Exhibit 1
Enerplus Resources Fund
The Dome Tower
3000, 333-7th Avenue SW
Calgary, Alberta T2P 2Z1
Tel 403.298.2200
Fax 403.298.2211
www.enerplus.com
February 24, 2006
FOR IMMEDIATE RELEASE
Enerplus Resources Fund
TSX: | ERF.UN |
NYSE: | ERF |
ENERPLUS ANNOUNCES 2005 YEAR-END AND RESERVES INFORMATION
Enerplus is pleased to announce our year-end results for 2005. We executed our business strategies on all fronts and achieved record levels of production, reserves, capital spending and opportunity generation. For the first time, we also more than replaced 2005 production through conventional reserve additions on our existing assets excluding any volumes added through acquisitions. These replacements came from capital development and rising commodity prices. Our performance generally met or exceeded targets on all significant metrics and positions us for an even stronger year in 2006. In 2006 we expect to replace reserves once again through conventional and oil sands additions. We also expect to grow our production for the first time through our development program without reliance on new acquisition activity.
HIGHLIGHTS:
• | Achieved a total return of 38.2% for our Canadian unitholders and a 42.1% return for our U.S. unitholders. |
• | Increased our monthly cash distributions per unit from 35 cents to 42 cents while reducing our payout ratio to 64% and funding 77% of our capital development program from retained funds flow. |
• | Recorded a new high in our annual average production of 79,727 BOE/day representing a 6% increase over 2004’s average. We exited the year at 85,000 BOE/day with 3,800 BOE/day expected to come on in early 2006. |
• | Executed our most significant development capital program in our history of $369 million including the participation in drilling 859 wells (net 393.3) with virtually a 100% success rate. |
• | Earned record funds flow from operations of $794 million, a 47% increase over 2004, a 67% increase in net income to $432 million and increases per trust unit of 34% and 52%, respectively. |
• | Increased our proved plus probable reserves by 11% to 449.1 million barrels of oil equivalent which reflects over 100% reserve replacement excluding acquisitions and a 247% replacement of 2005 production including acquisitions. |
• | Essentially maintained both reserves and production per unit on a debt-adjusted basis. |
• | Our reserve life index based on proved plus probable reserves decreased to 13.5 years, a 4% reduction from 14 years due to higher 2006 production forecasted in the independent engineering reports. |
• | Completed a record year of acquisitions and established a new core area in the United States, with $704 million of oil and gas acquisitions including $614 million associated with the acquisitions of Lyco Energy Corporation and Sleeping Giant LLC, two U.S. private companies with established production in Montana and undeveloped acreage in Montana and North Dakota. |
• | Received validation of our investment in the Joslyn property in the Alberta oil sands by virtue of the purchase of Deer Creek Energy Ltd. (our operating partner at Joslyn) by a wholly-owned subsidiary of Total S.A., the fourth largest oil and gas company in the world. |
• | Finding, development and acquisition costs for the year were $13.98 per BOE (based upon proved plus probable reserves) before future development costs and $17.18 per BOE including future development costs and three-year averages of $10.09 and $13.46 per BOE, respectively. |
• | Realized a 28% increase in our average sales price per BOE, 39% in net funds flow per BOE and 58% in net income per BOE. |
• | Maintained a strong balance sheet as shown through a reduction of our debt to trailing funds flow ratio to 0.8 times from 1.1 times at year end 2004. |
• | Achieved a recycle ratio for the year of 1.7 times and 1.8 times on a three-year basis. |
Financial Highlights
For the years ended December 31, | 2005 | 2004 | |||||
Financial (000’s) | |||||||
Net Income | $ | 432,041 | $ | 258,316 | |||
Funds Flow from Operations (1) | 794,410 | 539,969 | |||||
Cash Distributed (2) | 511,145 | 426,721 | |||||
Cash Withheld for Acquisitions and Capital Expenditures | 283,265 | 113,248 | |||||
Debt Outstanding (net of cash) | 649,825 | 584,991 | |||||
Development Capital Spending | 368,689 | 206,874 | |||||
Acquisitions | 704,028 | 636,326 | |||||
Divestments | 66,511 | 31,742 | |||||
Financial per Unit | |||||||
Net Income | $ | 3.96 | $ | 2.60 | |||
Funds Flow from Operations (1) | 7.28 | 5.44 | |||||
Cash Distributed (2) | 4.54 | 4.20 | |||||
Cash Withheld for Acquisitions and Capital Expenditures | 2.52 | 1.11 | |||||
Payout Ratio | 64 | % | 79 | % | |||
Selected Financial Results per BOE (3) | |||||||
Oil & Gas Sales (4) | $ | 52.36 | $ | 40.90 | |||
Royalties | (10.21 | ) | (8.40 | ) | |||
Financial Contracts | (4.90 | ) | (3.50 | ) | |||
Operating Costs | (7.45 | ) | (7.14 | ) | |||
General and Administrative | (1.28 | ) | (1.06 | ) | |||
Interest and Foreign Exchange | (0.64 | ) | (0.67 | ) | |||
Taxes | (0.31 | ) | (0.24 | ) | |||
Restoration and Abandonment | (0.27 | ) | (0.25 | ) | |||
Funds Flow from Operations (1) | $ | 27.30 | $ | 19.64 | |||
Weighted Average Number of Trust Units Outstanding (thousands) | 109,083 | 99,273 | |||||
Debt/Trailing 12 Month Funds Flow Ratio (1) | 0.8x | 1.1x |
(1) See the definition of funds flow in Management’s Discussion and Analysis
(2) Calculated based on distributions paid or payable each month relating to the period
(3) Non-cash amounts have been excluded
(4) Including oil and gas transportation costs and before financial contracts
Operating Highlights
Unless otherwise stated, all reserves information pertains to Enerplus’ company interest reserve volumes, which includes our working interest (operated and non-operated) share of reserves before the deduction of any royalty interest reserves, but inclusive of any royalty interest reserves owned by Enerplus. Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
For the years ended December 31, | 2005 | 2004 | |||||
Average Daily Production | |||||||
Natural gas (Mcf/day) | 274,336 | 271,091 | |||||
Crude oil (bbls/day) | 29,315 | 25,550 | |||||
NGLs (bbls/day) | 4,689 | 4,398 | |||||
Total (BOE/day) (6:1) | 79,727 | 75,130 | |||||
% Natural gas | 57 | % | 60 | % | |||
Average Selling Price (1) | |||||||
Natural gas (per Mcf) | $ | 8.41 | $ | 6.56 | |||
Crude oil (per bbl) | 55.93 | 43.80 | |||||
NGLs (per bbl) | 47.33 | 38.14 | |||||
US$ exchange rate | 0.83 | 0.77 | |||||
Net Wells drilled | 393 | 367 | |||||
Success Rate | 99 | % | 99 | % |
Reserves | ||
Proved Reserves (MMBOE) | 313.2 | 279.1 |
Probable Reserves (MMBOE) | 135.9 | 127.1 |
Total Proved plus Probable Reserves (MMBOE) | 449.1 | 406.2 |
Proved Reserve Life Index (years) (2) | 9.9 | 10.1 |
Proved plus Probable Reserve Life Index (years) (3) | 13.5 | 14.0 |
Finding, Development & Acquisition (“FD&A”) Costs | ||
Proved plus Probable FD&A Cost per BOE, excluding Future Development Capital | $13.98 | $7.68 |
Proved plus Probable FD&A Cost per BOE, including Future Development Capital | $17.18 | $11.34 |
Proved plus Probable Recycle Ratio | 1.7x | 1.9x |
Per Trust Unit Metrics | ||
Reserves per Debt-Adjusted Trust Unit | 3.48 | 3.46 |
Production per Debt-Adjusted Trust Unit | 0.241 | 0.245 |
(1) Including oil and gas transportation costs and before financial contracts
(2) Proved Reserve life index calculated using proved reserves at year-end divided by 2005 proved production forecast contained in our independent reserve engineering report
(3) Proved plus Probable Reserve Life Index calculated using proved plus probable reserves at year-end divided by 2005 proved plus probable production forecast contained in our independent reserve engineering report
TSX - ERF.un | NYSE- ERF | |
Trust Unit Trading Information | ($CDN) | ($US) |
High | $58.55 | $50.29 |
Low | $40.00 | $32.00 |
Close | $55.86 | $47.98 |
Volume (000’s) | 62,279 | 70,454 |
OPERATIONS REVIEW
Production
2005 production averaged 79,727 BOE/day slightly ahead of forecast based on better performance from our waterflood and shallow gas properties along with higher capital spending. Our exit production rate was 85,000 BOE/day essentially in line with our guidance of 86,000 BOE/day despite delays at our Bantry North development (1,400 BOE/day) and our coalbed methane projects (500 BOE/day). In total, approximately 3,800 BOE/day of production associated with 2005 capital spending is expected to come on stream early in 2006.
Our 2006 average daily production is expected to increase to 84,000 BOE/day based on a full year of production from our U.S. assets and an expanded capital program. We expect to exit 2006 at 89,000 BOE/day, 5% above our 2005 exit rate without the benefit of additional acquisitions.
Capital
We invested a record $369 million on capital development in 2005, approximately 4% ahead of our guidance of $355 million. Through this spending, we added approximately 13,400 BOE/day of new production which offset the natural production declines of our assets. Our ability to bring on significant new production volumes through our development program speaks to the rich opportunity set that exists within our asset base and our technical skills in maximizing on these opportunities. While our capital efficiency of $27,500/BOE/day remains attractive, this metric was negatively impacted due to significant “behind pipe” production associated with our 2005 spending, increased investments in long-term opportunities and inflationary cost pressures across the industry.
Approximately 3,800 BOE/day of production associated with 2005 spending is delayed and expected to be on stream in early 2006. This negatively impacts our capital efficiency in 2005 but improves capital efficiency in 2006. We also invested approximately $60 million in the oil sands, infrastructure, land, seismic, and exploration activities in 2005 which did not add current year production but will provide significant rewards in production and reserve growth in the future. The project life-cycle of these types of projects range from one to several years, as seen in the oil sands and other resource plays. We expect this type of spending to represent 15-20% of our capital budget going forward.
Inflationary cost pressures continue to be seen across the industry. We are experiencing double-digit inflation on a number of services and supplies across our business and expect that continued cost pressures will be evident as long as commodity prices and activity levels remain high.
We plan to increase spending in 2006 by approximately 30% to $485 million on our development program. We expect to drill over 550 net wells during the year, almost a 40% increase over 2005. We also expect to invest approximately $90 million in long-term opportunities which are not expected to add significant production in the current year but will further position us for attractive production and reserve additions in the years ahead. This long-term capital is weighted approximately 50% to higher risk exploration activities. Overall we still expect an improvement in 2006 capital efficiencies to approximately $24,000/BOE/day due to the significant carry-over of 2005 production into 2006, lower infrastructure investment and an attractive inventory of development prospects. A majority of our capital budget in 2006 is discretionary and can be revised downward in the event of a commodity downturn or similar economic event.
2005 Capital Efficiency Summary
Play type | 2005 Initial Production (BOE/day) | 2005 Capital ($MM) | 2005 Cost of Production Additions ($/BOE/day) | 2006 Estimated Capital ($MM) | |||||||||
Shallow Gas | 1,900 | $ | 58.7 | $ | 30,900 | $ | 74.0 | ||||||
Waterflood | 2,000 | $ | 62.2 | $ | 31,100 | $ | 78.0 | ||||||
Coalbed Methane | 1,100 | $ | 42.1 | $ | 38,300 | $ | 49.0 | ||||||
Bakken Oil | 2,300 | $ | 29.1 | $ | 12,700 | $ | 89.0 | ||||||
Oil Sands (SAGD) | 0* | $ | 33.2 | n/a | $ | 31.0 | |||||||
Other | 6,100 | $ | 143.4 | $ | 23,500 | $ | 164.0 | ||||||
Total | 13,400 | $ | 368.7 | $ | 27,500 | $ | 485.0 |
* 2005 production is not recorded for Joslyn as the operation has not reached commercial production levels.
2005 Drilling Activity
We drilled 859 gross wells (393.3 net) during 2005 with an almost 100% success rate. Although we participated in the drilling of a record number of gross wells, our net wells were up only modestly from 2004 levels (393 versus 367) despite a significant increase in development capital spending. The increased spending was driven largely by a greater investment in infrastructure and oil sands development, a meaningful increase in higher cost oil wells and rising industry costs. Specifically, a number of our oil well drilling programs consist of horizontal wells which have a significantly higher cost than a typical shallow gas well, especially the deep Bakken wells in the U.S.
Crude Oil | Bitumen | Natural Gas | Service | Dry & Abandoned | Total | ||||||||||||||||||||||||||||||||
Wells | Wells | Wells | Wells | Wells | Wells | ||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||
Operated | 67.0 | 56.7 | 0.0 | 0.0 | 307.0 | 223.6 | 2.0 | 1.6 | 0.0 | 0.0 | 376.0 | 281.9 | |||||||||||||||||||||||||
Non-operated | 92.0 | 13.6 | 14.0 | 2.2 | 365.0 | 93.8 | 11.0 | 1.8 | 1.0 | 0.0 | 483.0 | 111.4 | |||||||||||||||||||||||||
Total | 159.0 | 70.3 | 14.0 | 2.2 | 672.0 | 317.4 | 13.0 | 3.4 | 1.0 | 0.0 | 859.0 | 393.3 |
Future Opportunities
We have been tracking our future development capital opportunities on existing assets as part of our annual budget and planning cycle. Throughout this time, we have seen our future development opportunity set increase dramatically through attractive acquisitions and robust technical work despite increasing capital spending each year. We currently estimate that we have a drilling inventory of approximately 1,500 net wells representing almost $1 billion in attractive investment opportunities on our existing conventional assets. This translates into almost four years of future conventional development opportunities based upon historic drilling levels and prior to any new acquisitions of land or properties. Over and above these conventional opportunities, we have also identified significant development potential at our Joslyn oil sands lease in the years ahead on both the SAGD and mine development. We see potential for $200 million in attractive SAGD future development and approximately $500 million in mining development exclusive of an upgrader solution. In total, Enerplus has line of sight to over $1.5 billion in future investment opportunities in our current portfolio.
In 2006 our goal is to identify new opportunities which will more than replace the projects that will be executed in our 2006 capital program. These new opportunities will come through internal efforts on our existing lands and the
acquisition of both undeveloped land and new producing properties. A majority of this growth is expected in our traditional focus areas including shallow gas, waterfloods, CBM and our most recent resource play addition, the Bakken.
SUSTAINABILITY
We believe that long-term success comes from sustainable production, reserves, cash flow and distributions. The effectiveness of our efforts to achieve sustainability can be measured by the consistency of our reserves per unit, production per unit, reserve life index and recycle ratio.
Both reserves and production per debt-adjusted trust unit were essentially maintained year-over-year. Our relatively low base decline, an attractive inventory of internally generated development projects and attractive acquisitions allows us to achieve these results. We ended the year at a record level of proved plus probable reserves of 449 MMBOE after replacing 247% of production. Positive changes to existing assets of 25 MMBOE and a reserve increase due to economic factors (mainly due to increased commodity price forecasts) of 13 MMBOE more than replaced production of 29 MMBOE. In addition, we added 34 MMBOE of net reserves from our acquisitions activity, for total aggregate reserve additions of 72 MMBOE. Our reserve life decreased slightly year-over-year to 13.5 years based on a strong 2006 production outlook.
Production per Debt-Adjusted Trust Unit
Production per unit is measured in respect of the average production for the year, and the weighted average number of trust units outstanding during the year. The measurements are then debt-adjusted by assuming additional trust units are issued at quarter-end unit prices to replace long-term debt outstanding at each quarter-end. The average number of trust units created over the four quarters is then added to the weighted average number of trust units to obtain the debt-adjusted number of trust units for the year.
2005 | 2004 | 2003 | ||||||||
Average daily production | 79,727 | 75,130 | 69,414 | |||||||
Debt-adjusted weighted average trust units (000’s) | 120,875 | 112,381 | 99,051 | |||||||
Production per debt-adjusted trust unit (BOE/unit) | 0.241 | 0.245 | 0.256 |
Reserves per Debt-Adjusted Trust Unit
Reserves per trust unit are measured in respect of year-end proved plus probable reserves and the number of trust units outstanding at year-end. To eliminate the temporary timing effects of financing decisions, we have debt-adjusted these measurements by assuming we issue additional trust units at year-end prices to replace year-end long-term debt.
2005 | 2004 | 2003 | ||||||||
Year-end proved plus probable reserves | 449,137 | 406,222 | 328,066 | |||||||
Debt-adjusted trust units outstanding at year-end (000’s) | 129,172 | 117,541 | 100,898 | |||||||
Reserves per debt-adjusted trust unit (BOE/unit) | 3.48 | 3.46 | 3.25 |
Our 2005 recycle ratio was 1.7x which is in line with our three-year average of 1.8x on a proved plus probable basis. This measure accounts for the quality of reserves, operating costs and attractiveness of acquisitions and internal development capital. Recycle ratio is determined by dividing the operating income per BOE by the finding, development and acquisition cost (“FD&A”) per BOE including future development capital (“FDC”) and is indicative of the value created for each dollar invested. Our 2005 recycle ratio has decreased compared to the previous two years, mainly due to higher cost acquisitions for higher quality properties and inflationary pressures on FD&A costs.
Looking forward into 2006, we expect strong results in these areas as a result of:
• | Increasing production year-over-year from our existing assets. |
• | Attractive netbacks as our U.S. operations will be producing for a full year. |
• | Significant reserve adds from our existing conventional assets combined with the expected recognition of the Joslyn mining project. |
• | Competitive FD&A costs driven by the reserve adds noted above. |
• | An attractive recycle ratio because of improving netbacks and attractive FD&A costs. |
These expected results are dependent upon a continued strong commodity price environment, a successful capital program and recognition of the mining reserves in 2006.
ACQUISITIONS & DIVESTMENTS
On August 30, we completed our single largest transaction to date and first acquisition outside of Canada with the purchase of Lyco Energy Corporation (“Lyco”), a private oil and natural gas producer operating in Montana and North Dakota for $501.9 million, prior to adjustments for working capital. The strategic move into the United States establishes a new core resource play producing high quality Middle Bakken light oil from the Sleeping Giant project area of the Williston basin in Montana. The Middle Bakken resource play covers a large, aerial extent and exhibits relatively low geologic risk. In a follow-on transaction, on October 4, we closed the acquisition of Sleeping Giant LLC (“Sleeping Giant”), a private U.S. company, for $111.9 million prior to working capital adjustments. The acquired assets increased our working interest in the Sleeping Giant project area to approximately 70%.
As well as the establishment of a new resource focused core area, the U.S. acquisitions provide us with a significant operating platform, expanding our opportunity set for future acquisitions and providing us with flexibility and an alternate market in which to invest. Enerplus now has over 120,000 net acres of undeveloped land in Montana and North Dakota.
On July 1, we completed the acquisition of TriLoch Resources Inc. (“TriLoch”) for $77.4 million prior to working capital adjustments. The single property owned by TriLoch is adjacent to our existing properties in the Enchant area of southern Alberta. While meeting our objective of acquiring Canadian assets in existing core areas, the acquired property also permits us to exploit our competitive technical advantage through our expertise in waterflood development and shallow natural gas drilling. We have identified numerous drilling opportunities in the Mannville formation as well as shallow gas infill drilling locations.
Through these acquisitions, we acquired 42.8 MMBOE of proved plus probable reserves and added approximately 10,000 BOE/day of production. These assets were all within our strategic focus areas as they represented resource plays or waterflood areas. High quality assets such as these with significant upside potential are typically characterized by higher flowing barrel and per BOE reserve costs yet provide greater long-term value.
As part of our ongoing portfolio management strategy, we also divested $66.5 million of non-core properties. These properties are characterized by small working interests with high operating costs and limited upside potential. These types of assets typically receive lower valuations on both a flowing barrel and reserve basis because of the lower asset quality. In aggregate, we sold approximately 8.2 MMBOE of proved plus probable reserves with associated production of 2,529 BOE/day. We will continue to rationalize non-core assets, however, we currently do not have plans for a significant divestment program in 2006.
Cost/Proceeds* ($ millions) | Proved plus Probable Reserves (MBOE) | Production (BOE/day) | Cost of Proved plus Probable Reserves ($/BOE) | Cost per Daily Barrel | ||||||||||||
Acquired | $ | 704.0 | 42,832 | 10,021 | $ | 16.44 | $ | 70,255 | ||||||||
Divested | ($66.5 | ) | (8,248 | ) | (2,529 | ) | ($8.06 | ) | $ | 26,299 | ||||||
Net | $ | 637.5 | 34,584 | 7,492 | $ | 18.43 | $ | 85,082 |
* after adjustments for working capital and excluding future development capital
2006 Outlook
In 2006, we anticipate the Canadian domestic acquisition market will remain competitive with a limited supply of opportunities coupled with continued strong demand from the trust sector and overall industry. We will continue to focus on add-on transactions (additional working interests in existing areas) where we have a natural competitive advantage. We will monitor overall market developments in pursuit of opportunities that meet our acquisition criteria.
We believe the U.S. market may be more attractive given current valuation levels and more abundant opportunities. Through the establishment of our U.S. platform, we feel we have a strategic advantage, compared to trusts without U.S. operations, to capitalize on the differences between these two markets. We see increasing competition in the United States, however, as new tax-advantaged U.S. exploration and production companies enter the market. Despite these challenges, we expect to grow our U.S. presence in and around our existing Williston basin production and in new areas throughout the U.S. including the Rocky Mountain region. We will remain disciplined in seeking acquisitions that provide attractive economics, accretion and long-term growth.
In addition to evaluating opportunities both domestically and in the United States, we will continue to examine both non-conventional and international opportunities which meet our strategic focus and long-range plans.
In our latest investment, in early 2006, we sold a 1% working interest in our Joslyn oil sands lease in exchange for an equity stake in Laricina Energy Ltd. and the formation of an area of mutual interest to jointly pursue additional in-situ oil sands ventures. This partnership will allow us to accelerate additional oil sands resource development outside of Joslyn, facilitate the transfer of intellectual expertise while supporting our efforts to internally attract and build a focused oil sands area team. Laricina is a private oil sands focused company lead by the former chief executive officer of Deer Creek Energy.
RESERVES
Our 2005 year-end reserves were notable due to a number of achievements:
• | Reserves at year-end set another record level with proved plus probable reserves of 449 million BOE, an increase of 43 million BOE (11%) over last year. |
• | Our internal development program generated the highest number of reserve additions in history with 25 million BOE of proved plus probable and 13 million BOE from economic factors (mainly forecast prices) totaling 38 million BOE, more than offsetting annual production of 29 million BOE. |
• | Our acquisitions activity resulted in 34 million BOE of net proved plus probable reserve additions after divestments of 8 million BOE. |
• | Reserve additions were realized from all major play types including shallow gas, waterfloods, CBM, deep gas and other conventional play types. Shallow gas was the top contributor to the reserve additions from our development efforts with approximately 7 million BOE on a proved plus probable basis. |
• | On a proved basis, our reserves increased by 34 million BOE (12%). Our proved reserves now account for approximately 70% of our total reserves. |
• | 9.5 million BOE of proved reserves were assigned to our Joslyn SAGD project and proved plus probable reserves in the project increased by 5.4 million BOE. |
• | Net acquisitions and development additions replaced 247% of 2005 production on a proved plus probable basis and 217% on a proved basis. |
• | FD&A costs increased both including FDC ($17.18/BOE) and without FDC ($13.98/BOE) on a proved plus probable basis mainly due to higher acquisition costs. The Sleeping Giant field of Montana was our major acquisition target in 2005 and produces exceptionally high priced light oil with low operating costs. The relatively high FD&A cost of ownership in this field is justified by the high netback received from production. We still maintain an attractive 3 year average FD&A with FDC of $13.46/BOE and $10.09/BOE without FDC. |
• | Our finding and development costs (including FDC) were $11.97/BOE due to the record additions achieved from our internal development program. |
• | Our recycle ratio was 1.7x decreasing slightly due to the higher cost of acquisitions used in calculating the ratio coupled with our 2005 operating income that does not reflect the higher quality of these acquisitions due to timing. Our three-year average recycle ratio remains attractive at 1.8x. |
Reserve Reporting and Determination Methodologies
All reports, including our U.S. reserves, were evaluated using Canadian NI 51-101 rules. Three external, independent third party engineering firms were used to evaluate and review our reserves this year. Sproule Associates Limited
(“Sproule”), our historical independent engineering evaluators, evaluated our Canadian conventional reserves. GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated the Joslyn SAGD bitumen reserves as they have previously performed such evaluations for the operator of the Joslyn project. DeGolyer and MacNaughton (“D&M”) of Dallas, Texas, evaluated the reserves attributed to our assets in the United States. Sproule evaluated 89% of the total proved plus probable value (discounted at 10%) of the Fund’s Canadian conventional year-end reserves, in keeping with NI 51-101 and has reviewed the remainder of the reserves internally evaluated by Enerplus. Both GLJ and D&M evaluated 100% of the reserves in their respective areas. Both GLJ and D&M utilized Sproule’s price forecast and cost assumptions as of December 31, 2005 in their evaluations to maintain consistency.
The following tables report company interest reserves that include gross working interest reserves and owned royalty interest reserves using forecast prices. In addition, net and gross reserve information using forecast prices is contained under the “Supplementary Information” section of this report. Our reserve statement, which includes complete disclosure of our oil and gas reserves and other oil and gas information, as contained within our Annual Information Form is available on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com on March 10, 2006. Additionally, the Annual Information Form will be part of our Form 40-F that will be filed with the SEC and available on www.edgar-online.com on March 10, 2006.
Probable reserves are risked by our third party engineering firms or our own internal evaluators under the review of the third party engineering firm. Care should be used when comparing U.S. and Canadian style reserves and production reporting between companies. Under U.S. reporting, reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report with typically only net proved reserves reported. As such, proved reserve standards in the U.S. may not be comparable to the Canadian standards. Generally, Canadian standards for reporting proved reserves may be more conservative than U.S. standards.
All evaluations of future net production revenues set forth in the tables are stated after the provision for income taxes, and exclude abandonment costs on wells and facilities where reserves are not assigned or associated general and administrative costs. These schedules have been prepared on the basis that no cash income tax will be paid by Enerplus’ Canadian operating subsidiaries in the future. Under our current mutual fund structure and existing tax legislation in Canada, annual taxable income is transferred from our operating entities to the Fund through interest, royalty and other payments. We, in turn, make distributions to our unitholders and therefore currently do not incur any Canadian income tax. As a result, after-tax future net revenues from oil and gas reserves are equal to before tax future net revenues from oil and gas reserves.
Our U.S. operations are subject to cash income taxes and as a result, our U.S. reserves are shown net of the taxes that we estimate would be payable after taking into account inter-company debt in our structure.
The present value of all future cash flows at December 31, 2005 was based upon crude oil and natural gas pricing assumptions prepared by Sproule. These prices were applied to the reserves evaluated by Sproule, GLJ and D&M. The base reference prices and exchange rates used by Sproule are detailed below:
Sproule December 31, 2005 - Forecast Price and Cost Assumptions
WTI crude oil US$/bbl | Light crude Edmonton (1) CDN$/bbl | Hardisty Heavy 12° API CDN$/bbl | Differential Between Hardisty Heavy And Bitumen CDN$/bbl | Henry Hub Price US$/MMbtu | Natural Gas 30 day spot @ AECO CDN$/MMbtu | Exchange Rate US$/CDN$ | ||||||||||||||||
2006 | $ | 60.81 | $ | 70.07 | $ | 37.07 | $ | 9.30 | $ | 11.59 | $ | 11.58 | $ | 0.85 | ||||||||
2007 | 61.61 | 70.99 | 37.29 | 9.21 | 10.11 | 10.84 | 0.85 | |||||||||||||||
2008 | 54.60 | 62.73 | 34.23 | 10.75 | 8.50 | 8.95 | 0.85 | |||||||||||||||
2009 | 50.19 | 57.53 | 32.27 | 11.49 | 7.58 | 7.87 | 0.85 | |||||||||||||||
2010 | 47.76 | 54.65 | 31.15 | 10.75 | 7.32 | 7.57 | 0.85 | |||||||||||||||
Thereafter | + 1.5 | % | + 1.5 | % | ** | ** | +1.5 | % | ** | 0.85 |
(1) Edmonton refinery postings for 40° API, 0.4% sulphur content crude.
** Escalation varies after 2010
Reserves Summary
The following table sets out our company interest volumes by production type and reserve category under a forecast price scenario. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit and reserves associated with a property.
2005 Reserve Summary - Company Interest Volumes (Forecast Prices)
OIL AND GAS RESERVES | |||||||
Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |
Proved developed producing | |||||||
Canada | 69,768 | 30,583 | - | 100,351 | 11,644 | 771,428 | 240,566 |
United States | 15,773 | - | - | 15,773 | - | 8,794 | 17,239 |
Total | 85,541 | 30,583 | - | 116,124 | 11,644 | 780,222 | 257,805 |
Proved developed non-producing | |||||||
Canada | 163 | - | - | 163 | 475 | 19,468 | 3,884 |
United States | - | - | - | - | - | - | - |
Total | 163 | - | - | 163 | 475 | 19,468 | 3,884 |
Proved undeveloped | |||||||
Canada | 3,318 | 2,318 | 9,453 | 15,089 | 965 | 161,728 | 43,008 |
United States | 7,822 | - | - | 7,822 | - | 4,358 | 8,548 |
Total | 11,140 | 2,318 | 9,453 | 22,911 | 965 | 166,086 | 51,556 |
Total Proved | |||||||
Canada | 73,249 | 32,901 | 9,453 | 115,603 | 13,084 | 952,624 | 287,458 |
United States | 23,595 | - | - | 23,595 | - | 13,152 | 25,787 |
Total | 96,844 | 32,901 | 9,453 | 139,198 | 13,084 | 965,776 | 313,245 |
Probable | |||||||
Canada | 17,498 | 8,495 | 43,700 | 69,693 | 3,539 | 309,572 | 124,827 |
United States | 5,574 | - | - | 5,574 | - | 32,946 | 11,065 |
Total | 23,072 | 8,495 | 43,700 | 75,267 | 3,539 | 342,518 | 135,892 |
Total Proved plus Probable | |||||||
Canada | 90,747 | 41,396 | 53,153 | 185,296 | 16,623 | 1,262,196 | 412,285 |
United States | 29,169 | - | - | 29,169 | - | 46,098 | 36,852 |
Total | 119,916 | 41,396 | 53,153 | 214,465 | 16,623 | 1,308,294 | 449,137 |
Reserve Reconciliation
The following tables reconcile the reported volumes of the company interest reserves from December 31, 2004 to December 31, 2005 and highlight which production type and reserves categories contributed to the change.
Some of the notable positive changes for proved plus probable reserves include:
• | “Extensions” from deep gas drilling in the Deep Basin and Moose (3.5 MMBOE). |
• | “Technical revisions” for bitumen reserves (5.4 MMBOE) from positive results of our delineation drilling. |
• | “Improved recovery” due to shallow gas infill drilling at Verger and Bantry (2.9 MMBOE) and oil infill drilling at Bantry North and Joarcam (2.8 MMBOE). |
• | “Economic factors” (13.2 MMBOE) were mainly due to changes in price forecasts for oil and gas which extend the life and recovery of an oil and gas field. |
These positive changes to proved plus probable reserves more than offset negative adjustments. Some of the key negative adjustments include “technical revisions” for lower gas production performance at Hanna Garden (-1.6 MMBOE) and a reduction at Enchant (-2.3 MMBOE) for reserves assigned for a planned waterflood and a number of gas drilling locations. We expect that reserves will be added to Enchant in the future once the waterflood development program is initiated.
Proved Reserves - Company Interest Volumes (forecast prices)
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | 73,039 | 31,369 | - | 104,408 | 12,776 | 971,598 | 279,117 | |||||||||||||||
Acquisitions | 1,899 | - | - | 1,899 | 49 | 13,609 | 4,216 | |||||||||||||||
Divestments | (1,297 | ) | (1,343 | ) | - | (2,640 | ) | (59 | ) | (15,614 | ) | (5,301 | ) | |||||||||
Discoveries | 103 | - | - | 103 | 7 | 2,887 | 591 | |||||||||||||||
Extensions | 238 | 38 | - | 276 | 724 | 36,671 | 7,112 | |||||||||||||||
Technical Revisions | (1,966 | ) | 1,400 | 9,453 | 8,887 | 874 | (16,995 | ) | 6,930 | |||||||||||||
Economic Factors | 4,368 | 1,694 | - | 6,062 | 353 | 20,889 | 9,896 | |||||||||||||||
Improved Recovery | 3,280 | 2,976 | - | 6,256 | 71 | 39,134 | 12,849 | |||||||||||||||
Production | (6,415 | ) | (3,233 | ) | - | (9,648 | ) | (1,711 | ) | (99,555 | ) | (27,952 | ) | |||||||||
Proved Reserves at Dec. 31, 2005 | 73,249 | 32,901 | 9,453 | 115,603 | 13,084 | 952,624 | 287,458 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 23,900 | - | - | 23,900 | - | 12,784 | 26,031 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 747 | - | - | 747 | - | 946 | 904 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | (1,052 | ) | - | - | (1,052 | ) | - | (578 | ) | (1,148 | ) | |||||||||||
Proved Reserves at Dec. 31, 2005 | 23,595 | - | - | 23,595 | - | 13,152 | 25,787 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | 73,039 | 31,369 | - | 104,408 | 12,776 | 971,598 | 279,117 | |||||||||||||||
Acquisitions | 25,799 | - | - | 25,799 | 49 | 26,393 | 30,247 | |||||||||||||||
Divestments | (1,297 | ) | (1,343 | ) | - | (2,640 | ) | (59 | ) | (15,614 | ) | (5,301 | ) | |||||||||
Discoveries | 103 | - | - | 103 | 7 | 2,887 | 591 | |||||||||||||||
Extensions | 238 | 38 | - | 276 | 724 | 36,671 | 7,112 | |||||||||||||||
Technical Revisions | (1,219 | ) | 1,400 | 9,453 | 9,634 | 874 | (16,049 | ) | 7,834 | |||||||||||||
Economic Factors | 4,368 | 1,694 | - | 6,062 | 353 | 20,889 | 9,896 | |||||||||||||||
Improved Recovery | 3,280 | 2,976 | - | 6,256 | 71 | 39,134 | 12,849 | |||||||||||||||
Production | (7,467 | ) | (3,233 | ) | - | (10,700 | ) | (1,711 | ) | (100,133 | ) | (29,100 | ) | |||||||||
Proved Reserves at Dec. 31, 2005 | 96,844 | 32,901 | 9,453 | 139,198 | 13,084 | 965,776 | 313,245 |
Probable Reserves - Company Interest Volumes (forecast prices)
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | 17,180 | 9,603 | 47,747 | 74,530 | 3,292 | 295,698 | 127,105 | |||||||||||||||
Acquisitions | 1,075 | - | - | 1,075 | 14 | 5,951 | 2,081 | |||||||||||||||
Divestments | (780 | ) | (808 | ) | - | (1,588 | ) | (40 | ) | (7,911 | ) | (2,947 | ) | |||||||||
Discoveries | 34 | - | - | 34 | (1 | ) | 568 | 127 | ||||||||||||||
Extensions | (25 | ) | 20 | - | (5 | ) | 143 | 14,322 | 2,525 | |||||||||||||
Technical Revisions | (1,808 | ) | (610 | ) | (4,047 | ) | (6,465 | ) | (54 | ) | (16,860 | ) | (9,329 | ) | ||||||||
Economic Factors | 1,441 | 468 | - | 1,909 | 159 | 7,541 | 3,325 | |||||||||||||||
Improved Recovery | 381 | (178 | ) | - | 203 | 26 | 10,263 | 1,940 | ||||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 17,498 | 8,495 | 43,700 | 69,693 | 3,539 | 309,572 | 124,827 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 5,041 | - | - | 5,041 | - | 32,779 | 10,504 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 533 | - | - | 533 | - | 167 | 561 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 5,574 | - | - | 5,574 | - | 32,946 | 11,065 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | 17,180 | 9,603 | 47,747 | 74,530 | 3,292 | 295,698 | 127,105 | |||||||||||||||
Acquisitions | 6,116 | - | - | 6,116 | 14 | 38,730 | 12,585 | |||||||||||||||
Divestments | (780 | ) | (808 | ) | - | (1,588 | ) | (40 | ) | (7,911 | ) | (2,947 | ) | |||||||||
Discoveries | 34 | - | - | 34 | (1 | ) | 568 | 127 | ||||||||||||||
Extensions | (25 | ) | 20 | - | (5 | ) | 143 | 14,322 | 2,525 | |||||||||||||
Technical Revisions | (1,275 | ) | (610 | ) | (4,047 | ) | (5,932 | ) | (54 | ) | (16,693 | ) | (8,768 | ) | ||||||||
Economic Factors | 1,441 | 468 | - | 1,909 | 159 | 7,541 | 3,325 | |||||||||||||||
Improved Recovery | 381 | (178 | ) | - | 203 | 26 | 10,263 | 1,940 | ||||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 23,072 | 8,495 | 43,700 | 75,267 | 3,539 | 342,518 | 135,892 |
Proved Plus Probable Reserves - Company Interest Volumes (forecast prices)
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | 90,219 | 40,972 | 47,747 | 178,938 | 16,068 | 1,267,296 | 406,222 | |||||||||||||||
Acquisitions | 2,974 | - | - | 2,974 | 63 | 19,560 | 6,297 | |||||||||||||||
Divestments | (2,077 | ) | (2,151 | ) | - | (4,228 | ) | (99 | ) | (23,525 | ) | (8,248 | ) | |||||||||
Discoveries | 137 | - | - | 137 | 6 | 3,455 | 718 | |||||||||||||||
Extensions | 213 | 58 | - | 271 | 867 | 50,993 | 9,637 | |||||||||||||||
Technical Revisions | (3,774 | ) | 790 | 5,406 | 2,422 | 820 | (33,855 | ) | (2,399 | ) | ||||||||||||
Economic Factors | 5,809 | 2,162 | - | 7,971 | 512 | 28,430 | 13,221 | |||||||||||||||
Improved Recovery | 3,661 | 2,798 | - | 6,459 | 97 | 49,397 | 14,789 | |||||||||||||||
Production | (6,415 | ) | (3,233 | ) | - | (9,648 | ) | (1,711 | ) | (99,555 | ) | (27,952 | ) | |||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 90,747 | 41,396 | 53,153 | 185,296 | 16,623 | 1,262,196 | 412,285 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 28,941 | - | - | 28,941 | - | 45,563 | 36,535 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 1,280 | - | - | 1,280 | - | 1,113 | 1,465 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | (1,052 | ) | - | - | (1,052 | ) | - | (578 | ) | (1,148 | ) | |||||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 29,169 | - | - | 29,169 | - | 46,098 | 36,852 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | 90,219 | 40,972 | 47,747 | 178,938 | 16,068 | 1,267,296 | 406,222 | |||||||||||||||
Acquisitions | 31,915 | - | - | 31,915 | 63 | 65,123 | 42,832 | |||||||||||||||
Divestments | (2,077 | ) | (2,151 | ) | - | (4,228 | ) | (99 | ) | (23,525 | ) | (8,248 | ) | |||||||||
Discoveries | 137 | - | - | 137 | 6 | 3,455 | 718 | |||||||||||||||
Extensions | 213 | 58 | - | 271 | 867 | 50,993 | 9,637 | |||||||||||||||
Technical Revisions | (2,494 | ) | 790 | 5,406 | 3,702 | 820 | (32,742 | ) | (934 | ) | ||||||||||||
Economic Factors | 5,809 | 2,162 | - | 7,971 | 512 | 28,430 | 13,221 | |||||||||||||||
Improved Recovery | 3,661 | 2,798 | - | 6,459 | 97 | 49,397 | 14,789 | |||||||||||||||
Production | (7,467 | ) | (3,233 | ) | - | (10,700 | ) | (1,711 | ) | (100,133 | ) | (29,100 | ) | |||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 119,916 | 41,396 | 53,153 | 214,465 | 16,623 | 1,308,294 | 449,137 |
Net Present Value
The following table shows the net present value of future net revenue from our reserves using the forecast prices shown. The estimated future net revenues disclosed do not represent the fair market value of our reserves.
Net Present Value of Future Production Revenue - Forecast Prices and Costs (After tax)
At December 31, 2005
($ millions, discounted at) | 0% | 5% | 10% | 15% | |||||||||
Conventional Reserves | |||||||||||||
Proved developed producing | |||||||||||||
Canada | 6,991 | 4,800 | 3,789 | 3,199 | |||||||||
United States | 620 | 500 | 419 | 360 | |||||||||
Total | 7,611 | 5,300 | 4,208 | 3,559 | |||||||||
Proved developed non-producing | |||||||||||||
Canada | 107 | 81 | 65 | 57 | |||||||||
United States | - | - | - | - | |||||||||
Total | 107 | 81 | 65 | 57 | |||||||||
Proved undeveloped | |||||||||||||
Canada | 687 | 501 | 380 | 296 | |||||||||
United States | 180 | 133 | 102 | 82 | |||||||||
Total | 867 | 634 | 482 | 378 | |||||||||
Total Proved | |||||||||||||
Canada | 7,785 | 5,382 | 4,234 | 3,552 | |||||||||
United States | 800 | 633 | 521 | 442 | |||||||||
Total | 8,585 | 6,015 | 4,755 | 3,994 | |||||||||
Probable | |||||||||||||
Canada | 2,376 | 1,121 | 695 | 495 | |||||||||
United States | 308 | 174 | 108 | 72 | |||||||||
Total | 2,684 | 1,295 | 803 | 567 | |||||||||
Total Proved Plus Probable Conventional Reserves | 11,269 | 7,310 | 5,558 | 4,561 | |||||||||
Bitumen Reserves | |||||||||||||
Proved undeveloped | 38 | 19 | 9 | 3 | |||||||||
Probable | 299 | 88 | 27 | 6 | |||||||||
Total Proved Plus Probable Bitumen Reserves | 337 | 107 | 36 | 9 | |||||||||
Total Conventional and Bitumen Reserves | 11,606 | 7,417 | 5,594 | 4,570 |
Net Asset Value
Enerplus’ net asset value is measured with reference to the present value of all future net revenue from our reserves as estimated by our independent reserve engineers, Sproule, GLJ and D&M, plus land values, adjusted for working capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural gas price assumptions used by the independent reserve engineers. In addition, this calculation ignores “going concern” value and assumes only the reserves identified in the reserve reports with no further acquisitions, despite our 20 year history of replacing production through acquisitions and development.
Net Asset Value - Forecast Prices and Costs (After Tax) at December 31, 2005
($ millions, discounted at) | 0% | 5% | 10% | 15% | |||||||||
Present value of proved plus probable reserves | |||||||||||||
Canada | 10,498 | 6,610 | 4,965 | 4,056 | |||||||||
United States | 1,108 | 807 | 629 | 514 | |||||||||
Total Present value of proved plus probable reserves | 11,606 | 7,417 | 5,594 | 4,570 | |||||||||
Undeveloped acreage | |||||||||||||
Canada | 44 | 44 | 44 | 44 | |||||||||
United States | 23 | 23 | 23 | 23 | |||||||||
Long-term debt (net of cash) | (650 | ) | (650 | ) | (650 | ) | (650 | ) | |||||
Net Working Capital excluding deferred financial asset, distributions payable to unitholders and deferred credits | (119 | ) | (119 | ) | (119 | ) | (119 | ) | |||||
Net Asset Value | 10,904 | 6,715 | 4,892 | 3,868 | |||||||||
Net Asset Value per Trust Unit (1) | $ | 92.77 | $ | 57.13 | $ | 41.62 | $ | 32.91 |
(1) Based on 117,539,000 Trust Units outstanding as at December 31, 2005.
FINDING, DEVELOPMENT AND ACQUISITION COSTS
FD&A costs can be calculated either including or excluding future development capital. FD&A costs under NI 51-101 include FDC as this provides a more representative view of the full cost of reserve additions as it accounts for future costs to bring the reserves to market. Under the historic method, FD&A costs are understated as reserves are included without taking into account the future capital expenditures required to fully develop the reserve base. We have included both the NI 51-101 method which includes FDC and the historic method for comparison purposes.
Our 2005 FD&A cost including FDC based on proved plus probable reserves has increased to $17.18/BOE and our recycle ratio declined modestly to 1.7x. On a three-year average basis, Enerplus has maintained an attractive FD&A cost with FDC of $13.46/BOE with a three-year average recycle ratio of 1.8x. Excluding FDC, our one-year FD&A is $13.98/BOE and our three-year average FD&A is $10.09/BOE.
This year, there was an increase in FDC due to higher costs for development projects, increased costs for the Joslyn SAGD development and new future development activities associated with our acquisitions. The change in FDC on a proved plus probable basis associated with internal conventional development reserves was $92 million while the change in future capital associated with net acquisitions (TriLoch, Lyco and Sleeping Giant) was approximately $106 million ($198 million total). The change in FDC associated with the Joslyn SAGD project was approximately $33 million.
FD&A Costs Under NI 51-101 (including future development capital)
($ millions, except per BOE amounts) | 2005 | 2004 | 2003 | |||||||
Proved Reserves | ||||||||||
Excluding Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | $ | 973.0 | $ | 803.2 | $ | 305.6 | ||||
Net change in future development capital | 184.7 | 99.0 | (26.1 | ) | ||||||
Company reserve additions (MMBOE) | 53.7 | 57.5 | (13.8 | ) | ||||||
Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | 33.2 | 8.3 | 4.2 | |||||||
Net change in future development capital | 44.6 | - | - | |||||||
Company reserve additions (MMBOE) | 9.5 | - | - | |||||||
FD&A costs ($/BOE) | $ | 19.55 | $ | 15.83 | N/A (1 | ) | ||||
Three-year average FD&A costs ($/BOE)(2) | $ | 22.73 | $ | 18.85 | $ | 11.41 |
Proved plus Probable Reserves | ||||||||||
Excluding Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | $ | 973.0 | $ | 803.2 | $ | 305.6 | ||||
Net change in future development capital | 197.7 | 120.7 | (43.0 | ) | ||||||
Company reserve additions (MMBOE) | 66.6 | 58.0 | 23.0 | |||||||
Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | 33.2 | 8.3 | 4.2 | |||||||
Net change in future development capital | 33.4 | 266.1 | - | |||||||
Company reserve additions (MMBOE) | 5.4 | 47.7 | - | |||||||
FD&A costs ($/BOE) | $ | 17.18 | $ | 11.34 | $ | 11.60 | ||||
Three-year average FD&A costs ($/BOE)(2) | $ | 13.46 | $ | 11.02 | $ | 8.54 |
(1) As the negative proved revisions during 2003 were greater than the reserve additions, the proved FD&A cost for 2003 is not determinable.
(2) FD&A calculated over a three-year period.
FD&A Costs Excluding Future Development Capital
($ millions, except per BOE amounts) | 2005 | 2004 | 2003(1) | |||||||
Proved Reserves | ||||||||||
Excluding Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | $ | 973.0 | $ | 803.2 | $ | 305.6 | ||||
Company reserve additions (MMBOE) | 53.7 | 57.5 | 28.1 | |||||||
Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | 33.2 | 8.3 | 4.2 | |||||||
Company reserve additions (MMBOE) | 9.5 | - | - | |||||||
FD&A costs ($/BOE) | $ | 15.92 | $ | 14.11 | $ | 11.02 | ||||
Three-year average FD&A costs ($/BOE)(2) | $ | 14.30 | $ | 11.62 | $ | 8.50 | ||||
Proved plus Probable Reserves | ||||||||||
Excluding Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | $ | 973.0 | $ | 803.2 | $ | 305.6 | ||||
Company reserve additions (MMBOE) | 66.6 | 58.0 | 33.1 | |||||||
Joslyn SAGD: | ||||||||||
Capital expenditures and net acquisitions | 33.2 | 8.3 | 4.2 | |||||||
Company reserve additions (MMBOE) | 5.4 | 47.7 | - | |||||||
FD&A costs ($/BOE) | $ | 13.98 | $ | 7.68 | $ | 9.36 | ||||
Three-year average FD&A costs ($/BOE)(2) | $ | 10.09 | $ | 8.22 | $ | 7.86 |
(1) 2003 reserve volumes are adjusted to negate the impacts of NI 51-101
(2) Calculated as FD&A over a three-year period.
RECYCLE RATIO
Recycle ratio is the product of operating income divided by FD&A including FDC. This measure is indicative of the value creation within the business as it represents the dollars generated for each dollar invested. The escalating cost of acquiring new assets and developing our existing assets is increasing FD&A costs and limiting our recycle ratio despite the high commodity price environment. Our recycle ratio was also affected by the full cost of our U.S. acquisition with only a partial year of high netback production. With the full benefit of the higher netback properties acquired in the U.S. late in 2005, we anticipate our operating income will improve in 2006 which should benefit our recycle ratio.
(Proved plus probable reserves) | 2005 | 2004 | 2003 | |||||||
Operating income ($/BOE) | 29.80 | 21.86 | 20.89 | |||||||
Finding, development and acquisition costs including FDC ($/BOE) | 17.18 | 11.34 | 11.60 | |||||||
Recycle ratio | 1.7x | 1.9x | 1.8x | |||||||
Three-year average recycle ratio | 1.8x | 1.8x | 1.9x |
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)
The following discussion and analysis of financial results is dated February 18, 2006 and is to be read in conjunction with the audited consolidated financial statements as at and for the years ended December 31, 2005 and 2004. All amounts are stated in Canadian dollars unless otherwise specified. All note references relate to the notes included with the consolidated financial statements. In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before deduction of crown and other royalties, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of BOE in isolation may be misleading.
NON-GAAP MEASURES
Throughout the MD&A, we use the terms funds flow from operations (“funds flow”) and cash available for distribution. These terms as presented do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles (“GAAP”), and therefore they may not be comparable with the calculation of similar measures for other entities. Funds flow as presented is not intended to represent operating cash flows or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with GAAP. Funds flow is used by management to analyze operating performance, leverage and liquidity. All references to funds flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital. Cash available for distribution is calculated using funds flow less discretionary amounts of cash withheld for acquisitions, capital expenditures and debt repayment. Refer to the Cash Available for Distribution section of the MD&A for a quantitative reconciliation of “funds flow” to cash flow from operating activities.
2005 OVERVIEW
2005 was an extremely active year with the acquisitions of TriLoch Resources Inc. (“TriLoch”) and Lyco Energy Corporation (“Lyco”) occurring throughout our third quarter. The acquisition of Lyco was a strategic move into the United States and has provided further opportunities evidenced by the acquisition of Sleeping Giant LLC (“Sleeping Giant”) which closed in the fourth quarter. These acquisitions, collectively, added approximately 10,000 BOE/day of production and 42.8 MMBOE of total proved plus probable reserves, replacing approximately 147% of 2005 total production.
Overall we achieved our corporate guidance targets for annual production, operating costs per BOE and general and administrative (“G&A”) costs per BOE. Development capital expenditures were $13.7 million higher than our guidance due to additional opportunities and increased costs. Our annual production increased 6% year over year due to our capital program and acquisitions. Exit production was approximately 85,000 BOE/day based on December’s monthly average, which is below our guidance of 86,000 BOE/day due to delays and facility restrictions. We estimate 3,800 BOE/day associated with 2005 capital spending was delayed and is expected to come on production early in 2006.
Compared to 2004, funds flow from operations increased 47%, net income per trust unit increased 52% and distributions to unitholders increased 20%. Additional production combined with a 28% rise in commodity prices were the main contributors to the year-over-year increases which were partially offset by a 4% increase in operating costs.
Highlights
• | Our Canadian unitholders realized a 38.2% total return in 2005 (representing the appreciation in unit price plus distributions paid during the year). |
• | Our U.S. unitholders realized a 42.1% total return in 2005, as the appreciation in the Canadian dollar effectively increased distributions and the unit price when exchanged into U.S. dollars. |
• | Rising commodity prices and higher production increased funds flow from operations to $794.4 million or $7.28 per trust unit, an increase of 34% per unit. |
• | Distributions to unitholders increased by 20% to $511.1 million or 8% per unit to $4.54 per unit. |
• | Actual monthly distributions per trust unit increased from $0.35 to $0.42 during 2005. |
• | Average selling price per BOE increased 28% to $52.36 due to strengthening commodity prices. |
• | Production averaged 79,727 BOE/day, a new record, which exceeded our annual target of 79,000 BOE/day. |
• | Total development capital expenditures for the year were $368.7 million. |
• | On July 1, 2005 we closed the acquisition of TriLoch with the issuance of 1.6 million trust units for total consideration of $77.4 million. |
• | On August 30, 2005 we completed the acquisition of Lyco for total consideration of $501.9 million, our single largest transaction to date and our first acquisition outside of Canada. |
• | In connection with the Lyco acquisition we completed an equity offering, issuing 10.6 million trust units for gross proceeds of $492.0 million ($466.9 million net of costs). |
• | On October 4, 2005 we closed the acquisition of Sleeping Giant for total consideration of $111.9 million, increasing our working interest on existing U.S. properties. |
• | Net income increased 67% to $432.0 million. On a trust unit basis the increase was 52% to $3.96 per unit reflecting the increase in trust units outstanding. |
• | Our payout ratio decreased from 79% to 64% as we retained additional funds flow for development capital opportunities. |
• | Operating costs were $7.45/BOE, consistent with our guidance for 2005. This represented a 4% increase from 2004 despite rapidly rising industry costs. |
• | Cash G&A costs were in line with our guidance at $1.28/BOE. |
• | Our commodity price risk management costs were $142.6 million ($4.90/BOE) during 2005 due to record high commodity oil prices. |
• | Drilling efforts resulted in a success rate of over 99% with participation in 393 net wells. |
• | Our finding, development and acquisition costs (“FD&A”) for the year were $19.55/BOE on a proved basis and $17.18/BOE on a proved plus probable basis including future development capital. |
• | Proved reserves increased 12% to 313.2 MMBOE and proved plus probable reserves increased 11% to 449.1 MMBOE. |
• | Positive reserve additions from development capital spending and acquisitions replaced 217% of 2005 production on a proved basis, and 247% on a proved plus probable basis. |
• | Enerplus’ Reserve Life Index (“RLI”) continued to be one of the longest in the sector at 9.9 years on a proved basis and 13.5 years on a proved plus probable basis. |
• | Our recycle ratio (operating income divided by FD&A) was 1.8x on a three-year basis and 1.7x for 2005 using proved plus probable reserves. |
• | We continue to maintain a conservative balance sheet as evidenced by a net debt to trailing funds flow ratio of 0.8x. |
RESULTS OF OPERATIONS
Production
Daily production increased 6% during 2005 averaging 79,727 BOE/day, up from 75,130 BOE/day in 2004. This increase was primarily due to our development capital program and acquisitions. The most significant acquisitions completed during the year included TriLoch, Lyco and Sleeping Giant.
Average production during 2005 was weighted 57% natural gas and 43% liquids on a BOE basis. Our operations have now expanded into the United States further diversifying our production base which already included Alberta, Saskatchewan, British Columbia and Manitoba. With operations widely distributed across more than 300 producing areas we minimize the risk that operational problems on a given property will materially impact our production or funds flow.
Average production volumes for the years ended December 31, 2005 and 2004 are outlined below:
Daily Production Volumes | 2005 | 2004 | % change | |||||||
Natural gas (Mcf/day) | 274,336 | 271,091 | 1 | % | ||||||
Crude oil (bbls/day) | 29,315 | 25,550 | 15 | % | ||||||
Natural gas liquids (bbls/day) | 4,689 | 4,398 | 7 | % | ||||||
Total daily sales (BOE/day) | 79,727 | 75,130 | 6 | % |
We exited the year with production of approximately 85,000 BOE/day based on December’s monthly average production, slightly below our target of 86,000 BOE/day. Our development capital program experienced delays due to pipeline curtailment at Bashaw and facility restrictions at Bantry North. As a result we expect approximately 3,800 BOE/day of production related to 2005 activity to come on stream early in 2006.
We expect 2006 production to average 84,000 BOE/day, weighted 53% natural gas and 47% liquids. In addition, we expect to exit 2006 with production of approximately 89,000 BOE/day which is 5% above our 2005 exit rate. This reflects our planned development capital program, however does not contemplate potential acquisitions or dispositions.
Pricing
Our earnings, funds flow and financial condition are dependent on the prices received for our natural gas and crude oil production. The following table compares our average selling prices for 2005 with those of 2004. It also compares the benchmark price indices for the same periods.
Average Selling Price(1) | 2005 | 2004 | % Change | |||||||
Natural gas (per Mcf) | $ | 8.41 | $ | 6.56 | 28 | % | ||||
Crude oil (per bbl) | 55.93 | 43.80 | 28 | % | ||||||
Natural gas liquids (per bbl) | 47.33 | 38.14 | 24 | % | ||||||
Per BOE | $ | 52.36 | $ | 40.90 | 28 | % |
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments
Average Benchmark Pricing | 2005 | 2004 | % Change | |||||||
AECO natural gas - monthly index (CDN$/Mcf) | $ | 8.48 | $ | 6.79 | 25 | % | ||||
AECO natural gas - daily index (CDN$/Mcf) | 8.71 | 6.53 | 33 | % | ||||||
NYMEX natural gas - monthly NX3 index (US$/Mcf) | 8.55 | 6.09 | 40 | % | ||||||
NYMEX natural gas - monthly NX3 index CDN$ equivalent (CDN$/Mcf) | 10.30 | 7.91 | 30 | % | ||||||
WTI crude oil (US$/bbl) | 56.56 | 41.40 | 37 | % | ||||||
WTI crude oil: CDN$ equivalent (CDN$/bbl) | 68.14 | 53.77 | 27 | % | ||||||
CDN$/US$ exchange rate | $ | 0.83 | $ | 0.77 | 8 | % |
Natural Gas
During the first half of the year, the monthly AECO benchmark natural gas price averaged just over $7.00/Mcf. Late in the summer, prices climbed to over $12.00/Mcf in response to hurricane activity and strength in crude oil prices. Despite disruption in the Gulf Coast area, production during the summer injection season was sufficient to fill North American storage. Cold weather was slow to arrive in the fall of 2005 and as a result demand for natural gas combined with adequate storage levels caused prices to retreat at year-end to $10.78/Mcf. Overall, the average price for the AECO monthly index price for 2005 was $8.48/Mcf, up 25% compared to $6.79/Mcf in 2004.
Within our sales portfolio of aggregator, downstream and spot gas, we sold approximately 40% of our natural gas based on AECO month index, 40% based on AECO day index and 20% at NYMEX monthly NX3 index prices. With the volatility around the weather and supply issues, there can be significant price differences between the month and day indices.
During 2005 we realized an average price of $8.41/Mcf (net of transportation) on our natural gas, an increase of 28% from $6.56/Mcf in 2004. In comparison, the AECO monthly index price for natural gas increased 25% and the AECO daily index increased 33%.
As indicated by the current market for future prices (the “forward market”), AECO natural gas prices are expected to average $8.08/Mcf for 2006. Weather continues to be a significant factor in the near term volatility of natural gas prices.
Crude Oil
The crude oil benchmark West Texas Intermediate (“WTI”) price experienced volatility throughout 2005. Early in the year, fears concerning the supply demand balance and the refining infrastructure caused the prices to rise above US$50.00/bbl. Mid year unrest in Nigeria combined with the onset of the hurricane
season pushed prices to peak at approximately US$70.00/bbl. Warmer weather and a reassessment of inventory levels post hurricane season, caused prices to settle into the US$60.00/bbl range near the end of the year. Overall, WTI prices denominated in U.S. dollars were 37% higher in 2005 compared to 2004.
Our average crude oil selling price increased 28% from CDN$43.80 to CDN$55.93 which was comparable to the increase in the Canadian dollar equivalent WTI at 27%. Furthermore, our additional light sweet production in the United States offset the effect of increasing Canadian heavy oil differentials on our existing production.
Continued geopolitical instability throughout the world combined with expected steady growth in a number of key economies have the current forward crude oil price at approximately US$64.70/bbl converted to CDN$74.39 using an exchange rate of US$0.87 for 2006.
Throughout 2005 the Canadian dollar strengthened 8% against the U.S. dollar, reducing prices received for our crude oil and a portion of our natural gas. Most of Canada’s crude oil and natural gas is exported to the U.S. and is priced with reference to U.S. dollar denominated benchmarks. The CDN$/US$ exchange rate entered 2005 at $0.83 and increased throughout the year to $0.86 in December.
Price Risk Management
Our commodity price risk management program incurred cash costs of $142.6 million during 2005 compared to $96.2 million during 2004. The increase in cash costs was primarily due to record high commodity prices exceeding our calls. The majority of these derivative instruments were contracted in 2003 and 2004, some of which expired on December 31, 2005 with the remaining expiring by the end of 2006.
Risk Management Cash Costs ($ millions, except per unit amounts) | 2005 | 2004 | |||||||||||
Crude oil | $ | 91.0 | $ | 8.51/bbl | $ | 76.3 | $ | 8.16/bbl | |||||
Natural Gas | 51.6 | $ | 0.52/Mcf | 19.9 | $ | 0.20/Mcf | |||||||
Net cost | $ | 142.6 | $ | 4.90/BOE | $ | 96.2 | $ | 3.50/BOE |
We continue to review our risk management strategies in response to the increasing price environment, the economics of our acquisitions and development projects along with our overall financial position. Recently, we have not been actively hedging commodity prices, however, this strategy may change in the future as management is constantly comparing the value of hedging with our overall requirement for price protection.
The following table summarizes the effect that our financial contracts have had on income for the years ended December 31, 2005 and 2004.
2005 | 2004 | ||||||||||||
Commodity Derivative Instruments | ($ millions) | (Per BOE) | ($ millions) | (Per BOE) | |||||||||
Financial contracts not qualifying as hedges: | |||||||||||||
Change in fair value - other financial contracts | $ | (35.8 | ) | $ | (1.23 | ) | $ | 21.3 | $ | 0.77 | |||
Amortization of deferred financial assets | 3.1 | 0.11 | 17.9 | 0.65 | |||||||||
Cash costs of financial contracts | 115.4 | 3.96 | 78.0 | 2.84 | |||||||||
$ | 82.7 | $ | 2.84 | $ | 117.2 | $ | 4.26 | ||||||
Financial contracts qualifying as hedges: | |||||||||||||
Cash costs of financial contracts | 27.2 | 0.94 | 18.2 | 0.66 | |||||||||
Total cost of financial contracts | $ | 109.9 | $ | 3.78 | $ | 135.4 | $ | 4.92 |
The unrealized gain on our financial contracts of $35.8 million for the year ended December 31, 2005 represents the change in the fair value of financial contracts not qualifying for hedge accounting and results in a non-cash increase to earnings.
Effective December 31, 2005, we elected to stop designating our commodity financial contracts as hedges. As a result we recorded a deferred credit representing the fair value of these contracts on that day, with an offset recorded as a deferred financial asset that is amortized to income over the life of the underlying contracts. All of these contracts mature during 2006, therefore the deferred financial asset will be fully amortized by December 31, 2006. In the future, non-cash gains or losses on any new commodity contracts will be reflected in our income statement.
Funds flow remains sensitive to changes as demonstrated by the following table:
Sensitivity Table | Estimated Effect on 2006 Funds Flow per Trust Unit | |||
Change of $0.15 per Mcf in the price of AECO natural gas | $ | 0.09 | ||
Change of US$1.00 per barrel in the price of WTI crude oil | $ | 0.09 | ||
Change of 1,000 BOE/day in production | $ | 0.14 | ||
Change of $0.01 in the US$/CDN$ exchange rate | $ | 0.11 | ||
Change of 1% in interest rate | $ | 0.06 |
These sensitivities reflect all commodity contracts as described in Note 12 and are based on current forward markets for 2006. To the extent the market price of crude oil and natural gas change significantly from current levels, the above sensitivities will no longer be relevant.
REVENUES
Crude oil and natural gas revenues for the year ended December 31, 2005 were $1,523.7 million ($1,550.6 million, net of $26.9 million transportation) compared to $1,124.6 million ($1,149.7 million, net of $25.1 million transportation) during 2004. Higher crude oil and natural gas prices, combined with increased production from our development capital program and recent acquisitions resulted in a 35% increase of $399.1 million.
Analysis of Sales Revenue(1) ($ millions) | Crude oil | NGLs | Natural Gas | Total | |||||||||
2004 Sales Revenue | $ | 409.5 | $ | 61.4 | $ | 653.7 | $ | 1,124.6 | |||||
Price variance(1) | 129.8 | 15.7 | 184.6 | 330.1 | |||||||||
Volume variance | 59.1 | 3.9 | 6.0 | 69.0 | |||||||||
2005 Sales Revenue | $ | 598.4 | $ | 81.0 | $ | 844.3 | $ | 1,523.7 |
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
ROYALTIES
Royalties are paid to various government entities and other land and mineral rights owners. Royalties in 2005 and 2004 were approximately 19% and 20% of oil and gas sales, net of transportation, respectively. Overall royalties were $297.0 million compared to $231.0 million during 2004 which is consistent with our increase in revenue. We expect royalties to remain at approximately 19% for 2006.
OPERATING EXPENSES
Operating expenses for the year ended December 31, 2005 were on target with our guidance at $7.45/BOE or $216.8 million. This represented a 4% increase from $7.14/BOE or $196.5 million in 2004. As expected, we experienced increased cost pressures due to industry activity levels and higher utility rates. We also incurred additional well servicing costs as we focused on production enhancement initiatives. We expect cost pressures to continue in 2006 and estimate annual operating costs will be approximately $7.95/BOE, representing an increase of 7% per BOE compared to 2005.
GENERAL AND ADMINISTRATIVE EXPENSES
G&A expenses were $1.39/BOE or $40.4 million for the year ended December 31, 2005 compared to $1.23/BOE or $33.9 million for 2004.
Cash G&A costs of $1.28/BOE or $37.4 million were in line with our guidance of $1.27/BOE and higher than costs of $1.06/BOE or $29.2 million experienced during 2004. The increase from the prior year can be attributed to recruiting and retaining skilled professional and technical staff along with increased infrastructure and information technology to support and enhance our expanded operations.
Non-cash charges for our trust unit rights incentive plan for the year ended December 31, 2005 were $3.0 million or $0.11/BOE compared to $4.7 million or $0.17/BOE for 2004. Based on revised guidance on accounting for stock based compensation and related interpretations by the securities commissions, we have retroactively adopted the fair value method of accounting for our trust unit rights incentive plan to January 1, 2003. The impact of the adoption on our 2003 and 2004 reported earnings is not material and therefore prior period financial statements have not been restated. Our fourth quarter compensation expense in 2005 includes a non-cash recovery of $10.6 million. This recovery represents the difference between the unit based compensation expense related to 2005 originally calculated under the intrinsic method compared to the expense calculated using the fair value method. This change had no impact on funds flow from operations. See Notes 2 and 10.
The following table summarizes the cash and non-cash expenses recorded in G&A:
General and Administrative Costs ($ millions) | 2005 | 2004 | |||||
Cash | $ | 37.4 | $ | 29.2 | |||
Trust unit rights incentive plan (non-cash) | 3.0 | 4.7 | |||||
Total G&A | $ | 40.4 | $ | 33.9 |
(Per BOE) | 2005 | 2004 | |||||
Cash | $ | 1.28 | $ | 1.06 | |||
Trust unit rights incentive plan (non-cash) | 0.11 | 0.17 | |||||
Total G&A | $ | 1.39 | $ | 1.23 |
For 2006 we expect total G&A costs to be approximately $1.70/BOE, including non-cash G&A costs of $0.15/BOE. The forecasted increase reflects rising costs within a very competitive market place and our expanded operations in the United States.
INTEREST EXPENSE
Annual interest expense was $25.8 million compared to $20.7 million in 2004. This increase is due to higher debt levels and rising interest rates during 2005. At December 31, 2005, 21% of our debt was based on fixed interest rates while 79% was floating. These instruments are more fully described in Note 12.
FOREIGN EXCHANGE
We experienced a foreign exchange loss of $1.7 million during the year ended December 31, 2005 compared to a gain of $5.0 million in 2004. A loss on foreign exchange contracts that were used to secure purchase price economics on the acquisition of Lyco was partially offset by gains on our US$54 million debentures. See Note 9 for further information.
CAPITAL EXPENDITURES
During the year ended December 31, 2005 we spent $1,010.5 million on capital expenditures and acquisitions net of dispositions compared to $813.6 million in 2004. As discussed in Notes 6 and 7, our most significant acquisitions during 2005 were TriLoch, Lyco, and Sleeping Giant. Our capital expenditures were financed through bank borrowing, the issuance of trust units and funds flow.
Capital Expenditures ($ millions) | 2005 | 2004 | |||||
Development expenditures | $ | 272.2 | $ | 157.7 | |||
Plant and facilities | 96.5 | 49.1 | |||||
Development Capital | 368.7 | 206.8 | |||||
Office | 4.3 | 2.2 | |||||
Sub-total | 373.0 | 209.0 | |||||
Acquisitions of oil and gas properties | 119.9 | 505.8 | |||||
Corporate acquisitions | 584.1 | 130.5 | |||||
Dispositions of oil and gas properties | (66.5 | ) | (31.7 | ) | |||
Total Net Capital Expenditures | 1,010.5 | 813.6 | |||||
Total Capital Expenditures financed with funds flow | 283.3 | 113.3 | |||||
Total Capital Expenditures financed with debt and equity | $ | 727.2 | $ | 700.3 |
The following is a summary by major property of our largest development capital expenditures during 2005 and 2004.
($ millions) | Development Type | 2005 | 2004 | |||||||
Bantry | Conventional oil and shallow gas | $ | 42.0 | $ | 12.0 | |||||
Joslyn | SAGD oil | 33.2 | 8.3 | |||||||
Sleeping Giant | Conventional oil | 29.1 | - | |||||||
Pembina 5-Way | Oil waterflood | 19.8 | 8.8 | |||||||
Hanna/Garden Plains | Shallow gas | 18.5 | 11.4 | |||||||
Joarcam | Oil waterflood | 16.9 | 9.0 | |||||||
Joffre | Coalbed methane | 15.9 | 4.7 | |||||||
Bashaw | Coalbed methane | 14.9 | 2.2 | |||||||
Deep Basin | Natural gas | 11.6 | 13.9 | |||||||
Medicine Hat | Oil waterflood and shallow gas | 11.0 | 12.4 | |||||||
Other | Oil and gas | 155.8 | 124.1 | |||||||
Total | $ | 368.7 | $ | 206.8 |
Total development capital expenditures in 2006 are expected to be approximately $485 million. We plan to spend approximately $74 million on shallow natural gas development, $78 million on waterflood development, $89 million on Bakken oil development at our U.S. properties, $31 million on oil sands development and $49 million with respect to coalbed methane. Other conventional development costs are expected to be approximately $164 million during 2006.
In 2005, we sold $66.5 million worth of non-core properties and we expect to continue the process of acquiring new properties and rationalizing marginal properties in 2006. At this time we have no significant divestment program planned for 2006.
ASSET RETIREMENT OBLIGATIONS
We have estimated total future asset retirement obligations based on our net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. Our asset retirement obligation was $110.6 million at December 31, 2005 compared to $106.0 million at December 31, 2004. The increase of $4.6 million was due to our acquisition and development activity during the year combined with changes in estimated future liabilities, offset by our dispositions of non-core properties. The remainder of the change was due to retirement costs incurred offset by accretion expense for the year. See Note 4.
DEPLETION, DEPRECIATION, AMORTIZATION AND ACCRETION (“DDA&A”)
DDA&A of property, plant and equipment (“PP&E”) is recognized using the unit-of-production method based on proved reserves. For the year ended December 31, 2005, DDA&A increased to $13.27/BOE compared to $11.87/BOE during the year ended December 31, 2004. The increase is due to rising FD&A costs experienced over the last couple of years.
No impairment existed at December 31, 2005 using year-end reserves and management’s estimates of future prices. Our future price estimates are more fully discussed in Note 5.
TAXES
Future Income Taxes
Future income taxes arise from differences between the accounting and tax bases of the operating companies’ assets and liabilities. The future income tax liability associated with Canadian assets recorded on the balance sheet is recovered through earnings over time.
For the year ended December 31, 2005, a future income tax expense of $15.3 million was recorded in income compared to a future income tax recovery of $76.8 million in 2004. The change from 2004 to 2005 was due to the combination of a future tax expense with respect to U.S. operations, amended tax pool balances, and a reduced payout ratio. Our expected future income tax rate incorporating these changes is approximately 34% which is the same as 2004.
Current Income Taxes
In our current structure, payments are made between the Canadian operating entities and the Fund, ultimately transferring both income and future income tax liability to our unitholders. Therefore, no cash income taxes have been paid by our Canadian operating entities.
Our U.S. operations incurred taxes (income and withholding) in the amount of $2.8 million. The amount of tax was lower than originally projected due to increased development capital spending combined with additional tax pools.
In 2006, we expect current and withholding taxes to be approximately 20% of U.S. funds flow from operations.
Capital Taxes
Capital taxes of $6.5 million decreased slightly in 2005 compared to 2004. The decrease is due to a reduction in the tax rate for Federal Large Corporations Tax. Capital taxes are expected to be $6.5 million in 2006.
SELECTED FINANCIAL RESULTS
Per BOE of production (6:1) | 2005 | 2004 | |||||
Production per day | 79,727 | 75,130 | |||||
Weighted average sales price (1) | $ | 52.36 | $ | 40.90 | |||
Royalties | (10.21 | ) | (8.40 | ) | |||
Financial contracts | (3.78 | ) | (4.92 | ) | |||
Add back / (deduct): Non-cash financial contracts | (1.12 | ) | 1.42 | ||||
Operating costs | (7.45 | ) | (7.14 | ) | |||
General and administrative | (1.39 | ) | (1.23 | ) | |||
Add back: Non-cash G&A expense (trust unit rights) | 0.11 | 0.17 | |||||
Interest expense, net of interest and other income | (0.51 | ) | (0.68 | ) | |||
Foreign exchange (loss) gain | (0.06 | ) | 0.18 | ||||
Deduct: Non-cash foreign exchange loss | (0.07 | ) | (0.17 | ) | |||
Capital taxes | (0.22 | ) | (0.24 | ) | |||
Current income tax | (0.09 | ) | - | ||||
Restoration and abandonment cash costs | (0.27 | ) | (0.25 | ) | |||
Funds flow from operations | 27.30 | 19.64 | |||||
Restoration and abandonment cash costs | 0.27 | 0.25 | |||||
Non-cash items: | |||||||
Depletion, depreciation, amortization and accretion | (13.27 | ) | (11.87 | ) | |||
Financial contracts | 1.12 | (1.42 | ) | ||||
G&A expense (trust unit rights) | (0.11 | ) | (0.17 | ) | |||
Foreign exchange | 0.07 | 0.17 | |||||
Future income tax expense | (0.53 | ) | 2.79 | ||||
Total net income per BOE | $ | 14.85 | $ | 9.39 |
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments
SELECTED CANADIAN AND U.S. FINANCIAL RESULTS
The following table provides a geographical analysis of key financial results for 2005. Prior period information has not been presented as we only had operations in Canada prior to 2005.
($ millions, except per unit amounts) | Canada | U.S. | Total | |||||||
Daily Production Volumes | ||||||||||
Natural gas (Mcf/day) | 272,754 | 1,582 | (1) | 274,336 | ||||||
Crude oil (bbls/day) | 26,432 | 2,883 | (1) | 29,315 | ||||||
Natural gas liquids (bbls/day) | 4,689 | - | 4,689 | |||||||
Total Daily Sales (BOE/day) | 76,580 | 3,147 | (1) | 79,727 | ||||||
Pricing (2) | ||||||||||
Natural gas (per Mcf) | $ | 8.39 | $ | 12.58 | $ | 8.41 | ||||
Crude oil (per bbl) | 54.58 | 68.25 | 55.93 | |||||||
Natural gas liquids (per bbl) | 47.33 | - | 47.33 | |||||||
Revenues | ||||||||||
Oil and gas sales (2) | $ | 1,444.6 | $ | 79.1 | $ | 1,523.7 | ||||
Royalties | (281.9 | ) | (15.1 | )(3) | (297.0 | ) | ||||
Financial Contracts - Qualified Hedges | (27.2 | ) | - | (27.2 | ) | |||||
Other Financial Contracts | (83.1 | ) | 0.4 | (82.7 | ) | |||||
Expenses | ||||||||||
Operating | $ | 214.7 | $ | 2.1 | $ | 216.8 | ||||
General and Administrative | 39.1 | 1.3 | 40.4 | |||||||
Depletion, depreciation, amortization and accretion | 354.7 | 31.8 | 386.5 | |||||||
Current income taxes | - | 2.8 | 2.8 | |||||||
(1) United States production per day (BOE/day) represents four months of Enerplus’ production commencing with the closing of the Lyco acquisition on August 30, 2005 (9,415 BOE/day expressed on an annualized basis).
(2) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
(3) Royalties include U.S. state production tax.
NET INCOME AND FUNDS FLOW FROM OPERATIONS
Increased production volumes and commodity prices resulted in increased oil and gas sales, net income and funds flow from operations during the three years. The following table provides a summary of net income, funds flow from operations and other key measures.
($ millions, except per unit amounts) | 2005 | 2004 | 2003 | |||||||
Oil and Gas Sales(1) | $ | 1,523.7 | $ | 1,124.6 | $ | 935.8 | ||||
Net Income | 432.0 | 258.3 | 248.0 | |||||||
Per unit (Basic) | 3.96 | 2.60 | 2.88 | |||||||
Per unit (Diluted) | 3.95 | 2.60 | 2.87 | |||||||
Funds flow from operations | 794.4 | 540.0 | 413.2 | |||||||
Per unit (Basic) | 7.28 | 5.44 | 4.79 | |||||||
Cash available for distribution | 511.1 | 426.7 | 379.1 | |||||||
Per unit (Basic) | 4.54 | 4.20 | 4.32 | |||||||
Payout ratio | 64 | % | 79 | % | 92 | % | ||||
Total assets | 4,130.6 | 3,180.7 | 2,661.8 | |||||||
Long-term debt, net of cash | 649.8 | 585.0 | 257.7 |
(1) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments
Funds flow from operations for the year ended December 31, 2005 was $794.4 million or $7.28 per trust unit compared to $540.0 million or $5.44 per trust unit for 2004. Net income for the year ended December 31, 2005 was $432.0 million or $3.96 per trust unit compared to $258.3 million or $2.60 per trust unit for 2004. The increase in both funds flow from operations and net income was a result of higher commodity prices and production during 2005 compared to 2004. These increases were offset partially by cash losses on our commodity price risk management program and increased operating expenses.
QUARTERLY FINANCIAL INFORMATION
Overall oil and gas sales have increased due to higher commodity prices and production as well as through development capital activity and acquisitions throughout the last two years. Net income has been affected by rising oil and gas sales, increased risk management costs, the strengthening Canadian dollar, higher operating costs, changes in future tax recovery and changes to accounting policies adopted during 2005.
Oil and Gas Sales(1) | Net Income | Net Income Per Trust Unit | |||||||||||
Basic | Diluted | ||||||||||||
2005 | |||||||||||||
Fourth Quarter | $ | 503.2 | $ | 161.5 | $ | 1.38 | $ | 1.37 | |||||
Third Quarter | 398.7 | 100.3 | 0.91 | 0.91 | |||||||||
Second Quarter | 320.0 | 108.0 | 1.03 | 1.03 | |||||||||
First Quarter | 301.8 | 62.2 | 0.60 | 0.59 | |||||||||
Total | $ | 1,523.7 | $ | 432.0 | $ | 3.96 | $ | 3.95 | |||||
2004 | |||||||||||||
Fourth Quarter | $ | 317.5 | $ | 114.5 | $ | 1.10 | $ | 1.10 | |||||
Third Quarter | 302.2 | 50.6 | 0.49 | 0.49 | |||||||||
Second Quarter | 265.6 | 48.0 | 0.51 | 0.51 | |||||||||
First Quarter | 239.3 | 45.2 | 0.48 | 0.48 | |||||||||
Total | $ | 1,124.6 | $ | 258.3 | $ | 2.60 | $ | 2.60 |
SUMMARY FOURTH QUARTER INFORMATION
In comparing the fourth quarter of 2005 with the same period in 2004:
• Net income increased 41% to $161.5 million.
• Funds flow from operations increased 95% to $291.2 million and 87% on a BOE basis as a result of increased production and rising commodity prices.
• Average daily production increased 4% due to our successful development capital program as well as our recent acquisitions.
• The average selling price per BOE increased 52% due to stronger crude oil and natural gas prices.
• Operating expenses increased 5% to $7.29/BOE mainly due to higher power and utility rates.
• G&A expenses decreased 81% to $0.30/BOE, as the fourth quarter of 2005 includes a $10.6 million non-cash recovery related to the adoption of the fair value method of accounting for our trust unit rights incentive plan (see Note 2).
• Development capital spending increased 86% due to our expanded development program in 2005.
Summary Fourth Quarter Information ($ millions, except per unit amounts) | Three Months Ended December 31, 2005 | Three Months Ended December 31, 2004 | % Change | |||||||
Daily Production Volumes | ||||||||||
Natural gas (Mcf/day) | 269,443 | 292,671 | (8 | %) | ||||||
Crude oil (bbls/day) | 35,167 | 28,752 | 22 | % | ||||||
Natural gas liquids (bbls/day) | 5,045 | 4,157 | 21 | % | ||||||
Total daily sales (BOE/day) | 85,119 | 81,688 | 4 | % | ||||||
Average Selling Price (1) | ||||||||||
Natural gas (per Mcf) | $ | 11.65 | $ | 6.59 | 77 | % | ||||
Crude oil (per bbl) | 58.41 | 46.20 | 26 | % | ||||||
Natural gas liquids (per bbl) | 50.56 | 45.46 | 11 | % | ||||||
Per BOE | 64.26 | 42.25 | 52 | % | ||||||
Revenue (1) | 503.2 | 317.5 | 58 | % | ||||||
Per BOE | 64.26 | 42.25 | 52 | % | ||||||
Operating Expenses | 57.1 | 52.1 | 10 | % | ||||||
Per BOE | 7.29 | 6.93 | 5 | % | ||||||
General and Administrative Expenses | 2.3(2 | ) | 11.9 | (81 | %) | |||||
Per BOE | 0.30(2 | ) | 1.59 | (81 | %) | |||||
Net Income | 161.5 | 114.5 | 41 | % | ||||||
Per BOE | 20.62 | 15.24 | 35 | % | ||||||
Funds Flow from Operations | 291.2 | 149.4 | 95 | % | ||||||
Per BOE | 37.19 | 19.88 | 87 | % | ||||||
Development Capital Spending | 139.1 | 74.9 | 86 | % | ||||||
Acquisitions | 112.5 | 14.5 | 676 | % | ||||||
Divestments | $ | 0.4 | $ | 12.7 | (97 | %) |
(1) Net of oil and gas transportation costs, but before the effects of commodity derivatives.
(2) The entire non-cash recovery related to the adoption of the fair value method of accounting for our trust unit rights incentive plan has been recorded in the fourth quarter of 2005.
CASH AVAILABLE FOR DISTRIBUTION
Our payout ratio for the year ended December 31, 2005 was 64%, compared to a payout ratio of 79% for the year ended December 31, 2004. During 2005, we funded over $1 billion in acquisitions and development capital spending through a combination of equity issuance, cash retained by the business, increased bank debt, and proceeds from divestments.
We continually monitor our distribution payout with respect to forecasted funds flows, debt levels and spending plans. The level of cash retained typically varies between 10% and 40% of annual funds flow. This range has increased over the last two years. Recently we have been funding a greater portion of our development capital and acquisition programs with cash generated by the business, rather than through new equity issuance or increased debt. We are prepared to adjust the payout levels in an effort to balance the investor’s desire for distributions with the Fund’s requirement to maintain a prudent capital structure. The actual amount of funds flow withheld is dependant upon our current levels of production, the prevailing commodity price environment and is at the discretion of our Board of Directors.
The following table reconciles Enerplus’ funds flow from operations with the cash available for distribution
to unitholders.
Reconciliation of Cash Available for Distribution ($ millions, except per unit amounts) | 2005 | 2004 | |||||
Cash flow from operating activities | $ | 774.6 | $ | 555.1 | |||
Change in non cash working capital | 19.8 | (15.1 | ) | ||||
Funds flow from operations | 794.4 | 540.0 | |||||
Cash withheld for acquisitions, capital expenditures and debt repayment(1) | (283.3 | ) | (113.3 | ) | |||
Cash available for distribution(2) | $ | 511.1 | $ | 426.7 | |||
Cash available for distribution per trust unit | $ | 4.54 | $ | 4.20 | |||
Payout ratio | 64 | % | 79 | % |
(1) Cash withheld for acquisitions, capital expenditures and debt repayment is a discretionary amount and represents the difference between cash flow from operations less distributions.
(2) Cash available for distribution will differ from Cash Distributions to Unitholders on the Consolidated Statements of Cash Flows due to the timing of distribution announcements and the number of trust units outstanding on the record dates.
LIQUIDITY AND CAPITAL RESOURCES
Long-term debt, net of cash, at December 31, 2005 was $649.8 million, an increase of $64.8 million from December 31, 2004. Long-term debt at December 31, 2005 is comprised of $328.6 million of bank indebtedness and $331.3 million of senior unsecured notes.
Our working capital at December 31, 2005 decreased compared to December 31, 2004. Current liabilities increased due to significant development capital spending late in the year, which more than offset increased current assets, including receivables for oil and gas sales.
We continue to maintain a conservative balance sheet as demonstrated below:
Financial Leverage and Coverage | Year ended Dec. 31, 2005 | Year ended Dec. 31, 2004 | |||||
Long-term debt to trailing funds flow | 0.8 x | 1.1 x | |||||
Funds flow to interest expense | 30.8 x | 26.0 x | |||||
Long-term debt to long-term debt plus equity | 21 | % | 23 | % |
Long-term debt is measured net of cash.
Funds flow and interest expense are 12-months trailing (calculated based on the last 12 months after adjusting for acquisitions).
Enerplus has an $850 million bank credit facility (the “Bank Credit Facility”) through its wholly-owned subsidiary EnerMark Inc. The Bank Credit Facility is an unsecured, covenant-based, three-year committed credit agreement with nine North American banks. We have the ability to extend the facility each year or repay the entire balance at the end of the three-year term. At December 31, 2005, we had $521.4 million of available borrowing capacity under this facility, which currently extends to November, 2008. This bank debt carries floating interest rates that are expected to range between 60.0 and 115.0 basis points over Bankers Acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before interest, taxes and non-cash items.
Payments with respect to the bank facilities, senior unsecured notes and other third party debt have priority over claims of and future distributions to the unitholders. Unitholders have no direct liability should funds flow be insufficient to repay this indebtedness. The agreements governing these bank facilities and senior unsecured notes stipulate that if we default or fail to comply with certain covenants, the ability of the operating companies to make payments to the Fund and consequently the Fund’s ability to make distributions to the unitholders may be restricted.
Principal payments on Enerplus’ senior unsecured notes are required commencing in 2010 and 2011 and are more fully discussed in Note 8.
We anticipate that we will continue to have adequate liquidity to fund planned development capital spending during 2006 through a combination of funds flow from operations and debt. Most of our $485 million capital budget for 2006 is discretionary and can be revised downward in the event of a commodity price downturn or similar economic event.
COMMITMENTS
We have contracted to transport natural gas with various pipelines totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends until 2015. We also have a contract to transport a minimum of 2,480 bbls/day of crude oil until 2010. These transportation contracts will cost approximately $6.0 million in 2006.
Our office lease commitments expire between November 2009 and January 2011. Annual costs of these lease commitments, which include rent and operating fees, amount to approximately $5.7 million. The Fund’s commitments, contingencies, and guarantees are more fully described in Note 13.
We must continue to pay crown and surface royalties, lease rentals, mineral taxes along with abandonment and reclamation costs with respect to our ongoing ownership of hydrocarbon production rights. The amounts paid with respect to these burdens will depend on the future ownership, production, prices and legislative environment at the time.
Approximately 28% of our current gas production is dedicated to certain aggregator sales arrangements. Under these arrangements, we receive a price based on the average netback price of the pool, net of transportation costs incurred by the aggregator for the life of the reserves.
Enerplus has the following minimum annual commitments including long-term debt:
Minimum Annual Commitment Each Year | Total Committed | |||||||||||||||||||||
Total | 2006 | 2007 | 2008 | 2009 | 2010 | after 2010 | ||||||||||||||||
Bank credit facility | $ | 328.6(1) | $ | - | $ | - | $ | 328.6 | $ | - | $ | - | $ | - | ||||||||
Senior unsecured notes | 331.3(1) | - | - | - | - | 35.0 | 296.3 | |||||||||||||||
Pipeline commitments | 33.9 | 6.0 | 6.0 | 5.6 | 3.0 | 2.4 | 10.9 | |||||||||||||||
Office lease | 23.4 | 5.7 | 5.7 | 5.7 | 5.6 | 0.6 | 0.1 | |||||||||||||||
Total commitments | $ | 717.2 | $ | 11.7 | $ | 11.7 | $ | 339.9 | $ | 8.6 | $ | 38.0 | $ | 307.3 |
(1) Interest payments have not been included since future debt levels and rates are not known at this time.
TRUST UNIT INFORMATION
We had 117,539,000 trust units outstanding at December 31, 2005 compared to 104,124,000 trust units at December 31, 2004. The weighted average basic number of trust units outstanding during 2005 was 109,083,000 (2004 - 99,273,000). At February 10, 2006 we had 117,689,000 trust units outstanding.
On July 1, 2005 the Fund acquired all of the issued and outstanding shares of TriLoch in exchange for 1,632,516 trust units. The trust units exchanged were valued at $42.32 per unit, which was the weighted average trading price of the Fund’s trust units on the Toronto Stock Exchange during the five day trading period surrounding the announcement of the TriLoch transaction, for a recorded value of approximately $69.1 million after issuance costs.
On August 9, 2005 the Fund announced the closing of its subscription receipt financing related to the Lyco acquisition. A total of 10,637,500 subscription receipts were issued at a price of CDN$46.25 per receipt for gross proceeds of approximately $492.0 million. With the closing of the Lyco acquisition on August 30, 2005, subscription receipt holders received one trust unit for each subscription receipt held along with the August 2005 cash distribution of $0.37 per trust unit. The distribution paid to subscription receipt holders has been included in cash distributions to unitholders. During 2004, units with a value of $287.2 million, net of transaction costs, were issued to acquire corporate and property interests.
In addition 1,144,000 trust units (2004 - 950,000) were issued pursuant to the Trust Unit Monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”) and the trust unit rights plans, net of redemptions. This resulted in $40.4 million (2004 - $28.1 million) of additional equity to the Fund.
INCOME TAXES
The following is a general discussion of the Canadian and U.S. tax consequences of holding Enerplus trust units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Investors or potential unitholders should consult their own legal or tax advisors as to their particular tax consequences.
Canadian Unitholders
The Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and accordingly, trust units of the Fund are qualified investments for RRSPs, RRIFs, RESPs, and DPSPs. Each year, the Fund is required to file an income tax return and any taxable income in the Fund is allocated to the unitholders.
In computing income, unitholders are required to include their pro-rata share of any taxable income earned by the Fund in that year. An investor’s adjusted cost base (“ACB”) in a trust unit equals the purchase price of the trust unit less any non-taxable cash distributions received from the date of acquisition. To the extent a unitholder’s ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholder’s ACB will be brought to $nil.
We paid $4.47 per trust unit in cash distributions to unitholders on record during 2005. For Canadian tax purposes, approximately 10% of these distributions, or $0.43 per trust unit was a tax deferred return of capital, approximately 90% or $4.02 per trust unit was taxable to unitholders as other income, and less than 1% or $0.02 per trust unit was taxable dividend income.
For 2006, we estimate that 95% of cash distributions may be taxable and 5% may be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependent upon production, commodity prices and funds flow experienced throughout the year.
U.S. Unitholders
U.S. unitholders who received cash distributions were subject to at least a 15% Canadian withholding tax. The withholding tax is applied to both the taxable portion of the distribution as computed under Canadian tax law, and the non-taxable portion of the distribution. U.S. taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid.
The taxable portion of the cash distribution for U.S. tax purposes is determined by Enerplus in relation to its current and accumulated earnings and profits using U.S. income tax principles. The taxable portion determined is considered to be a dividend for U.S. tax purposes. For most U.S. taxpayers, this should be a “Qualified Dividend” eligible for the reduced tax rate. We believe Enerplus should not be classified as a Passive Foreign Investment Company for U.S. income tax purposes for 2005 and 2004.
The non-taxable portion of the cash distribution is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss arising from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as gains.
We paid US$3.63 per trust unit to U.S. residents during the 2005 calendar year, of which 7% or US$0.25 per trust unit was a tax deferred return of capital and 93% or US$3.38 per unit was a taxable qualified dividend.
For 2006, we estimate that 95% of cash distributions will be taxable to most U.S. investors and 5% will be a tax deferred return of capital. Actual taxable amounts may vary depending on actual distributions which are dependant upon production, commodity prices and funds flow experienced throughout the year.
CRITICAL ACCOUNTING POLICIES
The financial statements have been prepared in accordance with GAAP. A summary of significant accounting policies is presented in Note 1. A reconciliation of differences between Canadian and United States GAAP is presented in Note 15. Most accounting policies are mandated under GAAP. However, in accounting for oil and gas activities, we have a choice between two acceptable accounting policies: the full cost and the successful effort methods of accounting.
The Fund follows the full cost method of accounting for oil and natural gas activities. Using the full cost method of accounting, all costs of acquiring, exploring and developing oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with acquisitions and development. Under the successful efforts method of accounting, all exploration costs, except costs associated with drilling successful exploration wells, are expensed in the period in which they are incurred. The difference between these two methodologies is not expected to be significant to the Fund’s net income or net income per unit as the majority of the Fund’s drilling activity is in low risk development drilling that has traditionally achieved high success rates.
Under the full cost method of accounting, an impairment test is applied to the overall carrying value of property, plant and equipment, on a country by country cost centre basis with the reserves valued using estimated future commodity prices at period end. Under the successful efforts method of accounting, the costs are aggregated on a property-by-property basis. The carrying value of each property is subject to an impairment test. Each policy may generate a different carrying value of property, plant and equipment and a different net income depending on the circumstances at period end.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates. Due to the timing of when activities occur compared to the reporting of those activities, management must estimate and accrue operating results and capital spending. Changes in these judgments and estimates could have a material impact on our financial results and financial condition.
The process of estimating reserves is critical to several accounting estimates. It requires significant judgments based on available geological, geophysical, engineering and economic data. These estimates may change substantially as data from ongoing development and production activities becomes available, and as economic conditions impacting oil and gas prices, operating costs and royalty burdens change. Reserve estimates impact net income through depletion, the determination of asset retirement obligations and the application of an impairment test. Revisions or changes in the reserve estimates can have either a positive or a negative impact on net income and the asset retirement obligation.
Management calculates the asset retirement obligation based on estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. The fair value estimate is capitalized to PP&E as part of the cost of the related asset and amortized over its useful life.
Management makes various assumptions in determining the fair values of any acquired company’s assets and liabilities in a business combination. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we estimated (a) oil and gas reserves in accordance with our reserve standards, and (b) future prices of oil and gas.
Management’s estimates of oil and natural gas prices are also critical as these prices are used to determine the carrying amount of PP&E, amounts recorded for depletion, impairment in the cost centre, and the change in fair value of financial contracts that do not qualify for hedge accounting.
Management calculates the fair value of rights granted under our trust unit rights incentive plan using a binomial lattice option pricing model. This process involves the use of significant estimates and assumptions, which may change over time. The values calculated under the option pricing model may not reflect the actual value realized by trust unit rights holders.
RECENT CANADIAN ACCOUNTING AND RELATED PRONOUNCEMENTS
Non-Monetary Transactions
In June 2005, the Accounting Standards Board (“AcSB”) issued Section 3831, Non-Monetary Transactions, which replaces Section 3830 and requires all non-monetary transactions to be measured at fair value unless:
• | The transaction lacks commercial substance. |
• | The transaction is an exchange of a product or property held for sale in the ordinary course of business for a product or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange. |
• | Neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable. |
• | The transaction is a non-monetary, non-reciprocal transfer to owners that represent a spin-off or other form of restructuring or liquidation. |
The new requirements apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006. Earlier adoption is permitted beginning on or after July 1, 2005. We do not expect the adoption of this standard will have any material impact on our results of operations or financial position.
Financial Instruments - Recognition and Measurement, Hedges, and Comprehensive Income
The AcSB has issued three sections on financial instruments; Section 1530, Comprehensive Income, Section 3855, Financial Instruments - Recognition and Measurement, and Section 3865, Hedges. These three sections will apply to interim and annual financial statements relating to fiscal years beginning on or after October 1, 2006. They will require the following:
• | all trading financial instruments will be recognized on the balance sheet and will be fair valued through the income statement; |
• | all remaining financial assets will be recorded at cost and amortized through the financial statements; |
• | a new statement for comprehensive income that will include certain gains and losses on translation of assets and liabilities; and |
• | an update to Accounting Guideline 13 to incorporate the fair value changes currently recorded in the income statement to be recorded through the comprehensive income statement. |
We have not assessed the future impact on the financial statements of the Fund at this time.
RISK FACTORS AND RISK MANAGEMENT
Enerplus investors are participating in the net funds flow from a portfolio of crude oil and natural gas producing properties. As such, the funds flow paid to investors and the value of Enerplus units are subject to numerous risk factors. These risk factors, many of which are associated with the oil and gas industry, include, but are not limited to, the following influences:
Commodity Price Risk
Enerplus’ operating results and financial condition are dependent on the prices we receive for our crude oil and natural gas production. These prices may fluctuate widely in response to a variety of factors including global and domestic economic conditions, weather conditions, the supply and price of imported oil and liquefied natural gas, the production and storage levels of North American natural gas, political stability, transportation facilities, the price and availability of alternative fuels and government regulations.
We may use financial derivative instruments and other hedging mechanisms to help limit the adverse effects of natural gas and oil price volatility. However, we do not hedge all of our production and expect there will always be a portion that remains unhedged. Furthermore, we may use financial instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, we may forego the benefits that would otherwise be experienced if commodity prices increase.
Operational Risk and Cost Control
The value of Enerplus trust units is based on the underlying value of the oil and gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and natural gas prices may increase the risk of write-downs of our oil and gas property investments. Regulatory changes to reserve reporting practices can also result in reserve write-downs. As activity levels in the industry increase, upward pressure is placed on administrative and operating costs. Higher costs will decrease the amount of funds flow received by the Fund and therefore, reduce distributions to unitholders.
We strive to acquire low risk, mature properties with a high proportion of proved reserves, positive operating metrics, long reserve lives and predictable production. Similarly, we generally participate in lower-risk development projects, while farming out or monetizing higher risk exploratory prospects.
Each year, independent engineers evaluate a significant portion of our proved and probable reserves.
Sproule Associates Limited (“Sproule”) evaluated 89% of the total proved plus probable value (discounted at 10%) of the Fund’s Canadian conventional year-end reserves, in keeping with NI 51-101 and has reviewed the remainder of the reserves internally evaluated by Enerplus. GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated the Joslyn SAGD bitumen reserves as they have previously performed such evaluations for the operator of the Joslyn project. DeGolyer and MacNaughton (“D&M”) of Dallas, Texas, evaluated the reserves attributed to our assets in the United States. Both GLJ and D&M evaluated 100% of the reserves in their respective areas. Both GLJ and D&M utilized Sproule’s forecast price and cost assumptions as of December 31, 2005 in their evaluations to maintain consistency. The Reserves Committee of the Board of Directors has reviewed and approved the reserve reports of the independent evaluators.
We strive to control costs through incentive-based compensation plans that reward employees for such things as cost control and value-added initiatives. We attempt to minimize costs by exploiting our purchasing strength with suppliers. We use detailed budgeting and accounting practices to monitor costs. Multi-functional teams regularly perform integrated field reviews designed to reduce costs and increase revenues from our properties.
Despite these efforts, it can be difficult to control costs in the oil and gas industry, especially in periods of high commodity prices when the demand for goods and services is strong. Oil and gas production involves a significant amount of fixed costs that are difficult to reduce without decreasing production. In addition, approximately 35% of Enerplus’ production is operated by third parties. We have limited ability to influence costs on partner-operated properties.
Production Replacement Risk
Oil and natural gas reserves naturally deplete as they are produced over time. Our ability to replace production depends on our success in acquiring new reserves and developing existing reserves. Acquisitions of oil and gas assets depend on Enerplus’ assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the trust units.
Acquisitions are subject to investment guidelines, due diligence and review. Major acquisitions are approved by the Board of Directors and where appropriate, independent reservoir engineer evaluations are obtained.
Non-Resident Ownership and Mutual Fund Trust Status
Since our listing on the New York Stock Exchange in November of 2000, we have seen increased trading volumes and levels of ownership by non-residents of Canada. Based on information received from our transfer agent and financial intermediaries in February 2006, an estimated 73% of our outstanding trust units are held by non-residents. However, this estimate may not be accurate as it is based on certain assumptions and data from the security industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.
Enerplus currently meets the requirements of a Mutual Fund Trust as defined in the Income Tax Act (Canada). Our trust indenture does not have a specific limit on the percentage of trust units that may be owned by non-residents.
At this time, management does not anticipate any legislative changes that would affect our status as a mutual fund trust, however, we have implemented provisions in our trust indenture to allow the Board of Directors to adopt non-resident ownership constraints if required in order to ensure Enerplus maintains its mutual fund trust status.
Regulatory Risk
Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and operational impact on Enerplus. Our U.S. operations expose us to possible regulatory changes by the U.S. government. As an oil and gas producer, we are subject to a broad range of regulatory requirements. Similarly, as a mutual fund trust, Enerplus has a unique structure that is vulnerable to changes in legislation or income tax law.
In 2004, the Canadian government announced that it was studying the taxation of trusts. Included in this review were issues such as imposing restrictions on non-resident ownership and imposing taxation at the trust level. After a consultative process, the government announced in November 2005 that it would not make changes to the tax regulations. In the January 2006 election, the Canadian Liberal government was replaced by a Conservative government. Both parties are on record as stating that they do not intend to change the tax treatment of trusts. Nevertheless, there is always a risk that the Canadian government may reconsider its position and propose changes to the tax regime that could negatively impact the Fund.
Access to Capital Markets
Since Enerplus distributes the majority of net funds flow to unitholders, we must finance a large portion of our acquisition and development activity with equity and debt capital markets. As such, we are dependent on continued access to the capital markets to fund our activities directed towards maintaining and increasing value for
our unitholders.
Enerplus has listings on the Toronto and New York stock exchanges and maintains an active investor
relations program.
We maintain a prudent capital structure by retaining a portion of funds flow for capital spending and utilizing the equity markets when deemed appropriate.
Continued access to capital is dependant on our ability to maintain our track record of performance and to demonstrate the advantages of the acquisition or development program that we are financing at the time.
Environmental, Health and Safety Risk (“EHS”)
Environmental and safety risks influence the workforce, operating costs and the establishment of
regulatory standards.
We have established an EHS Management System designed to:
• | provide staff with the training and resources needed to complete work safely and effectively; |
• | incorporate hazard assessment and risk management as an integral part of everyday business; |
• | monitor performance to ensure that Enerplus operations comply with legal obligations and the standards we set for ourselves; and |
• | identify and manage environmental liabilities associated with our existing asset base and potential acquisitions. |
We have a site inspections program and a corrosion risk management program designed to ensure compliance with environmental laws and regulations. Enerplus carries insurance to cover a portion of our property losses, liability and business interruption. EHS risks are reviewed regularly by a committee of the Board of Directors.
Interest Rate Exposure
The Fund has exposure to movements in interest rates. Changing interest rates can affect borrowing costs and the trust unit price of yield-based investments such as Enerplus.
We monitor the interest rate forward market and have fixed the interest rate on approximately 21% of our debt through our senior unsecured notes and interest rate swaps.
Foreign Currency Exposure
Enerplus has exposure to fluctuations in foreign currency as a result of the issuance of senior unsecured notes denominated in U.S. dollars.
Enerplus also has indirect exposure to fluctuations in foreign currency as crude oil sales and a portion of natural gas sales are based on U.S. dollar indices. Our oil and gas revenues are negatively impacted as the Canadian dollar strengthens relative to the U.S. dollar. Enerplus now has operations in the United States with direct exposure to fluctuations in the U.S. dollar on translation to our Canadian dollar denominated financial statements.
We have hedged our foreign currency exposure on US$175 million of senior unsecured notes using financial swaps that convert the U.S. denominated debt to Canadian dollar debt with Canadian dollar interest obligations. We have not hedged our foreign exchange exposure with respect to the US$54 million of senior unsecured notes issued in October 2003 which have U.S. dollar interest payment obligations.
We have not entered into any foreign currency derivatives with respect to oil and gas sales or our U.S. operations.
Counterparty Risk
We assume customer credit risk associated with oil and gas sales, financial hedging transactions and joint
venture participants.
We have established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and gas sales, financial hedging transactions and joint venture participants. Enerplus maintains a diversified sales customer base and we review our single-entity exposure on a regular basis.
Unitholder Liability
In the past, there has been some concern that trust unitholders might be held personally liable for the indebtedness of the Fund.
Enerplus is registered in Alberta, which passed legislation in June 2004 to provide statutory protection for unitholders similar to the protection afforded shareholders in a corporation. Two other provinces (Ontario and Quebec) also have statutory protection for unitholders. Our bank credit agreement and our debenture agreements do not allow the creditors to extend recourse to unitholders beyond the unitholders’ equity investment in the Fund.
SUMMARY 2006 OUTLOOK
Enerplus offers investors the benefits of owning a large, diversified portfolio of producing oil and natural gas properties within Canada and the United States. As such, our business prospects are closely linked to the opportunities and challenges associated with oil and natural gas production. In particular, we are strongly influenced by the price of crude oil and natural gas, both of which have been volatile in recent years. Our comments with respect to our 2006 outlook should be taken within the context of the current commodity price environment.
The following summarizes Enerplus’ 2006 guidance as provided throughout this MD&A. We do not attempt to forecast commodity prices, and as a result, we do not forecast future cash distributions to unitholders. Readers are encouraged to apply their own price expectations to the following factors to arrive at an expected cash distribution.
Summary of 2006 Expectations | Target | Comments |
Average Annual Production | 84,000 BOE/day | Assumes no new acquisitions or dispositions |
Exit rate December 2006 production | 89,000 BOE/day | Assumes $485 million development capital spending |
2006 production mix | 53% gas, 43% oil, 4% NGL | |
Average royalty rate | 19% | Percentage of gross unhedged sales |
Operating Expenses | $7.95/BOE | |
G&A costs | $1.70/BOE | Includes non-cash charges of $0.15BOE (unit rights plan) |
Capital taxes | $6.5 million | Based on current capital structure |
U.S. income and withholding tax - cash costs | 20% | Applied to net funds flow generated by U.S. operations |
Average interest cost | 4.5% | Based on current fixed rates and forward market |
Payout ratio | 60% -90% | |
Development capital spending | $485 million | Based on current plans and price environment |
We have made progress towards sustainability by reducing our reliance on acquisitions to supplement production declines and focusing our efforts on development capital opportunities within our existing assets. This progress is supported by our ability to maintain reserves and production per debt-adjusted trust unit. We expect to be able to increase our production in 2006 through internally generated development efforts without relying on new acquisitions. We anticipate that our average 2006 annual production will be 5% higher than 2005, and our 2006 exit rate will be 5% higher than our 2005 exit rate. Furthermore, we expect to increase our reserves during 2006 by replacing production with new reserve additions from our development program.
Our 2006 development capital spending is expected to be $485 million, which is 32% higher than our 2005 spending, reflecting a robust opportunity set and continued cost escalation in the sector. We plan to continue to withhold a portion of our funds flow to finance this capital program and we expect the payout ratio to trend towards the lower end of our 60-90% guidance range. We believe it is important to maintain a conservative balance sheet as a defense for commodity price volatility.
We will continue to focus on low-risk development opportunities and review our risk management strategies in response to increasing prices and the economics of our acquisitions and development projects. We do not anticipate entering into any commodity hedging transactions in the first half of 2006. However, this strategy may change in the future as management is constantly comparing the value of hedging with our overall requirement for price protection.
For 2006, we estimate that 95% of cash distributions will be taxable and 5% will be a tax-deferred return of capital for both our Canadian and U.S. unitholders.
We are encouraged by the results from our recent acquisitions and our efforts to integrate these operations with our existing staff and systems. The establishment of an office in Denver will enhance our growing presence in the U.S. oil and gas market.
DISCLOSURE CONTROLS AND PROCEDURES
The Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Fund’s disclosure controls and procedures as of December 31, 2005 and concluded that the Fund’s disclosure controls and procedures were effective.
ADDITIONAL INFORMATION
Additional information relating to Enerplus Resources Fund, including the Fund’s Annual Information Form, is available under the Fund’s profile on the SEDAR website at www.sedar.com and at www.enerplus.com.
FORWARD-LOOKING STATEMENTS
This discussion and analysis contains certain forward-looking statements and forward-looking information which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "plan", "should", "believe" and similar expressions are intended to identify forward-looking statements and forward-looking information. These statements are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements or information. Enerplus believes the expectations reflected in those forward-looking statements and information are reasonable but no assurance can be given that these expectations will prove to be correct, and such forward-looking statements and information included in this discussion and analysis should not be unduly relied upon. Such forward-looking statements and information speak only as of the date of this discussion and analysis and Enerplus does not undertake any obligation to publicly update or revise any forward-looking statements or information, except as required by applicable laws.
CONSOLIDATED BALANCE SHEETS
As at December 31 (CDN$ thousands) | 2005 | 2004 | |||||
Assets | |||||||
Current assets | |||||||
Cash | $ | 10,093 | $ | - | |||
Accounts receivable | 170,623 | 107,996 | |||||
Deferred financial assets (Note 3) | 49,874 | - | |||||
Other current | 26,751 | 9,602 | |||||
257,341 | 117,598 | ||||||
Property, plant and equipment (Note 5) | 3,650,327 | 3,029,007 | |||||
Goodwill (Note 7) | 221,234 | 29,082 | |||||
Deferred charges (Note 8) | 1,721 | 5,061 | |||||
$ | 4,130,623 | $ | 3,180,748 | ||||
Liabilities | |||||||
Current liabilities | |||||||
Accounts payable | $ | 316,875 | $ | 179,568 | |||
Distributions payable to unitholders | 49,367 | 36,443 | |||||
Deferred credits (Note 3) | 57,368 | 42,303 | |||||
423,610 | 258,314 | ||||||
Long-term debt (Note 8) | 659,918 | 584,991 | |||||
Future income taxes (Note 11) | 442,970 | 235,551 | |||||
Asset retirement obligations (Note 4) | 110,606 | 105,978 | |||||
1,213,494 | 926,520 | ||||||
Equity | |||||||
Unitholders’ capital (Note 10) | 3,410,614 | 2,831,277 | |||||
Accumulated income | 1,408,178 | 976,137 | |||||
Accumulated cash distributions | (2,309,705 | ) | (1,811,500 | ) | |||
Cumulative translation adjustment (Note 1(j)) | (15,568 | ) | - | ||||
2,493,519 | 1,995,914 | ||||||
$ | 4,130,623 | $ | 3,180,748 |
CONSOLIDATED STATEMENTS OF INCOME
For the year ended December 31 (CDN$ thousands except per trust unit amounts) | 2005 | 2004 | |||||
Revenues | |||||||
Oil and gas sales | $ | 1,550,569 | $ | 1,149,765 | |||
Royalties | (296,983 | ) | (230,954 | ) | |||
Derivative instruments (Notes 3 and 12) | |||||||
Financial contracts - qualified hedges | (27,256 | ) | (18,167 | ) | |||
Other financial contracts | (82,664 | ) | (117,213 | ) | |||
Interest and other income | 11,064 | 2,095 | |||||
1,154,730 | 785,526 | ||||||
Expenses | |||||||
Operating | 216,808 | 196,451 | |||||
General and administrative (Note 10(b)) | 40,375 | 33,863 | |||||
Transportation | 26,915 | 25,119 | |||||
Interest on long-term debt (Note 8) | 25,791 | 20,737 | |||||
Foreign exchange loss/(gain) (Note 9) | 1,677 | (5,018 | ) | ||||
Depletion, depreciation, amortization and accretion | 386,545 | 326,269 | |||||
698,111 | 597,421 | ||||||
Income before taxes | 456,619 | 188,105 | |||||
Capital taxes | 6,486 | 6,612 | |||||
Current taxes | 2,764 | - | |||||
Future income tax expense/(recovery) (Note 11) | 15,328 | (76,823 | ) | ||||
Net Income | $ | 432,041 | $ | 258,316 | |||
Net income per trust unit | |||||||
Basic | $ | 3.96 | $ | 2.60 | |||
Diluted | $ | 3.95 | $ | 2.60 | |||
Weighted average number of trust units outstanding (thousands) | |||||||
Basic | 109,083 | 99,273 | |||||
Diluted | 109,371 | 99,416 |
CONSOLIDATED STATEMENTS OF ACCUMULATED INCOME
For the year ended December 31 (CDN$ thousands) | 2005 | 2004 | |||||
Accumulated income, beginning of year | $ | 976,137 | $ | 717,821 | |||
Net income | 432,041 | 258,316 | |||||
Accumulated income, end of year | $ | 1,408,178 | $ | 976,137 |
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the year ended December 31 (CDN$ thousands) | 2005 | 2004 | |||||
Operating Activities | |||||||
Net income | $432,041 | $258,316 | |||||
Non-cash items add/(deduct): | |||||||
Depletion, depreciation, amortization and accretion | 386,545 | 326,269 | |||||
Non-cash financial contracts | (32,679 | ) | 39,160 | ||||
Non-cash foreign exchange gain (Note 9) | (2,036 | ) | (4,795 | ) | |||
Unit based compensation (Notes 2 and 10) | 3,040 | 4,668 | |||||
Future income tax expense / (recovery) (Note 11) | 15,328 | (76,823 | ) | ||||
Asset retirement costs settled (Note 4) | (7,829 | ) | (6,826 | ) | |||
794,410 | 539,969 | ||||||
Decrease / (Increase) in non-cash working capital | (19,777 | ) | 15,091 | ||||
774,633 | 555,060 | ||||||
Financing Activities | |||||||
Issue of trust units, net of issue costs (Note 10) | 507,209 | 314,309 | |||||
Cash distributions to unitholders | (498,205 | ) | (423,311 | ) | |||
Increase in bank credit facilities (Note 8) | 76,963 | 251,669 | |||||
Decrease in non-cash financing working capital | 12,924 | 3,421 | |||||
98,891 | 146,088 | ||||||
Investing Activities | |||||||
Capital expenditures | (373,032 | ) | (209,052 | ) | |||
Property acquisitions (Note 6) | (123,896 | ) | (504,857 | ) | |||
Property dispositions | 66,511 | 31,742 | |||||
Corporate acquisitions, net of cash acquired (Note 7) | (483,014 | ) | (121,171 | ) | |||
Decrease in non-cash investing working capital | 51,045 | 21,774 | |||||
(862,386 | ) | (781,564 | ) | ||||
Effect of exchange rate changes on cash | (1,045 | ) | - | ||||
Change in cash | 10,093 | (80,416 | ) | ||||
Cash, beginning of year | - | 80,416 | |||||
Cash, end of year | $ | 10,093 | $ | - | |||
SUPPLEMENTARY CASH FLOW INFORMATION | |||||||
Cash income taxes paid | $ | 2,669 | $ | - | |||
Cash interest paid | $ | 24,220 | $ | 19,196 |
CONSOLIDATED STATEMENTS OF ACCUMULATED CASH DISTRIBUTIONS
For the year ended December 31 (CDN$ thousands) | 2005 | 2004 | |||||
Accumulated cash distributions, beginning of year | $ | 1,811,500 | $ | 1,388,189 | |||
Cash distributions | 498,205 | 423,311 | |||||
Accumulated cash distributions, end of year | $ | 2,309,705 | $ | 1,811,500 |
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The management of Enerplus Resources Fund (“Enerplus” or the “Fund”) prepares the financial statements in accordance with Canadian generally accepted accounting principles (“GAAP”). A reconciliation between Canadian GAAP and United States of America GAAP is disclosed in Note 15. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The following significant accounting policies are presented to assist the reader in evaluating these consolidated financial statements and, together with the following notes, should be considered an integral part of the consolidated financial statements.
(a) Organization and Basis of Accounting
The Fund is an open-end investment trust created under the laws of the Province of Alberta operating pursuant to the Amended and Restated Trust Indenture between EnerMark Inc., its wholly-owned subsidiary, Enerplus Resources Corporation (“ERC”) and CIBC Mellon Trust Company as Trustee. The beneficiaries of the Fund (the “unitholders”) are holders of the trust units issued by the Fund. As a trust under the Income Tax Act (Canada), Enerplus is limited to holding and administering permitted investments and making distributions to the unitholders.
The Fund’s financial statements include the accounts of the Fund and its subsidiaries on a consolidated basis. All inter-entity transactions have been eliminated.
(b) Revenue Recognition
Revenue associated with the sale of crude oil, natural gas and natural gas liquids is recognized when title passes from the Fund to its customers based on volumes delivered and contractual delivery points and price. A portion of the properties acquired through the March 5, 2003 acquisition of PCC Energy Inc. and PCC Energy Corp. are subject to a royalty arrangement with a private company that is structured as a net profits interest. The results from operations included in the Fund's consolidated financial statements for these properties are reduced for this net profits interest.
(c) Property, Plant and Equipment (“PP&E”)
The Fund follows the full cost method of accounting for petroleum and natural gas properties under which all acquisition and development costs are capitalized on a country by country cost centre basis. Such costs include land acquisition, geological, geophysical and drilling costs for productive and non-productive wells and directly related overhead charges. Repairs, maintenance and operational costs that do not extend or enhance the recoverable reserves are charged to earnings. Proceeds from the sale of petroleum and natural gas properties are applied against the capitalized costs. Gains and losses are not recognized upon disposition of oil and natural gas properties unless such a disposition would alter the rate of depletion by 20% or more. Net costs related to operating and administrative activities during the development of large capital projects are capitalized until commercial production has commenced.
(d) Impairment Test
A limit is placed on the aggregate carrying value of PP&E (the “impairment test”). The Fund performs an impairment test on a country by country basis. An impairment loss exists when the carrying amount of the country’s PP&E exceeds the estimated undiscounted future net cash flows associated with the country’s proved reserves. If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the country’s proved and probable reserves are charged to income. Reserves are determined pursuant to National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities”.
(e) Depletion and Depreciation
The provision for depletion and depreciation of oil and natural gas assets is calculated on a country by country basis using the unit-of-production method, based on the country’s share of estimated proved reserves before royalties. Reserves and production are converted to equivalent units on the basis of 6 Mcf = 1 bbl, reflecting the approximate relative energy content.
(f) Goodwill
The Fund, when appropriate, recognizes goodwill relating to corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired companies. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment. To assess impairment, the fair values of the Canadian and U.S. reporting units are compared to their respective book values. If the fair value is less than the book value, a second test is performed to determine the amount of impairment. The amount of impairment is measured by allocating the fair value of the reporting unit to its identifiable assets and liabilities as if they had been acquired in a business combination for a purchase price equal to their fair value. If goodwill determined in this manner is less than the carrying value of goodwill, an impairment loss is recognized in the period in which it occurs. Goodwill is stated at cost less impairment and is not amortized.
(g) Asset Retirement Obligations
The Fund recognizes as a liability the estimated fair value of the future retirement obligations associated with PP&E. The fair value is capitalized and amortized over the same period as the underlying asset. The Fund estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in all wells and facilities and the estimated timing of the costs to be incurred in future periods. This estimate is evaluated on a periodic basis and any adjustment to the estimate is prospectively applied. As time passes, the change in net present value of the future retirement obligation is expensed through accretion. Retirement obligations settled during the period reduce the future retirement liability. No gains or losses on retirement activities were realized, due to settlements approximating the estimates.
(h) Income Taxes
The Fund is a taxable entity under the Income Tax Act (Canada) and is taxable only on Canadian income that is not distributed or distributable to the Fund’s unitholders. In the Trust structure, payments made between the Canadian operating entities and the Fund, ultimately transfers both income and future income tax liability to the unitholders. The future income tax liability associated with Canadian assets recorded on the balance sheet is recovered over time through these payments. As the Canadian operating entities transfer all of their Canadian taxable income to the Fund, no provision for current Canadian income tax has been made by any Canadian operating entity.
The U.S. operating entity is subject to U.S. income taxes on its taxable income determined under U.S. income tax rules and regulations. Repatriation of funds from U.S. operations will also be subject to applicable withholding taxes as required under U.S. tax law. A provision has been setup to reflect these current U.S. income taxes.
The Fund follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to temporary differences between the amounts reported in the financial statements of the Fund’s corporate subsidiaries and their respective tax bases, using substantively enacted income tax rates. The effect of a change in these income tax rates on future income tax liabilities and assets is recognized in income during the period that the change occurs.
(i) Financial Instruments
The Fund is exposed to market risks resulting from fluctuations in commodity prices and interest rates in the normal course of operations. The Fund uses various types of financial instruments to manage these market risks. Prior to December 31, 2005, the Fund designated certain commodity contracts and interest rate swaps as qualified hedges. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges. The fair value of the former commodity hedges has been recorded as a financial liability with an offset to deferred financial assets. The deferred financial asset will be amortized over the remaining lives of the associated financial contracts. The fair value of the financial liability will be determined at each period end with any resulting change in fair value being taken into income in that period.
The gain or loss in fair value of all financial contracts that had not previously qualified for hedge accounting are taken into income during the period of change and charged to deferred credits or deferred charges on the balance sheet.
Proceeds or costs realized from holding interest rate swaps are recognized at the time each transaction under a contract is settled and is recorded in interest expense. The Fund has designated the interest rate swaps as qualified hedges and these swaps are evaluated quarterly to ensure they effectively hedge the underlying interest rate.
(j) Foreign Currency Translation
The Fund’s U.S. operations are self-sustaining. Assets and liabilities of these operations are translated into Canadian dollars at period end exchange rates, while revenues and expenses are converted using average rates for the period. Gains and losses from the translation into Canadian dollars are deferred and included in the foreign currency translation adjustment as part of unitholders’ equity.
Other monetary assets and liabilities, not related to the Fund’s U.S. operations, are translated into Canadian dollars at rates of exchange in effect at the balance sheet date. The other assets and related depreciation, depletion and amortization, other liabilities, revenue and other expenses are translated into Canadian dollars at rates of exchange in effect at the respective transaction dates. The resulting exchange gains or losses are included in earnings.
2. CHANGES IN ACCOUNTING POLICIES
Unit Based Compensation
Generally accepted accounting principles require the Fund to estimate the fair value of unit options issued under its unit based compensation programs and recognize this amount as compensation expense in the income statement over the respective vesting period with a credit to contributed surplus. Prior to October 1, 2005, the Fund measured unit based compensation based on the intrinsic value of the rights and recognized the amount in income over the vesting period. After the rights vested, changes in the intrinsic value were recognized in income in the period of change. The intrinsic value was determined as the excess of the trust unit price over the exercise price of the right at the date of exercise, or the date of the financial statements for the unexercised rights. The change in value was reflected in general and administrative expenses (“G&A”) and contributed surplus. Cash received upon exercise of the rights and the related amount of contributed surplus was credited to unitholders’ capital.
On October 1, 2005 the Fund retroactively adopted the fair value method of accounting for the trust unit rights incentive plan to January 1, 2003. Under this method, the fair value of the rights is determined on the date in which fair value can reasonably be determined, generally being the grant date. This amount is charged to earnings over the vesting period of the rights, with a corresponding increase in contributed surplus. When rights are exercised, the proceeds, together with the amount recorded in contributed surplus, are recorded to unitholders’ capital. The impact of the adoption on our 2003 and 2004 reported earnings was not material and therefore prior period financial statements have not been restated.
For the year ended December 31, 2005, the fair value methodology resulted in a compensation expense of $3,040,000 compared to an $18,688,000 compensation expense calculated under the intrinsic methodology.
3. DEFERRED FINANCIAL ASSETS AND DEFERRED CREDITS
Current Deferred Financial Assets ($ thousands) | ||||
Deferred financial asset as at December 31, 2004 | $ | - | ||
Deferred financial asset recorded upon termination of hedging relationships (1) | 49,874 | |||
Deferred financial asset as at December 31, 2005 | $ | 49,874 |
(1) Represents the fair value of financial contracts on December 31, 2005 for which hedge accounting is no longer applied. This deferred financial asset will be amortized over the remaining lives of the associated financial contracts.
Current Deferred Credits ($ thousands) | ||||
Deferred credits as at December 31, 2004 | $ | 42,303 | ||
Financial contract assumed through Lyco acquisition | 1,014 | |||
Financial liability recorded upon termination of hedging relationships(1) | 49,874 | |||
Change in fair value - other financial contracts(2) | (35,823 | ) | ||
Deferred credits as at December 31, 2005 | $ | 57,368 |
(1) Represents the fair value of financial contracts on December 31, 2005 for which hedge accounting is no longer applied.
(2) Changes in the fair value of financial contracts that do not qualify for hedge accounting are taken into income during the period as other financial contracts and reflected as an increase or decrease in the deferred financial liability.
The following table summarizes the income statement effects of other financial contracts:
Other Financial Contracts ($ thousands) | 2005 | 2004 | |||||
Change in fair value | $ | (35,823 | ) | $ | 21,288 | ||
Amortization of deferred financial assets | 3,144 | 17,872 | |||||
Realized cash costs, net | 115,343 | 78,053 | |||||
Other financial contracts | $ | 82,664 | $ | 117,213 |
During the year ended December 31, 2005, the Fund realized cash costs of $27,256,000 (net gains and losses) from financial contracts that qualified as hedges compared to cash costs of $18,167,000 during 2004.
4. ASSET RETIREMENT OBLIGATIONS
Total future asset retirement obligations were estimated by management based on the Fund’s net ownership interest in wells and facilities, estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Fund has estimated the net present value of its total asset retirement obligations to be $110,606,000 at December 31, 2005 compared to $105,978,000 at December 31, 2004 based on a total liability of $422,045,000 and $383,942,000 respectively. These payments are expected to be made over the next 66 years with the majority of costs incurred between 2026 and 2035. To calculate the present value of the asset retirement obligations for 2005 the Fund used a weighted credit-adjusted rate of approximately 6.3% (2004 - 6.5%) and an inflation rate of 2.0% for both years. Settlements during the year approximated our estimates and as a result, no gains or losses were recognized.
Following is a reconciliation of the asset retirement obligations:
($ thousands) | 2005 | 2004 | |||||
Asset retirement obligations, beginning of year | $ | 105,978 | $ | 63,936 | |||
Changes in estimates | 8,764 | 23,100 | |||||
Acquisition and development activity | 6,791 | 23,723 | |||||
Dispositions | (9,413 | ) | (3,000 | ) | |||
Retirement obligations settled | (7,829 | ) | (6,826 | ) | |||
Accretion expense | 6,315 | 5,045 | |||||
Asset retirement obligations, end of year | $ | 110,606 | $ | 105,978 |
5. PROPERTY, PLANT AND EQUIPMENT
($ thousands) | 2005 | 2004 | |||||
Property, plant and equipment | $ | 5,306,137 | $ | 4,305,584 | |||
Accumulated depletion, depreciation and accretion | (1,655,810 | ) | (1,276,577 | ) | |||
Net property, plant and equipment | $ | 3,650,327 | $ | 3,029,007 |
Capitalized development G&A of $11,571,000 (2004 - $8,451,000) is included in PP&E and the depletion and depreciation calculation includes future capital costs of $464,423,000 (2004 - $279,700,000) included in our reserve reports. Excluded from PP&E for the depletion and depreciation calculation is $61,795,000 (2004 - $28,574,000) related to the Joslyn development project that has not commenced commercial production.
An impairment test calculation was performed on a country by country basis on the PP&E values at December 31, 2005 in which the estimated undiscounted future net cash flows associated with the proved reserves exceeded the carrying amount of the Fund’s PP&E.
The following table outlines benchmark prices and the exchange rate used in the impairment tests for both Canadian and U.S. cost centres at December 31, 2005:
Year | WTI Crude Oil (1) US$/bbl | Exchange Rate US$/CDN$ | Edm Light Crude(1) CDN$/bbl | Natural Gas 30 day spot @ AECO (1) CDN$/Mcf | |||||||||
2006 | $ | 60.81 | $ | 0.85 | $ | 70.07 | $ | 11.58 | |||||
2007 | 61.61 | 0.85 | 70.99 | 10.84 | |||||||||
2008 | 54.60 | 0.85 | 62.73 | 8.95 | |||||||||
2009 | 50.19 | 0.85 | 57.53 | 7.87 | |||||||||
2010 | 47.76 | 0.85 | 54.65 | 7.57 | |||||||||
Thereafter | + 1.5 | % | 0.85 | + 1.5 | % | * |
(1) Actual prices used in the impairment test were adjusted for commodity price differentials specific to the Fund
* Escalation varies after 2010
6. PROPERTY ACQUISITIONS
Assets of Sleeping Giant LLC (“Sleeping Giant”)
On October 4, 2005 the Fund acquired all ownership interests and retired the debt of Sleeping Giant, a private U.S. company holding additional working interests in certain properties of Lyco Energy Corporation for total cash consideration of $111,914,000 which was financed through existing credit facilities. The fair value of this consideration was allocated to cash and positive working capital assumed of $5,754,000 and PP&E of $106,160,000. This acquisition has been accounted for as an asset acquisition. The operating results of Sleeping Giant subsequent to October 4, 2005 are included in the Fund’s consolidated financial statements.
Assets of ChevronTexaco Corporation (“ChevronTexaco”)
On June 30, 2004 the Fund acquired certain oil and natural gas properties from ChevronTexaco. Total consideration was $467,199,000 financed concurrently by subscription receipts issued on June 15, 2004 and available lines of credit. Results from operations have been included in Enerplus’ financial results from June 30, 2004 forward.
7. CORPORATE ACQUISITIONS
The allocation to the fair value of the assets acquired and liabilities assumed plus the future income tax cost are summarized as follows:
($ thousands) | 2005 Lyco | 2005 TriLoch | 2004 Ice Energy | |||||||
Property, plant and equipment | $ | 506,379 | $ | 77,786 | $ | 130,544 | ||||
Goodwill (with no tax base) | 179,019 | 18,450 | 29,082 | |||||||
Future income taxes | (179,019 | ) | (18,450 | ) | (29,082 | ) | ||||
506,379 | 77,786 | 130,544 | ||||||||
Cash | 27,231 | - | - | |||||||
Non-cash working capital deficiency | (31,664 | ) | (399 | ) | (9,373 | ) | ||||
Net assets acquired | $ | 501,946 | $ | 77,387 | $ | 121,171 |
Goodwill is comprised of the following:
($ thousands) | ||||
Goodwill as at December 31, 2004 | $ | 29,082 | ||
Lyco acquisition | 179,019 | |||
TriLoch acquisition | 18,450 | |||
Foreign exchange (1) | (5,317 | ) | ||
Goodwill as at December 31, 2005 | $ | 221,234 |
(1) The foreign exchange results from the translation of the Lyco goodwill at the period end rate.
Lyco Energy Corporation (“Lyco”)
On August 30, 2005 the Fund acquired all the outstanding common shares and retired the debt including all outstanding mandatorily redeemable preferred shares of Lyco, a private U.S. company operating in the states of Montana and North Dakota. Total consideration was approximately $501,946,000, and the Fund assumed a net working capital deficiency of $4,433,000. Goodwill of $179,019,000 was recorded based on the excess of the consideration paid over the value assigned to the identifiable assets and liabilities including the future income tax liability. The acquisition, which was financed through an equity offering and available credit facilities, has been accounted for using the purchase method of accounting for business combinations. Results from the operations of Lyco subsequent to August 30, 2005 are included in the Fund’s consolidated financial statements.
TriLoch Resources Inc. (“TriLoch”)
On July 1, 2005 the Fund acquired all the outstanding common shares of TriLoch, a public Alberta corporation operating in southern Alberta, in exchange for 1,632,516 trust units of the Fund with a recorded value of $69,088,000. The trust unit value was based on the weighted average price of the Fund’s trust units on the Toronto Stock Exchange during the five day trading period surrounding the announcement of the TriLoch transaction. Total consideration was $77,387,000 consisting of units, deal costs and the retirement of TriLoch’s bank indebtedness. The Fund also assumed a working capital deficiency of $399,000. Goodwill of $18,450,000 has been recorded as a result of the excess of the consideration paid over the value allocated to the identifiable assets and liabilities including the future income tax liability. This acquisition has been accounted for using the purchase method of accounting for business combinations. Results from the operations of TriLoch subsequent to July 1, 2005 are included in the Fund’s consolidated financial statements.
Ice Energy Limited (“Ice Energy”)
On January 7, 2004 the Fund acquired all of the outstanding common shares of Ice Energy for total consideration of $121,171,000. The excess of the consideration paid over the fair value of the identifiable assets and liabilities resulted in the recording of $29,082,000 of goodwill. Available lines of credit financed the acquisition, which has been accounted for using the purchase method of accounting for business combinations. Results from operations of Ice Energy subsequent to January 7, 2004 are included in the Fund’s consolidated financial statements.
8. LONG-TERM DEBT
($ thousands) | 2005 | 2004 | |||||
Bank credit facilities (a) | $ | 328,632 | $ | 251,669 | |||
Senior notes (b) | |||||||
US $175 million (issued June 19, 2002) | 268,328 | 268,328 | |||||
US $54 million (issued October 1, 2003) | 62,958 | 64,994 | |||||
Total long-term debt | $ | 659,918 | $ | 584,991 |
(a) Unsecured Bank Credit Facilities
In November 2004 the Fund negotiated an $850,000,000 unsecured covenant based three year term facility. Enerplus has the ability to extend the facility each year or repay the entire balance at the end of the three year term. During 2005, the facility was extended until November 2008. At December 31, 2005, Enerplus had available credit of $521,368,000 under this facility. The facility is extendible each year with a bullet payment required at the end of the three year term. Various borrowing options are available under the facility including prime rate based advances and banker’s acceptance loans. This facility carries floating interest rates that are expected to range between 60.0 and 115.0 basis points over Bankers Acceptance rates, depending on Enerplus’ ratio of senior debt to earnings before interest, taxes and non-cash items. The effective interest rate on the facilities for the year ended December 31, 2005 was 3.4% (2004 - 3.1%).
(b) | Senior Unsecured Notes |
On October 1, 2003 Enerplus issued US$54,000,000 senior unsecured notes that mature October 1, 2015. The notes have a coupon rate of 5.46% priced at par with interest paid semi-annually on April 1 and October 1 of each year. Principal payments are required in five equal installments beginning October 1, 2011 and ending October 1, 2015. Costs incurred in connection with issuing the notes in the amount of $475,000 are classified as deferred charges on the balance sheet and are being amortized as a part of depletion, depreciation, amortization and accretion (“DDA&A”) over the term of the notes. At December 31, 2005, the amount remaining to be amortized associated with these costs was $386,000 (2004 - $425,000). The notes are subject to fluctuations in foreign exchange rates.
On June 19, 2002 Enerplus issued US$175,000,000 senior unsecured notes that mature June 19, 2014. The notes have a coupon rate of 6.62% priced at par, with interest paid semi-annually on June 19 and December 19 of each year. Principal payments are required in five equal installments beginning June 19, 2010 and ending June 19, 2014. Costs incurred in connection with issuing the notes in the amount of $1,892,000 are classified as deferred charges on the balance sheet and are being amortized to DDA&A over the term of the notes. At December 31, 2005, the amount remaining to be amortized was $1,335,000 (2004 - $1,492,000). Concurrent with the issuance of the notes on June 19, 2002, the Fund entered into a cross currency swap with a syndicate of financial institutions. Under the terms of the swap, the amount of
the notes was fixed for purposes of interest and principal repayments at a notional amount of CDN$268,328,000. Interest payments are made on a floating rate basis, set at the rate for three-month Canadian banker’s acceptances, plus 1.18%.
The bank credit facilities and the senior notes (the “Combined Facilities”) are the legal obligation of EnerMark Inc. and are guaranteed by its subsidiaries. Payments with respect to the Combined Facilities have priority over payments to the Fund and over claims of and future distributions to the unitholders. However, unitholders have no direct liability beyond their equity investment should cash flow be insufficient to repay the Combined Facilities.
9. FOREIGN EXCHANGE
($ thousands) | 2005 | 2004 | |||||
Unrealized foreign exchange gain on translation of U.S. dollar denominated senior notes | $ | (2,036 | ) | $ | (4,795 | ) | |
Realized foreign exchange loss/(gain) | 3,713 | (223 | ) | ||||
Foreign exchange loss/(gain) | $ | 1,677 | $ | (5,018 | ) |
The US$54,000,000 senior unsecured notes that are exposed to foreign currency fluctuations are translated into Canadian dollars at the exchange rate in effect at the balance sheet date. Foreign exchange gains and losses are included in the determination of net income for the year.
10. FUND CAPITAL
(a) Unitholders’ Capital
Trust Units
Authorized: Unlimited number of trust units
(thousands) | 2005 | 2004 | |||||||||||
Issued: | Units | Amount | Units | Amount | |||||||||
Balance before Contributed Surplus, beginning of year | 104,124 | $ | 2,826,641 | 94,349 | $ | 2,510,011 | |||||||
Issued for cash: | |||||||||||||
Pursuant to public offerings | 10,638 | 466,885 | 8,800 | 286,248 | |||||||||
Pursuant to rights plans | 805 | 24,737 | 648 | 16,947 | |||||||||
Trust unit rights incentive plan (non- cash) - exercised | - | 2,163 | - | 1,396 | |||||||||
DRIP*, net of redemptions | 339 | 15,613 | 302 | 11,114 | |||||||||
Issued for acquisition of corporate and property interests (non-cash) | 1,633 | 69,062 | 25 | 925 | |||||||||
117,539 | 3,405,101 | 104,124 | 2,826,641 | ||||||||||
Contributed Surplus (Trust Unit Rights Plan) | - | 5,513 | - | 4,636 | |||||||||
Balance, end of year | 117,539 | $ | 3,410,614 | 104,124 | $ | 2,831,277 |
* Distribution Reinvestment and Unit Purchase Plan
Contributed surplus ($ thousands) | 2005 | 2004 | |||||
Balance, beginning of year | $ | 4,636 | $ | 1,364 | |||
Trust unit rights incentive plan (non-cash) - exercised | (2,163 | ) | (1,396 | ) | |||
Trust unit rights incentive plan (non-cash) - expensed | 3,040 | 4,668 | |||||
Balance, end of year | $ | 5,513 | $ | 4,636 |
On August 9, 2005 the Fund completed a Canadian equity offering of 10,637,500 subscription receipts at a price of $46.25 per subscription receipt for gross proceeds of $491,984,000 ($466,885,000 net of issuance costs). The subscription receipts were exchanged for an equal number of trust units on August 30, 2005 upon the closing of the Lyco transaction. The holders of the subscription receipts received the August 2005 cash distribution of $0.37 per trust unit and this amount has been included in cash distributions to unitholders.
On July 1, 2005 the Fund issued 1,632,516 trust units pursuant to the acquisition of TriLoch valued at $42.32 per trust unit, being the weighted average trading price of the Fund’s trust units on the Toronto Stock Exchange during the five day trading period surrounding the announcement of the TriLoch transaction, for a recorded value of $69,088,000 ($69,062,000 net of issuance costs).
On June 15, 2004 Enerplus completed an equity offering of 8,800,000 subscription receipts at a price of $34.30 per subscription receipt for gross proceeds of $301,840,000 ($286,248,000 net of issuance costs). The subscription receipts were exchanged for trust units on June 30, 2004 upon closing of the ChevronTexaco asset acquisition. The holders of the subscription receipts received the June 2004 cash distribution of $0.35 per trust unit and this amount has been included in cash distributions to unitholders.
Pursuant to the monthly Distribution Reinvestment and Unit Purchase Plan (“DRIP”), Canadian unitholders are entitled to reinvest cash distributions in additional trust units of the Fund. Trust units are issued at 95% of the weighted average market price on the Toronto Stock Exchange for the 20 trading days preceding a distribution payment date without service charges or brokerage fees. Eligible unitholders are also entitled to make optional cash payments to acquire additional trust units, however the 5% discount does not apply.
Trust units are redeemable by unitholders at approximately 85% of the current market price. Redemptions are limited to $500,000 during any rolling two calendar months. Redemption requests in excess of $500,000 can be paid using investments of the Fund or a non-interest bearing instrument.
(b) Trust Unit Rights Incentive Plan
As at December 31, 2005 a total of 2,621,000 rights issued pursuant to the Trust Unit Rights Incentive Plan (“Rights Plan”) at an average exercise price of $42.80 were outstanding. This represents 2.2% of the total trust units outstanding of which 643,000 rights with an average exercise price of $32.46 were exercisable. Under the Rights Plan, distributions per trust unit to Enerplus unitholders in a calendar quarter which represent a return of more than 2.5% of the net PP&E of Enerplus at the end of such calendar quarter, may result in a reduction in the exercise price of the rights. Results for the year ended December 31, 2005 reduced the exercise price of the outstanding rights by $1.64 per trust unit of which a $0.41 reduction is effective January 2006 and a $0.48 reduction is effective April 2006. Plan members have the choice to exercise rights using the original exercise price or a reduced strike price, should a reduction take place. In certain circumstances, it may be more advantageous to use the original exercise price as it could effectively lower the plan member’s tax rate on the transaction.
The Fund uses a binomial lattice option-pricing model to calculate the estimated fair value of rights granted under the plan. The following assumptions were used to arrive at the estimate of fair value:
2005 | 2004 | ||||||
Dividend yield | 8.97 | % | 10.45 | % | |||
Right’s exercise price reduction | $ | 1.43 | $ | 1.05 | |||
Volatility | 21.46 | % | 20.77 | % | |||
Risk-free interest rate | 3.70 | % | 3.63 | % | |||
Forfeiture rate | 4.60 | % | 5.80 | % |
The fair value of the rights granted under the plan ranged between 7% and 10% of the underlying market price of a trust unit on the grant date.
During the year the Fund expensed $3,040,000 of unit based compensation expense using the fair value method. The remaining future fair value of the rights of $6,380,000 at December 31, 2005 will be recognized in earnings over the remaining vesting period of the rights.
Activity for the rights issued pursuant to the Rights Plan is as follows:
2005 | 2004 | ||||||||||||
Number of Rights (000’s) | Weighted Average Exercise Price(1) | Number of Rights (000’s) | Weighted Average Exercise Price(1) | ||||||||||
Trust unit rights outstanding | |||||||||||||
Beginning of year | 2,401 | $ | 34.33 | 2,192 | $ | 30.05 | |||||||
Granted | 1,125 | 53.07 | 1,002 | 40.22 | |||||||||
Exercised | (805 | ) | 30.72 | (644 | ) | 26.16 | |||||||
Cancelled | (100 | ) | 37.15 | (149 | ) | 30.94 | |||||||
End of year | 2,621 | 42.80 | 2,401 | 34.33 | |||||||||
Rights exercisable at the end of the year | 643 | $ | 32.46 | 551 | $ | 27.84 |
(1) Exercise price reflects grant prices less reduction in strike price discussed above.
The following table summarizes information with respect to outstanding Unit Rights as at December 31, 2005. Unit rights vest between one and three years and expire between four and six years.
Rights Outstanding at December 31, 2005 (000’s) | Original Exercise Price | Exercise Price after Price Reductions | Expiry Date December 31 | Rights Exercisable at December 31, 2005 (000’s) |
14 | 24.50 | 20.31 | 2007 | 14 |
1 | 26.40 | 22.33 | 2008 | 1 |
2 | 27.33 | 23.33 | 2008 | 2 |
162 | 26.09 | 22.23 | 2008 | 162 |
33 | 27.70 | 24.04 | 2009 | 11 |
47 | 33.00 | 29.65 | 2009 | 26 |
31 | 36.00 | 33.03 | 2009 | 18 |
404 | 37.62 | 35.04 | 2009 | 199 |
33 | 40.70 | 38.51 | 2010 | 7 |
51 | 37.25 | 35.43 | 2010 | - |
88 | 38.83 | 37.41 | 2010 | 8 |
645 | 40.80 | 39.73 | 2010 | 195 |
121 | 45.55 | 44.80 | 2011 | - |
132 | 44.86 | 44.46 | 2011 | - |
169 | 49.75 | 49.75 | 2011 | - |
688 | 56.93 | 56.93 | 2011 | - |
2,621 | 44.03 | 42.80 | 643 |
Non-cash compensation costs of $3,040,000 ($0.03 per unit) related to the rights issued since January 1, 2003 have been charged to G&A expense during 2005 compared to $4,668,000 ($0.05 per unit) during 2004.
The following table outlines the estimated compensation cost associated with the rights issued during 2002 and the pro forma effects on net income and net income per unit, had the Canadian Institute of Chartered Accountants Handbook (“CICA”) section 3870 been applied retroactive to 2002.
($ thousands, except per unit amounts) | 2005 | 2004 | |||||
Net income as reported | $432,041 | $258,316 | |||||
Compensation expense for rights issued in 2002 | (160 | ) | (4,734 | ) | |||
Pro forma net income | $ | 431,881 | $ | 253,582 | |||
Net income per trust unit - basic | |||||||
Reported | $ | 3.96 | $ | 2.60 | |||
Pro forma | $ | 3.96 | $ | 2.55 | |||
Net income per trust unit - diluted | |||||||
Reported | $ | 3.95 | $ | 2.60 | |||
Pro forma | $ | 3.95 | $ | 2.55 |
(c) | Basic and Diluted per Trust Unit Calculations |
Net income per trust unit has been determined based on the following:
2005 | 2004 | ||||||
Weighted average units | 109,083 | 99,273 | |||||
Dilutive impact of rights | 288 | 143 | |||||
Diluted trust units | 109,371 | 99,416 |
In calculating the weighted average number of diluted units outstanding for the year ended December 31, 2005, we excluded 132,511 rights (2004 - 40,929), because their exercise price was greater than the annual average unit market price in those periods. During the last two years, outstanding rights were the only potential dilutive instrument.
11. INCOME TAXES
(a) Enerplus Resources Fund
The Fund is an inter-vivos trust for income tax purposes. As such, the Fund’s income that is not allocated to the Fund’s unitholders is taxable. The Fund intends to allocate all income to unitholders.
For 2005, the Fund had taxable income of $451,000,000 (2004 - $381,000,000) or $4.05 per trust unit (2004 - $3.77 per trust unit). Taxable income of the Fund is comprised of dividend, royalty, interest and partnership income, less deductions for Canadian oil and gas property expense (“COGPE”) and trust unit issue costs.
The amounts of COGPE and issue costs remaining in the Fund at December 31, 2005 are $466,700,000 and $40,109,000 respectively (2004 - $506,985,000 and $32,297,000).
(b) Corporate Subsidiaries
The future income tax liability on the balance sheet arises as a result of the following temporary differences:
($ thousands) | 2005 | 2004 | |||||
Excess of net book value of property, plant and equipment over the underlying tax bases | $ | 485,965 | $ | 285,606 | |||
Asset retirement obligations | (37,976 | ) | (35,945 | ) | |||
Deferred hedging and other | (5,019 | ) | (14,110 | ) | |||
Future income tax liability | $ | 442,970 | $ | 235,551 |
The provision for income taxes varies from the amounts that would be computed by applying the combined Canadian federal and provincial income tax rates for the following reasons:
($ thousands) | 2005 | 2004 | |||||
Income before taxes | $ | 456,619 | $ | 188,105 | |||
Computed income tax expense at the enacted rate of 38.01% (38.86% for 2004) | $ | 173,564 | $ | 73,098 | |||
Increase (decrease) resulting from: | |||||||
Net income attributed to the Fund | (172,463 | ) | (153,686 | ) | |||
Non-deductible crown royalties | 30,652 | 38,647 | |||||
Resource allowance | (37,047 | ) | (35,966 | ) | |||
Amended returns and pool balances | 16,544 | (105 | ) | ||||
Change in tax rate | - | (5,700 | ) | ||||
Tax rate differentials (1) | 628 | - | |||||
Other | 6,214 | 6,889 | |||||
18,092 | (76,823 | ) | |||||
Future income tax expense / (recovery) | 15,328 | (76,823 | ) | ||||
Current tax | 2,764 | - |
(1) The corporate income tax rate in the U.S. is 40.75%.
12. FINANCIAL INSTRUMENTS
The Fund’s financial instruments presented on the balance sheet consist of cash, accounts receivable, deferred financial assets, other current assets, a portion of deferred charges, current liabilities and long-term debt.
The carrying value of cash, accounts receivable, current liabilities and the outstanding bank credit facility balances approximate their fair value. Other current assets are comprised of prepaid expenses and marketable securities. The marketable securities are carried on the balance sheet at the lower of cost and fair value. The fair value of the marketable securities at December 31, 2005 exceeded the cost of these securities by $10,898,000. The Fund carried US$54,000,000 of fixed rate debt. In addition, it carried US$175,000,000 of fixed rate debt that was converted to CDN$268,328,000 floating rate debt through a cross-currency swap with a syndicate of financial institutions. At December 31, 2005 the fair value of the senior unsecured notes was $64,110,000 (for the US$54,000,000 notes) and $212,025,000 (for the US$175,000,000 notes), see Note 8. The balance related to derivative instruments that did not qualify for hedge accounting treatment upon adoption of AcG-13 in 2004, was fully amortized at December 31, 2005. At December 31, 2004, this balance was $3,144,000 and was included in deferred charges.
The estimated fair values have been determined based on available market information and appropriate valuation methods. The actual amounts realized may differ from these estimates.
(a) Credit Risk
Most of the Fund’s accounts receivable relate to oil and natural gas sales and are exposed to typical industry credit risks. The Fund manages this credit risk by entering into sales contracts with only highly rated entities and reviewing its exposure to individual entities on a regular basis. The Fund is also exposed to certain losses in the event of non-performance by counterparties to derivative financial instruments. This credit risk is managed by the Fund by selecting financially sound counterparties.
(b) Interest Rate Risk
The Fund is exposed to movements in interest rates. Long-term debt is comprised of both variable rate bank facilities and fixed rate senior notes. The Fund monitors the interest rate forward market and through the use of interest rate swaps along with the fixed-rate notes has fixed the interest rate on approximately 21% of its debt. See part (d) below.
(c) Currency Risk
The Fund is exposed to fluctuations in foreign currency as a result of its U.S. operations and the issuance of senior unsecured notes denominated in U.S. dollars. Through the use of a financial swap, the exposure on our US$175,000,000 senior unsecured notes has been converted to Canadian dollar debt. As well, the Fund has indirect exposure to fluctuations in foreign currency as crude oil sales and a portion of natural gas sales are based on U.S. dollar indices. We have not entered into any foreign currency derivatives with respect to oil and natural gas sales.
(d) Derivative Financial Instruments
The Fund uses certain derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. The fair values of these instruments are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the instruments outstanding as at December 31, 2005 with reference to forward prices and market valuations provided by third party sources.
The fair values of derivative financial instruments are as follows:
Interest Rate and Cross Currency Swaps
The Fund has entered into interest rate swaps on $75,000,000 of notional debt at rates varying from 3.74% to 4.12% before banking fees that are expected to range between 0.60% and 1.15%. These interest rate swaps mature between June 2006 and January 2007. The fair value of the $75,000,000 interest rate swaps as at December 31, 2005 represents an unrealized cost of $206,000. These swaps have been designated as hedges for accounting purposes.
The fair value of the cross currency swap related to the US$175,000,000 senior unsecured notes as at December 31, 2005 represents an unrealized cost of $62,439,000 where as the fair value of the underlying debt instrument as at December 31, 2005 represents an unrealized gain of $56,303,000. The cross currency swap has been designated as a hedge for accounting purposes.
Crude Oil Instruments
Enerplus has entered into the following financial option contracts to reduce the impact of a downward movement in crude oil prices. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges. The fair value of the financial crude oil contracts that are no longer designated as hedges for accounting purposes results in a liability of $13,321,000 (see Note 3).
The following table summarizes the Fund’s crude oil risk management positions at February 15, 2006:
WTI US$/bbl | |||||||||||||
Daily Volumes bbls/day | Sold Call | Purchased Put | Sold Put | ||||||||||
Term | |||||||||||||
January 1, 2006 - June 30, 2006 | |||||||||||||
3-way option | 1,500 | $ | 45.80 | $ | 31.50 | $ | 27.50 | ||||||
Put * | 1,500 | - | $ | 41.50 | - | ||||||||
Put | 1,500 | - | - | $ | 35.00 | ||||||||
January 1, 2006 - June 30, 2006 | |||||||||||||
Costless Collar * | 1,500 | $ | 35.35 | $ | 30.00 | - | |||||||
Costless Collar * | 1,500 | $ | 37.00 | $ | 30.00 | - | |||||||
January 1, 2006 - December 31, 2006 | |||||||||||||
Put * | 1,500 | - | $ | 50.00 | - | ||||||||
Put | 1,500 | - | - | $ | 41.00 | ||||||||
January 1, 2006 - December 31, 2006 | |||||||||||||
Put * | 1,500 | - | $ | 53.00 | - | ||||||||
Put | 1,500 | - | - | $ | 43.00 | ||||||||
January 1, 2006 - December 31, 2006 | |||||||||||||
Put * | 1,500 | - | $ | 53.00 | - | ||||||||
Put | 1,500 | - | - | $ | 43.00 |
* Financial contracts that were treated as hedges during 2005, however the Fund elected to stop designating these contracts as hedges as of December 31, 2005.
The Fund did not enter into any new contracts in the fourth quarter of 2005.
Natural Gas Instruments
Enerplus has physical and financial contracts in place on its natural gas production as described below. Effective December 31, 2005, the Fund elected to stop designating commodity contracts as qualified hedges. The fair value of the financial natural gas contracts that are no longer designated as hedges for accounting purposes results in a liability of $36,553,000 (see Note 3).
The following table summarizes the Fund’s natural gas risk management positions at February 15, 2006:
AECO CDN$/Mcf | ||||||||||||||||
Daily Volumes MMcf/day | Sold Call | Purchased Put | Sold Put | Fixed Price and Swaps | ||||||||||||
Term | ||||||||||||||||
January 1, 2006 - March 31, 2006 | ||||||||||||||||
3-way option | 9.5 | $ | 9.92 | $ | 7.12 | $ | 5.80 | - | ||||||||
Put * | 9.5 | - | $ | 7.91 | - | - | ||||||||||
Put * | 9.5 | - | $ | 7.91 | - | - | ||||||||||
Put * | 9.5 | - | $ | 7.91 | - | - | ||||||||||
January 1, 2006 - October 31, 2006 | ||||||||||||||||
Swap * | 9.5 | - | - | - | $ | 5.47 | ||||||||||
Swap * | 4.8 | - | - | - | $ | 5.25 | ||||||||||
Swap * | 4.8 | - | - | - | $ | 5.24 | ||||||||||
Swap * | 4.8 | - | - | - | $ | 5.28 | ||||||||||
April 1, 2006 - October 31, 2006 | ||||||||||||||||
Put * | 9.5 | - | $ | 7.38 | - | - | ||||||||||
Put * | 9.5 | - | $ | 7.38 | - | - | ||||||||||
Put * | 9.5 | - | $ | 7.38 | - | - | ||||||||||
2006 - 2010 | ||||||||||||||||
Physical (escalated pricing) | 2.0 | - | - | - | $ | 2.52 |
* Financial contracts that were treated as hedges during 2005, however the Fund elected to stop designating these contracts as hedges as of December 31, 2005.
The Fund did not enter into any new contracts in the fourth quarter of 2005.
Electricity Instrument
The Fund has an electricity swap contract that fixed the price of electricity on 5MWh of Alberta Power Pool electricity consumption at $49.99/MWh from January 1, 2006 to December 31, 2006. This has been designated as a cash flow hedge and the fair value of this instrument as at December 31, 2005 is an unrealized gain of $1,019,000. Proceeds or costs realized from the electricity hedge are recognized as operating costs.
13. COMMITMENTS AND CONTINGENCIES
(a) Pipeline Transportation
Enerplus has contracted to transport natural gas with various pipelines totaling 35.3 MMcf/day until 2008; of this amount 5 MMcf/day extends until 2015. Enerplus also has a contract to transport a minimum of 2,480 bbls/day of crude oil from the field to suitable marketing sales points until 2010.
(b) Oil Sands Lease #24
During 2002 the Fund acquired a 16% working interest in the Oil Sands Lease #24 (Joslyn Creek Lease). The acquisition included the assumption of contingent project debt that is comprised of principal of $3,360,000 plus accrued interest to December 31, 2005 of $1,281,000. Interest is accrued at the Bank of Canada prime business rate and is not compounded. The debt is contingent on production hurdles with respect to development on the lease. As it is still too early in the development of this project to determine if these hurdles will be satisfied, the contingent debt has not been accrued in the consolidated financial statements.
(c) Office Lease
Enerplus has office lease commitments for both its Canadian and U.S. operations that expire between November 2009 and January 2011. Annual costs of these lease commitments, which include rent and operating fees, amount to approximately $5,700,000.
(d) Guarantee
(i) Corporate indemnities have been provided by the Fund to all directors and certain officers of its subsidiaries and affiliates for various items including, but not limited to, all costs to settle suits or actions due to their association with the Fund and its subsidiaries and/or affiliates, subject to certain restrictions. The Fund has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. Each indemnity, subject to certain exceptions, applies for so long as the indemnified person is a director or officer of one of the Fund’s subsidiaries and/or affiliates. The maximum amount of any potential future payment cannot be reasonably estimated.
(ii) The Fund may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Fund from making a reasonable estimate of the maximum potential amounts that may be required to be paid. Management believes the resolution of these matters would not have a material adverse impact on the Fund’s liquidity, consolidated financial position or results of operations.
Enerplus has the following minimum annual commitments including long-term debt:
Minimum Annual Commitment Each Year | Total Committed after 2010 | |||||||||||||||||||||
($ thousands) | Total | 2006 | 2007 | 2008 | 2009 | 2010 | ||||||||||||||||
Bank credit facility | $ | 328,632 | $ | - | $ | - | $ | 328,632 | $ | - | $ | - | $ | - | ||||||||
Senior unsecured notes | 331,286 | - | - | - | - | 35,000 | 296,286 | |||||||||||||||
Pipeline commitments | 33,956 | 6,026 | 6,026 | 5,513 | 2,952 | 2,444 | 10,995 | |||||||||||||||
Office lease | 23,373 | 5,680 | 5,651 | 5,722 | 5,678 | 592 | 50 | |||||||||||||||
Total commitments | $ | 717,247 | $ | 11,706 | $ | 11,677 | $ | 339,867 | $ | 8,630 | $ | 38,036 | $ | 307,331 |
In addition, the Fund is involved in claims and litigation arising in the normal course of business. The resolution of these claims is uncertain and there can be no assurance they will be resolved in favour of the Fund, however management believes the resolution of these matters would not have a material adverse impact on the Fund’s liquidity, consolidated financial position or results of operations.
14. GEOGRAPHICAL INFORMATION
Due to the acquisitions of Lyco and Sleeping Giant, the Fund now operates in Canada and the United States.
As at December 31, 2005 ($ thousands) | Oil and Gas Revenue | Capital Assets | Goodwill | |||||||
Canada | $ | 1,471,473 | $ | 3,054,078 | $ | 47,532 | ||||
United States | 79,096 | 596,249 | 173,702 | |||||||
Total | $ | 1,550,569 | $ | 3,650,327 | $ | 221,234 |
As at December 31, 2004 ($ thousands) | Oil and Gas Revenue | Capital Assets | Goodwill | |||||||
Canada | $ | 1,149,765 | $ | 3,029,007 | $ | 29,082 | ||||
United States | - | - | - | |||||||
Total | $ | 1,149,765 | $ | 3,029,007 | $ | 29,082 |
15. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
The Fund’s consolidated financial statements have been prepared in accordance with Canadian GAAP. These principles, as they pertain to the Fund’s consolidated statements differ from United States GAAP (“U.S. GAAP”) as follows:
The application of U.S. GAAP would have the following effects on net income as reported:
($ thousands) | 2005 | 2004 (1) | |||||
Net income as reported in the Consolidated | |||||||
Statement of Income - Canadian GAAP | $ | 432,041 | $ | 258,316 | |||
Adjustments | |||||||
Depletion, depreciation, amortization and accretion (Note (a)) | 57,050 | 74,775 | |||||
Amortization of financial derivative deferred charges (Note (b)) | 3,143 | 17,872 | |||||
Unrealized gain (loss) on cross-currency and interest rate swap (Note (c)) | (4,049 | ) | (2,549 | ) | |||
Compensation expense (Note (d)) | (19,732 | ) | (6,920 | ) | |||
Income tax expense of above adjustments, including recovery due to change in tax rates of $2,548 for 2005 and an expense of $10,543 for 2004 | (16,540 | ) | (40,897 | ) | |||
Net income before cumulative effect of change in accounting principle - U.S. GAAP | 451,913 | 300,597 | |||||
Cumulative effect of adoption of SFAS 123R (Note (d)) | 1,753 | - | |||||
Net income - U.S. GAAP | 453,666 | 300,597 | |||||
Net change in fair value of hedging instruments and available for sale securities, net of tax recovery of $5,887 (2004 - recovery of $2,860) and tax recovery due to change in tax rates of $38 for 2005 (2004 - expense of $118) (Note (e)) | (11,386 | ) | (5,709 | ) | |||
Net change in cumulative translation adjustment (2004 - nil) (Note (g)) | (15,568 | ) | - | ||||
Comprehensive income | $ | 426,712 | $ | 294,888 | |||
Net income per trust unit before cumulative change in accounting principle | |||||||
Basic | $ | 4.14 | $ | 3.03 | |||
Diluted | $ | 4.13 | $ | 3.02 | |||
Cumulative effect of change in accounting principle | |||||||
Basic | $ | 0.02 | $ | - | |||
Diluted | $ | 0.02 | $ | - | |||
Net income per trust | |||||||
Basic | $ | 4.16 | $ | 3.03 | |||
Diluted | $ | 4.15 | $ | 3.02 | |||
Weighted average number of trust units outstanding | |||||||
Basic | 109,083 | 99,273 | |||||
Diluted | 109,371 | 99,416 | |||||
Deficit | |||||||
Balance, beginning of year - U.S. GAAP | $ | (2,366,709 | ) | $ | (1,873,467 | ) | |
Net income - U.S. GAAP | 453,666 | 300,597 | |||||
Change in redemption value (Note (f)) | (1,140,261 | ) | (370,528 | ) | |||
Cash distributions | (498,205 | ) | (423,311 | ) | |||
Balance, end of year - U.S. GAAP | $ | (3,551,509 | ) | $ | (2,366,709 | ) | |
Accumulated other comprehensive income (loss) | |||||||
Balance, beginning of year - U.S. GAAP | $ | (13,818 | ) | $ | (8,109 | ) | |
Net change in fair value of hedging instruments and available for sale securities, net of tax | (11,386 | ) | (5,709 | ) | |||
Net change in cumulative translation adjustment | (15,568 | ) | - | ||||
Balance, end of year - U.S. GAAP | $ | (40,772 | ) | $ | (13,818 | ) |
(1) Certain amounts have been reclassified to ensure presentation consistency
The application of U.S. GAAP would have the following effects on the balance sheet as reported:
($ thousands) | Canadian GAAP | Increase (Decrease) | U.S. GAAP | |||||||
December 31, 2005 | ||||||||||
Other current assets (Note (e)) | $257,341 | $(38,977) | $218,364 | |||||||
Property, plant and equipment, net (Note (a)) | 3,650,327 | (712,380) | 2,937,947 | |||||||
Deferred credits/Financial derivative liabilities (Note (b)) | 57,368 | 61,626 | 118,994 | |||||||
Trust unit rights liability (Note (d)) | - | 20,654 | 20,654 | |||||||
Long-term debt (Note (c)) | 659,918 | (56,303 | ) | 603,615 | ||||||
Future income taxes/Deferred income taxes | 442,970 | (272,403 | ) | 170,567 | ||||||
Unitholders’ mezzanine equity (Note (f)) | - | 5,580,869 | 5,580,869 | |||||||
Unitholders’ capital (Note (f)) | 3,405,100 | (3,405,100 | ) | - | ||||||
Contributed surplus (Note (d)) | 5,514 | (5,514 | ) | - | ||||||
Deficit (Note (f)) | - | (3,551,509 | ) | (3,551,509 | ) | |||||
Accumulated income (Note (f)) | 1,408,178 | (1,408,178 | ) | - | ||||||
Accumulated other comprehensive income (loss) (Note (c)(e)(g)) | - | (40,772 | ) | (40,772 | ) | |||||
Accumulated cash distributions (Note (f)) | (2,309,705 | ) | 2,309,705 | - | ||||||
Cumulative translation adjustment (Note (g)) | (15,568 | ) | 15,568 | - | ||||||
December 31, 2004 (1) | ||||||||||
Other current assets (Note (e)) | $ | 9,602 | $ | 1,668 | $ | 11,270 | ||||
Deferred charges (Note (b)) | 5,061 | (3,143 | ) | 1,918 | ||||||
Property, plant and equipment, net (Note (a)) | 3,029,007 | (769,430 | ) | 2,259,577 | ||||||
Deferred credits/Financial derivative liabilities (Note (b)) | 42,303 | 67,899 | 110,202 | |||||||
Long-term debt (Note (c)) | 584,991 | (43,291 | ) | 541,700 | ||||||
Future income taxes/Deferred income taxes | 235,551 | (283,018 | ) | (47,467 | ) | |||||
Unitholders’ mezzanine equity (Note (f)) | - | 3,863,946 | 3,863,946 | |||||||
Unitholders’ capital (Note (f)) | 2,826,641 | (2,826,641 | ) | - | ||||||
Contributed surplus (Note (d)) | 4,636 | (4,636 | ) | - | ||||||
Deficit (Note (f)) | - | (2,366,709 | ) | (2,366,709 | ) | |||||
Accumulated income (Note (f)) | 976,137 | (976,137 | ) | - | ||||||
Accumulated other comprehensive income (loss) (Note (c)(e)) | - | (13,818 | ) | (13,818 | ) | |||||
Accumulated cash distributions (Note (f)) | (1,811,500 | ) | 1,811,500 | - |
(1) Certain amounts have been reclassified to ensure presentation consistency
(a) Property, Plant and Equipment and Depletion, Depreciation, Amortization and Accretion
Under U.S. GAAP full cost accounting, the carrying value of petroleum and natural gas properties and related facilities, net of deferred income taxes, is limited to the present value of after tax future net revenue from proved reserves, discounted at 10% (based on prices and costs at the balance sheet date), plus the lower of cost and fair value of unproved properties. Under Canadian GAAP, an impairment loss exists when the carrying amount of the Fund’s PP&E exceeds the estimated undiscounted future net cash flows associated with the Fund’s proved reserves. If an impairment loss is determined to exist, the costs carried on the balance sheet in excess of the discounted future net cash flows associated with the Fund’s proved and probable reserves are charged to income. The application of the impairment test under U.S. GAAP did not result in a write-down of capitalized costs in either 2005 or 2004.
A U.S. GAAP difference also exists relating to the basis of measurement of proved reserves that is utilized in the depletion calculation. Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices. Under Canadian GAAP, depletion charges are calculated by reference to proved reserves estimated using future prices and costs.
For the year ended December 31, 2005, DDA&A calculated under U.S. GAAP was $57,050,000 ($37,659,000 net of tax) lower than DDA&A calculated under Canadian GAAP. For the year ended December 31, 2004, DDA&A calculated under U.S. GAAP was $74,775,000 ($49,606,000 net of tax) lower than DDA&A calculated under Canadian GAAP.
(b) Derivative financial instruments (non-hedges)
Effective January 1, 2004, the Fund prospectively adopted CICA Accounting Guideline - 13 “Hedging Relationships” (“AcG-13”) and Emerging Issues Committee Abstract 128 “Accounting for Trading, Speculative or Non-hedging Derivative Financial Instruments”. As a result, most of the derivative financial instruments used by the Fund as economic hedges of commodity, interest and foreign currency transactions now receive the same accounting treatment under both Canadian and U.S. GAAP. Derivative financial assets and liabilities are presented as deferred charges and deferred credits.
Upon adoption of AcG-13, deferred credits and deferred charges of $21,015,000 were recognized representing the fair value of derivative financial instruments in place as of January 1, 2004 that do not qualify for hedge accounting. The deferred charges are amortized over the life of the financial instruments for Canadian GAAP and were equal to the aggregate of U.S. GAAP gains and losses incurred on these instruments prior to January 1, 2004. During 2005, the remaining $3,143,000 ($2,074,000 net of tax) of the deferred charges were amortized to income under AcG-13. Because this amount was expensed prior to 2004 for U.S. GAAP, the amount has been reversed in the current period.
(c) Cross-currency and interest rate swap
For Canadian GAAP, the cross-currency and interest rate swap qualifies as a fair value hedge for accounting purposes and therefore disclosure of the fair value is required with no effect on assets, liabilities or net income. Under U.S. GAAP, the fair value of the swap is recognized as a liability on the consolidated balance sheet and the underlying long-term debt is carried at fair value. Changes in the fair value of the cross-currency and interest rate swap are offset by changes in the fair value of the underlying long-term debt and the ineffective portion is taken into net income during the period.
(d) Unit-based compensation
On January 1, 2005 the Fund adopted Statement of Financial Accounting Standards (“SFAS”) 123R, “Share-Based Payment” using the modified prospective application of this standard. This resulted in the Fund adopting the fair value method of accounting for the rights plan for all rights granted under the plan. In 2003 and 2004 the Fund accounted for the rights plan using the intrinsic method. Financial results and comparatives for 2003 and 2004 have not been restated as the differences between the intrinsic and fair value method were not material.
Under SFAS 123R, rights granted under our rights plan are considered liability awards whereas they were previously considered equity awards. As a result of this change, on January 1, 2005 the Fund recorded a trust unit rights liability of $12,208,000 which represented the fair value of all outstanding rights on that date, in proportion to the requisite service period rendered to that date. In addition, mezzanine equity was reduced by $13,961,000, representing previously recognized compensation cost for all outstanding rights, and a recovery of $1,753,000 was recorded to cumulative effect of a change in accounting principle.
Under the fair value method for a liability award, the trust unit rights liability is calculated based on the rights fair value at each reporting date until the date of settlement. Compensation cost for each period is based on the change in the fair value of the rights for each reporting period. When rights are exercised, the proceeds, together with the amount recorded as a trust unit rights liability, are recorded to mezzanine equity.
A U.S. GAAP difference exists as compensation expense is not recorded for rights issued prior to January 1, 2003 under Canadian GAAP. In addition, rights granted under our rights plan are considered equity awards for Canadian GAAP purposes and are accounted for using the fair value method for an equity award. Under this method, the fair value of the right is determined on the grant date. This amount is charged to earnings over the vesting period of the rights, with a corresponding increase in contributed surplus. When rights are exercised, the fair value recorded in contributed surplus is recorded to unitholders’ capital.
The following chart details the U.S. GAAP differences related to our trust unit rights plan for the years ended December 31, 2005 and 2004.
2005 | 2004 | ||||||||||||||||||
CDN GAAP | U.S. GAAP | Difference | CDN GAAP | U.S. GAAP | Difference | ||||||||||||||
Compensation expense | 3,040,000 | 22,772,000 | 19,732,000 | 4,668,000 | 11,588,000 | 6,920,000 | |||||||||||||
Contributed Surplus | 5,514,000 | - | (5,514,000 | ) | 4,636,000 | - | 4,636,000 | ||||||||||||
Trust unit rights liability | - | 20,654,000 | 20,654,000 | - | - | - |
(e) Derivative instruments and available for sale securities
Under Canadian GAAP, disclosure of the fair value of derivative instruments that qualify for hedge accounting is required with no effect on assets, liabilities or net income. For U.S. GAAP, derivative instruments that qualify for hedge accounting must be measured and presented at fair value with changes in fair value of all cash flow hedges recognized in comprehensive income. Furthermore, the ineffective portion of qualified hedges is recognized in net income.
Effective December 31, 2005, the Fund stopped designating commodity financial contracts as hedges in accordance with CICA AcG-13, “Hedging Relationships”. As a result of this change, a deferred credit and deferred financial asset of $49,874,000 were recognized representing the fair value of these financial contracts. The deferred financial asset will be amortized during 2006 over the remaining lives of the financial contracts. For U.S. GAAP, these financial contracts are measured and presented at fair value with cumulative effective changes in fair value recognized in comprehensive income. Amortization of the deferred financial asset will result in a U.S. GAAP difference.
In addition, a U.S. GAAP difference exists relating to available for sale securities under SFAS 115 “Accounting for Certain Investments in Debt and Equity”. Under Canadian GAAP the fair value of marketable securities is disclosed, whereas under U.S. GAAP, available for sale securities are presented on the balance sheet at fair value with changes in fair value recognized in comprehensive income.
The Fund’s comprehensive income for the year ended December 31, 2005 includes a net loss in fair value of $17,311,000 ($11,424,000 net of tax). Comprehensive income for the year ended December 31, 2004 includes a net loss in fair value of $8,451,000 ($5,709,000 net of tax). The Fund’s accumulated comprehensive income is summarized below:
($ thousands) | 2005 | 2004 | |||||
Fair value of interest rate swaps | $ | (206 | ) | $ | (1,412 | ) | |
Fair value of natural gas instruments | (36,553 | ) | (14,723 | ) | |||
Fair value of crude oil instruments | (13,321 | ) | (6,406 | ) | |||
Fair value of electricity swap | 1,019 | 20 | |||||
Fair value of hedging instruments | $ | (49,061 | ) | $ | (22,521 | ) | |
Unrealized gain on available for sale securities | 10,898 | 1,668 | |||||
Cumulative translation adjustment | (15,568 | ) | - | ||||
Deferred income taxes | 12,959 | 7,035 | |||||
Accumulated other comprehensive income (loss) | $ | (40,772 | ) | $ | (13,818 | ) |
(f) Unitholders’ mezzanine equity
U.S. GAAP difference exists as a result of the redemption feature in the Fund’s trust units, which is required for the Fund to retain its Canadian mutual fund trust status. The trust units are redeemable at the option of the holder for approximately 85% of the current trading price. The amount of trust units that are redeemable for cash is limited to $500,000 in any two consecutive months. Any redemption in excess of the limit may be honored with promissory notes or other investments of the Fund. For Canadian GAAP, the trust units are considered to be permanent equity and are presented as unitholders’ capital. Under U.S. GAAP, the redemption feature of the trust units excludes them from classification as permanent equity and results in the trust units being classified as mezzanine equity.
The Fund has recorded, for U.S. GAAP, unitholders’ mezzanine equity in the amount of $5,580,869,000 for 2005 and $3,863,946,000 for 2004, which represents the estimated redemption value of the trust units at 85% of the year-end market price. For 2004, this amount also includes $13,961,000 which represents the intrinsic value of rights granted under our trust unit rights incentive plan. The Fund has also recognized a deficit of $3,551,509,000 for 2005 and $2,366,709,000 for 2004, resulting from eliminating the unitholders’ capital, accumulated income and cash distributions of the Fund and replacing them with unitholders’ mezzanine equity at redemption value. Changes in unitholders’ mezzanine equity in excess of trust units issued, net of redemptions, net income and cash distributions in any period are recognized as charges to the deficit.
(g) Cumulative translation adjustment
A U.S. GAAP difference exists relating to the cumulative translation adjustment that is generated upon translating the financial statements of the Fund’s U.S. subsidiaries. For Canadian GAAP the cumulative translation adjustment is deferred and included as a separate component of equity. For U.S. GAAP this amount is recognized in comprehensive income.
The Fund’s comprehensive income for the year ended December 31, 2005 includes a net change in the cumulative translation adjustment of $15,568,000 (2004 - nil).
U.S. Pronouncements
In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance test and fair value is determinable, the transaction must be accounted for at fair value resulting in the recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position.
In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.
SUPPLEMENTARY RESERVE INFORMATION
The following information has been prepared in accordance with National Instrument 51-101 and is derived from the independent engineering evaluations prepared by Sproule Associates Limited, GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton using forecast prices. Our reserve statement, which includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, as contained within our Annual Information Form will be available on our website at www.enerplus.com and on our SEDAR profile at www.sedar.com on March 10, 2006. Additionally, the Annual Information Form will be part of our Form 40-F that will be filed with the SEC and available on www.edgar-online.com on March 10, 2006.
Supplementary Reserve Information (forecast prices)
Oil And Gas Reserves | ||||||||||||||||||||||||||||
Light And Medium Oil | Heavy Oil | Bitumen | ||||||||||||||||||||||||||
Reserves Category | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | |||||||||||||||||||
Proved Developed Producing | ||||||||||||||||||||||||||||
Canada | 69,768 | 69,076 | 63,384 | 30,583 | 30,556 | 27,399 | - | - | - | |||||||||||||||||||
United States | 15,773 | 15,773 | 13,261 | - | - | - | - | - | - | |||||||||||||||||||
Total | 85,541 | 84,849 | 76,645 | 30,583 | 30,556 | 27,399 | - | - | - | |||||||||||||||||||
Proved Developed Non-Producing | ||||||||||||||||||||||||||||
Canada | 163 | 164 | 142 | - | - | - | - | - | - | |||||||||||||||||||
United States | - | - | - | - | - | - | - | - | - | |||||||||||||||||||
Total | 163 | 164 | 142 | - | - | - | - | - | - |
Oil And Gas Reserves | ||||||||||||||||||||||||||||
Light And Medium Oil | Heavy Oil | Bitumen | ||||||||||||||||||||||||||
Reserves Category | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) |
Proved Undeveloped | ||||||||||||||||||||||||||||
Canada | 3,318 | 3,281 | 2,901 | 2,318 | 2,318 | 1,966 | 9,453 | 9,453 | 9,358 | |||||||||||||||||||
United States | 7,822 | 7,822 | 6,554 | - | - | - | - | - | - | |||||||||||||||||||
Total | 11,140 | 11,103 | 9,455 | 2,318 | 2,318 | 1,966 | 9,453 | 9,453 | 9,358 | |||||||||||||||||||
Total Proved Reserves | ||||||||||||||||||||||||||||
Canada | 73,249 | 72,521 | 66,427 | 32,901 | 32,874 | 29,365 | 9,453 | 9,453 | 9,358 | |||||||||||||||||||
United States | 23,595 | 23,595 | 19,815 | - | - | - | - | - | - | |||||||||||||||||||
Total | 96,844 | 96,116 | 86,242 | 32,901 | 32,874 | 29,365 | 9,453 | 9,453 | 9,358 | |||||||||||||||||||
Probable Reserves | ||||||||||||||||||||||||||||
Canada | 17,498 | 17,272 | 14,967 | 8,495 | 8,487 | 6,131 | 43,700 | 43,700 | 41,150 | |||||||||||||||||||
United States | 5,574 | 5,574 | 4,673 | - | - | - | - | - | - | |||||||||||||||||||
Total | 23,072 | 22,846 | 19,640 | 8,495 | 8,487 | 6,131 | 43,700 | 43,700 | 41,150 | |||||||||||||||||||
Total Proved Plus Probable Reserves | ||||||||||||||||||||||||||||
Canada | 90,747 | 89,793 | 81,394 | 41,396 | 41,361 | 35,496 | 53,153 | 53,153 | 50,508 | |||||||||||||||||||
United States | 29,169 | 29,169 | 24,488 | - | - | - | - | - | - | |||||||||||||||||||
Total | 119,916 | 118,962 | 105,882 | 41,396 | 41,361 | 35,496 | 53,153 | 53,153 | 50,508 |
Oil And Gas Reserves | ||||||||||||||||||||||||||||
Natural Gas | Natural Gas Liquids | Total | ||||||||||||||||||||||||||
Reserves Category | Company Interest (MMcf) | Gross (MMcf) | Net (MMcf) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (MBOE) | Gross (MBOE) | Net (MBOE) | |||||||||||||||||||
Proved Developed Producing | ||||||||||||||||||||||||||||
Canada | 771,428 | 746,984 | 618,640 | 11,644 | 11,465 | 8,095 | 240,566 | 235,595 | 201,985 | |||||||||||||||||||
United States | 8,794 | 8,794 | 7,393 | - | - | - | 17,239 | 17,239 | 14,493 | |||||||||||||||||||
Total | 780,222 | 755,778 | 626,033 | 11,644 | 11,465 | 8,095 | 257,805 | 252,834 | 216,478 | |||||||||||||||||||
Proved Developed Non-Producing | ||||||||||||||||||||||||||||
Canada | 19,468 | 19,258 | 15,466 | 475 | 473 | 331 | 3,884 | 3,846 | 3,050 | |||||||||||||||||||
United States | - | - | - | - | - | - | - | - | - | |||||||||||||||||||
Total | 19,468 | 19,258 | 15,466 | 475 | 473 | 331 | 3,884 | 3,846 | 3,050 | |||||||||||||||||||
Proved Undeveloped | ||||||||||||||||||||||||||||
Canada | 161,728 | 156,197 | 132,094 | 965 | 963 | 681 | 43,008 | 42,048 | 36,922 | |||||||||||||||||||
United States | 4,358 | 4,358 | 3,651 | - | - | - | 8,548 | 8,548 | 7,163 | |||||||||||||||||||
Total | 166,086 | 160,555 | 135,745 | 965 | 963 | 681 | 51,556 | 50,596 | 44,085 | |||||||||||||||||||
Total Proved Reserves | ||||||||||||||||||||||||||||
Canada | 952,624 | 922,439 | 766,200 | 13,084 | 12,901 | 9,107 | 287,458 | 281,489 | 241,957 | |||||||||||||||||||
United States | 13,152 | 13,152 | 11,044 | - | - | - | 25,787 | 25,787 | 21,656 | |||||||||||||||||||
Total | 965,776 | 935,591 | 777,244 | 13,084 | 12,901 | 9,107 | 313,245 | 307,276 | 263,613 |
Oil And Gas Reserves | ||||||||||||||||||||||||||||
Natural Gas | Natural Gas Liquids | Total | ||||||||||||||||||||||||||
Reserves Category | Company Interest (MMcf) | Gross (MMcf) | Net (MMcf) | Company Interest (Mbbls) | Gross (Mbbls) | Net (Mbbls) | Company Interest (MBOE) | Gross (MBOE) | Net (MBOE) |
Probable Reserves | ||||||||||||||||||||||||||||
Canada | 309,572 | 301,586 | 252,478 | 3,539 | 3,480 | 2,470 | 124,827 | 123,203 | 106,798 | |||||||||||||||||||
United States | 32,946 | 32,946 | 27,655 | - | - | - | 11,065 | 11,065 | 9,282 | |||||||||||||||||||
Total | 342,518 | 334,532 | 280,133 | 3,539 | 3,480 | 2,470 | 135,892 | 134,268 | 116,080 | |||||||||||||||||||
Total Proved Plus Probable Reserves | ||||||||||||||||||||||||||||
Canada | 1,262,196 | 1,224,025 | 1,018,678 | 16,623 | 16,381 | 11,577 | 412,285 | 404,692 | 348,755 | |||||||||||||||||||
United States | 46,098 | 46,098 | 38,699 | - | - | - | 36,852 | 36,852 | 30,938 | |||||||||||||||||||
Total | 1,308,294 | 1,270,123 | 1,057,377 | 16,623 | 16,381 | 11,577 | 449,137 | 441,544 | 379,693 |
Net Reserve Reconciliation - Net Volumes (forecast prices)
Proved Reserves
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | 66,272 | 26,971 | - | 93,243 | 8,942 | 778,610 | 231,953 | |||||||||||||||
Acquisitions | 1,349 | - | - | 1,349 | 31 | 9,731 | 3,002 | |||||||||||||||
Divestments | (1,099 | ) | (1,205 | ) | - | (2,304 | ) | (49 | ) | (10,546 | ) | (4,111 | ) | |||||||||
Discoveries | 84 | - | - | 84 | 3 | 2,291 | 469 | |||||||||||||||
Extensions | 202 | 33 | - | 235 | 512 | 30,032 | 5,752 | |||||||||||||||
Technical Revisions | (1,789 | ) | 1,136 | 9,358 | 8,705 | 700 | (15,560 | ) | 6,812 | |||||||||||||
Economic Factors | 3,814 | 1,312 | - | 5,126 | 216 | 17,405 | 8,243 | |||||||||||||||
Improved Recovery | 2,939 | 3,759 | - | 6,698 | 49 | 32,974 | 12,243 | |||||||||||||||
Production | (5,345 | ) | (2,641 | ) | - | (7,986 | ) | (1,297 | ) | (78,737 | ) | (22,406 | ) | |||||||||
Proved Reserves at Dec. 31, 2005 | 66,427 | 29,365 | 9,358 | 105,150 | 9,107 | 766,200 | 241,957 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 20,076 | - | - | 20,076 | - | 10,738 | 21,866 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 624 | - | - | 624 | - | 792 | 756 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | (885 | ) | - | - | (885 | ) | - | (486 | ) | (966 | ) | |||||||||||
Proved Reserves at Dec. 31, 2005 | 19,815 | - | - | 19,815 | - | 11,044 | 21,656 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf | Total (MBOE) | |||||||||||||||
Proved Reserves at Dec. 31, 2004 | 66,272 | 26,971 | - | 93,243 | 8,942 | 778,610 | 231,953 | |||||||||||||||
Acquisitions | 21,425 | - | - | 21,425 | 31 | 20,469 | 24,868 | |||||||||||||||
Divestments | (1,099 | ) | (1,205 | ) | - | (2,304 | ) | (49 | ) | (10,546 | ) | (4,111 | ) | |||||||||
Discoveries | 84 | - | - | 84 | 3 | 2,291 | 469 | |||||||||||||||
Extensions | 202 | 33 | - | 235 | 512 | 30,032 | 5,752 | |||||||||||||||
Technical Revisions | (1,165 | ) | 1,136 | 9,358 | 9,329 | 700 | (14,768 | ) | 7,568 | |||||||||||||
Economic Factors | 3,814 | 1,312 | - | 5,126 | 216 | 17,405 | 8,243 | |||||||||||||||
Improved Recovery | 2,939 | 3,759 | - | 6,698 | 49 | 32,974 | 12,243 | |||||||||||||||
Production | (6,230 | ) | (2,641 | ) | - | (8,871 | ) | (1,297 | ) | (79,223 | ) | (23,372 | ) | |||||||||
Proved Reserves at Dec. 31, 2005 | 86,242 | 29,365 | 9,358 | 124,965 | 9,107 | 777,244 | 263,613 |
Net Reserve Reconciliation - Net Volumes (forecast prices) continued
Probable Reserves
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | 14,892 | 8,264 | 43,640 | 66,796 | 2,318 | 243,208 | 109,649 | |||||||||||||||
Acquisitions | 897 | - | - | 897 | 10 | 4,493 | 1,656 | |||||||||||||||
Divestments | (778 | ) | (702 | ) | - | (1,480 | ) | (29 | ) | (5,603 | ) | (2,443 | ) | |||||||||
Discoveries | 27 | - | - | 27 | 1 | 450 | 103 | |||||||||||||||
Extensions | (21 | ) | 20 | - | (1 | ) | 100 | 11,976 | 2,095 | |||||||||||||
Technical Revisions | (1,556 | ) | (441 | ) | (2,490 | ) | (4,487 | ) | (53 | ) | (15,893 | ) | (7,189 | ) | ||||||||
Economic Factors | 1,190 | 349 | - | 1,539 | 106 | 7,049 | 2,820 | |||||||||||||||
Improved Recovery | 316 | (1,359 | ) | - | (1,043 | ) | 17 | 6,798 | 107 | |||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 14,967 | 6,131 | 41,150 | 62,248 | 2,470 | 252,478 | 106,798 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 4,235 | - | - | 4,235 | - | 27,535 | 8,824 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 438 | - | - | 438 | - | 120 | 458 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 4,673 | - | - | 4,673 | - | 27,655 | 9,282 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Probable Reserves at Dec. 31, 2004 | 14,892 | 8,264 | 43,640 | 66,796 | 2,318 | 243,208 | 109,649 | |||||||||||||||
Acquisitions | 5,132 | - | - | 5,132 | 10 | 32,028 | 10,480 | |||||||||||||||
Divestments | (778 | ) | (702 | ) | - | (1,480 | ) | (29 | ) | (5,603 | ) | (2,443 | ) | |||||||||
Discoveries | 27 | - | - | 27 | 1 | 450 | 103 | |||||||||||||||
Extensions | (21 | ) | 20 | - | (1 | ) | 100 | 11,976 | 2,095 | |||||||||||||
Technical Revisions | (1,118 | ) | (441 | ) | (2,490 | ) | (4,049 | ) | (53 | ) | (15,773 | ) | (6,731 | ) | ||||||||
Economic Factors | 1,190 | 349 | - | 1,539 | 106 | 7,049 | 2,820 | |||||||||||||||
Improved Recovery | 316 | (1,359 | ) | - | (1,043 | ) | 17 | 6,798 | 107 | |||||||||||||
Production | - | - | - | - | - | - | - | |||||||||||||||
Probable Reserves at Dec. 31, 2005 | 19,640 | 6,131 | 41,150 | 66,921 | 2,470 | 280,133 | 116,080 |
Net Reserve Reconciliation - Net Volumes (forecast prices) continued
Proved Plus Probable Reserves
CANADA | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | 81,164 | 35,235 | 43,640 | 160,039 | 11,260 | 1,021,818 | 341,602 | |||||||||||||||
Acquisitions | 2,246 | - | - | 2,246 | 41 | 14,224 | 4,658 | |||||||||||||||
Divestments | (1,877 | ) | (1,907 | ) | - | (3,784 | ) | (78 | ) | (16,149 | ) | (6,554 | ) | |||||||||
Discoveries | 111 | - | - | 111 | 4 | 2,741 | 572 | |||||||||||||||
Extensions | 181 | 53 | - | 234 | 612 | 42,008 | 7,847 | |||||||||||||||
Technical Revisions | (3,345 | ) | 695 | 6,868 | 4,218 | 647 | (31,453 | ) | (377 | ) | ||||||||||||
Economic Factors | 5,004 | 1,661 | - | 6,665 | 322 | 24,454 | 11,063 | |||||||||||||||
Improved Recovery | 3,255 | 2,400 | - | 5,655 | 66 | 39,772 | 12,350 | |||||||||||||||
Production | (5,345 | ) | (2,641 | ) | - | (7,986 | ) | (1,297 | ) | (78,737 | ) | (22,406 | ) | |||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 81,394 | 35,496 | 50,508 | 167,398 | 11,577 | 1,018,678 | 348,755 |
UNITED STATES | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | - | - | - | - | - | - | - | |||||||||||||||
Acquisitions | 24,311 | - | - | 24,311 | - | 38,273 | 30,690 | |||||||||||||||
Divestments | - | - | - | - | - | - | - | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | |||||||||||||||
Extensions | - | - | - | - | - | - | - | |||||||||||||||
Technical Revisions | 1,062 | - | - | 1,062 | - | 912 | 1,214 | |||||||||||||||
Economic Factors | - | - | - | - | - | - | - | |||||||||||||||
Improved Recovery | - | - | - | - | - | - | - | |||||||||||||||
Production | (885 | ) | - | - | (885 | ) | - | (486 | ) | (966 | ) | |||||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 24,488 | - | - | 24,488 | - | 38,699 | 30,938 |
TOTAL ENERPLUS | Light & Medium Oil (Mbbls) | Heavy Oil (Mbbls) | Bitumen (Mbbls) | Total Oil (Mbbls) | Natural Gas Liquids (Mbbls) | Natural Gas (MMcf) | Total (MBOE) | |||||||||||||||
Proved Plus Probable Reserves at Dec. 31, 2004 | 81,164 | 35,235 | 43,640 | 160,039 | 11,260 | 1,021,818 | 341,602 | |||||||||||||||
Acquisitions | 26,557 | - | - | 26,557 | 41 | 52,497 | 35,348 | |||||||||||||||
Divestments | (1,877 | ) | (1,907 | ) | - | (3,784 | ) | (78 | ) | (16,149 | ) | (6,554 | ) | |||||||||
Discoveries | 111 | - | - | 111 | 4 | 2,741 | 572 | |||||||||||||||
Extensions | 181 | 53 | - | 234 | 612 | 42,008 | 7,847 | |||||||||||||||
Technical Revisions | (2,283 | ) | 695 | 6,868 | 5,280 | 647 | (30,541 | ) | 837 | |||||||||||||
Economic Factors | 5,004 | 1,661 | - | 6,665 | 322 | 24,454 | 11,063 | |||||||||||||||
Improved Recovery | 3,255 | 2,400 | - | 5,655 | 66 | 39,772 | 12,350 | |||||||||||||||
Production | (6,230 | ) | (2,641 | ) | - | (8,871 | ) | (1,297 | ) | (79,223 | ) | (23,372 | ) | |||||||||
Proved Plus Probable Reserves at Dec. 31, 2005 | 105,882 | 35,496 | 50,508 | 191,886 | 11,577 | 1,057,377 | 379,693 |
2005 INCOME TAX INFORMATION
Information for Canadian Residents (CDN$ per Unit)
The following table outlines the breakdown of cash distributions per unit and per subscription receipt paid by Enerplus Resources Fund for the period February 20, 2005 to January 20, 2006 for Canadian Income Tax purposes.
Record Date | Payment Date | Total Distribution Paid | Taxable Other Income | Taxable Dividend | Return of Capital | |||||||||||
Feb 10, 2005 | Feb 20, 2005 | $ | 0.350000 | $ | 0.314788 | $ | 0.001959 | $ | 0.033253 | |||||||
Mar 10, 2005 | Mar 20, 2005 | $ | 0.350000 | $ | 0.314793 | $ | 0.001954 | $ | 0.033253 | |||||||
Apr 10, 2005 | Apr 20, 2005 | $ | 0.350000 | $ | 0.314794 | $ | 0.001953 | $ | 0.033253 | |||||||
May 10, 2005 | May 20, 2005 | $ | 0.350000 | $ | 0.314796 | $ | 0.001951 | $ | 0.033253 | |||||||
Jun 10, 2005 | Jun 20, 2005 | $ | 0.350000 | $ | 0.314797 | $ | 0.001950 | $ | 0.033253 | |||||||
Jul 10, 2005 | Jul 20, 2005 | $ | 0.350000 | $ | 0.314828 | $ | 0.001919 | $ | 0.033253 | |||||||
Aug 10, 2005 | Aug 20, 2005 | $ | 0.370000 | $ | 0.332929 | $ | 0.001919 | $ | 0.035152 | |||||||
Sep 10, 2005 | Sep 20, 2005 | $ | 0.370000 | $ | 0.333104 | $ | 0.001743 | $ | 0.035153 | |||||||
Oct 10, 2005 | Oct 20, 2005 | $ | 0.370000 | $ | 0.333105 | $ | 0.001742 | $ | 0.035153 | |||||||
Nov 10, 2005 | Nov 20, 2005 | $ | 0.420000 | $ | 0.378355 | $ | 0.001742 | $ | 0.039903 | |||||||
Dec 10, 2005 | Dec 20, 2005 | $ | 0.420000 | $ | 0.378357 | $ | 0.001740 | $ | 0.039903 | |||||||
Dec 31, 2005 | Jan 20, 2006 | $ | 0.420000 | $ | 0.378359 | $ | 0.001738 | $ | 0.039903 | |||||||
TOTAL PER UNIT | $ | 4.470000 | $ | 4.023005 | $ | 0.022310 | $ | 0.424685 | ||||||||
PER SUBSCRIPTION RECEIPT | ||||||||||||||||
Paid August 30, 2005 | $ | 0.370000 | $ | 0.370000 |
Information for United States Residents (US$ per Unit)
The following table outlines the breakdown of cash distributions per unit, prior to any amounts deducted for Canadian withholding tax, paid by Enerplus Resources Fund for the period January 20, 2005 to December 20, 2005 for units held through a broker or other intermediary. The amounts shown on the schedule are in U.S. dollars as converted on the applicable payment dates.
Record Date | Payment Date | Distribution Paid CDN$ | Exchange Rate | Distribution Paid US$ | Taxable Qualified Dividend US$ | Non-Taxable Return of Capital US$ | |||||||||||||
Dec 31, 2004 | Jan 20, 2005 | $ | 0.35 | 0.8087 | $ | 0.283057 | $ | 0.263449 | $ | 0.019608 | |||||||||
Feb 10, 2005 | Feb 20, 2005 | $ | 0.35 | 0.8107 | $ | 0.283745 | $ | 0.264090 | $ | 0.019655 | |||||||||
Mar 10, 2005 | Mar 20, 2005 | $ | 0.35 | 0.8237 | $ | 0.288303 | $ | 0.268332 | $ | 0.019971 | |||||||||
Apr 10, 2005 | Apr 20, 2005 | $ | 0.35 | 0.8032 | $ | 0.281125 | $ | 0.261651 | $ | 0.019474 | |||||||||
May 10, 2005 | May 20, 2005 | $ | 0.35 | 0.7908 | $ | 0.276789 | $ | 0.257616 | $ | 0.019173 | |||||||||
Jun 10, 2005 | Jun 20, 2005 | $ | 0.35 | 0.8106 | $ | 0.283699 | $ | 0.264047 | $ | 0.019652 | |||||||||
Jul 10, 2005 | Jul 20, 2005 | $ | 0.35 | 0.8167 | $ | 0.285831 | $ | 0.266031 | $ | 0.019800 | |||||||||
Aug 10, 2005 | Aug 20, 2005 | $ | 0.37 | 0.8268 | $ | 0.305912 | $ | 0.284721 | $ | 0.021191 | |||||||||
Sep 10, 2005 | Sep 20, 2005 | $ | 0.37 | 0.8538 | $ | 0.315915 | $ | 0.294032 | $ | 0.021883 | |||||||||
Oct 10, 2005 | Oct 20, 2005 | $ | 0.37 | 0.8493 | $ | 0.314225 | $ | 0.292458 | $ | 0.021767 | |||||||||
Nov 10, 2005 | Nov 20, 2005 | $ | 0.42 | 0.8398 | $ | 0.352734 | $ | 0.328299 | $ | 0.024435 | |||||||||
Dec 10, 2005 | Dec 20, 2005 | $ | 0.42 | 0.8511 | $ | 0.357477 | $ | 0.332714 | $ | 0.024763 | |||||||||
TOTAL PER UNIT | $ | 4.40 | $ | 3.628812 | $ | 3.377440 | $ | 0.251372 |
For further information and a complete copy of the 2005 Annual Report, please contact Investor Relations at 1-800-319-6462 or email investorrelations@enerplus.com.
- 30 -
This news release contains certain forward-looking statements, which are based on Enerplus' current internal expectations, estimates, projections, assumptions and beliefs. Some of the forward-looking statements may be identified by words such as "expects", "anticipates", "believes", "projects", "plans" and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties. Such forward-looking statements necessarily involve known and unknown risks and uncertainties, which may cause Enerplus' 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. These risks and uncertainties include, among other things, changes in general economic, market and business conditions; changes or fluctuations in production levels, commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; changes to legislation, investment eligibility or investment criteria; Enerplus' ability to comply with current and future environmental or other laws; Enerplus' success at acquisition, exploitation and development of reserves; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; and the occurrence of unexpected events involved in the operation and development of oil and gas properties. Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Many of these risks and uncertainties are described in Enerplus' Annual Information Form and Enerplus' Management's Discussion and Analysis. Readers are also referred to risk factors described in other documents Enerplus files with the Canadian and U.S. securities authorities. Copies of these documents are available without charge from Enerplus. Enerplus disclaims any responsibility to update these forward-looking statements.
Eric P. Tremblay
Senior Vice-President, Capital Markets