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2002 Annual Report > Management Discussion and Analysis |
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MANAGEMENT'S DISCUSSION AND ANALYSIS
The following discussion and analysis of financial results is to be read in conjunction with the audited consolidated financial
statements as at and for the years ended December 31, 2002 and 2001 and is based on information available to March 6, 2003.
All amounts are stated in Canadian dollars unless otherwise specified.
Important Information Regarding Comparative Financial Statements
On June 21, 2001, the respective unitholders of EnerMark Income Fund ("EnerMark") and Enerplus Resources Fund
("Enerplus") approved a merger ("Merger") combining the two Funds. As the former unitholders of EnerMark held
approximately 69% of the outstanding trust units of the combined Fund at the date of acquisition, the Merger has been
accounted for using the reverse takeover method of accounting for business combinations. For accounting purposes, EnerMark
acquired Enerplus effective June 21, 2001 and continued as Enerplus Resources Fund ("Enerplus" or the "Fund").
As a result of the reverse takeover method of accounting, the audited consolidated financial statements for the year ended
December 31, 2001 presented herein include only EnerMark's operating results prior to the Merger with Enerplus on
June 21, 2001 and include the results of the merged Fund thereafter. All comparative figures and references to prior years are
those of EnerMark. Thus, unless otherwise indicated, all historical production, reserve and other operational information is
based on the historical operations of EnerMark. The production, reserve and other operational information attributable to the
operations of Enerplus as it existed prior to the Merger has only been included since June 21, 2001. This discussion, analysis
and information has been restated, as applicable, to reflect the trust unit exchange ratio of 1.000 EnerMark trust unit for 0.173
of an Enerplus trust unit, pursuant to the Merger.
Critical Accounting Policies
The financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP").
A summary of significant accounting policies is presented in Note 1 to the consolidated financial statements. A reconciliation
of differences between Canadian and United States GAAP is presented in Note 10 to the consolidated financial statements.
Certain accounting policies are critical to understanding the financial condition and results of operations of Enerplus. Most
accounting policies are mandated under GAAP and management does not have the ability to select alternatives. However, in
accounting for oil and gas activities, management has a choice between two acceptable accounting policies: the full cost and
the successful effort methods of accounting.
The Fund follows the full cost method of accounting for oil and natural gas activities, as described in Note 1 to the
consolidated financial statements. Using the full cost method of accounting, all costs of acquiring, exploring and developing
oil and natural gas properties are capitalized, including unsuccessful drilling costs and administrative costs associated with
acquisitions and development. Under the successful efforts method of accounting, all exploration costs, except costs associated
with drilling successful exploration wells, are expensed in the period in which they are incurred. The difference between these
two methodologies is not expected to be significant to the Fund's net income or net income per unit as the Fund participates
in low risk development drilling that has traditionally achieved high success rates.
Under the Fund's full cost method of accounting, costs are aggregated on a country by country basis. The ceiling test is applied
to the overall carrying value of the property, plant and equipment for a Canada-wide cost centre with the reserves valued using
constant dollar prices at period end. The Fund has one cost centre as operations are currently conducted only in Canada. Under
the successful efforts method of accounting, the costs are aggregated on a property by property basis. The carrying value of
each property is subject to an impairment test by determining the fair value of the reserves based on estimates of future prices
at period end. As each accounting methodology uses a different commodity price assumption and calculates impairment
differently, each policy may generate a different net income and a different carrying value of property plant and equipment,
depending on the circumstances at period end.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make certain judgements and
estimates, some of which may relate to matters that are uncertain. Changes in these judgements and estimates could have a
material impact on the Fund's financial results and financial condition. The Fund has determined that the process of estimating
reserves is critical to several accounting estimates. The process of estimating reserves is complex. It requires significant
judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may
change substantially as additional data from ongoing development and production activities becomes available, and as
economic conditions impacting oil and gas prices, operating costs, and royalty burdens change. Reserve estimates impact net
income through depletion, provision for site restoration and in the application of the ceiling test whereby the value of the oil
and gas assets are subjected to an impairment test. The reserve estimates are also used to assess the borrowing base for the
Fund's credit facilities. Revisions or changes in the reserve estimates can have either a positive or a negative impact on net
income or the borrowing base of the Fund.
Recent Canadian Accounting Pronouncements
In November 2002, the Canadian Institute of Chartered Accountants ("CICA") amended its accounting guideline on hedging
relationships, which was originally issued in November 2001. The guideline establishes certain conditions where hedge
accounting may be applied. It is effective for years beginning on or after July 1, 2003. The guideline will have a significant
impact to the Fund's net income and net income per trust unit, as the 3-way option contracts for oil and natural gas as
described in Note 7 to the consolidated financial statements will not qualify for hedge accounting. Where hedge accounting
does not apply, any changes in the mark-to-market values of the option contracts relating to a period can either reduce or
increase net income and net income per trust unit for that period. The Fund expects to adopt this standard January 1, 2004.
In December 2002, the CICA issued a new standard on the accounting for asset retirement obligations. This standard requires
recognition of a liability for the future retirement obligations associated with property, plant and equipment. These obligations
are initially measured at fair value, which is the discounted future value of the liability. This fair value is capitalized as part of
the cost of the related asset and amortized to expense over its useful life. The liability accretes until the date of expected
settlement of the retirement obligations. The new standard is effective for all fiscal years beginning on or after January 1, 2004.
The Fund expects to adopt this standard January 1, 2004. The impact of the effect of this new standard on the consolidated
financial statements has not been determined. The Fund currently provides future asset retirement obligations using the unitof-
production method and is included in depletion, depreciation and amortization expense. Actual site restoration costs are
charged against the accumulated liability.
Other accounting standards issued by the CICA during the year ended December 31, 2002 are not expected to materially
impact the Fund.
2002 Highlights
- With respect to fiscal 2002, Enerplus paid $246.8 million to unitholders ($3.32 per trust unit) or 85% of funds flow from
operations and retained $46.3 million ($0.62 per trust unit) for debt reduction.
- Enerplus diversified its debt portfolio by repaying a portion of its bank debt with the proceeds raised through the issuance
of US$175 million 12-year senior unsecured notes.
- During the year, the Fund replaced 181% of its production through acquisitions and development.
- The Fund successfully maintained production volumes throughout the year with average daily volumes of 62,784 BOE
while achieving a decrease in operating expenses of $0.23/BOE from $6.09/BOE to $5.86/BOE.
- Enerplus continued with its active development program, investing $141.7 million in development drilling and facility
enhancements for 2002, drilling 300 net wells with a 99% success rate.
- Enerplus acquired working interests in various oil and gas properties for $60.6 million. The major property acquisitions
include an incremental working interest in the Medicine Hat Glauc. "C" operated property for consideration of
$20.5 million and the acquisition of a 16% working interest in Oil Sands Lease #24 (also known as the Joslyn Creek Lease)
for $16.4 million.
- On September 12, 2002 the Fund successfully closed an equity offering of 4,750,000 trust units at a price of $26.85 per
trust unit for gross proceeds of $127.5 million ($120.9 million net of issuance costs).
- On October 21, 2002 Enerplus completed the acquisition of Celsius Energy Resources Ltd. for $161.4 million.
- During the fourth quarter 2002, the Fund successfully completed a cross-border equity offering of 7,959,300 trust units at
a price of $26.00 per trust unit for gross proceeds of $206.9 million ($193.7 million net of issuance costs).
- Subsequent to December 31, 2002, Enerplus closed the acquisition of PCC Energy Inc. and PCC Energy Corp (collectively
"PCC") for a total consideration of $167.6 million.
Results of Operations
Production
In accordance with Canadian practice, production volumes, reserve volumes and revenues are reported on a gross basis, before
deduction of Crown and other royalties, unless otherwise indicated.
Daily production during 2002 averaged 62,784 BOE/day, representing a 16% increase over average production volumes of
54,015 BOE/day for the previous year. Although the majority of this increase was a result of the Merger, acquisitions
completed during the year accounted for annualized production of 1,900 BOE/day primarily from the addition of Celsius
Energy Resources Ltd. ("Celsius") which closed on October 21, 2002 and the additional interest of the Medicine Hat
Glauc "C" property which closed in March 2002. Enerplus' production before acquisitions was on target with expectations for
the year. The Fund will see the full impact of these acquisitions in 2003.
Enerplus' production is widely distributed across more than 250 properties in Alberta, Saskatchewan and British Columbia.
The largest 10 properties account for 31% of Enerplus' production. This wide distribution minimizes the risk that production
might be materially impacted by the performance of a few major properties.
Average production volumes for the years ended December 31, 2002 and 2001 are outlined below:
 |
| Natural gas (Mcf/day) |
210,517 |
176,671 |
| Crude oil (bbls/day) |
23,288 |
20,592 |
| Natural gas liquids (bbls/day) |
4,410 |
3,978 |
|
| Total daily sales (BOE/day) |
62,784 |
54,015 |
|
Enerplus' exit production rate averaged 67,800 BOE/day for the month of December 2002, with a weighting of 58% natural
gas, 36% crude oil, and 6% natural gas liquids. Production is expected to average 68,900 BOE per day in 2003, assuming
capital development spending of approximately $155 million, but without taking into account any further acquisitions. This
production estimate is based on a full year benefit of the Celsius acquisition and the PCC acquisition from the closing date of
March 5, 2003.
Pricing and Price Risk Management
The average price that Enerplus received for its natural gas (before hedging) decreased 21% from $4.91/Mcf in 2001 to
$3.87/Mcf in 2002. In comparison, the AECO Monthly Index decreased 35% from $6.30/Mcf in 2001 to $4.07/Mcf in 2002
and the NYMEX Henry Hub index price decreased 26% from US$4.38/Mcf in 2001 to US$3.25/Mcf in 2002. The Fund
has a balanced natural gas portfolio of spot and term contracts that will respond differently to the market than the reference
indices. The wider basis differential between the AECO and NYMEX indices, the strengthening Canadian dollar, and the
physical fixed price contracts helped reduce the Fund's exposure to price volatility.
The average price that Enerplus received for its crude oil (before hedging) increased 13% from $30.48/bbl in 2001 to
$34.37/bbl in 2002. Although there was virtually no change in the average price of benchmark West Texas Intermediate
("WTI") crude oil from US$25.97 in 2001 to US$26.08 in 2002, Enerplus realized the benefit from a narrowing in the price
differentials on it's heavier streams of crude oil during the year and a slightly weaker Canadian dollar.
The realized prices for natural gas liquids ("NGLs") decreased 17% from $31.12/bbl in 2001 to $25.68/bbl during 2002.
These prices tend to be influenced by the corresponding prices for natural gas.
|
| Natural gas (per Mcf ) |
$ |
3.87 |
$ |
4.91 |
-21 |
| Crude oil (per bbl) |
|
34.37 |
|
34.37 |
13 |
| Natural gas liquids (per bbl) |
|
25.68 |
|
31.12 |
--17 |
| Per BOE |
$ |
27.49 |
$ |
29.89 |
-8 |
|
|
|
| AECO natural gas (per Mcf ) |
$ |
4.07 |
$ |
6.30 |
-35 |
| NYMEX natural gas (US$ per Mcf ) |
|
3.25 |
|
4.38 |
-26 |
| WTI crude oil (US$ per bbl) |
|
26.08 |
|
25.97 |
0 |
| CDN$/US$ exchange rate |
$ |
0.6369 |
$ |
0.6458 |
-1 |
|
Enerplus has an on-going commodity price risk management program that is designed to provide price protection on a portion
of its future production in the event of adverse commodity price movement, while retaining significant exposure to upside
price movements. The program is intended to provide a measure of stability to the Fund's cash distributions as well as ensure
Enerplus realizes positive economic returns from its capital development and acquisition activities.
In 2002, Enerplus realized a cost of $8.7 million compared to a $50.1 million gain in 2001 as a result of its price risk
management program, as outlined on next page:
|
| Crude oil |
$ |
(4.3) |
$ |
(0.50)/bbl |
$ |
5.5 |
$ |
0.73/bbl |
| Natural gas |
|
(4.4) |
$ |
(0.06)/Mcf |
$ |
44.6 |
$ |
0.69/Mcf |
| Net hedging gain (cost) |
$ |
(8.7) |
$ |
$(0.38)/BOE |
$ |
50.1 |
$ |
2.54/BOE |
|
Enerplus has the following physical and financial contracts in place:
During the first half of 2001, Enerplus was able to hedge a portion of its production for the remainder of the year at favourable
rates. When natural gas prices retreated from their record highs at the end of 2001, Enerplus' hedging protection resulted in
a significant gain. Hedging costs arose in 2002 as oil and natural gas prices strengthened through to the end of the year due
to colder winter temperatures, a crude oil production strike in Venezuela, and the threat of hostilities in the Middle East.
Enerplus' commodity risk management position as at December 31, 2002 is described in Note 7 to the consolidated financial
statements. Commodity price risk is managed through fixed price physical delivery contracts and financial instruments such
as forward contracts. The net receipts or payments arising from the forward contracts are recognized in income as a component
of oil and gas sales during the same period as the corresponding hedged position. At December 31, 2002, Enerplus had
$1.7 million in unamortized premium costs related to forward contracts that will be amortized over the remaining life of those
contracts. The mark-to-market value of the financial forward contracts at December 31, 2002 represented an unrealized cost
of $34.2 million on natural gas and an unrealized cost of $8.5 million on oil with reference to year-end prices and
forward markets.
In the future, Enerplus intends to continue to manage its commodity price exposure in a similar manner as in the past with
the objective of establishing downside price protection at a reasonable cost, while maintaining exposure to improving prices.
The future gain or cost from such a program depends on forward markets and future prices.
|
| First half 2003 |
104.5 |
42 |
11,000 |
46 |
| Second half 2003 |
103.4 |
41 |
12,000 |
50 |
| First half 2004 |
70.3 |
28 |
8,500 |
36 |
| Second half 2004 |
Second half 2004 |
20 |
5,000 |
21 |
|
Even with these positions, the Fund's cash flow remains sensitive to changes in commodity prices as demonstrated by the
following table:
|
| Change of $0.10 per Mcf in the price of natural gas |
$0.05 |
| Change of US$1.00 per barrel in the price of WTI crude oil |
$0.10 |
| Change of 1,000 BOE/day in production |
$0.08 |
| Change of $0.01 in the US$/CDN$ exchange rate |
$0.04 |
| Change of 1% in interest rate |
Change of 1% in interest rate $0.03 |
|
These sensitivities are based on current projections for 2003, which have been adjusted to include all commodity contracts as
described in Note 7 to the consolidated financial statements. They apply to commodity prices, production, interest and
exchange rates within the context of current market rates and the Fund's current risk management positions.
To the extent the market price of crude oil or natural gas change to levels that are above the ceiling or below the floor price
limits set by existing commodity contracts, the above sensitivities will no longer be relevant. As these sensitivity calculations
assume a number of factors, actual sensitivities may vary significantly from those presented.
Revenues
Crude oil and natural gas revenues, inclusive of hedging, were $621.5 million for the year ended December 31, 2002, which
was marginally lower than the $639.4 million reported for the year ended December 31, 2001. Revenues in 2002 represent a
full year's production compared to the partial year's production received in 2001, due to the Merger. The increase in revenues
from greater production volumes was more than offset by the combined effects of the variance in hedging results and the
overall decrease in natural gas and NGL prices during 2002 compared to 2001. These variances are described in the
table below.
|
|
| 2001 Sales Revenues |
$ |
234.5 |
$ |
45.2 |
$ |
359.7 |
$ |
639.4 |
|
| Price variance |
|
33.1 |
|
(8.8) |
|
(79.9) |
|
(55.6) |
| Volume variance |
|
30.0 |
|
4.9 |
|
61.6 |
|
96.5 |
| Hedging variance |
|
(9.7) |
|
|
|
(49.1) |
|
(58.8) |
|
| 2002 Sales Revenues |
$ |
287.9 |
$ |
41.3 |
$ |
292.3 |
$ |
621.5 |
|
Royalties
Royalties decreased marginally from $132.7 million or 22.5% of oil and gas sales before hedging for 2001 to $131.8 million
or 20.9% for 2002. The decline in royalties as a percentage of oil and gas sales before hedging is attributable to a lower reference
natural gas price used by the provincial government to calculate crown royalties during the year, which is consistent with the
decrease in realized natural gas prices during the year. In the current commodity price environment, Enerplus expects the
royalty percentage to remain at approximately 21%.
Operating Expenses
Operating expenses for the year ended December 31, 2002 increased to $134.4 million from $120.1 million in 2001 due to
higher production volumes associated with acquisitions and the Merger. On a per unit of production basis, operating expenses
decreased by 4% from $6.09/BOE in 2001 to $5.86/BOE in 2002. Several cost categories that decreased year over year include
water disposal costs, utility costs and the cost of supplies and services. Prior period adjustments to processing income also
contributed to the overall reduction in operating expenses. Enerplus expects to maintain a similar level of operating costs in
2003 and average approximately $5.85/BOE.
General and Administrative Expenses
General and administrative expenses were $16.0 million or $0.70 per BOE for the year ended December 31, 2002 compared
to $13.0 million or $0.66 per BOE for 2001. General and administrative costs per BOE of production increased due to the
relocation of the corporate head office combined with the incremental cost of consulting services retained to optimize cash
flows and pursue value creation opportunities within the existing property portfolio. Enerplus expects general and
administrative costs to be approximately $0.70/BOE for 2003. As allowed under the full cost method of accounting, Enerplus
capitalized $9.1 million of general and administrative costs in 2002 compared to $7.5 million in 2001. The majority of these
capitalized costs represent compensation costs for staff involved in development and acquisition activities.
Management Fees
|
| Base management fee |
$ |
9.2 |
$ |
9.3 |
| Performance fee |
|
12.4 |
|
- |
|
| Total management fees |
$ |
21.6 |
$ |
9.3 |
|
Enerplus Global Energy Management Company ("EGEM") supplies management services to Enerplus on a fee and cost
reimbursement basis. The management fees, which were renegotiated as a result of the Merger, are now comprised of two
components, a base management fee of 2.75% of net operating income and an incremental performance fee which can range
from 0% to 4% of net operating income.
For the year ended December 31, 2002 total management fees were $21.6 million compared to $9.3 million for 2001. The
performance fee, which is based on the Fund's total return and its relative performance compared to other senior conventional
oil and gas trusts, was $12.4 million or 3.5% of the Fund's net operating income for 2002. This performance fee was based
on the Fund earning a total return of approximately 29% for unitholders and placing second out of the eight senior
conventional oil and gas trusts for total return in its peer group. This return was calculated using the ten day weighted average
trading price of the trust units prior to December 31, 2002 and 2001. There was no performance fee recorded for 2001
pursuant to the terms of the management agreement as the Manager received a minimum fee of 172,500 trust units with an
assigned value of $5,000,000 in conjunction with the Merger. This fee was accounted for as a cost of the Merger.
On March 6, 2003, the Fund announced plans to internalize its management structure by acquiring the shares of the
management company, EGEM, from an indirect subsidiary of El Paso Corporation ("El Paso"). The proposed internalization
transaction will result in the elimination of all management fees effective April 23, 2003. Enerplus' unitholders will be asked
to approve the transaction at the annual general and special meeting to be held on April 23, 2003.
Under the terms of the proposed transaction, Enerplus will purchase EGEM for total cash consideration of approximately
$48.9 million. Furthermore, El Paso has agreed to fix the management fees for the period from January 1, 2003 to April 23,
2003 in an amount of $3.2 million.
Retention arrangements, at a maximum cost of $4.7 million to the Fund, have been made for the executive team and staff at
Enerplus to ensure continuity.
The expected benefits of the proposed internalization transaction are as follows:
- The transaction cost represents fair value to unitholders relative to the management fees that have been paid in the past,
the estimated future management fees, and the costs associated with terminating the existing agreement;
- The transaction is immediately accretive to Enerplus' net asset value and cash flow per trust unit;
- The transaction compares favorably in relation to other internalization transactions that have occurred in the energy trust
sector;
- In conjunction with the transaction, Enerplus has taken steps to affirm the continued commitment of the executive;
- The Fund's organizational structure will be simplified and its corporate governance will be improved. For example,
unitholders will be able to elect all nine members of the board of directors rather than just the six independent directors, as
EGEM's right to nominate three directors will be eliminated;
- The transaction may lower Enerplus' cost of capital by increasing the attractiveness of Enerplus trust units to a wider range
of investors, including institutions that have refrained from purchasing entities with external management contracts;
- Furthermore, by eliminating management fees, Enerplus can be more competitive with respect to future acquisitions and
consolidation opportunities within the trust and E&P sectors.
Interest Expense
Interest expense increased to $18.3 million in 2002 from $17.6 million in 2001 as a result of higher average debt outstanding
throughout 2002.
As at December 31, 2002, Enerplus' long-term debt was effectively structured to consist of $268.3 million of floating rate and
$75.0 million of fixed rate debt. Concurrent with the issuance of the US$175.0 million, 6.62% fixed rate senior unsecured
notes, Enerplus swapped the proceeds for CDN$268.3 million with interest based on floating rate three month Canadian
banker's acceptances, plus 1.18% (See Note 2 to the consolidated financial statements). In addition, the Fund entered into
three year fixed interest rate swaps on CDN$75 million as more fully described in Note 7 to the consolidated financial
statements.
Depletion, Depreciation and Amortization
Depletion of property, plant and equipment is provided using the unit-of-production method based on constant price proven
reserves. An estimate of the future costs for restoration and abandonment of well sites and facilities is updated annually and
this cost estimate is amortized over the life of the properties on a unit-of-production basis as part of depletion, depreciation
and amortization expense ("DD&A").
DD&A increased to $213.9 million or $9.33/BOE in 2002 from $194.1 million or $9.85/BOE in 2001. Higher production
volumes during 2002 have increased the total amount of DD&A however, on a BOE basis, DD&A has decreased.
Enerplus places a limit on the carrying value of property, plant and equipment (the "ceiling test"). The cost of these assets less
accumulated depletion, accumulated site restoration and future income taxes is limited to the estimated future net revenue
from proved reserves (based on unescalated prices and costs at the balance sheet date) less estimated future general and
administrative costs, financing costs, management fees and income taxes. The ceiling test at December 31, 2002 was calculated
using the December 31 closing WTI price of US$31.20/bbl and AECO spot price of $4.79/Mcf (2001 - WTI US$19.84/bbl
and AECO spot $3.75/Mcf ). In both 2002 and 2001 the ceiling test resulted in a surplus and accordingly there was no
additional charge to DD&A.
Taxes
Capital taxes, which are based on total debt and equity levels of the Fund's operating companies at the end of the year, increased
to $5.5 million for 2002 from $4.7 million in 2001 primarily due to the increase in the Fund's capital during 2002. According
to the February 2003 Federal Budget, capital taxes are to be gradually eliminated over the next five years.
Future income taxes arise from differences between the accounting and tax bases of the operating companies' assets and
liabilities. In the Fund's structure, payments are made between the operating companies and the Fund transferring both income
and future income tax liability to the unitholders. Therefore, it is the opinion of management that no cash income taxes are
expected to be paid by the operating companies in the future, and as such, the future income tax liability recorded on the
balance sheet will be recovered through earnings over time. For the year ended December 31, 2002, a future income tax
recovery of $35.4 million ($31.5 million on 2001) was recorded in income.
Upon the acquisition of Celsius, a future income tax liability of $42.1 million was recorded. This liability arose as the purchase
price of Celsius' assets exceeded the balance of its tax pools at the date of the acquisition.
Netbacks
|
| Production per day |
|
62,784 |
| Weighted average price (net of hedging) |
$ |
27.11 |
| Royalties, net of ARTC |
|
(5.75) |
| Operating costs |
|
(5.86) |
|
| Operating netback |
|
15.50 |
| General and administrative |
|
(0.70) |
| Management fees |
|
(0.94) |
| Interest expense, net of interest and other income |
|
(0.78) |
| Capital taxes |
|
(0.23) |
| Restoration and abandonment cash costs |
|
(0.20) |
|
| Funds flow from operations |
|
12.65 |
| Depletion and depreciation |
|
(9.07) |
| Amortization of site restoration and hedging, net of cash costs |
|
(0.06) |
| Future income tax recovery |
|
1.54 |
|
| Net income per BOE of production |
$ |
5.06 |
|
Net Income and Funds Flow From Operations
Net income for the year ended December 31, 2002 was $115.9 million, or $1.61 per trust unit, down 36% (51% per trust
unit) from $180.3 million or $3.28 per trust unit for 2001. After adding back non-cash expenses such as depletion,
depreciation and amortization and the future income tax recovery, the resultant funds flow from operations was $289.9 million
in 2002 or $4.03 per trust unit compared to $340.2 million or $6.20 per trust unit in 2001. This decrease in net income and
funds flow from operations is mainly due to the reduction in natural gas prices and the difference between the $50.1 million
gain recognized from crude oil and natural gas hedging contracts during 2001 compared to a hedging cost of $8.7 million
in 2002.
Quarterly Financial Information
|
|
| 2002 |
|
|
| First quarter |
$ |
97.0 |
$ |
9.4 |
$ |
0.13 |
$ |
0.13 |
| Second quarter |
|
120.6 |
|
26.0 |
|
26.0 |
|
0.37 |
| Third quarter |
|
122.3 |
|
29.1 |
|
0.41 |
|
0.41 |
| Fourth quarter |
|
149.7 |
|
51.4 |
|
0.66 |
|
0.66 |
|
|
| Total |
$ |
489.6 |
$ |
115.9 |
$ |
1.61 |
$ |
1.61 |
|
| 2001 |
|
|
| First quarter |
$ |
136.7 |
$ |
59.7 |
$ |
1.42 |
$ |
1.41 |
| Second quarter |
|
109.3 |
|
58.5 |
|
1.30 |
|
1.29 |
| Third quarter |
|
130.9 |
|
25.1 |
|
0.39 |
|
0.39 |
| Fourth quarter |
|
129.8 |
|
37.0 |
|
0.55 |
|
0.55 |
|
|
| Total |
$ |
506.7 |
$ |
180.3 |
$ |
3.28 |
$ |
3.28 |
|
Cash Available for Distribution
Enerplus makes monthly cash distributions to its unitholders based upon the net cash flow from its oil and gas operations. A
portion of this cash flow is typically withheld to repay bank debt incurred with respect to acquisitions and capital spending.
For the year ended December 31, 2002, Enerplus generated $289.9 million in funds flow from operations. Of this amount
(together with certain funds described in the following table), $246.8 million ($3.32 per trust unit) was paid to unitholders
and $46.3 million ($0.62 per trust unit) was retained for debt reduction.
Management monitors the Fund's distribution payout policy with respect to forecasted cash flows, debt levels, and spending
plans. The level of cash retained for debt repayment typically varies between 10% and 20% of annual cash flow, although
management is prepared to adjust the payout levels in an effort to balance the investor's desire for distributions with the Fund's
requirement to maintain a prudent capital structure.
The following table reconciles Enerplus' "Funds Flow from Operations" with the cash available for distribution to unitholders.
Reconciliation of Cash Available for Distribution
|
| Funds flow from operations |
$ |
289.9 |
$ |
340.2 |
| Cash withheld for debt reduction |
|
(46.3) |
|
(46.2) |
| Enerplus cash flows (Note A) |
|
- |
|
16.9 |
| Accruals (Note B) |
|
3.2 |
|
5.6 |
|
| Cash available for distribution (Note C) |
$ |
246.8 |
$ |
316.5 |
|
| Cash available for distribution per trust unit |
$ |
3.32 |
$ |
5.67 |
|
Capital Expenditures
During the year ended December 31, 2002, Enerplus spent $361.7 million compared to $874.4 million in 2001, on capital
expenditures and acquisitions net of divestitures. Enerplus finances its capital expenditures through bank borrowing, new
equity issues, and by withholding a portion of cash otherwise available for distribution.
|
| Development expenditures |
$ |
94.9 |
$ |
87.9 |
| Plant and facilities |
|
46.8 |
|
53.6 |
|
| Sub-total |
|
141.7 |
|
141.5 |
| Office |
|
4.4 |
|
1.8 |
|
| Sub-total |
|
146.1 |
|
143.3 |
| Acquisitions of oil and gas properties |
|
60.6 |
|
77.4 |
| Corporate acquisitions |
|
158.1 |
|
722.2 |
| Dispositions of oil and gas properties |
|
(3.1) |
|
(68.5) |
|
| Total Net Capital Expendituress |
$ |
361.7 |
$ |
874.4 |
|
| Established reserves (MMBOE): |
| Net change in established reserves after production |
|
18.1 |
|
102.2 |
| Annual production |
|
22.9 |
|
19.7 |
|
| Annual established reserve additions |
|
41.0 |
|
121.9 |
|
| Finding, development and acquisition costs ($/BOE): |
$ |
8.82 |
$ |
7.17 |
|
Finding, development and acquisition ("FD&A") costs based on established reserves for the year were $8.82/BOE compared
to $7.17/BOE for 2001. The increase in FD&A costs reflect higher prices paid for acquisitions (in an environment of increased
oil and gas price expectations); a focus on natural gas acquisitions (which typically trade at a higher FD&A cost due to the
attractive economics of natural gas); and the inclusion of Oil Sands Lease #24 (which is a long-term investment with no current
production or established reserve value).
|
| Joarcam |
$ |
22.0 |
$ |
5.1 |
| Medicine Hat |
|
13.3 |
|
13.1 |
| Hanna/Garden Plains |
|
12.9 |
|
26.5 |
| Bantry |
|
6.3 |
|
10.6 |
| Verger |
|
6.0 |
|
1.3 |
| Mount Benjamin |
|
5.7 |
|
6.1 |
| Other |
|
75.5 |
|
78.8 |
|
| Total |
$ |
141.7 |
$ |
141.7 |
|
Enerplus is forecasting capital expenditures of approximately $155 million in 2003 on existing properties. A total of
$95 million or 61% is expected to be invested in development drilling on natural gas projects at Countess, Verger, Bantry,
Medicine Hat, Hanna Garden and other areas. In addition to the development drilling on these properties, a number of wells
will be restimulated in the Medicine Hat, Bantry and Verger areas to improve natural gas productivity.
A total of $45 million is expected to be invested in further development of the oil properties at Progress, Valhalla, Joarcam,
Giltedge, Silver Heights and Cadogan. In addition, Enerplus expects to spend $7 million to develop a steam assisted gravity
drainage pilot on the Oil Sands Lease #24 north of Fort McMurray. Enerplus also expects to spend approximately $8 million
on land and seismic.
Enerplus routinely evaluates its property portfolio and disposes of properties that are viewed as non-core holdings with limited
contribution to cash flow or upside development potential. In 2002, Enerplus sold $3.1 million worth of non-core oil and gas
properties. Enerplus expects to continue its process of rationalizing marginal properties and acquiring new properties in 2003.
Liquidity and Capital Resources
Long-term debt at December 31, 2002 was $361.7 million, which includes $93.4 million of bank indebtedness and
$268.3 million of senior unsecured notes. Although the Fund's investing activities were higher than 2001 primarily due to the
acquisition of Celsius Energy Ltd., long-term debt was reduced by the end of the year with net proceeds from the issue of
13.3 million trust units combined with cash from operations that has been withheld for debt repayments.
During 2002, Enerplus diversified its debt portfolio through the issuance of US$175.0 million senior, unsecured notes with a
coupon rate of 6.62% priced at par (the "Notes"). The Notes have a final maturity of June 19, 2014, with amortizing payments
of 20% per annum on each of the five anniversary dates commencing on June 19, 2010. Concurrent with the issuance of the
Notes, Enerplus swapped the US$175.0 million into Canadian dollar denominated floating rate debt at an exchange rate of
1.5333 for gross proceeds of $268.3 million at a floating interest rate, based on Canadian three month banker's acceptances,
plus 1.18%. This cross currency swap on the senior unsecured notes represented a mark-to-market gain of $37.1 million at
December 31, 2002.
On November 7, 2002 the Fund's $620 million borrowing base with respect to its bank credit facilities and senior unsecured
notes increased to $700 million resulting in the bank credit facilities increasing by $80 million from $351.7 million to
$431.7 million. The limit is based on the bank's evaluation of the value of Enerplus' proven oil and gas reserves and reflected
the additional values attributable to acquisitions completed during the year.
Enerplus plans to finance future commitments with a combination of cash flow from operations, debt, and equity raised in
the Canadian and U.S. markets.
Key financial ratio's for the year were as follows:
|
| 1.1x |
1.2x |
| Funds flow from operations to interest expense |
15.8 |
19.3x |
| Debt to debt plus equity |
19% |
23% |
|
Commitments
Enerplus has contracted to transport 10MMcf/day of natural gas into Chicago on the Foothills and Northern Border pipelines
until October 31, 2008. It has also agreed to transport 5 MMcf/day to Marshfield, Illinois on the TransCanada and Viking
pipelines until October 31, 2008. In addition, Enerplus has pipeline commitments to transport 5 MMcf/day into Chicago on
Alliance Pipeline until October 31, 2015. These contracts apply to 10% of Enerplus' total natural gas production.
Enerplus must continue to pay crown royalties, surface rentals and mineral taxes with respect to its ongoing ownership of
hydrocarbon production rights. The amounts paid with respect of these burdens will depend on the future ownership,
production, prices and legislative environment at the time.
Trust Unit Information
Enerplus had 82,898,000 trust units outstanding at December 31, 2002 compared to 69,532,000 trust units at
December 31, 2001. The weighted average basic number of trust units outstanding during 2002 was 71,946,000
(2001 - 54,907,000).
Income Taxes
The following sets out a general discussion of the Canadian and U.S. tax consequences of holding Enerplus trust units as
capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or
potential unitholders should consult their own legal or tax advisors as to their particular tax consequences.
Canadian Taxpayers
The Fund qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, trust units of the Fund are
qualified investments for RRSPs, RRIFs, RESPs, and DPSPs. Each year, the Fund is required to file an income tax return and
any taxable income in the Fund is allocated to the unitholders.
Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Fund in
that year. An investor's adjusted cost base ("ACB") in a trust unit equals the purchase price of the trust unit less any non-taxable
cash distributions received from the date of acquisition. To the extent a unitholder's ACB is reduced below zero, such amount
will be deemed to be a capital gain to the unitholder and the unitholder's ACB will be brought to $nil.
Enerplus paid $3.25 per trust unit in cash distributions to unitholders during the 2002 calendar year. For Canadian tax
purposes, 34% of these distributions, or $1.10 per trust unit was a tax deferred return of capital, 64% or $2.09 per trust unit
was taxable to unitholders as other income, and 2% or $0.06 per trust unit was taxable dividend income.
U.S. Taxpayers
U.S. unitholders who receive cash distributions are subject to a 15% Canadian withholding tax, applied to the taxable portion
of the distribution as computed under Canadian tax law. U.S. taxpayers may be eligible for a foreign tax credit with respect to
Canadian withholding taxes paid.
The taxable portion of the cash distribution for U.S. tax purposes is determined by Enerplus in relation to its current and
accumulated earnings and profits using U.S. income tax principles. The taxable portion so determined is considered to be a
dividend for U.S. tax purposes.
The non-taxable portion of the cash distribution, is a return of the cost (or other basis). The cost (or other basis) is reduced
by this amount for computing any gain or loss arising from disposition. However, if the full amount of the cost (or other basis)
has been recovered, any further non-taxable distributions should be reported as gains.
Enerplus paid US$2.07 per trust unit to U.S. residents during the 2002 calendar year, of which 28% or US$0.57 per trust
unit was a tax deferred return of capital and 72% or US$1.50 per unit was a taxable dividend.
Risk Factors and Risk Management
Investors that purchase Enerplus trust units are participating in the net cash flow from a portfolio of western Canadian crude
oil and natural gas producing properties. As such, the cash flow paid to investors and the value of Enerplus units are subject
to numerous risk factors. These risk factors, many of which are associated with the oil and gas industry, include, but are not
limited to, the following influences that could affect the Fund's future results:
Commodity Price Risk
The Fund has exposure to movements in oil and natural gas prices that could have a material adverse effect on Enerplus' results
of operations and financial condition which, in turn, could affect the market price of the trust units and the amount of
distributions to unitholders. Oil and natural gas prices may fluctuate in response to a variety of factors including global and
domestic economic conditions, weather conditions, the supply and price of imported oil and liquified natural gas, the
production and storage levels of North American natural gas, political stability, the proximity of reserves to and capacity of
transportation facilities, the price and availability of alternative fuels, and government regulations.
Enerplus uses financial derivative instruments and other hedging mechanisms to limit a portion of the adverse effects resulting from
volatility in natural gas and oil commodity prices while retaining exposure to upside price movements. To the extent commodity price
exposure is hedged, the benefits that would otherwise be experienced if commodity prices were to increase may be forgone. In addition,
the commodity hedging activities could expose the Fund to losses.
Operational Risk
The value of Enerplus trust units is based on the underlying value of the oil and gas reserves. Geological and operational risks
can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and natural gas
prices may increase the risk of write-downs of Enerplus' oil and gas property investments. Higher operating costs may be
difficult to control as increased activity in the oil and gas industry may increase the cost of goods and services and make it
difficult to hire and retain staff which may decrease the amount of cash flow received by the Fund and therefore, reduce
distributions to unitholders.
Enerplus strives to acquire low risk, mature properties with a high proportion of proven reserves, high cash netbacks, long reserve lives,
and predictable production. Similarly, Enerplus participates in lower-risk development projects, while farming out or monetizing
higher risk exploratory prospects.
Each year a significant portion of Enerplus' proven and probable oil and gas reserves are evaluated by a firm of independent reservoir
engineers. Approximately 84% of the net present value of the total established reserves discounted at 12% were evaluated at
December 31, 2002. The Environment, Safety and Reserves Committee has reviewed and approved the reserve report.
Enerplus maintains certain insurance coverages related to liability and property exposures.
Enerplus offers competitive incentive-based compensation packages to attract and retain qualified staff.
Reserves Risk
Oil and natural gas reserves naturally deplete as they are produced over time. Enerplus' ability to replace production depends
on its success in acquiring new reserves and developing existing reserves. Acquisition of oil and gas assets depend on Enerplus'
assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders
and the value of the trust units.
Acquisitions are subject to stringent investment criteria, due diligence, and review. Acquisitions exceeding $10 million require
approval by the Board of Directors. Independent reservoir engineers evaluations are required for acquisitions in excess of $5 million.
Access to Capital Markets
Since Enerplus distributes the majority of its net cash flow to unitholders, it must finance a large portion of its acquisition and
development activity through continued access to the equity and debt capital markets. As such, Enerplus is dependent on
continued access to the capital markets to maintain and grow value for unitholders.
Enerplus has listings on the Toronto and New York stock exchanges and maintains an active investor relations program designed to
facilitate access to equity capital markets.
Enerplus maintains a prudent capital structure by retaining a portion of the cash flow for debt repayment, rationalizing properties
that no longer meet portfolio guidelines, managing capital expenditures within rate of return guidelines, and utilizing the equity
markets when deemed appropriate.
Interest Rate Exposure
The Fund has exposure to movements in interest rates. Changing interest rates can affect borrowing costs and the mark-tomarket
price of yield-based investments such as Enerplus.
Enerplus monitors the interest rate forward market and has fixed the interest rate on a portion of its debt through interest rate swaps
for terms of up to three years.
Foreign Currency Rate Exposure
Enerplus has exposure to fluctuations in foreign currency as a result of the issuance of the senior unsecured notes denominated
in U.S. dollars.
The Fund has hedged its foreign currency exposure on the senior unsecured notes using financial swaps that convert the
U.S. denominated debt to Canadian dollar debt with Canadian dollar interest obligations.
The Fund also has indirect exposure to fluctuations in foreign currency as crude oil sales and a portion of natural gas sales are
based on U.S. dollar indices. Enerplus' oil and gas revenues benefit from a weak Canadian dollar relative to the U.S. dollar.
Enerplus has not entered into any foreign currency hedges with respect to crude oil and natural gas sales. However, the Fund
is monitoring exchange rates, and it may consider locking in the exchange rate on a portion of its U.S. dollar exposure in the future.
Counterparty Risk
Enerplus assumes customer credit risk associated with oil and gas sales, financial hedging transactions, and joint venture
participants.
Management has established credit policies and controls designed to mitigate the risk of default or nonpayment with respect to oil and
gas sales, financial hedging transactions, and joint venture participants.
Environmental and Safety Risk
Environmental and safety risks influence the workforce, operating costs, and compliance with regulatory standards.
Enerplus has a site inspections program and a corrosion risk management program designed to ensure compliance with environmental
laws and regulations.
Enerplus has training and safety programs designed to educate personnel on safety awareness, monitor incidents and prevent accidents.
Regulatory Risk
Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant financial and
operational impact on Enerplus. As a mutual fund trust, Enerplus has a unique structure that is vulnerable to changes in
legislation or income tax law.
Although the Fund has no control over these regulatory risks, Enerplus continuously monitors changes in these areas by participating
in industry conferences and employing qualified individuals to assess the impact of such changes on the Funds' financial and
operating results.
Business Prospects
Enerplus Resources Fund offers investors the benefits of owning a large, diversified portfolio of mature producing crude oil
and natural gas properties without the exploration risks commonly associated with traditional E&P companies. As such,
Enerplus' business prospects will always be closely linked to the opportunities and challenges associated with crude oil and
natural gas production. In particular, Enerplus is strongly influenced by the price of crude oil and natural gas, both of which
have been extremely volatile in recent years.
In 2002, Enerplus delivered a 26.5% total return to unitholders through unit appreciation and monthly cash distributions.
Looking forward to 2003, Enerplus continues to be focused on delivering top quartile returns to investors. The business plan
for 2003 features many of the same strategies that have supported our 17-year track record of success:
Portfolio Optimization
- utilize proven technologies and talented expertise to optimize the performance of existing properties through low-risk
development;
- focus the efforts of technical teams on properties with the most potential to add value;
- dispose of non-core properties with limited upside, and re-deploy the proceeds towards key strategic focus areas;
Risk Management
- hedge oil and natural gas prices on a portion of future production to provide protection in the event of adverse commodity
price movements, realize positive economic returns from acquisitions and development activity, and provide a measure of
stability to the Fund's future cash flows;
- exclude exploration and focus on low-risk development;
Growth
- replace production through a disciplined acquisitions strategy;
- acquire oil and gas producing properties with predictable production profiles, long reserve lives, high cash netbacks, and
opportunities for low risk development;
- consider diversification beyond conventional oil and gas into other energy-related investments such as oil sands and
processing facilities;
- maintain a portfolio of future development opportunities;
- create and maintain a work environment that attracts and retains qualified professionals;
Corporate Governance
- continue to apply high standards of corporate governance and ethics, including compliance with the regulations and
guidelines of Canadian and U.S. securities commissions.
Financing
- utilize debt conservatively;
- diversify credit sources and payment terms;
- hedge interest rates associated with a portion of long-term debt;
- withhold 10 20% of cash flow from operations to contribute towards annual development expenditures;
- maintain an active investor relations department in an effort to maintain access to Canadian and U.S. equity markets;
- issue equity for acquisitions and growth opportunities in a manner that adds value to existing unitholders.
We are entering 2003 in an environment of strong commodity prices, volatile global politics, uncertain economic climate, and
increasing opportunities for acquisitions. Enerplus' strategy is to maintain its discipline and flexibility to take advantage of
opportunities within the context of this marketplace.
Forward Looking Statements
This discussion and analysis contains forward-looking statements relating to future events or future performance. In some
cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expects", "projects",
"plans", "anticipates" and similar expressions. These statements represent management's expectations or beliefs concerning,
among other things, future operating results and various components thereof or the economic performance of Enerplus.
Undue reliance should not be placed on these forward-looking statements which are based upon management's assumptions
and are subject to known and unknown risks and uncertainties, including the business risks discussed above, which may cause
actual performance and financial results in future periods to differ materially from any projections of future performance or
results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause results to differ materially from those predicted. Enerplus undertakes no obligation to update
publicly or revise any forward-looking statements contained herein and such statements are expressly qualified by the
cautionary statement.
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