EXHIBIT 1
Management’s Discussion & Analysis
As discussed in Note 3 (d) to the financial statements, NCE Petrofund (the “Trust”) and NCE Petrofund Corp. (“NCEP”) were consolidated on November 1, 2000 and the prior years have been restated to conform to the revised presentation. On July 6, 2001, the Trust units were consolidated on a one- for-three basis. All unit-related numbers including units outstanding, options outstanding and option prices, net income per unit and distributions per unit have been restated for all prior periods to reflect this consolidation.
The following discussion and analysis of financial results should be read in conjunction with the audited consolidated financial statements of the Trust for the fiscal years ended December 31, 2002 and 2001 presented below. This commentary is based on information available to March 10, 2003.
Where amounts and volumes are expressed on a barrel of oil equivalent (boe) basis, gas vo lumes have been converted to barrels of oil at 6,000 cubic feet per barrel.
The year 2002 was very successful from a growth standpoint with production increasing 24% to 25,782 barrels of oil equivalent per day (boe/d) in 2002 from 20,810 boe/d in 2001. Production for the second half of 2002 averaged 27,139 boe/d. The growth was due to $60 million of property acquisitions completed at the end of 2001 and in the first quarter of 2002, and the acquisition of NCE Energy Trust (“NCE Energy”) effective May 31, 2002.
One of the key objectives of management was to acquire and amalgamate NCE Energy into NCE Petrofund as the Trusts had similar mandates and strategies and were already under common management. The NCE Energy purchase significantly increased the market capitalization of NCE Petrofund, eliminated duplicate reporting costs, corporate expenses, transfer agent and other costs, and simplified operations. The acquisition also increased the percentage of operated properties and, therefore, provided more control over costs and the timing of capital projects.
Oil prices were fairly strong throughout the past two years, averaging US$26.08 on the benchmark West Texas Intermediate (WTI) barrel in 2002 compared to US$25.90 in 2001. In the past two years, there were two quarters of relative price weakness, the fourth quarter of 2001 when oil averaged US$20.43 and the first quarter of 2002 when the price averaged US$21.64.
Monthly AECO prices averaged $4.25 per mcf in 2002, compared to $6.30 per mcf in 2001, a decrease of 33%. Over the course of 2001, the AECO price declined from an average of $13.62 per mcf in January (a level significantly higher than experienced in recent years) to $3.74 per mcf in December. The AECO gas price remained weak through the first nine mo nths of 2002, averaging $3.67 per mcf, before rising significantly to $5.26 per mcf in the fourth quarter. The daily AECO price reached its high for the year of $6.75 per mcf in December 2002.
Cash flow from operating activities increased from $110.2 million in 2001 to $112.6 million in 2002. The 24% increase in production on a boe basis was largely offset by the lower gas prices.
Significant Financial Transactions
On January 17, 2002, NCE Petrofund announced the acquisition of two property packages for $19.8 million. The acquisition costs were reflected in the 2001 year-end financial statements and the results of operations from the properties are reflected in this report, effective January 1, 2002.
The acquired properties had a reserve life index of 18.1 years and consisted mainly of unitized production. The most significant unit interest acquired was in Swan Hills Unit #1. Production at the date of acquisition was approximately 700 boe/d, of which 95% was oil. According to independent engineering estimates, established reserves were 4.7 million boe.
On March 5, 2002, NCE Petrofund announced the purchase of two gas-producing properties and two oil-producing properties in central Alberta for $40.2 million. Three of the properties are unitized and one is operated. Net established reserves acquired were estimated at 8.8 million boe and net production at the date of acquisition was 1,800 boe/d, consisting of 67% oil. The properties had a reserve life index in excess of 13 years.
On March 28, 2002, NCE Petrofund closed a “bought deal” financing of Trust units raising gross proceeds of $59.8 million. A total of 4.6 million units were issued at $13.00 per unit.
On April 19, 2002, NCE Petrofund signed an agreement whereby NCE Petrofund would acquire NCE Energy on the basis of 0.2325 of an NCE Petrofund Trust unit for each NCE Energy unit on a tax-free rollover basis. On May 31, 2002, NCE Petrofund completed the acquisition for $140.1 million. The total price consisted of the issue of 7.6 million Petrofund units with an assigned value of $98.6 million, the assumption of $39.5 million of debt and negative working capital, as well as transaction costs of $2.0 million. The purchase price of $140.1 million does not include the $27.1 million added to oil and gas properties to reflect the difference between the cost and the tax basis of the properties acquired. Production from the properties at the time of acquisition was approximately 5,300 boe/d, representing a cost of $26,500 per boe/d, excluding the non-cash component of the pu rchase price. Approximately 50% of the production was gas.
On December 31, 2002, NCEP acquired producing gas properties in the Fort Saskatchewan, Alberta area from ATCO Gas for $31.5 million. NCEP will operate the properties and holds an average 95% working interest. Current production net to NCEP is approximately 6 mmcf/d and the established reserves acquired were approximately 19 bcf.
During the year, the Trust also spent $40.8 million for exploratory and development drilling, well-equipping costs, facilities and tie- ins. The Trust drilled 290 gross (72.7 net) gas wells, 40 gross (10.6 net) oil wells and had 4 gross (3.3 net) dry holes for an overall success rate of 96%. The drilling added approximately 1,750 boe/d of production at $23,500 per boe/d and established reserves of 3.8 million boe at a cost of $10.64 per boe, including equipping and facility costs. A significant portion of the capital expenditures were incurred to convert proved undeveloped reserves to developed and, therefore, did not add reserves.
In total, the Trust incurred net capital expenditures of $229.3 million in 2002, excluding future income taxes of $27.1 million, and replaced 206% of its 2002 production. Established reserves of 19.4 million boe, net of revisions were added. The cost was $8.42 per boe excluding the reserve revisions and $11.79 per boe after giving effect to the revision. A number of minor non-core properties with short reserve life indexes and high operating costs were sold for $30.0 million at a price of $8.94 per boe.
Cash Distributions
Trust unitholders who held their units throughout 2002 received cash distributions of $1.71 per unit as compared to $4.24 per unit in 2001, and $3.99 in 2000. During the first two months of 2003, the Trust distributed $0.31 per unit.
The Trust generated cash flow available for distributions of $103.1 million in 2002. The cash flow was reduced by $10 million for capital expenditures during the last half of the year in accordance with our revised distribution policy to use a portion of the cash flow generated to offset production decline and enhance long-term unitholder returns. The $10 million represents 17% of cash flow for the six- month period. A total of $85 million was paid out in distributions, representing a payout ratio of 83%.
At December 31, 2002, the Trust had $30.1 million available to pay future distributions, capital and other costs, of which $16.8 million was used to pay the January and February 2003 distributions. There is approximately a two-month delay between collecting revenues and the payment of distributions.
Production Revenue
2002 | 2001 | 2000 | |
Production | |||
Oil (bbl/d) | 11,162 | 8,156 | 5,784 |
Gas (mmcf/d) | 76.9 | 67.2 | 49.3 |
NGLs (bbl/d) | 1,808 | 1,452 | 1,001 |
Total (boe/d – 6:1) | 25,782 | 20,810 | 14,998 |
Sales Prices | |||
Oil per bbl (1) | $34.68 | $34.37 | $39.99 |
Gas per mcf(2) | 3.95 | 5.09 | 4.76 |
NGL per bbl | 28.30 | 32.57 | 38.19 |
Weighted average (6:1) | $ 28.77 | $32.19 | $33.66 |
Production Revenue (millions) | |||
Oil | $141.3 | $102.3 | $ 84.7 |
Gas | 110.7 | 125.0 | 85.8 |
NGLs | 18.7 | 17.2 | 14.3 |
Total | $270.7 | $ 244.5 | $184.8 |
(1) The oil price was increased | |||
(decreased) per bbl due to hedging | $(2.10) | $ 1.05 | $ (2.24) |
(2) The gas price was increased | |||
(decreased) per mcf due to hedging | $ 0.00 | $(0.13) | $ (0.17) |
Revenues from the sale of crude oil, natural gas and natural gas liquids increased 11% to $270.7 million in 2002 from $244.6 million in 2001 due to a 24% increase in production. Prices declined 11% on a boe basis.
Crude oil sales rose to $141.3 million in 2002 from $102.3 million in 2001 due to a 37% increase in production from 8,156 bbl/d in 2001 to 11,162 bbl/d in 2002. The average Canadian wellhead price increased marginally from $34.37 per barrel in 2001 to $34.68 per barrel in 2002.
Natural gas sales decreased to $110.7 million in 2002, from $125.0 million in 2001 in spite of the 14% rise in production. The average price decreased 22% from $5.09 per mcf in 2001 to $3.95 per mcf in 2002. Production volumes were 76.9 mmcf/d in 2002, compared to 67.2 mmcf/d in 2001. Gas prices were weak throughout most of the first nine months of 2002, averaging $3.57 per mcf, then rose to $5.15 per mcf in the fourth quarter.
Sales of natural gas liquids increased to $18.7 million in 2002 from $17.2 million in 2001 as production rose to 1,808 bbl/d in 2002 from 1,452 bbl/d in 2001. The average price declined from $32.57 per barrel in 2001 to $28.30 per barrel in 2002.
Crude oil sales accounted for 43% of total production volumes in 2002 (2001 – 39%), while natural gas sales contributed 50% of production in 2002 (2001 – 54%). Natural gas liquid volumes accounted for 7% of total production in 2002 (2001 – 7%). The Trust continues to maintain an excellent balance between oil and gas production.
Royalties | 2002 | 2001 | 2000 |
Royalties (millions) | $ 50.4 | $ 54.8 | $ 39.2 |
Average royalty rate (%) | 19% | 22% | 21% |
$/boe | $ 5.36 | $ 7.21 | $ 7.13 |
Royalties, which include Crown, freehold and overrides paid on oil and gas production, decreased to $50.4 million in 2002 from $54.8 million in 2001, net of the Alberta Royalty Credit. Royalties declined to 19% of revenues in 2002 from 22% of revenues in 2001 and 21% in 2000, mainly due to the lower average gas prices.
Expenses | 2002 | 2001 | 2000 |
Expenses(millions) | |||
Lease operating | $ 74.8 | $ 48.2 | $ 28.7 |
General & administrative | 15.5 | 14.4 | 8.8 |
Management fee | 4.7 | 5.3 | 4.4 |
Net interest | 8.3 | 7.8 | 6.0 |
Expenses per boe | |||
Lease operating | $ 7.95 | $ 6.35 | $ 5.23 |
General & administrative | 1.65 | 1.90 | 1.60 |
Management fee | 0.50 | 0.70 | 0.80 |
Net interest | 0.88 | 1.03 | 1.10 |
Lease Operating
Oil and gas operating expenses were $74.8 million in 2002, up from $48.2 million in 2001 due to the additional wells on production resulting mainly from acquisition and the increase in costs on a boe basis. Operating costs on a boe basis increased to $7.95 in 2002 from $6.35 in 2001 due to increased production optimization work performed on existing and newly acquired properties, as well as higher repair and maintenance and utility costs. The current year costs also include an under accrual of prior year costs of $5.5 million, or $0.58 per boe, including a $1 million loss on a utility power hedge, primarily relating to the properties acquired from Magin Energy Inc. (“Magin”).
General and Administrative
General and administrative costs increased to $15.5 million in 2002 from $14.4 million in 2001. The 2001 costs include $2.6 million relating to a U.S. offering which was withdrawn mainly due to the events of September 11, 2001. One of our major objectives has been to reduce general and administrative costs on a boe basis. Major progress has been made - costs have been reduced from $1.78 per boe in the first half of 2002 to $1.53 per boe in the second half. We expect this downward trend to continue into 2003.
Upon completion of the internalization transaction described below under the heading “Management Fees”, the Trust’s management will be consolidated in Calgary, which is expected to reduce future general and administrative costs. To ensure an orderly transition of the services currently provided by the manager through its Toronto office, upon completion of the internalization transaction, an affiliate of the manager will enter into an agreement effective January 1, 2003 to provide certain of these services to the Trust until December 31, 2003, for a maximum fee of $2 million.
Management Fees
Management fees decreased to $4.7 million in 2002 from $5.3 million in 2001 in spite of the increase in cash flow from operations, as the fee was reduced to 3.25% from 3.75% effective January 1, 2002. This percentage applies to net operating revenue including the Alberta Royalty Credit.
As announced on March 10, 2003, the Trust has entered into an agreement to internalize its management structure such that NCE Petrofund Management Corp., the manager of the Trust, would become a wholly owned subsidiary of NCEP. Completion of the transaction is subject to unitholder and regulatory approval. If completed, all management, acquisition and disposition fees payable to the manager would be eliminated effective January 1, 2003. The purchase price payable by the Trust will be $23.6 million, subject to adjustment, to be satisfied by the issuance of 1,939,147 exchangeable shares. Each exchangeable share will be exchangeable into one NCE Petrofund unit, sub ject to adjustment to reflect distributions paid after the date of closing. Each unit or exchangeable share is valued at $12.1703, the weighted average trading price of NCE over the 10 trading days ending Ma rch 4, 2003 on the Toronto Stock Exchange. In addition, at closing NCEP will pay $3.4 million in cash to fund the repayment of indebtedness owing by the manager and an aggregate of $2 million to certain senior executives of the manager, such payment to be comprised of $780,000 in cash and 100,244 units, subject to adjustment.
Interest
Interest expense increased to $8.3 million in 2002 from $7.8 million in 2001, due to the increase in the average loan balance outstanding.
Depletion and Depreciation and Provision for Reclamation and Abandonment
Depletion and depreciation is provided on the unit-of-production method based on total estimated proven reserves. Depletion and depreciation expense was $98.8 million in 2002 compared to $68.5 million in 2001 (2000 - $30.6 million). The depletion rate per boe increased to $10.50 in 2002 from $9.01 in 2001 and $5.57 in 2000. The $1.49 increase in the depletion rate from 2001 to 2002 was due to the increase in the acquisition costs of properties and negative reserve revisions. Unproved properties are included in the depletion and depreciation rate. The provision for reclamation and abandonment per boe in 2002 was $0.62, compared to $0.48 in 2001 (2000 - $0.42).
Reclamation and Abandonment Reserve
At the end of the year, NCEP had $3.0 million set aside in cash to fund future abandonment costs. This cash fund is increased by $0.075 per boe produced on an ongoing basis. The fund is maintained to provide for unusual or exceptionally large reclamation and abandonment costs. Ongoing well abandonment costs are paid from cash flow.
Working Capital
Accounts receivable increased by $29 million, as $22.9 million is due on the sale of properties, and joint and other receivables increased as a result of the purchase of NCE Energy Trust.
Prepaid expenses and deferred charges increased by $5.5 million due to cash calls paid on capital projects, prepaid royalty deposits and deferred costs on the purchase of hedge contracts.
Current liabilities increased by $19 million due to the increase in distributions payable to unitholders.
Liquidity and Capital Resources
The Trust completed a public offering in 2002, raising net proceeds of $56.3 million and generated cash flow from operating activities of $112.6 million. The Trust paid out $85 million in distributions in 2002 including $12.2 million accrued at December 31, 2001.
The credit facility was increased from $165 million to $200 million on February 28, 2002 and from $200 million to $245 million on July 3, 2002. At year-end, there was $212 million outstanding.
NCEP incurred net capital expenditures of $229.3 million during 2002, of which $154.9 million was financed by the issue of units for the Energy Trust acquisition and from the equity offering and $84 million by an increase in the bank loan.
As at December 31, 2002 NCEP had drilling and other commitments of approximately $1 million.
Accounting Changes
As discussed in Note 3d to the financial statements, the Trust and NCEP were consolidated effective with the third quarter of 2000 and the prior periods have been restated.
Quarterly Financial
Net Oil and | Net | Net income per unit | |||||||
($millions, except per unit amounts) | Natural Gas Sales* | Income | Basic | Diluted | |||||
2002 | |||||||||
First quarter |
| $ 42.7 | $ 0.9 | $ 0.02 | $ 0.02 | ||||
Second quarter | 53.1 | 8.5 | 0.17 | 0.17 | |||||
Third quarter | 55.8 | 9.6 | 0.18 | 0.18 | |||||
Fourth quarter | 68.6 | 5.4 | 0.10 | 0.10 | |||||
$ 220.2 | $ 24.4 | $ 0.49 | $ 0.49 | ||||||
2001 | |||||||||
First quarter | $ 54.4 | $ 26.3 | $ 1.19 | $ 1.19 | |||||
Second quarter | 46.9 | 16.4 | 0.60 | 0.60 | |||||
Third quarter | 45.4 | 7.7 | 0.20 | 0.20 | |||||
Fourth quarter | 43.0 | 3.6 | 0.09 | 0.09 | |||||
| $ 189.7 | $ 54.0 | $ 1.71 | $ 1.71 | |||||
2000 | |||||||||
First quarter | $ 26.1 | $ 8.8 | $ 0.55 | $ 0.55 | |||||
Second quarter | 32.6 | 12.1 | 0.65 | 0.65 | |||||
Third quarter | 39.8 | 17.5 | 0.89 | 0.89 | |||||
Fourth quarter | 47.1 | 24.5 | 1.12 | 1.12 | |||||
$ 145.6 | $ 62.9 | $ 3.31 | $ 3.30 | ||||||
*Net after royalties
Business Risks
The success of the Trust in meeting its objective of stable distributions over the long term depends mainly on management’s ability to:
1) Identify and acquire oil and gas properties and/or companies at prices that add value to the Trust.
2) Cost effectively add or extend reserves with internal development and drilling or farm-outs.
3) Manage and control costs.
There are numerous factors beyond management’s control that have a major influence on distribution levels including product prices, unforeseen production declines and cost increases from major suppliers. (A much more detailed assessment of risk factors and strategies to offset them appears elsewhere in this report.)
Below is a table that shows sensitivities to pre- hedging cash flow as a result of product price and operational changes. The table is based on actual 2002 prices and production volumes.
Change to annual cash flow | ||||
Change | $ 000s | $/unit | ||
Price per barrel of oil (US$ WTI)* | $ 1.00 |
| $ 5,865 | $ 0.117 |
Price per mcf of natural gas (C$ AECO)* | $ 0.10 | 2,217 | 0.044 | |
US / Cdn exchange rate | $ 0.01 | 2,363 | 0.047 | |
Interest rate on debt | 1.0% | 1,710 | 0.034 | |
Oil production volumes - 100 bbl/d* | 0.77% | 1,094 | 0.022 | |
Gas production volumes - 1 mmcf/d* | 1.30% | 1,139 | 0.023 | |
* After adjustment for estimated royalties.
Outlook
Looking ahead to 2003, we intend to continue with our acquisition strategy to add value through the purchase of long- life production. It is our expectation that more properties will come available on the market as a result of non-core property divestitures by the large E&P companies, and NCEP will participate in the review and evaluation process of these properties. We will also continue with our drilling, development and optimization programs as a complement to our base strategy. We expect to continue to grow but we are more focused on providing good yields to our unitholders while, at the same time, maintaining unit value.
In the event that the internalization transaction announced on March 10, 2003 is completed, we expect to be able to further reduce general and administrative costs on a boe basis, a trend which has already become evident in the second half of 2002.
Impact of New Canadian Accounting Pronouncements
In November 2002, the Canadian Institute of Chartered Accountants ("CICA") amended the effective date of its accounting guideline on hedging relationships, which was originally issued in November 2001. The guideline establishes certain conditions where hedge accounting may be applied. It is effective for fiscal years beginning on or after July 1, 2003. The guideline will not have a significant impact on the Trust's financial position or results of operations.
In December 2002, the CICA issued a new standard on the accounting for asset retirement obligations. This standard, as with the new U.S. standard (FAS 143) described in Note 16 to the consolidated financial statements, requires recognition of a liability for the future retirement obligations associated with property, plant and equipment. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected settlement of the retirement obligations. The new standard is effective for all fiscal years beginning on or after January 1, 2004 but earlier adoption is encouraged. The Trust expects to adopt this standard effective January 1, 2003. The impact of the effect of this new standard on the consolidated financial statements has not been determined.
Other accounting standards issued by the CICA during the year ended December 31, 2002 are not expected to impact the Trust at this time.
Controls and Procedures
Evaluation of disclosure controls and procedures.The Trust’s principal executive officer and its principal financial officer, after evaluating the effectiveness of the Trust disclosure controls and procedures (as defined in U.S. Exchange Act Rules 13a-14(c) and 15d-14(c)) as of a date within 90 days prior to the filing date of this annual report, have concluded that, as of such date, the Trust’s disclosure controls and procedures were adequate and effective to ensure that material information relating to the Trust and its subsidiaries would be made known to them by others within those entities.
Changes in internal controls.There were no significant changes in the Trust’s internal controls or in other factors that could significantly affect the Trust’s internal controls subsequent to the date of their evaluation, nor were there any significant deficiencies or material weaknesses in the Trust’s internal controls. As a result, no corrective actions were required or undertaken.
Statement of Corporate Governance
NCE Petrofund’s Statement of Corporate Governance is included in the Information Circular for the Annual General Meeting, which is being mailed to unitholders at the same time as this Annual Report.
Forward-looking Statements
Some of the statements contained herein including, without limitation, financial and business prospects and financial outlooks, may be forward- looking statements which reflect management’s expectations regarding future plans and intentions, growth, results of operations, performance and business prospects and opportunities. Words such as “may”, “will”, “should”, “could”, “anticipate”, “believe”, “expect”, “intend”, “plan”, “potential”, “continue” and other similar expressions have been used to identify these forward- looking statements. These statements reflect management’s current beliefs and are based on information currently available to management. Forward-looking statements involve significant risk and uncertainties. A number of factors could cau se actual results to differ materially from the results discussed in the forward- looking statements, including, but not limited to, changes in general economic and market conditions and other risk factors. Although the forward-looking statements contained herein are based upon what management believes to be reasonable assumptions, we cannot assure that actual results will be consistent with these forward- looking statements. Investors should not place undue reliance on forward- looking statements. These forward- looking statements are made as of the date hereof and we assume no obligation to update or revise them to reflect new events or circumstances.
Forward- looking statements and other information contained herein concerning the oil and gas industries and our general expectations concerning these industries are based on estimates prepared by us using data from publicly available industry sources as well as from reserve report, market research and industry analysis and on assumptions based on data and knowledge of these industries which we believe to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While we are not aware of any misstatements regarding any industry data presented herein, the industries involve risks and uncertainties and are subject to change based on various factors.
