Baytex Energy Trust

Baytex Energy Trust

May 12, 2009 09:02 ET

Baytex Energy Trust Announces First Quarter 2009 Results

CALGARY, ALBERTA--(Marketwire - May 12, 2009) - Baytex Energy Trust (TSX:BTE.UN) (NYSE:BTE) is pleased to announce its operating and financial results for the three months ended March 31, 2009.


- Produced an average of 39,762 boe/d in the quarter, an increase of 4% over Q1/08;

- Generated cash flow of $59.4 million ($0.60 per diluted unit) for the first quarter of 2009;

- Continued Seal development with the drilling of four cold producers in the first quarter, continuing our record of 100% success and demonstrating commercial productivity of our heavy oil resource at West Harmon Valley; and

- Subsequent to the end of the first quarter, completed a bought deal equity financing, issuing 7.9 million units for net proceeds of $109 million, and increased our credit facilities from $485 million to $515 million.

FINANCIAL ($ thousands, except per unit
March 31, December 31, March 31,
Three Months Ended 2009 2008 2008

Petroleum and natural gas sales 150,943 199,890 264,448
Cash flow from operations (1) 59,372 60,472 101,570
Per unit - basic 0.61 0.62 1.19
- diluted 0.60 0.61 1.12
Cash distributions 34,947 55,314 38,474
Per unit 0.42 0.68 0.56
Net income (loss) (8,490) 52,401 35,848
Per unit - basic (0.09) 0.54 0.42
- diluted (0.09) 0.53 0.41

Exploration and development 47,664 42,969 51,003
Acquisitions - net of dispositions (16) 8,174 581
Total capital expenditures 47,648 51,143 51,584

Long-term notes 226,768 220,362 184,967
Bank loan 272,421 208,482 198,045
Convertible debentures 10,219 10,195 15,041
Working capital deficiency 52,531 93,979 37,909
Total monetary debt (2) 561,939 533,018 435,962

March 31, December 31, March 31,
Three Months Ended 2009 2008 2008

Daily production
Light oil & NGL (bbl/d) 7,120 7,803 7,330
Heavy oil (bbl/d) 23,432 24,635 22,484
Total oil (bbl/d) 30,552 32,438 29,814
Natural gas (MMcf/d) 55.3 57.6 50.1
Oil equivalent (boe/d @ 6:1) (3) 39,762 42,035 38,157

Average prices (before hedging)
WTI oil (US$/bbl) 42.98 58.35 97.90
Edmonton par oil ($/bbl) 50.29 63.94 97.50
BTE light oil & NGL ($/bbl) 43.05 55.31 84.91
BTE heavy oil ($/bbl) (4) 33.97 38.93 59.88
BTE total oil ($/bbl) 36.11 42.83 65.84
BTE natural gas ($/Mcf) 5.39 7.05 7.42
BTE oil equivalent ($/boe) 35.23 42.71 61.30

TSX (C$)
Unit price
High $17.49 $27.05 $23.40
Low $ 9.77 $12.81 $16.30
Close $15.10 $14.65 $22.78
Volume traded (thousands) 38,989 31,267 25,748

Unit price
High $14.85 $25.49 $23.34
Low $ 7.84 $10.16 $15.88
Close $12.07 $11.95 $22.16
Volume traded (thousands) 12,545 14,498 4,786

Units outstanding (thousands) (5) 98,479 97,685 88,474

(1) Cash flow 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. The Trust s cash flow from
operations may not be comparable to other issuers. The Trust considers
cash flow from operations a key measure of performance as it
demonstrates the Trust s ability to generate the cash flow necessary to
fund future distributions and capital investments. For a reconciliation
of cash flow from operations to cash flow from operating activities, see
Management s Discussion and Analysis of the operating and financial
results of the Trust for the three months ended March 31, 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 derivative 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. BOEs 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.

(5) Number of trust units outstanding at March 31, 2008 includes the
conversion of exchangeable shares at the exchange ratio in effect at the
end of such reporting period.

Operations Review

Capital expenditures for exploration and development activities totaled $47.7 million for the first quarter of 2009. During this quarter, Baytex participated in drilling 29 (27.8 net) wells, resulting in 19 (19.0 net) oil wells, four (2.8 net) gas wells, two (2.0 net) stratigraphic test wells and four (4.0 net) dry and abandoned wells, for an 86% success rate. First quarter drilling included 11 (11.0 net) oil wells and three (3.0 net) dry holes in the Lloydminster area, four (4.0 net) horizontal production wells and two (2.0 net) stratigraphic test wells at Seal, one (1.0 net) oil well and three (1.8 net) gas wells in the Pembina/Ferrier area, two (2.0 net) oil wells in the Stoddart area, and one (1.0 net) oil well, one (1.0 net) gas well and one (1.0 net) dry hole in east-central Alberta.

Production averaged 39,762 boe/d during the first quarter of 2009, as compared to 42,035 boe/d for the fourth quarter of 2008. Production was consistent with our guidance of approximately 40,000 boe/d for 2009 under the reduced capital program announced in February 2009. Production is expected to be roughly flat at this level for each quarter of 2009. Capital spending guidance also remains unchanged at $150 million for exploration and development activities and $10 million for deferred acquisition payments for our North Dakota assets.

Although in-line with guidance, heavy oil production was modestly curtailed by our decision early in the first quarter to defer well servicing on a small number of higher-cost wells until oil pricing improves. In addition, a portion of our originally-planned Seal drilling program was deferred until after breakup based on our expectation of higher oil prices. Although drilling of Seal wells is economic at first quarter oil prices, we deferred some of the drilling based on the expectation of increasing net present value by selling oil from the high production rate early-time period at higher prices later in the year. In the reduced first quarter Seal program, we drilled three horizontal producing wells in our Harmon Valley development area, which commenced production at an average initial rate of 275 bbl/d per well. In addition, we drilled the first producing well in our West Harmon Valley area, which commenced production at an initial rate of 180 bbl/d, demonstrating commercial productivity of our heavy oil resource using cold methods in a new area approximately six miles from our existing development area.

Light oil and gas production was also in-line with guidance for the first quarter, but should be modestly positively affected by commencing production from several Alberta wells in April 2009. In the first quarter, we completed construction of an eight kilometre gas pipeline in the Ferrier/O'Chiese area which reduced production constraints and improved operating netbacks. In North Dakota, we completed a 260 square mile 3D seismic survey over our Bakken-Three Forks project area. The survey is expected to assist in the high-grading of future Bakken-Three Forks locations and also may lead to identification of conventional drilling prospects in other formations. We plan to resume drilling in the third quarter of 2009.

Financial Review

Cash flow from operations for the first quarter was $59.4 million, a decrease of 2% compared to $60.5 million for the fourth quarter of 2008. The largest contributor to the decline was decreased commodity prices in the first quarter of 2009. Baytex received an average oil price of $36.11 per barrel before hedging in the first quarter, a decrease of 16% compared to $42.83 per barrel before hedging in the fourth quarter of 2008. Natural gas prices also decreased in the first quarter, with Baytex receiving an average wellhead price of $5.39 per Mcf, 24% lower than the previous quarter. The decline in commodity prices was partially offset by a $25.1 million realized gain on financial instruments in the first quarter of 2009. This gain is primarily related to a series of costless WTI collars with an average floor price of US$100 per barrel, covering a total of 4,000 bbl/d for calendar 2009.

Net loss for the first quarter of 2009 computed in accordance with Generally Accepted Accounting Principles ("GAAP") in Canada was $8.5 million compared to net income of $35.8 million for the first quarter in 2008. A key contributor to the loss was the timing of recognition of income related to our financial derivative instruments. The WTI collar contracts were entered into in 2008 to provide cash flow protection for 2009. Under Canadian GAAP, the unrealized mark-to-market net income benefit of those WTI collars was required to be recorded in 2008. In the first quarter of 2009, the realized benefit of those contracts is reflected in our cash flows, but not in our net income, because the net income impact had previously been recorded. If the benefit of these financial contracts were permitted to be recorded in the period to which the contracts relate, our pre-tax net income would have been higher in the first quarter by approximately $26 million.

Heavy oil pricing differential, as measured by market pricing for Lloyd Blend, averaged 22% of WTI for the first quarter of 2009, as compared to 34% in the fourth quarter of 2008. This decline in differential through the historically higher-differential winter months supports our view that there has been a structural change in heavy oil supply and demand, which bodes very well for the longer term outlook for heavy oil pricing. The differential for the second quarter of 2009 is currently being traded at approximately 15% of WTI, resulting in estimated wellhead pricing of $50 per barrel for Lloydminster-area raw heavy crude, based on current WTI prices, foreign exchange rates and condensate costs.

After the end of the first quarter, Baytex entered into a series of contracts concurrently to lock in the raw heavy oil price on a portion of our production for calendar 2010. By simultaneously entering into forward contracts for WTI, blend differential, condensate differential and foreign exchange, we established a raw Hardisty heavy oil price of $55.26 per barrel on 1,925 bbl/d for 2010. When compared to historic pricing, the only year in which Hardisty pricing exceeded this contracted price was 2008, and this price exceeded the next highest year by over 30%. We believe that the availability of this type of contract pricing provides support for our long-term positive outlook for heavy oil pricing.

Total cash distributions in the quarter of $34.9 million, or $0.42 per unit, represented a payout ratio of 59% net of distribution reinvestment plan ("DRIP") participation (69% before DRIP). In order to conserve our financial liquidity, and to better match our distribution levels with the prevailing commodity price, we reduced our monthly distribution from $0.18 to $0.12 per unit in respect of February 2009 operations. At the current commodity price outlook, we expect to be able to fully fund this adjusted distribution level along with our capital expenditure program from our internally generated cash flow.

Total monetary debt, excluding notional mark-to-market assets at the end of the quarter, was $561.9 million which was an increase of $28.9 million from the end of 2008. At the end of the first quarter, Baytex had over $160 million in available undrawn credit lines.

Subsequent to the end of the first quarter, we completed a bought deal equity financing, issuing 7.9 million trust units for net proceeds of $109.3 million. In addition, through the regularly scheduled annual review, we reached agreement with our lending syndicate to increase our credit facilities from $485 million to $515 million. The equity issuance and increase in bank facilities have significantly strengthened our balance sheet and expanded our financial liquidity. We are appreciative of the confidence in Baytex shown by the equity market and our lenders in this challenging economic time, and believe that both represent a strong endorsement of our business model.

Additional Information

Our unaudited consolidated financial statements for the three months ended March 31, 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, May 12, 2009 to discuss our first 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 May 12, 2009 until May 19, 2009 by dialing 1-800-408-3053 (within North America) or 416-695-5800 within the Toronto area and entering the reservation code 6080016. 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 2009; our exploration and development capital program for 2009; the amount of deferred acquisition payments for the North Dakota acquisition to be paid in 2009; our heavy oil resource play at Seal, including the economics of drilling heavy oil wells and the resource potential of our undeveloped land; oil and gas prices and differentials between light, medium and heavy oil prices; our light oil resource play in North Dakota, including the use of seismic data to enhance the identification of drilling prospects and the timing of the resumption of drilling on this project, the demand for and supply of crude oil; 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
    Erin Cripps
    Investor Relations Representative
    (403) 538-3681
    Baytex Energy Trust
    Cheryl Arsenault
    Investor Relations Representative
    (403) 267-0761
    Toll Free Number: 1-800-524-5521