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Baytex Announces 2019 Year End Reserves and Preliminary Financial and Operating Results


CALGARY – Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) announces its year-end 2019 reserves and 2019 fourth quarter and year-end preliminary unaudited financial and operating results (all amounts are in Canadian dollars unless otherwise noted).

“Our production in 2019 exceeded the high end of our annual guidance with outstanding capital efficiencies in our development program. As a result, we generated $329 million of free cash flow and a 17% reduction in net debt. Each of our core properties (Eagle Ford, Viking and Heavy Oil) contributed substantial asset level free cash flow. We also achieved a strong year of reserves development with proved developed producing reserves increasing 5% with finding & development costs of $13.04/boe and a recycle ratio of 2.3x. We are building on this momentum in 2020 as we continue to maximize free cash flow and further strengthen our balance sheet,” commented Ed LaFehr, President and Chief Executive Officer.

Preliminary Financial and Operating Highlights

We will release our 2019 fourth quarter and year-end audited financial and operating results on March 4, 2020. In conjunction with the release of our 2019 reserves, we are providing preliminary unaudited financial and operating results.

  • Generated production of 96,360 boe/d (83% oil and NGL) during Q4/2019 and 97,680 boe/d for full-year 2019, exceeding the high end of guidance.
  • Exploration and development expenditures totaled $153 million in Q4/2019, bringing aggregate spending for 2019 to $552 million, which is at the low end of our original guidance.
  • Delivered adjusted funds flow of $232 million ($0.42 per basic share) in Q4/2019 and $902 million ($1.62 per basic share) for the full-year 2019.
  • Generated EBITDA of $256 million in Q4/2019 and $1.01 billion for the full-year 2019.
  • Reduced net debt by $100 million in Q4/2019 and by $394 million in 2019 as adjusted funds flow exceeded capital expenditures and the Canadian dollar strengthened relative to the U.S. dollar. Net debt totaled $1.87 billion at December 31, 2019.
  • Maintained strong financial liquidity with our credit facilities approximately 50% undrawn and $524 million of liquidity at year-end 2019.
  • Realized an operating netback (inclusive of hedging) of $29.89/boe in Q4/2019 and $29.47/boe for the full-year 2019.

Reserves Highlights

  • Proved developed producing (“PDP”) reserves increased by 5%, from 135 mmboe to 142 mmboe while proved reserves (“1P”) and proved plus probable reserves (“2P”) are largely unchanged at 314 mmboe (315 mmboe at year-end 2018) and 529 mmboe (527 mmboe at year-end 2018), respectively.
  • Replaced 112% of 2019 production, adding 40 mmboe of 2P reserves through development activities.
  • Finding and development (“F&D”) costs, including changes in future development costs (“FDC”), were $13.04/boe for PDP reserves, $12.92/boe for 1P reserves and $16.30/boe for 2P reserves.
  • Generated a PDP and 1P recycle ratio of 2.3x and a 2P recycle ratio of 1.8x based on 2019 operating netback of $29.47/boe.
  • Reserves on a 1P basis are comprised of 82% oil and NGL (37% light oil, 25% NGL’s, 16% heavy oil and 4% bitumen) and 18% natural gas.
  • PDP reserves represent 45% of 1P reserves (43% at year-end 2018) and 1P reserves represent 59% of 2P reserves (60% at year-end 2018).
  • Baytex maintains a strong reserves life index of 8.9 years based on 1P reserves and 15.1 years based on 2P reserves.
  • Our net asset value at year-end 2019, discounted at 10%, is estimated to be $6.97 per share. This is based on the estimated reserves value plus a value for undeveloped acreage, net of long-term debt and working capital.

2019 Preliminary Financial and Operating Results

The following are our certain preliminary unaudited results for the year ended December 31, 2019.


Preliminary Operating Results
Fourth Quarter 2019 Year Ended
December 31, 2019
Daily Production
  Light oil and condensate (bbl/d) 43,906 43,587
  Heavy oil (bbl/d) 27,050 26,741
  NGL (bbl/d) 8,699 10,229
  Total liquids (bbl/d) 79,655 80,557
  Natural gas (mcf/d) 100,235 102,742
Oil equivalent (boe/d @ 6:1) (1) 96,360 97,680

 

Fourth Quarter 2019 Year Ended December 31, 2019
Preliminary Financial Results (2) $ millions
$/boe
$ millions
$/boe
  Total sales, net of blending and other expenses (3) $428 $48.25 $1,737 $48.72
  Royalties (77 ) (8.72 ) (320 ) (8.98 )
  Operating expense (100 ) (11.23 ) (398 ) (11.16 )
  Transportation expense (9 ) (1.00 ) (44 ) (1.23 )
Operating netback (4) $242 $27.30 $975 $27.35
  General and administrative (10 ) (1.12 ) (45 ) (1.28 )
  Cash financing and interest (24 ) (2.75 ) (107 ) (3.01 )
  Realized financial derivatives gain (loss) 23 2.59 76 2.12
  Other (5) 1 0.16 4 0.13
Adjusted funds flow (4) $232 $26.19 $902 $25.31
  Exploration and development expenditures (4) (153 ) (17.27 ) (552 ) (15.49 )
  Asset retirement obligations (5 ) (0.51 ) (15 ) (0.43 )
  Leasing expenditures (2 ) (0.18 ) (6 ) (0.17 )
Free cash flow (4) $73 $8.22 $329 $9.22

Notes:

  1. 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.
  2. Data in the table may not add due to rounding.
  3. 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.
  4. The terms “adjusted funds flow”, “operating netback”, “exploration and development expenditures” and “free cash flow” 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. See the advisory on non-GAAP measures at the end of this press release.
  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.

Risk Management

To manage commodity price movements we utilize various financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow.  For 2020, we have entered into hedges on approximately 48% of our net crude oil exposure, largely utilizing a 3-way option structure on 24,500 bbl/d that provides WTI price protection at US$58.04/bbl with upside participation to US$63.06/bbl. The 3-way contracts are structured as follows:

WTI Baytex Receives (1)
At or below US$50.44/bbl WTI + US$7.60/bbl
Between US$50.44/bbl and US$58.04/bbl US$58.04/bbl
Between US$58.04/bbl and US$63.06/bbl WTI
Above US$63.06/bbl US$63.06/bbl

Note:

  1. The price Baytex receives as illustrated in the table represents an average of all contracts entered into.

In addition to the 3-way options, we have WTI-based fixed price swaps on 3,500 bbl/d at US$57.40/bbl for 2020.

Crude-by-rail is an integral part of our egress and marketing strategy for our heavy oil production. For 2020, we are contracted to deliver approximately 11,000 bbl/d of our heavy oil volumes to market by rail. In addition, we have entered into WCS differential hedges on 2,500 bbl/d at a WTI-WCS differential of US$16.10/bbl.

2020 Outlook

Our 2020 guidance remains unchanged as we target production of 93,000 to 97,000 boe/d with exploration and development expenditures of $500 to $575 million.

We have a high quality and diversified oil portfolio with a strong drilling inventory of approximately 10 or more years in each of our core areas (Viking, Eagle Ford and Heavy Oil). Our commitment remains to deliver stable production, generate free cash flow and further strengthen our balance sheet. Our 2020 capital expenditures program is expected to be fully funded from adjusted funds flow at a WTI price of US$50/bbl. Adjusted funds flow in excess of capital expenditures, lease payments and asset retirement obligations will be allocated to debt repayment.

Year-end 2019 Reserves

Baytex’s year-end 2019 proved and probable reserves were evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”), an independent qualified reserves evaluator. All of our oil and gas properties were evaluated 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”) using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants (“GLJ”) and Sproule Associates Limited (“Sproule”) as of January 1, 2020. 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, 2019, which will be filed on or before March 30, 2020.

The following table sets forth our gross and net reserves volumes at December 31, 2019 by product type and reserves category. Please note that the data in the table may not add due to rounding.

Reserves Summary

Light and
Medium Oil
Tight Oil Heavy Oil Bitumen Total Oil Natural Gas
Liquids (3)
Conventional
Natural Gas (4)
Shale Gas Total (5)
Reserves Summary (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mmcf) (mmcf) (mboe)
Gross (1)
  Proved producing 27,297 23,273 28,050 2,711 81,331 34,218 56,743 99,628 141,611
  Proved developed non-producing 39 570 7,196 7,805 388 2,492 1,018 8,778
  Proved undeveloped 33,322 32,250 22,691 1,892 90,155 43,333 45,272 133,516 163,286
  Total proved 60,619 55,562 51,311 11,799 179,291 77,939 104,506 234,162 313,674
  Total probable 31,218 24,139 37,805 53,743 146,905 35,654 99,816 99,739 215,818
Proved plus probable 91,837 79,701 89,116 65,542 326,196 113,592 204,323 333,901 529,492
Net (2)
  Proved producing 25,447 17,245 24,818 2,504 70,015 25,470 53,003 74,009 116,654
  Proved developed non-producing 29 483 6,766 7,278 287 2,022 757 8,029
  Proved undeveloped 31,052 24,029 20,371 1,873 77,325 32,206 40,444 99,106 132,789
  Total proved 56,499 41,303 45,672 11,144 154,618 57,963 95,469 173,872 257,471
  Total probable 28,703 18,214 32,813 43,031 122,761 26,797 90,061 74,952 177,060
Proved plus probable 85,201 59,517 78,486 54,175 277,379 84,760 185,530 248,823 434,531

Notes:

  1. “Gross” reserves means the total working 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 plus royalty interest reserves.
  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. Please note that the data in the table may not add due to rounding.

Proved Reserves – Gross Volumes (1) (Forecast Prices)

Light and
Medium Oil
Tight Oil Heavy Oil Bitumen Total Oil Natural
Gas
Liquids (4)
Conventional
Natural Gas (5)
Shale Gas Total (6)
  (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mmcf) (mmcf) (mboe)
December 31, 2018 71,545 52,819 49,613 12,805 186,783 74,614 168,104 151,156 314,607
Product Type Transfer (2) (57,548 ) 57,548
Extensions 7,328 7,510 4,845 19,683 8,260 6,225 26,200 33,347
Technical Revisions (3) (9,133 ) 1,865 9,012 (341 ) 1,403 2,109 8,463 21,868 8,567
Acquisitions 1,264 18 1,282 2 227 1,322
Dispositions (2,347 ) (2,347 ) (90 ) (2,362 )
Economic Factors (217 ) (1,232 ) (3,201 ) 118 (4,531 ) (625 ) (3,590 ) (2,393 ) (6,153 )
Production (7,822 ) (5,401 ) (8,977 ) (784 ) (22,983 ) (6,421 ) (17,285 ) (20,216 ) (35,653 )
December 31, 2019 60,619 55,562 51,311 11,799 179,291 77,939 104,506 234,162 313,674

Probable Reserves – Gross Volumes (1) (Forecast Prices)

Light and
Medium Oil
Tight Oil Heavy Oil Bitumen Total Oil Natural
Gas
Liquids (4)
Conventional
Natural Gas (5)
Shale Gas Total (6)
  (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mmcf) (mmcf) (mboe)
December 31, 2018 20,941 21,879 42,687 55,545 141,052 38,473 122,685 71,550 211,898
Product Type Transfer (2) (24,653 ) 24,653
Extensions 8,761 2,877 (363 ) 11,275 63 (473 ) 2,504 11,676
Technical Revisions (3) 1,696 768 (4,317 ) (1,887 ) (3,740 ) (1,590 ) 2,822 5,923 (3,873 )
Acquisitions 416 5 420 1 82 435
Dispositions (579 ) (579 ) (27 ) (583 )
Economic Factors (17 ) (1,385 ) (207 ) 85 (1,524 ) (1,293 ) (619 ) (4,890 ) (3,735 )
Production
December 31, 2019 31,218 24,139 37,805 53,743 146,905 35,654 99,816 99,739 215,818

Proved Plus Probable Reserves – Gross Volumes (1) (Forecast Prices)

Light and
Medium Oil
Tight Oil Heavy Oil Bitumen Total Oil Natural
Gas
Liquids (4)
Conventional
Natural Gas (5)
Shale Gas Total (6)
  (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mbbls) (mmcf) (mmcf) (mboe)
December 31, 2018 92,487 74,698 92,301 68,350 327,836 113,087 290,789 222,706 526,505
Product Type Transfer (2) (82,200 ) 82,200
Extensions 16,089 10,387 4,482 30,958 8,323 5,752 28,703 45,023
Technical Revisions (3) (7,437 ) 2,634 4,695 (2,228 ) (2,337 ) 518 11,285 27,790 4,695
Acquisitions 1,680 23 1,702 3 309 1,757
Dispositions (2,926 ) (2,926 ) (118 ) (2,945 )
Economic Factors (234 ) (2,616 ) (3,408 ) 204 (6,054 ) (1,919 ) (4,209 ) (7,283 ) (9,888 )
Production (7,822 ) (5,401 ) (8,977 ) (784 ) (22,983 ) (6,421 ) (17,285 ) (20,216 ) (35,653 )
December 31, 2019 91,837 79,701 89,116 65,542 326,196 113,592 204,323 333,901 529,492

Notes:

  1. “Gross” reserves means the total working interest share of remaining recoverable reserves owned by Baytex before deductions of royalties payable to others.
  2. Product type transfer reflects the reclassification of solution gas in the Eagle Ford from conventional natural gas to shale gas.
  3. Positive technical revisions for heavy oil are largely the results of positive production performance versus previous forecasts in both our Lloydminster and Peace River areas. Positive conventional natural gas revisions are predominately related to the solution gas associated with our heavy oil assets. Positive technical revisions in the tight oil and shale gas are a result of enhanced type well profiles in our Eagle Ford acreage. Negative technical revisions in the light and medium oil are associated with our Viking area and are predominately a result of a reduction in later life reserves associated with the production profile.
  4. Natural gas liquids include condensate.
  5. Conventional natural gas includes associated, non-associated and solution gas.
  6. 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.

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 ($ millions) Proved
Reserves
Proved Plus
Probable Reserves
2020 530 536
2021 522 562
2022 563 625
2023 444 611
2024 496 848
Remainder 2 1,132
Total FDC undiscounted 2,558 4,315

F&D and FD&A Costs – including future development costs

Based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, the efficiency of our capital program is summarized in the following table.

millions except for per boe amounts 2019 2018 2017 3 Year
Proved plus Probable Reserves
Finding & Development Costs
Exploration and development expenditures $552.3 $495.7 $326.3 $1,374.3
Net change in Future Development Costs $96.7 $132.3 ($76.4 ) $152.7
Gross Reserves additions (mmboe) 39.8 31.2 34.4 105.5
F&D Costs ($/boe) $16.30 $20.11 $7.26 $14.48
Finding, Development & Acquisition (“FD&A”) Costs
Exploration and development expenditures and net acquisitions $554.5 $2,099.6 $386.1 $3,040.2
Net change in Future Development Costs $79.9 $1,064.5 $84.2 $1,228.6
Gross Reserves additions (mmboe) 38.6 123.9 51.6 214.1
FD&A Costs ($/boe) $16.42 $25.55 $9.11 $19.94
Proved Reserves
Finding & Development Costs
Exploration and development expenditures $552.3 $495.7 $326.3 $1,374.3
Net change in Future Development Costs ($90.4 ) $117.4 ($132.6 ) ($105.6 )
Gross Reserves additions (mmboe) 35.8 17.5 21.7 74.9
F&D Costs ($/boe) $12.92 $35.05 $8.93 $16.93
Finding, Development & Acquisition Costs
Exploration and development expenditures and net acquisitions $554.5 $2,099.6 $386.1 $3,040.2
Net change in Future Development Costs ($107.2 ) $987.4 ($97.1 ) $783.1
Gross Reserves additions (mmboe) 34.7 88.4 28.5 151.7
FD&A Costs ($/boe) $12.88 $34.91 $10.13 $25.21
Proved Developed Producing Reserves
Finding & Development Costs
Exploration and development expenditures $552.3 $495.7 $326.3 $1,374.3
Gross Reserves additions (mmboe) 42.5 31.3 23.8 97.4
F&D Costs ($/boe) $13.04 $15.82 $13.73 $14.10
Finding, Development & Acquisition Costs
Exploration and development expenditures and net acquisitions $554.5 $2,099.6 $386.1 $3,040.2
Gross Reserves additions (mmboe) 42.5 63.7 27.5 133.7
FD&A Costs ($/boe) $13.04 $32.95 $14.06 $22.73

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 2019 by annualized Q4/2019 production.

  Reserves Life Index (years)
Q4/2019
Production
Proved Proved Plus Probable
Crude Oil and NGL (bbl/d) 79,655 8.8 15.1
Natural Gas (mcf/d) 100,234 9.3 14.7
Oil Equivalent (boe/d) 96,360 8.9 15.1

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, 2019. The estimated future net revenue to be derived from the production of the reserves is based on the following average of the price forecasts of McDaniel, GLJ and Sproule as of January 1, 2020.

Year  WTI Crude Oil
US$/bbl
Edmonton Light
Crude Oil
 $/bbl
Western
Canadian Select

$/bbl
Henry Hub
US$/MMbtu
AECO Spot
$/MMbtu
Inflation Rate
%/Yr
Exchange Rate
$US/$Cdn
2019 act. 56.95 68.65 58.10 2.55 1.60 2.0 0.750
2020 61.00 72.64 57.57 2.62 2.04 0.0 0.760
2021 63.75 76.06 62.35 2.87 2.32 1.7 0.770
2022 66.18 78.35 64.33 3.06 2.62 2.0 0.785
2023 67.91 80.71 66.23 3.17 2.71 2.0 0.785
2024 69.48 82.64 67.97 3.24 2.81 2.0 0.785
2025 71.07 84.60 69.72 3.32 2.89 2.0 0.785
2026 72.68 86.57 71.49 3.39 2.96 2.0 0.785
2027 74.24 88.49 73.20 3.45 3.03 2.0 0.785
2028 75.73 90.31 74.80 3.53 3.09 2.0 0.785
2029 77.24 92.17 76.43 3.60 3.16 2.0 0.785
Thereafter Escalation rate of 2.0% 2.0 0.785

Net Present Value of Reserves (1) (Forecast Prices and Costs)

The following table summarizes the McDaniel estimate of the net present value before income taxes of the future net revenue attributable to our reserves.

Reserves at December 31, 2019 ($ millions, discounted at) 0% 5% 10% 15%
Proved developed producing 2,640 2,501 2,211 1,965
Proved developed non-producing 179 118 81 57
Proved undeveloped 3,256 2,096 1,419 991
Total proved 6,075 4,714 3,710 3,013
Probable 5,627 3,029 1,890 1,298
Total Proved Plus Probable (before tax) 11,702 7,743 5,600 4,310

Note:

  1. Includes abandonment, decommissioning and reclamation costs for all producing and nonproducing wells and facilities.

Net Asset Value (Forecast Prices and Costs)

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 McDaniel at year-end, plus the estimated value of our undeveloped land holdings, less net debt. 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, 2019.

($ millions, except per share amounts, discounted at) 5% 10% 15%
Net present value of proved plus probable reserves (1) 7,743 5,600 4,310
Undeveloped land holdings (2) 162 162 162
Net Debt (1,871 ) (1,871 ) (1,871 )
Net Asset Value 6,034 3,891 2,601
Net Asset Value per Share (3) 10.81 6.97 4.66

Notes:

  1. Includes abandonment, decommissioning and reclamation costs for all producing and nonproducing wells and facilities.
  2. The value of undeveloped land holdings generally represents the estimated replacement cost of our undeveloped land.
  3. Based on 558.3 million common shares outstanding as at December 31, 2019.


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