CALGARY, ALBERTA–(Marketwired – Oct. 30, 2014) – Baytex Energy Corp. (“Baytex”) (TSX:BTE)(NYSE:BTE) reports its operating and financial results for the three and nine months ended September 30, 2014 (all amounts are in Canadian dollars unless otherwise noted).
Commenting on the results, James Bowzer, President and Chief Executive Officer, said: “Our third quarter results reflect a strong contribution from our Eagle Ford assets, which has resulted in record production and funds from operations. Our operating results to-date in the Eagle Ford have exceeded our initial expectations with individual well performance from wells drilled in 2014 outperforming the type curves upon which our acquisition evaluation was based. Reflective of our strong operating results, we are increasing our production guidance by 5% for the second half of 2014 with an unchanged exploration and development capital budget.”
- Generated production of 94,093 boe/d (85% oil and NGL) in Q3/2014, an increase of 41% over Q2/2014 and 56% over Q3/2013;
- Delivered funds from operations (“FFO”) of $298.0 million ($1.79 per basic share) during Q3/2014, an increase of 80% over Q2/2014 and 49% over Q3/2013;
- Produced approximately 34,000 boe/d in the Eagle Ford in Q3/2014, an increase of approximately 21% from the closing of the acquisition;
- Realized an operating netback (sales price less royalties, production and operating expenses, and transportation expenses) in Q3/2014 of $40.86/boe;
- Maintained a conservative payout ratio, net of Dividend Reinvestment Plan (“DRIP”) participation, of 30% (40% before DRIP) in Q3/2014; and
- Divested of our North Dakota assets for after-tax net proceeds of approximately $290 million which were used to repay debt.
|Three Months Ended||Nine Months Ended|
|September 30, 2014||June 30, 2014||September 30, 2013||September 30, 2014||September 30, 2013|
(thousands of Canadian dollars, except per common share amounts)
|Petroleum and natural gas sales||$ 634,415||$ 476,404||$ 422,791||$ 1,496,627||$ 1,036,747|
|Funds from operations (1)||297,964||165,503||199,318||634,277||456,894|
|Per share – basic||1.79||1.22||1.61||4.44||3.71|
|Per share – diluted||1.78||1.21||1.59||4.40||3.66|
|Cash dividends declared (2)||89,771||75,397||61,354||228,610||178,129|
|Dividends declared per share||0.72||0.68||0.66||2.06||1.98|
|Per share – basic||0.87||0.27||0.70||1.60||1.08|
|Per share – diluted||0.86||0.27||0.70||1.59||1.07|
|Exploration and development||230,032||148,916||121,484||551,373||465,840|
|Acquisitions, net of divestitures||(341,908)||2,920,845||2,838||2,580,818||(41,340)|
|Total oil and natural gas capital expenditures||$ (111,876)||$ 3,069,761||$ 124,322||$ 3,132,191||$ 424,500|
|Bank loan||$ 624,067||$ 952,402||$ 244,651||$ 624,067||$ 244,651|
|Working capital deficiency||250,939||178,517||57,703||250,939||57,703|
|Total monetary debt (3)||$ 2,255,817||$ 2,460,406||$ 756,629||$ 2,255,817||$ 756,629|
|Three Months Ended||Nine Months Ended|
|September 30, 2014||June 30, 2014||September 30, 2013||September 30, 2014||September 30, 2013|
|Heavy oil (bbl/d)||45,456||45,986||44,908||45,559||41,664|
|Light oil and condensate (bbl/d)||28,124||9,864||6,670||14,569||6,403|
|Total oil and NGL (bbl/d)||80,209||58,326||53,274||63,842||49,827|
|Natural gas (mcf/d)||83,300||51,645||41,460||58,766||41,979|
|Oil equivalent (boe/d @ 6:1)||94,093||66,934||60,184||73,636||56,823|
|Average prices (before hedging)|
|WTI oil (US$/bbl)||97.17||102.99||105.82||99.61||98.15|
|WCS Heavy Oil (US$/bbl)||76.99||82.95||88.34||78.50||75.29|
|Edmonton par oil ($/bbl)||98.65||106.68||105.07||101.83||95.55|
|LLS oil (US$/bbl)||100.87||105.55||109.92||103.60||109.55|
|BTE heavy oil ($/bbl)||73.99||79.26||79.29||74.84||66.41|
|BTE light oil and condensate ($/bbl)||99.65||104.16||100.81||100.19||92.20|
|BTE NGL ($/bbl)||36.77||38.74||40.71||40.59||41.32|
|BTE total oil and NGL ($/bbl)||79.91||81.74||80.75||78.62||68.83|
|BTE natural gas ($/mcf)||4.43||4.84||2.72||4.73||3.26|
|BTE oil equivalent ($/boe)||72.04||75.06||73.36||71.97||62.77|
|CAD/USD noon rate at period end||1.1208||1.0676||1.0285||1.1208||1.0285|
|CAD/USD average rate for period||1.0893||1.0894||1.0385||1.0940||1.0236|
|Share price (Cdn$)|
|Volume traded (thousands)||40,645||45,952||24,658||140,378||82,511|
|Share price (US$)|
|Volume traded (thousands)||5,212||3,552||3,282||12,915||11,414|
|Common shares outstanding (thousands)||166,709||165,421||124,497||166,709||124,497|
- 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 and nine months ended September 30, 2014.
- Cash dividends declared are net of DRIP participation.
- Total monetary debt is a non-GAAP measure which we define to be the sum of monetary working capital (which is current assets less current liabilities (excluding non-cash items such as unrealized gains or losses on financial derivatives, assets held for sale and liabilities related to assets held for sale)), the principal amount of long-term debt and long-term bank loan.
- 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.
Production averaged 94,093 boe/d (85% oil and NGL) during Q3/2014, an increase of 41% from Q2/2014 and 56% from Q3/2013, which reflects a strong contribution (and first full quarter) from our Eagle Ford assets and continued strong performance from our Canadian assets. Capital expenditures for exploration and development activities totaled $230.0 million in Q3/2014 and included the drilling of 107 (41.4 net) wells with a 99% success rate.
As previously announced, we divested of our North Dakota Bakken assets on September 24, 2014 for after-tax net proceeds of approximately $290 million. The proceeds were applied against outstanding indebtedness. The North Dakota assets contributed approximately 3,500 boe/d of production in Q3/2014.
We are updating our 2014 guidance to reflect our strong third quarter operating performance. We now expect to generate an average production rate of 91,000 to 92,000 boe/d for the second half of 2014, which at the mid-point reflects an increase of 5% over our previous guidance of 86,000 to 88,000 boe/d. We expect to generate this additional production while maintaining our original capital spending guidance of $440 to $465 million for the second half of 2014. Our full-year 2014 production guidance has also been adjusted upward to 77,000 to 78,000 boe/d (previously 74,000 to 76,000 boe/d) with forecast exploration and development expenditures of $765 to $790 million remaining unchanged.
Wells Drilled – Three Months Ended September 30, 2014
|Primary||Thermal||Natural Gas||and Service||Abandoned||Total|
|Light oil, NGL and natural gas|
Wells Drilled – Nine Months Ended September 30, 2014
|Primary||Thermal||Natural Gas||and Service||Abandoned||Total|
|Light oil, NGL and natural gas|
Eagle Ford Performance
Our Q3/2014 results reflect the first full quarter of operations for our Eagle Ford assets. When we acquired the Eagle Ford assets, the acreage position included 22,200 net contiguous acres in the Sugarkane Field located in South Texas in the core of the liquids-rich Eagle Ford shale. Since that time, we have acquired additional acreage bringing our total land position to approximately 23,000 net acres. At the time of the acquisition, production from the Eagle Ford was approximately 28,000 boe/d. In Q3/2014, production from the Eagle Ford averaged approximately 34,000 boe/d, an increase of approximately 21%. Production from the Eagle Ford represented approximately 36% of our Q3/2014 production.
Drilling results in the Eagle Ford have exceeded our initial expectations with wells drilled in 2014 outperforming the type curves upon which our acquisition evaluation was based. The evaluation was based on 30-day initial production rates of 800 to 1,000 boe/d. Through the first eight months of 2014, a total of 22.3 net wells have been drilled and placed on production for more than 30 days. For these wells, we are seeing an approximate 20% improvement in 30-day initial production rates. This improved performance is driven by a combination of factors, including the drilling of longer horizontal laterals, tighter spacing of fracs and an increased amount of proppant per frac stage. These individual well economics provide some of the highest capital efficiencies in North America.
In Q3/2014, we participated in the drilling of 60 (14.9 net) wells and commenced production from 51 (14.4 net) wells. The capital expenditures for the Eagle Ford assets incurred during the quarter totaled $140.3 million.
We have also identified additional well locations to support future growth. 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 approximately 50% of our acreage. Furthermore, we are now piloting the drilling of up to four stacked horizons from a single pad, which, if successful, could lead to a further expansion of our drilling inventory.
During the third quarter, two new central processing facilities were commissioned, each capable of processing 20,000 bbl/d of oil and 60 mmcf/d of natural gas. This increases the total number of central processing facilities across our Eagle Ford assets to 15 and has contributed to a debottlenecking of production in the quarter. Planned maintenance on facilities is expected to occur during the fourth quarter.
In Canada, our operations and capital program remain on track with our full-year plans. Production in Canada averaged 56,709 boe/d (87% oil and NGL) in Q3/2014, essentially unchanged from Q3/2013.
Production from our Peace River area properties averaged approximately 26,500 boe/d in Q3/2014, essentially unchanged from Q3/2013. In Q3/2014, we drilled six (6.0 net) cold horizontal producers encompassing a total of 81 laterals in the Peace River area. We also received regulatory approval to implement a water flood pilot in the Bluesky reservoir in Harmon Valley. Construction of the required facilities commenced in Q3/2014 and we anticipate that water injection will begin in Q4/2014. This is our first water flood project in the Peace River area, which, if successful, could enhance our ultimate recoveries from the field.
In our Lloydminster heavy oil area, we continue to expand the use of multi-lateral drilling techniques. In Q3/2014, we drilled three (3.0 net) successful horizontal multi-lateral wells (one dual lateral well and two triple lateral wells). Initial results are showing an approximate 20% improvement in capital efficiencies through the use of multi-lateral drilling. We continue to monitor the performance of these wells and are planning for an expanded multi-lateral drilling program in the Lloydminster area for 2015.
At our Gemini steam-assisted gravity drainage (“SAGD”) pilot project, the 600 metre horizontal well pair averaged 850 bbl/d in Q3/2014, with peak oil rates exceeding 1,100 bbl/d. Since acquiring the Gemini acreage in 2013, we have drilled 21 stratigraphic test wells to further delineate our acreage position. At the time of initial acquisition, the Gemini project had regulatory approval for a 10,000 bbl/d SAGD facility. Consistent with our delineation plans, in Q4/2014 we will be filing the required regulatory amendment for our planned 5,000 bbl/d SAGD facility. The amendment will include the additional delineated lands as well as capture various facility modifications. While this regulatory step is necessary to progress the project, a final investment decision is contingent upon a full economic review and the outcome of the front end engineering study which is currently in progress.
We generated FFO of $298.0 million ($1.79 per basic share) during Q3/2014, representing an increase of 80% from Q2/2014 and 49% from Q3/2013. This level of FFO on both an absolute and per-share basis is the highest ever recorded by Baytex and reflects a strong contribution from our Eagle Ford assets and continued strong operational execution in Canada.
The average WTI price for Q3/2014 was US$97.17/bbl, representing a decrease of 6% from Q2/2014 and 8% from Q3/2013. The discount for Canadian heavy oil, as measured by the Western Canadian Select (“WCS”) price differential to WTI, averaged 21% in Q3/2014, as compared to 19% in Q2/2014 and 17% in Q3/2013. Our realized oil and NGL price of $79.91/bbl in Q3/2014 decreased by 2% from $81.74/bbl in Q2/2014 and 1% from $80.75/bbl in Q3/2013.
Subsequent to quarter-end, WTI has fallen to the US$80.00/bbl level due to lower than expected global demand, the return of Libyan exports and increased crude inventories. Offsetting to a certain degree the decline in WTI has been a strengthened market for WCS heavy oil and a decline in the Canadian dollar relative to the U.S. dollar. The WCS dollar differential for the October and November trade months averaged US$13.74/bbl and US$12.94/bbl, respectively, as compared to US$20.18/bbl in Q3/2014. The improvement in WCS pricing has been driven by increased refinery demand in the U.S. Midwest, a continued increase in crude by rail volumes and, more recently, expanded pipeline shipping capacity. The Canadian dollar has weakened from an average of 1.0893 (C$/US$) in Q3/2014 to its current level of approximately 1.1250 (C$/US$) in response to broad U.S. dollar strength through the wind down of U.S. quantitative easing.
Our Eagle Ford assets contributed positively to our overall operating netback in Q3/2014. Our Canadian operations generated an operating netback of $37.86/boe while the Eagle Ford generated an operating netback of $45.29/boe. On a combined basis (including North Dakota) we generated an operating netback (excluding financial derivatives) of $40.86/boe in Q3/2014. The table below provides a summary of our operating netbacks for the periods noted.
|Three Months Ended Sept. 30, 2014||Three Months Ended
Sept. 30, 2013
|($ per boe)||Canada||Eagle Ford||Total||Change|
|Sales Price||$67.93||$77.19||$72.04||$73.36||(2) %|
|Production and operating expenses||12.70||7.37||10.85||13.09||(17) %|
|Transportation expenses||3.92||1.50||2.90||3.09||(6) %|
|Operating netback||$37.86||$45.29||$40.86||$42.14||(3) %|
We employ risk mitigation strategies to reduce the volatility in our FFO. For Q4/2014, we have entered into hedges on approximately 51% of our net WTI exposure at a weighted average price of US$96.45/bbl. In addition, we have hedged approximately 36% of our net natural gas price exposure and 34% of our exposure to currency movements between the U.S. and Canadian dollars. For the first half of 2015, we have entered into hedges on approximately 37% of our net WTI exposure at a weighted average price of US$94.79/bbl, and approximately 11% at US$94.23/bbl for the second half of 2015.
As part of our hedging program, we are focusing on opportunities to mitigate the volatility in WCS price differentials by transporting crude oil to higher value markets by rail. Currently, approximately 60% of our heavy oil volumes are delivered to market by rail. Earlier this year, we entered into our first Brent-based fixed differential physical heavy oil sale. This six-month term rail contract runs from October 1, 2014 to March 31, 2015 and is expected to represent approximately 25% of our crude by rail volumes.
Total monetary debt at the end of Q3/2014 is $2.26 billion of which approximately $1.38 billion is comprised of long-term debt with no material repayments required until 2021. With approximately $600 million in undrawn capacity on existing credit facilities of approximately $1.2 billion, we have ample liquidity to allow us to execute our growth and income model.
We are committed to our growth and income business model and its three fundamental principles: delivering organic production growth, paying a meaningful dividend and maintaining capital discipline. When oil prices fall as they have in the past month, this can put stress on any business model. However, we believe we are well positioned to weather the current downturn. We have some of the strongest capital efficiencies across our portfolio which allows us to add production at relatively low capital costs per barrel and we are now directing over 90% of our capital to three resource plays which have among the highest capital efficiencies in North America. Our strong capital efficiencies benefit us as we require a lower percentage of our FFO to be reinvested to maintain our productive capacity.
While we have not finalized our plans for 2015, we have carried out various sensitivity analyses. A sensitivity analysis using a WTI price of US$80.00/bbl, an exchange rate of 1.12 (C$/US$) and a WCS differential of 18% provides some context to the current commodity price environment. Under these assumptions, we would expect to generate sufficient FFO to fund our sustaining capital requirements and the cash portion of our dividend. Over the long-term, our objective is to fund our capital expenditures and cash dividends with FFO. While this represents just one scenario, in a persistent low commodity price environment, we would initially look to reduce our capital expenditures to achieve this balance.
Our unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2014 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, October 30, 2014, starting at 9:00am MDT (11:00am EDT). To participate, please dial 416-340-9432 or toll free in North America 1-800-446-4472 and toll free international 1-800-2787-2090. Alternatively, to listen to the conference call online, please enter http://www.gowebcasting.com/6012 in your web browser.|
|An archived recording of the conference call will be available until November 6, 2014 by dialing toll free 1-800-408-3053 within North America (Toronto local dial 905-694-9451, International toll free 1-800-3366-3052) and entering reservation code 9252276. The conference call will also be archived on the Baytex website at http://www.baytexenergy.com/.|
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; our average production rate for the second half of 2014 and full-year 2014; our exploration and development capital expenditures for the second half of 2014 and full-year 2014; our Eagle Ford shale play, including our assessment of the performance of wells drilled in the Eagle Ford in 2014, initial production rates from new wells, our expectations that the Eagle Ford assets have the drilling inventory and infrastructure in place that support future growth, the potential to expand our drilling inventory by drilling up to four stacked horizons from a single well pad, the capital efficiency of our Eagle Ford wells relative to other North American projects and the timing of completion of planned maintenance on central processing facilities; our Peace River heavy oil resource play, including our plans to implement a water flood pilot, the timing of commencing water injection and the potential to enhance ultimate recovery from the field; our Lloydminster heavy oil properties, including the potential to improve capital efficiencies through the use of multi-lateral drilling techniques and our plans for an expanded multi-lateral drilling program in 2015; our Gemini steam-assisted gravity drainage project, including our assessment of the performance of the pilot project and our plans to file an application to amend the currently approved project; the outlook for Canadian heavy oil prices and the pricing differential between Canadian heavy oil and West Texas Intermediate light oil; 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; our liquidity and financial capacity; the sufficiency of our financial resources to fund our operations; the capital efficiency of our projects relative to other North American projects; our ability to continue to add production at relatively low capital costs per barrel and maintain our productive capacity by reinvesting a portion of our funds from operations; our ability to generate sufficient funds from operations in 2015 under specified pricing assumptions to fund our sustaining capital requirements and cash dividends on our common shares; and our objective, over the long-term, to fund our capital expenditures and cash dividends on our common shares with funds from 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. Although Baytex believes that the expectations and assumptions upon which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Baytex can give no assurance that they will prove to be correct.
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 reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; the amount of future cash dividends that we intend to pay; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). 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: failure to realize the anticipated benefits of the acquisition of the Eagle Ford assets; declines in oil and natural gas prices; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; variations in interest rates and foreign exchange rates; risks associated with our hedging activities; uncertainties in the credit markets may restrict the availability of credit or increase the cost of borrowing; refinancing risk for existing debt and debt service costs; access to external sources of capital; third party credit risk; a downgrade of our credit ratings; the cost of developing and operating our assets; risks associated with the exploitation of our properties and our ability to acquire reserves; increases in operating costs; changes in government regulations that affect the oil and gas industry; changes to royalty or mineral/severance tax regimes; risks relating to hydraulic fracturing; changes in income tax or other laws or government incentive programs; uncertainties associated with estimating petroleum and natural gas reserves; risks associated with acquiring, developing and exploring for oil and natural gas and other aspects of our operations; risks associated with properties operated by third parties; risks associated with delays in business operations; risks associated with the marketing of our petroleum and natural gas production; risks associated with large projects or expansion of our activities; risks related to heavy oil projects; expansion of our operations; the failure to realize anticipated benefits of acquisitions and dispositions or to manage growth; changes in environmental, health and safety regulations; the implementation of strategies for reducing greenhouse gases; competition in the oil and gas industry for, among other things, acquisitions of reserves, undeveloped lands, skilled personnel and drilling and related equipment; the activities of our operating entities and their key personnel and information systems; depletion of our reserves; risks associated with securing and maintaining title to our properties; seasonal weather patterns; our permitted investments; access to technological advances; changes in the demand for oil and natural gas products; involvement in legal, regulatory and tax proceedings; the failure of third parties to comply with confidentiality agreements; risks associated with the ownership of our securities, including the discretionary nature of dividend payments and changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond the control of Baytex. These 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, 2013, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.
Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.
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 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.
Oil and Gas Information
References herein to initial test production rates, 30-day IP 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. 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.
When converting volumes of natural gas to oil equivalent amounts, Baytex has adopted a conversion factor of six million cubic feet of natural gas being equivalent to one barrel of oil, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Oil equivalent amounts may be misleading, particularly if used in isolation.
Non-GAAP Financial Measures
Funds from operations is not a measurement based on 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. Baytex defines 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)), the principal amount of long-term debt and long-term bank loans. Baytex believes that this measure assists in providing a more complete understanding of its 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 sales price less royalties, production and operating expenses and transportation expenses divided 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 by other entities. Baytex believes that this measure assists in characterizing our ability to generate cash margin on a unit of production basis.
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 85% 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.
Senior Vice President, Capital Markets and Public Affairs
Toll Free Number: 1-800-524-5521