CALGARY, ALBERTA–(Marketwired – May 3, 2016) – Baytex Energy Corp. (“Baytex”) (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three months ended March 31, 2016 (all amounts are in Canadian dollars unless otherwise noted).
“We continue to meet the challenges brought on by this low oil price environment head on. During the first quarter, we announced amendments to our bank credit facilities that provide us with increased financial flexibility and we shut-in low or negative margin heavy oil production. To generate the highest netback and rate of return, we focused our capital expenditures on the Eagle Ford. Our operating results in the Eagle Ford were strong during the quarter with production up 2% over Q4/2015 and well costs continuing to decline. We remain well positioned to benefit from an oil price recovery as our three core plays provide some of the strongest capital efficiencies in North America,” commented James Bowzer, President and Chief Executive Officer.
- Generated production of 75,776 boe/d (78% oil and NGL) in Q1/2016;
- Delivered funds from operations (“FFO”) of $45.6 million ($0.22 per share) in Q1/2016;
- Realized an operating netback (sales price less royalties, operating and transportation expenses) in Q1/2016 of $5.82/boe ($12.29/boe including financial derivatives gain);
- Produced 41,067 boe/d in the Eagle Ford, an increase of 2% from Q4/2015 and 5% from Q3/2015;
- Advanced the multi-zone potential of our Sugarkane acreage with 19 wells establishing an average 30-day initial production rate of approximately 1,300 boe/d;
- Amended our bank credit facilities and financial covenants to provide increased financial flexibility; and
- Maintained strong levels of financial liquidity with a Senior Secured Debt to Bank EBITDA ratio of 0.61:1.00.
|Three Months Ended|
|FINANCIAL(thousands of Canadian dollars, except per common share amounts)|
|Petroleum and natural gas sales||$||153,598||$||229,361||$||283,384|
|Funds from operations (1)||45,645||93,095||160,221|
|Per share – basic||0.22||0.44||0.95|
|Per share – diluted||0.22||0.44||0.95|
|Net income (loss)||607||(412,924||)||(175,916||)|
|Per share – basic||0.00||(1.96||)||(1.04||)|
|Per share – diluted||0.00||(1.96||)||(1.04||)|
|Exploration and development||81,685||140,796||147,429|
|Acquisitions, net of divestitures||(9||)||(574||)||1,550|
|Total oil and natural gas capital expenditures||$||81,676||$||140,222||$||148,979|
|Working capital deficiency||150,332||169,498||162,546|
|Net debt (3)||$||1,981,343||$||2,049,905||$||2,455,995|
|Three Months Ended|
|Heavy oil (bbl/d)||24,807||31,733||39,226|
|Light oil and condensate (bbl/d)||24,489||24,930||28,056|
|Total oil and NGL (bbl/d)||59,405||65,659||75,506|
|Natural gas (mcf/d)||98,220||92,708||91,010|
|Oil equivalent (boe/d @ 6:1) (4)||75,776||81,110||90,675|
|WTI oil (US$/bbl)||33.45||42.18||48.64|
|WCS heavy oil (US$/bbl)||19.22||27.69||33.91|
|Edmonton par oil ($/bbl)||40.80||52.94||51.94|
|LLS oil (US$/bbl)||33.24||43.33||50.55|
|Baytex average prices (before hedging)|
|Heavy oil ($/bbl) (5)||12.54||24.41||28.57|
|Light oil and condensate ($/bbl)||37.97||50.17||52.34|
|Total oil and NGL ($/bbl)||24.02||33.21||36.40|
|Natural gas ($/mcf)||2.40||2.76||3.22|
|Oil equivalent ($/boe)||21.93||30.03||33.54|
|CAD/USD noon rate at period end||1.2971||1.3840||1.2683|
|CAD/USD average rate for period||1.3748||1.3353||1.2308|
|COMMON SHARE INFORMATION|
|Share price (Cdn$)|
|Volume traded (thousands)||483,311||283,619||122,179|
|Share price (US$)|
|Volume traded (thousands)||154,052||153,763||24,213|
|Common shares outstanding (thousands)||210,689||210,583||169,001|
|(1) 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 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 capital investments and potential future dividends. 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, 2016.|
|(2) Principal amount of instruments.|
|(3) Net 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 current financial derivatives)) and the principal amount of both the long-term notes and the bank loan.|
|(4) 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.|
|(5) Heavy oil prices exclude condensate blending.|
Our operating results for the first quarter were consistent with our expectations and reflect a reduced pace of drilling activity in response to the low crude oil price environment. Production of 75,776 boe/d (78% oil and NGL) in Q1/2016 exceeded our first quarter guidance range of 73,000 to 75,000 boe/d, due largely to continued strong operating results in the Eagle Ford. Capital expenditures for exploration and development activities totaled $81.7 million in Q1/2016 and included the drilling of 45 (13.5 net) wells with a 100% success rate.
During the first quarter, we pro-actively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production in order to optimize the value of our resource base and maximize our funds from operations. Should netbacks improve, we have the ability to restart these wells within one month.
Our 2016 production guidance remains at 68,000 to 72,000 boe/d with budgeted exploration and development expenditures of $225 to $265 million. In 2016, we are targeting capital expenditures to approximate funds from operations in order to minimize additional bank borrowings. Our 2016 program will remain flexible and allows for adjustments to spending based on changes in the commodity price environment. In addition, we may contemplate minor non-core asset sales.
Wells Drilled – Three Months Ended March 31, 2016
|Crude Oil||Natural Gas||and Service||Abandoned||Total|
|Light oil and natural gas|
Our performance in the Eagle Ford was strong during the first quarter with production averaging 41,067 boe/d (77% liquids), an increase of 2% from Q4/2015 and 5% from Q3/2015. Capital expenditures totaled $76.8 million in the Eagle Ford, representing 96% of our exploration and development spending during the quarter. Our pace of development in the Eagle Ford was largely unchanged during the first quarter with approximately six drilling rigs and one frac crew working on our lands. At March 31, 2016, we had 36 (10.7 net) wells waiting on completion.
Significant advancements have been made in the past twelve months to delineate the multi-zone potential of our Sugarkane acreage and we continue to monitor “stack and frac” pilots which target up to three zones in the Eagle Ford formation in addition to the overlying Austin Chalk formation. A recent five-well pad that targeted the Austin Chalk and Upper Eagle Ford formations delivered an average 30-day initial production rate per well of approximately 1,350 boe/d. We currently have 13 multi-zone projects in various stages of execution and production.
In the Eagle Ford in Q1/2016, we participated in the drilling of 44 (12.5 net) wells and commenced production from 34 (10.2 net) wells. Of the 34 wells that commenced production during the first quarter, 19 wells have been producing for more than 30 days and have established an average 30-day initial production rate of approximately 1,300 boe/d. To-date, we have achieved an approximate 32% reduction in well costs in the Eagle Ford – with wells now being drilled, completed and equipped for approximately US$5.6 million, as compared to US$8.2 million in 2014.
Production in Canada averaged 34,709 boe/d (80% oil and NGL) during Q1/2016 as compared to 40,826 boe/d in Q4/2015. The reduced volumes in Canada reflect the impact of production that was shut-in during the first quarter and the fact there has been no heavy oil drilling since Q3/2015. Capital expenditures for our Canadian assets in Q1/2016 totaled $4.8 million, a decrease from $8.8 million in Q4/2015, and included the drilling of one (1.0 net) liquids-rich natural gas well in the Pembina/O’Chiese region of west-central Alberta.
The first quarter of 2016 was challenging as the global oversupply of crude oil continued to weigh on the market, with crude oil prices hitting a low of US$26/bbl in February. The sharp reduction in crude oil prices had a significant impact on our FFO, which totaled $45.6 million ($0.22 per share) in Q1/2016, as compared to $93.1 million ($0.44 per share) in Q4/2015.
In Q1/2016, the average price for West Texas Intermediate light oil (“WTI”) averaged US$33.45/bbl, as compared to US$42.18/bbl in Q4/2015. This 21% decline in the benchmark index resulted in our realized price for light oil and condensate decreasing 24% to $37.97/bbl. The discount for Canadian heavy oil, as measured by the price differential between Western Canadian Select (“WCS”) and WTI, averaged US$14.23/bbl in Q1/2016, as compared to US$14.49/bbl in Q4/2015. The lower WTI price in Q1/2016 resulted in a 31% decrease in the price of WCS and a 49% decrease in our realized heavy oil price to $12.54/bbl, as compared to Q4/2015.
We generated an operating netback in Q1/2016 of $5.82/boe ($12.29/boe including financial derivatives gain). The Eagle Ford generated an operating netback of $11.41/boe while our Canadian operations generated an operating loss of $0.77/boe. In Canada, 71% of our production during the quarter was weighted to heavy oil, where price realizations were particularly weak. As a result, we proactively shut-in approximately 7,500 boe/d of predominantly low or negative margin heavy oil production during the first quarter. With WTI currently trading above US$40/bbl, our operating netback in Canada has improved from that reported in the first quarter.
In the Eagle Ford, our assets are located in south Texas, proximal to Gulf Coast markets, with light oil and condensate production priced off a Louisiana Light Sweet crude oil benchmark which typically trades at a premium to WTI. Declining production in the region has increased competition for field supplies resulting in lower transportation and gathering costs and improved price realizations. This relative pricing, combined with low cash costs, contributed positively to our operating netback. During the quarter, the terms of certain post-production NGL processing arrangements in the Eagle Ford were changed, which increased both revenues and operating expenses by approximately $1.00/boe.
During the quarter, we continued to focus on cost reduction initiatives across all of our operations. Operating expenses in Canada decreased 19% on a per boe basis as compared to Q1/2015, despite the impact of fixed costs on lower production volumes. Transportation expenses in Canada have been reduced by 40% on a per boe basis as compared to Q1/2015, due to ongoing optimization within our trucking division and decreased fuel costs.
The following table provides a summary of our operating netbacks for the periods noted.
|Three Months Ended March 31|
|($ per boe)||Canada||U.S.||Total||Canada||U.S.||Total|
|Realized financial derivatives gain||–||–||6.47||–||–||12.48|
|Operating netback after financial derivatives||$||(0.77||)||$||11.41||$||12.29||$||7.35||$||21.78||$||26.37|
General and administrative expenses were $14.2 million in Q1/2016, as compared to $17.1 million in Q1/2015. The decrease is primarily a result of reductions to staffing levels to coincide with lower activity levels combined with a reduction in discretionary spending. As a continued cost control measure, all full-time employee salaries and all annual retainers paid to our directors were reduced by 10% effective March 1, 2016.
As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates and interest rates. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to partially reduce the volatility in our FFO. We realized a financial derivatives gain of $44.6 million in Q1/2016, primarily due to crude oil prices being at levels significantly below those set in our financial derivative contracts.
For the balance of 2016, we have entered into hedges on approximately 44% of our net WTI exposure with 17% fixed at US$62.03/bbl and 27% hedged utilizing a 3-way option structure (as described in note 2 to the table below). We have also entered into hedges on approximately 38% of our net WCS differential exposure and 58% of our net natural gas exposure.
For 2017, we have entered into hedges on approximately 28% of our net WTI exposure hedged utilizing a 3-way option structure (as described in note 2 to the table below). We have also entered into hedges on approximately 8% of our net WCS differential exposure and 32% of our net natural gas exposure.
The unrealized financial derivatives gain with respect to our hedges as at April 26, 2016 was approximately $54 million. The following table summarizes our hedges in place as at May 3, 2016.
|WTI Fixed Hedges|
|WTI 3-Way Option|
|Average Ceiling/Floor/Sold Floor (US$/bbl) (2)||$60/$50/$40||$60/$50/$40||$60/$50/$40||$60/$50/$40||$59/$46/$36|
|Total WTI Hedge Volumes (bbl/d)||17,500||15,000||15,000||15,833||10,000|
|Hedge (%) (1)||49%||42%||42%||44%||28%|
|WCS Differential Hedges|
|WCS Price Relative to WTI (US$/bbl)||($13.26||)||($13.32||)||($13.40||)||($13.32||)||($13.42||)|
|Hedge % (1)||42%||37%||37%||38%||8%|
|AECO Fixed Hedges|
|NYMEX Fixed Hedges|
|Total Hedge Volume (mmbtu/d)||41,855||45,804||45,804||44,488||24,478|
|Hedge % (1)||55%||60%||60%||58%||32%|
|(1) Percentage of hedged volumes is based on the mid-point of our revised 2016 production guidance (excluding NGL), net of royalties.|
|(2) WTI 3-way option consists of a sold call, a bought put and a sold put. In a $60/$50/$40 example, Baytex receives WTI + US$10/bbl when WTI is at or below US$40/bbl; Baytex receives US$50/bbl when WTI is between US$40/bbl and US$50/bbl; Baytex receives WTI when WTI is between US$50/bbl and US$60/bbl; and Baytex receives US$60/bbl when WTI is above US$60/bbl.|
Total long-term debt at March 31, 2016 was $1.83 billion, comprised of a bank loan of $290 million and senior unsecured notes of $1.54 billion. The decrease in total long-term debt at March 31, 2016, as compared to December 31, 2015, was due to an increase in the Canada-U.S. dollar exchange rate which resulted in the principal amount of our U.S. dollar denominated debt decreasing when converted to Canadian dollars. Our U.S. dollar long-term notes total US$956 million with no material maturities until 2021 and our Canadian dollar long-term notes total C$300 million and mature in 2022. These long-term notes contain no material financial maintenance covenants.
On March 31, 2016, we announced amendments to our bank credit facilities that provide us with increased financial flexibility. The amendments included reducing our credit facilities to US$575 million, granting our bank lending syndicate first priority security with respect to our assets and restructuring our financial covenants. These facilities are not borrowing base facilities and do not require annual or semi-annual reviews. There are no mandatory principal payments prior to maturity in June 2019 and the maturity date can be further extended with the consent of our bank lending syndicate. With this revised agreement, we expect to realize savings of approximately $8 million in 2016 from lower interest expense and standby fees.
The following table summarizes the financial covenants contained in the amended credit agreement and our compliance therewith as at March 31, 2016.
|Ratio for the Quarter(s) ending:|
|Covenant Description||Position as at
March 31, 2016
|March 31, 2016 to
March 31, 2018
|June 30, 2018 to
Sept. 30, 2018
|Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio)||0.61:1.00||5.00:1.00||4.50:1.00||4.00:1.00||3.50:1.00|
|Interest Coverage (3) (Minimum Ratio)||4.82:1.00||1.25:1.00||1.50:1.00||1.75:1.00||2.00:1.00|
|(1) “Senior Secured Debt” is defined as the principal amount of our bank loan and other secured obligations under the credit facilities. At March 31, 2016, our Senior Secured Debt totaled $303 million.|
|(2) “Bank EBITDA” is calculated based on terms and conditions set out in the credit agreement which adjusts net income for interest expense, income taxes, certain non-cash items and acquisition and disposition activity. Bank EBITDA is calculated based on a trailing twelve month basis and was $495 million for the twelve months ended March 31, 2016.|
|(3) “Interest Coverage” is computed as the ratio of Bank EBITDA to interest expense on our Senior Secured Debt and long-term notes. Interest expense for the trailing twelve months ended March 31, 2016 was $103 million.|
With these amendments to our bank credit facilities, we expect to have adequate liquidity and financial flexibility to execute our business plan. In addition, we are well positioned to benefit from an oil price recovery as our three core plays provide some of the strongest capital efficiencies in North America.
Our unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016 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 3, 2016, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-2219 (Toronto area), 1-866-225-2055 (North America toll-free) or 1-800-6578-9868 (International toll-free). Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/7374 in your web browser.
An archived recording of the conference call will be available until May 10, 2016 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 6106828. The conference call will also be archived on our 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 but not limited to: our business strategies, plans and objectives; with respect to the shut-in of certain heavy oil production, our expectation that it will preserve the value of our resource base and maximize our funds from operations and the time required to re-start such production; our expectations for annual average production rate and exploration and development capital expenditures for 2016; our target for 2016 capital expenditures to approximate funds from operations in order to minimize additional bank borrowings; the possibility of non-core asset sales; our Eagle Ford shale play, including our assessment of the performance of wells drilled in Q1/2016, 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, and the cost to drill, complete and equip a well; 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 partially reduce the volatility in our funds from operations by utilizing financial derivative contracts; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in reducing the volatility in our funds from operations; our liquidity and financial capacity; our belief that the revised credit agreement provides us with increased financial flexibility; the amount that we will save in 2016 on interest expense and standby fees as a result of the amendments to our credit agreement; and our belief that we have adequate liquidity and financial flexibility to execute our business plan, that we are well positioned to benefit from an oil price recovery and that our three core plays provide some of the strongest capital efficiencies in North America. 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.
These forward-looking statements are based on certain key assumptions regarding, among other things: petroleum and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; 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; 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). Readers are 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 natural gas prices; further declines or an extended period of the currently low oil and natural gas prices; failure to comply with the covenants in our debt agreements; that our credit facilities may not provide sufficient liquidity or may not be renewed; uncertainties in the capital markets that may restrict or increase our cost of capital or borrowing; risks associated with a third-party operating our Eagle Ford properties; changes in government regulations that affect the oil and gas industry; changes in environmental, health and safety regulations; restrictions or costs imposed by climate change initiatives; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; the cost of developing and operating our assets; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; depletion of our reserves; 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 risks; risks of counterparty default; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with large projects; risks related to our thermal heavy oil projects; risks associated with the ownership of our securities, including changes in market-based factors and the discretionary nature of dividend payments; 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, 2015, 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 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 will be the same in whole or in part as those referenced in the forward-looking statements 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 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 capital investments and potential future dividends to shareholders. The most directly comparable measures calculated in accordance with GAAP are cash flow from operating activities and net income.
Net debt is not a measurement based on GAAP in Canada. We define net debt as the sum of monetary working capital (which is current assets less current liabilities (excluding current financial derivatives)) and the principal amount of both the long-term notes and the bank loan. We believe that this measure assists in providing a more complete understanding of our cash liabilities.
Bank EBITDA is not a measurement based on GAAP in Canada. We define Bank EBITDA as our consolidated net income attributable to shareholders before interest, taxes, depletion and depreciation, and certain other non-cash items as set out in our credit agreements governing our revolving credit facilities. This measure is used to measure compliance with certain financial covenants.
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 divided by barrels of oil equivalent sales volume for the applicable period. Our determination of operating netback may not be comparable with the calculation of similar measures for other entities. We believe 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 an 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 78% of Baytex’s production is weighted toward crude oil and natural gas liquids. Baytex’s common shares trade 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.
Baytex Energy Corp.
Senior Vice President, Capital Markets and Public Affairs
Toll Free Number: 1-800-524-5521