UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 6-K
REPORT OF FOREIGN ISSUER PURSUANT TO RULES 13a-16 AND 15D-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
November, 2002
NCE Petrofund
(Translation of registrant's name into English)
56 Temperance Street, 4th Floor, Toronto, Ontario, M5H 3V5
(Address of principal offices)
Unaudited Interim Financial Statements – “For the nine months ended November 30th, 2002”
Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2 (b) under the Securities Exchange Act of 1934.
Yes ______ No _XXX
NCE Petrofund
3RD QUARTER REPORT
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002
Introduction
The following discussion and analysis of financial results should be read in conjunction with the consolidated interim financial statements for the three months and nine months ended September 30, 2002 included herein.
Where amounts and volumes are expressed on a barrel of oil equivalent basis, gas volumes have been converted to barrels of oil at six thousand cubic feet per barrel. On July 6, 2001, the Trust units were consolidated on a one-for-three basis. Prior periods have been restated for comparative purposes.
All figures are in Canadian dollar values unless otherwise stated.
NCE Petrofund Highlights | ||||||||||
(unaudited) | ||||||||||
(thousands of dollars except per unit amounts) | ||||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||||
2002 | 2001 | Variance | 2002 | 2001 | Variance | |||||
Financial | ||||||||||
Revenues | $ | 70,030 | $ | 56,973 | 23% | $ | 186,237 | $ | 190,929 | (2%) |
Cash flow from operating activities | $ | 28,247 | $ | 22,433 | 26% | $ | 74,058 | $ | 91,841 | (19%) |
Cash flow available for distribution | $ | 21,629 | $ | 21,000 | 3% | $ | 70,751 | $ | 90,224 | (22%) |
Cash flow available for | ||||||||||
distribution per unit | $ | 0.40 | $ | 0.54 | (26%) | $ | 1.46 | $ | 2.80 | (48%) |
Net income | $ | 9,589 | $ | 7,715 | 24% | $ | 19,027 | $ | 50,379 | (62%) |
Net income per unit | ||||||||||
- basic | $ | 0.18 | $ | 0.20 | (10%) | $ | 0.39 | $ | 1.56 | (75%) |
- diluted | $ | 0.18 | $ | 0.20 | (10%) | $ | 0.39 | $ | 1.56 | (75%) |
Units outstanding | ||||||||||
Weighted average | 54,100 | 38,711 | 40% | 48,512 | 32,267 | 50% | ||||
Diluted | 54,199 | 38,722 | 40% | 48,546 | 32,344 | 50% | ||||
At period end | 54,102 | 38,714 | 40% | 54,102 | 38,714 | 40% | ||||
Operating | ||||||||||
Daily Production | ||||||||||
Oil (bbls) | 11,718 | 10,364 | 13% | 10,847 | 7,558 | 44% | ||||
Natural gas (mcf) | 81,431 | 71,248 | 14% | 75,845 | 64,398 | 18% | ||||
Liquids (bbls) | 1,625 | 1,372 | 18% | 1,762 | 1,377 | 28% | ||||
BOE (6:1) | 26,915 | 23,611 | 14% | 25,250 | 19,667 | 28% | ||||
Prices | ||||||||||
Oil (per bbl) | $ | 37.31 | $ | 33.64 | 11% | $ | 34.01 | $ | 36.21 | (6%) |
Natural gas (per mcf) | 3.36 | 3.27 | 3% | 3.52 | 5.83 | (40%) | ||||
Liquids (per bbl) | 31.51 | 27.43 | 15% | 26.42 | 36.23 | (27%) | ||||
Operating netback per BOE | $ | 14.99 | $ | 14.18 | 6% | $ | 14.23 | $ | 20.98 | (32%) |
For further information regarding NCE Petrofund, please contact our Investor Services Department at 1-888-739-4623
e-mail: info@nceresources.com or www.nceresources.com
Results summary
We are pleased to present the results for NCE Petrofund (or "Petrofund") for the three months and nine months ended September 30, 2002.
For the three months ended September 30, production increased 14% from 23,611 barrels of oil equivalent per day (boe/d) in 2001 to 26,915 boe/d in 2002 mainly due to the acquisition of NCE Energy Trust ("NCE Energy") effective May 30, 2002. Cash flow from operating activities increased from $22.4 million in the third quarter of 2001 to $28.2 million in the third quarter of 2002 due to the production increase and an 8% increase in prices on a boe basis to $28.31 in 2002 from $26.23 in 2001.
The West Texas Intermediate (WTI) crude oil price averaged US$28.27 in the third quarter of 2002 as compared to US$26.48 in the third quarter of 2001. This resulted in Canadian wellhead prices of $37.31 per bbl in 2002 as compared to $33.64 per bbl in 2001. The average gas price increased 3% from $3.27 per mcf in 2001 to $3.36 per mcf in 2002.
For the nine-month period ended September 30, cash flow from operating activities decreased 19% from $91.8 million in 2001 to $74.1 million in 2002 due to the lower product prices. Production increased 28% from 19,667 boe/d to 25,250 boe/d in 2002. The average oil price decreased from $36.21 per bbl in 2001 to $34.01 per bbl in 2002 after hedging adjustments. The average gas price was down 40% from $5.83 per mcf in 2001 to $3.52 per mcf in 2002.
Significant financial transactions
As noted in the second quarter report, NCE Petrofund completed the acquisition of NCE Energy Trust on May30,2002. The September 30, 2002 financial statements of NCE
Petrofund reflect the acquisition of the oil and gas properties and working capital of NCE Energy effective May 30 and include the operating income of NCE Energy effective June 1. This is the first quarterly report to include the operating results of NCE Energy for the full quarter.
Petrofund continues to source and evaluate new acquisition opportunities. Efforts have been hampered by a scarcity of properties suitable for inclusion in Petrofund's property portfolio. Those properties that were of interest to us were sold at prices significantly higher than our investment criteria could justify. We are expecting to see an increased supply of properties on the market and will actively pursue those that are of interest. In the meantime, Petrofund continues to emphasize development projects including drilling, recompletion work, workovers and optimization projects to capitalize on its significant undeveloped land base.
Operations highlights
Petrofund was very active implementing development and exploitation projects during the third quarter. Preparation and lead-in work completed during the first half of the year on our ongoing development program resulted in a high level of field activity in the third quarter. Petrofund participated in approximately 70 gross wells during the quarter (50 net wells) with an overall 95% success rate.
At Hatton, in southwestern Saskatchewan, Petrofund successfully drilled and completed 47 shallow Milk River and Medicine Hat gas wells on its 100%-owned lands. These new wells are currently being equipped and tied into existing gathering and compression infrastructure. All wells should be producing by mid to late October, adding 3,000 mcf/d of initial production and 2,000 mcf/d of stabilized production after six to eight months.
Near Medicine Hat in southeastern Alberta, Petrofund has a 10% working interest in a 212-well shallow gas drilling program that started late in the third quarter. Petrofund expects the operator to have all wells drilled and producing by year end. Petrofund expects to net 1,000 mcf/d initially from these wells (600 mcf/d stabilized).
Petrofund participated in the successful drilling of two new horizontal wells at Queensdale and Viewfield in southeastern Saskatchewan. Petrofund has a 50% interest in the Queensdale well and a 25% interest in the Viewfield well. Petrofund's net combined production from both wells is currently 150 bbl/d. An additional drilling location is currently contemplated for the Queensdale property.
At Alliance, in east-central Alberta, Petrofund drilled a 100% Dina oil well, which is currently producing 40 bbl/d. A subsequent location was drilled and abandoned. Petrofund is using additional seismic data to firm up a Dina gas location on its 100%-owned lands for possible drilling in the upcoming quarter.
At Sunchild, in west-central Alberta, the third quarter was very active for Petrofund, both as an operator and as a non-operator. As operator, Petrofund successfully drilled a Shunda gas well (50% working interest) that is currently being equipped and tied into existing infrastructure. Petrofund also took over operatorship of a 50% working interest Ostracod gas well drilled in the second quarter and is now equipping and tying it in. Petrofund participated for its 18% working interest in drilling a Belly River gas well late in the quarter. This well is currently being completed. Petrofund expects to net 1,500 mcf/d from these three new working interest wells. In addition, Petro-fund also farmed out its interest in two other Ostracod gas new drills, which have been completed and are awaiting tie-in.
At Ogston, in north-central Alberta, an oil well drilled late in the second quarter continues to provide positive results. Based on this success, Petrofund, as operator, is preparing to drill a follow-up location early in the upcoming quarter. On this same 100%-owned property, Petrofund is expanding its production facilities using surplus equipment from a non-producing property, which will result in four shut-in wells being restarted (a 30-40 bbl/d gain).
At Strachan, in west-central Alberta, Petrofund as operator successfully worked over a previously uneconomic gas well that is currently being equipped and tied in. Petrofund's net share of production is expected to be 250 mcf/d. Petrofund is also preparing to spud an operated Viking oil well early in the fourth quarter. At Three Hills, in central Alberta, several farmout wells were drilled on Petrofund lands during the third quarter. Two of these farmout wells were abandoned; the others have been cased and are awaiting completion by the operators. Petrofund, as operator, plans to drill two to three lower risk gas wells on these lands next quarter. At the nearby Innisfail property, Petrofund farmed out a portion of its 100% working interest and participated for the remainder to drill a successful Pekisko gas well late in the third quarter. This well is expected to be producing by mid to late October.
Capital expenditures
As discussed in the second quarter report, NCE Petrofund acquired NCE Energy for $167 million. The total price consisted of the issue of 7.6 million Petrofund units with an assigned value of $98.6 million and the assumption of $39.5 million of debt and negative working capital as well as transaction costs of $2.0 million. In addition, the acquisition cost includes $27 million to account for the difference between the book and tax basis of the assets acquired. The NCE Energy acquisition was in addition to $40 million incurred for property acquisitions in the first quarter.
During the nine months ended September 30, 2002, $27.1 million was also incurred for other development drilling and production enhancement activities. A summary of total expenditures for the three- and nine-month periods appears below.
Three months | Nine months | |||
ended Sept. 30, | ended Sept. 30, | |||
($000) | 2002 | 2002 | ||
Acquisitions | $ | 1,941 | $ | 211,291 |
Dispositions | (3,004) | (6,132) | ||
Net acquisitions | (1,063) | 205,159 | ||
Finding and development cost: | ||||
Land and seismic | 708 | 1,786 | ||
Drilling and completions | 8,666 | 15,238 | ||
Well equipping | 1,716 | 4,021 | ||
Tie-ins | 585 | 1,723 | ||
Facilities | 612 | 1,967 | ||
Other | 558 | 2,363 | ||
Total | 12,845 | 27,098 | ||
Total net capital expenditures | $ | 11,782 | $ | 232,257 |
Cash distributions
NCE Petrofund unitholders who held their units throughout the third quarter of 2002 received distributions of $0.42 in cash compared to $0.93 in the third quarter of 2001. A cash distribution of $0.15 per unit was paid in October and $0.15 per unit was announced for November2002. Petrofund generated cash flow available for distribution of $21.6 million in the third quarter of 2002, after the deduction of $5 million for capital expenditures.
NCE Petrofund unitholders who held their units for the nine-month period ended September 30, 2002, received distributions of $1.26 per unit in cash compared to $3.51 per unit in 2001. Petrofund generated cash flow available for distribution of $70.8 million for the nine-month period ended September 30, 2002, compared to distributions paid of $60.9million. At September 30, 2002, the Trust had $22million in distributions accruing to unitholders. There is approximately a two-month delay in collecting revenues and the payment of distributions.
Production revenue
Revenues increased 23% to $70.0 million in the third quarter of 2002 from $57.0 million in the third quarter of 2001, due to the 14% increase in production plus an 8% increase in prices on a boe basis.
For the nine-month period ended September 30, 2002, revenue decreased 2% to $186.2 million from $190.9 million in 2001 in spite of a 28% increase in production. Prices decreased 24% on a boe basis to $27.02 in 2002 from $35.55 in 2001 as a result of the significant decline in natural gas prices.
Crude oil sales increased 25% from $32.1 million in the third quarter of 2001 to $40.2 million in the third quarter of 2002 due to the 13% rise in production. Oil production volumes were 11,718 bbl/d in the third quarter of 2002 as compared to 10,364 bbl/d in the third quarter of 2001. The average price increased 11% from $33.64 per bbl in the third quarter of 2001 to $37.31 per bbl in the third quarter of 2002. The price in the third quarter of 2002 is net of a negative hedging adjustment of $3.02 per bbl.
During the nine-month period ended September 30, 2002, crude oil sales increased 35% to $100.7 million in 2002 from $74.7 million in 2001. Oil production rose to 10,847 bbl/d for the period, compared to 7,558 bbl/d for the same period in 2001. The average price declined from $36.21 per bbl in 2001 to $34.01 per bbl in 2002.
Natural gas sales increased 17% from $21.4 million in the third quarter of 2001 to $25.2 million in the third quarter of 2002 due to a 14% increase in production from 71.2 mmcf/d to 81.4 mmcf/d. The average gas price rose 3% from $3.27permcf in the third quarter of 2001 to $3.36 per mcf in the third quarter of 2002.
During the nine-month period ended September 30, 2002, natural gas sales decreased 29% to $72.9 million from $102.5 million in 2001. Gas production was up 18% to 75.8 mmcf/d from 64.4 mmcf/d for the same period in 2001. However, the average gas price decreased 40% from $5.83permcf in 2001 to $3.52 per mcf in 2002.
Sales of natural gas liquids increased 36% from $3.5million in the third quarter of 2001 to $4.7 million in 2002. Production volumes increased 18% from 1,372 boe/d in the third quarter of 2001 to 1,625 boe/d in the third quarter of 2002. The average price rose from $27.43 per bbl in the third quarter of 2001 to $31.51 per bbl in the third quarter of 2002.
For the nine-month period ended September 30, sales of natural gas liquids decreased 7% from $13.6 million in 2001 to $12.7 million in 2002. Production volumes rose 28% from 1,377 bbl/d to 1,762 bbl/d. However, the average price received fell from $36.23 per bbl in 2001 to $26.42 per bbl in 2002.
Royalties
Royalties increased to 20.4% of revenues in the third quarter of 2002 from 20.2% in the third quarter of 2001, net of the Alberta Royalty Credit.Royalties for the nine-month period ended September 30, 2002 averaged 18.6% of revenues in 2002 compared to 23.2% for the corresponding period of 2001 due to the lower average gas prices in 2002.
Field operating costs
Operating expenses increased to $18.6 million in the third quarter of 2002 compared to $14.3 million in the third quarter of 2001. This reflects property acquisitions totaling $60 million at the end of 2001 and in the first quarter of 2002 and the NCE Energy Trust acquisition effective May 30, 2002.
Operating expenses were $53.5 million for the nine-month period ended September 30, 2002 compared to $32.5 million for the same period in 2001. Operating costs for the nine months ended September 30, 2002 were $7.76 per boe as compared to $6.05 per boe for the same period in the previous year. This is due to a general increase in operating costs and normal production decline. In addition, recent acquisitions made by the Trust have a higher cost per boe, part of which is due to additional equipment, maintenance and facility upgrades. Operating costs decreased from $7.76 per boe in the second quarter of 2002 to $7.52 per boe in the third quarter mainly due to lower repair and maintenance costs.
General and administrative expenses
General and administrative costs increased from $3.1 million in the third quarter of 2001, to $4.0 million for the same period in 2002. This excludes costs associated with an offering of Trust units in the United States that was launched on
September 10, 2001, but subsequently withdrawn following the attacks on key U.S. landmarks. For the nine-month period ended September 30, 2002, general and administrative costs rose from $8.6 million excluding the U.S. offering costs, to $11.9 million. General and administrative costs per boe in 2002 decreased to $1.63 in the third quarter from $1.73 in the second quarter and from $1.83 in the first quarter.
Management fees remained constant at $1.2 million as the higher cash flow was offset by a reduction in the management fee effective January 1, 2002. Management fees for the nine-month period ended September 30, 2002 were $3.2 million, compared to $4.3 million for the same period in 2001.
Price risk management
The Trust entered into several small transactions during the quarter to protect cash flows in late 2002 and the first quarter of 2003. The Trust continues to have 4,200 bbl/d hedged for the balance of the year. This is comprised of 1,200 bbl/d at $30.00 per bbl and 3,000 bbl/d between $30.13 and $38.65per bbl. The Trust has 1,320 bbl/d fixed at $44.60 per bbl in the first quarter of 2003 and no crude hedged thereafter.
The Trust has 27.4 mmcf/d of AECO-based price hedges in place until December 31, 2002. These hedges are comprised of:
1)
8.2 mmcf/d subject to a price ceiling of $3.04 per mcf;
2)
4.8 mmcf/d with an average floor price of $3.07 per mcf;
3)
11.1 mmcf/d with an average floor price of $3.01 per mcf and an average ceiling price of $5.12 per mcf; and
4)
3.4 mmcf/d fixed at $4.22 per mcf.
The Trust's hedged volumes of natural gas decline to approximately 9.8 mmcf/d for 2003. About 5.1 mmcf/d of this volume is a contract with a price cap of $3.16 per mcf and the balance is wide collar (from $4.59 per mcf to $7.97 per mcf) in the first quarter of the year. No hedges have been transacted beyond 2003. For a complete listing of all hedge transaction details please see Note 4 to the Consolidated Interim Financial Statements.
Depletion, reclamation and abandonment
The provision for depletion and reclamation costs rose from $21.8 million in the third quarter of 2001 to $26.8 million in the third quarter of 2002 due to the 14% increase in production and an increase in depletion rate from $9.60 per boe in 2001 to $10.16 per boe in 2002. In the third quarter of 2002, NCE Petrofund Corp. ("NCEP") set aside $186,000 in cash to fund future abandonment costs. As at September30,2002, NCEP has a cash abandonment reserve of $2.8 million.
For the nine-month period ended September 30, 2002, depletion and reclamation costs increased to $76.0 million compared to $48.2 million for the same period in the previous year. The depletion rate rose from $8.54 per boe in 2001 to
$10.38 per boe in 2002. This was due to the increase in the cost of acquiring reserves and future income taxes of $110 million recorded on the 2001 corporate acquisition of Magin Energy Inc. to account for the difference between the book and the tax basis of the assets acquired.
Liquidity and capital resources
The credit facility was increased to $245.0 million in conjunction with the NCE Energy acquisition, of which $183.3 million was outstanding at September 30, 2002.
For the three months ended September 30, 2002, the Trust generated cash flow from operating activities of
$28.2 million and paid out $22.7 million in distributions. For the nine-month period the Trust generated cash flow of $74.1 million and paid out $60.9 million in distributions.
Total capital expenditures of $232.3 million were incurred during the nine-month period. The expenditures were financed by the increase in the bank loan outstanding from $128.8million at December 31, 2001 to $183.3 million at September30,2002, net proceeds of $55 million from an equity issue in the first quarter, and the issue of 7.6 million units for the purchase of NCE Energy.
NCE Petrofund Consolidated Balance Sheet | ||||
(unaudited) | ||||
(thousands of dollars) | ||||
As at September 30, 2002 and December 31, 2001 | 2002 | 2001 | ||
Assets | ||||
Current assets | ||||
Cash | $ | 10,302 | $ | 1,917 |
Accounts receivable | 15,985 | 12,965 | ||
Due from affiliates | 903 | - | ||
Prepaid expenses | 9,134 | 4,584 | ||
Total current assets | 36,324 | 19,466 | ||
Reclamation and abandonment reserve | 2,812 | 2,073 | ||
Oil and gas royalty and property interests at cost less accumulated | ||||
depletion and depreciation of $327,139 (2001 - $255,532) | 838,426 | 677,776 | ||
$ | 877,562 | $ | 699,315 | |
Liabilities and unitholders' equity | ||||
Current liabilities | ||||
Accounts payable and accrued liabilities | $ | 26,589 | $ | 21,319 |
Payable to affiliates | 899 | 1,056 | ||
Current portion of capital lease obligation | 3,839 | 5,467 | ||
Distributions payable to unitholders | 22,059 | 12,188 | ||
Total current liabilities | 53,386 | 40,030 | ||
Bank loan | 183,291 | 128,783 | ||
Capital lease obligations | 7,410 | 16,168 | ||
Future income taxes | 111,755 | 104,000 | ||
Accrued reclamation and abandonment costs | 14,397 | 11,632 | ||
Total liabilities | 370,239 | 300,613 | ||
Unitholders' equity | 507,323 | 398,702 | ||
$ | 877,562 | $ | 699,315 | |
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement. | ||||
NCE Petrofund Consolidated Statement of Operations | ||||||||
(unaudited) | ||||||||
(thousands of dollars except per unit amounts) | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
2002 | 2001 | 2002 | 2001 | |||||
Revenues | ||||||||
Oil and gas sales | $ | 70,030 | $ | 56,973 | $ | 186,237 | $ | 190,929 |
Royalties, net of incentives | (14,280) | (11,529) | (34,637) | (44,199) | ||||
55,750 | 45,444 | 151,600 | 146,730 | |||||
Expenses | ||||||||
Lease operating | 18,621 | 14,259 | 53,493 | 32,478 | ||||
Management fee | 1,207 | 1,170 | 3,189 | 4,285 | ||||
Interest and other financing costs | 2,482 | 2,909 | 6,085 | 6,030 | ||||
General and administrative | 4,035 | 4,216 | 11,907 | 9,680 | ||||
Capital taxes | 277 | 375 | 932 | 1,205 | ||||
Depletion and depreciation | 25,159 | 20,844 | 71,607 | 45,863 | ||||
Provision for reclamation and abandonment | 1,601 | 956 | 4,427 | 2,299 | ||||
53,382 | 44,729 | 151,640 | 101,840 | |||||
Net income (loss) before provision for income taxes | 2,368 | 715 | (40) | 44,890 | ||||
Provision for (recovery of) income taxes | ||||||||
Current | 188 | - | 275 | 1,072 | ||||
Future | (7,409) | (7,000) | (19,342) | (6,561) | ||||
(7,221) | (7,000) | (19,067) | (5,489) | |||||
Net income | $ | 9,589 | $ | 7,715 | $ | 19,027 | $ | 50,379 |
Net income per Trust unit | ||||||||
Basic | $ | 0.18 | $ | 0.20 | $ | 0.39 | $ | 1.56 |
Diluted | $ | 0.18 | $ | 0.20 | $ | 0.39 | $ | 1.56 |
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement. | ||||||||
NCE Petrofund Consolidated Statement of Unitholders' Equity | ||||||||
(unaudited) | ||||||||
(thousands of dollars) | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
2002 | 2001 | 2002 | 2001 | |||||
Balance, beginning of period | $ | 519,326 | $ | 342,031 | $ | 398,702 | $ | 136,812 |
Units issued, net of issue costs | 37 | 48,442 | 154,693 | 280,221 | ||||
Net income | 9,589 | 7,715 | 19,027 | 50,379 | ||||
Distributions accruing to unitholders | (21,629) | (21,000) | (65,099) | (90,224) | ||||
Balance, end of period | $ | 507,323 | $ | 377,188 | $ | 507,323 | $ | 377,188 |
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement. | ||||||||
NCE Petrofund Consolidated Statement of Cash Flows | ||||||||
(unaudited) | ||||||||
(thousands of dollars except per unit amounts) | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
2002 | 2001 | 2002 | 2001 | |||||
Cash provided by (used in) operating activities | ||||||||
Net income | $ | 9,589 | $ | 7,715 | $ | 19,027 | $ | 50,379 |
Add items not affecting cash: | ||||||||
Depletion and depreciation | 25,159 | 20,844 | 71,607 | 45,863 | ||||
Provision for reclamation and abandonment | 1,601 | 956 | 4,427 | 2,299 | ||||
Future income taxes | (7,409) | (7,000) | (19,342) | (6,561) | ||||
Actual abandonment costs incurred | (693) | (82) | (1,661) | (139) | ||||
Cash flow from operating activities | 28,247 | 22,433 | 74,058 | 91,841 | ||||
Net change in non-cash operating balances | 6,097 | (20,233) | 569 | 14,683 | ||||
Cash provided by operating activities | 34,344 | 2,200 | 74,627 | 106,524 | ||||
Financing activities | ||||||||
Bank loan | 5,782 | (21,686) | 54,508 | 30,064 | ||||
Distributions paid | (22,721) | (34,766) | (60,880) | (97,889) | ||||
Increase in capital lease obligation | - | - | - | 19,137 | ||||
Capital lease repayments | (7,432) | (1,302) | (10,387) | (1,302) | ||||
Issuance of Trust units | 37 | 48,442 | 56,054 | 123,082 | ||||
Deferred issue costs | - | (82) | - | (750) | ||||
Advances to affiliates, net (Note 2) | (3,416) | - | (38,445) | - | ||||
Cash provided by (used in) financing activities | (27,750) | (9,394) | 850 | 72,342 | ||||
Investing activities | ||||||||
Reclamation and abandonment reserve | (186) | (131) | (517) | (315) | ||||
Acquisition of property interests | (14,786) | (8,830) | (73,134) | (176,533) | ||||
Proceeds on disposition of property interests | 3,004 | (13) | 6,132 | 162 | ||||
Cash acquired on acquisition (Note 2) | - | - | 427 | - | ||||
Cash used in investing activities | (11,968) | (8,974) | (67,092) | (176,686) | ||||
Net change in cash | (5,374) | (16,168) | 8,385 | 2,180 | ||||
Cash, beginning of period | 15,676 | 20,082 | 1,917 | 1,734 | ||||
Cash, end of period | $ | 10,302 | $ | 3,914 | $ | 10,302 | $ | 3,914 |
Cash flow from operating activities per Trust unit | ||||||||
Basic | $ | 0.52 | $ | 0.58 | $ | 1.53 | $ | 2.85 |
Diluted | $ | 0.52 | $ | 0.58 | $ | 1.53 | $ | 2.84 |
Interest paid during the period | $ | 2,604 | $ | 2,919 | $ | 5,949 | $ | 6,626 |
Income taxes paid during the period | $ | 160 | $ | - | $ | 1,569 | $ | 325 |
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement. | ||||||||
NCE Petrofund Consolidated Statement of Distributions Accruing to Unitholders | ||||||||
(unaudited) | ||||||||
(thousands of dollars except per unit amounts) | ||||||||
Three months ended September 30, | Nine months ended September 30, | |||||||
2002 | 2001 | 2002 | 2001 | |||||
Distributions payable, beginning of period | $ | 23,151 | $ | 34,526 | $ | 12,188 | $ | 28,425 |
Distributions accruing during the period | ||||||||
Cash flow from operating activities | 28,247 | 22,433 | 74,058 | 91,841 | ||||
Proceeds on disposition of property interests | - | - | 946 | - | ||||
Reclamation and abandonment reserve | (186) | (131) | (517) | (315) | ||||
Capital lease repayments (2) | (1,432) | (1,302) | (4,387) | (1,302) | ||||
Capital expenditure | (5,000) | - | (5,000) | - | ||||
NCE Energy Trust cash flows (1) | - | - | 5,651 | - | ||||
Total distributions accruing during the period | 21,629 | 21,000 | 70,751 | 90,224 | ||||
Distributions paid | (22,721) | (34,766) | (60,880) | (97,889) | ||||
Distributions payable, end of period | $ | 22,059 | $ | 20,760 | $ | 22,059 | $ | 20,760 |
Distributions accruing to unitholders per Trust unit | ||||||||
Basic | $ | 0.40 | $ | 0.54 | $ | 1.46 | $ | 2.80 |
Diluted | $ | 0.40 | $ | 0.54 | $ | 1.46 | $ | 2.79 |
(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002 (see Note 2). (2) Net of $6 million refinanced by increased bank loan.
The accompanying notes to the consolidated financial statements are an integral part of this consolidated statement.
NCE Petrofund Notes to Consolidated Interim Financial Statements
September 30, 2002 and 2001 (Unaudited)
1. INTERIM FINANCIAL STATEMENTS
These unaudited consolidated interim financial statements have been prepared by management following the same accounting policies and methods of their application as the most recent annual financial statements, except as noted below. The note disclosure for annual financial statements provides additional disclosure to that required for interim financial statements. Accordingly, these interim financial statements should be read in conjunction with the audited consolidated financial statements included in NCE Petrofund's or (the "Trust's") 2001 annual report.
2. ACQUISITION OF NCE ENERGY TRUST
On May 30, 2002, NCE Petrofund acquired NCE Energy Trust for 0.2325 of a NCE Petrofund Trust unit for each NCE Energy Trust unit on a tax-free rollover basis. The value assigned to the NCE Petrofund Trust units issued on the acquisition is based on the market value of the Petrofund units at the time the acquisition was announced.
The acquisition was accounted for using the purchase method. A summary of the net assets acquired is as follows:
($000) | ||
Working capital | $ | (39,518) |
Oil and gas properties | 165,254 | |
Future income taxes | (27,097) | |
$ | 98,639 | |
Prior to the acquisition, NCE Petrofund advanced $37.3 million to NCE Energy Trust to pay down the bank debt of NCE Energy Trust.
3. TRUST UNITS | |||||
Authorized: unlimited number of Trust units | |||||
Number of units | Amount ($000) | ||||
Issued | |||||
December 31, 2001 | 41,915,740 | $ | 639,892 | ||
Issued for cash | 4,600,000 | 59,827 | |||
Issued for NCE Energy Trust | 7,573,753 | 98,639 | |||
Commissions and issue costs | - | (3,917) | |||
Options exercised | 3,733 | 40 | |||
Unit purchase plan | 8,292 | 104 | |||
September 30, 2002 | 54,101,518 | $ | 794,585 | ||
The weighted average units outstanding are as follows: | |||||
Three months ended September 30, | Nine months ended September 30, | ||||
2002 | 2001 | 2002 | 2001 | ||
Basic | 54,099,739 | 38,711,170 | 48,512,318 | 32,267,308 | |
Diluted | 54,198,724 | 38,722,130 | 48,545,676 | 32,343,714 | |
| |||||
Unit Incentive Plan
Effective for fiscal years beginning on or after January 1, 2002, the Trust adopted the recommendations of the CICA on accounting for stock-based compensation, which apply to new rights granted on or after January 1, 2002. The Trust has elected to continue to measure compensation cost based on the intrinsic value of the award at the date of grant and recognize that cost over the vesting period. As the exercise price of the rights granted approximates the market price of the Trust units at the grant date, no compensation cost has been provided in the statement of operations.
The exercise price of rights granted under the Trust's rights plan may be reduced in future periods in accordance with the terms of the rights plan. The amount of the reduction cannot be reasonably determined as it is dependent upon a number of factors including, but not limited to, future prices received on the sale of oil and natural gas, future production of oil and gas, and determination of the amounts to be withheld from future distributions to fund capital expenditures. Therefore, it is not possible to determine a fair value for the rights granted under the plan.
On July 25, 2002, 1,468,100 rights were granted at an initial exercise price of $10.65. Under the Incentive Plan, distributions per Trust unit to Petrofund unitholders in a calendar quarter, which represent a return of more than 2.5% of the net oil and gas royalty and property interests of Petrofund at the end of such quarter would result in a reduction of the exercise price of the rights. During the period from July 25 to September 30, 2002, the exercise price of the rights was reduced to $10.63.
As it is not possible to determine the fair value of rights granted under the plan, compensation cost for pro-forma disclosure purposes has been determined based on the excess of the unit price over the exercise price at the date of the financial statements. For the period from July 25, 2002 to September 30, 2002, net income would be reduced by $108,000 for the estimated compensation cost associated with rights granted under the plan on or after January 1, 2002, with negligible impact on net income per Trust unit.
4. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS
NCE Petrofund enters into various pricing mechanisms to reduce price volatility and establish minimum prices for a portion of its oil and gas production. These include fixed-price contracts and the use of derivative financial instruments.
The outstanding derivative financial instruments and physical contracts as at September 30, 2002, all of which constitute | ||||||
effective hedges, and the related unrealized gains or losses, are summarized separately below: | ||||||
Financial Gas Hedges | ||||||
Volume | Delivery | Unrealized gain | ||||
Natural Gas | Term | mcf/d | Price $/mcf | point | (loss) ($000) | |
Call option | ||||||
(purchased) | July 1, 2001 to October 31, 2002 | 6,064 | $4.91 | AECO | $ | - |
Call option | ||||||
(purchased) | July 1, 2001 to October 31, 2003 | 6,159 | $4.91 | AECO | 2,910 | |
Collar | April 1, 2002 to December 31, 2002 | 4,737 | $2.80 - $4.70 | AECO | (552) | |
Collar | April 1, 2002 to December 31, 2002 | 4,737 | $2.80 - $5.07 | AECO | (237) | |
Floor | August 1, 2002 to November 1, 2002 | 7,106 | $2.96 | AECO | - | |
Floor | August 1, 2002 to November 1, 2002 | 7,106 | $3.17 | AECO | - | |
Collar | January 1, 2003 to March 31, 2003 | 4,737 | $4.59 - $7.97 | AECO | 8 | |
Total | $ | 2,129 | ||||
Financial Oil Hedges | ||||||
Volume | Delivery | Unrealized gain | ||||
Oil | Term | bbl/d | Price $/bbl | point | (loss) ($000) | |
Fixed Price | January 1, 2002 to December 31, 2002 | 1,200 | $30.00 | Edmonton | $ | (1,941) |
Collar | April 1, 2002 to December 31, 2002 | 1,500 | $30.13 - $38.45 | Edmonton | (1,285) | |
Collar | April 1, 2002 to December 31, 2002 | 1,500 | $30.13 - $38.85 | Edmonton | (1,605) | |
Fixed Price | January 1, 2003 to January 31, 2003 | 2,000 | $44.72 | Edmonton | (68) | |
Fixed Price | February 1, 2003 to February 28, 2003 | 2,000 | $44.48 | Edmonton | (16) | |
Total | $ | (4,915) | ||||
In addition to the financial instruments, the Trust has the following physical gas contracts: | ||||||
Volume | Delivery | Unrealized gain | ||||
Natural Gas | Term | mcf/d | Price $/mcf | point | (loss) ($000) | |
Collar | April 1, 2002 to October 31, 2002 | 4,737 | $4.27 - $6.54 | AECO | $ | - |
Capped | November 1, 1999 to October 31, 2002 | 6,064 | $2.90 | AECO | (322) | |
Capped | November 1, 1999 to October 31, 2003 | 6,159 | $3.16 | AECO | (6,345) | |
Fixed | September 1, 2002 to October 31, 2002 | 9,996 | $4.22 | AECO | (123) | |
Collar | January 1, 2003 to March 31, 2003 | 14,212 | $4.59 - $7.97 | AECO | (122) | |
Total | $ | (6,912) | ||||
The gains or losses are recognized on a monthly basis over the terms of the contracts and adjust the prices received. | ||||||
Derivative financial instruments and physical contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counterparties. Market risk relating to changes in value or settlement cost of the Trust's derivative financial instruments is essentially offset by gains or losses on the underlying physical sales.
5. MANAGEMENT ADVISORY AND ADMINISTRATION AGREEMENT
Effective January 1, 2002, management fees were reduced from 3.75% of net operating income to 3.25% and acquisition fees were reduced from 1.75% of the purchase cost of oil and gas properties to 1.50%.
6. LONG-TERM DEBT
In conjunction with its acquisition of NCE Energy Trust, NCEP increased the maximum it can borrow under its credit facility. NCEP currently has a revolving working capital operating facility of $25 million and a syndicated facility of $220 million. The revolving period ends on May 30, 2003 unless extended for a further 364-day period. If not extended, the balance outstanding would be due and payable on May 30, 2004.
The limit of the syndicated facility is subject to adjustment from time to time to reflect changes in NCEP's asset base. The next review was scheduled for September 30, 2002 but has been extended to November 15, 2002.
Definitions and Descriptions
Abbreviations | Glossary of Terms | ||
bbl | barrel | boe: Barrel of oil equivalent, which | Proved reserves: Those reserves |
bcf | billion cubic feet | is determined on the basis that | estimated as recoverable with a high |
boe | barrels of oil equivalent | 6,000 cubic feet (6 mcf) of natural | degree of certainty under current tech- |
boe/d | barrels of oil equivalent per day | gas is equivalent to one barrel of oil. | nology and existing economic conditions. |
bbl/d | barrels per day | ||
mbbls | thousand barrels | Caps: A contract that establishes a | Reserve production ratio: A measure |
mboe | thousand barrels of oil equivalent | maximum price to be paid for a | of the expected future life of a resource, |
mmbtu | million British thermal units | security or commodity. See also Floors. | also known as reserve life index. Reserves |
mbbl/d | thousand barrels of oil per day | divided by production. | |
mcf | thousand cubic feet | Collars: A contract that establishes | |
mcf/d | thousand cubic feet per day | a maximum and a minimum price to | Spud: The first boring of the hole in |
mlt | thousand long tons | be paid for a security or commodity | the drilling of a well. |
mmbbls | million barrels | - a combination of a cap and a floor. | |
mmboe | million barrels of oil equivalent | Swaps: An exchange of streams of | |
mmcf | million cubic feet | Crown royalty: The government's | payments between two counterparties, |
mmcf/d | million cubic feet per day | share of a property's production. | sometimes directly and at other times |
mstb | thousand stock tank barrels | through an intermediary. | |
tcf | trillion cubic feet | Established reserves: Proved reserves | |
API | American Petroleum Institute | plus 50% of probable reserves. | Watercut: The percentage of water |
APO | after payout | produced per thousand barrels of oil. | |
ARC | Alberta Royalty Credit | Floors: A contract that establishes | |
BPO | before payout | a minimum price to be paid for a | Water flood: A method of secondary |
Gj | gigajoules | security or commodity. See also Caps. | recovery in which water is injected into |
NGLs | natural gas liquids | an oil reservoir for the purpose of washing | |
RLI | reserve life index (in years) | Netback: The amount received from | the oil out of the reservoir rock and into |
WTI | West Texas Intermediate | the sale of a barrel of oil or barrel of oil | the bore of a producing well. |
equivalent after deduction of operating | |||
costs and royalty payments. | Working interest: The interest in a | ||
lease that carries with it the rights and | |||
Net production: The working interest | obligations to develop and operate an | ||
share of gross production. | oil or natural gas property. | ||
Probable reserves: Those reserves that | |||
analysis suggests exist and whose future | |||
recovery, under current technology, is | |||
highly likely. | |||
Corporate Directory | ||
NCE PETROFUND CORP. | Jeffrey Newcommon | Peter N. Thomson 1 2 |
DIRECTORS AND OFFICERS | Senior Vice-President, Land and Exploration | Director |
John F. Driscoll 1 | John Vooglaid | Frank Potter 1 2 |
Chief Executive Officer, | Vice-President and Secretary-Treasurer | Director |
Chairman of the Board and Director | ||
Gordon M. Thompson | Sandra Cowan 2 | |
Jeffery E. Errico | Senior Vice-President, Corporate Development | Director |
President and Chief Operating Officer | ||
John Nestor | 1 Member of the Executive Committee | |
Glen Fischer | Director | 2 Member of the Audit Committee |
Senior Vice-President, Operations | ||
Richard J. Zarzeczny | ||
Vince P. Moyer | Director | |
Senior Vice-President, Finance | ||
LEGAL COUNSEL | PETROLEUM CONSULTANTS | |
Goodman and Carr | Gilbert Laustsen Jung Associates Ltd. | |
Toronto, Ontario | Calgary, Alberta | |
Burnet, Duckworth & Palmer | Paddock Lindstrom & Associates Ltd. | |
Calgary, Alberta | Calgary, Alberta | |
AUDITORS | STOCK EXCHANGE LISTINGS | |
Deloitte & Touche LLP | Toronto Stock Exchange | |
Calgary, Alberta | Symbol: NCF.UN | |
TRUSTEE AND TRANSFER AGENT | American Stock Exchange | |
Computershare Investor Services of Canada | Symbol: NCN | |
Toronto, Ontario | ||
Investor Services | Head Office | Operations Office | ||
Tel: | 416-364-9297 | The Exchange Tower | 444-7th Avenue SW | |
1-888-739-4623 | 130 King Street West | Suite 600 | ||
Fax: | 416-364-1197 | Suite 2850, P.O. Box 104 | Calgary, Alberta T2P 0X8 | |
E-mail: info@nceresources.com | Toronto, Ontario M5X 1A4 | Tel: | 403-218-8625 | |
Web site: www.nceresources.com | Tel: 416-364-8788 | Fax: | 403-269-5858 | |
1-800-563-4623 | ||||
Fax: 416-364-5615 | ||||
Certain statements contained herein may constitute forward-looking statements. The use of any of the words "anticipate", "continue", "expect" "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. These statements will involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in our forward-looking statements. These risks and uncertainties include among other things, product supply and demand, volatility of oil and gas prices, imprecision of reserve estimates, our ability to replace and expand oil and gas reserves, risks and uncertainties inherent in our oil and gas operations, market competition, our ability to generate sufficient cash flow from operations to meet our current and future obligations, our ability to access external sources of debt and equity capital, and such other risks and uncertainties described from time to time in our filings with the Ontario Securities Commission and SEDAR.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly cause this Form 6-K to be signed on its behalf by the undersigned, thereunto duly authorized.
NCE Petrofund - SEC File No. 00-115124
(Registrant)
Date - - November 22, 2002
By: _"John Vooglaid"____________
John Vooglaid, V-President, Finance
