|
|
 |
|
| 2001 Annual Report > M D & A |
   |
|
Enerplus Unitholders received record cash distributions in 2001
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, 2001 and 2000, and is based
on information available to March 1, 2002. All
amounts are stated in Canadian dollars unless
otherwise specified.
2001 HIGHLIGHTS
- On June 21, 2001, the Unitholders of Enerplus
Resources Fund and EnerMark Income Fund
agreed to combine the two funds and continue
as Enerplus Resources Fund. This created North
America’s largest and most liquid conventional
oil and natural gas income fund with an
enterprise value of approximately $2 billion.
- In connection with the combination of the two
funds, Enerplus restructured its management fee
to better align the interests of the Manager and
the Unitholders by eliminating acquisition and
divestment fees and replacing them with
performance incentive fees.
- Aside from the reverse takeover combination of
Enerplus and EnerMark, acquisitions net of
dispositions of producing oil and gas properties
totaled
$8.9 million during the year ($77.4
million in acquisitions less $68.5 million in
dispositions of non-core properties). The Fund
avoided high cost acquisitions in a high priced
environment for much of 2001 as a result of its
disciplined bidding strategy.
- Enerplus invested $143 million in development
projects in 2001, drilling a record 350 net wells.
- Enerplus’ commodity price risk management
program generated a net gain of $50.1 million
for the year, demonstrating the value of such a
program during periods of price volatility.
- On November 15, 2001, the Fund issued 4,312,500
Trust Units at $24.75 per unit in a successful
Canadian equity issue.
COMBINATION OF ENERMARK AND ENERPLUS
On June 21, 2001, the respective Unitholders of the
EnerMark Income Fund ("EnerMark") and the Enerplus
Resources Fund ("Enerplus") overwhelmingly
approved a 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 continues as Enerplus Resources Fund
which has a 16 year history, market recognition and a
listing on the New York Stock Exchange.
IMPORTANT INFORMATION REGARDING
COMPARATIVE FINANCIAL STATEMENTS
With the reverse takeover method of accounting, the
audited consolidated financial statements presented
herein include the accounts of EnerMark as at, and
for the twelve months ended December 31, 2001, plus
the results of Enerplus for the 193-day period from
June 21, 2001 to December 31, 2001. In addition, the
historical comparative financial information for the
year 2000 presented in the audited consolidated
financial statements is solely that of EnerMark.
In other words, the financial statements do not reflect
the pre-acquisition Enerplus results for the period
from January 1, 2001 to June 20, 2001, nor do they
include the pre-acquisition results of Enerplus for the
year ending December 31, 2000.
The remaining discussion and analysis refers to
Enerplus as the combined Fund, and information
included herein has been restated, as applicable, to
reflect the Trust Unit exchange ratio of 1.000
EnerMark Unit for 0.173 Enerplus Unit, pursuant to
the reverse takeover.
Comparison of 2001 results with those of 2000 is also complicated by the fact that EnerMark, as predecessor to
Enerplus, completed five major acquisitions during 2000. Accordingly, the 2001 financial results include a full year
of operations for these acquisitions, while the 2000 results reflect only a partial-year impact, commencing on the
closing date of each acquisition as set forth below:
 |
Corporate and Property Acquisitions |
($millions) |
Closing Date |
|
| Enerplus Resources Fund |
$ 601 |
Jun. 21, 2001 |
| Cabre Exploration Ltd. (purchase of remaining 11.35% interest) |
32 |
Jan. 8, 2001 |
| Cabre Exploration Ltd. (purchase of 88.65% interest) |
260 |
Dec. 31, 2000 |
| EBOC Energy Ltd. |
148 |
Sep. 1, 2000 |
| Pursuit Resources Corp. |
82 |
Apr. 3, 2000 |
| Hanna / Garden Plains |
35 |
Feb. 28, 2000 |
| Western Star Exploration Ltd. |
22 |
Jan. 7, 2000 |
|
RESULTS OF OPERATIONS
Production
As a result of changing practices in the oil and gas industry in Canada, Enerplus has adopted the standard of 6 Mcf:1
barrel of oil equivalent when converting natural gas to barrels of oil equivalent ("BOE"). 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 averaged 54,015 BOE per day during 2001, representing a
74% increase over production volumes
of 31,112 BOE per day the previous year. The increase is attributed to the reverse takeover of Enerplus by EnerMark
on June 21, 2001, as well as the previously mentioned acquisitions during 2000. The acquisitions in 2000 had a full
year impact on 2001 production, but only a partial-year impact on 2000 production, relative to the respective
closing date of the acquisition.
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, 2001 and 2000 are outlined below:
|
| Daily Production Volumes |
2001 ¹ |
2000 |
% Change |
|
| Natural gas (Mcf/day) |
176,671 |
101,473 |
74% |
| Crude oil (bbls/day) |
20,592 |
12,089 |
70% |
| Natural gas liquids (bbls/day) |
3,978 |
2,111 |
88% |
| Total daily sales (BOE/day) |
54,015 |
31,112 |
74% |
|
¹ 2001 production reflects only 193 days of the post-merger Enerplus production (from June 21, 2001 to December 31, 2001) after the date of the reverse takeover.
Enerplus’ exit production rate averaged 62,300 BOE per day for the month of December 2001, with a weighting of
56% natural gas, 37% crude oil, and 7% natural gas liquids. Production is currently expected to average 61,000 BOE
per day in 2002, after considering a full-year impact from the reverse takeover of Enerplus and a forecast
$130 million in development capital spending, but without taking into account any further acquisitions.
PRICING AND PRICE RISK MANAGEMENT
The average price that Enerplus received for its natural gas (before hedging) increased 9% from $4.52/Mcf in 2000
to $4.91/Mcf in 2001. In comparison, the AECO monthly index increased 25% from $5.02/Mcf in 2000 to $6.30/Mcf
in 2001 and the NYMEX index price increased 12% from $3.91/Mcf in 2000 to $4.38/Mcf in 2001. Enerplus’ realized
gas prices did not increase as much as the reference indices due to:
- Long-term fixed price physical delivery contracts representing approximately
5% of production that were
priced below prevailing index prices in 2001; and
- Sales to aggregators that were also priced below prevailing indices in 2001 because they reflect a basket of
fixed, floating, and downstream delivery contracts.
The average price that Enerplus received for its crude oil (before hedging) decreased 15% from CDN$35.86/bbl in
2000 to CDN$30.48/bbl in 2001. This reflects a comparable 14% decline in the pricing of benchmark West Texas
Intermediate (WTI) crude oil. Enerplus benefited from the weaker Canadian exchange rate and a lighter average
blend of crude oil as a result of recent acquisitions, however, these advantages were offset by wider price differentials
on heavier streams of crude oil during the year.
The realized prices for natural gas liquids ("NGLs") decreased 4% from the previous year to average $31.12/bbl in
2001. However, the price of NGLs as a proportion of Enerplus’ crude oil price increased from 90% in 2000 to 102%
in 2001 reflecting significantly higher values attributed to ethane production in the first half of 2001.
|
| Average Selling Price ($CDN) Before the Effects of Hedging |
2001 |
2000 |
% Change |
|
| Natural gas (per Mcf) |
$ 4.91 |
$ 4.52 |
9% |
| Crude oil (per bbl) |
30.48 |
35.86 |
(15%) |
| Natural gas liquids (per bbl) |
31.12 |
32.33 |
(4)% |
| Total daily sales (per BOE) |
$ 29.89 |
$ 30.94 |
(3)% |
|
|
|
| Benchmark Pricing |
2001 |
2000 |
% Change |
|
| AECO natural gas (per Mcf) |
$ 6.30 |
$ 5.02 |
25% |
| NYMEX natural gas (US$ per Mcf) |
4.38 |
3.91 |
12% |
| WTI crude oil (US$ per bbl) |
25.97 |
30.19 |
(14)% |
| CDN$/US$ exchange rate |
$ 0.6458 |
$ 0.6736 |
(4)% |
|
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 2001, Enerplus realized a gain of $50.1 million as a result of its price risk management program, as
outlined below:
|
| Opportunity Gain (Loss) from Financial Hedging ($millions) |
2001 |
2000 |
|
| Crude oil |
$ 5.5 |
$ (9.6) |
| Natural gas |
44.6 |
0.5 |
| | | |
| Net hedging opportunity gain (loss) |
$ 50.1 |
$ (9.1) |
| | | |
| Net gain (loss) per bbl crude oil |
$ 0.73 |
$ (2.19) |
| Net gain (loss) per Mcf natural gas |
$ 0.69 |
$ 0.01 |
|
Enerplus’ commodity risk management position as at December 31, 2001 is described in Note 8 to the 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 hedge position.
At December 31, 2001, Enerplus had $4.6 million in deferred costs related to forward contracts that will be amortized
over the remaining life of those instruments. The mark-to-market value of the financial forward contracts represented
an unrealized loss of $0.4 million with reference to year-end prices and forward markets.
Subsequent to year end, on January 8, 2002, Enerplus entered into an additional
3-way financial option on
1,500 bbls/day of oil from April 2002 to December 2003. Under the terms of this option Enerplus purchased a WTI
put at US$19.50/bbl, sold a WTI call at US$27.00/bbl and sold a WTI put at US$17.00/bbl. Enerplus also entered into
a 3-way option on 9,480 Mcf/day of natural gas for the period from April to October 2002, selling an AECO call at
$4.22/Mcf, purchasing an AECO put at $3.29/Mcf and selling an AECO put at $2.37/Mcf. The cost of this gas price
protection was mitigated by selling an AECO call at $6.33/Mcf for the period from November 2002 to March 2003.
In the future, Enerplus intends to continue to manage its commodity price exposure in a similar manner with the
objective of establishing downside price protection at a reasonable cost, while maintaining exposure to improving
prices. The future gain or loss from such a program depends on forward markets and future prices. Readers are
cautioned that the significant hedging gains experienced in 2001 are not expected to be replicated in 2002.
REVENUES
Crude oil and natural gas revenues, including hedging gains, were $639.4 million for the year ended
December 31, 2001, which was 86% higher than the $343.2 million reported for the year ended December 31, 2000.
This substantial increase was due to the reverse takeover of Enerplus on June 21, 2001, as well as the acquisitions of
Cabre, EBOC, Pursuit, and Western Star and the acquisition of the Hanna/Garden Plains property during 2000. The
acquisitions in 2000 had a full year impact on 2001 revenues, but only a partial-year impact on 2000 revenues,
depending on the closing date of the acquisition. Enerplus’ 2001 increase in revenues was primarily the result of
lighter production volumes and hedging gains offset by a slight reduction in prices as described in the table below.
|
| Analysis of Sales Revenues ($millions) |
Crude Oil
Revenues |
NGL
Revenues |
Natural Gas
Revenues |
Total
Revenues |
|
| 2000 Sales Revenues |
$ 149.0 |
$ 25.0 |
$ 169.2 |
$ 343.2 |
| Price variance |
(40.4) |
(1.8) |
25.1 |
(17.1) |
| Volume variance |
110.8 |
22.0 |
121.3 |
254.1 |
| Hedging gain variance |
15.1 |
- |
44.1 |
59.2 |
| | |
| 2001 Sales Revenues |
$ 234.5 |
$ 45.2 |
$ 359.7 |
$ 639.4 |
|
ROYALTIES
Royalties increased by $51.7 million to $132.7 million for the year ended
December 31, 2001, as a consequence of
the increase in production revenue. The royalty rate before hedging for the year ended December 31, 2001,
decreased to 22.5% from 23.0% for the year 2000. In the current commodity price environment, Enerplus expects a
royalty rate of approximately 21% for 2002, without taking into account future acquisitions.
OPERATING EXPENSES
Operating expenses increased to $120.1 million for the year ended December 31, 2001 from $55.0 million in 2000,
due mainly to the higher production volumes associated with acquisition activities. This represents a cost of
$6.09/BOE in 2001 compared to $4.83/BOE in 2000. Increased activity levels in the industry during the first nine
months of 2001 created a higher demand for goods and services and placed a corresponding upward pressure on
costs. In addition, Enerplus experienced higher electricity costs in the first half of 2001 compared to 2000. Finally, the
acquisition of properties during 2000 and 2001 with relatively higher operating costs than the pre-existing property
portfolio added to Enerplus’ operating cost per BOE.
Lower electricity costs and reduced activity levels in the industry are expected to stabilize and moderate Enerplus’
operating expenses in 2002.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses were $13.0 million for the year ended
December 31, 2001 compared to
$7.2 million for the year 2000. The increase reflects the additional costs of managing entities acquired during 2000
for a full year. General and administrative costs per BOE of production increased marginally to $0.66/BOE for 2001
compared to $0.63/BOE for 2000.
In accordance with the full cost method of accounting, Enerplus capitalized $7.5 million of G&A costs in 2001
compared to $7.9 million capitalized in 2000. The majority of these capitalized costs represent compensation costs
for staff involved in development drilling and acquisition activities.
In 2002 the Fund is targeting G&A costs of approximately $0.60/BOE, before taking into account any further acquisitions.
MANAGEMENT FEES
Management services are supplied to Enerplus on a fee and cost reimbursement basis. Management fees expensed
were $9.3 million for the year ended December 31, 2001 represents an increase of $4.8 million over the year 2000 as
a result of higher operating income as well as the increase in the base management fee percentage as discussed
below relative to the restructuring of management fees in their entirety.
In conjunction with the reverse takeover of Enerplus, a new management agreement was approved by the Unitholders
on June 21, 2001. Under the new agreement, base management fees were set at 2.75% of operating income
(compared to
pre-June 21, 2001 rates of 2.2% for EnerMark and 3.5% for Enerplus). In addition, acquisition and
divestment fees (capitalized for financial statement purposes) were eliminated and were replaced by performance
fees based on both the total return of the Fund, and its relative performance as compared to other senior conventional
oil and gas trusts. The performance fee can range between 0% and 4% of operating income. In connection with the
merger, the management company was paid a fee of 172,500 Enerplus Trust Units with a value of $5 million in 2001,
which was capitalized as part of the merger cost. The management fee is described in Note 6 to the financial
statements.
In 2002, the base management fee will be 2.75% of the Fund’s operating income. In addition, there are two types
of incremental performance fees which can range in aggregate from 0% to 4%:
Total Return Performance Fee (minimum 0%, maximum 2% of the Fund’s operating income)
- If the total return of Enerplus Units (amount of distributions and appreciation in Trust Unit price) exceeds 11%,
then the Total Return Performance Fee will be a minimum of 0.5%.
- If the total return of Enerplus Units is less than the yield on 10-year Government of Canada bonds plus 5%;
then the Total Return Performance Fee will be 0% (subject to the minimum payment described in (1) above).
- If the total return of Enerplus Units exceeds the yield on 10-year Government of Canada bonds plus 15%; then
the Total Return Performance Fee will be 2% of the operating income of the Fund.
- If the total return of Enerplus Units is between the yield on 10-year Government of Canada bonds plus a factor
of 5% to 15% (subject to the minimum payment described in (1) above), then a sliding scale calculation
(ranging from 0% to 2%) will be used.
Relative Performance Fee (minimum 0%, maximum 2% of the Fund’s operating income)
- The relative performance of Enerplus as compared to seven other qualifying conventional oil and gas trusts
will be ranked based on distributions and unit price appreciation.
- The Relative Performance Fee will be calculated using a percentage equal to 2% divided by the number of
trusts in the top half of the rankings multiplied by the number of rankings which Enerplus is below the number
one ranking and subtracting the product obtained thereby from 2%; and
- If the resulting value obtained is less than zero, then no Relative Performance Fee will be paid, otherwise the
Relative Performance Fee will be the amount obtained by multiplying the resulting percentage (not to
exceed 2%) by the operating income of the Fund.
In effect, Enerplus must rank at least fourth out of the eight largest conventional oil and gas trusts (including
Enerplus) before any Relative Performance Fee is payable.
This fee arrangement will be reviewed annually with the Board of Directors. The new management fee arrangements
were designed to better align the interests of the Manager with the interests of Unitholders.
INTEREST EXPENSE
Interest expense for the year 2001 was $17.6 million, up $2.3 million from 2000 due to higher outstanding bank debt
incurred in connection with the acquisition activities in 2000 and 2001. Bank debt increased to $412.6 million at
December 31, 2001 from $275.9 million on December 31, 2000.
During 2001, Enerplus’ interest costs were entirely based on floating rates, as those rates offered the most
cost-effective financing strategy. Subsequent to the year end, Enerplus entered into an interest rate swap that fixed
the rate on a notional $25 million in debt for a three year term from January 18, 2002 to January 18, 2005 at a rate
of 3.89% per annum (before banking fees that are expected to range between 0.85% and 1.05%). Enerplus may
consider fixing an additional portion of its interest rate exposure in 2002, depending on its financing requirements
and the forward interest rate market.
DEPLETION AND CEILING TEST
Depletion of the property, plant and equipment is provided on 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.
|
| |
2001 |
2000 |
|
| Depletion and depreciation |
$ 181.1 |
$ 76.5 |
| Amortization of future site restoration |
5.9 |
3.8 |
| Amortization of deferred hedging costs |
7.1 |
- |
| | | |
| Total |
$ 194.1 |
$ 80.3 |
|
Depletion, depreciation and amortization increased to $194.1 million in 2001 from
$80.3 million in 2000. Included
in the amortization amount are $7.1 million of amortized costs relating to the mark-to-market value of the Enerplus
commodity price forward contracts at the time of the reverse takeover. The mark-to-market value of these contracts
was recognized as either a deferred hedge asset or liability as part of the acquisition cost and will be amortized over
the remaining term of the contract ending in 2004. The actual gain (or loss) associated with this contract will be
recognized in oil and gas sales as they are realized.
The rate of depletion and depreciation has increased to $9.18/BOE in 2001 from $6.72/BOE in 2000. The increase is
the result of higher costs attributed to petroleum and natural gas assets acquired during 2000 and 2001. The
adoption of the liability method of accounting for future income taxes, as required by Canadian generally accepted
accounting principles, had the effect of substantially increasing the recorded value of acquired property, plant and
equipment compared to the previous deferral method of accounting. In the case of the corporate acquisitions in
2000 the value of acquired assets were increased to reflect any shortfall between the net book value and the cost
basis for income tax purposes.
Enerplus places a limit on the carrying value of property, plant and equipment (the "ceiling test"). The cost of these
assets, less accumulated depletion, 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, and management fees. There was a surplus in the ceiling test at year end 2001.
TAXES
Capital taxes increased to $4.7 million for the year 2001 from $2.9 million in 2000 primarily due to the increase in
capital structure.
For the year ended December 31, 2001, a future income tax recovery of $31.5 million was recorded in income. Under
Canadian generally accepted accounting principles, the Fund does not recognize any future income taxes, as
taxable income is distributed to Unitholders in the form of taxable distributions. However, the Fund’s operating
companies are required to account for future income taxes. Future income taxes arise because of the difference
between the accounting and tax bases of the operating companies’ assets and liabilities.
NETBACKS
|
| Netbacks per BOE of Production (6:1) year ended December 31, |
2001 |
2000 |
|
| Oil and Gas sales |
$ 32.43 |
$ 30.14 |
| Royalties |
(6.73) |
(7.10) |
| Operating expenses |
(6.09) |
(4.83) |
| General and administrative expenses |
(0.66) |
(0.63) |
| Management fees |
(0.47) |
(0.40) |
| Interest expense, net of interest and other income |
(0.85) |
(1.30) |
| Capital taxes |
(0.24) |
(0.26) |
| Restoration and abandonment cash costs |
(0.13) |
(0.13) |
| | | |
| Funds flow from operations |
17.26 |
15.49 |
| Depletion and depreciation |
(9.18) |
(6.72) |
| Amortization, net of cash costs |
(0.54) |
(0.21) |
| Future income tax recovery (provision) |
1.60 |
(1.35) |
| | | |
| Net income per BOE of production |
$ 9.14 |
$ 7.21 |
|
NET INCOME AND FUNDS FLOW FROM OPERATIONS
Net income for the year ended December 31, 2001 was $180.3 million, or
$3.28 per Trust Unit, up 119% (7% per Trust
Unit) from $82.2 million or
$3.06 per Trust Unit for the year 2000. After adding back non-cash expenses such as
depletion, depreciation, amortization and the future income tax provision (recovery), the resultant Funds Flow
from Operations was $340.2 million in 2001 or
$6.20 per Trust Unit compared to $176.4 million or $6.57 per Trust Unit
in 2000.
QUARTERLY FINANCIAL INFORMATION
|
| $millions, except per Unit amounts |
Oil and Gas
Revenue Net
of Royalties |
Net Income |
Net Income per Unit |
| Basic |
Diluted |
|
| 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 |
|
| 2000 |
| First Quarter |
$ 43.5 |
$ 10.1 |
$ 0.45 |
$ 0.45 |
| Second Quarter |
55.4 |
10.9 |
0.42 |
0.42 |
| Third Quarter |
68.6 |
23.9 |
0.88 |
0.88 |
| Fourth Quarter |
94.7 |
37.3 |
1.16 |
1.16 |
| | | |
| Total |
$ 262.2 |
$ 82.2 |
$ 3.06 |
$ 3.05 |
|
CASH AVAILABLE FOR DISTRIBUTION
Enerplus distributes the net cash flow from its oil and gas properties to the Trust Unitholders on a monthly basis.
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, 2001, Enerplus generated $340.2 million in Funds Flow from Operations.
Of this amount (together with certain funds described in the following table), $316.5 million was paid to Unitholders
and $48.8 million was retained for debt reduction.
Management monitors the Fund’s distribution payout policy with respect to forecast cash flows, debt levels, and
spending plans. The level of cash retained for debt repayment typically varies between 5% and 10% of total 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" as per the Statement of Cash Flows with the
cash available for distribution to Unitholders.
|
Reconciliation of Cash Available for Distribution for the year ended December 31,
$millions except per Unit amounts |
2001 |
2000 |
|
| Funds flow from operations |
$ 340.2 |
$ 176.4 |
| Site restoration and abandonment costs incurred |
2.6 |
1.4 |
| Cash withheld for debt reduction |
(48.8) |
(11.7) |
| Enerplus cash flows (Note A) |
16.9 |
- |
| Accruals (Note B) |
5.6 |
- |
| Pursuit cash flows, net of debt reduction (Note C) |
- |
2.1 |
| | | |
| Cash available for distribution (Note D) |
$ 316.5 |
$ 168.2 |
| | | |
| Cash available for distribution per Trust Unit |
$ 5.67 |
$ 5.49 |
|
Cash available for distribution per Trust Unit of $5.67 for 2001 represent what an EnerMark Unitholder would have
received for the 2001 production year (which was paid to Unitholders from March 20, 2001 to February 20, 2002)
after converting
1 EnerMark Unit for 0.173 Enerplus Unit pursuant to the terms of the Merger. Similarly, cash
available for distribution of $5.49 per Trust Unit for the 2000 production year was paid to EnerMark Unitholders
between March 20, 2000 and February 20, 2001.
| Note A: |
As a result of the reverse takeover, funds flow from operations do not include funds earned by the
former Enerplus prior to June 21, 2001. However, cash distributions include the July/August payment in
respect of this cash flow. As a result, the July/August payment to Unitholders is added to funds flow from
operations for purposes of this reconciliation. |
| Note B: |
According to the current Royalty Agreement with Enerplus Resources Corporation, the royalty paid to
the Fund must be on a cash basis. As a consequence, the change in accrued net revenues for the year are
added back to funds flow from operations for purposes of this reconciliation. |
| Note C: |
In the acquisition of Pursuit Resources Corp., Enerplus distributed a portion of the Pursuit net cash flow
generated between the effective date and the closing date of the acquisition. |
| Note D: |
The cash for distribution of $316.5 million in 2001 can be reconciled to the cash paid to Unitholders of
$328.9 million on the Statement of Cash Flows by subtracting the January and February 2001 payments
to Unitholders and adding the January and February 2002 payments to Unitholders, as the Statement of
Cash Flows reflects cash payments to Unitholders during the calendar year. |
CAPITAL EXPENDITURES
During the year ended December 31, 2001, Enerplus spent $152.2 million
(2000 - $65.8 million) on capital expenditures
and acquisitions net of divestitures.
|
| Capital Expenditures for the year ended December 31, $millions |
2001 |
2000 |
|
| Development drilling and completions |
$ 83.0 |
$ 27.1 |
| Plant and facilities |
53.6 |
11.9 |
| Office and other expenditures |
6.7 |
1.0 |
| | | |
| Total |
143.3 |
40.0 |
| Acquisitions of oil and gas properties |
77.4 |
51.1 |
| Dispositions of oil and gas properties |
(68.5) |
(25.3) |
| | | |
| Total Net Capital Expenditures |
$ 152.2 |
$ 65.8 |
|
|
| Capital Expenditures for the year ended December 31, ($millions) |
2001 |
2000 |
Development
Drilling |
Facilities |
Other |
Total |
Total |
|
| Hanna / Garden Plains |
$ 11.5 |
$ 11.9 |
$ 1.7 |
$ 25.1 |
$ 3.5 |
| Pembina Five Way |
7.2 |
1.7 |
- |
8.9 |
- |
| Medicine Hat |
6.7 |
5.8 |
- |
12.5 |
0.5 |
| Bantry |
7.7 |
2.3 |
- |
10.0 |
1.9 |
| Benjamin |
2.4 |
3.2 |
0.1 |
5.7 |
1.4 |
| Giltedge |
0.4 |
3.8 |
- |
4.2 |
9.7 |
| Other |
47.1 |
24.9 |
4.9 |
76.9 |
23.0 |
| | |
| Total |
$ 83.0 |
$ 53.6 |
$ 6.7 |
$ 143.3 |
$ 40.0 |
|
Enerplus is currently forecasting capital expenditures of approximately $130 million in 2002 on existing properties.
Of this total, Enerplus expects to spend $20 million at Joarcam drilling 18 potential oil wells and 5 potential gas
wells, recompleting 30 wells, and increasing the facility infrastructure capacity in the region. At Hanna/Garden
Plains, Enerplus expects to spend $12 million drilling 75 shallow gas wells, performing well workovers and completing
facility modifications. At Medicine Hat North, the capital budget of $9 million includes drilling 50 potential gas wells
and installation of compression in the region. At Bantry, Enerplus expects to spend $5 million drilling
37 potential
gas wells and refracing existing wells.
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 2001, Enerplus sold $68.5 million worth
of non-core oil and gas properties. Offsetting these dispositions were $77.4 million of acquisitions for the year,
including $25.0 million on Kaybob, $8.8 million on Ferrier, and $8.3 million on Gleneath. Enerplus expects to
continue its process of rationalizing marginal properties and acquiring new properties in 2002.
LIQUIDITY AND CAPITAL RESOURCES
Enerplus’ bank debt increased to $412.6 million as at December 31, 2001 compared to $275.9 million at
December 31, 2000.
|
| Continuity of Bank Debt ($millions) |
2001 |
2000 |
|
| Beginning balance January 1, |
$ 275.9 |
$ 131.3 |
| Items that affect bank debt as per Statement of Cash Flows |
|
|
| Purchase of property, plant and equipment |
243.0 |
251.9 |
| Proceeds on sale of property, plant and equipment |
(75.3) |
(18.5) |
| Assumption of acquired entities' bank debt |
78.6 |
66.9 |
| Proceeds from issue of Trust Units |
(151.4) |
(120.6) |
| Cash distributions paid to Unitholders during the calendar year |
328.9 |
132.6 |
| Fund flow from operating activities (on an accrued basis) |
(340.2) |
(176.4) |
| Increase in non-cash operating working capital |
52.9 |
11.4 |
| Other |
0.2 |
(2.7) |
| | | |
| Ending Bank Debt December 31, |
$ 412.6 |
$ 275.9 |
| | | |
| Bank Debt per Trust Unit at December 31, |
$ 5.93 |
$ 6.74 |
|
As at March 1, 2002, Enerplus renegotiated its bank facilities and consolidated the bank lines of the former EnerMark
and Enerplus operating companies. Enerplus currently has $620 million committed under the unsecured bank
facilities with a syndicate of 7 banks, comprised of a $590 million revolving 364 day committed facility with an
incremental amortizing two-year term, and an additional $30 million demand operating facility. These credit
facilities have no financial covenants, however, the size of the facility is based on the banks’ evaluation of the value
of Enerplus’ proven oil and gas reserves. The banks have reserved the right to revise the commitment based on a
review of the year end reserve information. The bank debt has priority over claims of and distributions to the
Unitholders. However, Unitholders have no direct liability with respect to the bank loan should revenues be
insufficient to repay it.
In the event that the revolving bank line is not extended at the end of the 364 day revolving period, no payments
are required to be made to non-extending lenders during the first year of the term period. However, Enerplus will
be required to maintain certain minimum balances on deposit with the syndicate agent.
|
| Financial Leverage and Coverage |
2001 |
2000 |
|
| Bank debt to funds flow from operations |
1.2x |
1.6x |
| Funds flow from operations to interest expense |
19.3x |
11.5x |
| Bank debt to bank debt plus equity |
23% |
27% |
|
Enerplus has no off-balance sheet financing arrangements.
In 2002, Enerplus may consider replacing a portion of its bank debt with term debt (such as 5-10 year debentures) in order
to diversify credit sources, secure term financing commitments, and potentially fix interest rates for a longer term.
NATURAL GAS PIPELINE 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.
TRUST UNIT INFORMATION
Enerplus had 69,532,000 Trust Units and no warrants outstanding at
December 31, 2001 compared to 40,925,000
Trust Units and 3,045,000 warrants at
December 31, 2000. The weighted number of Trust Units outstanding during
2001 was 54,907,000 (2000 - 26,841,000).
During 2001, Enerplus issued 20,863,000 additional Trust Units pursuant to the Merger agreement on June 21, 2001.
In addition, 1,267,000 Trust Units were issued to acquire the non-controlling interest with respect to the Cabre
acquisition, and
4,312,500 Trust Units were issued pursuant to the November 15, 2001 equity offering. Enerplus also
issued 3,045,000 warrants on December 31, 2000 and an additional 390,000 warrants on January 8, 2001 pursuant to
the Cabre acquisition, of which 1,197,000 were exercised during 2001 and 2,238,000 expired on
December 17, 2001.
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 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 $6.25 per Trust Unit in cash distributions to Unitholders during the 2001 calendar year. For Canadian
tax purposes, 25% of these distributions, or $1.54 per Unit was a tax deferred return of capital, 74% or $4.6269 per
Unit was taxable to Unitholders as other income, and 1% or $0.0831 per 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$3.83 per Trust Unit to U.S. residents during the 2001 calendar year, of which 13% or US$0.49 per
Unit was a tax deferred return of capital and 87% or US$3.34 per Unit was a taxable dividend.
BUSINESS RISKS
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:
- The prices that Enerplus receives for its crude oil, natural gas, and NGLs can fluctuate significantly due to
global and North American supply and demand, worldwide economic conditions, weather, political stability,
Canada/U.S. exchange rates, the proximity to and capacity of transportation and processing facilities, the
price and availability of alternative fuels and government regulations. Declines in oil or natural gas prices
will have an adverse effect on our operations, financial condition, reserves and ultimately our ability to pay
distributions to Trust Unitholders.
- 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. Since Enerplus
distributes the majority of its net cash flow to Unitholders, it must finance a large portion of this acquisition
and development activity through continued access to the equity and debt capital markets. As such, it is
dependent on continued access to the capital markets to maintain and grow value for Unitholders.
- 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.
- 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 increase the risk of write-downs of Enerplus’ oil and gas
property investments.
- Changing interest rates can affect borrowing costs and the market price of
yield-based investments such
as Enerplus.
- Government royalties, income tax laws, environmental laws and regulatory requirements can have a significant
financial and operational impact on Enerplus.
- 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.
- Third party operators operate approximately 35% of Enerplus’ production, which reduces Enerplus’ ability
to control costs, capital, and operation activities with respect to these properties.
- Enerplus assumes customer credit risk associated with oil and gas sales, financial hedging transactions, and
joint venture participants.
- Environmental and safety risks influence the workforce, operating costs, and compliance with regulatory
standards.
Enerplus has no control over many of these risk factors. Nevertheless, management has attempted to mitigate some
of these risks through the following:
- Enerplus has an ongoing commodity price risk management strategy that is intended to provide price
protection on a portion of its future production in the event of adverse commodity price movement, while
retaining exposure to upside price movements.
- 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 appropriate.
- Acquisitions are subject to stringent investment criteria, due diligence, and review and approval by the
Fund’s Board of Directors. Independent reservoir engineers evaluations are required for acquisitions in
excess of $5 million.
- 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 83% of the net present value of the total established
reserves discounted at 12% were evaluated at December 31, 2001. A special committee of the Board of
Directors reviews and approves the reserve report.
- Enerplus monitors the interest rate forward market and has recently begun to fix the interest rate on a
portion of its debt through interest rate swaps for terms up to 3 years. In addition, the Fund may consider
fixing longer-term interest rates in conjunction with the issuance of longer-term debentures.
- Management has established credit policies and controls designed to limit the risk of default or nonpayment
with respect to oil and gas sales, financial hedging transactions, and joint venture participants.
- Enerplus offers competitive incentive-based compensation packages to attract and retain qualified staff.
- Enerplus has employee training and safety programs designed to educate on safety awareness, monitor
incidents and prevent accidents.
- Enerplus has a site inspections program and a corrosion risk management program designed to ensure
compliance with environmental laws and regulations.
- Enerplus maintains certain insurance coverages related to liability and property exposures.
BUSINESS PROSPECTS
Enerplus strives to be the premier oil and gas income fund in North America by continuing to deliver top quartile
returns to its Unitholders. The Fund’s objective is to increase value for Unitholders through successful acquisitions
and the low-risk development of its existing properties utilizing technology, creativity and innovation.
Enerplus offers investors the benefits of owning a diversified portfolio of mature crude oil and natural gas producing
properties and related facilities. As such, the most influential factor affecting the future prospects of the Fund is the
price of crude oil and natural gas. Commodity prices continue to be volatile and difficult to forecast.
Natural gas prices are expected to remain weak for the first part of 2002, or until such time as economic and
weather-related demand can reduce the current North American storage oversupply. Over the longer term, Enerplus
expects natural gas prices to strengthen, although not to the elevated levels experienced in the first quarter of 2001.
A cyclical re-balancing of gas supply is expected as reduced exploration and development drilling, combined with
natural reservoir depletion, reduces supplies at the same time North American demand is recovering.
The price of crude oil has weakened since the third quarter of 2001 due to reduced economic demand and the
threat that OPEC may abandon its production quota practices in an attempt to regain market share from non-OPEC
nations. Other developments, such as continued political instability in the Middle East, natural reservoir declines,
reduced exploration and development drilling, and signs of a worldwide economic recovery are creating
compensating upward pressure on oil prices.
Enerplus has a price risk management strategy that is designed to provide a measure of price protection in the event
of adverse commodity price movement, while retaining exposure to upside price movements. At year end,
approximately 28% of Enerplus’ expected natural gas production and 15% of its expected crude oil production was
protected against downward price movement. Even with these positions, the Fund’s cash flow remains sensitive to
changes in commodity prices as demonstrated by the following table:
|
| Sensitivity to Changes in Price and Exchange Rate |
Effect on 2002
Distributions per Trust Unit |
|
| Change of CDN$0.10 per Mcf in the price of natural gas |
$ 0.07 |
| Change of US$1.00 per barrel in the price of WTI crude oil |
$ 0.15 |
| Change of 1,000 BOE / day in production |
$ 0.06 |
| Change of $0.01 in the US$ / CDN$ exchange rate |
$ 0.04 |
| Change of 1% in interest rate |
$ 0.05 |
|
As with most yield-based investments, the level of interest rates can have an impact on the trading value of Enerplus
Trust Units. The recent period of declining interest rates has had a positive impact on Enerplus’ Trust Unit value and
the Fund’s ability to raise capital. While the prospect of an economic recovery may reverse the current trend of low
interest rates, such a recovery would be positive for the oil and natural gas markets, and it is expected that the
benefits associated with a commodity price recovery far outweighs the risk of rising short-term interest rates.
The combination of Enerplus and EnerMark has created the largest conventional oil and gas income fund in North
America. It has increased liquidity for investors and attracted a broader base of institutional and U.S. investors
through its listings on the TSE and NYSE. More importantly, it has improved the Fund’s access to capital and its
ability to pursue large acquisition opportunities.
Enerplus also has numerous internal development opportunities on existing properties, including low risk
development drilling, the application of waterflood technology, and application of incremental recovery techniques
designed to increase production and improve reservoir recoveries. In particular, Enerplus has a large inventory
of low-cost shallow gas drilling opportunities that can be activated quickly in the event of a recovery in natural
gas prices.
As Enerplus distributes much of its net cash flow, its ability to replace production and grow Unitholder value
depends on its success in acquiring new reserves. Although Enerplus bid on numerous asset and corporate packages
throughout 2001, the Fund was largely unsuccessful due to its disciplined acquisition criteria. With the recent
decline in commodity prices, the desire or need of many E&P companies to strengthen their balance sheets, and the
asset rationalization that typically follows a period of industry consolidation, we expect that 2002 will bring better
opportunities to acquire quality properties at more reasonable prices.
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. The projections, estimates and beliefs contained in such forward-looking statements
necessarily involve 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.
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