Exhibit 99.3
| Regarding this MD&A The following discussion and analysis, dated |
| March 7, 2005, should be read in conjunction with Baytex Energy Trust’s |
| (the “Trust” or “Baytex”) audited consolidated financial statements for |
| the fiscal years ended December 31, 2004 and 2003. Per 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. |
MANAGEMENT’S DISCUSSION AND ANALYSIS
The Trust evaluates performance based on net income and cash flow from operations. Cash flow from operations and cash flow per unit are not measurements based on generally accepted accounting principles (“GAAP”), but are financial terms commonly used in the oil and gas industry. Cash flow represents cash generated from operating activities before changes in non-cash working capital, deferred charges and other assets and deferred credits. The Trust’s determination of cash flow may not be comparable with the calculation of similar measures for other entities. The Trust considers it a key measure of performance as it demonstrates the ability of the Trust to generate the cash flow necessary to fund future distributions to unitholders and capital investments.
The Trust also uses certain key performance indicators and industry benchmarks such as operating netbacks (“netbacks”), finding, development and acquisition costs (“FD&A”), recycle ratio and payout ratio to analyze financial and operating performance. These key performance indicators and benchmarks as presented do not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities.
This discussion and analysis contains forward-looking statements relating to future events or future performance. In some cases, forward-looking statements can be identified by terminology such as “may”, “will”, “should”, “expects”, “projects”, “plans”, “anticipates” and similar expressions. These statements represent management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of the Trust. The projections, estimates and beliefs contained in such forward-looking statements necessarily involve known and unknown risks and uncertainties, including the business risks discussed in the MD&A as at and for the years ended December 31, 2004 and 2003, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Readers should not place undue reliance on any such forward-looking statements, which speak only as of the date they were made. The Trust is not obligated to publicly update or revise the forward-looking statements relating to future events or future performance to reflect any change in management’s expectations or events.
The Trust was established on September 2, 2003 under a Plan of Arrangement involving the Trust, Baytex Energy Ltd. (the “Company”) and Crew Energy Inc. (“Crew”). The Trust is an open-ended investment trust created pursuant to a trust indenture. The Company is a subsidiary of the Trust.
Prior to the Plan of Arrangement, the consolidated financial statements included the accounts of the Company and its subsidiaries and partnership. After giving effect to the Plan of Arrangement,
9
the consolidated financial statements have been prepared on a continuity of interests basis which recognizes the Trust as the successor to Baytex Energy Ltd. The consolidated financial statements include the accounts of the Trust and its subsidiaries and have been prepared by management in accordance with Canadian generally accepted accounting principles.
2004 OVERVIEW
ACQUISITIONS
Effective September 22, 2004, the Company acquired all of the outstanding shares of a Calgary based private oil and gas company for a cash consideration of $109 million. The results of its operations have been included in the consolidated financial statements of the Trust since the effective date. This acquisition added approximately 3,000 boe per day of production comprised of 12 mmcf/d of natural gas and 1,000 barrels per day of light oil and NGLs from three geographically-focused areas in southern Alberta. Subsequent to the acquisition, the private company was amalgamated with the Company.
Effective December 22, 2004, the Company acquired oil and natural gas interests in the West Stoddart area of northeast British Columbia for a total cash consideration of $90 million. This property added approximately 3,300 boe per day of primarily high netback liquids-rich natural gas production comprised of 10.0 mmcf/d of natural gas, 1,300 barrels per day of NGLs and 330 barrels per day of light oil. The production is from three properties near Fort St. John, B.C. generally with year-round access for efficient operations and capital activities.
OPERATIONS REVIEW
PRINCIPAL PROPERTIES
Baytex’s crude oil and natural gas operations are organized into two operating districts – the Heavy Oil District and the Conventional Oil and Gas District. Each district constitutes an extensive portfolio of operated properties and development prospects with considerable upside potential. Baytex has established skilled technical teams to operate each district. Each team has a mandate to apply its specific knowledge and expertise to its operating area. This focused approach aids in the evaluation of exploration, development and acquisition opportunities and improves cost efficiency.
HEAVY OIL DISTRICT
The Heavy Oil District accounts for approximately 60 percent of the Trust’s current production and approximately three-quarters of its reserves and 50 percent of cash flow from operations. Heavy oil operations consist largely of cold conventional production from wells with multi-zone potential. Production is generated primarily from vertical, slant and horizontal wells using progressive cavity pump technology to generate large volumes of heavy oil combined with gas, water and sand. Initial production from these wells usually averages between 40 and 100 barrels per day of low gravity crude ranging from 11 to 18 API. Once produced, the oil is trucked or pipelined to markets in both Canada and the United States. After being sold by Baytex, the crude oil is then upgraded into lighter grades of crude or refined into petroleum products such as fuel oil, lubricants and asphalt.
In 2004, production in the Heavy Oil District averaged 22,700 barrels per day of heavy oil and 8.9 mmcf/d of natural gas (24,200 boe per day). Baytex drilled 115 gross (113.7 net) wells in the heavy oil district resulting in 95 gross (95.0 net) oil wells, three gross (2.2 net) gas wells, seven gross (6.5 net) stratigraphic test wells, and 10 gross (10.0 net) dry and abandoned wells, for a success rate of 91.3 percent.
10
The Heavy Oil district possesses a large inventory of development projects within the west-central Saskatchewan, Cold Lake/Ardmore, and Peace River/Seal heavy oil deposits. The ability to generate relatively lowcost replacement production through conventional cold production methods is one of the key elements of the Trust’s sustainability.
The Trust will continue to build value through internal property development and selective acquisitions. Future heavy oil activity will focus on the development of the Seal and Ardmore properties along with continued infill drilling at the adjacent Cold Lake property and throughout the Saskatchewan properties. Company net undeveloped lands in this district totaled 344,892 acres at year-end 2004.
ARDMORE – ALBERTA
Ardmore is one of the key heavy oil development and production areas for the Trust. Acquired in 2002 with production of 2,200 barrels per day, Ardmore has been developed in the Sparky, McLaren and Colony formations. Average production during 2004 was 4,200 barrels per day of oil and 1.0 mmcf/d of natural gas (4,400 boe per day). Current production is 3,800 barrels per day of oil and 950 mcf/d of natural gas (4,000 boe per day). Baytex has applied leading-edge slotted-liner production technology to improve production and increase wellbore stability. Slotted-liner wells in the area are capable of producing up to 300 barrels per day of heavy oil and continue to be used extensively for pool development projects. Twenty-six oil wells and three dry wells were drilled in the area during 2004 and 20 to 25 wells are anticipated to be drilled during 2005. During 2004, operating expenses were reduced to $5.50/bbl primarily by building a water disposal facility and conserving solution gas produced in conjunction with the heavy oil. It is expected that operating expenses will be further reduced as a result of the construction of a sand disposal facility in late 2004. The Trust also added 6,500 acres of new lands through Crown land sales in 2004 that are prospective for Colony oil pool development. Company net undeveloped lands were 39,120 acres at year-end 2004.
COLD LAKE – ALBERTA
Baytex acquired the Cold Lake heavy oil property in 2001. This year-round drilling area is located on the Cold Lake First Nations lands, with heavy oil production generated largely from the Colony formation. Average production was 1,000 barrels per day during 2004. The Trust drilled 12 oil wells and three dry wells in the Cold Lake area during 2004. Up to 15 new drills are anticipated during 2005. Company net undeveloped lands were 18,062 acres at year-end 2004.
SEAL – ALBERTA
The Seal property is a highly prospective property located in the Peace River oil sands area of northwest Alberta. The Trust holds a 100 percent working interest in approximately 96 sections of land, of which 42 sections were acquired in 2004. The Seal oil deposits can be produced through horizontal well-bores at initial rates of approximately 200 barrels per day per well without the use of capital intensive steam injection methods. A seven-well stratigraphic test program completed during the first quarter of 2004 has led to the Trust’s current development program on the western block of these land holdings. Two horizontal wells drilled at the end of 2004 are currently producing a total of approximately 400 barrels per day. The prospective undeveloped area of the western block is over 25,000 acres. During 2005, Baytex plans to drill up to six additional stratigraphic test wells to further delineate this land block and up to 15 horizontal producers in the immediate area that are currently producing. In addition, other industry operators are currently drilling horizontal production wells on adjoining sections that will help define the productive capability of the Trust’s lands. Company net undeveloped lands in this area were 63,680 acres at year-end 2004.
11
TANGLEFLAGS – SASKATCHEWAN
Baytex acquired the Tangleflags property in 2000. Tangleflags is characterized by multiple-zone reservoirs with production from the Colony, McLaren, Waseca, Sparky, General Petroleum and Lloydminster formations. Provincial government regulations generally prohibit production from more than one formation at a time. As such, this property possesses long-term development potential from a considerable number of up-hole recompletion opportunities. Average production during 2004 was approximately 3,800 barrels per day of heavy oil and 1.2 mmcf/d of natural gas (4,000 boe per day). Ongoing projects in the area include up to 15 development wells during 2005, uphole recompletions after depletion of deeper producing intervals, and optimization of the solution gas gathering system. Company net undeveloped lands were 11,160 acres at year-end 2004.
CARRUTHERS – SASKATCHEWAN
The Carruthers property was obtained by Baytex in 1997. The property consists of separate “North” and “South” oil pools in the Cummings formation. Typical vertical oil wells initially produce approximately 40 barrels per day with ultimate recoveries of approximately 60,000 barrels of reserves. During 2004, average production was approximately 3,200 barrels per day of heavy oil and 850 mcf/d of natural gas (3,300 boe per day). The Trust drilled 1.2 net natural gas wells and 14 net oil wells in South Carruthers and three net horizontal oil wells in North Carruthers during 2004. This area represents a relatively stable production base with continued development drilling expected to total 10 to 15 wells annually. Company net undeveloped lands were 14,425 acres at year-end 2004.
MARSDEN/EPPING/MACKLIN/SILVERDALE – SASKATCHEWAN
This area of Saskatchewan is characterized by low-access costs and higher quality oil of 13 to 18 API gravity and low sand content. Initial production rates are typically 70 barrels per day and primary recovery factors can be as high as 30 percent of the original oil in place. This oil is also receptive to waterflood recovery schemes to further increase recovery. Average production in this area during 2004 was approximately 4,600 barrels per day. Twenty oil wells were drilled in 2004, increasing production to over 4,900 barrels per day by year-end. In addition, ongoing flow-line installation and water disposal projects have combined to keep operating costs below $5.50/bbl. Drilling in 2005 will add up to 15 new oil wells, mostly through development of the Macklin pool. In Epping, waterflood and solution gas tie-in projects are planned for 2005. Company net undeveloped lands were 20,932 acres at year-end 2004.
CONVENTIONAL OIL AND GAS DISTRICT
The Conventional Oil and Gas district produces light and medium gravity crude oil, natural gas and natural gas liquids from various fields in Alberta and British Columbia. In 2004, production averaged 46.0 mmcf/d of natural gas and 2,200 barrels per day of hydrocarbon liquids (9,800 boe per day). In 2004, the Conventional District drilled 23 gross (20.9 net) wells resulting in four gross (4 net) oil wells, 14 gross (12.4 net) gas wells and five gross (4.5 net) dry and abandoned wells for a success rate of 78 percent. The Company undeveloped lands in the Conventional district were 453,055 net acres at year-end 2004. During 2004, property acquisitions at Garden Plains, Turin and Stoddart were added to the Conventional District.
12
STODDART – BRITISH COLUMBIA
The Stoddard asset acquisition was closed on December 22, 2004. Oil and liquids rich gas production from this largely year-round-access area comes from the Doig, Halfway, Baldonnal, Coplin and Bluesky formations. Oil is treated at two Company-operated batteries. Natural gas is compressed at four company-operated sites and sent for further processing at the outside-operated West Stoddart and Taylor Younger plants. Year-end 2004 production was approximately 10 mmcf/d of natural gas and 1,700 barrels per day of hydrocarbon liquids (3,400 boe per day). The Company plans to drill approximately four wells and recomplete up to seven wells in 2005 in the Stoddart area. Company net undeveloped lands were 25,343 acres at December 31, 2004.
GARDEN PLAINS/SEDALIA – ALBERTA
In 2001, Baytex acquired its initial position in this area and significantly increased its presence with a 2004 acquisition of a private company. December 2004 gas production was approximately 10 mmcf/d (1,700 boe per day). This area has the advantage of year-round access and multi-zone potential (Second White Specks, Viking and Mannville). Most of the gas production is processed by two Company-operated gas plants. The Company plans to drill four wells during 2005 in this area. Company net undeveloped lands were 77,498 acres at year-end 2004.
TURIN – ALBERTA
This multi-zone, year-round access property was acquired in 2004. December 2004 production was approximately two mmcf/d of natural gas and 900 barrels per day liquids (1,200 boe per day). Production comes from the Second White Specks, Milk River, Bow Island, Mannville, Sawtooth and Livingstone formations. Oil production is treated at three Company-operated batteries and gas is processed at two outside-operated gas plants. The Company plans to drill approximately five wells and recomplete up to 10 other wells during 2005 in the Turin area. Company net undeveloped lands were 31,335 acres at December 31, 2004.
RED EARTH/GOODFISH – ALBERTA
This winter-access, multi-zone property was acquired by Baytex in 1997. Relatively shallow decline oil production from Granite Wash and Slave Point pools is treated at two Company-operated sweet oil batteries. Natural gas production from the Bluesky formation is handled at two gas plants, one of which is Company-operated. Production during 2004 from this area averaged approximately eight mmcf/d of natural gas and 1,000 barrels per day hydrocarbon liquids (2,300 boe per day). In 2004, Baytex drilled eight net wells in 2004 resulting in four oil wells, two gas wells and two abandoned wells and plans to drill one well during 2005. Company net undeveloped lands were 44,448 acres at year-end 2004.
BON ACCORD – ALBERTA
This multi-zone property was acquired by Baytex in 1997. Production is from the Belly River, Viking and Mannville formations and averaged approximately six mmcf/d of gas and 300 barrels per day of hydrocarbon liquids (1,300 boe per day) in 2004. Natural gas is processed at two Company-operated plants and oil is treated at three Company-operated batteries. In late 2004, Baytex drilled two gas wells (1.5 net) which will be put on production in 2005, and plans to drill one well during 2005. Company net undeveloped lands were 47,725 acres at year-end 2004.
13
LEAHURST – ALBERTA
Production averaged approximately eight mmcf/d (1,300 boe per day) in 2004 from this multi-zone, year-round access area. Natural gas from the Edmonton, Belly River, Viking and Mannville formations is processed at several plants, one of which is Company-operated. In 2004, Baytex drilled five Mannville natural gas wells resulting in three gas wells and two abandonments. Baytex also successfully recompleted nine wells for coal-bed methane production from the Horseshoe Canyon coals during 2004. In 2005, Baytex plans to drill approximately 15 wells and recomplete seven wells in the Leahurst area. Company net undeveloped lands were 35,310 acres at year-end 2004.
NINA/DARWIN – ALBERTA
Both properties in this winter-access area produce natural gas from the Bluesky formation. Natural gas production is processed at two Company-operated gas plants. Production during 2004 averaged approximately five mmcf/d (800 boe per day). Six net wells were drilled in 2004 resulting in three producing gas wells. Company net undeveloped lands were 46,203 acres at year-end 2004.
HEAVY OIL SUPPLY AGREEMENT
In October 2002, Baytex signed a five-year crude oil supply agreement with Frontier Oil and Refining Company (“Frontier”) of Houston, Texas. The agreement calls for Baytex to deliver 20,000 barrels per day of Lloyd Blend (“LLB”) quality crude at Hardisty, Alberta through the Express Pipeline to Guernsey, Wyoming. The blended crude is comprised of approximately 15,500 barrels of Baytex production and 4,500 barrels per day of diluent. Prices are fixed at 71 percent of WTI or a 29 percent LLB differential which represents the long-term average differential since 1986. This contract significantly reduces the volatility of Baytex’s cash flow from its heavy oil production.
The Frontier Crude Oil Supply Agreement effectively mitigates the risk of volatile heavy oil differentials on Baytex’s cash flow
14
MARKETING
CRUDE OIL
World crude oil prices reached unprecedented levels in 2004 as strong Asian demand, uncertainty over Middle East supplies, hurricane-inflicted damage to U.S. Gulf of Mexico production facilities and diminishing excess OPEC productive capacity all contributed to record prices. Benchmark West Texas Intermediate (WTI) prices, after reaching an all-time high of US$55.17 per barrel in late October, averaged $41.40 in 2004, an increase of 33 percent from the 2003 average of $31.04. The five-year average is $30.92.
Canadian crude oil prices, while enjoying the strength in world prices, were tempered by the rising Canadian dollar against its U.S. counterpart. Canadian Par crude at Edmonton averaged $52.57 per barrel in 2004, up 22 percent from $43.16 in 2003. The five-year average is $43.82.
Baytex’s conventional crude oil and natural gas liquids prices averaged $48.64 per barrel in 2004 compared to $40.01 in 2003.
With OPEC increasing oil output late in 2004 to meet surging world demand, supplies of heavy and sour crude oil grades increased and prices versus benchmark light sweet prices deteriorated. Canadian heavy oil prices were affected by this increased supply as the differential between WTI and Lloyd blend prices in Alberta averaged US$14.01 per barrel in 2004 (34 percent of WTI) compared to US$8.88 in 2003 (29 percent of WTI), with five-years averages at US$9.68 and 31 percent.
Baytex’s heavy oil prices averaged $30.32 per barrel in 2004, compared to $26.68 in 2003.
Baytex’s heavy crude oil is shipped to the Frontier Refinery in Cheyenne, Wyoming via the Express Pipeline system.
15
NATURAL GAS
Natural gas prices in North America were strong in 2004, reflecting high oil prices and concerns over gas supplies. U.S. gas prices, represented by the NYMEX futures contract, averaged US$6.09 per thousand cubic feet (mcf) in 2004, an increase of 12 percent from $5.44 in 2003. Daily prices for Alberta gas delivered to the AECO “C” trading hub averaged $6.53/mcf in 2004 compared to $6.66 in 2003, due to the impact of the strong Canadian dollar. Five-year average prices are US$4.62 for the NYMEX contract, and $5.71 for Alberta daily prices.
Baytex received an average of $6.46 per mcf for 2004 natural gas sales compared to $6.23 in 2003.
PRODUCTION
The Trust’s average production for fiscal 2004 decreased by seven percent to 34,022 boe per day from 36,686 boe per day for fiscal 2003 due to asset dispositions and the transfer of properties pursuant to the Plan of Arrangement.
Light oil production decreased four percent to 2,172 barrels per day during 2004 from 2,273 barrels per day in 2003. Heavy oil production during 2004 was 22,703 barrels per day, a decrease of five percent from production of 23,911 barrels per day during 2003. Natural gas production for 2004 decreased by 13 percent to 54.9 mmcf/d compared to 63.0 mmcf/d for the prior year.
PRODUCTION BY AREA
|
| Light Oil |
|
|
|
|
| Barrels of |
|
|
| and NGLs |
| Heavy Oil |
| Natural Gas |
| Oil Equivalent |
|
|
| (bbls/d) |
| (bbls/d) |
| (mmcf/d) |
| (boe/d) |
|
2004 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 22,703 |
| 8.9 |
| 24,177 |
|
Conventional Oil and Gas District |
| 2,172 |
| — |
| 46.0 |
| 9,845 |
|
Total Production |
| 2,172 |
| 22,703 |
| 54.9 |
| 34,022 |
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
|
|
|
|
|
|
|
Heavy Oil District |
| — |
| 23,911 |
| 10.6 |
| 25,676 |
|
Conventional Oil and Gas District |
| 2,273 |
| — |
| 52.4 |
| 11,010 |
|
Total Production |
| 2,273 |
| 23,911 |
| 63.0 |
| 36,686 |
|
|
|
|
|
|
|
|
|
|
|
REVENUE
Petroleum and natural gas sales for 2004 increased by four percent to $420.4 million from $403.0 million for fiscal 2003. Benchmark WTI crude oil averaged US$41.40 per barrel for 2004, representing a 33 percent increase over the US$31.04 per barrel for 2003. However, the Trust’s realized wellhead prices were reduced by a strengthening Canadian dollar, which averaged US$0.7683 in 2004, compared to US$0.7135 in 2003. The Trust’s light oil and NGLs price increased to $48.64 per barrel from $40.01 per barrel. The heavy oil price increased 14 percent to $30.32 per barrel in 2004 from $26.68 per barrel in 2003. Natural gas prices were four percent higher in 2004, averaging $6.46 per mcf compared to $6.23 per mcf during the previous year. Overall, after accounting for $78.1 million of realized losses on financial derivative contracts, the Trust averaged $27.48 per boe for 2004, a two percent decrease from $28.07 per boe received in the prior year. For the per-sales-unit calculations, heavy oil sales for 2004 were five barrels per day lower (2003 – 650 barrels per day lower) than the production for the year due to inventory in transit under the Frontier supply agreement.
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For 2004, light oil revenue increased 16 percent over 2003, due to a 22 percent increase in wellhead prices and a four percent decrease in production. Revenue from heavy oil increased 11 percent due to a five percent decrease in sales volume and a 14 percent increase in wellhead prices. Natural gas revenue decreased 10 percent as the 13 percent production decrease was offset by a four percent increase in wellhead price.
GROSS REVENUE ANALYSIS
|
|
|
| 2004 |
|
|
| 2003 |
|
|
| $thousands |
| $/Unit(1) |
| $thousands |
| $/Unit (1) |
|
Oil revenue (barrels) |
|
|
|
|
|
|
|
|
|
Light oil |
| 38,673 |
| 48.64 |
| 33,197 |
| 40.01 |
|
Heavy oil |
| 252,016 |
| 30.32 |
| 226,482 |
| 26.68 |
|
Derivative contract loss |
| (78,124 | ) | (8.58 | ) | (33,777 | ) | (3.62 | ) |
Total oil revenue |
| 212,565 |
| 23.34 |
| 225,902 |
| 24.24 |
|
Natural gas revenue (mcf) |
| 129,711 |
| 6.46 |
| 143,343 |
| 6.23 |
|
Total revenue (boe @ 6:1) |
| 342,276 |
| 27.48 |
| 369,245 |
| 28.07 |
|
(1) Per-unit oil revenue is in $/bbl; per unit natural gas revenue is in $/mcf.
ROYALTIES
For the year ended December 31, 2004, royalties decreased to $66.0 million from $67.2 million for last year and were 15.7 percent of sales compared to 16.7 percent of sales in 2003. Royalties for 2004 were 14.1 percent of sales for light oil, 13.3 percent for heavy oil and 20.9 percent for natural gas. These rates compared to 17.4 percent, 13.0 percent and 22.3 percent, respectively, for 2003.
OPERATING EXPENSES
Operating expenses for 2004 increased five percent to $89.1 million from $86.0 million for 2003. This increase is attributable to general industry inflation. Operating expenses were $7.15 per boe for 2004 compared to $6.54 per boe for the prior year. In 2004, operating expenses were $9.51 per barrel of light oil, $7.83 per barrel of heavy oil and $0.82 per mcf of natural gas compared to $8.32, $7.34 and $0.73, respectively, for 2003.
TRANSPORTATION EXPENSES
Transportation expenses for 2004 were $18.7 million compared to $17.8 million for 2003. These expenses were $1.50 per boe in 2004 compared to $1.36 in 2003. Transportation expenses were $1.66 per barrel of oil and $0.18 per mcf of natural gas in 2004 and $1.50 per barrel of oil and $0.16 per mcf of natural gas in 2003.
OPERATING NETBACKS
|
| Light oil |
| Heavy |
| Total Oil |
| Natural |
|
|
|
|
| ||||||||
|
| and NGLs |
| Oil |
| and NGLs |
| Gas |
| BOE |
| ||||||||||
|
| ($/bbl) |
| ($/bbl) |
| ($/bbl) |
| ($/mcf) |
| ($/boe) |
| ||||||||||
|
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
| 2004 |
| 2003 |
|
Sales price |
| 48.64 |
| 40.01 |
| 30.32 |
| 26.68 |
| 31.91 |
| 27.86 |
| 6.46 |
| 6.23 |
| 33.75 |
| 30.64 |
|
Royalties |
| (6.88 | ) | (6.96 | ) | (4.02 | ) | (3.47 | ) | (4.27 | ) | (3.78 | ) | (1.35 | ) | (1.39 | ) | (5.30 | ) | (5.11 | ) |
Operating costs |
| (9.51 | ) | (8.32 | ) | (7.83 | ) | (7.34 | ) | (7.97 | ) | (7.43 | ) | (0.82 | ) | (0.73 | ) | (7.15 | ) | (6.54 | ) |
Transportation |
| (0.92 | ) | (0.97 | ) | (1.73 | ) | (1.55 | ) | (1.66 | ) | (1.50 | ) | (0.18 | ) | (0.16 | ) | (1.50 | ) | (1.36 | ) |
Net revenue |
| 31.33 |
| 23.76 |
| 16.74 |
| 14.32 |
| 18.01 |
| 15.15 |
| 4.11 |
| 3.95 |
| 19.80 |
| 17.63 |
|
Note: Sales prices in this table are before the loss/gain recognized on financial derivative contracts.
17
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses for the year were $15.2 million compared to $8.9 million for the prior year. On a per sales unit basis, these expenses were $1.22 per boe in 2004 and $0.71 per boe in 2003. In accordance with full cost accounting policy, $4.4 million of expenses were capitalized in 2003, while no expenses have been capitalized in 2004. The amount of capitalized expenses has been reduced due to lower exploration activity since the effective date of the Plan of Arrangement.
GENERAL AND ADMINISTRATIVE EXPENSES
($ thousands) |
| 2004 |
| 2003 |
|
Gross corporate expense |
| 20,413 |
| 20,496 |
|
Operator’s recoveries |
| (5,170 | ) | (7,166 | ) |
Subtotal |
| 15,243 |
| 13,330 |
|
Capitalized expense |
| — |
| (4,403 | ) |
Net expense |
| 15,243 |
| 8,927 |
|
UNIT BASED COMPENSATION EXPENSE
The Trust accounts for compensation expense based on the fair value of rights granted under its unit-based compensation plan. The Trust is unable to determine the fair value of the rights granted as the plan contains a provision for the reduction, in certain circumstances, in the exercise price. Therefore, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the financial statements for unexercised rights. For 2004, compensation expense was $7.7 million compared to $0.7 million for 2003. Compensation expense on the Trust’s unit rights incentive plan has been determined based on the amount that the market price of the trust unit exceeds the exercise price for rights issued as at the date of the consolidated financial statements. The compensation expense for 2003 also includes $0.5 million based on the fair value of the stock options outstanding prior to the Plan of Arrangement
INTEREST EXPENSE
In 2004, interest expense was $19.4 million for the year compared to $23.5 million last year. The decrease in total interest expense is due to the redemption of the Company’s senior secured notes in May 2003 and the stronger Canadian currency as interest on the long-term notes is denominated in U.S. dollars.
COSTS ON REDEMPTION AND EXCHANGE OF NOTES
On July 9, 2003, the Company completed an exchange offer related to its previously outstanding US$150 million 10.5 percent senior subordinated notes due 2011 (the “Old Notes”). The Company issued US$179.7 million of 9.625 percent senior subordinated notes due 2010 in exchange for US$149.8 million of the Old Notes and incurred a non-cash loss of $40.0 million on the completion of this transaction, which was recognized in income. Also recognized in income is $4.7 million of costs on the redemption of the US$57 million 7.23 percent senior secured notes.
FOREIGN EXCHANGE
The foreign exchange gain for 2004 was $16.0 million compared to a gain of $52.1 million in the prior year. The 2004 gain is based on the translation of the Company’s U.S. dollar denominated long-term debt at 0.8308 at December 31, 2004 compared to 0.7737 at December 31, 2003. The 2003 gain is based on translation at 0.7737 at December 31, 2003 compared to 0.6331 at December 31, 2002.
18
DEPLETION, DEPRECIATION AND ACCRETION
Depletion, depreciation and accretion increased to $160.8 million for 2004 compared to $123.1 million for the same period last year. On a sales-unit basis, the depletion and depreciation provision for the current period was $12.91 per boe compared to $9.36 per boe for the same period a year earlier. This rate increase is due to the revisions in proved reserves at year-end 2003 pursuant to the implementation of the new standards of disclosure for oil and gas activities, National Instrument (“NI”) 51-101.
INCOME TAXES
Current tax expenses were $9.0 million for 2004 compared to $9.7 million for the same period last year. The current tax expense is comprised of $7.0 million of Saskatchewan Capital Tax and $2.0 million of Large Corporation Tax compared to $8.0 million and $1.7 million, respectively, in 2003.
The fiscal 2004 provision for future income taxes was a recovery of $41.2 million compared to a recovery of $14.5 million for the prior year. The future income tax recovery for 2004 included a non-recurring adjustment resulting from a 0.5 percent decrease to the Alberta corporate income tax rate and from the federal legislation introduced to change the taxation of resource income.
CANADIAN TAX POOLS
($ thousands) |
| December 31, 2004 |
|
Cumulative Canadian Exploration Expense |
| 1,283 |
|
Cumulative Canadian Development Expense |
| 99,741 |
|
Cumulative Canadian Oil and Gas Property Expense |
| 155,930 |
|
Undepreciated Capital Cost |
| 195,235 |
|
Other |
| 39,430 |
|
|
| 491,619 |
|
CASH FLOW FROM OPERATIONS
Cash flow from operations 2004 decreased 1.6 percent to $136.0 million from $138.2 million for the previous year. On a barrel of oil equivalent basis, cash flow from operations was $10.03 for 2004 compared to $10.40 for 2003. The decrease is due to higher realized losses from financial derivative contracts in 2004.
CASH FLOW NETBACKS
|
| 2004 |
| 2003 |
| ||||
|
| $/boe |
| Percent |
| $/boe |
| Percent |
|
Production revenue |
| 33.75 |
| 100 |
| 30.64 |
| 100 |
|
Derivative contract loss |
| (6.27 | ) | (19 | ) | (2.57 | ) | (8 | ) |
Royalties |
| (5.30 | ) | (16 | ) | (5.11 | ) | (17 | ) |
Operating expenses |
| (7.15 | ) | (21 | ) | (6.54 | ) | (21 | ) |
Transportation |
| (1.50 | ) | (4 | ) | (1.36 | ) | (5 | ) |
Field netbacks |
| 13.53 |
| 40 |
| 15.06 |
| 49 |
|
General and administrative expenses |
| (1.22 | ) | (4 | ) | (0.71 | ) | (2 | ) |
Reorganization costs |
| — |
| — |
| (1.43 | ) | (5 | ) |
Interest expense |
| (1.56 | ) | (4 | ) | (1.79 | ) | (6 | ) |
Current income taxes |
| (0.72 | ) | (2 | ) | (0.73 | ) | (2 | ) |
Cash flow netbacks |
| 10.03 |
| 30 |
| 10.40 |
| 34 |
|
19
NET INCOME
Net income for 2004 was $13.8 million compared to $35.8 million for 2003. The increased petroleum and natural gas sales realized through higher wellhead prices in 2004 were offset by increased charges for depletion, depreciation and accretion, a lower foreign exchange gain and a higher realized loss on financial derivatives. Net income for each year has also been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust’s consolidated net income.
CAPITAL EXPENDITURES
Exploration and development expenditures decreased to $94.5 million for 2004 compared to $179.2 million last year. The lower capital expenditures reflect a different business plan since the conversion to an income trust. For the year ended December 31, 2004, the Trust participated in the drilling of 138 (135.0 net) wells, resulting in 104 (103.1 net) oil wells, 16 (14.4 net) gas wells, seven (6.5 net) stratigraphic test wells and 11 (11.0 net) dry holes compared to prior year activities of 266 (243.4 net) wells, including 173 (158.9 net) oil wells, 67 (61.4 net) gas wells, seven (5.1 net) service wells and 19 (18.0 net) dry holes. On September 22, 2004, the Company acquired all of the issued and outstanding shares of a private oil and gas company with operations in Alberta for $109 million plus adjustments. Effective December 22, 2004, the Company acquired oil and natural gas interests in the West Stoddart area of northeast British Columbia for $90 million plus adjustments.
Year Ended December 31 |
|
|
|
|
|
($ thousands) |
| 2004 |
| 2003 |
|
Land |
| 8,744 |
| 14,138 |
|
Seismic |
| 1,283 |
| 5,436 |
|
Drilling and completion |
| 55,322 |
| 110,892 |
|
Equipment |
| 25,982 |
| 42,365 |
|
Other |
| 3,152 |
| 6,401 |
|
Total exploration and development |
| 94,483 |
| 179,232 |
|
Corporate acquisition |
| 111,042 |
| — |
|
Property acquisitions |
| 89,582 |
| 6,644 |
|
Property dispositions |
| (14,441 | ) | (137,493 | ) |
Total capital expenditures |
| 280,666 |
| 48,383 |
|
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2004, total net debt (including working capital) was $422.0 million compared to $213.6 million at December 31, 2003. The $422.0 million net debt included $9.5 million of notional liabilities based on the mark-to-market valuations of derivative contracts as at December 31, 2004. The increase in total debt at year-end 2004 compared to 2003 was the result of the increase in bank loans used to fund capital expenditures during 2004.
The Company’s debt structure consists of two components. The first component is the senior credit facilities. The Company has a credit agreement with a syndicate of chartered banks. The credit facilities consist of an operating loan and a 364-day revolving loan. Advances under the credit facilities or letters of credit can be drawn in either Canadian or U.S. funds and bear interest at the agent bank’s prime lending rate, bankers’ acceptance rates plus applicable margins or LIBOR rates plus applicable margins. The facilities aggregating $250 million are subject to semi-annual review and are secured by a floating charge over all of the Company’s assets. At December 31, 2004 at total of $161.4 million had been drawn under the credit facilities.
The second component is the senior subordinated notes. On February 12, 2001, the Company issued US$150 million of senior subordinated term notes (“Old Notes”) bearing interest at 10.5 percent payable semi-annually with principal repayable on February 15, 2011. These notes are unsecured and
20
are subordinate to the Company’s bank credit facilities. On July 9, 2003, the Company completed an exchange offer related to its Old Notes. The Company issued US$179.7 million ($247.1 million) of 9.625 percent senior subordinated notes due July 15, 2010 (“New Notes”) in exchange for US$149.8 million of the Old Notes. The New Notes are unsecured and are subordinate to the Company’s bank credit facilities.
The bank credit facilities contain restrictions on the Company’s ability to make distributions to the Trust if the Company is in default under such facilities or the distribution would have a material adverse effect on the ability of the Company to meet its obligations to its lenders. In addition, the note indenture relating to the senior subordinated notes contains a limitation on restricted payments whereby the Company is restricted from making any restricted payments, including distributions to the Trust, if a default or event of default under the note indenture has occurred and is continuing.
The Trust believes that cash flow generated from its operations, together with existing capacity under the bank facilities, will be sufficient to finance current operations and planned capital expenditures for the next year. The timing of most of the capital expenditures is discretionary and there are no material long-term capital expenditure commitments.
UNITHOLDERS’ EQUITY
The Trust is authorized to issue an unlimited number of trust units. Pursuant to the Plan of Arrangement, 53.3 million trust units and 4.7 million exchangeable shares were issued on September 2, 2003 on the exchange of the common shares of the Company. An additional 6.5 million trust units were issued on December 12, 2003 for gross proceeds of $65 million. On December 20, 2004, the Trust issued 3.6 million trust units at $12.80 per unit for gross proceeds of $46.1 million.
On October 18, 2004, the Trust implemented a Distribution Reinvestment Plan (“DRIP”). Under the DRIP, Canadian unitholders can elect to reinvest monthly cash distributions in additional trust units of the Trust. Trust units purchased from treasury under the DRIP will be issued at a 5 percent discount from the weighted average closing price of the trust units on the Toronto Stock Exchange The weighted average closing price is calculated as the weighted average trading price of trust units for the period commencing on the second business day after the distribution record date and ending on the second business day immediately prior to the distribution payment date, such period not to exceed 20 trading days. The Trust can also acquire trust units to be issued under the DRIP at prevailing market rates.
NON-CONTROLLING INTEREST
The Company is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares can be converted (at the option of the holder) into trust units at any time up to September 2, 2013. Up to 1.9 million exchangeable shares may be redeemed annually by the Company for either cash or the issue of trust units. At December 31, 2004, there were 1.9 million exchangeable shares outstanding. During 2004, a total of 1.8 million exchangeable shares were exchanged for trust units. The number of trust units issuable upon conversion is based upon the exchange ratio in effect at the conversion date. The exchange ratio is calculated monthly based on the cash distribution paid divided by the weighted average trust unit price of the five-day trading period ending on the record date. The exchange ratio at December 31, 2004 was 1.21472 trust units per exchangeable share (December 31, 2003 – 1.04530 trust units per exchangeable share). Cash distributions are not paid on the exchangeable shares. The exchangeable shares are not publicly traded, although they may be transferred by the holder without first being converted to trust units.
The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary for them to be classified as equity. Net income has been reduced by an amount equivalent to the non-controlling interest proportionate share of the Trust’s consolidated net income with a corresponding increase to the non-controlling interest on the balance sheet.
21
CASH DISTRIBUTIONS
During 2004 total cash distributions of $1.80 per unit were declared. The monthly cash distribution of $0.15 per unit has been maintained since the inception of the Trust in September 2003.
OFF BALANCE SHEET ARRANGEMENTS AND CONTRACTUAL OBLIGATIONS
The Trust has assumed various contractual obligations and commitments, as detailed in the table below, in the normal course of operations and financing activities. These obligations and commitments have been considered when assessing the cash requirements in the above discussion of future liquidity.
CONTRACTUAL OBLIGATIONS
|
|
|
| Payments Due by Period |
| ||||||
($ thousands) |
| Total |
| Less than |
| 1-3 years |
| 4-5 years |
| After |
|
Long-term debt (1) |
| 216,583 |
| — |
| — |
| — |
| 216,583 |
|
Operating leases |
| 9,473 |
| 1,359 |
| 5,469 |
| 2,645 |
| — |
|
Capital lease |
| 782 |
| 221 |
| 561 |
| — |
| — |
|
Transportation agreements |
| 5,166 |
| 2,675 |
| 2,491 |
| — |
| — |
|
Total contractual obligations |
| 232,004 |
| 4,255 |
| 8,521 |
| 2,645 |
| 216,583 |
|
(1) Total US $180 million
The Trust also has ongoing obligations related to the abandonment and reclamation of well and facility sites which have reached the end of their economic lives. Programs to abandon and reclaim well and facility sites are undertaken regularly in accordance with applicable legislative requirements.
RISK AND RISK MANAGEMENT
The exploration for and the development, production and marketing of petroleum and natural gas involves a wide range of business and financial risks, some of which are beyond the Trust’s control. Included in these risks are the uncertainty of finding new reserves, the fluctuations of commodity prices, the volatile nature of interest and foreign exchange rates, and the possibility of changes to royalty, tax and environmental regulations. The petroleum industry is highly competitive and the Trust competes with a number of other entities, many of which have greater financial and operating resources.
The business risks facing the Trust are mitigated in a number of ways. Geological, geophysical, engineering, environmental and financial analyses are performed on new exploration prospects, development projects and potential acquisitions to ensure a balance between risk and reward. The Trust’s ability to increase its production, revenues and cash flow depends on its success in not only developing its existing properties but also in acquiring, exploring for and developing new reserves and production and managing those assets in an efficient manner.
Despite best practice analysis being conducted on all projects, there are numerous uncertainties inherent in estimating quantities of petroleum and natural gas reserves, including future oil and natural gas prices, engineering data, projected future rates of production and the timing of future expenditures. The process of estimating petroleum and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. An independent engineering firm evaluates the Trust’s properties annually to determine a fair estimate of reserves. The Reserves Committee, consisting of independent members of the Company’s Board of Directors, assists the Board in their annual review of the reserves evaluation.
22
The provision for depletion and depreciation in the financial statements and the ceiling test are based on reserves estimates. Any future significant revisions could result in a full cost accounting write-down or material changes to the annual rate of depletion and depreciation.
The financial risks that the Trust is exposed to as part of the normal course of its business are managed, in part, with various financial derivative instruments, in addition to fixed-price physical delivery contracts. The use of derivative instruments is governed under formal internal policies established by the Board of Directors. Derivative instruments are not used for speculative or trading purposes.
The Trust’s financial results can be significantly affected by the prices received for petroleum and natural gas production as commodity prices fluctuate in response to changing market forces. This pricing volatility is expected to continue. As a result, The Trust has a risk management program that may be used to protect the prices of oil and natural gas on a portion of the total expected production. The objective is to decrease exposure to market volatility and ensure the Trust’s ability to finance its distributions and capital program.
The Trust’s financial results are also impacted by fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil and, to a large extent, natural gas prices are based on reference prices denominated in U.S. dollars, while the majority of expenses are denominated in Canadian dollars. The exchange rate also impacts the valuation of the U.S. dollar denominated long-term notes. The related foreign exchange gains and losses are included in net income. There is no plan at this time to fix the exchange rate on any of the Trust’s long-term borrowings.
The Trust is exposed to changes in interest rates as the Company’s banking facilities are based on our lenders’ prime lending rate and short-term Bankers’ Acceptance rates. Changes in interest rates also impact the Company’s interest rate swap contract which converts the fixed interest rate of 9.625 percent on the US$179.7 million notes to a floating rate reset quarterly at the three month LIBOR rate plus 5.2 percent until the maturity of these notes.
The Trust’s current position with respect to its financial derivative contracts is detailed in note 16 of the consolidated financial statements.
CRITICAL ACCOUNTING POLICIES
The preparation of the consolidated financial statements in accordance with generally accepted accounting principles requires management to make judgments and estimates that affect the financial results of the Trust. These critical estimates are discussed below.
OIL AND GAS ACCOUNTING
The Trust follows the full-cost accounting guideline to account for its petroleum and natural gas operations. Under this method, all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized in one Canadian cost centre. These capitalized costs, along with estimated future development costs, are depleted and depreciated on a unit-of-production basis using estimated proved petroleum and natural gas reserves. By their inclusion in the unit-of-production calculation, reserve estimates are a significant component of the calculation of depletion and depreciation and site restoration expense.
Independent engineers engaged by the Trust use all available geological, reservoir, and production performance data to prepare the reserve estimates. These estimates are reviewed and revised, either upward or downward, as new information becomes available. Revisions are necessary due to changes in assumptions based on reservoir performance, prices, economic conditions, government restrictions and other relevant factors. If reserve estimates are revised downward, net income could be affected by increased depletion and depreciation.
23
IMPAIRMENT OF PETROLEUM AND NATURAL GAS ASSETS
Companies that use the full-cost method of accounting for oil and natural gas operations are required to perform a ceiling test that calculates a limit for the net carrying cost of petroleum and natural gas assets. The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test (the “ceiling test”). The ceiling test is a two-stage process. The first stage of the test is a recovery test which compares the undiscounted future cash flow from proved reserves at forecast prices plus the cost less impairment of unproved properties to the net book value of the petroleum and natural gas assets to determine if the assets are impaired. An impairment loss exists when the net book value of the petroleum and natural gas assets exceeds such undiscounted cash flow. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flow from proved plus probable reserves at forecast prices. If reserve estimates are revised downward, net income could be affected by any additional depletion and deprecation recorded under the ceiling test calculation and could result a significant accounting loss for a particular period.
ASSET RETIREMENT OBLIGATIONS
The amounts recorded for asset retirement obligations were estimated based on the Trust’s net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future. Any changes to these estimates could change the amount recorded for asset retirement obligations and may materially impact the consolidated financial statements of future periods.
CHANGES IN ACCOUNTING POLICIES
UNIT-BASED COMPENSATION
At December 31, 2003, the Trust elected to adopt amendments to CICA Handbook Section 3870, “Stock-based Compensation and Other Stock-based Payments” pursuant to the transitional provisions contained therein. Under this amended standard, the Trust accounts for compensation expense based on the fair value of rights granted under its unit-based compensation plan. As the Trust is unable to determine the fair value of the rights granted, compensation expense has been determined based on the intrinsic value of the rights at the exercise date or at the date of the consolidated financial statements for unexercised rights. For the year ended December 31, 2003, compensation expense of $0.22 million was recorded as non cash general and administrative expense for all trust unit rights granted during 2003, with a corresponding amount recorded as contributed surplus.
The adoption of these amendments also impacted the stock options outstanding prior to the Plan of Arrangement. For the year ended December 31, 2003, compensation expense of $0.52 million was recorded as non-cash general and administrative expense for all stock options granted on or after January 1, 2003, with a corresponding amount recorded as contributed surplus. For stock options granted prior to January 1, 2003, the pro forma earnings impact of related stock-based compensation expense is disclosed (note 18 to the consolidated financial statements).
FULL COST ACCOUNTING
In 2003, the CICA issued Accounting Guideline 16, Oil and Gas Accounting – Full Cost (AcG-16). The guideline is effective for fiscal years beginning on or after January 1, 2004. The new guideline modifies the ceiling test calculation applied by the Trust. The ceiling test was changed to a two-stage process which is to be performed at least annually. The first stage of the test is a recognition test which compares the undiscounted future cash flow from proved reserves at forecast prices plus the cost less
24
impairment of unproved properties to the net book value of the petroleum and natural gas assets to determine if the assets are impaired. An impairment loss exists when the carrying amount of the petroleum and natural gas assets exceeds such undiscounted cash flow. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flow from proved plus probable reserves at forecast prices. The adoption of this guideline on January 1, 2004 did not have an impact on the financial results of the Trust. The ceiling test impairment test was calculated on January 1, 2004 using the following benchmark reference prices at January 1, 2004 for the years 2004 to 2008 adjusted for commodity differentials specific to the Trust (note 17 to the consolidated financial statements):
|
| 2004 |
| 2005 |
| 2006 |
| 2007 |
| 2008 |
|
WTI ($US/bbl) |
| 29.63 |
| 26.80 |
| 25.76 |
| 26.14 |
| 26.53 |
|
AECO ($CDN/mcf) |
| 6.03 |
| 5.36 |
| 4.80 |
| 4.91 |
| 4.98 |
|
ASSET RETIREMENT OBLIGATIONS
Effective January 1, 2004, the Trust adopted the CICA Section 3110, “Asset Retirement Obligations”. This section requires recognition of a liability at discounted fair value for the future abandonment and reclamation associated with the petroleum and natural gas properties. The fair value of the liability is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The related accretion expense is recognized in the statement of operations. The provision will be revised for any changes to timing related to cash flow or undiscounted abandonment costs. Actual expenditures incurred for the purpose of site reclamation are charged to the asset retirement obligations to the extent that the liability exists on the balance sheet. Differences between the actual costs incurred and the fair value of the liability recorded are recognized in income in the period incurred.
The provisions of this section require that the standard be applied retroactively with restatement of comparative periods. As a result of this change, net income for the comparative year ended December 31, 2003 decreased by $2.8 million, net of future income tax of $0.8 million. At December 31, 2003 the asset retirement obligations balance increased by $32.5 million to $56.0 million, the petroleum and natural gas assets balance increased by $19.2 million to $862.3 million and the future tax liability decreased by $5.0 million to $169.3 million. The opening 2003 accumulated deficit increased by $5.4 million (net of future income tax of $0.8 million). There was no impact on cash flow from operations as a result of adopting this policy (note 8 to the consolidated financial statements).
FINANCIAL DERIVATIVE CONTRACTS
Effective January 1, 2004, the Trust implemented CICA Accounting Guideline 13 “Hedging Relationships” (AcG-13) for accounting for derivative contracts. This guideline addresses the identification, designation, documentation and effectiveness of hedging transactions for the purposes of applying hedge accounting. It also establishes conditions for applying or discontinuing hedge accounting. Under the new guideline, hedging transactions must be documented and it must be demonstrated that the hedges are sufficiently effective in order to continue accrual accounting for positions hedged with derivatives. Upon implementation of AcG-13, Emerging Issues Committee Abstract 128 (EIC-128) also became effective. EIC-128 requires that changes in the fair value of these derivative contracts that do not qualify for hedge accounting under AcG-13 be recognized in the balance sheet and measured at fair value, with changes in fair value reported as income or expense in each reporting period. The income or expense relating to the change in fair value of the derivative contracts is an expense that has no impact on cash flow but may result in significant fluctuations in net income due to volatility in the underlying market prices. In accordance with the transitional provisions of AcG-13 and EIC-128, the new accounting treatment has been applied prospectively whereby prior periods have not been restated.
25
Prior to January 1, 2004, the Trust accounted for all derivative contracts whereby realized gains and losses on such contracts were included in the statement of operations within the corresponding item to which the contract was related. Following implementation of the guideline, realized and unrealized gains and losses on derivative contracts that do not qualify as effective hedges are reported separately in the statement of operations.
Pursuant to the transitional provisions contained in AcG-13, on January 1, 2004, the Trust recorded a deferred charge for the unrealized loss of $10.1 million for the mark-to-market value of the outstanding non-hedging financial derivatives. This balance has being recognized in income during the year ended December 31, 2004. At December 31, 2004, the Trust recorded a liability of $9.5 million on the mark-to-market value of the outstanding non-hedging financial derivatives. The change in the mark-to-market value of the non-hedging financial derivatives from the inception of the contracts to December 31, 2004 has been recorded as an unrealized gain on non-hedging financial derivatives of $0.6 million in the consolidated statement of operations (note 16 to the consolidated financial statements).
TRANSPORTATION COSTS
CICA Handbook Section 1100, “Generally Accepted Accounting Principles”, is effective for fiscal years beginning on or after October 1, 2003. This standard focuses on what constitutes Canadian generally accepted accounting principles and its sources, including the primary sources of generally accepted accounting principles. In prior periods, it had been industry practice to record revenue net of related transportation costs. In accordance with the new accounting standards, revenue is now reported before transportation costs with separate disclosure in the consolidated statement of operations of transportation costs. Petroleum and natural gas sales and transportation costs for the year ended December 31, 2004 both increased by $18.7 million (2003 – $17.8 million) as a result of this change. This change in classification has no impact on net income and the comparative figures have been restated to conform to the presentation adopted for the current period.
NON-CONTROLLING INTEREST
The Trust has implemented the accounting for the exchangeable shares issued by the Company as required by EIC Abstract 151, “Exchangeable Securities Issued by Subsidiaries of Income Trusts” (EIC 151), issued in January 2005. Under EIC 151, exchangeable shares issued by a subsidiary of an income trust are presented as non-controlling interest, unless certain conditions are met. The exchangeable shares of the Company are presented as a non-controlling interest on the consolidated balance sheet because they fail to meet the non-transferability criteria necessary for them to be classified as equity. The presentation of the exchangeable shares at December 31, 2003 was restated to conform to the presentation for the current year, pursuant to the transitional provisions contained in EIC 151. Previously, the exchangeable shares were reflected as a component of Unitholders’ Equity (note 10).
As a result of the adoption of EIC 151, net income was reduced in 2004 by $0.35 million for the non-controlling interest’s share of income and was increased in 2003 by $0.67 million for the non-controlling interest’s share of the loss from the date of the Arrangement. There was no impact on cash flow from operations as a result of adopting this policy. As the exchangeable shares are converted to Trust units, Unitholders’ capital was increased by the fair value of the Trust units issued. The difference between the fair value of the Trust units issued and the book value of the exchangeable shares is recorded as an increase in petroleum and natural gas properties.
26
The adoption of EIC 151 had the following impact on the Trust’s previously reported financial statements:
|
| Three Months Ended |
| ||||||||
($ thousands, except per unit amounts) |
| September |
| June |
| March |
| December |
| September |
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (12,604 | ) | (11,170 | ) | (4,296 | ) | 9,127 |
| (46,245 | ) |
Restated: |
| (12,554 | ) | (11,213 | ) | (4,578 | ) | 8,490 |
| (45,079 | ) |
Net income (loss) per unit basic |
|
|
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (0.20 | ) | (0.17 | ) | (0.07 | ) | 0.14 |
| (0.84 | ) |
Restated: |
| (0.20 | ) | (0.18 | ) | (0.07 | ) | 0.14 |
| (0.82 | ) |
Net income (loss) per unit diluted |
|
|
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (0.20 | ) | (0.17 | ) | (0.07 | ) | 0.14 |
| (0.84 | ) |
Restated: |
| (0.20 | ) | (0.18 | ) | (0.07 | ) | 0.15 |
| (0.84 | ) |
($ thousands, except per unit amounts) |
| Nine Months |
| Six Months |
| Year |
| Nine Months |
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (28,070 | ) | (15,466 | ) | 35,315 |
| 26,188 |
|
Restated: |
| (28,345 | ) | (15,791 | ) | 35,844 |
| 27,354 |
|
Net income (loss) per unit basic |
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (0.45 | ) | (0.24 | ) | 0.64 |
| 0.48 |
|
Restated: |
| (0.45 | ) | (0.25 | ) | 0.66 |
| 0.51 |
|
Net income (loss) per unit diluted |
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| (0.45 | ) | (0.24 | ) | 0.62 |
| 0.48 |
|
Restated: |
| (0.45 | ) | (0.25 | ) | 0.62 |
| 0.48 |
|
|
| As At |
| ||||||||
($ thousands, except per unit amounts) |
| September |
| June |
| March |
| December |
| September |
|
Unitholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
Previously reported: (1) |
| 325,292 |
| 362,791 |
| 400,492 |
| 431,210 |
| 385,678 |
|
Restated: |
| 323,083 |
| 360,267 |
| 397,012 |
| 408,176 |
| 356,049 |
|
Non-controlling interest |
|
|
|
|
|
|
|
|
|
|
|
Previously reported: |
| — |
| — |
| — |
| — |
| — |
|
Restated: |
| 11,822 |
| 12,332 |
| 13,198 |
| 25,705 |
| 30,322 |
|
(1) The amounts previously reported as at and for the periods ended September 2003 and December 2003 have been restated for the adoption of the new accounting standard for asset retirement obligations.
27
NEW ACCOUNTING PRONOUNCEMENTS
FINANCIAL INSTRUMENTS
In January, 2005 the CICA issued three new standards relating to the reporting of financial instruments in financial statements. These standards introduce new requirements for the recognition and measurement of financial instruments and comprehensive income. Section 3855, “Financial Instruments – Recognition and Measurement” requires that all financial instruments, including derivatives, are to be included on a company’s balance sheet and measured, either at their fair values or, in limited circumstances when fair value may not be considered most relevant, at cost or amortized cost. The standard also provides guidance on when gains and losses as a result of changes in fair values are to be recognized in the income statement.
The issuance of the new Section 3855 will result in amendments to Section 3860 “Financial Instruments – Disclosure and Presentation” to make the scope and definitions consistent with that of the new Section 3855, including expanding the scope to include certain commodity-based contracts, and to update certain disclosures in light of the introduction of Section 3855. Other Handbook Sections have also been amended for conformity with the new standards.
Section 3865 “Hedges”, extends the existing requirements for hedge accounting currently under AcG -13. This new section allows for the optional treatment of accounting for financial instruments that are designated as either fair value hedges, cash flow hedges or hedges of a net investment in a self-sustaining foreign operation. For a fair value hedge, the gain or loss on a derivative hedging item, or the gain or loss on a non-derivative hedging item attributable to the hedged risk, is recognized in net income in the period of change together with the offsetting loss or gain on the hedged item attributable to the hedged risk. The carrying amount of the hedged item is adjusted for the hedged risk. For a cash flow hedge, the effective portion of the hedging item’s gain or loss is initially reported in other comprehensive income and subsequently reclassified to net income when the hedged item affects net income. For a hedge of a net investment in a self-sustaining foreign operation the same accounting is followed as for a cash flow hedge.
A new location for recognizing certain gains and losses – other comprehensive income – has been introduced with the issued of Section 1530, “Comprehensive Income”. An integral part of the accounting standards on recognition and measurement of financial instruments is the ability to present certain gains and losses outside net income, in other Comprehensive Income. This standard requires that a company should present comprehensive income and its components in a financial statement displayed with the same prominence as other financial statements that constitute a complete set of financial statements, in both annual and interim financial statements. Exchange gains and losses arising from the translation of the financial statements of a self-sustaining foreign operation, previously recognized in a separate component of shareholders’ equity, in accordance with Section 1650, “Foreign Currency Translation”, will now be recognized in a separate component of other comprehensive income.
These three new Handbook Sections are effective date for annual and interim periods in fiscal years beginning on or after October 1, 2006. The Trust is evaluating the impact the adoption of these new standards will have on its consolidated financial statements.
OTHER PROPOSED STANDARDS
The CICA has proposed amendments to Section 3500 “Earnings per Share”, which include the requirement to include in the computation of basic earnings per share any shares issued upon conversion of a mandatorily convertible instrument. The computational guidance for calculating the number of incremental shares included in diluted shares when applying the treasury stock method
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is also amended. These amendments were not enacted in final form as of the time of release of the Trust’s 2004 consolidated financial statements.
The CICA has issued an Exposure Draft of a new Section 3830, “Non-Monetary Transactions” which proposes that all non-monetary transactions be measured at fair value, unless certain criteria are met. A final standard is planned to be issued in the first quarter of 2005.
A Re-Exposure draft on Section 3820, “Subsequent Events” was issued in January 2005, which proposes to separately define the subsequent event period and to require disclosure of the dates to which subsequent events are reflected in the financial statements. This Re-Exposure draft was not enacted in final form as of the time of release of the Trust’s 2004 consolidated financial statements.
FOURTH QUARTER 2004
The following discussion reviews the Trust’s results of operations for the fourth quarter of 2004.
Light oil production for the fourth quarter of 2004 increased by 41 percent to 2,786 barrels per day from 1,982 barrels per day a year earlier primarily due to the acquisition in September 2004. Heavy oil production decreased 8 percent to 22,490 barrels per day for the fourth quarter of 2004 compared to 24,400 barrels per day a year ago. Natural gas production decreased by 6 percent to 55.5 mmcf/d for the fourth quarter of 2004 compared to 58.9 mmcf/d for the same period last year. These decreases are due to a lower exploration and development program in 2004.
Petroleum and natural gas sales increased 24 percent to $111.5 million for the quarter ended December 31, 2004 from $89.5 million for the same period in 2003. Total royalties increased to $17.4 million for the fourth quarter of 2004 from $13.5 million in 2003. Total royalties for the fourth quarter of 2004 were 15.6 percent of sales compared to 15.1 percent of sales for the same period in 2003. Operating expenses for the fourth quarter of 2004 increased to $24.2 million from $22.1 million in the corresponding quarter last year. Operating expenses were $7.63 per boe for the fourth quarter of 2004 compared to $6.74 per boe for the fourth quarter of 2003. Transportation expenses for the fourth quarter of 2004 were $4.6 million compared to $4.7 million for the fourth quarter of 2003. These expenses were $1.43 per boe for the fourth quarter of 2004 compared to $1.45 for the same period in 2003.
General and administrative expenses increased to $4.1 million in the fourth quarter of 2004 from $3.6 million one year ago. On a per sales unit basis, these expenses were $1.43 per boe for the fourth quarter of 2004 compared to $1.21 per boe for 2003. In accordance with full cost accounting policy, no expenses were capitalized in either the fourth quarter of 2003 or 2004.
Interest expense increased to $6.4 million for the fourth quarter of 2004 from $5.2 million for the same quarter last year. The increase can be attributed to interest incurred on amounts drawn on the Trust’s credit facilities in the fourth quarter of 2004.
The foreign exchange gain in the fourth quarter of 2004 was $10.9 million compared to a gain of $10.4 million in the prior year.
The provision for depletion, depreciation and accretion was $41.5 million for the fourth quarter of 2004 compared to $42.6 million for the same quarter a year ago. On a sales-unit basis, the provision for the current quarter was $12.87 per boe compared to $12.14 per boe for the same quarter in 2003.
Net income for the fourth quarter of 2004 was $42.1 million compared to $9.0 million for the corresponding quarter of 2003. In 2004, the increased petroleum and natural gas sales realized through higher wellhead prices in 2004 were offset by increased charges for depletion, depreciation and accretion, a lower foreign exchange gain and a higher realized loss on financial derivatives. In 2003, increased depletion expense was offset by foreign exchange gains and a recovery of future income taxes.
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OUTSTANDING UNIT INFORMATION
At of February 28, 2005, the Trust had 66,650,987 units outstanding and the Company had 1,860,944 exchangeable shares outstanding. The exchange ratio at February 28, 2005 was 1.243 trust units per exchangeable share.
SELECTED ANNUAL INFORMATION
FINANCIAL (unaudited)
($ thousands, except per unit amounts) |
| 2004 |
| 2003(2) |
| 2002(2) |
|
Revenue |
| 420,400 |
| 403,022 |
| 372,037 |
|
Net income (loss) (1) |
| 13,763 |
| 35,844 |
| 43,729 |
|
Per unit basic (1) |
| 0.22 |
| 0.66 |
| 0.84 |
|
Per unit diluted (1) |
| 0.21 |
| 0.62 |
| 0.82 |
|
Total assets |
| 1,104,136 |
| 982,640 |
| 1,018,382 |
|
Total long-term financial liabilities |
| 216,583 |
| 232,562 |
| 326,977 |
|
Cash distributions declared |
| 113,063 |
| 33,382 |
| — |
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(1) Net income and net income per unit is after non-controlling interest related to exchangeable shares. The net income and net income per unit for 2003 have been restated due to the retroactive application of the new accounting standard for non-controlling interest (see note 3 of the consolidated financial statements). The application of this standard did not impact the 2002 financial information.
(2) The financial information for 2003 and 2002 has been restated for the adoption of the new accounting standards related to asset retirement obligations and transportation expenses.
Overall production for 2004 was 34,022 boe per day which represented a seven percent decrease from 36,686 boe per day in 2003. Average wellhead prices received during 2004 were $27.48 per boe compared to $28.07 during 2003. Production in 2002 was 39,214 boe per day. Average wellhead prices received in 2002 were $25.56 per boe. Total revenue for 2004 was $420.4 million compared to $403.0 million in 2003 and $372.0 million in 2002.
QUARTERLY INFORMATION
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| 2004 |
| 2003 |
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($ thousands, except per share amounts) |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
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FINANCIAL (unaudited) |
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Revenue |
| 111,521 |
| 108,216 |
| 104,517 |
| 96,146 |
| 89,526 |
| 98,692 |
| 89,999 |
| 124,805 |
|
Cash flow from operations |
| 28,144 |
| 32,235 |
| 36,944 |
| 38,689 |
| 30,179 |
| 19,975 |
| 33,372 |
| 54,707 |
|
Per unit basic |
| 0.44 |
| 0.51 |
| 0.59 |
| 0.63 |
| 0.51 |
| 0.36 |
| 0.62 |
| 1.03 |
|
Per unit diluted |
| 0.42 |
| 0.49 |
| 0.57 |
| 0.60 |
| 0.51 |
| 0.36 |
| 0.61 |
| 1.01 |
|
Cash distribution declared |
| 28,856 |
| 28,266 |
| 28,237 |
| 27,704 |
| 25,344 |
| 8,038 |
| — |
| — |
|
Per unit |
| 0.45 |
| 0.45 |
| 0.45 |
| 0.45 |
| 0.45 |
| 0.15 |
| — |
| — |
|
Net income (loss) (1) |
| 42,108 |
| (12,554 | ) | (11,213 | ) | (4,578 | ) | 8,490 |
| (45,079 | ) | 40,329 |
| 32,104 |
|
Per unit basic (1) |
| 0.66 |
| (0.20 | ) | (0.18 | ) | (0.07 | ) | 0.14 |
| (0.82 | ) | 0.75 |
| 0.60 |
|
Per unit diluted (1) |
| 0.65 |
| (0.20 | ) | (0.18 | ) | (0.07 | ) | 0.14 |
| (0.84 | ) | 0.73 |
| 0.59 |
|
(1) Net income and net income per unit is after non-controlling interest related to exchangeable shares. The net income and net income per unit for 2003 have been restated due to the retroactive application of the new accounting standard for non-controlling interest (see note 3 of the consolidated financial statements).
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| 2004 |
| 2003 |
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| Q4 |
| Q3 |
| Q2 |
| Q1 |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
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PRODUCTION |
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Conventional oil and NGLs (bbls/d) |
| 2,786 |
| 1,890 |
| 1,952 |
| 2,058 |
| 1,982 |
| 1,989 |
| 2,167 |
| 2,969 |
|
Heavy oil (bbls/d) |
| 22,490 |
| 22,083 |
| 22,927 |
| 23,322 |
| 24,400 |
| 25,123 |
| 22,816 |
| 23,278 |
|
Total oil and NGLs (bbls/d) |
| 25,276 |
| 23,973 |
| 24,879 |
| 25,380 |
| 26,382 |
| 27,112 |
| 24,983 |
| 26,247 |
|
Natural gas (mmcf/d) |
| 55.5 |
| 50.9 |
| 57.2 |
| 56.0 |
| 58.9 |
| 61.8 |
| 57.5 |
| 74.0 |
|
Barrels of oil equivalent (boe/d @ 6:1) |
| 34,525 |
| 32,454 |
| 34,411 |
| 34,709 |
| 36,195 |
| 37,412 |
| 34,574 |
| 38,580 |
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AVERAGE PRICES |
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WTI oil (US$/bbl) |
| 48.28 |
| 43.88 |
| 38.32 |
| 35.15 |
| 31.18 |
| 30.20 |
| 28.91 |
| 33.86 |
|
Edmonton par oil ($/bbl) |
| 57.72 |
| 56.32 |
| 50.59 |
| 45.59 |
| 39.56 |
| 40.94 |
| 41.08 |
| 50.91 |
|
BTE light oil ($/bbl) |
| 50.46 |
| 52.63 |
| 47.55 |
| 43.50 |
| 37.46 |
| 35.40 |
| 38.24 |
| 46.21 |
|
BTE heavy oil ($/bbl) |
| 31.24 |
| 34.69 |
| 29.21 |
| 26.29 |
| 24.01 |
| 25.68 |
| 24.59 |
| 32.99 |
|
BTE total oil ($/bbl) |
| 33.35 |
| 36.11 |
| 30.63 |
| 27.70 |
| 25.04 |
| 26.39 |
| 25.80 |
| 34.57 |
|
BTE natural gas ($/mcf) |
| 6.60 |
| 6.16 |
| 6.61 |
| 6.43 |
| 5.56 |
| 5.79 |
| 6.21 |
| 7.17 |
|
BTE oil equivalent ($/boe) |
| 35.03 |
| 36.34 |
| 33.12 |
| 30.63 |
| 27.34 |
| 28.69 |
| 29.02 |
| 37.39 |
|
ADDITIONAL INFORMATION
Additional information relating to the Trust, including the Annual Information Form, may be found on SEDAR at www.sedar.com.
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