UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 6-K

REPORT OF FOREIGN ISSUER PURSUANT TO RULE 13A-16 OR 15D-16
OF THE SECURITIES EXCHANGE ACT OF 1934

For the month of: ~~August~~November, 2003 Commission File Number: 00-115124

~~NCE~~ PETROFUND ENERGY TRUST
(Name of Registrant)

Barclay Centre 600 444 7Avenue SW Calgary, Alberta Canada T2P 0X8 ~~(Address~~ ~~of Principal Executive~~ ~~Offices)~~
(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F _____ Form 40-F X

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 X

If "Yes" is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b): N/A

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

~~NCE~~ PETROFUND ENERGY TRUST

Date: ~~August~~November 1312, 2003 By: ____________________________ Vince P. Moyer, CA Senior Vice President, Finance and CFO

EXHIBIT

Exhibit Description of Exhibit

Third Quarter Report dated November 12, 2003.

NCE PETROFUND 444 - 7th Avenue S.W Suite 600 Calgary, Alberta T2P 0X8 Telephone: (403) 218-8625 Fax: (403) 269-5858

EXHIBIT 1 News Release

CALGARY- August 13, 2003

NCE Petrofund (

NCE Petrofund announces its second quarter 2003 results.

Key items include:

a 68% increase in cash flow to $45.8 million or $0.78 per unit

a 29% increase in distributions to $0.53 per unit

a second quarter payout ratio of 69%

a first half payout ratio of 56%

the closing of a $62 million property acquisition

completion of an oversubscribed $97.5 million equity financing

the successful completion of management internalization

The Trust's results for the three and six month periods ended June 30th are as follows:

NCE Petrofund Highlights (unaudited)

	3 Months Ended June 30,			6 Months Ended June 30,
	2003	2002	Variance	2003	2002	Variance
FINANCIAL
Revenues	$95,807	$65,688	46%	$204,982	$116,207	76%
Cash flow from operating activities (1)	$45,761	$27,206	68%	$104,380	$45,811	128%
Cash flow available for distribution (2)	$36,414	$31,194	17%	$86,416	$49,121	76%
Cash flow available for distribution per unit (2)

Before allocation for capital	$0.74	$0.63	17%	$1.79	$1.08	66%
Allocation for capital	$0.12	-	-%	$0.26	$-	-%
After allocation for capital	$0.62	$0.63	(2)%	$1.53	$1.08	42%
Cash distributions paid per unit	$0.53	$0.41	29%	$1.01	$0.84	20%
Net income	$15,116	$8,535	77%	$47,292	$9,438	401%
Net income per unit
Basic	$0.26	$0.17	53%	$0.84	$0.21	300%
Diluted	$0.26	$0.17	53%	$0.83	$0.21	295%
Units and Exchangeable Shares outstanding (see note 3)
Weighted average	58,967	49,184	20%	56,562	45,672	24%
Diluted	59,067	49,184	20%	56,682	45,672	24%
At period end	65,667	54,096	21%	65,667	54,096	21%
OPERATING
Daily Production
Oil (bbls)	12,363	10,589	17%	11,817	10,404	14%
Natural gas (mcf)	86,210	75,290	15%	84,116	73,005	15%
Liquids (bbls)	1,971	2,015	(2)%	1,983	1,831	8%
BOE (6:1)	28,702	25,152	14%	27,819	24,403	14%
Prices
Oil (per bbl)	$35.75	$34.60	3%	$39.94	$32.12	24%
Natural gas (per mcf)	6.33	3.97	59%	6.98	3.61	93%
Liquids (per bbl)	32.54	27.12	20%	36.87	24.12	53%
BOE (6:1)	36.66	28.64	28%	40.69	26.30	55%
Operating netback per BOE	$20.06	$15.45	30%	$23.39	$13.81	69%
(1) See special notes.
(2) See Note 6 to interim consolidated financial statements for details.

SPECIAL NOTES

The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the three and six months ended June 30, 2003 included herein and the December 31, 2002 annual financial statements and management's discussion and analysis included in NCE Petrofund's ("Petrofund" or the "Trust"), 2002 annual report.

Where amounts and volumes are expressed on a barrel of oil equivalent basis, gas volumes have been converted to barrels of oil at 6,000 cubic feet per barrel (6 mcf/bbl).

Management uses cash flow before changes in non-cash working capital to analyze operating performance and leverage. Cash flow as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore, it may not be comparable with the calculation of similar measures for other entities. Cash 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 Canadian GAAP. All references to cash flow throughout this report are based on cash flow before changes in non-cash working capital.

FORWARD-LOOKING STATEMENTS

This discussion may include statements about expected future events and/or financial results that are forward-looking in nature and subject to risks and uncertainties. For those statements, Petrofund claims the protection of the safe harbor for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. Petrofund cautions that actual performance will be affected by a number of factors, many of which are beyond its control. Future events and results may vary substantially from what Petrofund currently foresees. Discussion of the various factors that may affect future results is contained in Petrofund's recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities. Petrofund undertakes no obligation to update publication of or revise any forward-looking statements contained herein and such statements are expressly qualified by this cautionary statement.

RESULTS SUMMARY

We are pleased to present the results for Petrofund for the three and six months ended June 30, 2003.

The results were favourable in the three and six month periods as compared to the prior year due to production increases and strong commodity prices.

Production increased 14% to 28,702 barrels of oil equivalent per day ("boe/d") in the second quarter of 2003 from 25,152 boe/d in 2002 due to a number of acquisitions in 2002, the most significant being NCE Energy Trust, which was acquired effective May 30, 2002. In addition, the quarter included prior period adjustments received from other operators of approximately 1,000 boe/d. Cash flow from operations increased 68% to $45.8 million in the second quarter of 2003 from $27.2 million in the second quarter of 2002. Prices on a boe basis increased 28% to $36.66 in 2003 from $28.64 in 2002.

The West Texas Intermediate (WTI) crude oil price averaged US$28.91 in the second quarter of 2003 as compared to US$26.25 in the second quarter of 2002. This resulted in Canadian wellhead prices of $35.75/bbl in 2003 as compared to $34.60/bbl in 2002. The average gas price increased 59% from $3.97/mcf in 2002 to $6.33/mcf in 2003.

For the six month period ended June 30, 2003 cash flow from operating activities increased 128% from $45.8 million in 2002 to $104.4 million in 2003. The average oil price increased from $32.12/bbl in 2002 to $39.94/bbl in 2003. The average gas price was up 93% from $3.61/mcf in 2002 to $6.98/mcf in 2003.

The net income for the three and six month periods ended June 30, 2003 of $15.1 million and $47.3 million, respectively, was impacted by one-time adjustments for costs of the internalization of the management contract and the reduction of income taxes for the decrease in future tax rates. The net income was reduced by $29.1 million and $30.8 million for the three and six month periods for management internalization costs and increased by $26.0 million and $29.3 million, respectively, for future tax rate reductions.

The Canadian dollar averaged $0.663 per U.S. dollar in the first quarter; however, it significantly strengthened to average $0.716 per U.S. dollar in the second quarter, which negatively affected the Canadian oil price received for the second quarter.

SIGNIFICANT FINANCIAL TRANSACTIONS

As disclosed in the previous quarterly report, Unitholders of the Trust voted over 90% in favour of the resolution for the internalization of management at the Annual and Special Meeting held on April 16, 2003. The transaction closed on April 29, 2003 and the majority of the costs have been expensed this quarter. As a result of the internalization, NCE Petrofund Management Corp. (the "Manager"), and NCE Management Services Inc. ("NMSI"), which employs all of the Calgary-based personnel who provide services to the Trust and NCE Petrofund Corp ("NCEP"), became wholly-owned subsidiaries of NCEP. All management, acquisition and disposition fees payable to the Manager were eliminated effective January 1, 2003 and the Trust's operations have been consolidated in NCEP's Calgary offices. To ensure an orderly transition of the services formerly provided by the Manager through its office in Toronto, NCEP entered into an agreement with Sentry Select Capital Corp. ("Sentry") to provide certain of these services to the Trust and NCEP until December 31, 2003 for a maximum cost of $2 million. The amount incurred decreased from $1 million in the first quarter to $500,000 in the second quarter and will decrease further to $250,000 in the third and fourth quarters, after which Sentry will no longer provide such services. Sentry is a company in which John Driscoll, Chairman of the Board of Directors, owns a controlling interest.

The elimination of management fees and the reduction in general and administrative costs resulting from the streamlining and consolidation of the on-going management in Calgary, have improved the long-term operating structure of the Trust. General and administrative costs were $1.65 per boe in 2002 and decreased to $1.43 in the first quarter and to $1.27 in the second quarter of 2003. The internalization was accretive to Petrofund's net asset value, distributions and cash flow per unit.

In addition, Petrofund's governance structure has been revised to reflect current "best practices", with unitholders having the right to designate all of the nominees to be elected directors of NCEP. The Board has established Audit, Human Resources and Compensation, Governance and Reserve Committees. All committees are composed solely of directors that are unrelated to management.

The elimination of management fees and the increased management ownership increased the alignment of interests of unitholders and management. Petrofund's competitiveness for acquisitions is expected to improve due to the elimination of acquisition and disposition fees. The completion of the internalization is expected to enhance the attractiveness of the units to potential investors and expand the investor base, which may result in a lower cost of capital.

The cost of the internalization to NCEP was approximately $31 million, consisting of the issue of 1,939,147 exchangeable shares, 100,244 Trust Units, and cash of approximately $7.9 million, including $3.4 million to repay indebtedness owing by the Manager. Initially, each Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio will be adjusted from time to time to reflect distributions paid on each Trust Unit after the closing date. The purchase price was determined taking into account numerous factors, including a fairness opinion by CIBC World Markets, who were retained by a special committee of the Board of Directors formed to consider this transaction and negotiate the terms of the internalization.

In the second quarter of 2003, NCEP closed the acquisition of a diverse group of oil and gas properties for $61.7 million after adjustment. The purchase was accretive to distributable cash flow, production per unit and reserves per unit. The properties added established reserves of 9.7 million boe as estimated by independent engineering firm, Gilbert Laustsen Jung. At the time of acquisition, production from the properties was approximately 2,300 boe/d of which 42% was gas. Production and cash flow for the month of June have been included in this report. Net revenue of $4.3 million from the effective date to May 31, 2003 was applied against the purchase price. The properties contain a large percentage of unit production, and have an RLI of 11.6 years. This purchase, when combined with the acquisitions completed in the first quarter, replaces over 100% of Petrofund's 2002 annual production.

On May 22, 2003, Petrofund closed a "bought deal" financing of trust units raising gross proceeds of $97.5 million. A total of 9.2 million units were issued at $10.60 per unit. The net proceeds were used to pay down debt.

OPERATIONAL HIGHLIGHTS

Development drilling is a key component of Petrofund's strategy to generate sustainable cash flow.

A total of eighteen wells were drilled on Petrofund lands during the quarter; four working interest wells (2.1 net wells) and fourteen farmout wells. This drilling activity resulted in two oil wells, fourteen gas wells and two dry holes, for an overall success rate of 89%. Year-to-date Petrofund participated in 69 wells (13.1 net) and farmed out 14 wells for an overall success rate of 95%.

At Hatton in southwestern Saskatchewan, Petrofund drilled two 100% working interest shallow gas wells late in the quarter. Drilling will continue throughout the third quarter as 87 gross wells (81 net wells) are planned. Production from these new wells is expected to commence early in the fourth quarter.

At Strachan in west central Alberta, Petrofund, as operator, completed, equipped and tied-in two high working interests wells drilled earlier in 2003. Petrofund also equipped and tied-in third Strachan non-producing gas well. Collectively, these three Strachan wells have added 1,250 mcfd net to Petrofund's production base. As well, Petrofund equipped and tied-in a previously non-producing gas well located on its nearby Sylvan Lake lands, adding 300 mcfd net.

At Eyehill in east central Alberta, Petrofund commenced waterflood operations in a 100% WI Sparky oil pool during the quarter. This waterflood is forecast to significantly boost Eyehill productivity and reserves.

At Provost in east central Alberta, five farmout wells were drilled on Petrofund lands, resulting in three gas wells and two dry holes.

At Jenner and Armada in southeastern Alberta, three farmout wells were drilled and cased for gas. These are currently being production tested.

At Three Hills Creek in central Alberta, the appraisal of Petrofund's lands for coalbed methane potential continued with the farmee drilling four additional wells during the quarter. The farmee is presently production testing these new wells as well as several previously drilled coalbed methane wells. Coalbed methane drilling will carry on throughout the remainder of this year at no cost to Petrofund.

At report time, Petrofund was actively involved in working over several gas wells located on its Fort Saskatchewan property that was acquired in early 2003. Additional workovers have been identified for the third quarter.

Petrofund conducts an active abandonment and reclamation program to return well and facility sites back to their natural state. This year's program commenced in the second quarter and includes the abandonment of approximately 60 wells as well as ongoing reclamation work associated with previously abandoned sites.

CAPITAL EXPENDITURES

Petrofund acquired Solaris Oil and Gas Inc. in the first quarter and oil and gas properties from a major Canadian oil and gas company in the second quarter. These acquisitions, along with some minor property purchases, have resulted in total year-to-date expenditures of $77.2 million.

During the three and six months ended June 30, 2003, $12.8 and $29.5 million, respectively, has been incurred for development drilling and the other production enhancement activity discussed under Operational Highlights. These activities are very instrumental in offsetting part of the decline on existing production. Total capital expenditures for these activities in 2003 are expected to be in the $60 million range.

A summary of expenditures for the periods appear below:

	Three months Ended June 30,	Six months Ended June 30,
	2003	2003
	(thousands of dollars)
Acquisitions	$64,313	$77,205
Dispositions	(87)	(616)
Net acquisitions	64,226	76,589
Finding & development costs:
Land and seismic	954	1,684
Drilling & completions	5,047	15,782
Well equipping	1,815	4,202
Tie-ins	1,344	1,945
Facilities	2,027	3,879
Other	1,581	2,045
Total	12,768	29,537
Total net capital expenditures	$76,994	$106,126

CASH DISTRIBUTIONS

NCE Petrofund unitholders who held their units throughout the second quarter of 2003 received distributions of $0.53 per unit in cash as compared to $0.41 in the second quarter of 2002. A cash distribution of $0.18 per unit was paid in July and $0.18 per unit has been announced for August and indicated for September.

Petrofund generated cash flow available for distribution in the second quarter of $43.9 million, or $0.74 per unit before deducting $7.5 million or $0.12 per unit for reinvestment in capital projects. Of the $43.9 million, $30.4 million was paid out in distributions representing a payout ratio of 69% (see Note 6).

Petrofund unitholders who held their units for the six month period ended June 30, 2003, received distributions of $1.01 per unit in cash compared to $0.84 per unit in 2002. Petrofund generated cash flow available for distributions of $101.4 million before deducting $ 15.0 million or $0.26 per unit for reinvestment in capital projects. Of the $101.4 million, $56.4 million was paid out in distributions representing a payout ratio of 56% (see Note 6).

For the 12 months ended June 30, 2003, the Trust generated cash flow available for distribution of $165.4 million, withheld $25.0 million for reinvestment in development drilling and other projects, and paid out distributions of $103.5 million, resulting in a payout ratio of 63%. The Trust is continuing its policy of stabilizing monthly distributions and reinvesting a portion of its cash flow for the long-term benefit of the Trust.

Future distributions will depend on several factors, including future prices and capital expenditure needs. In higher price environments, a larger percentage of the Trust's cash flow will be retained for re-investment and to ensure more consistent monthly distributions.

PRODUCTION REVENUE

Revenues increased 46% to $95.8 million in the second quarter of 2003 from $65.7 million in the second quarter of 2002 as production increased 14% to 28,702 boe/d and prices were up 28% on a boe basis.

For the six month period ended June 30, 2003, revenue increased 76% to $205.0 million from $116.2 million in 2002 due to a 14% increase in production to 27,819 boe/d and an increase in the average price per BOE to $40.69 in 2003 from $26.30 in 2002.

Crude oil sales increased 21% from $33.3 million in the second quarter of 2002 to $40.2 million in the second quarter of 2003. Oil production volumes increased 17% to 12,363 bbl/d in the second quarter of 2003 as compared to 10,589 in the second quarter of 2002. The average price was up 3% from $34.60 per bbl in the second quarter of 2002 to $35.75 in the corresponding period of 2003. These prices are net of negative oil hedging adjustments of $0.22 per bbl in 2003 and $2.06 per bbl in 2002.

During the six month period ended June 30, 2003, crude oil sales increased 41% to $85.4 million in 2003 from $60.5 million in 2002. Oil production rose to 11,817 bbl/d for the period, compared to 10,404 bbl/d for the same period in 2002. The average price increased from $32.12 per bbl in 2002 to $39.94 per bbl in 2003.

Natural gas sales increased 83% from $27.2 million in the second quarter of 2002 to $49.7 million in the second quarter of 2003. Gas production increased 15% from 75.3 mmcf/d to 86.2 mmcf/d and the average gas price was up 59% from $3.97 per mcf to $6.33 per mcf. These prices are net of negative gas hedging adjustments of $0.19 per mcf in 2003, and $0.03 per mcf in 2002. The AECO monthly spot gas prices increased from $4.42 per mcf in the second quarter of 2002 to $6.91 per mcf in the second quarter of 2003.

During the six month period ended June 30, 2003, natural gas sales increased 123% to $106.2 million from $47.7 million in 2002. Gas production was up 15% to 84.1 mmcf/d from 73.0 mmcf/d for the same period in 2002. The average gas price increased 93% from $3.61 per mcf in 2002 to $6.98 per mcf in 2003.

Sales of natural gas liquids increased 17% to $5.8 million in the second quarter of 2003, from $5.0 million in the second quarter of 2002. Production was down 2% to 1,971 bbl/d from 2,015 bbl/d. The average price was $32.54 per bbl in the second quarter of 2003, as compared to $27.12 in the same period in the prior year.

For the six month period ended June 30, 2003, sales of natural gas liquids increased 66% from $8.0 million in 2002 to $13.2 million in 2003. Production volumes increased 8% from 1,831 bbl/d to 1,983 bbl/d, while the average price received rose from $24.12 per bbl to $36.87 per bbl in 2003.

ROYALTIES

Royalties (net of the Alberta Royalty Credit) were 22% of revenues in the second quarter of 2003, as compared to 19% in the second quarter of 2002. The percentage increase was mainly due to the significant increase in average gas prices, which were up 59%. The Crown royalty rate increases as gas prices increase.

Royalties for the six month period averaged 22.1% of revenue in 2003 compared to 18% for the corresponding period in 2002.

FIELD OPERATING COSTS

Operating expenses were $22.4 million in the second quarter of 2003 compared to $17.8 million in the second quarter of 2002. Operating costs on a boe basis increased to $8.58 in 2003 from $7.76 for the same period in the prior year.

Operating costs for the six month period ended June 30, 2003, were up 5.6% to $8.34 per boe as compared to an average of $7.90 in the prior year.

Power costs were 70% higher in the first half of 2003 as compared to the same period in the prior year. 2003 is also the initial year of processing fees payable on the Weyburn property. These fees result from capital expenditures incurred on behalf of Petrofund by the operator for the last three years.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative costs were $3.3 million in the second quarter of 2003, as compared to $4.0 million for the same period in 2002. Costs were down significantly on a boe basis to $1.27 in 2003 from $1.73 in 2002 due to reduced costs and an increase in production.

Costs per boe decreased from $1.65 per boe in 2002 to $1.43 in the first quarter and to $1.27 in the second quarter reflecting the consolidation of activities in Calgary and a decrease in quarterly payments due under the transitional services agreement with Sentry.

No management fees were payable in the first half of 2003 and no future fees will be paid due to the internalization of management. Fees of $2.0 million were paid in the first half of 2002 to the Manager.

PRICE RISK MANAGEMENT

Crude oil hedged volumes for the balance of 2003 are 4,000 bbl/d, down from 4,900 bbl/d at the end of the first quarter due to expiring second quarter hedges. The gas volumes under hedges for the balance of 2003 were also down slightly, decreasing from 38.5 mmcf/d to 35.7 mmcf/d.

The Trust's portfolio of crude hedges for the balance of 2003 consists of 2,000 bbl/d @ $38.07/bbl and 2,000 bbl/d collared between $33.35/bbl and $41.44/bbl. Petrofund will lose the floor protection on all of the collared volumes for any month WTI retreats below $27.96/bbl ($20.75 US); however, in this event the Trust will still receive a premium of $5.39/bbl ($4.00 US). At June 30, 2003, the Trust had 2,500 bbl/d collared for 2004, and no crude hedged thereafter.

After the end of the quarter, the Trust extended crude oil hedges into 2004 and hedged more natural gas as several deals were placed for the summer of 2004. By the end of July, Petrofund had increased its hedged position for 2004 to 3,000 bbl/d of crude and 10.0 mmcf/d of natural gas. Specific hedges placed subsequent to the end of the second quarter are: 9.5 mmcf/d gas collared between $5.15/mcf and $7.25/mcf from April 2004 to October 2004; 2,000 bbl/d crude oil collared between $32.34/bbl and $38.00/bbl from April 2004 to June 2004; 1,000 bbl/d crude oil fixed at $41.19/bbl for August 2003.

DEPLETION, RECLAMATION AND ABANDONMENT

The provision for depletion and reclamation costs increased from $24.8 million in the second quarter of 2002 to $29.6 million in the second quarter of 2003 due to the 14% increase in production and an increase in the depletion rate from $10.83 per boe in 2002 to $11.34 per boe in 2003.

The provision for depletion and reclamation costs for the six months ended June 30, 2003, was $57.5 million, or $11.41 per boe as compared to $49.3 million or $11.15 per boe for 2002. The increase was due to the downward revision to reserves at December 31, 2002. The cost of the proven reserves acquired during the first half of 2003 was in the $9.00 range, which offset part of the increase.

In the second quarter of 2003, NCEP set aside $196,000 in cash to fund future abandonment costs. NCEP has a cash abandonment reserve of $3.4 million at June 30, 2003. This cash fund is in place to fund significant future reclamation costs, such as the decommissioning of a major facility.

NCEP has an established program in place to manage its ongoing well-abandonment liabilities. Approximately $3.0 million is scheduled for these activities in 2003. This amount is deducted directly from distributions accruing to Unitholders

DEBT

As at June 30, 2003, the amount outstanding on the credit facility was $160 million with $105 million available to finance future activities.

The revolving period on the syndicated facility was scheduled to end on May 30, 2003; however, it has been extended for an additional 364-day period ending May 28, 2004. The borrowing base was increased to $265 million, in conjunction with the closing of the recent acquisition.

WORKING CAPITAL

Accounts receivable decreased by $19.0 million as amounts due on the sale of properties as at December 31, 2002 were received in the first half of 2003.

Current liabilities increased by $30.0 million from December 31, 2002, due to the increase in distributions payable to unitholders.

LIQUIDITY AND CAPITAL RESOURCES

During the six months ended June 30, 2003, the Trust incurred $106.1 million of capital expenditures. The expenditures were financed by the following:

In addition cash distributions accruing to unitholders exceeded distributions paid by $30 million and the bank loan was paid down by $46.9 million.

NCE Petrofund Consolidated Statement of Operations

Three months ended June 30,

Six months ended June 30,

(thousands of dollars, except per unit amounts)

The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.

NCE Petrofund Consolidated Statement of Unitholders' Equity

	Three months ended June 30,					Six months ended June 30,
		2003		2002		2003		2002
				(thousands of dollars)
Balance, beginning of period	$	462,702	$	437,950	$	480,097	$	398,702
Units issued, net of issue costs		96,402		98,385		96,833		154,656
Exchangeable shares issued		21,718		-		21,718		-
Redemption of exchangeable shares		(698)		-		(698)		-
Net income		15,116		8,535		47,292		9,438
Distributions accruing to unitholders		(36,414)		(25,544)		(86,416)		(43,470)
Balance, end of period	$	558,826	$	519,326	$	558,826	$	519,326

The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.

NCE Petrofund Consolidated Statement of Cash Flows

	Three months ended June 30,					Six months ended June 30,
		2003		2002		2003		2002
			(thousands of dollars, except per unit amounts)
Cash provided by (used in) operating activities
Net income	$	15,116	$	8,535	$	47,292	$	9,438
Add items not affecting cash:
Depletion and depreciation		28,249		23,458		54,740		46,448
Provision for reclamation and abandonment		1,366		1,330		2,721		2,826
Future income taxes		(27,872)		(5,360)		(30,799)		(11,933)
Actual abandonment costs incurred		(213)		(757)		(336)		(968)
Internalization of management contract (Note 4)		29,115		-		30,762		-
Cash flow from operating activities		45,761		27,206		104,380		45,811
Net change in non-cash working capital balances		(3,955)		(66,933)		19,488		(40,558)
Cash provided (used in) by operating activities		41,806		(39,727)		123,868		5,253
Financing activities
Bank loan		(46,899)		25,536		(52,702)		48,726
Distributions paid		(30,440)		(20,134)		(56,427)		(38,159)
Redemption of exchangeable shares		(698)		-		(698)		-
Capital lease repayments		(953)		(1,491)		(1,888)		(2,955)
Issuance of trust units		95,281		(254)		95,712		56,018
Cash provided by (used in) financing activities		16,291		3,657		(16,003)		63,630
Investing activities
Reclamation and abandonment reserve		(196)		(172)		(378)		(331)
Acquisition of property interests		(77,081)		(8,359)		(102,066)		(58,348)
Proceeds on disposition of property		87		(3)		616		3,128
Cash acquired on acquisition		-		427		-		427
Internalization of management contract (Note 4)		(6,274)		-		(7,921)		-
Cash used in investing activities		(83,464)		(8,107)		(109,749)		(55,124)
Net change in cash		(25,367)		(44,177)		(1,884)		13,759
Cash (bank overdraft), beginning of period		21,911		59,853		(1,572)		1,917
Cash (bank overdraft), end of period	$	(3,456)	$	15,676	$	(3,456)	$	15,676
Interest paid during the period	$	2,159	$	2,345	$	4,435	$	3,345
Income taxes paid (recovered) during the period	$	236	$	(37)	$	375	$	1,409

The accompanying notes to consolidated financial statements are an integral part of these consolidated statements.

Notes to Interim Consolidated Financial Statements (unaudited) (thousands of dollars except per unit amounts unless otherwise stated)

1. INTERIM FINANCIAL STATEMENTS

These unaudited interim consolidated financial statements follow the same accounting policies and methods of their application as the most recent annual financial statements. The note disclosure requirements for annual statements provide additional disclosures to that required for interim statements. Accordingly, these statements should be read in conjunction with the audited consolidated financial statements of NCE Petrofund (the "Trust") as at December 31, 2002 and 2001 and for each of the years in the three-year period ended December 31, 2002.

2. ACQUISITION

On February 7, 2003, NCE Petrofund Corp. ("NCEP") acquired 100% of the outstanding common shares of Solaris Oil & Gas Inc. for $7.4 million in cash and assumed $1.2 million of debt including negative working capital and outstanding bank loan. The acquisition was accounted for using the purchase method. A summary of the net assets acquired is as follows:

Working capital	$ (813)
Oil and gas properties	13,219
Bank loan	(370)
Future income taxes	(4,676)
	$ 7,360

3. TRUST UNITS

Authorized: unlimited number of trust units

	Number
	of units	Amount
Issued
December 31, 2002	54,107,764	$	794,352
Issued for cash	9,200,000		97,520
Issued for internalization of management contract	100,244		1,123
Commissions and issue costs	-		(5,223)
Options exercised	316,033		3,362
Unit purchase plan	4,297		52
June 30, 2003	63,728,338	$	891,186

The weighted average units/exchangeable shares outstanding are as follows:

	Three months			Six months
	ended June 30,		ended June 30,
	2003	2002	2003	2002
Basic	58,967,204	49,184,166	56,561,904	45,672,320
Diluted	59,067,223	49,184,166	56,682,075	45,672,320

Units/exchangeable shares, at end of period:

	As at June 30,
	2003	2002
Trust units outstanding	63,728,338	54,096,369
Trust units issuable on exchangeable
shares outstanding (Note 5)	1,939,147	-
	65,667,485	54,096,369

4. INTERNALIZATION OF MANAGEMENT

On April 29, 2003, NCE Petrofund Corp. ("NCEP") purchased 100% of NCE Petrofund Management Corp. (the "Manager"), the manager of the Trust and NCE Management Services Inc., which employed all of the Calgary based personnel who provide services to the Trust. As a result of these transactions, all management acquisition and disposition fees payable to the Manager were eliminated retroactive to January 1, 2003. In addition, all of the Trust's operations are now consolidated in NCEP's Calgary offices.

The total consideration paid was $30.8 million as detailed below.

Total Consideration	$ 000's
Issuance of 1,939,147 exchangeable shares
to the shareholder of the Manager	$ 21,718
Cash payment to fund the repayment of indebtedness
owing by the Manager	3,400
Issuance of 100,244 units to executive management	1,123
Cash payment to executive management	780
Cash payment for distributions on exchangeable shares
and trust units from January 1
to April 30, 2003	1,326
Transaction costs	2,415
Total Purchase Price	$ 30,762

To ensure an orderly transition of the services that were provided by the Manager through its offices in Toronto, NCEP entered into an agreement with Sentry Select Capital Corp. ("Sentry") to provide certain services to the Trust and NCEP until December 31, 2003 for a maximum cost of $2 million. The amount incurred decreased from $1 million in the first quarter to $500,000 in the second quarter, and will decrease further to $250,000 in the third and fourth quarters, after which Sentry will no longer provide such services. Sentry is a company in which John Driscoll, the Chairman of the Board of Directors of NCEP, owns a controlling interest.

Prior to the acquisition, the Manager was paid a management fee equal to 3.25% of net operating income plus Alberta Royalty Credit, an investment fee equal to 1.50% of the purchase price of all properties purchased by NCEP and a disposition fee of 1.25% of properties sold, except replacement properties.

5. EXCHANGEABLE SHARES

The number of exchangeable shares to be issued in connection with the internalization of the management contract was determined based on a negotiated value of $12.17 per share as set out in the Information Circular dated March 10, 2003. For accounting purposes, the 1,939,147 exchangeable shares were deemed to be issued at the value of $11.20 per share being the average trading value of the trust units for the last ten days prior to the closing date. Initially, each Exchangeable Share was exchangeable into one Trust Unit. The exchange ratio is adjusted from time to time to reflect the per unit distributions paid to unitholders after the closing date. Under the terms of the Exchangeable Share Agreement, the holder of the Exchangeable Shares is entitled to redeem for cash the number of shares equal to the cash distributions that would have been received had the Exchangeable Shares been converted to trust units. As a result of the redemption feature, the number of trust units issuable upon conversion is expected to remain constant over time. As the substance of this feature is to allow the holder of the Exchangeable Shares to receive cash distributions, the redemption has been accounted for as a distribution of earnings rather than a return of capital. At June 30, 2003, 1,881,263 Exchangeable Shares were outstanding, at an exchange ratio of 1.03077 per Trust Unit.

		Amount
Issued and Outstanding	Number of Shares	$ 000's
Issued for internalization of Management Contract	1,939,147	$21,718

Redemption of Shares	(57,884)	-
Exchanged for Trust Units	-	-
Balance, June 30, 2003	1,881,263	21,718
Exchange ratio, end of period	1.03077	-
Trust Units issuable upon conversion	1,939,147	$21,718

6. DISTRIBUTIONS ACCRUING TO UNITHOLDERS

Under the terms of the Trust Indenture, the Trust makes monthly distributions on the last business day of each month ("Cash Distribution Date"). Distributions are equal to amounts received by the Trust on the Cash Distribution Date less permitted expenses. Distributions to Unitholders coincide with receipts of royalty income, other income and other cash receipts from NCEP. An overall analysis is as follows:

For the period ended	Cash Distribution Date		2003		2002
November 30	January 31	$	0.15	$	0.15
December 31	February 28		0.16		0.15
January 31	March 31		0.17		0.13
February 28	April 30		0.17		0.13
March 31	May 31		0.18		0.14
April 30	June 30		0.18		0.14
Cash distributions paid per Trust unit		$	1.01	$	0.84

Reconciliation of Distributions Accruing to Unitholders
		Three months				Six months
		ended June 30				ended June 30
		2003		2002		2003		2002
Distributions payable, beginning of period	$	54,080	$	12,090	$	30,065	$	12,188
Distributions accruing during the period
Cash flow
from operating activities	45,761		27,206		104,380		45,811
Redemption of exchangeable shares		(698)		-		(698)		-
Proceeds on disposition of property interests		-		-		-		945
Reclamation and abandonment reserve		(196)		(172)		(378)		(331)
Less capital lease repayment		(953)	(1,491)		(1,888)		(2,955)
Capital expenditures	(7,500)			-	(15,000)			-
Total distributions accruing during the period		36,414		25,543		86,416		43,470
NCE Energy Trust cash flow (1)		-		5,651		-		5,651
Total distributable income for the period		36,414		31,194		86,416		49,121
Distributions paid
Distributions payable, end of period	$	60,054	$	23,150	$	60,054	$	23,150
Distributions accruing to unitholder per Trust unit
Basic	$	0.62	$	0.63	$	1.53	$	1.08
Diluted	$	0.62	$	0.63	$	1.52	$	1.08
(1) Remaining undistributed cash flow of NCE Energy Trust on May 30, 2002.

7. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS

The Trust 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 June 30, 2003, all of which constitute effective hedges, and the related unrealized gains or losses, are summarized separately below:

Gas Hedges
				Unrealized
		Volume	Price	Delivery		Gain
Natural Gas Term		mcf/d	$/mcf	Point		(Loss)
Fixed	March 1, 2003 to	6,159	$5.75	AECO	$	(428)
	October 31, 2003
Collar	April 1, 2003 to	9,475	$4.64-$6.23	AECO		(538)
	October 31, 2003
Collar	April 1, 2003 to	4,737	$4.64-$6.23	AECO		(230)
	October 31, 2003
Collar	April 1, 2003 to	4,737	$4.64-$6.24	AECO		(258)
	October 31, 2003
Collar	April 1, 2003 to 14,212		$5.86-$9.60	AECO		353
	October 31, 2003
Collar	April 1, 2003 to	4,737	$5.86-$9.82	AECO		119
	October 31, 2003
Collar	November 1, 2003	9,475	$5.80-$10.87	AECO		342
	to March 31, 2004
Collar	November 1, 2003	9,475	$5.80-$10.98	AECO		288
	to March 31, 2004
Total					$	(352)

Oil Hedges
				Unrealized
				Delivery		Gain
Oil	Term	bbl/d	$/bbl	Point		(Loss)
Fixed
Price	July 1, 2003 to	2,000	$38.07	Edmonton	$	(342)
	December 31, 2003
Three Way
Collar	July 1, 2003 to	2,000	(1)	Edmonton		(182)
	December 31, 2003
Collar	January 1, 2004
	to March 31, 2004	2,000	$32.34-$37.39	Edmonton		(203)
Three Way
Collar	January 1, 2004	2,000	(2)	Edmonton		(306)
	to June 30, 2004
Three Way
Collar	July 1, 2004 to	2,000	(3)	Edmonton		(58)
	December 31, 2004
Total					$(1,091)

*(1)	At Prices above $41.44, Petrofund receives $41.44/bbl. At Prices between $33.35 and $41.44/bbl Petrofund receives the market price. At Prices below $27.96, Petrofund receives a premium of $5.39/bbl.
*(2)	At Prices above $38.74, Petrofund receives $38.74/bbl.
	At Prices between $32.34 and $38.74/bbl Petrofund receives the market price.
	At Prices below $28.30, Petrofund receives a premium of $4.04/bbl.
*(3)	At Prices above $39.08, Petrofund receives $39.08/bbl.
	At Prices between $32.69 and $39.08/bbl Petrofund receives the market price.
	At Prices below $28.65, Petrofund receives a premium of $4.04/bbl.

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 hedge contracts involve a degree of credit risk, which the Trust controls through the use of financially sound counter parties. 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.

8. BANK LOAN

The revolving period on the syndicated facility was scheduled to end on May 30, 2003, however, it has been extended for an additional 364-day period ending May 28, 2004. In addition, the borrowing base on the facility was increased to $265 million from $250 million in conjunction with the closing of the most recent acquisition.

9. FUTURE INCOME TAXES

The future income tax recovery for the three months and six months ended June 30, 2003, has been increased by $26.0 million and $29.3 million, respectively, due to the substantively enacted reduction in federal and Alberta income tax rates. The changes, to be phased in over five years, reduce the applicable rate on resource income from 28% to 21%.

CORPORATE DIRECTORY

NCE PETROFUND CORP. DIRECTORS AND OFFICERS

Jeffery E. Errico	John F. Driscoll
President and Chief Executive Officer	Chairman of the Board and Director
Jeffrey Newcommon	James E. Allard 2,3
Executive Vice-President	Director
Glen Fischer	Sandra Cowan 1,4
Senior Vice-President, Operations	Director
Vince P. Moyer	Jeffery E. Errico
Senior Vice-President, Finance and	Director
Chief Financial Officer
	Wayne M. Newhouse 3,4
Noel Cronin	Director
Vice-President, Production

	Frank Potter 1, 2,4
Hugo Potts	Director
Corporate Secretary
	Peter N. Thomson 1, 2,3
	Director
1 Member of the Governance Committee	3 Member of Reserves Audit Committee
2 Member of the Audit Committee	4 Member of Human Resources and Compensation Committee
LEGAL COUNSEL	PETROLEUM CONSULTANTS
Goodman and Carr, LLP	Gilbert Laustsen Jung Associates Ltd
Toronto, Ontario	Calgary, Alberta
Burnet, Duckworth & Palmer, LLP	STOCK EXCHANGE LISTINGS
Calgary, Alberta	Toronto Stock Exchange
	Symbol: NCF.UN
AUDITORS	American Stock Exchange
Deloitte & Touche LLP	Symbol: NCN
Calgary, Alberta
TRANSFER AGENT
Computershare Investor Services of Canada
Calgary, Alberta

Canadian Ownership

As at July 31, 2003, based on the information provided by our transfer agent, NCE Petrofund estimates that Canadian ownership of the trust was approximately 59%. Management will continue to monitor ownership levels closely in conjunction with an active program to encourage and promote Canadian ownership.

NCE Petrofund

NCE Petrofund is a royalty trust that acquires and manages producing oil and gas properties in Western Canada. The Trust derives its income from these properties and distributes the resulting cash flow monthly to unitholders. NCE Petrofund is one of the oldest and most experienced oil and gas royalty trusts in Canada. The Trust began its first full year of operations in 1989. It trades on the Toronto Stock Exchange under the symbol NCF.UN. It trades on the American Stock Exchange under the symbol NCN.

Disclaimer

This news release shall not constitute an offer to sell, or the solicitation of an offer to buy NCE Petrofund trust units in the United States, or any province or territory of Canada, nor shall there be any sale of NCE Petrofund trust units in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.

# # #

Contact Information

For Investor Services, please call 1-866-318-1767, or fax (403) 539-4300 For analyst enquiries, please contact Chris Dutcher at (403) 218-8625 e-mail: info@ncepetrofund.com website: www.ncepetrofund.com

Filing Compare · PETROFUND ENERGY TRUST