Baytex Announces Fourth Quarter and Full Year 2019 Financial and Operating Results and Board Appointment
March 4, 20208:30 AM Globe Newswire
CALGARY, Alberta – Baytex Energy Corp. (“Baytex”)(TSX, NYSE: BTE) reports its operating and financial results for the three months and year ended December 31, 2019 (all amounts are in Canadian dollars unless otherwise noted).“2019 was an exceptional year with $1 billion EBITDA, $329 million of free cash flow and a 17% reduction in net debt. During the first quarter of 2020, we enhanced our long-term note maturity schedule and extended the term of our revolving credit facilities to 2024. Our operations continue to perform well with strong capital efficiencies in each of our core properties (Eagle Ford, Viking and Heavy Oil). Together, these measures give us confidence and significant flexibility to execute our business plan to continue driving free cash flow and strengthening our balance sheet,” commented Ed LaFehr, President and Chief Executive Officer.2019 HighlightsWe released preliminary unaudited financial and operating results on January 20, 2020 in conjunction with the release of our 2019 reserves. Our audited financial and operating results for the three months and year ended December 31, 2019 are unchanged from the preliminary 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 2019.Generated EBITDA of $256 million in Q4/2019 and $1.01 billion for 2019.Reduced net debt by $100 million in Q4/2019 and by $393 million in 2019 with free cash flow along with a strengthening of the Canadian dollar relative to the U.S. dollar. Net debt totaled $1.87 billion at December 31, 2019.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.Bond Refinancing and Bank Credit ExtensionOn February 6, 2020, we issued US$500 million principal amount of 8.75% senior unsecured notes due April 1, 2027. Net proceeds have been used to redeem US$400 million principal amount of 5.125% senior unsecured notes due 2021. We also called for redemption $300 million principal amount of 6.625% senior unsecured notes due 2022 on March 6, 2020.On March 3, 2020, we extended the maturity of our revolving credit facilities and term loan to April 2, 2024 (from June 4, 2021). The credit facilities total approximately $1,046 million and do not require annual or semi-annual reviews.2020 OutlookOur 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. Our exploration and development program is expected to be fully funded from adjusted funds flow at the forward strip(1) and we have the operational flexibility to adjust our spending plans based on changes in commodity prices. For 2020, we have entered into hedges on approximately 48% of our net crude oil exposure, largely utilizing a 3-way option structure that provides WTI price protection at US$58.04/bbl.(1) 2020 full-year pricing assumptions: WTI – US$48.64/bbl; LLS – US$51.39/bbl; WCS differential – US$16.15/bbl; MSW differential – US$5.51/bbl, NYMEX Gas – US$1.97/mcf; AECO Gas – $1.79/mcf and Exchange Rate (CAD/USD) – 1.336.Three Months EndedYears EndedDecember 31, 2019September 30, 2019December 31, 2018December 31, 2019December 31, 2018FINANCIAL (thousands of Canadian dollars, except per common share amounts)Petroleum and natural gas sales$445,895$424,600$358,437$1,805,919$1,428,870Adjusted funds flow (1)232,147213,379110,828902,426472,983Per share – basic0.420.380.201.621.35Per share – diluted0.420.380.201.621.35Net income (loss)(117,772)15,151(231,238)(12,459)(325,309)Per share – basic(0.21)0.03(0.42)(0.02)(0.93)Per share – diluted(0.21)0.03(0.42)(0.02)(0.93)Capital ExpendituresExploration and development expenditures (1)$153,117 $139,085$184,162$552,291$495,721Acquisitions, net of divestitures563 (30)2292,1801,603,850Total oil and natural gas capital expenditures$153,680 $139,055$184,391$554,471$2,099,571Net DebtBank loan (2)$506,471 $570,792$522,294$506,471$522,294Long-term notes (2)1,337,2001,359,4801,596,3231,337,2001,596,323Long-term debt1,843,6711,930,2722,118,6171,843,6712,118,617Working capital deficiency28,12041,067146,55028,120146,550Net debt (1)$1,871,791 $1,971,339$2,265,167$1,871,791$2,265,167Shares Outstanding – basic (thousands)Weighted average558,228557,888554,036557,048351,542End of period558,305557,972554,060558,305554,060BENCHMARK PRICES Crude oil WTI (US$/bbl)$56.96$56.45$58.81$57.03$64.77LLS (US$/bbl)60.7361.8866.6462.8470.09LLS differential to WTI (US$/bbl)3.775.437.835.815.32Edmonton par ($/bbl)68.1068.4142.6869.2269.31Edmonton par differential to WTI (US$/bbl)(5.37)(4.66)(26.51)(4.86)(11.30)WCS heavy oil ($/bbl)54.2958.3925.6258.7549.85WCS differential to WTI (US$/bbl)(15.83)(12.24)(39.42)(12.75)(26.31)Natural gas NYMEX (US$/mmbtu)$2.50$2.23$3.64$2.63$3.09AECO ($/mcf)2.341.04 1.941.621.54 CAD/USD average exchange rate1.3201 1.3207 1.32151.32691.2962Three Months EndedYears EndedDecember 31, 2019September 30, 2019December 31, 2018December 31, 2019December 31, 2018OPERATINGDaily ProductionLight oil and condensate (bbl/d)43,90642,82944,98743,58729,264Heavy oil (bbl/d)27,05025,71226,33926,74125,954NGL (bbl/d)8,6999,54310,32710,2299,745Total liquids (bbl/d)79,65578,08481,65380,55764,963Natural gas (mcf/d)100,235101,054103,424102,74292,971Oil equivalent (boe/d @ 6:1) (3)96,36094,92798,89097,68080,458Netback (thousands of Canadian dollars)Total sales, net of blending and other expense (4)$427,728 $411,650$344,682$1,737,124$1,360,038Royalties(77,282)(75,017)(79,765)(320,241)(313,754)Operating expense(99,573)(97,377)(97,857)(397,716)(311,592)Transportation expense(8,840)(9,903)(10,994)(43,942)(36,869)Operating netback (1)$242,033$229,353$156,066$975,225$697,823General and administrative(9,893)(9,934)(14,096)(45,469)(45,825)Cash financing and interest(24,389)(26,752)(27,933)(107,417)(104,318)Realized financial derivatives gain (loss)22,95620,857(3,063)75,620(73,165)Other (5)1,440 (145)(146)4,467(1,532)Adjusted funds flow (1)$232,147$213,379$110,828$902,426$472,983Netback (per boe)Total sales, net of blending and other expense (4)$48.25$47.14$37.89$48.72$46.31Royalties(8.72)(8.59)(8.77)(8.98)(10.68)Operating expense(11.23)(11.15)(10.76)(11.16)(10.61)Transportation expense(1.00)(1.13)(1.21)(1.23)(1.26)Operating netback (1)$27.30$26.27$17.15$27.35$23.76General and administrative(1.12)(1.14)(1.55)(1.28)(1.56)Cash financing and interest(2.75)(3.06)(3.07)(3.01)(3.55)Realized financial derivatives gain (loss)2.592.39(0.34)2.12(2.49)Other (5)0.16 (0.03)(0.02)0.13(0.05)Adjusted funds flow (1)$26.18$24.43$12.17$25.31$16.11Notes: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. See the advisory on non-GAAP measures at the end of this press release.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 capital or repayment obligations.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.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.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 2019 MD&A for further information on these amounts.Operating ResultsOur 2019 operating and financial results demonstrate the benefits of our diversified oil weighted portfolio and our commitment to allocate capital effectively, generate free cash flow and further strengthen our balance sheet.Our production exceeded the high end of our annual guidance with outstanding capital efficiencies in our development program and each of our core properties (Eagle Ford, Viking and Heavy Oil) generated an operating netback in excess of exploration and development expenditures. 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.Production during the fourth quarter averaged 96,360 boe/d (83% oil and NGL), as compared to 94,927 boe/d (82% oil and NGL) in Q3/2019. Production in 2019 averaged 97,680 boe/d as compared to 80,458 boe/d in 2018. Exploration and development expenditures totaled $153 million in Q4/2019 and $552 million for full-year 2019. We participated in the completion of 417 (313.9 net) wells with a 99% success rate during the year.The following table compares our 2019 results to our 2019 original budget guidance.2019 Original Guidance (1)2019 ResultsExploration and development expenditures$550 – $650 million$552.3 millionProduction (boe/d)93,000 – 97,00097,680Expenses: Royalty rate20.0%18.4% Operating$10.75 – $11.25/boe$11.16/boe Transportation$1.25 – $1.35/boe$1.23/boe General and administrative~ $46 million ($1.30/boe)$45.5 million ($1.28/boe) Interest~ $112 million ($3.23/boe)$107.4 million ($3.01/boe)Leasing expenditures$5 million$6 millionAsset retirement obligations$17 million$15 millionNote:As announced on December 17, 2018. Includes updated guidance on May 2, 2019 for general and administrative expenses and leasing expenditures to reflect a change associated with the adoption of IFRS 16.Eagle Ford and Viking Light OilProduction in the Eagle Ford averaged 38,567 boe/d (78% oil and NGL) during Q4/2019, as compared to 36,793 boe/d in Q3/2019. Production for 2019 averaged 39,055 boe/d, as compared to 37,076 boe/d in 2018. In 2019, we invested $178 million on exploration and development in the Eagle Ford and generated an operating netback of $416 million.In the Eagle Ford, we continued to see strong well performance driven by enhanced completions across our acreage position. In 2019, we participated in the drilling of 96 (20.2 net) wells and commenced production from 109 (25.1 net) wells. The wells brought on-stream during 2019 generated an average 30-day initial production rate of approximately 1,900 boe/d per well, which represents an approximate 8% improvement over wells brought on-stream in 2018.Production in the Viking averaged 22,050 boe/d (91% oil and NGL) during Q4/2019, as compared to 22,198 boe/d in Q3/2019. Production for the full-year 2019 averaged 22,546 boe/d. In 2019, we invested $266 million on exploration and development in the Viking and generated an operating netback of $349 million.In the Viking, we maintained an active pace of development in 2019, drilling 275 (243.6 net) wells and commencing production from 271 (239.7 net) wells. In 2019, over 90% of our drilling program was extended reach horizontal wells. We also added 229 net high quality drilling opportunities through multiple deals and asset swaps.Heavy OilOur heavy oil assets at Peace River and Lloydminster produced a combined 29,707 boe/d (91% oil and NGL) during the fourth quarter, as compared to 28,483 boe/d in Q3/2019. We drilled 40 (40.0 net) heavy oil wells in 2019, including 34 net wells at Lloydminster and six net wells at Peace River. In 2019, we invested $80 million on exploration and development on our heavy oil assets and generated an operating netback of $188 million.East Duvernay Shale Light OilWe continue to advance the delineation of the East Duvernay Shale, an early stage, high operating netback light oil resource play. As of December 31, 2019, we have drilled seven wells at Pembina, confirming the prospectivity of our acreage. Two wells brought on-stream in 2019 generated an average 30-day initial production rate of approximately 1,050 boe/d per well (75% oil and NGL) and are in the top 15% of all wells drilled to date in the play.In Q1/2020, we drilled two wells at Pembina and completion activities are scheduled for Q2/2020. The success of our drilling program in the Pembina area has significantly de-risked our approximately 38 kilometer long acreage fairway, where we hold 275 sections (100% working interest) of Duvernay land.Financial ReviewWe delivered adjusted funds flow of $232 million ($0.42 per basic share) in Q4/2019 and $902 million ($1.62 per basic share) in 2019. This resulted in free cash flow of $73 million in Q4/2019 and $329 million in 2019. This strong free cash flow, along with the Canadian dollar strengthening relative to the U.S. dollar, contributed to a 17% reduction in our net debt this year.We recorded a net loss of $118 million ($0.21 per basic share) in Q4/2019 and $12 million ($0.02 per basic share) in 2019. The net loss is attributable to a non-cash impairment charge of $188 million on our heavy oil assets and reflects lower heavy oil prices and a change in development plan for our thermal projects at Peace River.We realized an operating netback of $27.30/boe in Q4/2019, as compared to $26.27/boe in Q3/2019 and $17.15/boe in Q4/2018. Including financial derivatives, our operating netback improved to $29.89/boe, as compared to $16.81/boe in Q4/2018. Our Canadian operations generated an operating netback of $24.72/boe during Q4/2019 while our Eagle Ford asset generated an operating netback of $31.17/boe.The following table summarizes our operating netbacks for the periods noted.Three Months Ended December 3120192018($ per boe except for production)CanadaU.S.TotalCanadaU.S.TotalProduction (boe/d)57,79438,56696,36060,45338,43798,890Total sales, net of blending and other (1)$45.52$52.33$48.25$24.04$59.66$37,89Royalties(4.73)(14.69)(8.72)(3.10)(17.68)(8.77)Operating expense(14.41)(6.47)(11.23)(13.42)(6.56)(10.76)Transportation expense(1.66)—(1.00)(1.98)—(1.21)Operating netback (2)$24.72$31.17$27.30$5.54$35.42$17.15Realized financial derivatives gain (loss)——2.59——(0.34)Operating netback after financial derivatives$24.72$31.17$29.89$5.54$35.42$16.81Notes: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.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. See the advisory on non-GAAP measures at the end of this press release.Balance Sheet and LiquidityIn 2019, we set a priority to further deleverage and strengthen our balance sheet. We delivered on this commitment as highlighted by the following key milestones:We generated free cash flow of $73 million in Q4/2019 and $329 million in 2019.We reduced net debt by $100 million in Q4/2019 and by $393 million in 2019 due to the strong free cash flow and a strengthening of the Canadian dollar relative to the U.S. dollar.We completed the early redemption of US$150 million principal amount of 6.75% senior unsecured notes due February 17, 2021 at par on September 13, 2019.Subsequent to year-end, we further improved our financial position:We enhanced our long-term note maturity schedule which provides us significant flexibility and liquidity to execute our business plan.On February 5, 2020, we issued US$500 million principal amount of 8.75% senior unsecured notes, which mature on April 1, 2027. These notes are redeemable at our option, in whole or in part, at specified redemption prices after April 1, 2023.On February 20, 2020, we redeemed US$400 million principal amount of 5.125% senior unsecured notes due June 1, 2021 at par.We issued a redemption notice for $300 million principal amount of 6.625% senior unsecured notes due July 19, 2022 for redemption on March 6, 2020 at 101.104% of the principal amount.Following these redemptions, our next long-term note maturity will be June 2024.We amended our credit facilities to extend the maturities of our revolving facilities and term loan to April 2, 2024. The credit facilities are not borrowing base facilities and do not require annual or semi-annual reviews. Our facilities total approximately $1,046 million and include US$575 million of revolving credit facilities and a $300 million term loan.Our net debt, which includes our bank loan, long-term notes and working capital, totaled $1,872 million at December 31, 2019, down 17% from $2,265 million at December 31, 2018. Following the US$500 million note issue and the redemption of the US$400 million and $300 million notes, our credit facilities are approximately one-third undrawn, we retain over $300 million of liquidity and the weighted average interest rate on our long-term debt is approximately 6%.Risk ManagementTo manage commodity price movements we utilize various financial derivative contracts and crude-by-rail to reduce the volatility in our adjusted funds flow. We realized a financial derivatives gain of $76 million in 2019, as compared to a loss of $73 million in 2018.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:WTIBaytex Receives (1)At or below US$50.44/bblWTI + US$7.60/bblBetween US$50.44/bbl and US$58.04/bblUS$58.04/bblBetween US$58.04/bbl and US$63.06/bblWTIAbove US$63.06/bblUS$63.06/bblNote:The price Baytex receives 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. We also have WTI-MSW basis differential swaps for 4,250 bbl/d of our light oil production in Canada at US$6.19/bbl.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 11,500 bbl/d of our heavy oil volumes to market by rail. In addition, we have WCS differential hedges on 5,500 bbl/d at a WTI-WCS differential of US$16.25/bbl.A complete listing of our financial derivative contracts can be found in Note 20 to our 2019 financial statements.2020 OutlookWe 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 annual 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. For Q1/2020, production is trending above 97,000 boe/d with exploration and development expenditures of approximately $200 million, consistent with our plan and capital guidance range.Our exploration and development program is expected to be fully funded from adjusted funds flow at the forward strip(1) and we have the operational flexibility to adjust our spending plans based on changes in commodity prices.(1) 2020 full-year pricing assumptions: WTI – US$48.64/bbl; LLS – US$51.39/bbl; WCS differential – US$16.15/bbl; MSW differential – US$5.51/bbl, NYMEX Gas – US$1.97/mcf; AECO Gas – $1.79/mcf and Exchange Rate (CAD/USD) – 1.336.The following table summarizes our 2020 annual guidance.Exploration and development expenditures$500 – $575 millionProduction (boe/d)93,000 to 97,000Expenses:Royalty rate18.0% – 18.5%Operating$11.25 – $12.00/boeTransportation$1.20 – $1.30/boeGeneral and administrative$45 million ($1.30/boe)Interest$112 million ($3.23/boe)Leasing expenditures$7 millionAsset retirement obligations$19 millionBoard AppointmentThe Board of Directors is pleased to announce the appointment of Don Hrap as a director of Baytex.“We are very pleased that Don has joined the Baytex board. His business knowledge, strategic perspective and tremendous breadth of experience across U.S. and Canadian energy will serve the board and Baytex well in the years ahead,” commented Mark Bly, Chairman of Baytex.Mr. Hrap has spent 35 years in the upstream oil and gas business, primarily holding executive positions in North America. From 2009-2018, he served as President, Lower 48 at ConocoPhillips with strong breadth and depth of experience across several U.S. oil resource plays. Prior to this at ConocoPhillips, Mr. Hrap was senior vice president of Western Canada Gas. He joined ConocoPhillips in 2006 through the merger with Burlington Resources, serving as senior vice president of operations for Burlington Canada. Earlier, he was vice president for the North American Division at Gulf Canada Resources, where he worked for 17 years. Mr. Hrap previously served as chairman of the API Upstream Committee, a Board member of the Independent Petroleum Association of America (IPAA) and a member of the U.S. Oil & Gas Association. He is also a Director of Tall City III Exploration LLC and WildFire Energy I LLC, and also serves as an Industry Advisor to Warburg Pincus. Mr. Hrap graduated from the University of Manitoba with a Bachelor of Science in Mechanical Engineering in 1982. In 1995, he graduated from the University of Calgary with a Master in Business Administration.Baytex has an ongoing board renewal process led by its Nominating and Governance Committee. In the last year, we have significantly restructured our board. Throughout this renewal process, our intent has been to create an efficient board with complementary skill sets suited to our business, ensure independence and increase diversity.Conference Call Today 9:00 a.m. MST (11:00 a.m. EST)Baytex will host a conference call today, March 4, 2020, starting at 9:00am MST (11:00am EST). To participate, please dial toll free in North America 1-800-319-4610 or international 1-416-915-3239. Alternatively, to listen to the conference call online, please enter http://services.choruscall.ca/links/baytexq4ye20200304.html in your web browser.An archived recording of the conference call will be available shortly after the event by accessing the webcast link above. The conference call will also be archived on the Baytex website at www.baytexenergy.com.Additional InformationOur audited consolidated financial statements for the year ended December 31, 2019 and the related Management’s Discussion and Analysis of the operating and financial results can be accessed 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.