News Release
May 26, 2003
NCE Petrofund (TSX: NCF.UN; AMEX: NCN)
Reports its Results for the First Quarter of 2003
NCE Petrofund announces its first quarter 2003 results.
Noteworthy points include:
•
a 14% increase in production to 26,927 boepd
•
a 215% increase in cash flow to $58.6 million or $1.08 per unit
•
a 12% increase in distributions paid to $0.48 per unit (44% of cash flow)
•
a total of $29.7 million in acquisition and development activities
•
the announcement of internalization of management (since completed)
The Trust's results for the first quarter 2003 are as follows:
NCE Petrofund Highlights (unaudited)
(All dollar figures in thousands except per unit amounts)
Financial | Three months ended March 31, |
| | 2003 | 2002 | Variance |
Revenues | $ 109,175 | $ 50,519 | 116% |
Cash flow from operating activities (1) | $ 58,619 | $ 18,604 | 215% |
Distributions accruing during the period (2) | $ 50,002 | $ 17,926 | 179% |
Cash flow available for distribution per unit | $ 0.92 | $ 0.44 | 109% |
Cash distributions paid per unit | $ 0.48 | $ 0.43 | 12% |
Net income | $ 32,176 | $ 903 | 3,463% |
Net income per trust unit | | | |
-basic | $ 0.59 | $ 0.02 | 2,850% |
-diluted | $ 0.59 | $ 0.02 | 2,850% |
Units outstanding | | | |
Weighted average | 54,130 | 42,121 | 29% |
Diluted | 54,270 | 42,121 | 29% |
At period end | 54,148
| 46,519 | 16% |
(1)
See special notes on Page 2.
(2)
See Note 4 for details.
| |
Operating | Three months ended March 31, |
Daily production | 2003 | 2002 | Variance |
Oil: barrels (bbls) | 11,264 | 10,217 | 10% |
Gas: thousand cubic feet (mcf) | 81,999 | 70,695 | 16% |
Liquids: barrels (bbls) | 1,996 | 1,645 | 21% |
Barrels of oil equivalent (boe) (6:1) | 26,927 | 23,645 | 14% |
Prices |
Oil (per bbl) | $ 44.60 | $ 29.51 | 51% |
Gas: (per mcf) | $ 7.66 | $ 3.22 | 138% |
Liquids: (per bbl) | $ 41.20 | $ 20.39 | 102% |
BOE (6:1) | $ 45.04 | $ 23.80 | 89% |
Operating netback (per boe) | $ 26.97 | $ 12.04 | 124% |
SPECIAL NOTES
The following discussion and analysis of financial results should be read in conjunction with the unaudited consolidated financial statements for the three months ended March 31, 2003 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 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, NCE Petrofund claims the protection of the safe harbour for forward-looking statements provisions contained in the U.S. Private Securities Litigation Reform Act of 1995. NCE 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 NCE Petrofund currently foresees. Discussion of the various factors that may affect future results is contained in NCE Petrofund’s recent filings with the Securities and Exchange Commission and Canadian securities regulatory authorities. NCE Petrofund undertakes no obligation to update publicly or revise any forward-looking statem ents contained herein and such statements are expressly qualified by this cautionary statement.
RESULTS SUMMARY
We are pleased to present the results for NCE Petrofund for the three months ended March 31, 2003.
Production increased 14% to 26,927 barrels of oil equivalent per day (“boe/d”) in the first quarter of 2003 from 23,645 boe/d in 2002 due to a successful development program and a number of acquisitions in 2002, the most significant being NCE Energy Trust, which was acquired effective May 30, 2002. Cash flow from operations increased 215% to $58.6 million in the first quarter of 2003 from $18.6 million in the first quarter of 2002. Prices on a boe basis increased 89% to $45.04 in 2003 from $23.80 in 2002.
The West Texas Intermediate (WTI) crude oil price averaged US$33.86 in the first quarter of 2003 as compared to US$21.64 in the first quarter of 2002. This resulted in Canadian wellhead prices of $44.60 per bbl in 2003 as compared to $29.51 per bbl in 2002. The average gas price increased 138% from $3.22 per mcf in 2002 to $7.66 per mcf in 2003.
SIGNIFICANT FINANCIAL TRANSACTIONS
Effective January 1, 2003, NCE Petrofund Corp. (“NCEP”) acquired 100% of the outstanding common shares of Solaris Oil & Gas Inc. (“Solaris”), and on February 7, 2003, amalgamated Solaris into NCEP. NCEP paid $7.4 million in cash, and assumed debt and negative working capital of $1.2 million, for a total cost of the oil and gas properties of $8.6 million. The acquisition added 720,000 boe of established reserves and approximately 200 boe/d of production.
At the Annual and Special Meeting held on April 16, 2003, unitholders of the Trust voted over 90% in favour of the resolution authorizing the internalization of management, and on April 29, 2003, the transaction closed. As a result of the internalization, NCE Petrofund Management Corp. (“NCEP Management”), the Manager of the Trust, and NCE Management Services Inc. (“NMSI”), which employs all of the Calgary-based personnel who provide services to the Trust and NCEP, became wholly owned subsidiaries of NCEP. All management, acquisition and disposition fees payable to the Manager were eliminated retroactive to January 1, 2003 and all the Trust’s operations are in the process of being consolidated in NCEP’s Calgary offices. To ensure an orderly transition of the services currently provided by NCEP Management through its office in T oronto, 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. The maximum cost is $2 million, decreasing from $1 million in the first quarter to $250,000 in the fourth quarter, after which Sentry will no longer provide such services. Sentry is a company in which John Driscoll, the Chairman of NCEP, owns a controlling interest.
The elimination of the management fees and the reduction in general and administrative costs expected from the streamlining and consolidation of the management functions in Calgary is expected to improve the long-term operating cost structure of the Trust. The internalization is accretive to Petrofund’s net asset value, distributions and cash flow per unit.
NCE Petrofund’s governance structure has been revised to reflect current “best practices”, with shareholders having the right to designate all of the nominees to be elected directors of NCEP.
In addition, Audit, Human Resources and Compensation, Governance and Reserve committees have been established consisting solely of directors that are unrelated to management.
The elimination of the management fees and the increased management ownership in Trust units resulting from the internalization further aligns the interests of the unitholders and management.
NCE Petrofund’s competitiveness for acquisitions is expected to improve due to the elimination of the acquisition and disposition fees. The completion of the internalization is expected to enhance the attractiveness of the units to a wider range of potential investors, expand the investor base, and may result in a lower cost of capital.
The cost to NCEP was approximately $31.0 million, consisting of the issue of 1,939,147 exchangeable shares of NCEP, 100,244 Trust units, and cash of approximately $8.2 million, including $3.4 million to repay indebtedness owing by NCEP Management. Initially, each exchangeable share will be exchangeable into one Trust unit. The exchange rate 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.
Transaction costs incurred to March 31, 2003 have been expensed in this quarterly report. As the closing took place on April 29, 2003, the purchase price and the remaining costs will be expensed in the second quarter.
On April 14, 2003, NCEP announced that it had entered into an agreement to purchase a diverse group of oil and gas properties for $66 million, subject to adjustment. A Purchase and Sale Agreement was signed on May 2, 2003. The purchase is accretive to distributable cash flow, production per unit and reserves per unit. The properties added net established reserves of 9.7 million boe as estimated by independent engineering firm, Gilbert Laustsen Jung, resulting in an established reserves purchase price of $6.78 per boe. Current production from the properties is approximately 2,300 boe/d of which 42% is gas. The properties contain a large percentage of unit production, and have a reserve life index of 11.6 years. The purchase is effective March 1, 2003 and is expected to close mid-June. This purchase, along with the acquisitions completed in the first quarter, will replace over 100% of NCE Petrofund’s 2002 annual production.
On May 22, 2003, NCE 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 and position NCE Petrofund to make additional acquisitions.
OPERATIONAL HIGHLIGHTS
NCE Petrofund continued its emphasis on field development activities during the first quarter of 2003. NCE Petrofund participated in the drilling of 65 gross wells during the quarter (11 net wells) with an overall 97% success rate.
In southeastern Saskatchewan, NCE Petrofund participated in the drilling of a highly successful horizontal oil well at Queensdale. This well is producing nearly 200 boe/d net to NCE Petrofund’s 50% working interest. An additional 1 or 2 follow-up locations are being considered for this property, likely in the third and fourth quarters of this year. At Silverton, Petrofund operated and drilled a 75% working interest dry hole on lands adjacent to its Silverton oil producing property.
At Alliance, in east-central Alberta, NCE Petrofund successfully drilled a 100% working interest Dina gas well. Although not yet completed due to road bans, this well is expected to produce 500 mcf/d based on offsetting analogous wells.
At Three Hills Creek in central Alberta, NCE Petrofund completed a Belly River gas well which was drilled late in the prior quarter, and drilled and completed two follow-up Belly River wells early in this quarter, resulting in one successful gas well. By way of a previous farmout, five coalbed methane gas wells were drilled on NCE Petrofund lands. Significant additional coalbed methane gas drilling is planned for this property after spring breakup. These wells are drilled at no cost to NCE Petrofund. On its nearby Innisfail gas property, NCE Petrofund participated for 25% and farmed out the remaining 75% working interest in the drilling of a Pekisko gas well. Plans are underway to complete the well for Belly River gas production. At Innisfail, NCE Petrofund also worked over one of its existing Pekisko gas wells for added productivity and reserves.
At Sylvan Lake in central Alberta, NCE Petrofund equipped and tied in a 100% working interest Edmonton Sand gas well drilled in the prior quarter. This well is producing steadily at 200 mcf/d.
At Strachan in west-central Alberta, NCE Petrofund operated the drilling of two high (50% average) working interest wells, each targeting multiple gas zones. Early completion results show each well to be highly commercial. Both wells will be brought on production in the next quarter. In addition to this drilling activity, NCE Petrofund continues to identify recompletion/workover candidates in this multi-zone area (two workovers are currently underway as of the end of this quarter).
At Sunchild in west-central Alberta, NCE Petrofund continued to optimize its production from several new gas wells drilled late last year by installing additional field compression. These new drills are currently producing 2,000 mcf/d net to NCE Petrofund. NCE Petrofund also has an overriding royalty in a successful Ostracod gas well drilled during the first quarter. This well is expected to be producing early in the second quarter.
At Red Earth, in northern Alberta, a total of 9 gross wells (3 net wells) were drilled for Granite Wash-Slave Point oil on NCE Petrofund lands during the first quarter. Seven of these wells were completed as producing oil wells for a success rate of 78%. Petrofund has interests varying from 25% to 50%, as well as a convertible overriding royalty in these wells. In addition, NCE Petrofund completed and started producing a horizontal re-entry well that had been drilled late in the fourth quarter of 2002. NCE Petrofund’s net production from all new Red Earth wells totals about 225 boe/d. NCE Petrofund expanded two of its operated oil batteries to accommodate this new production At Border, in northeastern British Columbia, Petrofund participated for its 10% working interest in the drilling of 24 Bluesky-Gething-Montney gas wells during the first quarter, all of which were cased and completed. Of these, 19 wells have since been tied into existing NCE Petrofund-owned infrastructure, thereby adding roughly 1,000 mcf/d to NCE Petrofund’s production base.
CAPITAL EXPENDITURES
As previously discussed, NCE Petrofund acquired the properties of Solaris for $8.6 million. In addition, $4.7 million was added to the cost to account for the difference between the book and tax basis of the assets acquired.
During the three months ended March 31, 2003, $16.7 million was also incurred for development drilling and other production enhancement activity discussed above. These activities are very important in offsetting part of the decline on existing production. NCEP expects to invest approximately $50 million in this area in 2003.
A summary of expenditures for the period appears below: ($000)
Acquisitions | $ 12,892 |
Dispositions | (529) |
Net acquisitions | 12,363 |
Finding and development cost: | |
Land and seismic | 730 |
Drilling and completions | 10,735 |
Well equipping | 2,387 |
Tie-ins
| 601 |
Facilities | 1,852 |
Other | 464 |
Total | 16,769 |
Total net capital expenditures | $ 29,132 |
CASH DISTRIBUTIONS
Petrofund unitholders who held their units throughout the first quarter of 2003 received distributions of $0.48 in cash as compared to $0.43 in the first quarter of 2002. A cash distribution of $0.17 per unit was paid in April and $0.18 per unit has been announced for May.
Petrofund generated cash flow available for distribution in the first quarter of $57.5 million, or $1.06 per unit before deducting $7.5 million or $0.14 per unit for reinvestment in capital projects. Of the remaining $50.0 million available, $26.0 million was paid out in distributions representing a payout ratio of 45% (see Note 4). If the equity issue had taken place in early January, and distributions had been paid on the additional
9.2 million units for the entire quarter, the payout ratio would have been 53%.
For the 12 months ended March 31, 2003, the Trust generated cash flow available for distribution of $152.7 million, withheld $17.5 million for re-investment in development drilling and other projects, and paid out distributions of $93.2 million, resulting in a payout ratio of 61%. The Trust is continuing its policy of stabilizing monthly distributions and re-investing a portion of its cash flow for the long-term health of the Trust. Petrofund expects to be able to sustain the current 18 cents per month distribution level for several months taking into account the recent equity issue. Over a twelve month period, Petrofund intends to distribute a majority of its cash flow. Actual 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 retai ned for re-investment and to ensure more consistent monthly distributions. When prices are lower, less cash flow is required for capital expenditure as projects become less economic.
PRODUCTION REVENUE
Revenues increased 116% to $109.2 million in the first quarter of 2003 from $50.5 million in the first quarter of 2002, as production increased 14% and prices were up 89% on a boe basis.
Crude oil sales increased 67% from $27.1 million in the first quarter of 2002 to $45.2 million in the first quarter of 2003. Oil production volumes increased 10% to 11,264 bbl/d in the first quarter of 2003 as compared to 10,217 in the first quarter of 2002. The average price was up 51% from $29.51 per bbl in the first quarter of 2002 to $44.60 in the corresponding period of 2003. These prices are net of negative oil hedging adjustments of $2.96 per bbl in 2003, and $0.12 per bbl in 2002.
Natural gas sales increased 176% from $20.5 million in the first quarter of 2002 to $56.5 million in the first quarter of 2003. Gas production increased 16% from 70.7 mmcf/d to 82.0 mmcf/d, and the average gas price was up 138% from $3.22 per mcf to $7.66 per mcf. The AECO monthly spot gas prices increased from $3.72 per mcf in the first quarter of 2002 to $7.92 per mcf in the first quarter of 2003.
Sales of natural gas liquids increased 145% to $7.4 million in the first quarter of 2003, from
$3.0 million in the first quarter of 2002. Production was up 21% to 1,996 bbl/d from 1,645 bbl/d. The average price was $41.20/bbl in the first quarter of 2003, and compared to $20.39 in the same period in the prior year.
ROYALTIES
Royalties (net of the Alberta Royalty Credit) were 22% of revenues in the first quarter of 2003, as compared to 16% in the first quarter of 2002. The percentage increase was mainly due to the significant increase in the average gas price. The Crown royalty rate increases as the price increases.
FIELD OPERATING COSTS
Operating expenses were $19.6 million in the first quarter of 2003 compared to $17.0 million in the first quarter of 2002. Operating costs on a boe basis were relatively flat at $8.08 in 2003, compared to $8.04 for the same period in 2002. The 2003 expenses reflect significantly higher power costs.
GENERAL AND ADMINISTRATIVE EXPENSES AND MANAGEMENT FEES
General and administrative costs were $3.5 million in the first quarter of 2003, as compared to
$3.9 million for the same period in 2002. Costs were down significantly on a boe basis to $1.43 in 2003 from $1.84/boe in 2002 due to reduced costs and an increase in production. Costs per boe are expected to further decrease throughout the year due to 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 quarter of 2003 and no future fees will be paid, due to the internalization of management. Fees of $0.8 million were paid in the first quarter of 2002 to NCEP Management.
PRICE RISK MANAGEMENT
Petrofund took advantage of price volatility in energy markets during the first quarter and hedged significant volumes of oil and gas for the balance of 2003. A small amount of hedging was completed for the first half of 2004. The volume of crude oil hedged for the balance of 2003 was increased to 4,220 bbl/d up from 1,985 bbl/d at the end of 2002. Gas hedges rose from 23.25 mmcf/d to 38.5 mmcf/d over this time. The Trust does not expect to hedge significant additional volumes for the 2003 year. NCE Petrofund will continue to take advantage of market opportunities as they arise to secure cash flows for 2004.
The Trust’s portfolio of crude oil hedges consists of:
1) 1,560 bbl/d @ $42.46 per bbl; and
2) 2,660 bbl/d collared between $35.78 and $43.79 per bbl.
NCE Petrofund will lose the floor protection on 75% of the collared volumes for any month WTI retreats below $29.91/bbl (US$20.38); however, in this event the Trust will still receive a premium of $5.87/bbl (US$4.00) over the actual price. The Trust has 2,000 bbl/d collared for the first half of 2004 under a wide collar and no crude hedged thereafter.
The Trust’s 2003 gas hedge portfolio comprises:
1) 4.8 mmcf/d fixed at $5.75/mcf; and
2) 33.7 mmcf/d with an average floor price of $5.32/mcf and an average ceiling price of $8.32/mcf.
Volumes subject to a cap without a corresponding floor have been eliminated. NCE Petrofund has collared approximately 19 mmcf/d for the first quarter of 2004 between $5.80 and $10.93 per mcf. No gas has been hedged beyond the first quarter of 2004. For a complete listing of all hedge transaction details, please see Note 5 to the Interim Consolidated Financial Statements.
DEPLETION, RECLAMATION AND ABANDONMENT
The provision for depletion and reclamation costs increased from $24.5 million in the first quarter of 2002 to $27.8 million in the first quarter of 2003 due to the 14% increase in production and an increase in the depletion rate from $10.80 per boe in 2002 to $10.93 per boe in 2003.
In the first quarter of 2003, NCEP set aside $182,000 in cash to fund future abandonment costs. NCEP has a cash abandonment reserve of $3.2 million at March 31, 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 million will be incurred on these activities in 2003. This amount is deducted directly from distribution accruing to Unitholders.
DEBT
As at March 31, 2003, the amount outstanding on the credit facility was $206.4 million, as compared to the $245 million available.
The revolving period on the syndicated facility ends on May 30, 2003. At that time, the syndicated facility will be increased by $20 million and extended for a further 364-day period.
WORKING CAPITAL
Accounts receivable decreased by $9.6 million as the amounts due on the sale of properties as at December 31, 2002 were received in the first quarter of 2003.
Current liabilities increased by $16.8 million from December 31, 2002, mainly due to capital expenditures incurred in the first quarter.
LIQUIDITY AND CAPITAL RESOURCES
For the three months ended March 31, 2003, the Trust generated cash flow from operating activities of $58.6 million. Of this amount, $26.0 million was paid out in distributions and $5.8 million was used to reduce the bank loan outstanding. Most of the remaining balance was used to fund acquisitions and the ongoing capital expenditure program.
Subsequent to the end of the quarter, the Trust completed 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.
Consolidated Balance Sheet |
(thousands of dollars) (Unaudited) | | | | | | |
| |
As at March 31, 2003 and at December 31, 2002 | | | | 2003 | | 2002 |
| | | | | | | |
Assets | | | | | | |
| | | | | | | |
Current assets | | | | | | |
Cash | | | | $ 21,911 | | $ - |
Accounts receivable | | | | 30,972 | | 41,953 |
Due from affiliates | | | | 952 | | 164 |
Prepaid expenses | | | | 11,487 | | 10,090 |
| | | | | | | |
Total current assets | | | | 65,322 | | 52,207 |
| | | | | | | |
Reclamation and abandonment reserve | | | | 3,183 | | 3,001 |
| | | | | | | |
Oil and gas royalty and property interests, | | | | | | |
at cost less accumulated depletion and depreciation | | | | | |
of $380,800 (2002 - $354,309) | | | | 838,008 | | 835,366 |
| | | | | | | |
| | | | $ 906,513 | | $ 890,574 |
| | | | | | | |
Liabilities and unitholders' equity | | | | | | |
| | | | | | | |
Current liabilities | | | | | | |
Bank overdraft | | | | $ - | | $ 1,572 |
Accounts payable and accrued liabilities | | | | 38,824 | | 22,007 |
Payable to affiliates | | | | - | | 2,168 |
Current portion of capital lease obligations | | | | 2,455 | | 3,304 |
Distributions payable to unitholders | | | | 54,080 | | 30,065 |
| | | | | | | |
Total current liabilities | | | | 95,359 | | 59,116 |
| | | | | | | |
Long-term debt | | | | 206,450 | | 212,253 |
Capital lease obligations | | | | 6,878 | | 6,965 |
Future income taxes | | | | 118,593 | | 116,845 |
Accrued reclamation and abandonment costs | | | | 16,531 | | 15,298 |
| | | | | | | |
Total liabilities | | | | 443,811 | | 410,477 |
| | | | | | | |
Unitholders' equity | | | | 462,702 | | 480,097 |
| | | | | | | |
| | | | $ 906,513 | | $ 890,574 |
| | | | | | | |
The accompanying notes to consolidated financial statements are an integral part of this consolidated balance sheet. |
Consolidated Statement of Operations |
(thousands of dollars except per unit amounts) (Unaudited) | | | | | |
| |
| | | | | | | |
For the three months ended March 31, | | 2003 | | 2002 | | |
| | | | | | | |
Revenues | | | | | | |
Oil and gas sales | | $ 109,175 | | $ 50,519 | | |
Royalties, net of incentives | | (24,227) | | (7,788) | | |
| | | | | | | |
| | 84,948 | | 42,731 | | |
| | | | | | | |
Expenses | | | | | | |
Lease operating | | 19,588 | | 17,112 | | |
Management fee | | - | | 833 | | |
Interest on long-term debt | | 2,129 | | 1,466 | | |
General and administrative | | 3,455 | | 3,916 | | |
Capital taxes | | 639 | | 377 | | |
Depletion and depreciation | | 26,491 | | 22,989 | | |
Provision for reclamation and abandonment | | 1,355 | | 1,496 | | |
Internalization of management contract (Note 6) | | 1,647 | | - | | |
| | | | | | | |
| | 55,304 | | 48,189 | | |
| | | | | | | |
Net income (loss) before provision for income taxes | 29,644 | | (5,458) | | |
| | | | | | | |
Provision for (recovery of) income taxes | | | | | | |
Current | | 395 | | 212 | | |
Future | | (2,927) | | (6,573) | | |
| | | | | | | |
| | (2,532) | | (6,361) | | |
| | | | | | | |
Net income | | $ 32,176 | | $ 903 | | |
| | | | | | | |
Net income per Trust unit | | | | | | |
Basic | | $ 0.59 | | $ 0.02 | | |
Diluted | | $ 0.59 | | $ 0.02 | | |
| | | | | | | |
Consolidated Statement Of Unitholders' Equity |
(thousands of dollars) (Unaudited) |
| | | | | | | |
| | | | | | | |
For the three months ended March 31, | | 2003 | | 2002 | | |
| | | | | | | |
Balance, beginning of year | | $ 480,097 | | $ 398,702 | | |
| | | | | | | |
Units issued, net of issue costs | | 431 | | 56,271 | | |
| | | | | | | |
Net income | | 32,176 | | 903 | | |
| | | | | | | |
Distributions accruing to unitholders | | (50,002) | | (17,926) | | |
| | | | | | | |
Balance,end of period | | $ 462,702 | | $ 437,950 | | |
| | | | | | | |
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements. |
| | | | | | | |
Consolidated Statement of Cash Flows |
(thousands of dollars except per unit amounts) (Unaudited) | | | | | |
| |
For the three months ended March 31, | | 2003 | | 2002 | | |
| | | | | | | |
Cash provided by (used in): | | | | | | |
| | | | | | | |
Operating activities | | | | | | |
Net income | | $ 32,176 | | $ 903 | | |
Add items not affecting cash: | | | | | | |
Depletion and depreciation | | 26,491 | | 22,989 | | |
Provision for reclamation and abandonment | | 1,355 | | 1,496 | | |
Future income taxes | | (2,927) | | (6,573) | | |
Actual abandonment costs incurred | | (123) | | (211) | | |
Internalization of management contract (Note 6) | | 1,647 | | �� - | | |
| | | | | | | |
Cash flow from operating activities | | 58,619 | | 18,604 | | |
| | | | | | | |
Net change in non-cash operating working capital balances | 23,443 | | 26,376 | | |
| | | | | | | |
Cash provided by operating activities | | 82,062 | | 44,980 | | |
| | | | | | | |
Financing activities | | | | | | |
Bank loan | | (5,803) | | 23,190 | | |
Distributions paid | | (25,987) | | (18,025) | | |
Capital lease repayments | | (935) | | (1,464) | | |
Issuance of Trust units | | 431 | | 56,272 | | |
| | | | | | | |
Cash provided by (used in) financing activities | | (32,294) | | 59,973 | | |
| | | | | | | |
| | | | | | | |
Investing activities | | | | | | |
Reclamation and abandonment reserve | | (182) | | (159) | | |
Acquisition of property interests | | (24,985) | | (49,989) | | |
Proceeds on disposition of properties | | 529 | | 3,131 | | |
Internalization of management contract (Note 6) | | (1,647) | | - | | |
| | | | | | | |
Cash used in investing activities | | (26,285) | | (47,017) | | |
| | | | | | | |
Net change in cash | | 23,483 | | 57,936 | | |
| | | | | | | |
Cash (bank overdraft),beginning of year | | (1,572) | | 1,917 | | |
| | | | | | | |
Cash,end of period | | $ 21,911 | | $ 59,853 | | |
| | | | | | | |
Interest paid during the year | | $ 2,276 | | $ 1,000 | | |
| | | | | | | |
Income taxes paid during the year | | $ 139 | | $ 1,446 | | |
| | | | | | | |
The accompanying notes to consolidated financial statements are an integral part of these consolidated statements. |
NCE Petrofund Notes to
Consolidated Interim 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 then ended.
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 the assumption of $1.2 million of debt including negative working capital and an outstanding bank loan.
The acquisition was accounted for using the purchase method of accounting. 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 |
| | | |
Options exercised | 39,166 | 421 |
Commissions and issue costs | – | (3) |
Unit purchase plan | 1,073 | 13 |
| | | |
March 31, 2003 | 54,148,003 | $ 794,783 |
The weighted average units outstanding are as follows:
For the three months ended March 31, | 2003 | 2002 |
Basic | 54,129,971 | 42,121,449 |
Diluted | 54,270,294 | 42,121,449 |
4. DISTRIBUTIONS ACCRUING TO UNITHOLDERS
Under the terms of the Trust Indenture, the Trust makes monthly distributions within a specified period following the end 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 cash receipts of royalty and other income 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 |
| | | | |
Cash distributions per Trust unit | | $ 0.48 | $ 0.43 |
Reconciliation of Distributions Accruing to Unitholders
For the three months ended March 31, | 2003 | 2002 |
| | | |
Distributions payable, beginning of period | $ 30,065 | $ 12,188 |
| | | |
Distributions accruing during the period | | |
Cash flow from operating activities | 58,619 | 18,604 |
Proceeds on disposition of property interests | – | 946 |
Reclamation and abandonment reserve | (182) | (159) |
Less capital lease repayment | (935) | (1,465) |
Capital expenditures | (7,500) | – |
| | | |
Total distributions accruing during the period | 50,002 | 17,926 |
| | | |
Distributions paid | (25,987) | (18,025) |
| | | |
Distributions payable, end of period | $ 54,080 | $ 12,089 |
| | | |
Distributions accruing to unitholder per Trust unit | | |
Basic | $ 0.92 | $ 0.44 |
Diluted | $ 0.92 | $ 0.44 |
5. DERIVATIVE FINANCIAL INSTRUMENTS AND PHYSICAL CONTRACTS
The Trust enters into various pricing mechanisms to reduce price volatility and exposure to low 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 March 31, 2003, all of which constitute effective hedges, and the related unrealized gains or losses, are summarized separately below:
Financial Gas Hedges
Natural Gas |
Term | Volume
mcf/d | Price
$/mcf | Delivery
point | Unrealized gain (loss) |
Fixed | March 1, 2003 to October 31, 2003 | 6,159 | $5.75 | AECO | $ (1,164) |
Collar | April 1, 2003 to October 31, 2003 | 9,475 | $4.65-$6.23 | AECO | (1,187) |
Collar | April 1, 2003 to October 31, 2003 | 4,737 | $4.64-$6.23 | AECO | (676) |
Collar | April 1, 2003 to October 31, 2003 | 4,737 | $4.64-$6.24 | AECO | (685) |
Collar | April 1, 2003 to October 31, 2003 | 14,212 | $5.86-$9.60 | AECO | 533 |
Collar | April 1, 2003 to October 31, 2003 | 4,737 | $5.86-$9.82 | AECO | 167 |
Collar | November 1, 2003 to March 31, 2004 | 9,475 | $5.80-$10.87 | AECO | 302 |
Collar | November 1, 2003 to March 31, 2004 | 9,475 | $5.80-$10.98 | AECO | 380 |
Total | | | | | $ (2,330) |
Financial Oil Hedges
Oil |
Term | Volume
bbl/d | Price $/bbl | Delivery
point | Unrealized gain (loss) |
Fixed Price | July 1, 2003 to December 31, 2003 | 2,000 | $42.46 | Edmonton | $ 810 |
Fixed Price | April, 2003 | 1,000 | $48.44 | Edmonton | 109 |
Fixed Price | May, 2003 | 1,000 | $48.44 | Edmonton | 188 |
Collar | January 1, 2003 to June 30, 2003 | 2,000 | $34.48-$42.18 | Edmonton | (745) |
Three-way collar | March 1, 2003 to June 30, 2003 | 1,000 | *(1) | Edmonton | (204) |
Three-way collar | March 1, 2003 to June 30, 2003 | 1,000 | *(2) | Edmonton | (414) |
Three-way collar | July 1, 2003 to December 31, 2003 | 2,000 | *(3) | Edmonton | 17 |
Total | | | | | $ (239) |
*(1)
At prices above $42.79, NCE Petrofund receives $42.79 per bbl
At prices between $35.96 and $42.79 per bbl, NCE Petrofund receives the market price
At prices below $29.35, NCE Petrofund receives a premium of $6.61 per bbl
*(2)
At prices above $42.57, NCE Petrofund receives $42.57 per bbl
At prices between $35.96 and $42.57 per bbl, NCE Petrofund receives the market price
At prices below $30.82, NCE Petrofund receives a premium of $5.14 per bbl
*(3)
At prices above $45.13, NCE Petrofund receives $45.13 per bbl
At prices between $36.33 and $45.13 per bbl, NCE Petrofund receives the market price
At prices below $30.45, NCE Petrofund receives a premium of $5.87 per 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 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.
6. SUBSEQUENT EVENTS
a)
Internalization of Management
The unitholders of the Trust approved the internalization of management at an Annual and Special Meeting held on April 16, 2003, and the transaction closed on April 29, 2003. As a result, NCE Petrofund Management Corp. and NCE Management Services Inc. became wholly owned subsidiaries of NCEP and all management, acquisition and disposition fees were eliminated retroactive to January 1, 2003. All the Trust’s operations will be consolidated and managed from its offices in Calgary. The cost to NCEP will be approximately $31.0 million, consisting of 2.04 million exchangeable shares and Trust units valued at $11.20 per unit, based on the trading price of the units at closing, or $22.7 million, and cash of approximately $8.2 million, including transaction costs and distributions on the exchangeable shares and Trust units from January 1, 2003 to closing. Costs of $1 .6 million incurred on this transaction to March 31, 2003 have been expensed. The purchase price and the remaining costs will be expensed in the second quarter.
b)
Acquisition of Properties
On May 2, 2003, NCEP signed a Purchase and Sale Agreement to acquire a diverse group of properties for $66 million, subject to adjustments. The transaction is effective March 1, 2003 and is expected to close in June 2003.
c)
Financing Activities
On May 22, 2003, NCE 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.
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
