Baytex Reports Q1 2015 Results
Baytex Energy Corp. (“Baytex”) (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three months ended March 31, 2015 (all amounts are in Canadian dollars unless otherwise noted).
“The Eagle Ford led our operating results with record production, continued advancement of the multi-zone development potential of our acreage and significant savings in our capital spending program. Corporately, we are focused on initiatives to provide strong levels of liquidity by scrutinizing capital and operating expenditures and deferring development activities in Canada. Additional strength was provided with an equity financing that closed in early April,” commented James Bowzer, President and Chief Executive Officer.
- Generated production of 90,710 boe/d (83% oil and NGL) in Q1/2015, largely unchanged from a Q4/2014 level of 92,220 boe/d, after adjusting for non-core dispositions of 1,250 boe/d which occurred late last year;
- Delivered funds from operations (“FFO”) of $160.2 million ($0.95 per share) during Q1/2015;
- Produced 41,076 boe/d in the Eagle Ford in Q1/2015, an increase of 8% from Q4/2014;
- Advanced the multi-zone development potential of our Eagle Ford acreage with 30-day initial production rates per well ranging from 1,100 to 1,500 boe/d for a four well pad that targeted four separate horizons;
- Maintained a conservative payout ratio, net of Dividend Reinvestment Plan (“DRIP”) participation, of 26% (32% before DRIP) in Q1/2015; and
- Subsequent to quarter-end, completed an equity financing, raising net proceeds of approximately $606 million which were applied to reduce outstanding indebtedness.
|Three Months Ended|
|FINANCIAL(thousands of Canadian dollars, except per common share amounts)|
|Petroleum and natural gas sales||$||285,615||$||472,390||$||385,809|
|Funds from operations (1)||160,221||245,513||170,810|
|Per share – basic||0.95||1.47||1.36|
|Per share – diluted||0.95||1.47||1.34|
|Cash dividends declared (2)||41,466||72,509||63,441|
|Dividends declared per share||0.30||0.58||0.66|
|Net income (loss)||(175,916||)||(361,816||)||47,841|
|Per share – basic||(1.04||)||(2.16||)||0.38|
|Per share – diluted||(1.04||)||(2.16||)||0.38|
|Exploration and development||147,429||214,697||172,425|
|Acquisitions, net of divestitures||1,550||(35,666||)||673|
|Total oil and natural gas capital expenditures||$||148,979||$||179,031||$||173,098|
|Working capital deficiency||162,546||210,409||65,909|
|Total monetary debt (4)||$||2,455,995||$||2,295,980||$||832,268|
|Three Months Ended|
|Heavy oil (bbl/d)||39,261||43,135||45,232|
|Light oil and condensate (bbl/d)||28,056||26,916||5,470|
|Total oil and NGL (bbl/d)||75,541||78,149||52,689|
|Natural gas (mcf/d)||91,010||84,428||40,886|
|Oil equivalent (boe/d @ 6:1) (5)||90,710||92,220||59,502|
|WTI oil (US$/bbl)||48.64||73.14||98.68|
|WCS Heavy Oil (US$/bbl)||33.91||58.90||75.55|
|Edmonton par oil ($/bbl)||51.94||75.69||100.18|
|LLS oil (US$/bbl)||50.55||77.02||104.90|
|Baytex average prices (before hedging)|
|Heavy oil ($/bbl) (6)||28.57||53.34||71.13|
|Light oil and condensate ($/bbl)||52.34||77.20||95.81|
|Total oil and NGL ($/bbl)||36.40||58.93||73.12|
|Natural gas ($/mcf)||3.22||4.12||5.22|
|Oil equivalent ($/boe)||33.54||53.72||68.33|
|CAD/USD noon rate at period end||1.2683||1.1601||1.1053|
|CAD/USD average rate for period||1.2308||1.1378||1.1035|
|COMMON SHARE INFORMATION|
|Share price (Cdn$)|
|Volume traded (thousands)||122,179||133,365||53,781|
|Share price (US$)|
|Volume traded (thousands)||24,213||20,255||4,150|
|Common shares outstanding (thousands)||169,001||168,107||126,442|
- 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. We define funds from operations as cash flow 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 ended March 31, 2015.
- Cash dividends declared are net of DRIP participation.
- Principal amount of instruments.
- 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)), the principal amount of long-term debt and long-term bank loan.
- 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.
- Heavy oil prices exclude condensate blending.
In response to the decline in crude oil prices, we have taken several prudent steps to maintain strong levels of financial liquidity, including evaluating our level of capital spending, negotiating cost savings with service providers, deferring development activity in Canada and shutting-in uneconomic production. Subsequent to the end of the first quarter, we completed an equity financing, raising net proceeds of $606 million. The net proceeds from the equity financing have been applied to reduce outstanding indebtedness, which enhances our financial position and provides increased certainty for us to pursue our planned capital program. Our 2015 program remains flexible and allows for adjustments to second half capital spending based on changes in the commodity price environment. We remain focused on creating long-term value for our shareholders.
Our operational performance in the first quarter is consistent with our full-year plans. Capital expenditures for exploration and development activities totaled $147.4 million in Q1/2015, down from $214.7 million in Q4/2014 and $172.4 million in Q1/2014. Approximately 86% of our exploration and development expenditures occurred in the Eagle Ford with the remaining 14% in Canada. In Q1/2015, we participated in the drilling of 81 (25.1 net) wells with a 98% success rate.
Despite the reduced activity level, our operating results were strong with production averaging 90,710 boe/d (83% oil and NGL) in Q1/2015, largely unchanged from a Q4/2014 level of 92,220 boe/d, after adjusting for non-core dispositions of 1,250 boe/d which occurred late last year.
Our 2015 production guidance remains at 84,000 to 88,000 boe/d with budgeted exploration and development expenditures of $500 to $575 million. We expect our production to be approximately evenly split between Canada and the Eagle Ford. Approximately 80% of our 2015 capital budget will be invested in our Eagle Ford operations where we expect to drill 39 to 45 net wells. The remaining 20% will be invested in our heavy oil operations at Peace River and Lloydminster. Our budget for Canada will see approximately 70% of planned expenditures occurring in the second half of the year.
Wells Drilled – Three Months Ended March 31, 2015
|Crude Oil||Natural Gas||and Service||Abandoned||Total|
|Light oil and natural gas|
Production in the Eagle Ford averaged 41,076 boe/d (80% oil and NGL) during Q1/2015, an increase of 8% over Q4/2014. Production from the Eagle Ford represented 45% of our Q1/2015 production. Capital expenditures for our Eagle Ford assets in Q1/2015 totaled $126.2 million, down from $149.5 million in Q4/2014. This reduction is reflective of reduced activity levels combined with negotiated cost savings with service providers.
In Q1/2015, we participated in the drilling of 68 (16.0 net) wells and commenced production from 52 (13.2 net) wells. Of the 52 wells that commenced production during the first quarter, 42 wells established an average 30-day initial production rate of approximately 1,050 boe/d. Our 2015 capital budget includes the drilling of 39 to 45 net wells.
In addition to targeting the Lower Eagle Ford formation, we are now actively delineating the Austin Chalk formation. To-date, we have delineated the Austin Chalk on over 50% of our acreage. Since acquisition, we have drilled 32 (9.0 net) Austin Chalk wells and brought 20 (5.7 net) on production. These 20 wells established an average 30-day initial production rate of approximately 1,000 boe/d. As of March 31, 2015, the Austin Chalk has 27 (7.8 net) producing wells.
Additional advancements have been made to delineate the multi-zone development potential of our Sugarkane acreage. We have initiated “stack and frac” pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk. Recent production data for a four-well pad that targeted the Lower Eagle Ford, Upper Eagle Ford and Austin Chalk formations delivered 30-day initial production rates per well ranging from 1,100 to 1,500 boe/d. Results from additional pilots are expected in 2015.
Production in Canada averaged 49,634 boe/d (86% oil and NGL) during Q1/2015, a decrease of 8% over Q4/2014 and 12% over Q1/2014. The reduced volumes in Canada include the divestiture of non-core assets in late 2014 and the shut-in of uneconomic production, which in aggregate totaled approximately 2,000 boe/d. Capital expenditures for our Canadian assets in Q1/2015 totaled $21.3 million, down from $65.2 million in Q4/2014 and $154.6 million in Q1/2014.
At Peace River, we drilled one (1.0 net) cold horizontal producer and five (5.0 net) stratigraphic and service wells. Our 2015 capital budget includes the drilling of approximately 8 net horizontal multi-lateral wells and 8 to 12 stratigraphic and service wells.
At Lloydminster, we drilled seven (3.1 net) oil wells. Our 2015 capital budget includes the drilling of approximately 26 net development wells.
In the current low oil price environment and following a power plant outage, we have made the decision to decommission our Gemini SAGD pilot project in the second quarter. Our Gemini operations commenced over a year ago and since that time we have successfully captured the key data associated with the pilot’s objectives. The project’s primary objective was to confirm reservoir production capacity and continuity to support a commercial scale project. Additionally, the pilot provided critical information on facility and well design. To-date, the well pair has produced nearly 200,000 barrels of bitumen with a current instantaneous steam-oil ratio of 2.3 barrels of steam per barrel of oil. Production from the well pair peaked at over 1,100 bbl/d and has consistently produced at rates of between 600 to 800 bbl/d. In December 2014, we filed an application requesting an amendment to our existing approval to allow for a 5,000 bbl/d facility. Following regulatory approval, any subsequent sanctioning decision will be considered in the context of the project economics in a higher commodity price environment.
We generated FFO of $160.2 million ($0.95 per share) in Q1/2015, compared to $245.5 million ($1.47 per share) in Q4/2014 and $170.8 million ($1.36 per share) in Q1/2014. Our reduced FFO is attributable to significantly lower commodity prices. Non-cash charges, which included unrealized hedging and foreign exchange losses and depletion expenses, resulted in a net loss of $175.9 million ($1.04 per share) in Q1/2015 compared to net income of $47.8 million ($0.38 per share) in Q1/2014.
Our Q1/2015 financial results were impacted by the decline in crude oil prices. The average price for West Texas Intermediate (“WTI”) for Q1/2015 was US$48.64/bbl, representing a decrease of 51% from Q1/2014 and 33% from Q4/2014. The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 30% in Q1/2015, as compared to 23% in Q1/2014 and 20% in Q4/2014. Our realized oil and NGL price of $36.40/bbl in Q1/2015 decreased by 50% from $73.12/bbl in Q1/2014 and 38% from $58.93/bbl in Q4/2014.
In Q1/2015 we recognized $16.9 million of current income tax expense, which relates to the increase in realized financial derivatives gains and the increase in previously deferred income being taxed in the current period. We continue to forecast cash income taxes in 2015 at an effective tax rate of approximately 5% of pre-tax funds from operations.
We generated an operating netback in Q1/2015 of $13.89/boe ($26.37/boe including financial derivative gains). Our Canadian operations generated an operating netback of $7.35/boe while the Eagle Ford generated an operating netback of $21.78/boe. Our Eagle Ford assets are located in south Texas and are proximal to Gulf Coast crude oil markets with established transportation systems, resulting in strong realized prices. Our light oil and condensate production in the Eagle Ford is priced primarily off a Louisiana Light Sweet (LLS) benchmark which typically trades at a premium to WTI. This strong pricing, combined with low cash costs, contributed positively to our operating netback in Q1/2015. The table on the following page provides a summary of our operating netbacks for the periods noted.
|Three Months Ended
March 31, 2015
Ended March 31,
|($ per boe)||Canada||Eagle Ford||Total||Change|
|Production and operating expenses||13.57||7.35(1)||10.75||12.87||(16)%|
|Financial derivatives gain||–||–||12.48||(0.30)||-%|
|Operating netback after financial derivatives||$7.35||$21.78||$26.37||$36.55||(28)%|
|(1) In the Eagle Ford, transportation expenses are included in production and operating expenses.|
We employ a comprehensive risk management program to reduce the volatility in our FFO. In Q1/2015, we realized financial derivative gains of $101.8 million, primarily due to crude oil prices being at levels significantly below those set in our fixed price contracts, which were partially offset by the settlement of our out-of-money foreign exchange contracts.
For Q2/2015, we have entered into hedges on approximately 33% of our net WTI exposure with 31% fixed at US$87.03/bbl and 2% receiving WTI plus US$11.01/bbl when WTI is below US$80.00/bbl. The unrealized financial derivatives gain with respect to our WTI hedges as at March 31, 2015 was $105.2 million. The following table summarizes our WTI hedges in place for 2015 as at May 4, 2015.
|Hedge (%) (1)||31%||15%||15%||20%||11%|
|Hedge (%) (1)||2%||7%||–||3%||–|
|Price (US$/bbl) (2)||WTI + $11.01||WTI + $10.00||–||WTI + $10.24||–|
|Total Hedge Volume|
|Hedge (%) (1)||33%||22%||15%||23%||11%|
|(1) Percentage of hedged volumes is based on the mid-point of our 2015 production guidance (excluding NGL), net of royalties.|
|(2) Hedges reflect our exposure when WTI is less than US$80/bbl.|
As part of our hedging program, we also focus on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to markets by rail when economics warrant. Baytex has no fixed investment or take or pay obligations to transport crude oil by rail and infrastructure growth around our core heavy oil producing regions allows for optimization between rail and pipe. In Q1/2015, approximately 22,000 bbl/d of our heavy oil volumes were delivered to market by rail, down 8% from the previous quarter. For Q2/2015, we expect to deliver approximately 20,000 bbl/d of our heavy oil volumes to market by rail as we optimize our heavy oil netbacks.
Total monetary debt at March 31, 2015 was $2.46 billion, comprised of a bank loan of $0.78 billion, long-term debt of $1.51 billion, and a working capital deficiency of $0.16 billion. The increase in total monetary debt at March 31, 2015, as compared to December 31, 2014, was primarily due to the revaluation of our U.S. dollar denominated debt and additional draws on the bank facility to fund the capital expenditure program.
On March 11, 2015, we announced an equity financing that closed on April 2, 2015. At closing, we issued 36,455,000 common shares at a price of $17.35 per share for aggregate net proceeds of approximately $606 million, which were utilized to reduce bank indebtedness.
We have unsecured revolving credit facilities consisting of a $1.0 billion Canadian facility and a US$200 million U.S. facility that mature in June 2018. These facilities do not require any mandatory principal payments prior to maturity and can be further extended beyond June 2018 with the consent of the lenders. As at March 31, 2015 and pro forma the equity financing, we had approximately $1.1 billion in undrawn capacity on these facilities.
During the first quarter, we amended the financial covenants contained in our unsecured revolving credit facilities to provide us with increased financial flexibility. Pro forma the equity financing, our total monetary debt is $1.85 billion, which results in a Senior Debt (1) to Bank EBITDA (2)ratio (twelve months trailing) of 1.51:1.00. Our revised financial covenants allow this ratio to reach a maximum of 4.75:1.00 through June 2016 and 4.50:1.00 through December 2016.
- “Senior debt” is defined as the sum of the principal amount of our bank loan and long-term debt.
- Bank EBITDA is a non-GAAP measure calculated based on terms and definitions set out in the credit agreement which adjusts net income for financing costs, income tax, certain specific unrealized and non-cash transactions (including depletion, depreciation, amortization, impairment, exploration expenses, unrealized gains and losses on financial derivatives and foreign exchange, and share based compensation) and acquisition and disposition activity (excluding acquisition-related costs incurred) and is calculated based on a trailing twelve month basis.
Our unaudited interim condensed consolidated financial statements for the three months ended March 31, 2015 and 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, May 5, 2015, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-8527 or toll free in North America 1-800-396-7098 and toll free international 1-800-6578-9868. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/6465 in your web browser.
An archived recording of the conference call will be available until May 12, 2015 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 3223079. The conference call will also be archived on the Baytex website at 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 annual average production rate for 2015; our capital budget for 2015; the geographic breakdown of our 2015 annual production; the breakdown of our 2015 capital budget by area; our plan for developing our properties in 2015, including the number and type of wells and the geographic location of wells; our Eagle Ford shale play, including initial production rates from new wells, our plans to use “stack and frac” pilots to target three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation, our assessment of the results of the first “stack and frac“ pilot and the timing of receiving the results from additional pilots; our expectation regarding the payment of cash income taxes in 2015, including our effective tax rate; 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 second quarter of 2015; our liquidity and financial capacity; and the sufficiency of our financial resources to fund our operations. 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: our ability to execute and realize on the anticipated benefits of the acquisition of the Eagle Ford assets; petroleum and natural gas prices and pricing differentials between light, medium and heavy gravity crude oil; well production rates and reserves 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 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 volatility of oil and natural gas prices; substantial or extended declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; uncertainties in the capital markets that may restrict the availability of or increase the cost of capital or of borrowing; refinancing risk for existing debt and the risk of failing to comply with covenants in existing debt agreements; risks associated with properties operated by third parties, specifically with respect to a substantially majority of our Eagle Ford assets; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks associated with the exploitation of our properties and our ability to acquire reserves; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; our inability to fully insure against all hazards associated with acquiring, developing and exploring for oil and natural gas; business risks; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; the implementation of strategies for reducing greenhouse gases; depletion of our reserves; 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 our control. These and additional 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, 2014, 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 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.
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
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.
Total monetary debt is not a measurement based on GAAP in Canada. We define total monetary debt as 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 bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.
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, production and 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
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. 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.
References herein to average 30-day initial 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 assets for which such rates are provided. 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.
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 Eagle Ford in the United States. Approximately 82% of Baytex’s production is weighted toward crude oil and natural gas liquids. 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.
For further information about Baytex, please visit our website at www.baytexenergy.com.