Baytex Energy Trust

Baytex Energy Trust

November 10, 2009 09:01 ET

Baytex Energy Trust Announces Third Quarter 2009 Results

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2009) - Baytex Energy Trust ("Baytex") (TSX:BTE.UN) (NYSE:BTE) is pleased to announce its operating and financial results for the three months and nine months ended September 30, 2009 (in Canadian dollars unless otherwise denoted).


- Generated funds from operations of $88.8 million ($92.2 million before deducting $3.4 million of transaction costs relating to the issuance of long-term notes during the quarter) an increase of 2% (6% before transaction costs for long-term notes issuance) over the prior quarter or $0.83 per basic unit ($0.86 per basic unit before transaction costs for long-term notes issuance) for the third quarter of 2009;

- Produced an average of 42,623 boe/d in the quarter, a record quarterly production level, and an increase of 6% over Q2/09;

- Completed an acquisition of predominantly heavy oil assets at accretive metrics with current production of approximately 3,000 boe/d for a net purchase price of $86.5 million;

- Reached agreement to pre-pay the remaining deferred acquisition payments for our Bakken-Three Forks lands in North Dakota subsequent to the end of the third quarter, providing greater and accelerated operating control as we continue to develop this light oil resource play;

- Issued $150 million in senior unsecured debentures, and redeemed US$180 million of senior subordinated notes; and

- Delivered total market return (assuming reinvestment of distributions) of 22.4% in the third quarter (73.1% for nine months ended September 30, 2009).

Three Months Ended Nine Months Ended
September 30, June 30, September 30, September 30, September 30,
2009 2009 2008 2009 2008
of Canadian
except per
unit amounts)
Petroleum and
natural gas
sales 208,229 192,667 363,044 551,839 959,828
Funds from
operations (1) 88,809 86,661 146,586 234,842 373,351
Per unit -
basic 0.83 0.82 1.53 2.26 4.16
Per unit -
diluted 0.80 0.81 1.47 2.23 3.94
Cash distributions
declared 32,799 32,569 57,233 100,315 141,712
Per unit 0.36 0.36 0.75 1.14 1.96
Net income 40,657 27,451 137,228 59,618 207,493
Per unit -
basic 0.38 0.26 1.44 0.57 2.31
Per unit -
diluted 0.37 0.26 1.39 0.57 2.23
Exploration and
development 36,477 30,278 48,584 114,419 142,114
Acquisitions - net
of dispositions 93,662 2,348 78,635 95,994 256,925
Total capital
expenditures 130,139 32,626 127,219 210,413 399,039

Long-term notes 150,000 209,187 190,725 150,000 190,725
Bank loan 272,918 154,171 200,445 272,918 200,445
debentures 8,799 10,053 10,377 8,799 10,377
Working capital
deficiency 34,536 38,500 56,446 34,536 56,446
Total monetary
debt (2) 466,253 411,911 457,993 466,253 457,993

Daily production
Light oil & NGL
(bbl/d) 7,021 7,073 8,377 7,071 7,498
Heavy oil
(bbl/d) 25,532 23,284 24,078 24,090 23,159
Total oil
(bbl/d) 32,553 30,357 32,455 31,161 30,657
Natural gas
(MMcf/d) 60.4 60.2 60.5 58.6 53.9
Oil equivalent
(boe/d @ 6:1)
(3) 42,623 40,387 42,538 40,934 39,635

Average prices
(before hedging)
WTI oil
(US$/bbl) 68.18 59.51 118.36 56.98 113.43
Edmonton par oil
($/bbl) 71.70 58.26 122.66 62.79 115.93
BTE light oil
& NGL ($/bbl) 57.50 54.28 107.41 51.63 100.66
BTE heavy oil
($/bbl) (4) 55.12 51.19 84.65 47.11 74.63
BTE total oil
($/bbl) 55.64 51.91 90.56 48.15 80.94
BTE natural gas
($/Mcf) 3.42 3.85 8.01 4.18 8.23
BTE oil
($/boe) 47.27 44.78 80.44 42.61 73.84

USD/CAD noon
rate at period
end 0.9327 0.8602 0.9435 0.9327 0.9435
USD/CAD average
rate for
period 0.9113 0.8568 0.9600 0.8547 0.9818

Unit price (Cdn$)
High $25.35 $ 20.18 $ 35.01 $ 25.35 $ 35.37
Low $17.80 $ 14.89 $ 23.15 $ 9.77 $ 16.30
Close $23.60 $ 19.59 $ 25.73 $ 23.60 $ 25.73
Volume traded
(thousands) 24,885 25,453 31,620 89,326 92,150
Unit price (US$)
High $23.69 $ 18.42 $ 35.20 $ 23.69 $ 35.20
Low $15.20 $ 11.76 $ 22.35 $ 7.84 $ 15.88
Close $22.04 $ 16.83 $ 24.71 $ 22.04 $ 24.71
Volume traded
(thousands) 5,778 9,426 10,240 27,748 20,016

Units outstanding
(thousands) 107,777 106,988 96,934 107,777 96,934

(1) Funds from operations is a non-GAAP term that represents cash generated
from operating activities before changes in non-cash 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 distributions and capital
investments. For a reconciliation of funds from operations to cash flow
from operating activities, see Management's Discussion and Analysis of
the operating and financial results for the three months and nine months
ended September 30, 2009.
(2) Total monetary debt is a non-GAAP term which we define to be the sum of
monetary working capital (which is current assets less current
liabilities (excluding non-cash items such as future income tax assets
or liabilities and unrealized financial instrument gains or losses)),
the principal amount of long-term debt and the balance sheet value of
the convertible debentures.
(3) 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.
(4) Heavy oil wellhead prices are net of blending costs.

Operations Review

Capital expenditures for exploration and development activities totaled $36.5 million for the third quarter of 2009. During this quarter, Baytex participated in the drilling of 33 (27.8 net) wells, resulting in 31 (26.8 net) oil wells and two (1.0 net) service wells, for a 100% success rate. Third quarter drilling included 20 (17.4 net) oil wells in the Lloydminster area, eight (8.0 net) oil wells at Seal, three (1.4 net) oil wells in the United States, and two (1.0 net) service (air injection) wells in a non-operated project at Kerrobert.

Baytex closed the acquisition of certain oil and gas assets located primarily in the Kerrobert and Coleville areas of Saskatchewan on July 30, 2009. The predominantly heavy oil assets have performed as expected, with production of approximately 3,000 boe/d since closing (contributing approximately 2,000 boe/d to average production in the third quarter).

Production averaged 42,623 boe/d during the third quarter of 2009, as compared to 40,387 boe/d in the second quarter. Production was slightly above guidance of approximately 42,000 boe/d for the third quarter of 2009. We expect production to be approximately 42,500 to 43,000 boe/d in the fourth quarter of 2009.

Heavy oil production from Seal averaged approximately 5,200 boe/d in the third quarter. Eight wells were drilled in the Seal area in the third quarter, increasing the total number of horizontal producing wells in the Seal area to 58 and continuing Baytex's record of 100% drilling success. We anticipate drilling approximately four more horizontal wells at Seal during the fourth quarter. In addition, we plan to drill approximately eight more heavy oil wells in the Lloydminster area during the remainder of the year.

In our Bakken-Three Forks project in North Dakota, we drilled two Baytex-operated horizontal oil wells (37.5% working interest) and subsequently applied multi-stage fracture treatments to both wells. Production from the first well averaged approximately 300 barrels of oil per day during the peak thirty days of production, exceeding our previous model for this play by one-third. The second well is in the early stages of production testing. We are continuing our drilling program with three more Bakken-Three Forks wells in the fourth quarter. Subsequent to the end of the quarter, we reached an agreement with our partner in this project, a private company, to pre-pay our remaining deferred acquisition payments for the land position we acquired in July 2008. Under the terms of the pre-pay agreement, Baytex will pay US$33.2 million to complete our remaining obligations, which would otherwise have totaled US$36 million over approximately the next five to six quarters. In addition, Baytex will be assigned an operating area corresponding to approximately 38% of the lands in the project area, an expansion of eleven operated sections from the operating area designated in the July 2008 agreement. In addition to decreasing the cost of the remaining land payments, the purpose of the pre-pay is to increase our degree of operating control in this large light oil resource play. Closing of the pre-pay agreement is expected to occur in mid-December, with assumption of the operating area at the beginning of 2010.

We continue to develop our Viking light oil resource play on lands in Alberta, following up on a successful well drilled in the second quarter which averaged approximately 90 barrels of oil per day during the peak thirty days of production. Subsequent to the end of the third quarter, we drilled and tested an additional well in the Viking in Alberta. This well will be placed on production during the fourth quarter, with production rates expected to be comparable to or better than those from the well drilled in the second quarter. We plan to drill up to four additional Viking wells in the fourth quarter.

We drilled our first horizontal well in our Mowry Shale play in Wyoming in the third quarter, with completion planned for the fourth quarter.

Consistent with previous guidance, full-year exploration and development capital expenditures are estimated to be $165 million. Total deferred acquisition payments for our North Dakota properties will be US$39.2 million, including the pre-pay of our remaining deferred land acquisition payments. In the absence of any other fourth quarter transactions, we project total acquisition capital expenditures of $133 million for 2009 (including expenditures for both the North Dakota and the Saskatchewan acquisitions).

Financial Review

During the third quarter of 2009, we completed a refinancing transaction to redeem our U.S. notes maturing in 2010 and to extend the maturity of our long-term debt. In August, we issued $150 million of 9.15%, 7-year (non-call 3) debentures at par in the emerging Canadian high yield market. This issue was one of very few placed in the Canadian market to-date, and was very well received, with a yield which was lower than prevailing rates in the U.S. high yield market. The proceeds of this issue were used to partially fund the third-quarter redemption of our US$180 million senior unsecured notes which were due to mature in July 2010. At the time of this redemption, we converted an equivalent amount of borrowings on our credit facility from Canadian to U.S. dollars in order to maintain the natural currency hedge and currency exposure provided by U.S. dollar denominated debt. Finally, we entered into a series of interest rate swaps with the result that our interest rate exposure is floating for the next two years, and the large majority of our exposure is fixed for years three to five forward, locking in relatively low costs of borrowing, and limiting our exposure to increases in future interest rates.

The third quarter asset acquisition was funded entirely through draws on our credit facility. At the end of the third quarter, total monetary debt was $466 million, which offers us undrawn credit facilities of over $200 million and represents a debt-to-cash flow ratio of 1.3 times based on annualized third quarter 2009 cash flow. Both of these metrics are well within our leverage and liquidity targets, and provide ample capacity to finance our operations going forward.

Funds from operations for the third quarter of 2009 was $88.8 million, which was a 2% increase over second quarter results. Third quarter revenue growth from improving commodity prices and increased sales volumes were partially offset by increased royalties and financing charges. As compared to the second quarter cash flow, several non-recurring items contributed to the quarter over quarter increase in expense items. First, the second quarter results included positive royalty and G&A adjustments of $3.3 million which were not repeated in the third quarter. Secondly, third quarter results were impacted by a one time payment of $3.4 million in transaction costs on the issuance of $150 million of senior unsecured debentures. Lastly, the third quarter results included several non-recurring operating expense items which in aggregate added approximately $1.0 million to third quarter operating costs. These payments relate to charges incurred by previous owners on acquired properties.

The third quarter saw continued improvement in world oil prices as the average WTI price for the quarter was US$68.18 per bbl, a 15% increase over the second quarter. The benefit of this improvement was partially offset for Canadian producers by the quarter over quarter weakening of the U.S. dollar relative to the Canadian dollar. Heavy oil pricing continued to be very strong, with third quarter differentials, as measured by market pricing for Lloyd Blend, averaging 15% of WTI for the third quarter of 2009. Baytex heavy oil pricing averaged $55.12 per bbl, an increase of 8% over the $51.19 per bbl realized in the second quarter. The near term outlook for heavy oil pricing continues to be favorable, supported by third party investment in refining and transportation infrastructure, including the looming commencement of oil shipments on the Keystone pipeline. We are pleased to see the development of additional transportation infrastructure which will enhance access to new markets for Canadian producers and, we believe, support the continuation of a strong heavy oil pricing environment. Capitalizing on the strength of near term heavy oil pricing, Baytex recently entered into a series of forward agreements which will result in sales of 1,000 barrels per day of blend for 2010 at a heavy oil price of over $68 per bbl, or $13 per bbl higher than our third quarter 2009 realized heavy oil price. Natural gas pricing continued to be weak, with our third quarter wellhead price averaging $3.42 per Mcf as compared to $3.85 per Mcf in the second quarter. Looking forward, Baytex has mitigated its exposure to weaker natural gas prices by hedging approximately 45% of its projected net of royalty natural gas sales for 2010.

Total cash distributions declared in the quarter of $32.8 million, or $0.36 per unit, represented a payout ratio of 37% net of distribution reinvestment plan ("DRIP") participation (44% before DRIP). This conservative payout ratio is consistent with our philosophy of sustainability and has contributed to our strong financial position, while maintaining a meaningful income stream to our unitholders.

Staff Appointment

Brian Ector has joined Baytex as Director of Investor Relations. Mr. Ector has fifteen years of experience as a research analyst covering both energy trusts and exploration and production corporations. He spent the last seven years with Scotia Capital where he was highly regarded for his definitive reports and insightful valuation perspectives, and where he consistently ranked as one of the top rated analysts in Canada. Brian is a graduate of the University of Calgary and received his CFA designation in 1996.

Additional Information

Our unaudited consolidated financial statements for the three months and nine months ended September 30, 2009 and 2008 and related Management's Discussion & Analysis can be accessed immediately on our website at and will be available shortly through SEDAR at and EDGAR at

Conference Call

Baytex will hold a conference call and question and answer session at 2:00 p.m. MT (4:00 p.m. ET) on Tuesday, November 10, 2009 to discuss our third quarter 2009 results. The conference call will be hosted by Anthony Marino, President and Chief Executive Officer, and Derek Aylesworth, Chief Financial Officer. Interested parties are invited to participate by calling toll-free across North America at 1-866-223-7781. An archived recording of the call will be available from November 10, 2009 until November 17, 2009 by dialing 1-800-408-3053 (within North America) or 416-695-5800 within the Toronto area and entering the reservation code 8017528. The conference call will also be archived on Baytex's website at

Advisory Regarding Forward-Looking Statements

In the interest of providing Baytex's unitholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements in this document 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 document speak only as of the date of this document and are expressly qualified by this cautionary statement.

Specifically, this document contains forward-looking statements relating to: our production levels for the fourth quarter of 2009; development plans for our properties; our exploration and development capital expenditures for 2009; the amount of deferred acquisition payments for the North Dakota acquisition to be paid in 2009; our liquidity and financial capacity; oil and gas prices and differentials between light, medium and heavy oil prices; the demand for and supply of crude oil; the development of refining and transportation infrastructure; and our ability to fund cash distributions and our capital program from internally-generated cash flow.

These forward-looking statements are based on certain key assumptions regarding, among other things: oil 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; the availability and cost of labour and other industry services; the amount of future cash distributions that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.

Actual results achieved during the forecast period 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: general economic, market and business conditions; industry capacity; fluctuations in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; fluctuations in foreign exchange or interest rates; stock market volatility and market valuations; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; changes in income tax laws, royalty rates and incentive programs relating to the oil and gas industry and income trusts; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in Baytex's Annual Information Form, Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2008, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission.

There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

Contact Information

  • Baytex Energy Trust
    Anthony Marino
    President and Chief Executive Officer
    (403) 267-0708
    Baytex Energy Trust
    Derek Aylesworth
    Chief Financial Officer
    (403) 538-3639
    Baytex Energy Trust
    Brian Ector
    Director of Investor Relations
    (403) 267-0702
    Baytex Energy Trust
    Cheryl Arsenault
    Investor Relations
    (403) 267-0761
    Toll Free Number: 1-800-524-5521