Investor Relations

MESSAGE TO SHAREHOLDERS  

Q3 2011 Message to Shareholders

2010 Year-End Message to Shareholders

Q3 2011 Message to Shareholders 

Operations Review

Production averaged 52,625 boe/d during the third quarter of 2011, as compared to 44,799 boe/d in the third quarter of 2010 and 47,853 boe/d in the second quarter of 2011. Oil-equivalent production increased by 17% from the third quarter of 2010, with oil and natural gas liquids ("NGL") production 25% higher and natural gas production 12% lower. Oil equivalent production increased by 10% from the second quarter of 2011, with oil and NGL production 11% higher and natural gas production 3% higher.

Capital expenditures for exploration and development activities totaled $100.4 million for the third quarter of 2011. During the third quarter, Baytex participated in the drilling of 48 (39.4 net) wells, resulting in 46 (37.4 net) oil wells and two (2.0 net) service wells for a 100% success rate.

In our Lloydminster heavy oil area, we drilled 19 (19.0 net) oil wells and two (2.0 net) service wells. In our Seal heavy oil area, we drilled seven (7.0 net) horizontal cold production wells. In our light oil and gas areas in western Canada, we drilled 15 (9.9 net) oil wells. We drilled five (1.5 net) oil wells in our Bakken/Three Forks play in North Dakota.

Our previous production guidance for 2011 was a range of 49,500 to 50,500 boe/d. Based on production performance for the first nine months of 2011, we can now narrow our full-year 2011 guidance to a range of 50,000 to 50,500 boe/d. We continue to project that our production mix will be comprised of approximately 70% heavy oil, 14% light oil and NGL and 16% natural gas. Our exploration and development capital budget for 2011 remains at $355 million. We plan to provide production and capital budget guidance for 2012 on or about December 6, 2011, following approval of our 2012 development plan by our Board of Directors.

Heavy Oil

In the third quarter of 2011, heavy oil production averaged 37,280 bbl/d, an increase of 29% over the third quarter of 2010 and 10% over the second quarter of 2011. During the third quarter of 2011, we drilled 26 (26.0 net) oil wells and two (2.0 net) service wells on our heavy oil properties for a success rate of 100%.

Production from our Seal properties averaged approximately 17,800 bbl/d, an increase of 24% from the second quarter of 2011. In the third quarter of 2011, we drilled seven (7.0 net) cold horizontal producers at Seal, including our first drilling on the Reno-area properties acquired earlier this year. Our most common multi lateral well design includes eight approximately 1,400 meter-long laterals, which are often augmented with several shorter "stubby" laterals to drain the region around the intermediate casing point to the starting point of the 1,400 meter-long laterals. Three of the wells drilled in the third quarter and two of the wells drilled in the second quarter established average 30-day peak production rates of approximately 340 bbl/d per well. Although we have not yet recorded a 30-day peak production rate on any wells drilled on the lands acquired at Reno earlier this year, the first two wells drilled have initial production rates averaging approximately 375 bbl/d per well, based on the first two weeks of production. The two Reno wells had an average of six full-length horizontal laterals per well, plus an average of four "stubbies" per well. During the remainder of 2011, we plan to drill approximately five additional multi lateral cold horizontal wells at Seal.

In our Cliffdale cyclic steam stimulation ("CSS") project at Seal, we continued production operations during the pilot well's third cycle. Consistent with our numerical reservoir simulation, we project a steam-oil ratio ("SOR") of approximately 1.9 for this cycle. Four additional CSS-project wells drilled in the first quarter continued pre-steam cold production in the third quarter at rates of approximately 20 bbl/d per well, while awaiting completion of our steam generation facility. We have now received regulatory approvals to install oil and water handling facilities and steam distribution piping at our Cliffdale facility. Construction has commenced, and we expect to begin steam injection late in the fourth quarter of 2011. To complete our first 10-well commercial CSS module, we also plan to drill an additional five horizontal CSS wells in the fourth quarter of 2011.

At our Kerrobert steam assisted gravity drainage ("SAGD") project, the well pair which commenced production in October 2010 continues to operate at oil rates in excess of 800 bbl/d. Two additional SAGD well pairs were drilled during the second quarter and placed on production in the third quarter at average rates of approximately 950 bbl/d per well. Current SOR for the Kerrobert SAGD project is 2.4. We drilled two stratigraphic test wells in the third quarter and plan to drill two additional stratigraphic test wells in the fourth quarter to optimize the placement of future SAGD well pairs. Design work is being conducted for steam plant expansion to allow the drilling of additional SAGD well pairs.

Light Oil & Natural Gas

During the third quarter of 2011, light oil, NGL and natural gas production averaged 15,345 boe/d, which was comprised of 7,170 bbl/d of light oil and NGL and 49.0 mmcf/d of natural gas. Compared to the third quarter of 2010, light oil and NGL production increased by 9% and natural gas production declined by 12%. Compared to the second quarter of 2011, light oil and NGL production increased by 18% and natural gas production increased by 3%.

In the third quarter of 2011, we drilled five (4.0 net) Viking multi lateral wells in eastern Alberta. Two of the wells drilled in the third quarter and two of the wells drilled in the second quarter established average 30-day peak rates of approximately 120 bbl/d per well. We plan to drill two more Viking light oil horizontal wells in eastern Alberta in the fourth quarter of 2011.

We drilled three Viking light oil horizontal wells in Saskatchewan in the third quarter, two of which were fracture stimulated and commenced production early in the fourth quarter but have not yet established 30-day peak rates. One of the Saskatchewan Viking wells was an unstimulated five-lateral well which had a 30-day peak production rate of approximately 20 bbl/d.

We participated in seven (2.9 net) Cardium light oil horizontal wells in the third quarter, two of which were operated. The operated wells will be fracture stimulated and put on production in the fourth quarter.

In our Bakken/Three Forks play in North Dakota, in the third quarter we participated in the drilling of five (1.5 net) horizontal oil wells, four of which were Baytex operated, and the fracture stimulation of six wells. During the third quarter, three operated 640-acre spacing wells established average 30-day peak production rates of 350 bbl/d per well and one operated 1,280-acre spacing well established an average 30-day peak production rate of 430 bbl/d. We plan to participate in the drilling of approximately seven (2.0 net) additional Bakken/Three Forks wells in the fourth quarter.

Acquisition and Divestiture Activity

As previously announced, in the third quarter we closed the acquisition of predominantly natural gas assets located in the Brewster area of west-central Alberta. Prior to the acquisition, we had non-operated interests in most of these assets. As a result of the acquisition, we are now the operator of all of the acquired assets. The total consideration for the acquisition (net of adjustments) was $22.4 million, which was funded by drawing on our credit facilities. The purchase price is a multiple of approximately three times projected net operating income from the acquired properties for 2011. The acquired assets are producing approximately 800 boe/d of production (80% natural gas). We estimate remaining proved plus probable reserves to be approximately 2.5 million boe. The acquired assets include 72,000 net acres of undeveloped land, a 64 kilometer gathering system and two compressor stations.

Subsequent to the end of the third quarter, we entered into and closed the sale of six sections of leasehold, including five sections with Duvernay rights, in the Kaybob South area of west central Alberta for $11.1 million. Five of the six sections faced lease expiry within the next year. There is no production on the divested lands.

Subsequent to the end of the third quarter, we entered into a definitive agreement to sell approximately 32,600 net acres of leasehold in the "halo" of the Dodsland field in southwest Saskatchewan for $36 million. As at December 31, 2010, the properties had booked proved plus probable reserves of approximately 1.5 million boe (9% proved developed producing). Current production from the lands is approximately 60 bbls/day. This disposition is expected to close on or about November 25, 2011. After the sale, we will continue to hold significant undeveloped land for Viking light oil development in the Kerrobert and Whiteside areas of southwest Saskatchewan.

Financial Review

The financial statements for the third quarter of 2011 have been prepared in accordance with International Financial Reporting Standards ("IFRS"). Comparative periods in 2010 have been restated to conform to IFRS presentation. Reconciliations from IFRS to the previously reported financial results are shown in the notes to our interim condensed consolidated financial statements. The adoption of IFRS did not have a material impact on the amounts reported as FFO.

We generated FFO of $145 million ($1.24 per basic share) in the third quarter of 2011, an increase of 31% compared to the third quarter of 2010, and an increase of 5% compared to the second quarter of 2011. The increase in FFO relative to the second quarter of 2011 is primarily the result of increased sales volumes which more than offset the lower commodity prices realized in the third quarter. Consistent with our practice prior to the adoption of IFRS, FFO is presented net of financing costs, which totaled $10.4 million in the third quarter.

The average WTI price for the third quarter of 2011 was US$89.76/bbl, an 18% increase from the third quarter of 2010, and a 12% decrease from the second quarter of 2011. We received an average oil and NGL price of $63.26/bbl in the third quarter of 2011 (inclusive of our physical hedging gains), up from $58.93/bbl for the third quarter of 2010 and down from $73.78/bbl for the second quarter of 2011. We received an average natural gas price of $4.20/mcf in the third quarter of 2011, a modest decrease from the second quarter of 2011.

The discount for Canadian heavy oil, as measured by the Western Canadian Select ("WCS") price differential to WTI, averaged 19.6% for the third quarter of 2011, as compared to 20.6% in the third quarter of 2010 and 17.2% in the second quarter of 2011. Looking forward, demand for Canadian heavy oil by US refiners in the midcontinent region is expected to increase in late 2011 through 2013 with the commissioning of heavy oil refining projects in the region. The impact of those refining projects is already being noted in the market, as the current heavy oil differential is approximately 12% of WTI, and the forward markets are suggesting similar levels for the first half of 2012.

Baytex continues to actively hedge its exposure to commodity prices, heavy oil differentials and interest and foreign exchange rates with the objective of reducing the volatility of its funds from operations, which are used to finance capital expenditures and dividend payments. Contracts currently in place have locked in pricing on approximately 24% of our 2012 WTI price, 22% of our heavy oil differential exposure, 32% of our natural gas price exposure, and 19% of our exposure to currency movements between the Canadian and US dollar. Details of those contracts are contained in the notes to our interim condensed consolidated financial statements. We continue to monitor the markets for opportunities to add to this hedging program for 2012 and later years.

At the end of the third quarter of 2011, total monetary debt was $739 million and undrawn credit facilities were $332 million. This level of debt represents a debt-to-FFO ratio of 1.4 times, based on trailing twelve months FFO. This level of debt and undrawn credit facilities are within our leverage and liquidity targets, and provide ample capacity to finance our operations.

Conclusion

We continued to execute our sustainable growth-and-income model in the third quarter of 2011.

We maintained our record of continuous production growth that has been in place since the beginning of 2009. Oil production was particularly strong, with a 10% increase over the second quarter of 2011 and a 17% increase over the third quarter of 2010. Together with the monthly income provided by our dividends, we think that our oil growth can be a meaningful contributor to our total return to shareholders.

We announced two minor divestitures of largely undeveloped land, one of which has already closed. These divestitures, coupled with occasional acquisitions, reflect our practice of continuously evaluating and improving the suitability and quality of our asset portfolio. The proceeds from these divestitures will reduce our leverage ratios, helping to maintain our conservative financial structure.

With respect to mid-stream infrastructure, although a decision by the U.S. Government regarding TransCanada's Keystone XL Pipeline has been delayed, there are competing proposals that have the potential to move Canadian heavy oil into the U.S. Gulf Coast market. While we await these longer-term pipeline projects, new initiatives in the form of rail and pipeline reversals are helping to maintain a positive outlook for heavy oil differentials.

It remains an honour to serve you, and we want to express our appreciation for your continued support as we move forward in executing our plan for long-term value creation.

On behalf of the Board of Directors,
 

Anthony Marino
President and Chief Executive Officer
November 10, 2011

 

Forward-Looking Statements 

This webpage contains forward-looking statements relating to: our average production rate for 2011; our product mix for 2011; our exploration and development capital expenditures for 2011; initial production rates from wells drilled; development plans for our properties, including the number of wells to be drilled in the fourth quarter of 2011; our Cliffdale cyclic steam stimulation project at Seal, including our assessment of the results of the third steam injection cycle for our pilot well, the steam-oil ratio for the third steam injection cycle and the completion of a 10-well commercial module of CSS development, including the commencement of steam injection into four additional wells and the drilling of five additional CSS wells; our Kerrobert steam assisted gravity drainage project, including the steam-oil ratio, our ability to optimize the placement of SAGD well pairs by drilling stratigraphic test wells and the expansion of the steam plant; the natural gas-weighted acquisition in west-central Alberta, including the 2011 net operating income from the acquired assets and the remaining proved plus probable reserves attributable to the acquired assets; the completion of the disposition of assets in the Dodsland area of Saskatchewan; the demand for Canadian heavy oil by U.S. refiners; the outlook for the pricing differential between Canadian heavy oil and West Texas Intermediate; the existence, operation and strategy of our risk management program for commodity prices, heavy oil differentials and interest and foreign exchange rates; the amount of our undrawn credit facilities at September 30, 2011; our debt to FFO ratio; 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. The level of future cash dividends will depend on the amount of funds from operations generated by our operations and our prevailing financial circumstances at the time. We refer you to our advisory regarding forward-looking statements which is contained on pages 27-28 of our Q3 2011 Report. To view this document, please click here.

Non-GAAP Financial Measures

This webpage contains references to certain measures that are commonly used in the oil and gas industry but are not based on generally accepted accounting principles in Canada, such as funds from operations and total monetary debt. For a description of these measures, we refer you to "Non-GAAP Financial Measures" on page 8 of our Q3 2011 Report. To view this document, please click here.

2010 Year-End Message to Shareholders 

We are pleased to report our 2010 results to our shareholders. In 2010, we achieved record levels of production, reserves and funds from operations. Operationally, we continued to advance several key projects that should provide reliable and diversified growth in the coming years. We also recorded another year in which we replaced more than 100% of our annual production with reserves developed by our organic exploration and development ("E&D") investment activities. Finally, our balance sheet continued to improve, maintaining our financial position as one of the strongest in our sector.

We were fortunate to deliver, for the second consecutive year, the strongest total market return performance among our peer group. This market recognition again leaves us honoured, and also determined to continue to focus on delivering sustainable income and growth to our shareholders.

We crossed an important milestone at the end of 2010. Effective December 31, we converted our legal structure from an income trust to a corporation, returning to the legal form that Baytex used in its original incarnation from 1993 to 2003. We pledge to our shareholders that we will remember the lessons of capital efficiency we learned in our seven years as an income trust. We will do our best to even more effectively execute our growth and income model as Baytex Energy Corp.

Operations Review

Production averaged 45,015 boe/d in the fourth quarter of 2010, and 44,341 boe/d for the full year, a 7% increase over 2009. Production increased each quarter during 2010, with the fourth quarter marking our eighth consecutive quarter of production growth. With respect to product mix, Baytex is one of the most oil-weighted entities in the North American energy industry, with 83% of our production and 91% of our reserves represented by heavy oil, light oil and natural gas liquids.

Our 2010 capital expenditures ("CAPEX") for E&D activities increased 51% from 2009 levels, reflective of both the end of the economic recession and higher growth rates for Baytex. Spending for E&D totaled $237 million, with the majority directed toward heavy oil projects. During the year, Baytex participated in the drilling of 155 gross (118.2 net) wells on our heavy oil, light oil and natural gas properties, generating a 97% success rate.

Our total capital program for 2010, including acquisitions net of dispositions, amounted to $284 million, about 2% less than in 2009. We only pursue acquisitions that meet three criteria: value accretion for our existing shareholders, growth potential for the acquired assets, and operating control and capability by Baytex. As a result of these restrictive criteria, we are not a frequent acquirer, and 2010 was a year of lower acquisition activity. Subsequent to year-end 2010, we did, however, close an accretive acquisition of heavy oil assets in the Seal and Lloydminster areas in February 2011 (the "2011 Heavy Oil Acquisition").

This CAPEX program allowed Baytex to increase its reserve base in both proved and probable reserve categories for the seventh consecutive year. At year-end 2010, our proved plus probable reserves, as evaluated by Sproule Associates Limited, reached 229 million boe. This reserve total represents a 13.2 year reserve life index based on our expected production rates for 2011. Neither these reserve levels nor reserve life index take into account the 2011 Heavy Oil Acquisition.

We released a contingent resource assessment prepared by Sproule Associates Limited for three of our resource plays (Seal, Bakken/Three Forks and Viking). At year-end 2010, the estimate of contingent resource ranged from 528 million barrels of oil and bitumen in the "Low Estimate" to 1.02 billion barrels of oil and bitumen in the "High Estimate", with a "Best Estimate" of 668 million barrels of oil and bitumen. During 2010, our E&D activities converted 17 million barrels of contingent resource into proved reserves and 42 million barrels of contingent resource into proved plus probable reserves.

Baytex continued to record strong CAPEX efficiencies in 2010. Finding, development and acquisition costs were $5.90/boe on a proved plus probable basis (excluding changes in future development costs), resulting in a recycle ratio of 5.6 times. Our strong capital efficiency is further demonstrated by replacement of 271% of the year's production through E&D, while reinvesting only 52% of funds from operations ("FFO") into E&D activities. Including acquisitions, we replaced 297% of our 2010 production while investing 62% of FFO. These results are consistent with our long-term performance in capital efficiency. Our five-year average finding, development and acquisition cost of $9.59/boe (excluding changes in future development costs), recycle ratio of 3.1 times and reserve replacement ratio of 225% all rank among the best in our industry.

At Seal in the Peace River oil sands region, we drilled 15 new cold horizontal producers, continuing our record of 100% drilling success and increasing production from this important growth property to more than 10,000 bbl/d by the end of 2010. We advanced our use of multi lateral horizontal wells at Seal to increase cold production rates and recoveries, and to further improve our capital efficiencies. During 2010, we conducted a second cyclic steam stimulation ("CSS") pilot, which we believe noteworthy because it was a multi cycle test and was implemented in a part of Seal where there was no prior cold development. We plan to install our first commercial thermally enhanced oil recovery project at Seal in 2011. We also drilled seven stratigraphic test wells to further delineate our land base for both cold and thermal development in the years ahead.

Production from our Lloydminster core heavy oil area was basically unchanged from 2009 levels as drilling, recompletion of existing wells and a small corporate acquisition in the second quarter of 2010 offset natural production declines. Our thermal operations continue to expand in the Lloydminster area, including the drilling and completion of a new steam assisted gravity drainage well pair in late 2010 which was producing over 1,000 bbl/d in early March 2011.

We continued to pursue several light oil growth projects of long-term importance. The Bakken Three Forks play in North Dakota and the Viking play in Alberta and Saskatchewan utilize horizontal wells, most often with multiple hydraulic fracture stimulations, to induce light oil production from low permeability reservoirs. These plays contain very large volumes of light oil resource in place and have the potential, over time, to generate significant increases in Baytex's light oil production and reserves. We assembled these new light oil resource plays with three objectives in mind: value accretion to our shareholders, enhancement of our overall growth rate and diversification of our long-term product and project mix. These light oil resource plays complement the growth of our heavy oil projects at Seal and Lloydminster.

In the Bakken Three Forks in Divide and Williams Counties, North Dakota, we expanded our land base to approximately 125,000 net acres during 2010. Drilling activity will continue to increase in 2011, as we drill a mix of well lengths that is increasingly oriented to two-mile long horizontal wells, which have exhibited initial production rates of approximately 400 bbl/d per well.

In our Viking play in Alberta, we drilled seven successful multi lateral horizontal wells (without hydraulic fracturing) with an average initial production rate of approximately 100 bbl/d per well. During 2011, we plan to continue with this type of development activity in the Viking in Alberta, as well as use single lateral horizontal wells with multi stage hydraulic fracturing in our Viking project in Saskatchewan.

Financial Review

We are encouraged by our operating results and CAPEX efficiencies, and it is through these measures that we seek to differentiate ourselves from our competitors. Our success in these areas has allowed us to successfully execute our growth and income model in a variety of commodity price environments.

West Texas Intermediate ("WTI") oil price for 2010 averaged US$79.53/bbl, an increase of 29% from the average for 2009. Because WTI prices are denominated in US dollars, a strengthening Canadian currency partially reduced the positive impact of the oil price recovery for Canadian producers. The Canadian dollar rose to an average of US$0.97 during 2010, an increase of 11% over 2009. For some time, we have been of the view that the Canadian currency was likely to strengthen versus the US dollar, and put in place currency hedges to protect about 39% of our foreign exchange exposure for 2010, thereby reducing the impact of the stronger Canadian dollar on our 2010 FFO. As we will discuss later, we have also arranged our debt structure to mitigate our exposure to a weaker US dollar.

We are fortunate to be particularly weighted to heavy oil, which has benefitted for the past few years from a narrowing of differentials and reduced volatility as compared to WTI. This long-term improvement in heavy oil differentials is the result of a number of North American and global supply/demand factors, including increased demand from refineries in both North America and Asia that have been reconfigured to process more heavy oil, reduced output of heavy oil by traditional suppliers such as Mexico, and increased pipeline capacity to US markets.

The heavy blend benchmark, Western Canadian Select ("WCS"), sold at an 18% discount to WTI during 2010, as compared to a 16% discount during 2009. This modestly higher WCS discount was primarily due to transportation constraints resulting from service disruptions on two oil export pipelines, which temporarily curtailed oil shipments to US refineries and resulted in wider price differentials for all Canadian crude oil grades during the second half of 2010. During the fourth quarter of 2010, these pipelines were repaired and deliveries resumed. As of this writing, the forward strip suggests a WCS differential of approximately 20% for the April to December 2011 period, resulting in wellhead prices for heavy oil that are yielding very high rates of return on our investment program.

Natural gas prices remained depressed during 2010. The average price for natural gas at the AECO hub was $4.13 per mmBtu, essentially unchanged from 2009. With only 10% of our revenue coming from natural gas in 2010, fluctuations in natural gas prices had a minor impact on our FFO.

Operating expenses decreased for the second consecutive year despite increases in costs for fuel and oilfield services. For 2010, our operating expense averaged $10.62/boe, a 2% decrease from 2009. Transportation expense decreased by 9% to $2.92/boe as a result of optimization of delivery points for our production from Seal. General and administrative expense ("G&A") expenses increased 6% to $2.46/boe. We do not capitalize any G&A costs, and our G&A expense has consistently been at or below the average for our peer group.

FFO for 2010 was our highest ever at $454 million, an increase of 37% from 2009. Despite fluctuations in commodity prices during the year, FFO increased each quarter during 2010, from a low of $107 million in the first quarter to a high of $125 million in the fourth quarter. As is the case with production, FFO has grown for eight consecutive quarters.

As a result of the improvement in commodity prices and our strong operating results, we increased our monthly distribution from $0.18 to $0.20 per unit in December 2010. As a corporation, we will continue to pay monthly dividends, with our initial dividend level set at $0.20 per share. Cash distributions for 2010 were $190 million, bringing our cumulative cash distributions to $1.1 billion since trust inception in 2003.

Our payout ratio for 2010 averaged 42%, net of participation in our distribution reinvestment plan. Importantly, we were able to fully fund our E&D CAPEX and cash distributions from FFO, which we consider a key measure of the sustainability of our growth and income model. At our current monthly dividend of $0.20 per share, our payout ratio (net of participation in our dividend reinvestment plan) is forecast to be approximately 36% for 2011, based on the commodity price strip from early March 2011.

Total monetary debt at year-end 2010 was $502 million, which represented a debt-to-FFO ratio of 1.1 times based on 2010 FFO. Pro forma the 2011 Heavy Oil Acquisition, our debt-to-FFO ratio is 1.1 times based on projected 2011 FFO (using the commodity price strip from early March 2011).

The majority of our debt is represented by drawings on our reserve based revolving credit facilities, which are provided by a syndicate of nine banks from Canada, the US and Europe. We are also pleased to note that our banking syndicate increased our credit facilities to $550 million in June 2010, to $625 million in January 2011, and to $650 million in February 2011 (following the closing of the 2011 Heavy Oil Acquisition).

In February 2011, our financial strength was further enhanced when we issued US$150 million of 6.75% ten-year senior unsecured debentures in the Canadian non-investment grade bond market. Our issue was the first US dollar denominated issue of its type in this developing debt market. We used the proceeds from the sale of the debentures to reduce Canadian dollar borrowings on our revolving credit facilities. The US dollar debt issue provides a partial hedge against further weakness in the US dollar relative to the Canadian dollar. Pro forma the debenture issue and the reduction in bank debt, our undrawn credit facilities are approximately $335 million, representing greater than 50% of the total credit facilities. Our new US dollar denominated Canadian debt issue and our history as an issuer in the Canadian and US bond markets illustrate our capability to access the debt markets should we have a need for external financing.

Outlook

My main message to you is that we intend to follow the same strategy as Baytex Energy Corp. that we have for the past few years as Baytex Energy Trust. Internally within Baytex, we intend to keep our organization as technically focused and as non-bureaucratic as possible. In terms of external communication, we pledge to continue to communicate with our shareholders in a complete and forthright manner. As in the past, we will emphasize organic growth, occasionally augmented by accretive acquisitions that bring their own enhancements to our future organic growth profile.

We remain committed to providing a combination of growth and income to the owners of our company. We are sometimes asked why a company with so many high-return projects chooses to pay a dividend. It is our view that the income component of our total return has several advantages for our shareholders. We believe that a dividend paying stock reduces investment risk by stabilizing a portion of total return. Our market assessment is that dividends meet the income needs of many investors and are, as a result, desired by a large segment of the equity market. We believe that a combination of income and growth will offer the most reliable path to long-term total return. Finally, as we learned in the trust era, returning a portion of our cash flow stream to investors helps keep companies disciplined in capital investment decisions - a critical element of success in a capital intensive business like oil and gas.

The market rewarded our disciplined approach with an energy trust sector leading total market return of 67% during 2010, including both appreciation of our unit price and reinvestment of distributions. This was the second consecutive year we led the energy trust sector in total return. Our total return over our seven-year tenure as a trust was 876%, the highest in the sector, and significantly higher than the 206% return of the S&P/TSX Capped Energy Trust Index and the 230% return of the corporate S&P/TSX Oil & Gas E&P Index over the same period.

In our first year as a corporation, our capital budget of $325 million for E&D is designed to generate average production of 49,000 to 50,000 boe/d (including the pro-rated impact of the 2011 Heavy Oil Acquisition), an increase of approximately 10% over 2010. Based on the current commodity price strip, we expect to generate sufficient FFO in 2011 to fully fund our E&D CAPEX and our dividends.

I can assure you that Baytex's management and staff, led by our Board of Directors, will continue to work hard on behalf of our shareholders in our new corporate era. It remains an honour to serve you, and we want to express our appreciation for your continued support as we move forward in executing our plan for long-term value creation.

On behalf of the Board of Directors,
 

Anthony Marino
President and Chief Executive Officer
March 15, 2011

 

Forward-Looking Statements 

This webpage contains forward-looking statements relating to: our business strategies, plans and objectives; our ability to grow our reserve base and add to production levels through exploration and development activities complemented by strategic acquisitions; contingent resource estimates and the assumptions relating thereto; our heavy oil resource play at Seal, including our ability to improve production rates, recoveries and capital efficiencies through enhanced development techniques and the timing of completing a thermally-enhanced oil recovery project; our Bakken/Three Forks and Viking light oil resource plays, including their resource potential and their potential to grow our light oil production and reserves; initial production rates from new wells; the pricing differential between Western Canadian Select and West Texas Intermediate crude oils; our dividend policy and level; our payout ratio for 2011; our debt-to-funds from operations ratio; our liquidity and financial capacity; our exploration and development capital expenditures for 2011; our average production rate for 2011; and our ability to fund our capital expenditures and dividends from funds from operations in 2011. 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. The level of future cash dividends will depend on the amount of funds from operations generated by our operations and our prevailing financial circumstances at the time. These forward-looking statements are based on certain key assumptions and are subject to numerous known and unknown risks and uncertainties and other factors. We refer you to our advisory regarding forward-looking statements which is contained on page 30 of our 2010 Annual Report. To view this document, please click here.

Contingent Resources

This web page contains estimates of "contingent resources". "Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined in the Canadian Oil and Gas Evaluation Handbook as "those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage." There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Baytex will produce any portion of the volumes currently classified as contingent resources. A "best estimate" of contingent resources means that it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate, and if probabilistic methods are used, there should be at least a 50% probability that the quantities actually recovered will equal or exceed the best estimate.

The recovery and resource estimates provided herein are estimates only. Actual contingent resources (and any volumes that may be reclassified as reserves) and future production from such contingent resources may be greater than or less than the estimates provided herein.

Non-GAAP Financial Measures

This webpage contains references to certain measures that are commonly used in the oil and gas industry but are not based on generally accepted accounting principles in Canada, such as funds from operations and total monetary debt. For a description of these measures, we refer you to "Non-GAAP Financial Measures" on page 9 of our 2010 Annual Report. To view this document, please click here.