income for the year ended December 31, 2013 includes gains on divestitures of oil and gas properties of $21.0 million (2012 - gain of $172.5 million) and loss on financial instruments of $13.1 million (2012 - gain of $61.6 million).
(4) Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives, assets held for sale and liabilities related to assets held for sale)), the principal amount of long-term debt and long-term bank loan.
(5) 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.
(6) Heavy oil prices exclude condensate blending.

Operations Review

Production averaged 58,304 boe/d (88% oil and NGL) during Q4/2013, an increase of 6% over Q4/2012, and 57,196 boe/d for full-year 2013, an increase of 6% over 2012. Average annual production for 2013 represented the highest production rate in company history.

As previously reported, our transportation operations were hampered by severe winter weather during Q4/2013 which impacted our ability to deliver crude oil from the field to sales delivery points. As inventory levels reached capacity, production was curtailed by approximately 5,000 bbl/d in December.

Capital expenditures for exploration and development activities totaled $550.9 million for the full-year 2013 and included the drilling of 281 (226.8 net) wells with a 99% success rate.

Our 2014 production guidance remains unchanged at 60,000 to 62,000 boe/d with budgeted exploration and development expenditures of $485 million, and does not include the integration of the Aurora Eagle Ford acquisition which was announced on February 6, 2014 and is expected to close in late May 2014. Following closing of the acquisition, Baytex will provide revised guidance for full-year 2014.

Wells Drilled - Three Months Ended December 31, 2013

Crude Oil Stratigraphic Dry and
Primary Thermal Natural Gas and Service Abandoned Total
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Heavy oil
Lloydminster area 22 10.2 - - - - 5 5.0 - - 27 15.2
Peace River area 11 11.0 5 5.0 - - - - - - 16 16.0
33 21.2 5 5.0 - - 5 5.0 - - 43 31.2
Light oil, NGL and natural gas
Western Canada - - - - 1 1.0 - - - - 1 1.0
North Dakota - - - - - - - - - - - -
Wyoming 1 0.7 - - - - - - - - 1 0.7
1 0.7 - - 1 1.0 - - - - 2 1.7
Total 34 21.9 5 5.0 1 1.0 5 5.0 - - 45 32.9

Wells Drilled - Year Ended December 31, 2013

Crude Oil Stratigraphic Dry and
Primary Thermal Natural Gas and Service Abandoned Total
Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Heavy oil
Lloydminster area 142 102.5 4 4.0 - - 8 8.0 2 2.0 156 116.5
Peace River area 41 41.0 15 15.0 - - 31 31.0 - - 87 87.0
183 143.5 19 19.0 - - 39 39.0 2 2.0 243 203.5
Light oil, NGL and natural gas
Western Canada 14 11.0 - - 3 3.0 - - - - 17 14.0
North Dakota 20 8.6 - - - - - - - - 20 8.6
Wyoming 1 0.7 - - - - - - - - 1 0.7
35 20.3 - - 3 3.0 - - - - 38 23.3
Total 218 163.8 19 19.0 3 3.0 39 39.0 2 2.0 281 226.8

Heavy Oil

In Q4/2013, heavy oil production averaged 43,254 bbl/d, an increase of 7% from Q4/2012. During Q4/2013, we drilled 38 (26.2 net) oil wells and five (5.0 net) stratigraphic and service wells on our heavy oil properties.

Production from our Peace River area properties averaged approximately 23,900 bbl/d in Q4/2013, an increase of 14% from Q4/2012. As previously reported, production at Peace River was hampered by severe winter weather during Q4/2013 which impacted our ability to deliver crude oil from the field to sales delivery points, resulting in production curtailments of approximately 5,000 bbl/d in the month of December.

In Q4/2013, we drilled 11 (11.0 net) cold horizontal producers encompassing a total of 125 laterals in the Peace River area bringing our 2013 drilling to 41 (41.0 net) wells. Our 2013 cold horizontal multi-lateral drilling program was one of the strongest in company history with average 30-day peak production rates of approximately 600 bbl/d, which is near the upper end of our expected range of 300 to 700 bbl/d.

Baytex continued to progress its thermal operations in the Cliffdale area with Pad 1 cumulative steam-oil ratio performance continuing to track our predictions. Pad 1 steaming operations were reduced in the fourth quarter due to steam generator repairs and maintenance. Pad 2, consisting of fifteen wells that were successfully drilled throughout 2013, are currently producing as planned under primary conditions to create the initial voidage required for the cyclic steam stimulation process. We expect steam injection at Pad 2 to commence in mid-2014.

The Alberta Energy Regulator ("AER") recently held a public proceeding to investigate concerns about odours and emissions associated with heavy oil production in the Peace River area. An oral proceeding was held during the last two weeks of January 2014. Baytex was an active participant in the proceeding and welcomed the opportunity to inform the public and the regulator about our efforts to improve our operations and reduce the environmental impact. The AER hearing panel is expected to issue their report and recommendations by March 31, 2014.

In our Lloydminster heavy oil area, Q4/2013 drilling included 15 (8.7 net) horizontal oil wells and seven (1.5 net) vertical oil wells, with a 100% success rate, and five (5.0 net) stratigraphic test wells. Construction of the Gemini steam-assisted gravity drainage ("SAGD") pilot project facilities continued in Q4/2013 and commissioning was completed early in January. Steam injection commenced on January 24, 2014 with first oil production projected to occur in Q2/2014.

Light Oil & Natural Gas

During Q4/2013, light oil and NGL production averaged 8,047 bbl/d (a 4% increase from Q4/2012) and natural gas production averaged 42.0 mmcf/d (essentially unchanged from Q4/2012). In our Bakken/Three Forks play in North Dakota, no drilling occurred in Q4/2013. Three previously drilled and completed wells on 1,280-acre spacing established average 30-day peak production rates of approximately 410 boe/d during Q4/2013.

Financial Review

We generated FFO of $147.5 million ($1.18 per basic share) in Q4/2013, which represented a 26% decrease from the $199.3 million generated in Q3/2013 and was the result of lower realized commodity prices and lower sales volumes. Full-year FFO was $604.4 million ($4.88 per basic share), an increase of 13% compared to 2012, and established a new company record for annual FFO. This increase was largely due to higher sales volumes and higher realized commodity prices.

The average WTI price for Q4/2013 was US$97.46/bbl, an 8% decrease from Q3/2013. The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 33% in Q4/2013, as compared to 17% in Q3/2013. The widening of the WCS differentials in the three months ended December 31, 2013 was caused by capacity restrictions on Canadian crude export pipelines in the fourth quarter of 2013, which triggered a back-up of crude in Western Canada, forcing it into storage. As a result of the weaker WCS in Q4/2013, our realized total oil and NGL price of $63.91/bbl in the fourth quarter of 2013 (inclusive of our physical hedging gains) decreased by 21% from $80.75/bbl in the third quarter of 2013.

Market conditions have recently improved with the forward market indicating a WCS average differential of approximately 23% for Q1/2014 and 21% for the remainder of this year. The improved market conditions reflect a number of positive catalysts unfolding in 2014, including increased refinery demand in the U.S. Midwest, a continued increase in crude by rail volumes and a number of pipeline capacity improvements and expansion projects.

We have taken advantage of the recent strength in WTI prices and the weaker Canadian dollar to add to our hedge portfolio. For Q1/2014, we have entered into hedges on approximately 55% of our WTI exposure at a weighted average price of US$99.31/bbl, 26% of our exposure to WCS price differentials primarily through a combination of long term physical supply contracts and rail delivery, 55% of our natural gas price exposure, and 31% of our exposure to currency movements between the U.S. and Canadian dollars. Details of our hedging contracts are contained in the notes to our financial statements.

As part of our hedging program, we are focusing on opportunities to further mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail. During the fourth quarter, approximately 21,500 bbl/d of our heavy oil volumes were delivered to market by rail, as compared to 7,500 bbl/d for full-year 2012 and 17,500 bbl/d for full-year 2013. For Q1/2014, we expect our heavy oil volumes on rail to increase to approximately 26,000 bbl/d.

Total monetary debt at December 31, 2013 was $762.1 million, representing a debt-to-FFO ratio of 1.3 times based on FFO over the trailing twelve-month period. At year-end, Baytex had $626.6 million in undrawn credit facilities and no long-term debt maturities until 2021.

Acquisition of Aurora

On February 6, 2014, Baytex entered an agreement to acquire all of the ordinary shares of Aurora for A$4.10 (Australian dollars) per share by way of a scheme of arrangement under Part 5.1 of the Corporations Act 2001 (Australia) (the "Arrangement"). The total purchase price for Aurora is estimated at $2.6 billion (including the assumption of approximately $0.7 billion of indebtedness). The acquisition enhances Baytex's growth-and-income business model, delivers production and reserves per share growth and provides attractive capital efficiencies for future investment. The acquisition is accretive to Baytex's funds from operations while maintaining a strong balance sheet.

Aurora's primary asset is 22,200 net contiguous acres in the prolific Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford shale. Aurora's fourth quarter 2013 gross production was 24,678 boe/d (82% liquids) of predominantly light, high-quality crude oil. The Sugarkane Field has been largely delineated with infrastructure in place which is expected to facilitate low-risk future annual production growth. In addition, these assets have significant future reserves upside potential from well downspacing, improving completion techniques and new development targets in additional zones.

The Arrangement is subject to a number of customary closing conditions, including the receipt of required regulatory approvals and court approvals, as well as the approval of the shareholders of Aurora. Regulatory approvals include approval of the Australian Foreign Investment Review Board and the applicable approvals required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 ("HSR"), as amended. On March 4, 2014, we received approval from the United States Federal Trade Commission with respect to HSR. The Arrangement must be approved by: (i) at least 75% of the votes cast by Aurora shareholders; and (ii) by a majority, in number, of the Aurora shareholders who cast votes. The Arrangement is expected to close in late May 2014.

To finance the acquisition of Aurora, Baytex completed a subscription receipt financing on February 24, 2014, raising gross proceeds of approximately $1.5 billion, and entered into a commitment letter with a Canadian chartered bank for the provision of new revolving credit facilities in the amount of $1.0 billion (to replace the $850 million revolving credit facilities of Baytex Energy) and a new two-year $200 million non-revolving loan. Baytex has also entered into a commitment letter with a Canadian chartered bank for the provision of a new borrowing base facility in the amount of US$300 million for a U.S. subsidiary of Aurora (to be established upon closing of the Arrangement as a replacement for Aurora's existing facility).

9% Dividend Increase

At Baytex, we are committed to a growth-and-income model and its three fundamental principles: delivering organic production growth, paying a meaningful dividend and maintaining capital discipline. Through the combination of an expanded inventory of high capital efficiency projects and an improved outlook for heavy oil differentials, we remain confident in our business plan going forward. Consequently, Baytex has committed to increase the monthly dividend on its common shares by 9% to $0.24 from $0.22 per share, subject to the completion of the Aurora acquisition.

Year-end 2013 Reserves

Baytex's year-end 2013 reserves were evaluated by Sproule Associates Limited ("Sproule"), the independent qualified reserves evaluator for all of Baytex's oil and gas properties, in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" ("NI 51-101"). Reserves associated with our thermal heavy oil projects at Peace River, Gemini (Cold Lake) and Kerrobert have been classified as bitumen, in accordance with NI 51-101. Finding and development ("F&D") and finding, development and acquisition costs are all reported inclusive of future development costs. Complete reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2013, which will be filed in late March 2014.

Highlights of the 2013 reserve report include:

  • Proved reserves increased 11% to 160 million boe (a 9% increase on a per share basis) and proved plus probable reserves increased 9% to 318 million boe (a 7% increase on a per-share basis). Year-end 2013 proved plus probable reserves are comprised of 90% oil and NGLs and 10% natural gas;
    • At Peace River, proved plus probable reserves attributable to our conventional heavy oil development in the Bluesky formation (cold horizontal multi-lateral wells) increased 6% to 67 million barrels. Our 2013 drilling program included 41.0 net multi-lateral wells;
    • At Lloydminster, proved plus probable reserves total 59 million barrels, essentially unchanged from year-end 2012, as reserve additions offset production. In 2013, we drilled 104.5 net wells (54% vertical wells, 46% horizontal wells) in the Lloydminster region with a 98% success rate;
    • In our Bakken/Three Forks resource play, proved plus probable reserves increased 55% to 53.5 million barrels of oil equivalent due largely to an increased drilling density of five wells (previously three wells) per 1,280 acre spacing unit. Our 2013 drilling program included 8.6 net wells; and
    • Bitumen reserves on a proved plus probable basis total 102 million barrels, unchanged from year-end 2012. During 2013, we continued to progress thermal development with facility construction at both our 15-well CSS module at Cliffdale and our Gemini SAGD pilot project;
  • Exploration and development capital expenditures in 2013 totaled $550.9 million. Net of property dispositions of $39.1 million, the total net capital outlay in 2013 was $511.8 million. This level of net expenditures resulted in the net addition of 47.4 million boe of proved plus probable reserves;
  • We replaced 234% of production through exploration and development activities (excluding acquisitions and divestitures) with F&D costs of $19.30/boe. Three-year average (2011-2013) F&D costs are $19.34/boe;
  • Inclusive of acquisitions and divestitures, we replaced 227% of production with FD&A costs of $18.28/boe. Three-year average (2011-2013) FD&A costs are $15.65/boe;
  • The net present value (before income taxes and discounted at 10%) of future net revenue attributable to our proved plus probable reserves increased 15% to $4.3 billion;
  • Baytex generated an operating netback of $32.62/boe (excluding financial derivatives) resulting in a proved plus probable recycle ratio of 1.8x. Three-year average (2011-2013) recycle ratio is 2.1x; and
  • Proved plus probable reserves life index increased to 14.3 years from 14.0 years based on the mid-point of our 2014 production guidance of 61,000 boe/d.

Petroleum and Natural Gas Reserves as at December 31, 2013

The following table sets forth our gross and net reserve volumes at December 31, 2013 by product type and reserve category using Sproule's forecast prices and costs. Please note that the data in the table may not add due to rounding.

Forecast Prices and Costs
Heavy Oil Bitumen Light and Medium
Crude Oil
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Reserve Category (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
Proved
Developed Producing 41,526 30,985 7,422 6,719 10,129 7,958
Developed Non-Producing 8,944 7,404 3,491 3,083 28 24
Undeveloped 32,433 26,757 8,409 7,336 25,792 21,021
Total Proved 82,903 65,146 19,322 17,139 35,949 29,003
Probable 42,644 34,141 82,564 66,117 16,765 13,474
Total Proved Plus Probable 125,547 99,287 101,886 83,256 52,714 42,477
Forecast Prices and Costs
Natural Gas Liquids Natural Gas Oil Equivalent(3)
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Reserve Category (mbbl) (mbbl) (mmcf) (mmcf) (mboe) (mboe)
Proved
Developed Producing 2,032 1,461 56,083 47,238 70,456 54,997
Developed Non-Producing 75 55 1,825 1,572 12,842 10,827
Undeveloped 965 675 51,757 40,936 76,226 62,611
Total Proved 3,073 2,191 109,665 89,745 159,524 128,436
Probable 3,469 2,421 78,895 60,721 158,591 126,273
Total Proved Plus Probable 6,542 4,611 188,561 150,466 318,115 254,709
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) 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.

Reserve Reconciliation

The following table reconciles the year-over-year changes in our gross reserve volumes by product type and reserve 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, 2012 79,843 42,021 121,863 19,476 82,085 101,562
Extensions 19,212 5,865 25,078 560 240 800
Discoveries 10 6 17 - - -
Improved Recoveries 243 888 1,131 - - -
Technical Revisions (2,535) (6,609) (9,145) 56 233 289
Acquisitions - - - - - -
Dispositions - - - - - -
Economic Factors 581 473 1,053 132 6 138
Production (14,451) - (14,451) (903) - (903)
December 31, 2013 82,903 42,644 125,547 19,322 82,564 101,886
Light and Medium Crude Oil Natural Gas Liquids
Proved Probable Proved +
Probable
Proved Probable Proved +
Probable
Gross Reserves Category (mbbl) (mbbl) (mbbl) (mbbl) (mbbl) (mbbl)
December 31, 2012 25,119 14,079 39,199 5,788 3,424 9,212
Extensions 16,514 6,075 22,589 262 1,739 2,001
Discoveries - - - - - -
Improved Recoveries - - - - - -
Technical Revisions (2,404) (3,184) (5,588) (2,234) (1,760) (3,994)
Acquisitions - - - - - -
Dispositions (1,156) (379) (1,535) - - -
Economic Factors 179 173 352 (77) 66 (11)
Production (2,303) - (2,303) (666) - (666)
December 31, 2013 35,949 16,765 52,714 3,073 3,469 6,542
Natural Gas Oil Equivalent (3)
Proved Probable Proved +
Probable
Proved Probable Proved +
Probable
Gross Reserves Category (mmcf) (mmcf) (mmcf) (mboe) (mboe) (mboe)
December 31, 2012 79,308 39,257 118,565 143,444 148,152 291,597
Extensions 27,745 41,382 69,127 41,172 20,817 61,989
Discoveries - - - 10 6 17
Improved Recoveries - - - 243 888 1,131
Technical Revisions 20,051 (3,080) 16,971 (3,776) (11,833) (15,609)
Acquisitions - - - - - -
Dispositions (22) (4) (26) (1,160) (379) (1,540)
Economic Factors (2,091) 1,341 (750) 466 941 1,407
Production (15,326) - (15,326) (20,877) - (20,877)
December 31, 2013 109,665 78,895 188,561 159,524 158,592 318,115
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) Reserve information as at December 31, 2013 and 2012 is prepared in accordance with NI 51-101.
(3) 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 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Reserve Life Index

The following table sets forth our reserve life index based on proved and proved plus probable reserves at year-end 2013 and the mid-point of our 2014 production guidance of 61,000 boe/d.

Mid-Point of 2014 Reserve Life Index (years)
Production Guidance Proved Proved Plus Probable
Oil and NGL (bbl/d) 54,300 7.1 14.5
Natural Gas (mcf/d) 40,200 7.5 12.8
Oil Equivalent (boe/d) 61,000 7.2 14.3

Capital Program Efficiency

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

2013 2012 2011 Three-Year
Total / Average
2011 - 2013
Capital Expenditures ($millions)
Exploration and development $ 550.9 $ 418.6 $ 367.9 $ 1,337.4
Acquisitions (net of dispositions) (39.1) (170.9) 148.8 (61.2)
Total $ 511.8 $ 247.7 $ 516.6 $ 1,276.1
Change in Future Development Costs ($millions)
Proved $ 261.5 $ (50.1) $ 315.4 $ 526.8
Proved plus probable $ 354.3 $ 433.5 $ 253.3 $ 1,041.1
Proved Reserve Additions (mboe)
Exploration and development 38,117 18,411 27,151 83,679
Acquisitions (net of dispositions) (1,160) (11,769) 7,519 (5,410)
Total 36,957 6,642 34,670 78,269
Proved plus Probable Reserve Additions (mboe)
Exploration and development 48,936 33,659 30,033 112,628
Acquisitions (net of dispositions) (1,540) 25,523 11,415 35,398
Total 47,396 59,182 41,448 148,027
F&D costs ($/boe) (1)
Proved $ 22.34 $ 29.14 $ 23.66 $ 24.26
Proved plus probable $ 19.30 $ 19.69 $ 19.02 $ 19.34
FD&A costs ($/boe)
Proved $ 20.92 $ 29.75 $ 24.00 $ 23.03
Proved plus probable $ 18.28 $ 11.51 $ 18.57 $ 15.65
Ratios (based on proved plus probable reserves)
Production replacement (2) 227% 300% 227% 251%
Recycle ratio (3) 1.8x 2.7x 1.9x 2.1x
Notes:
(1) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserve additions for that year.
(2) Production Replacement ratio is calculated as total reserve additions (including acquisitions and divestitures) divided by annual production.
(3) Recycle ratio is calculated as operating netback divided by FD&A costs (proved plus probable including FDC). Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating expenses and transportation expenses.

Net Present Value of Reserves (Forecast Prices and Costs)

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

Summary of Net Present Value of Future Net Revenue
As at December 31, 2013
Before Income Taxes and Discounted at (%/year)
Forecast Prices and Costs
0% 5% 10% 15% 20%
Reserve Category ($000s) ($000s) ($000s) ($000s) ($000s)
Proved
Developed Producing $ 2,132,314 $ 1,800,435 $ 1,572,541 $ 1,406,143 $ 1,279,038
Developed Non-Producing 396,448 310,251 249,035 204,183 170,432
Undeveloped 2,181,190 1,435,733 987,618 703,083 512,882
Total Proved 4,709,952 3,546,419 2,809,194 2,313,409 1,962,352
Probable 4,787,326 2,511,052 1,500,585 976,906 673,069
Total Proved Plus Probable $ 9,497,278 $ 6,057,470 $ 4,309,779 $ 3,290,315 $ 2,635,421

The net present values noted in the table above do not include any value for future net revenue which may ultimately be generated from the contingent resources discussed later in this press release.

Sproule December 31, 2013 Forecast Prices

The following table summarizes the forecast prices used by Sproule in preparing the estimated reserve volumes and the net present values of future net revenues at December 31, 2013.

Year WTI Cushing
US$/bbl
Edmonton Par
Price C$/bbl
Western Canada
Select C$/bbl
AECO
C-Spot C$/MMbtu
Inflation Rate %/Yr Exchange Rate $US/$Cdn
2013 act. 97.98 93.24 74.20 3.13 0.8 0.971
2014 94.65 92.64 77.81 4.00 1.5 0.940
2015 88.37 89.31 75.02 3.99 1.5 0.940
2016 84.25 89.63 75.29 4.00 1.5 0.940
2017 95.52 101.62 85.36 4.93 1.5 0.940
2018 96.96 103.14 86.64 5.01 1.5 0.940
2019 98.41 104.69 87.94 5.09 1.5 0.940
2020 99.89 106.26 89.26 5.18 1.5 0.940
2021 101.38 107.86 90.60 5.26 1.5 0.940
2022 102.91 109.47 91.96 5.35 1.5 0.940
2023 104.45 111.12 93.34 5.43 1.5 0.940
2024 106.02 112.79 94.74 5.52 1.5 0.940
Thereafter Escalation rate of 1.5%

Future Development Costs

The following table sets forth future development costs deducted in the estimation of the future net revenue attributable to the reserve categories noted below (using forecast prices and costs).

Year Proved Reserves
($000s)
Proved Plus
Probable Reserves
($000s)
2014 $ 262,175 $ 384,056
2015 362,214 528,549
2016 188,471 414,661
2017 306,304 422,621
2018 127,209 246,945
Remaining 67,831 269,952
Total (Undiscounted) $ 1,314,204 $ 2,266,786

Undeveloped Land Holdings

The following table sets forth our undeveloped land holdings as at December 31, 2013.

Undeveloped Acres
Gross Net
Canada
Alberta 591,159 512,682
British Columbia 38,239 29,629
Saskatchewan 178,918 169,934
Total Canada 808,316 712,245
United States
New Mexico 14,313 14,313
North Dakota 39,845 23,610
Wyoming 100,542 63,983
Total United States 154,700 101,906
Total Company 963,016 814,151

We estimate the value of our net undeveloped land holdings at December 31, 2013 to be approximately $282 million. This internal evaluation generally represents the estimated replacement cost of our undeveloped land. In determining replacement cost, we analyzed land sale prices paid at Provincial Crown and State land sales for the properties in the vicinity of our undeveloped land holdings, less an allowance for near-term expiries.

Contingent Resource Assessment

We commissioned Sproule to conduct an assessment of contingent resources effective December 31, 2013 on two of our oil resource plays: the Bluesky in the Peace River area of Alberta, and the Bakken/Three Forks in North Dakota. We did not request Sproule to prepare an update of the estimate of contingent resource in the Lower Cretaceous Mannville Group for the Gemini Thermal Project as no developments had occurred that would have caused a change in the estimate made effective December 31, 2012. We also commissioned McDaniel & Associates Consultants Ltd. ("McDaniel") to conduct an assessment of contingent resource effective December 31, 2013 on the Lower Cretaceous Mannville Group in northeast Alberta.

Contingent resource represents the quantity of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. The outstanding contingencies applicable to our disclosed contingent resources do not include economic contingencies. Economic contingent resources are those resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The assigned contingent resources are categorized as economically recoverable based on economics completed at year-end 2012.

For the total of these four plays, Sproule and McDaniel's estimate of contingent resource ranges from 612 million barrels of oil equivalent and bitumen in the "low estimate" (C1) to 1,181 million barrels of oil equivalent and bitumen in the "high estimate" (C3), with a "best estimate" (C2) of 798 million barrels of oil equivalent and bitumen. Contingent resources are in addition to currently booked reserves.

The best estimate contingent resource of 798 million barrels of oil equivalent and bitumen is largely unchanged from year-end 2012. The best estimate contingent resource for Bakken/Three Forks of 34 million barrels of oil equivalent represents a 26% increase over year-end 2012, and is largely attributable to reduced well spacing. Notable changes to our Bakken/Three Forks contingent resource assessment include land adjustments, transfer of reserves to contingent resource and the conversion of contingent resource to reserves during the year.

The table below summarizes the Sproule and McDaniel estimates of economic contingent resource for the four plays by geographic area. The contingent resource assessments were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101.

As of Date Economic Contingent
Resources (gross)
(1)(2)(4)(5)
(millions of barrels of oil equivalent and bitumen)(3) Low(6) Best(7) High(8)
Peace River, Alberta December 31, 2013 450 553 796
Northeast Alberta December 31, 2013 66 125 196
Gemini Thermal Project - Cold Lake, Alberta December 31, 2012 78 87 127
Bakken/Three Forks - North Dakota, USA December 31, 2013 19 34 63
Total 612 798 1,181
Notes:
(1) Contingent resource is defined in the Canadian Oil and Gas Evaluation Handbook as "those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets."
(2) Economic contingent resources are those resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The assigned contingent resources are categorized as economically recoverable based on economics completed at year-end 2012.
(3) Under NI 51-101, naturally occurring hydrocarbons with a viscosity greater than 10,000 centipoise are classed as bitumen. All of the contingent resource at Peace River and the Gemini Thermal Project that will be recovered by thermal processes has a viscosity greater than this value; therefore, this component of the contingent resource is classified as bitumen under NI 51-101.
(4) Sproule and McDaniel prepared the estimates of contingent resource shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table. The total volumes presented in the table are arithmetic sums of multiple estimates of contingent resource, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of contingent resource and appreciate the differing probabilities of recovery associated with each class as explained herein.
(5) Gross means the company's working interest share in the contingent resource before deducting royalties.
(6) Low estimate (C1) is considered to be a conservative estimate of the quantity of resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. Those resources in the low estimate have the highest degree of certainty - a 90% confidence level - that the actual quantities recovered will equal or exceed the estimate.
(7) Best estimate (C2) is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources in the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate.
(8) High estimate (C3) is considered to be an optimistic estimate of the quantity of resources that will actually be recovered. It is unlikely that the actual remaining quantities of resources recovered will equal or exceed the high estimate. Those resources in the high estimate have a lower degree of certainty - a 10% confidence level - that the actual quantities recovered will equal or exceed the estimate.

There is no certainty that it will be commercially viable to produce any portion of the contingent resource or that we will produce any portion of the volumes currently classified as contingent resource. The recovery and resource estimates provided herein are estimates. Actual contingent resource (and any volumes that may be reclassified as reserves) and future production from such contingent resource may be greater than or less than the estimates provided herein.

Additional Information

Our unaudited interim condensed consolidated financial statements for the three months ended December 31, 2013 and the audited consolidated financial statements for the year ended December 31, 2013 and the related Management's Discussion and Analysis of the operating and financial results can be accessed immediately on our website at www.baytexenergy.com and will be available shortly through SEDAR at www.sedar.com and EDGAR at www.sec.gov/edgar.shtml.

Conference Call Today
9:00 a.m. MDT (11:00 a.m. EDT)
Baytex will host a conference call today, March 13, 2014, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-8527 or toll free in North America 1-800-766-6630 and toll free international 1-800-2787-2090. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/5287 in your web browser.
An archived recording of the conference call will be available until March 20, 2014 by dialing toll free 1-800-408-3053 within North America (Toronto local dial 905-694-9451, International toll free 1-800-3366-3052) and entering reservation code 7295600. The conference call will also be archived on the Baytex website at http://www.baytexenergy.com/.

Advisory Regarding Forward-Looking Statements

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

Specifically, this press release contains forward-looking statements relating to: our business strategies, plans and objectives; our average production rate for 2014; our exploration and development capital expenditures for 2014; expected average 30-day peak production rates from cold horizontal multi-lateral wells at Peace River; our Cliffdale cyclic steam stimulation project, including our assessment of the performance of Pad 1 and the timing of commencing steam injection at Pad 2; the timing of the release of the final report and recommendations from the AER's public proceeding into concerns about odours and emissions associated with heavy oil production in the Peace River area; the timing of first oil production from our Gemini steam-assisted gravity drainage project; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy oil and West Texas Intermediate; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; our ability to mitigate our exposure to heavy oil price differentials by transporting our crude oil to market by railways; the volume of heavy oil to be transported to market on railways in the first quarter of 2014; our debt-to-FFO ratio; our liquidity and financial capacity; the sufficiency of our financial resources to fund our operations; the anticipated benefits from the acquisition of Aurora, including our beliefs that the acquisition will be an excellent fit with our business model and will provide shareholders with exposure to low-risk, repeatable, high-return projects with capital efficiencies; our expectations that the Aurora assets have infrastructure in place that support low-risk future annual production and that such assets will provide material production, long-term growth and high quality reserves with upside potential; anticipated effect of the acquisition of Aurora on us, including our funds from operations; our expectations regarding the effect of well downspacing, improving completion techniques and new development targets on the reserves potential of the Aurora assets; the timing of completion of the acquisition of Aurora; our plans to establish new revolving credit facilities and a term loan for us and a borrowing base facility for Aurora's U.S. subsidiary following closing of the Arrangement; payment of the purchase price for the acquisition of Aurora, including the use of proceeds from the subscription receipt financing and our plans to draw on the new revolving credit facilities and term loan; our plan to increase the dividend on our common shares upon completion of the acquisition of Aurora; our reserve life index; forecast prices for oil and natural gas; forecast interest and exchange rates; future development costs; and the value of our undeveloped land holdings. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. Cash dividends on our common shares are paid at the discretion of our Board of Directors and can fluctuate. In establishing the level of cash dividends, the Board of Directors considers all factors that it deems relevant, including, without limitation, the outlook for commodity prices, our operational execution, the amount of funds from operations and capital expenditures and our prevailing financial circumstances at the time.

These forward-looking statements are based on certain key assumptions regarding, among other things: the receipt of regulatory, court and shareholder approvals for the Arrangement; our ability to execute and realize on the anticipated benefits of the acquisition of Aurora; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the acquisition of Aurora may not be completed on the terms contemplated or at all; failure to realize the anticipated benefits of the acquisition of Aurora; closing of the acquisition of Aurora could be delayed or not completed if we are unable to obtain the necessary regulatory, court and shareholder approvals for the Arrangement or any other approvals required for completion or, unless waived, some other condition to closing is not satisfied; failure to put in place a borrowing base facility for Aurora's U.S. subsidiary following completion of the Arrangement; declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2012, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

The above summary of assumptions and risks related to forward-looking statements in this press release has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex's current and future operations (if the acquisition of Aurora is completed) and such information may not be appropriate for other purposes. There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

Non-GAAP Financial Measures

Funds from operations is not a measurement based on Generally Accepted Accounting Principles ("GAAP") in Canada, but is a financial term commonly used in the oil and gas industry. Funds from operations represents cash generated from operating activities adjusted for financing costs, changes in non-cash operating working capital and other operating items. Baytex's determination of funds from operations may not be comparable with the calculation of similar measures for other entities. Baytex considers funds from operations a key measure of performance as it demonstrates its ability to generate the cash flow necessary to fund future dividends to shareholders and capital investments. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.

Operating netback is not a measurement based on GAAP in Canada, but is a financial term commonly used in the oil and gas industry. Operating netback is equal to product revenue less royalties, operating expenses and transportation expenses dividend by barrels of oil equivalent sales volume for the applicable period. Baytex's determination of operating netback may not be comparable with the calculation of similar measures for other entities. Baytex believes that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.

Advisory Regarding Oil and Gas Information

The reserves information contained in this press release has been prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101"). Complete NI 51-101 reserves disclosure will be included in our Annual Information Form for the year ended December 31, 2013, which will be filed later in March 2014. Listed below are cautionary statements that are specifically required by NI 51-101:

  • Where applicable, oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
  • With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.
  • This press release contains estimates of the net present value of our future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves.

This press release contains estimates as of December 31, 2013 of the volumes of the "contingent resource" for our oil resource plays in the Bluesky in the Peace River area of Alberta, the Mannville group in northeast Alberta and the Bakken/Three Forks in North Dakota and as of December 31, 2012 for the Gemini Thermal Project in Cold Lake, Alberta. These estimates were prepared by independent qualified reserves evaluators.

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

The primary contingencies which currently prevent the classification of the contingent resource as reserves consist of: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; stakeholder and regulatory approvals; access to required services and field development infrastructure; oil prices; future drilling program and testing results; further reservoir delineation and studies; facility design work; limitations to development based on adverse topography or other surface restrictions; and the uncertainty regarding marketing and transportation of petroleum from development areas.

There is no certainty that it will be commercially viable to produce any portion of the contingent resource or that we will produce any portion of the volumes currently classified as contingent resource. The estimates of contingent resource involve implied assessment, based on certain estimates and assumptions, that the resource described exists in the quantities predicted or estimated and that the resource can be profitably produced in the future. The net present value of the future net revenue from the contingent resource does not necessarily represent the fair market value of the contingent resource.

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

References herein to average 30-day peak production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating aggregate production for us or the acquired assets. A pressure transient analysis or well-test interpretation has not been carried out in respect of all wells. Accordingly, we caution that the test results should be considered to be preliminary.

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

Notice to United States Readers

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

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

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

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

Baytex Energy Corp.

Baytex Energy Corp. is a dividend-paying oil and gas corporation based in Calgary, Alberta. The company is engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin and in the Williston Basin in the United States. Approximately 88% of Baytex's production is weighted toward crude oil. Baytex pays a monthly dividend on its common shares which are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The subscription receipts issued by Baytex to fund a portion of the purchase price for Aurora Oil & Gas Limited trade on the Toronto Stock Exchange under the symbol BTE.R.

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