Shiningbank Energy Income Fund

Shiningbank Energy Income Fund

March 04, 2005 09:00 ET

Shiningbank Energy Announces 2004 Financial Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: SHININGBANK ENERGY INCOME FUND

TSX SYMBOL: SHN.UN

MARCH 4, 2005 - 09:00 ET

Shiningbank Energy Announces 2004 Financial Results

CALGARY, ALBERTA--(CCNMatthews - March 4, 2005) - Shiningbank Energy
Income Fund (the "Fund" or "Shiningbank") (TSX:SHN.UN), today announced
its audited financial results for the year ended December 31, 2004.

2004 HIGHLIGHTS

- Production volumes increased by 19% over 2003 to average 19,933 boe/d
of which 72% was natural gas.

- Production increases were mainly due to the acquisition of the
Birchill Resources Limited in early 2004 and the subsequent development
drilling.

- Revenues increased by 24% in 2004 to $307.5 million, as a result of
higher production volumes and commodity prices.

- Net earnings before income tax increased by 3% to $52.6 million from
$51.2 million in 2003.

- Net earnings after income tax increased by 117% to $138.8 million from
$64.0 million due to a $74.8 million one-time recovery of future income
taxes related to a corporate restructuring completed in the fourth
quarter. This had no effect on cash flow or distributions.

- Cash flow before change in non-cash working capital increased 29% in
2004 to $174.9 million, up from $136.0 million in 2003.

- Fourth quarter distributions totaling $37.4 million resulted in a
payout ratio of 79% in the quarter and 84% for the year.

- The combination of strong commodity prices and level operating
expenses, 1% higher than in 2003, resulted in record operating netbacks
of $25.96 per boe.

- The Fund's balance sheet ended the year in very healthy condition with
a debt to annual cash flow ratio of 1 to 1.

- Investors' pre-tax total return for 2004 amounted to 30%, comprised of
a 15% cash-on-cash distribution yield and a 15% increase in unit price.

Shiningbank Energy Income Fund - 2004 Financial and Operating Highlights



Shiningbank Energy Income Fund - 2004 Financial and Operating Highlights

------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------
2004 2003(1) % 2004 2003(1) %
------------------------------------------------------------------------
FINANCIAL
($ thousands
except per
Trust Unit
amounts)
Oil and natural
gas sales(2) $ 82,453 $ 58,474 41 $ 307,514 $ 247,207 24
Net earnings
before
income tax 13,974 6,092 129 52,607 51,232 3
Future income tax
(recovery) (74,064) 738 (10,136) (86,199) (12,722) 578
Net earnings after
income tax 88,038 5,354 1,544 138,806 63,954 117
Cash flow before
change in 47,220 30,082 57 174,878 136,038 29
non-cash
working capital
Distributions to
unitholders 37,390 30,629 22 146,360 122,287 20
Distributions per
Trust Unit 0.69 0.69 - 2.76 2.85 (3)
Long term debt 182,147 121,691 50 182,147 121,691 50
Unitholders'
equity 515,944 364,215 42 515,944 364,215 42
------------------------------------------------------------------------

OPERATIONS
Daily Production
Oil (bbl/d) 2,502 2,018 24 2,381 2,023 18
Natural gas
(mmcf/d) 90.4 76.6 18 86.6 74.9 16
Natural gas
liquids (bbl/d) 3,259 2,530 29 3,125 2,252 39
Oil equivalent
(boe/d) 20,833 17,311 20 19,933 16,759 19
Average Prices
(including
hedging)(2)
Oil ($/bbl) $ 42.61 $ 33.62 27 $ 43.14 $ 37.95 14
Natural gas
($/mcf) $ 7.20 $ 6.32 14 $ 7.06 $ 7.00 1
Natural gas
liquids ($/bbl)$ 43.70 $ 32.93 33 $ 40.24 $ 33.65 20
Oil equivalent
($/boe) $ 43.23 $ 36.71 18 $ 42.14 $ 40.42 4
------------------------------------------------------------------------

UNIT TRADING
Units traded
(thousands) 12,715 9,073 40 44,001 37,262 18
Value traded
($ thousands) $ 277,894 $ 153,851 81 $ 865,687 $ 612,995 41
Unit price
High $ 23.98 $ 18.99 $ 23.98 $ 18.99
Low $ 20.01 $ 15.05 $ 16.51 $ 14.80
Close $ 21.49 $ 18.64 $ 21.49 $ 18.64
Units
outstanding
(thousands) 54,141 44,343 54,141 44,343
------------------------------------------------------------------------
(1) 2003 figures restated as per note 3 to the consolidated financial
statements.

(2) Oil & natural gas sales and average prices are stated before
transportation costs.


The following discussion and analysis of the operating and financial
results of Shiningbank is for the three months and year ended December
31, 2004. This information is provided as of March 1, 2005. The fourth
quarter and year- end results have been compared with the corresponding
periods in 2003. Certain comparative figures have been restated to
reflect the accounting changes described in Note 3 to the consolidated
financial statements. Average prices have been restated to be prior to
transportation costs in order to be consistent with the 2004
presentation. This discussion and analysis should be read in conjunction
with the Fund's audited consolidated financial statements for the years
ended December 31, 2004 and 2003, together with the accompanying notes
included herein. Additional information about the Fund is available on
SEDAR at www.sedar.com.

Barrel of oil equivalent (boe) volumes are reported at 6:1 with 6 mcf =
1 bbl. All figures are in Canadian dollars unless otherwise noted.



Results of Operations

PRODUCTION VOLUMES

Daily Production Volumes
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Oil (bbl/d) 2,502 2,018 24 2,381 2,023 18
Natural gas
(mmcf/d) 90.4 76.6 18 86.6 74.9 16
Natural gas
liquids (bbl/d) 3,259 2,530 29 3,125 2,252 39
Oil equivalent
(boe/d) 20,833 17,311 20 19,933 16,759 19
------------------------------------------------------------------------
Natural gas %
of production 72% 74% (2) 72% 74% (2)
------------------------------------------------------------------------
------------------------------------------------------------------------


Fourth quarter daily average production grew 20% over fourth quarter
2003, and 19% year over year. Natural gas liquids ("NGL") accounted for
the majority of the volume increases as a result of the acquisition of
NGL-rich properties, notably Ferrier, during the year. The volume growth
in 2004 was primarily due to acquisitions, along with a successful
development drilling program.

The most significant acquisitions were the first quarter 2004 purchases
of Birchill Resources Limited ("Birchill") for $170.1 million and Good
Ridge Explorations Ltd. ("Good Ridge") for $7.0 million. Both
acquisitions closed in early March and, together, added approximately
19% to 2004 production. These acquisitions were partially offset by the
natural declines of producing properties, which are estimated to average
14% per year. Production in 2005 is expected to average between 19,500
and 20,000 boe/d.

The Fund's 2004 drilling program added approximately 2,000 boe/d to
year-end production rates. Due to wet weather in the spring and summer
of 2004 which restricted field access, the effect of the drilling
program was not fully realized until late in the year, and will carry
over to 2005. Production from these new wells will initially decline
faster than the Fund's average. The impact is expected to be a slight
increase in the average decline rate in 2005, as well as a marginal
reduction in the Fund's reserve life index until the wells have
stabilized at a level of long-term deliverability.



PRICING (INCLUDING HEDGING ACTIVITY)

Average Prices - After Hedging
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Average Prices
Oil ($/bbl) $ 42.61 $ 33.62 27 $ 43.14 $ 37.95 14
Natural gas
($/mcf) $ 7.20 $ 6.32 14 $ 7.06 $ 7.00 1
Natural gas
liquids ($/bbl) $ 43.70 $ 32.93 33 $ 40.24 $ 33.65 20
Oil equivalent
($/boe) $ 43.23 $ 36.71 18 $ 42.14 $ 40.42 4
------------------------------------------------------------------------
Benchmark Prices
WTI (US$/bbl) $ 48.28 $ 31.21 55 $ 41.40 $ 31.04 33
AECO natural gas
(Cdn$/mcf) $ 7.08 $ 5.59 27 $ 6.79 $ 6.70 1
------------------------------------------------------------------------
------------------------------------------------------------------------


Natural Gas

Shiningbank's realized natural gas prices averaged $7.20/mcf for the
fourth quarter, 14% higher than for the same period in 2003. For the
full year, the average price was 1% higher than 2003 at $7.06/mcf.
Natural gas pricing remained relatively flat throughout 2004 despite
significant increases in oil prices. Hedging decreased the realized gas
price by $0.11/mcf for the quarter and $0.07/mcf for the year, which
compares with a 2003 hedging gain of $0.35/mcf for the quarter and
$0.11/mcf for the year.

Gas pricing fundamentals remain strong. The Fund expects prices to
weaken late in first quarter 2005 with the end of winter, a normal
seasonal effect. The Fund also expects that there will be significant
market volatility in 2005 with benchmark prices averaging in the range
of Cdn$6.50 to $7.50/mcf. Shiningbank does not control the prices
received for its production, but it does mitigate market risk through
various methods including hedges and geographical diversity.

Oil and Natural Gas Liquids

Realized oil prices for the quarter were $42.61/bbl, up 27% from fourth
quarter 2003. Hedging reduced the realized price by $8.36/bbl for the
quarter compared with a hedging loss of $1.50/bbl in fourth quarter 2003.

For full-year 2004, Shiningbank's average oil price rose 14% to
$43.14/bbl. Hedging reduced this realized price by $5.46/bbl as compared
to a $1.33/bbl decline in 2003. The benchmark West Texas Intermediate
("WTI") price averaged 33% higher than in 2003, however strength in the
Canadian dollar partially offset this increase. Oil prices are expected
to remain high in US dollar terms, with many analysts calling for a
US$40.00/bbl average price for 2005. Futures prices at the time of
writing were over US$50.00/bbl.

NGL prices were also strong, reflecting high oil prices. The average NGL
price in the fourth quarter 2004 was 33% higher than in fourth quarter
2003 at $43.70/bbl, and 20% higher for the full year at an average
$40.24/bbl.

Hedging

Shiningbank maintains an active hedging program designed to reduce the
variability of cash flow and stabilize distributions. Under the Fund's
hedging policy, not more than one-half of production volumes of any
commodity can be hedged at any one time. Gains and losses from hedging
activities are typically recorded when they are realized and are
included in oil and natural gas sales unless a particular hedge is
considered ineffective. During 2004, the Fund hedged an average of 26%
of total gas production (25% - 2003) and 39% of total oil production
(37% - 2003). Currently, Shiningbank has the following hedging contracts
in place:



----------------------------------------------------------------------
Period Commodity Volume Price
----------------------------------------------------------------------

April 1, 2004 -
March 31, 2005 Gas 5,000 GJ/d $5.91 /GJ
November 1, 2004 -
March 31, 2005 Gas 5,000 GJ/d $7.50 /GJ floor
$11.00/GJ ceiling
April 1, 2005 -
December 31, 2005 Gas 5,000 GJ/d $5.00 /GJ floor
$6.39/GJ ceiling
January 1, 2005 -
June 30, 2005 Oil 500 bbl/d US$37.00/bbl floor
US$50.50/bbl ceiling
February 1, 2005 -
December 31, 2005 Oil 500 bbl/d US$40.00/bbl floor
US$55.40/bbl ceiling
April 1, 2005 -
October 31, 2005 Gas 5,000 GJ/d $6.70/GJ
----------------------------------------------------------------------
----------------------------------------------------------------------


REVENUES
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------
% of % of % of % of
(000s) 2004 Revenue 2003 Revenue 2004 Revenue 2003 Revenue
------------------------------------------------------------------------
Oil $11,731 14 $ 6,520 11 $ 42,352 14 $29,000 12
Natural
gas 60,850 74 42,116 72 226,040 74 188,454 76
Natural
gas
liquids 13,102 15 7,664 13 46,019 15 27,667 11
Other
income
(loss) (398) - 49 - 91 - 84 -
Gas
hedging (909) (1) 2,402 4 (2,229) (1) 2,980 1
Oil
hedging (1,923) (2) (277) - (4,759) (2) (978) -
------------------------------------------------------------------------
$82,453 100 $58,474 100 $307,514 100 $247,207 100
------------------------------------------------------------------------
------------------------------------------------------------------------

The accompanying table demonstrates the net effect of price and volume
variances on revenues.

SALES VARIANCE ANALYSIS (INCLUDING HEDGING ACTIVITY)

Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------
(000s) 2004/2003 2004/2003
------------------------------------------------------------------------
Oil and natural gas liquids
Volume increase $ 3,705 $ 15,880
Price increase 5,298 12,043
------------------------------------------------------------------------
Net increase $ 9,003 $ 27,923
------------------------------------------------------------------------
Natural gas
Volume increase $ 8,057 $ 30,388
Price increase 7,366 1,989
------------------------------------------------------------------------
Net increase $ 15,423 $ 32,377
------------------------------------------------------------------------
------------------------------------------------------------------------


ROYALTIES
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Total royalties,
net (000s) $ 19,159 $ 12,794 50 $ 63,930 $ 53,628 19
As a % of revenue 23.2% 21.9% 6 20.8% 21.7% (4)
Per boe $ 10.00 $ 8.03 25 $ 8.76 $ 8.77 -
------------------------------------------------------------------------


Royalty expense consists of royalties paid to provincial governments,
freehold landowners and overriding royalty owners. The royalty rate was
marginally lower in 2004 due to a one-time credit received in the third
quarter of 2004 related to 2003 Crown royalties, offset in part by the
high commodity price environment. The fourth quarter royalty rate was 6%
higher due to the hedging loss experienced in 2004 as compared to a
hedging gain in 2003. Hedging gains and losses affect revenue without a
corresponding effect on royalties. The 2004 fourth quarter pre-hedging
royalty rate was 22.4% which is comparable to the 2003 rate of 22.7% for
the same period. The Fund expects that commodity prices in 2005 will be
similar to those realized in 2004, resulting in little change to the
2005 royalty rate. The Alberta government provides a credit under the
Alberta Royalty Credit program, which the Fund is eligible to access on
a small portion of its properties. The Fund recorded the maximum credit
of $500,000 in both 2004 and 2003.



TRANSPORTATION COSTS
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Transportation
costs (000s) $ 1,186 $ 1,293 (8) $ 5,550 $ 5,050 10
Per boe $ 0.62 $ 0.81 (23) $ 0.76 $ 0.83 (8)
------------------------------------------------------------------------


Transportation costs decreased 23% on a boe basis from fourth quarter
2003. The decrease was the result of prior quarter adjustments flowing
through the fourth quarter. The 8% year over year decrease was the
result of lower pricing and termination of certain transportation
service commitments. In 2005, transportation costs are expected to be
flat on a boe basis with 2004.



OPERATING COSTS
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Operating
costs (000s) $ 11,465 $ 11,058 4 $ 48,692 $ 40,536 20
Per boe $ 5.98 $ 6.94 (14) $ 6.67 $ 6.63 1
------------------------------------------------------------------------
------------------------------------------------------------------------


Operating costs on a boe basis decreased 14% from fourth quarter 2003
and increased 1% year over year. Higher field and plant maintenance
costs in most areas were offset by volume increases in some areas with
lower operating costs. The Fund expects 2005 costs to average $7.00/boe.
While the Fund has gained efficiencies of scale in its operations on a
per boe basis, operating costs will remain under pressure due to rising
field costs, aging of the property portfolio and the likelihood of
higher energy costs in 2005.




OPERATING NETBACKS

Natural Gas Wells
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

($/boe) 2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Oil and natural
gas sales $ 44.47 $ 35.36 26 $ 42.90 $ 40.12 7
Hedging gain
(loss) (1.22) 1.50 (181) (0.78) 0.42 (286)
Royalties 10.09 8.07 25 8.83 8.91 (1)
Transportation
costs 0.65 0.87 (25) 0.80 0.89 (10)
Operating costs 5.59 6.50 (14) 6.29 6.25 1
------------------------------------------------------------------------
Operating netback $ 26.92 $ 21.42 26 $ 26.20 $ 24.49 7
------------------------------------------------------------------------

Oil Wells
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

($/boe) 2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Oil and natural
gas sales $ 49.70 $ 35.27 41 $ 46.94 $ 39.49 19
Hedging gain
(loss) (7.54) (0.97) 677 (4.45) (1.00) 345
Royalties 8.07 7.06 14 7.55 6.64 14
Operating costs 14.29 13.50 6 14.15 11.96 18
------------------------------------------------------------------------
Operating netback $ 19.80 $ 3.74 44 $ 20.79 $ 19.89 5
------------------------------------------------------------------------

All Wells
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

($/boe) 2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Oil and natural
gas sales $ 44.71 $ 35.35 26 $ 43.10 $ 40.09 8
Hedging gain
(loss) (1.48) 1.33 (211) (0.96) 0.33 (391)
Other income
(loss) (0.21) 0.03 (800) 0.01 - -
Royalties 10.00 8.03 25 8.76 8.77 -
Transportation
costs 0.62 0.81 (23) 0.76 0.83 (8)
Operating costs 5.98 6.94 (14) 6.67 6.63 1
------------------------------------------------------------------------
Operating netback $ 26.42 $ 20.93 26 $ 25.96 $ 24.19 7
------------------------------------------------------------------------
------------------------------------------------------------------------


Total operating netback increased 26% quarter over quarter due mainly to
higher commodity prices and lower transportation and operating costs.
The year over year operating netback increased 7% due to higher
commodity prices and lower transportation costs.



GENERAL AND ADMINISTRATIVE COSTS
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
General and
administrative
costs (000s) $ 1,686 $ 1,432 18 $ 6,681 $ 4,649 44
Per boe $ 0.88 $ 0.90 (2) $ 0.92 $ 0.76 21
Per average
Trust Unit $ 0.03 $ 0.03 - $ 0.13 $ 0.11 18
------------------------------------------------------------------------
------------------------------------------------------------------------


General and administrative costs per boe decreased 2% from fourth
quarter 2003, and increased 21% year over year. The increases, including
higher per average Trust Unit metrics, were due to higher activity
levels resulting from acquisitions and increasing costs for corporate
governance due to additional regulation. At year end, Shiningbank had 43
full-time employees and 24 full-time and part-time consultants at its
head office. Field and production staff consisted of two production
superintendents, 18 full-time employees and 38 contract operators. Costs
of field and production staff are included in operating costs. General
and administrative costs for 2005 are expected to trend upward to
approximately $1.25/boe as a result of further corporate governance and
related administrative costs.



INTEREST ON LONG TERM DEBT
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Interest on long
term debt (000s) $ 1,759 $ 1,093 61 $ 6,159 $ 6,103 1
Per boe $ 0.92 $ 0.69 33 $ 0.84 $ 1.00 (16)
Per average
Trust Unit $ 0.03 $ 0.02 50 $ 0.12 $ 0.15 (20)
------------------------------------------------------------------------
------------------------------------------------------------------------


Interest expense, which includes bank charges, increased 61% from fourth
quarter 2003 due to higher debt levels resulting from the funding of
capital expenditures. Year over year interest expense was relatively
flat due to higher debt levels being offset by lower interest rates.
Shiningbank is currently in compliance with all external debt covenants.
Interest expense in 2005 is expected to be approximately $1.25/boe due
to higher projected debt levels and interest rates.



DEPLETION, DEPRECIATION AND ACCRETION
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Depletion,
depreciation
and accretion
(000s) $ 32,035 $ 22,865 40 $ 118,547 $ 78,853 50
Per boe $ 16.71 $ 14.36 16 $ 16.25 $ 12.89 26
------------------------------------------------------------------------
------------------------------------------------------------------------


Depletion, depreciation and accretion rose 16% per boe for the fourth
quarter and 26% year over year. These increases were primarily due to
expansion of the asset base from acquisitions made during the first
quarter and associated future development costs. The fourth quarter
depletion calculation was based on December 31, 2004 reserve estimates.

The 2003 comparative figure has been restated and increased by $3.8
million as a result of the adoption of the new asset retirement
obligation standard. The accretion of discount on the asset retirement
liability and additional depletion due to asset retirement costs are now
included as part of this expense.



TRUST UNIT INCENTIVE COMPENSATION
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Trust unit incentive
compensation (000s)$ 333 $ 147 127 $ 1,263 $ 572 121
Per boe $ 0.17 $ 0.09 89 $ 0.17 $ 0.09 89
------------------------------------------------------------------------
------------------------------------------------------------------------


During fourth quarter 2003, the Fund elected to prospectively adopt
amendments to the Canadian Institute of Chartered Accountants (CICA)
Handbook Section 3870, "Stock-based Compensation and Other Stock-based
Payments" for all rights issued on or after January 1, 2003. At that
time, a total of $572,000 was expensed for 2003, representing the fair
value of rights issued and which vested in 2003.

During fourth quarter 2004, one new issue of rights was granted. Six new
issues of rights, aggregating 580,000 in total (2003 - 525,000) were
granted during the year. The fair value of rights issued was determined
using a Black-Scholes model, and will be brought into income over the
vesting period of the rights. Expenses in 2004 of $1.3 million
represented the fair value of rights issued during 2003 and 2004 and
which vested in 2004. All of these costs are "non-cash" costs and are
not deducted in calculating distributions to unitholders.



INTERNALIZATION OF MANAGEMENT CONTRACT
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Internalization
of management
contract (000s) $ 1,307 $ 1,561 (16) $ 3,511 $ 5,989 (41)
Per boe $ 0.68 $ 0.98 (31) $ 0.48 $ 0.98 (51)
------------------------------------------------------------------------
------------------------------------------------------------------------


Effective October 9, 2002, the Fund internalized its management by
acquiring all of the shares of Shiningbank Energy Management Inc., the
former Manager of the Fund. Prior to the acquisition, the Fund paid fees
of 3.25% of net operating income, a fee of 1.5% on the purchase price of
acquisitions and a quarterly scheduled dividend in accordance with the
terms of a management agreement. The acquisition eliminated all future
fees and dividends.

Of the total purchase price of $20.6 million, $11.0 million was
deferred, representing Exchangeable Shares subject to escrow provisions
which are being amortized into income over specific vesting periods
through 2007. During 2004, $2.7 million (2003 - $5.4 million) was
expensed, representing the amortization of these escrowed Exchangeable
Shares. At December 31, 2004, $1.9 million was left to be amortized
($1.3 million in 2005, $0.4 million in 2006 and $0.2 million in 2007).

Total consideration for the internalization was reduced by $1.8 million
at the time of the transaction to provide for performance and retention
bonuses to be paid to employees. During 2004, the remaining balance of
this bonus pool, or $817,250, was paid out in cash and included in
internalization expenses. This compares with $582,000 paid in 2003.



TAXES
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------

2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Capital and large
corporation
taxes (000s) $ (451) $ 139 (424) $ 574 $ 595 (4)
Future income
tax (recovery)
(000s) $ (74,064) $ 738 (10,136) $(86,199) $(12,722) 578
Per boe $ (38.88) $ 0.55 (7,169) $ (11.74) $ (1.98) 493
------------------------------------------------------------------------
------------------------------------------------------------------------


The Fund is obligated to pay provincial capital taxes and federal large
corporations tax in its operating entities. Under the Fund's structure,
payments are made between Shiningbank Energy Ltd. and the Fund. These
payments provide the mechanism for transferring income to unitholders
along with tax benefits and future tax liabilities. Current income taxes
are not presently payable by the Fund or Shiningbank Energy Ltd.

In first quarter 2004, the Alberta government passed legislation to
reduce the provincial corporate income tax rate to 11.5% from 12.5%
effective April 1, 2004. Shiningbank's expected future income tax rate
incorporating this rate reduction is approximately 38.49% compared with
the current rate of approximately 38.62% applicable to the 2004 tax year.

During the fourth quarter, the Fund changed its organizational structure
to take advantage of certain tax attributes of a partnership acquired in
the Birchill acquisition. These changes eliminated future income taxes
payable within the Fund on income earned from the Birchill assets by
taking advantage of the tax flow-through structure of that partnership.
As a result of the Fund's restructuring, a reduction in future income
taxes was credited to income in the fourth quarter in accordance with
Canadian generally accepted accounting principles ("GAAP"). The effect
on earnings for the year was an additional $78.4 million, or $1.50 per
Trust Unit ($1.47 diluted). Net earnings were also affected through
increased depletion charges arising from future income taxes being
recorded in the cost of the assets at the time of the Birchill
acquisition. This additional depletion reduced earnings by $8.1 million,
or $0.15 per Trust Unit, basic and diluted. The costs of the
restructuring were included in general and administrative costs in the
fourth quarter.

NET EARNINGS

Shiningbank's fourth quarter earnings were $88.0 million or $1.62 per
Trust Unit ($1.60 diluted). Earnings in fourth quarter 2003, after
restatement for the retroactive application of new accounting policies,
were $5.4 million or $0.12 per Trust Unit, basic and diluted. For the
year ended December 31, 2004 net earnings were $138.8 million or $2.66
per Trust Unit ($2.61 diluted), compared with restated 2003 figures of
$64.0 million or $1.54 per Trust Unit ($1.51 diluted). Net earnings for
the fourth quarter were increased by $78.4 million or $1.44 per Trust
Unit ($1.43 diluted) as a result of an internal restructuring which
reduced future income taxes. See "Taxes".



DISTRIBUTIONS TO UNITHOLDERS

Distributions to unitholders
------------------------------------------------------------------------
Three months ended December 31, Year ended December 31,
------------------------------------------------------------------------
(000s except
per Trust
Unit amounts) 2004 2003 % 2004 2003 %
------------------------------------------------------------------------
Cash flow before
change in
non-cash
working capital $ 47,220 $ 30,082 57 $ 174,878 $ 136,038 29
Capital
expenditures (13,323) (6,865) 94 (56,339) (22,931) 146
Asset retirement
expenditures (208) (57) 265 (684) (218) 214
Working capital
adjustments 3,701 7,469 (50) 28,505 9,398 203
------------------------------------------------------------------------
Distributions
to unitholders $ 37,390 $ 30,629 22 $ 146,360 $ 122,287 20
------------------------------------------------------------------------
Distributions
per Trust Unit $ 0.69 $ 0.69 - $ 2.76 $ 2.85 (3)
------------------------------------------------------------------------
Trust Units
outstanding 54,141 44,343 22 54,141 44,343 22
------------------------------------------------------------------------
------------------------------------------------------------------------


Distributions to unitholders for the quarter increased 22% over the same
period in 2003 to $37.4 million, while distributions per Trust Unit were
consistent in both periods at $0.69. For full-year 2004, distributions
to unitholders increased 20% to $146.4 million from $122.3 million in
2003. The increases in distributions to unitholders for both periods in
2004 were due to higher production volumes, large gains in pricing for
oil and NGL and strong gas prices. On a per Trust Unit basis, the effect
of an increased number of Trust Units outstanding offset the increase in
distributions to unitholders. Full-year distributions decreased 3% to
$2.76 in 2004 from $2.85 in 2003 as a result of greater holdbacks to
fund capital expenditures. The Fund paid out 84% of its cash flow in
2004 compared with 90% in 2003. Management expects that the current
distribution level will continue through 2005 provided that commodity
prices remain at or near 2004 levels.

2005 Cash Flow Sensitivities

The estimated sensitivity of cash flow to commodity price variables is
shown in the table below.



Per Trust
(000s) Unit
------------------------------------------------------------------------
US $1 per bbl $ 1,700 $ 0.03
Cdn $0.25 per mcf $ 5,900 $ 0.11
US $0.01 exchange $ 800 $ 0.01
100 bbl/d $ 1,100 $ 0.02
1 mmcf/d $ 1,700 $ 0.03
1% prime rate $ 1,900 $ 0.03
------------------------------------------------------------------------


INCOME TAX INFORMATION

In 2004, 73.57% of cash distributions paid by the Fund were required to
be included in the income of unitholders. The remaining 26.43% reduced
each unitholder's adjusted cost base ("ACB") for income tax purposes. A
summary of cash distributions paid in 2004 and the implications for
Canadian taxpayers is shown below.



Taxable ACB
Distribution(1) Income Reduction
($ per ($ per ($ per
Record Date Payment Date Trust Unit) Trust Unit) Trust Unit)
------------------------------------------------------------------------
December 31, 2003 January 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
January 31, 2004 February 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
February 29, 2004 March 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
March 31, 2004 April 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
April 30, 2004 May 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
May 31, 2004 June 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
June 30, 2004 July 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
July 31, 2004 August 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
August 31, 2004 September 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
September 30, 2004 October 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
October 31, 2004 November 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
November 30, 2004 December 15, 2004 $ 0.23 $ 0.1692 $ 0.0608
------------------------------------------------------------------------
Total $ 2.76 $ 2.0304 $ 0.7296
------------------------------------------------------------------------

(1) Distributions for income tax purposes are based on cash received
during 2004 rather than accrual-based income reported elsewhere in
this report.


For US unitholders, 82.39% of distributions were taxable in 2004.
Unitholders in both Canada and the US should consult tax advisors as to
the proper treatment of Shiningbank distributions for income tax
purposes.



ANNUAL FINANCIAL INFORMATION

(000s except per Trust Unit amounts) 2004 2003 2002
------------------------------------------------------------------------
Restated Restated
(note 3) (note 3)
Oil and natural gas sales $ 307,514 $ 247,207 $ 142,661
Net earnings (loss) before
income tax 52,607 51,232 (1,859)
Per Trust Unit - basic 1.01 1.23 (0.06)
Per Trust Unit - diluted 0.99 1.21 (0.06)
Net earnings after income tax 138,806 63,954 12,598
Per Trust Unit - basic 2.66 1.54 0.40
Per Trust Unit - diluted 2.61 1.51 0.40
Total assets 826,797 614,149 507,824
Total long term debt 182,147 121,691 115,283
Property acquisitions 2,615 156,829 49,595
Corporate acquisitions 177,067 - -
Capital expenditures 56,339 22,931 11,867
Cash flow before change in
non-cash working capital 174,878 136,038 68,243
Per weighted average Trust Unit 3.35 3.27 2.15
Distributions to unitholders 146,360 122,287 69,607
Per Trust Unit 2.76 2.85 2.16
Payout ratio 84% 90% 102%
Trust Units outstanding 54,141 44,343 33,194
Weighted average 52,209 41,595 31,677
Dividends to former Manager - - 517
------------------------------------------------------------------------
------------------------------------------------------------------------


Acquisitions are a key driver of Shiningbank's growth. In 2003, the Fund
completed a major acquisition of properties at Ferrier/O'Chiese. In
2004, the Fund completed a major corporate acquisition of Birchill and a
much smaller corporate acquisition of Good Ridge. Such acquisitions add
to production volumes, revenues, earnings and assets. Revenues and
earnings are also greatly affected by commodity prices, particularly
natural gas prices as 72% of the Fund's 2004 production was natural gas.
With its high weighting to natural gas, the Fund's revenue and earnings
results closely track changes in natural gas pricing.

In 2003, substantial production growth through acquisitions and a
rebound in oil and gas prices boosted revenues and earnings compared
with relatively weak natural gas prices in 2002 which resulted in lower
revenues and earnings. In 2004, the same combination of
acquisition-driven production growth and high commodity prices resulted
in higher revenues and cash flow. Earnings increased as a percentage of
revenue in 2004 as a result of the recovery of future income taxes
related to the Fund's internal restructuring.



QUARTERLY FINANCIAL INFORMATION
------------------------------------------------------------------------
(000s except per March June September December
Trust Unit amounts) 31 30 30 31
------------------------------------------------------------------------

2004
Oil and natural gas sales $ 69,625 $ 80,723 $ 74,713 $ 82,453
Net earnings before
income tax 13,485 12,851 12,297 13,974
Per Trust Unit - basic 0.29 0.24 0.24 0.26
- diluted 0.28 0.24 0.23 0.25
Net earnings after income tax 18,796 16,072 15,900 88,038
Per Trust Unit - basic 0.40 0.30 0.30 1.62
- diluted 0.39 0.29 0.29 1.60
Cash flow before change
in non-cash working capital 39,544 45,190 42,924 47,220
Per weighted average Trust Unit 0.84 0.84 0.80 0.87
Distributions to unitholders 34,767 36,977 37,226 37,390
Per Trust Unit 0.69 0.69 0.69 0.69
Payout ratio 88% 82% 87% 79%
------------------------------------------------------------------------

2003
Oil and natural gas sales $ 60,180 $ 65,507 $ 63,046 $ 58,474
Net earnings before income tax 16,885 15,027 13,227 6,092
Per Trust Unit - basic 0.47 0.36 0.30 0.14
- diluted 0.47 0.35 0.29 0.14
Net earnings after income tax 19,499 23,583 15,517 5,354
Per Trust Unit - basic 0.55 0.56 0.35 0.12
- diluted 0.54 0.55 0.35 0.12
Cash flow before change
in non-cash working capital 34,176 36,723 35,057 30,082
Per weighted average Trust Unit 0.96 0.87 0.79 0.68
Distributions to unitholders 30,886 30,330 30,442 30,629
Per Trust Unit 0.78 0.69 0.69 0.69
Payout ratio 90% 83% 87% 102%
------------------------------------------------------------------------
------------------------------------------------------------------------


As with Shiningbank's annual results, quarterly fluctuations are
primarily the result of production increases due to acquisitions, the
Fund's development drilling program and realized gas prices which can be
extremely volatile. Volume increases from acquisitions occurred in
second quarter 2003 through the acquisition of assets at
Ferrier/O'Chiese and again, in second quarter 2004 with the acquisitions
of Birchill and Good Ridge.

Natural gas prices remained strong and relatively consistent through the
two years, apart from exceptionally strong prices in first quarter 2003
which led to higher distributions for that period. Oil prices increased
substantially in late 2004, however, with oil playing a small role in
Shiningbank's overall revenues, and with increased capital programs
absorbing the extra cash flow, there was no change in distributions.

COSTS OF ACQUISITIONS AND DEVELOPMENT

During the first quarter, Shiningbank spent $177.1 million on the
acquisitions of Birchill and Good Ridge. These acquisitions added
approximately 19% to Shiningbank's production volumes for 2004 with the
majority of additions coming in the Ferrier area, adjacent to
Shiningbank's existing property and using much of the same
infrastructure.

A total of $56.3 million was spent on drilling and new facilities during
2004, compared with $22.9 million in 2003. Cash flow was used to fund
$27.8 million of these expenditures, with the balance being funded by
debt. The increased expenditures funded a successful development
drilling program concentrated in the Ferrier/O'Chiese area. Of the
year's total, $13.3 million was spent in the fourth quarter compared
with $6.9 million in fourth quarter 2003. A total of 96 wells (20.3 net)
were drilled in 2004, 88 (18.5 net) of which were successful gas wells,
four (0.9 net) were successful oil wells and four (0.9 net) were dry and
abandoned. In addition, Shiningbank farmed-out an additional 30 wells
for which no costs were incurred.

In 2005, the Fund plans to spend approximately $50 million on drilling,
new facilities and maintenance capital. This will be funded through a
combination of cash flow and debt financing.



NET ASSET VALUE

Discount Factor
(000s except per Trust Unit amounts) 10% 12%
------------------------------------------------------------------------
Present value of reserves(1)
Proved $ 672,753 $ 634,333
Probable 188,585 166,835
Undeveloped lands 27,800 27,800
Working capital deficiency (10,015) (10,015)
------------------------------------------------------------------------
Total assets 879,123 818,953
Long term debt (182,147) (182,147)
------------------------------------------------------------------------
Net asset value $ 696,976 $ 636,806
------------------------------------------------------------------------
Trust Units outstanding 54,141 54,141
Net asset value per Trust Unit at
December 31, 2004 $ 12.87 $ 11.76
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) The present value of reserves is calculated based on price forecasts
and reserve estimates prepared by Sproule Associates Limited in
their December 31, 2004 evaluations.


LIQUIDITY AND CAPITAL RESOURCES

Shiningbank's ability to grow depends on access to bank lines of credit
supplemented by periodic equity infusions. Smaller acquisitions through
the course of the year are funded by bank debt. Equity is issued to fund
single large acquisitions, or to pay down debt acquired following a
number of smaller acquisitions. When the proceeds of an equity issue are
greater than acquisition costs, the excess is used to reduce bank debt.

Since the Fund's initial public offering in 1996, 11 public equity
issues have been completed. Acquisitions have led to steady accretion in
value to unitholders. This accretion is offset when equity is issued as
existing unitholders are diluted by the issue of new units. However, as
all new equity issues have been done in conjunction with an acquisition,
over time, unitholders have not been diluted. This is apparent in the
stability of the Net Asset Value (NAV) per unit of the Fund over time.
At the inception of the Fund, the NAV was $9.43 per unit, discounted at
10%. At the end of 2004, despite payment of over $19 per unit in
distributions over eight years, the NAV per unit is at a level of
$12.87, discounted at 10%, indicating that unitholders have not been
diluted.

Long Term Debt

The Fund has a $225 million revolving credit facility with a syndicate
of four Canadian chartered banks of which $182.1 million was drawn at
December 31, 2004. The revolving period extends to April 27, 2005, at
which time the facility reverts to a two-year term with principal
payments, if necessary, commencing on July 28, 2005. The facility is
secured by a $300 million floating charge debenture on all assets of
Shiningbank together with supporting debentures and guarantees from the
Fund's operating subsidiaries and affiliates. Borrowings under the
facility bear interest at an annual rate ranging from the banks' prime
rate to the banks' prime rate plus 0.95%, depending on the total debt to
cash flow ratio or, at Shiningbank's option, the bankers' acceptance
rate plus a stamping fee.

Unitholders' Equity

On March 8, 2004, the Fund issued 8,800,000 new Trust Units at $17.00
each for gross proceeds of $149.6 million. In addition, a total of
997,204 Trust Units were issued during the year under the Trust Unit
Rights Incentive Plan, under the Fund's Distribution Reinvestment Plan,
and through the exercise of Exchangeable Shares.

When equity is raised, the intended use of proceeds is specified in the
related prospectus. Each major equity issue has been undertaken to
acquire properties or to reduce debt incurred from prior acquisitions.
In all cases, the proceeds were used according to the purpose specified.

As of March 1, 2005, the Fund had 54,280,516 Trust Units, 263,482
non-escrowed Exchangeable Shares and 353,614 escrowed Exchangeable
Shares outstanding. Exchangeable Shares held in escrow will be released
over the next three years under the terms of two escrow agreements.
Exchangeable Shares are not eligible for distributions until they are
exchanged for Trust Units at the discretion of the holder. The exchange
rate was initially one Trust Unit for each Exchangeable Share. The
exchange rate increases with each distribution by an amount equal to the
per unit distribution divided by the 10-day weighted average trading
price of the Trust Units preceding the record date for that
distribution. As of December 31, 2004, the exchange rate was 1 to
1.32647.

Future Growth

Shiningbank's growth is based on its ability to raise debt and equity
capital in Canadian financial markets. The Fund examines acquisition
opportunities and selects those it believes to be accretive for such
parameters as cash flows, distributions, net asset value, production and
reserves.

Acquisitions are typically made using the Fund's credit facilities.
Periodically, new Trust Units are issued, and the proceeds are used to
pay down debt accumulated from previous acquisitions.

If the Canadian equity or debt markets were unable to satisfy
Shiningbank's funding needs, it would impair the Fund's ability to
continue to replace production and maintain distributions. The Fund has
lines of credit held by four Canadian chartered banks, which provide
sufficient debt capital to satisfy the Fund's ability to complete all
but the largest acquisitions. However, the Fund's governing documents
restrict debt levels to 40% of the value of its properties, and debt
service costs are not to exceed 30% of the projected annual cash flow.



Contractual Obligations
------------------------------------------------------------------------
Payments Due by Period
------------------------------------------------------------------------
Less than 1 - 3 4 - 5 After
(000s) Total 1 Year Years Years 5 Years
------------------------------------------------------------------------
Long term debt
principal(1) $ 182,147 $ - $ 182,147 $ - $ -
Operating leases 8,071 826 3,003 3,173 1,069
Pipeline
transportation 5,234 1,306 2,612 1,316 -
------------------------------------------------------------------------
Total obligations $ 195,452 $ 2,132 $ 187,762 $ 4,489 $ 1,069
------------------------------------------------------------------------

(1) The long term debt obligation assumes that the revolving credit line
is not renewed in April 2005.


Shiningbank has on-going capital commitments in the ordinary course of
business for development drilling, equipment and facilities. These are
funded through a combination of cash flow, debt financing and periodic
equity financing.

CRITICAL ACCOUNTING ESTIMATES

The Fund makes numerous accounting estimates in its financial statements
in order to provide timely information to users. A critical accounting
estimate is one that requires management to make assumptions about
matters that are highly uncertain at the time the estimate is made and,
if a different estimate was used, financial results would be materially
different. The following estimates are considered critical:

Reserves

The Fund must estimate its reserves. Reserves are evaluated and reported
on annually by independent petroleum reserve evaluators who use various
subjective factors and assumptions, including forecasts of costs based
on geological and engineering data, projected future rates of
production, and timing and amounts of future development costs. Although
reserves are estimated, management believes the estimates are reasonable
based on information available at the time the estimates were prepared.
Management, the Fund's internal engineers, and the Board's
Environmental, Corporate Governance and Reserve Review Committee all
review and approve the estimates reported by the independent reserve
evaluators.

As new information becomes available, changes are made to the reserve
estimates and future development cost estimates. Historically, the Fund
has had no significant changes to these estimates, with the exception of
adjusting reserves for acquisitions and divestitures and the results of
new drilling. Future actual results could vary greatly from the
estimates made, resulting in material changes to the depletion
calculation and asset impairment test.

Asset Retirement Obligation

The Fund's estimated asset retirement obligation is based on estimated
timing and costs to abandon and restore properties.

FINANCIAL REPORTING

During 2003 and 2004, there were numerous changes to financial reporting
and regulatory requirements. The most important changes for Shiningbank
are described below.

Asset Retirement Obligations

Effective January 1, 2004, Shiningbank adopted CICA handbook section
3110, "Asset Retirement Obligations." The standard requires the
recognition and measurement of liabilities related to legal obligations
to retire property, plant and equipment upon acquisition of the
liability. The initial liability must be measured at fair value and
subsequently adjusted for the accretion of discount and changes in the
fair value. The asset retirement cost is capitalized and depleted into
earnings over time.

Hedging Relationships

Effective January 1, 2004, the Fund adopted Accounting Guideline 13,
"Hedging Relationships" which establishes standards for the
documentation and effectiveness of hedging relationships for the
purposes of applying hedge accounting. The adoption of this standard had
no effect on the Fund's financial results.

Trust Unit Incentive Compensation

In September 2003, the CICA amended section 3870 of its handbook -
"Stock-based Compensation and Other Stock-based Payments." Effective
January 1, 2004, companies are required to use the fair value method to
measure all stock-based payments and recognize compensation expense in
their financial statements. The Fund elected to adopt these amendments
in fourth quarter 2003 for all rights issued on or after January 1,
2003.

Previously the Fund followed common practice in the sector and used the
excess of the unit price over the exercise price at the date of the
financial statement as a surrogate for fair value. If the Fund were to
continue to use this method under the amended standard, the Fund could
experience large fluctuations, even recoveries, in compensation expense
over the next 10 years. Because of the highly volatile nature of
distributions and unit trading prices, management believes amounts
expensed and/or recovered under this calculation do not properly
represent the benefit conveyed to rights holders during the vesting
period, and could be confusing when reading the financial statements.

Management considered numerous methods of determining the fair value of
rights granted and has chosen to use a Black-Scholes option-pricing
model to determine fair value. The calculation of fair value requires
management to make numerous assumptions, as outlined in note 7 to the
financial statements. Readers are cautioned that the assumptions made
are estimates of future events and actual results could differ
materially from those estimated.

Supplemental Disclosure

Management believes that distributions to unitholders, cash flow and
netbacks are useful supplemental measures. Distributions to unitholders
should not be construed as an alternate to net income as determined by
Canadian GAAP. All references to cash flow throughout this MD&A are
based on cash flow before changes in non-cash working capital, which
management uses to analyze operating performance and leverage. Cash flow
as presented is not intended to represent operating cash flow or
operating profits, nor should it be viewed as an alternative to cash
flow from operating activities, net earnings or other measures of
financial performance calculated in accordance with Canadian GAAP.
Operating netbacks, which are calculated as average unit sales price
less royalties, transportation costs and operating costs, represent the
cash margin for product sold, calculated on a boe basis. Distributions
to unitholders, cash flow and netbacks as presented do not have any
standardized meanings prescribed by Canadian GAAP and therefore may not
be comparable with the calculations of similar measure for other
entities.

Forward-looking statements

This MD&A contains forward-looking statements relating to future events.
In some cases, forward-looking statements can be identified by such
words as "may," "expects" or similar expressions. These statements
represent management's best projections, but undue reliance should not
be placed upon them as they are derived from numerous assumptions. These
assumptions are subject to known and unknown risks and uncertainties,
including the business risks discussed in this MD&A and in the AIF,
which may cause actual performance and financial results 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.

Barrel of oil equivalent

Barrel of oil equivalent (boe) volumes are reported at 6:1 with 6 mcf =
1 bbl. The 6:1 boe conversion ratio is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. While it is useful for
comparative measures, it may not accurately reflect individual product
values and may be misleading if used in isolation.



Consolidated Balance Sheets

December 31 ($ thousands)
----------------------------------------------------------------------
2004 2003
----------------------------------------------------------------------
Restated
(note 3)
ASSETS
Current assets
Accounts receivable $ 50,712 $ 31,587
Prepaid expenses 4,471 2,630
----------------------------------------------------------------------
55,183 34,217
Fixed assets (note 4)
Petroleum and natural gas
properties and equipment 1,133,426 826,352
Accumulated depletion
and depreciation (364,814) (248,670)
----------------------------------------------------------------------
768,612 577,682

Other assets 3,002 2,250
----------------------------------------------------------------------
$ 826,797 $ 614,149
----------------------------------------------------------------------
----------------------------------------------------------------------


LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities $ 40,268 $ 30,727
Trust Unit distributions payable 24,930 20,428
----------------------------------------------------------------------
65,198 51,155

Long term debt (note 5) 182,147 121,691
Future income taxes (note 6) 33,266 50,564
Asset retirement obligation (note 3) 30,242 26,524

Unitholders' equity
Trust Units (note 7) 706,954 550,267
Exchangeable Shares (note 7) 7,019 5,267
Contributed surplus (note 7) 1,416 572
Accumulated earnings 308,517 169,711
Accumulated Trust Unit distributions (507,962) (361,602)
----------------------------------------------------------------------
515,944 364,215
----------------------------------------------------------------------
$ 826,797 $ 614,149
----------------------------------------------------------------------
----------------------------------------------------------------------

See accompanying notes to the consolidated financial statements


Consolidated Statements of Earnings and Unitholders' Equity

Year ended December 31 ($ thousands, except per Trust Unit amounts)
----------------------------------------------------------------------
2004 2003
----------------------------------------------------------------------
Restated
(note 3)
Revenues
Oil and natural gas sales $ 307,514 $ 247,207
Royalties 63,930 53,628
----------------------------------------------------------------------
243,584 193,579

Expenses
Transportation 5,550 5,050
Operating 48,692 40,536
General and administrative 6,681 4,649
Interest on long term debt 6,159 6,103
Depletion, depreciation and accretion 118,547 78,853
Trust Unit incentive compensation (note 7) 1,263 572
Internalization of management
contract (note 10) 3,511 5,989
----------------------------------------------------------------------
190,403 141,752
----------------------------------------------------------------------
Earnings before taxes 53,181 51,827
Capital and large corporation
taxes (note 6) 574 595
Future income tax recovery (note 6) (86,199) (12,722)
----------------------------------------------------------------------
Net earnings $ 138,806 $ 63,954


Unitholders' equity, beginning of year 364,215 264,887
Issue of Trust Units 156,687 158,297
Change in Exchangeable Shares, net (note 7) 1,752 (1,208)
Change in contributed surplus (note 7) 844 572
Distributions to Unitholders (146,360) (122,287)
----------------------------------------------------------------------

Unitholders' equity, end of year $ 515,944 $ 364,215
----------------------------------------------------------------------
----------------------------------------------------------------------

Net earnings per Trust Unit (note 7)
Basic $ 2.66 $ 1.54
Diluted $ 2.61 $ 1.51
----------------------------------------------------------------------
----------------------------------------------------------------------

See accompanying notes to the consolidated financial statements


Consolidated Statements of Cash Flows

Years ended December 31 ($ thousands)
----------------------------------------------------------------------
2004 2003
----------------------------------------------------------------------
Restated
(note 3)
Operating activities
Net earnings $ 138,806 $ 63,954
Items not requiring cash
Depletion, depreciation and accretion 118,547 78,853
Internalization of management contract 2,693 5,381
Trust Unit incentive compensation 1,263 572
Gain on sale of other assets (232) -
Future income tax recovery (86,199) (12,722)
----------------------------------------------------------------------
Cash flow before change in non-cash
working capital 174,878 136,038
Asset retirement expenditures (684) (218)
Change in non-cash working capital (note 8) (21,291) 1,514
----------------------------------------------------------------------
152,903 137,334
----------------------------------------------------------------------
Financing activities
Increase in long term debt 60,456 6,408
Distributions to Unitholders (138,806) (122,287)
Issue of Trust Units 155,327 151,708
----------------------------------------------------------------------
76,977 35,829
Change in non-cash working capital (note 8) 4,502 512
----------------------------------------------------------------------
81,479 36,341
----------------------------------------------------------------------
Total cash provided $ 234,382 $ 173,675
----------------------------------------------------------------------
----------------------------------------------------------------------

Investing activities
Property acquisitions $ (2,615) $ (156,829)
Corporate acquisitions (note 4) (177,067) -
Capital expenditures (56,339) (22,931)
Long term investments (23) (211)
Proceeds on sale of fixed assets 3,496 5,770
Proceeds on sale of other assets 1,000 -
----------------------------------------------------------------------
(231,548) (174,201)
Change in non-cash working capital (note 8) 4,720 526
----------------------------------------------------------------------
Total cash used $ (226,828) $ (173,675)
----------------------------------------------------------------------
----------------------------------------------------------------------

See accompanying notes to the consolidated financial statements


Notes to the Consolidated Financial Statements

For the years ended December 31, 2004 and 2003

($ thousands, except Trust Units and per Trust Unit amounts)

1. ORGANIZATION

Shiningbank Energy Income Fund ("Shiningbank" or the "Fund") is an
unincorporated open-end investment trust formed under the laws of the
Province of Alberta pursuant to a trust indenture dated May 16, 1996 and
subsequently amended. Operations commenced on July 1, 1996. The
beneficiaries of the Fund are the holders (the "Unitholders") of trust
units (the "Trust Units").

On March 5, 2004, the Fund acquired all of the shares of Good Ridge
Explorations Ltd. ("Good Ridge") through its wholly owned indirect
subsidiary Shiningbank Energy Ltd. (the "Corporation"). On March 8,
2004, the Corporation acquired all of the shares of Birchill Resources
Limited ("Birchill") which in turn held substantially all of its assets
in a partnership. Also on March 8, 2004, the Corporation, Good Ridge and
Birchill were amalgamated, continuing as Shiningbank Energy Ltd. The
partnership, which was renamed Shiningbank Energy Partnership ("SEP"),
remained in place and was held by the Corporation.

On December 31, 2004, the Corporation transferred substantially all of
its interest in SEP to a newly formed limited partnership called
Shiningbank Limited Partnership ("SLP") and SEP was wound up. SLP is
held by a newly created operating trust called Shiningbank Operating
Trust ("SOT"), the sole beneficiary of which is the Fund. The
Corporation is the general partner of SLP.

The trust indenture provides that 300,000,000 Trust Units may be issued.
Each Trust Unit represents an equal fractional beneficial interest in
any distributions from the Fund and in the net assets of the Fund on
termination or winding up of the Fund. All Trust Units rank among
themselves equally and rateably without discrimination, preference or
priority. The trust indenture provides that Trust Units are redeemable
at any time on demand by the Unitholders at amounts as determined by a
market price formula. The total amount payable by the Fund in respect of
all Trust Units tendered for redemption, however, may not exceed
$100,000 in any calendar month.

2. SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial statements have been prepared by management
using Canadian generally accepted accounting principles. The preparation
of financial statements requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
the disclosure of contingencies at the date of the financial statements,
and revenues and expenses during the reporting period. Actual results
could differ from those estimated.

Significant items subject to such estimates and assumptions include the
amounts recorded for depletion and depreciation of the petroleum and
natural gas properties, accretion of discount on asset retirement
obligations, and asset retirement expenditures which are based on
estimates of reserves and future costs and the amounts recorded for
Trust Unit incentive compensation which are based on the estimated fair
value of rights granted. By their nature, these estimates, and those
related to future cash flows used to assess impairment, are subject to
measurement uncertainty and the impact on the financial statements of
future periods could be material.

(a) Principles of consolidation

These consolidated financial statements include the accounts of the Fund
and its direct and indirect subsidiaries, including the Corporation,
SLP, SOT, Shiningbank Holdings Corporation ("SHC") and 1130243 Alberta
Inc.

(b) Fixed assets

The Fund follows the full cost method of accounting for petroleum and
natural gas properties under which all acquisition and development costs
are capitalized. Such costs include land acquisition, geological,
geophysical and drilling costs for productive and non-productive wells
and directly related overhead charges. Proceeds from the sale of
petroleum and natural gas properties are applied against capitalized
costs. Gains or losses upon disposition of such properties are not
recognized unless the disposition would alter the depletion and
depreciation rate by 20% or more.

The costs of fixed assets, plus a provision for future development costs
of proved undeveloped reserves, are depleted and depreciated using the
unit-of-production method based on estimated total proved reserves
volumes, before royalties, as determined by independent engineers.
Proved reserves are converted to a common unit of measure on the basis
of their approximate relative energy content. Other miscellaneous assets
are depreciated on a declining balance basis at 20% per annum.

Oil and gas assets are evaluated annually to determine that the carrying
amount in a cost centre is recoverable and does not exceed the fair
value of the properties in the cost centre. The carrying amounts are
assessed to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves, the lower of cost and
market of unproved properties and the cost of major development
projects, exceeds the carrying amount of the cost centre. When the
carrying amount is in excess, and is therefore assessed as not
recoverable, an impairment loss would be recognized to the extent that
the carrying value of assets exceeds the sum of the discounted cash
flows from the production of proved and probable reserves, the lower of
cost and market of unproved properties and the cost of major development
projects. The cash flows are estimated using expected future product
prices and costs and are discounted using a risk-free interest rate (see
note 4).

(c) Goodwill

Goodwill is recorded upon a corporate acquisition when the total
purchase price exceeds the net identifiable assets and liabilities of
the acquired company. The goodwill balance is not amortized but instead
is assessed for impairment annually or more frequently, if necessary.
Impairment is determined based on the fair value of the reporting entity
compared to the carrying or net book value of the reporting entity. Any
impairment will be charged to earnings in the period in which the fair
value of the reporting entity is below the carrying value.

(d) Asset retirement obligation

Shiningbank recognizes the fair value of an Asset Retirement Obligation
("ARO") in the period in which it is incurred when a reasonable
estimation of the fair value can be made. The fair value of the
estimated ARO is recorded as a long-term liability, with a corresponding
increase in the carrying value of the asset. In periods subsequent to
initial measurement, the passage of time results in liability changes
and the amount of accretion is charged against current period income.
The liability is also adjusted for revisions to previously used
estimates.

Previously, Shiningbank recognized a provision for estimated future site
restoration and abandonment costs calculated on the unit-of-production
method over the remaining proved reserves. Actual site restoration and
abandonment costs were charged against the liability as incurred.

(e) Income taxes

The Fund is a taxable trust under the Income Tax Act (Canada). Any
taxable income is allocated to the Unitholders and therefore no
provision for income taxes relating to the Fund is included in these
financial statements.

The Fund's corporate subsidiaries follow the tax liability method of
accounting for income taxes. Under this method, income tax liabilities
and assets are recognized for the estimated tax consequences
attributable to differences between the amounts reported in the
financial statements and their respective tax bases, using enacted
income tax rates. The effect of a change in income tax rates on future
income tax liabilities and assets is recognized in income in the period
that the change occurs.

The Fund's corporate subsidiaries are taxable Canadian corporations and
are liable for tax on income that they retain. The Corporation is also
subject to capital taxes in jurisdictions where such taxes apply and
these taxes are deducted from distributions to Unitholders.

(f) Financial instruments

The Corporation from time to time employs financial instruments to
manage exposures related to interest rates and commodity prices. These
instruments are not used for speculative trading purposes. The Fund
formally documents all relationships between hedging instruments and
hedged items and assesses, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging
transactions are highly effective in offsetting changes in fair values
or cash flows of hedged items. Gains and losses on commodity price
hedges are included in revenues upon the sale of related production
provided there is reasonable assurance that the hedge is and will
continue to be effective.

Realized and unrealized gains and losses associated with hedging
instruments that have been terminated or cease to be effective prior to
maturity, are deferred on the balance sheet and recognized in income in
the period in which the underlying hedged transaction is recognized.

For transactions that do not qualify for hedge accounting, the Fund
applies the fair value method of accounting by recording an asset or
liability on the consolidated balance sheet and recognizing changes in
the fair value of the instruments in the current period statement of
earnings.

(g) Trust Unit Rights Incentive Plan

The Fund accounts for the Trust Unit Rights Incentive Plan using the
fair value based method. Under this method, compensation costs
attributed to the Trust Unit rights are measured at fair value at the
grant date and recognized over the vesting period, with a corresponding
increase to contributed surplus. Consideration paid by employees and
directors of the Corporation on the exercise of Trust Unit rights under
this plan is recorded in Trust Units equity upon receipt, along with the
amount of non-cash Trust Unit incentive compensation expense recognized
in contributed surplus.

(h) Joint ventures

Substantially all of the Fund's petroleum and natural gas activities are
conducted jointly with others and, accordingly, these financial
statements reflect only the Fund's proportionate interest in such
activities.

(i) Per Trust Unit amounts

Basic earnings per Trust Unit is computed by dividing net earnings by
the weighted average number of Trust Units outstanding for the year.
Diluted net earnings per Trust Unit amounts reflect the potential
dilution that could occur if securities or other contracts to issue
Trust Units were exercised or converted to Trust Units.

(j) Revenue recognition

Revenue from the sale of oil and natural gas is recognized when the
product is delivered.

(k) Comparative figures

Comparative figures have been reclassified to conform to current year
presentation.

3. CHANGE IN ACCOUNTING POLICIES

(a) Asset retirement obligation

Effective January 1, 2004 Shiningbank has adopted CICA handbook section
3110, "Asset Retirement Obligations." The standard requires the
recognition and measurement of liabilities related to legal obligations
to retire property, plant and equipment upon acquisition of the
liability. The initial liability must be measured at fair value and
subsequently adjusted for the accretion of discount and changes in the
fair value. The asset retirement cost is capitalized and depleted into
earnings over time.

This change in accounting policy has been adopted retroactively with
restatement of the prior period presented for comparative purposes. The
effect of the adoption is as follows:



--------------------------------------------------------------------
December 31, December 31,
Balance sheet 2003 2002
--------------------------------------------------------------------
Increase in fixed assets for
asset retirement costs $ 12,531 $ 13,521
Net increase in asset
retirement obligation 15,329 15,560
Decrease in future income tax liability (771) (493)
Decrease in accumulated earnings (2,028) (1,546)
--------------------------------------------------------------------



--------------------------------------------------------------------
Statement of earnings Year ended December 31, 2003
--------------------------------------------------------------------
Accretion expense on asset
retirement obligation $ 1,981
Increased depletion due to asset
retirement costs 1,845
Eliminate prior provision for site restoration (3,066)
Increase future income tax recovery (277)
--------------------------------------------------------------------
Net earnings impact $ 483
--------------------------------------------------------------------
Basic net earnings per Trust Unit $ 0.01
Diluted net earnings per Trust Unit $ 0.01
--------------------------------------------------------------------


The estimated asset retirement obligation is based upon the Fund's net
ownership interest in each area, estimated costs to abandon and reclaim
wells and facilities in the area, and the anticipated timing of such
expenditures.

Undiscounted expenditures totalling $37.6 million are expected to be
made over the next 33 years. The Fund's credit adjusted risk free rate
of 7% and an inflation rate of 2% were used to calculate the present
value of the obligation.

The Fund's asset retirement obligation is as follows:



--------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2004 2003
--------------------------------------------------------------------
Carrying amount, beginning of year $ 26,524 $ 23,907
Liability incurred during the year,
net of dispositions 2,212 854
Settlement of liability during the year (684) (218)
Accretion expense 2,190 1,981
--------------------------------------------------------------------
Carrying amount, end of year $ 30,242 $ 26,524
--------------------------------------------------------------------


(b) Trust Unit incentive compensation

During 2003 the Fund elected to adopt the amendments to the CICA
Handbook Section 3870, "Stock-based Compensation and Other Stock-based
Payments." The section was adopted effective January 1, 2003 and Trust
Unit incentive compensation expense of $572,000 was recorded in 2003 for
rights granted during 2003 and vesting within the year.

(c) Hedging relationships

Effective January 1, 2004, the Fund adopted Accounting Guideline 13,
"Hedging Relationships" that establishes standards for the documentation
and effectiveness of hedging relationships for the purposes of applying
hedge accounting. The adoption of this standard had no effect on the
Fund's financial results.

4. FIXED ASSETS

(a) Acquisition of Birchill Resources Limited

Effective January 1, 2004 the Corporation acquired all the outstanding
shares of Birchill for $170.1 million. The transaction closed on March
8, 2004. The acquisition was accounted for by the purchase method and
the results of operations of Birchill are included in the accounts from
the closing date. Birchill and the Corporation were subsequently
amalgamated.



--------------------------------------------------------------------
Cash consideration $ 169,639
Related fees and expenses 463
--------------------------------------------------------------------
Cost of acquisition $ 170,102
--------------------------------------------------------------------
Working capital deficiency $ (5,724)
Future income tax (66,700)
Asset retirement obligation (3,028)
Petroleum and natural gas properties and equipment 245,554
--------------------------------------------------------------------
Total consideration $ 170,102
--------------------------------------------------------------------


(b) Acquisition of Good Ridge Explorations Ltd.

Effective January 1, 2004 the Corporation acquired all the outstanding
shares of Good Ridge for $7.0 million. The transaction closed on March
5, 2004. The acquisition was accounted for by the purchase method and
the results of operations of Good Ridge are included in the accounts
from the closing date. Good Ridge and the Corporation were subsequently
amalgamated.



--------------------------------------------------------------------
Cash consideration $ 6,935
Related fees and expenses 30
--------------------------------------------------------------------
Cost of acquisition $ 6,965
--------------------------------------------------------------------
Working capital $ 578
Future income tax (2,201)
Asset retirement obligation (147)
Petroleum and natural gas properties and equipment 7,025
Goodwill 1,710
--------------------------------------------------------------------
Total consideration $ 6,965
--------------------------------------------------------------------


(c) Ceiling test

The Fund performed a ceiling test calculation at December 31, 2004 to
assess the recoverable value of fixed assets. Future prices were
obtained from third parties, adjusted for commodity differentials
specific to the Fund, and then escalated based on factors in the Fund's
year-end independent reserves evaluation. The following table summarizes
the benchmark prices used in the ceiling test calculation. Based on
these assumptions, the undiscounted value of future net revenues from
proved reserves exceeded the carrying value of the Fund's fixed assets
at December 31, 2004.



Oil Gas
--------------------------------------------------------------------
Edmonton Alberta
Year WTI Light AECO Reference
--------------------------------------------------------------------
US$/bbl C$/bbl C$/mmbtu C$/mmbtu
2005 $ 44.29 $ 51.25 $ 6.97 $ 6.76
2006 41.60 48.03 6.66 6.45
2007 37.09 42.64 6.21 6.00
2008 33.46 38.31 5.73 5.55
2009 31.84 36.36 5.37 5.21
2010 32.32 36.91 5.47 5.31
2011 32.80 37.47 5.57 5.38
2012 33.30 38.03 5.67 5.48
2013 33.79 38.61 5.77 5.58
2014 34.30 39.19 5.87 5.68
2015 34.82 39.78 5.98 5.79
Thereafter + 1.5%/annum + 1.5%/annum + 1.5%/annum + 1.5%/annum
--------------------------------------------------------------------


5. LONG TERM DEBT

The Corporation has a $225 million revolving credit facility with a
syndicate of four Canadian chartered banks of which $182.1 million was
drawn at December 31, 2004 (2003 - $121.7 million). The revolving period
extends to April 27, 2005. If the revolving facility is not renewed on
that date, it will revert to a two year term with principal payments
commencing on July 28, 2005. The facility is secured by a $300 million
floating charge debenture on all assets of the Corporation together with
supporting debentures and guarantees from operating subsidiaries and
affiliates. Borrowings under the facility bear interest at an annual
rate ranging from the banks' prime rate to the banks' prime rate plus
0.95%, depending on the Fund's total debt to cash flow ratio, or, at
Shiningbank's option, the bankers' acceptance rate plus a stamping fee.

6. INCOME TAXES

The provision for income taxes in the financial statements differs from
the result that would have been obtained by applying the combined
federal and provincial tax rate to the Corporation's and SHC's earnings
before income taxes. This difference results from the following items:



2004 2003
--------------------------------------------------------------------
Taxable loss of the Corporation and SHC $ (27,800) $ (17,400)
Combined federal and provincial tax rate 38.62% 40.60%
Computed income tax recovery (10,700) (7,100)
Increase (decrease) in income taxes
resulting from:
Non-deductible Crown charges 3,500 1,800
Other 2,901 (222)
Internalization of management contract 1,400 2,400
Resource allowance (1,800) (1,900)
Change in tax rate (3,100) (7,700)
Internal restructuring (78,400) -
--------------------------------------------------------------------
Future income tax recovery (86,199) (12,722)
Capital and large corporation taxes 574 595
--------------------------------------------------------------------
Income and capital taxes $ (85,625) $ (12,127)
--------------------------------------------------------------------


The recovery of future income taxes, through the internal restructuring,
resulted from the transfer of the partnership acquired in the Birchill
acquisition from the Corporation to a new operating trust, the
beneficiary of which is the Fund.

The components of the Corporation's and SHC's future income tax
liability at December 31, are as follows:



2004 2003
--------------------------------------------------------------------
Future income taxes:
Oil and natural gas properties $ 49,151 $ 59,999
Asset retirement obligation (9,084) (4,636)
Non-capital losses (4,383) (3,935)
Other (2,418) (864)
--------------------------------------------------------------------
$ 33,266 $ 50,564
--------------------------------------------------------------------


7. TRUST UNITS

(a) Authorized

300,000,000 Trust Units


(b) Issued

2004 2003
---------------------------------------------------------------------
Number Amount Number Amount
---------------------------------------------------------------------
Balance, beginning
of year 44,343,415 $ 550,267 33,193,937 $ 391,970
Issued for cash 8,800,000 149,600 10,338,500 155,078
Less: Commissions
and issue costs - (8,143) - (8,216)
Issued on exercise
of rights 618,166 8,024 134,673 1,831
Issued for cash under
Dividend Reinvestment
Plan 296,538 5,846 179,488 3,016
Issued on conversion
of Exchangeable Shares 82,500 941 496,817 6,588
Transfer from contributed
surplus on exercise
of rights - 419 - -
---------------------------------------------------------------------
Balance, end of year 54,140,619 $ 706,954 44,343,415 $ 550,267
---------------------------------------------------------------------


(c) Exchangeable Shares

On October 9, 2002, SHC issued 1,136,614 Exchangeable Shares in
connection with the management internalization transaction. The
Exchangeable Shares are exchangeable, at the option of the holder, into
Trust Units for no additional consideration. As at December 31, 2004,
353,614 (2003 - 555,678) Exchangeable Shares were held in escrow to be
released over periods up to October 2007 under the terms of two escrow
agreements. The number of Trust Units issuable upon conversion is based
upon the exchange ratio in effect at the conversion date. The exchange
ratio is adjusted by the distributions paid to Unitholders divided by
the 10-day weighted average unit price preceding the record date. The
Exchangeable Shares are not eligible for distributions.



2004 2003
---------------------------------------------------------------------
Number Amount Number Amount
---------------------------------------------------------------------
Balance, beginning
of year 126,290 $ 5,267 378,872 $ 6,475
Released from escrow 202,064 - 202,064 -
Conversion of
Exchangeable Shares (64,872) (941) (454,646) (6,589)
Amortization of
deferred portion - 2,693 - 5,381
---------------------------------------------------------------------
Balance, end of year 263,482 $ 7,019 126,290 $ 5,267
---------------------------------------------------------------------
Exchange ratio,
end of year 1.32647 1.18417
---------------------------------------------------------------------
Trust Units issuable
upon conversion of
non-escrowed shares 349,501 149,549
Trust Units issuable
upon conversion of
escrowed shares 469,058 658,016
---------------------------------------------------------------------
Total Trust Units
issuable upon
conversion of
all shares 818,559 807,565
---------------------------------------------------------------------


(d) Trust Unit Rights Incentive Plan

Under Shiningbank's Trust Unit Rights Incentive Plan the initial
exercise price of rights granted may not be less than the current market
price of the Trust Units as of the date of grant and the maximum term of
each right is not to exceed 10 years. The exercise price of the rights
is to be adjusted downwards from time to time by the amount, if any,
that distributions to Unitholders in any calendar quarter exceed 2.5%
(10% annually) of the Fund's consolidated net book value of fixed
assets. A total of 3,197,796 Trust Units have been reserved for issuance
under the plan. At December 31, 2004, there were 1,396,901 (2003 -
1,460,067) rights outstanding, of which 395,234 (2003 - 583,401) were
exercisable at a weighted average exercise price of $13.34 (2003 -
$14.20). In January 2005, a further 717,500 Trust Unit rights were
granted.



Rights 2004 2003
---------------------------------------------------------------------
Weighted Weighted
Average Average
Exercise Exercise
Number Price Number Price
---------------------------------------------------------------------
Balance, beginning
of year 1,460,067 $ 13.93 1,059,000 $ 15.00
Granted 580,000 $ 18.75 525,000 $ 15.24
Forfeited (25,000) $ 16.44 - $ -
Exercised (618,166) $ 12.98 (123,933) $ 13.44
---------------------------------------------------------------------
Balance before reduction
of exercise price 1,396,901 $ 16.31 1,460,067 $ 15.22
Reduction of
exercise price (1.57) (1.29)
---------------------------------------------------------------------
Balance, end of year 1,396,901 $ 14.74 1,460,067 $ 13.93
---------------------------------------------------------------------


The following table summarizes information about Trust Unit rights
outstanding and exercisable at December 31, 2004:



------------------------------------------------------------------------
Rights Outstanding Rights Exercisable
------------------------------------------------------------------------
Weighted
Average Weighted Weighted
Range of Number Remaining Average Number Average
Exercise Outstanding Contractual Exercise Exercisable Exercise
Prices At 12/31/04 Life (Yrs) Price At 12/31/04 Price
------------------------------------------------------------------------
$10.00 to $12.99 481,667 7.8 $12.08 65,000 $11.96
$13.00 to $16.99 380,234 6.8 $13.92 330,234 $13.62
$17.00 to $21.50 535,000 9.1 $17.71 - $ -
------------------------------------------------------------------------
$10.00 to $21.50 1,396,901 8.0 $14.74 395,234 $13.34
------------------------------------------------------------------------


Shiningbank recorded Trust Unit incentive compensation expense of
$1,263,000 for the year ended December 31, 2004 (2003 - $572,000) for
rights issued in 2003 and 2004, and vesting within the year.

During the year, $419,000 (2003 - $nil) of contributed surplus was
transferred to Trust Unit equity in respect of rights exercised during
the period.

The following table reconciles the movement in the contributed surplus
balance:



Contributed surplus 2004 2003
--------------------------------------------------------------------
Balance, beginning of year $ 572 $ -
Trust Unit incentive compensation 1,263 572
Net benefit on rights exercised(1) (419) -
--------------------------------------------------------------------
Balance, end of year $ 1,416 $ 572
--------------------------------------------------------------------

(1)Upon exercise, the net benefit is reflected as a reduction of
contributed surplus and an increase to Unitholders' capital.


The fair value of the 580,000 rights issued during the year was
estimated using a Black-Scholes option-pricing model with the following
assumptions: risk-free interest rates ranging from 4.33 to 4.82% (2003 -
4.16 to 4.76%), volatility of 60%, life of 10 years, and a dividend
yield rate of 10% representing the difference between the anticipated
distribution and the anticipated drop in the strike price.

For rights issued in 2002, Shiningbank has elected to disclose the pro
forma effect as if the amended accounting standard had been adopted
January 1, 2002. For the years ended December 31, 2004 and 2003,
Shiningbank's net income would have decreased by $508,000 per year
($0.01 per basic and diluted Trust Unit in 2003 and 2004) due to
additional Trust Unit incentive compensation expense related to rights
granted in 2002.

(e) Distribution Reinvestment Plan

The Distribution Reinvestment Plan ("DRIP") entitles eligible
Unitholders to purchase additional Trust Units by re-investing their
cash distributions or by making additional optional cash payments of up
to a maximum of $3,000 per quarter for the purchase of additional Trust
Units. Trust Units are acquired on the open market at the prevailing
market price or issued from treasury at the average market price over
the last 10 days of trading. During 2004, 296,538 Trust Units were
issued from treasury (2003 - 179,488) under the DRIP for proceeds of
$5.8 million (2003 - $3.0 million).

(f) Per Trust Unit amounts

For the year ended December 31, 2004, the weighted average number of
Trust Units and non-escrowed Exchangeable Shares outstanding was
52,208,852 (2003 - 41,594,854). In computing diluted net earnings per
Trust Unit, the dilutive effect of unit rights and escrowed Exchangeable
Shares, added 984,155 Trust Units (2003 - 772,760) to the weighted
average number of Trust Units outstanding.



8. OTHER CASH FLOW DISCLOSURES

(a) Change in non-cash operating working capital

2004 2003
--------------------------------------------------------------------
Accounts receivable $ (24,271) $ (7,950)
Prepaid expenses (1,841) 248
Accounts payable and accrued liabilities 4,821 9,216
--------------------------------------------------------------------
$ (21,291) $ 1,514
--------------------------------------------------------------------


(b) Change in non-cash financing working capital

2004 2003
--------------------------------------------------------------------
Distributions payable to Unitholders $ 4,502 $ 512
--------------------------------------------------------------------


(c) Change in non-cash investing working capital

2004 2003
--------------------------------------------------------------------
Accounts payable for capital accruals $ 4,720 $ 526
--------------------------------------------------------------------


(d) Cash payments

2004 2003
--------------------------------------------------------------------
Cash payments made for taxes $ 1,231 $ 625
Cash payments made for interest $ 6,023 $ 6,077
--------------------------------------------------------------------


9. FINANCIAL INSTRUMENTS

As at December 31, 2004, there are no significant differences between
the carrying amounts and the fair value of accounts receivable, accounts
payable, accrued liabilities, Trust Unit distributions payable, and
long-term debt. The Corporation is exposed to interest rate variance on
the long term debt disclosed in the balance sheet. Gains and losses on
commodity price hedges are included in revenues upon the sale of related
production provided there is reasonable assurance that the hedge is and
will continue to be effective.

Substantially all of the Fund's accounts receivable are due from
customers in the oil and gas industry and are subject to the normal
industry credit risks. The carrying value of accounts receivable
reflects management's assessment of the associated credit risk.
Substantially all derivative financial instruments are entered into with
Canadian chartered banks in order to reduce credit risk.

At December 31, 2004, Shiningbank held certain oil and natural gas hedge
contracts, the terms of which are listed in the following table. The
estimated market value at December 31, 2004, had the contracts been
settled at that time, would have been a loss of $103,484.



Period Commodity Volume Price
---------------------------------------------------------------------
April 1, 2004
- March 31, 2005 Gas 5,000 GJ/d $5.91 /GJ

November 1, 2004
- March 31, 2005 Gas 5,000 GJ/d $7.50 /GJ floor
$11.00/GJ ceiling
April 1, 2005
- December 31, 2005 Gas 5,000 GJ/d $5.00 /GJ floor
$6.39/GJ ceiling
January 1, 2005
- June 30, 2005 Oil 500 bbl/d US$37.00/bbl floor
US$50.50/bbl ceiling
---------------------------------------------------------------------


Subsequent to December 31, 2004, Shiningbank entered into two additional
hedge contracts.



Period Commodity Volume Price
---------------------------------------------------------------------
February 1, 2005
- December 31, 2005 Oil 500 bbl/d US$40.00/bbl floor
US$55.40/bbl ceiling
April 1, 2005
- October 31, 2005 Gas 5,000 GJ/d $6.70/GJ
---------------------------------------------------------------------


10. INTERNALIZATION OF MANAGEMENT CONTRACT

Effective October 9, 2002, the Fund acquired all of the outstanding
shares of Shiningbank Energy Management Inc., the former Manager of the
Fund. Total consideration for the transaction consisted of a cash
payment of $2.91 million plus 1,136,614 Exchangeable Shares. Total
consideration was reduced by $1.8 million to provide for
performance/retention bonuses to be paid to employees. During 2004, the
remainder of this bonus pool, or $817,250 (2003 - $582,750) was paid out
in cash and expensed.

Total consideration:



-----------------------------------------------------
Cash $ 2,910
Exchangeable Shares issued 16,490
Costs associated with the transaction 1,195
-----------------------------------------------------
Total purchase price $ 20,595
-----------------------------------------------------


Prior to the acquisition, the Fund paid fees to the former Manager of
3.25% of net operating income, a fee of 1.5% on the purchase price of
acquisitions and a quarterly scheduled dividend in accordance with the
terms of the management agreement. The acquisition resulted in the
elimination of all fees and dividends under the management contract.

Exchangeable Shares in the amount of $10.0 million were originally
subject to escrow provisions and are being deferred and amortized into
income as internalization of management contract expense over the
specific vesting periods through 2007. For the year ending December 31,
2004, $2,693,400 (2003 - $5,380,600) has been recorded as expense
representing the amortization of these escrowed Exchangeable Shares.

Shiningbank Energy Income Fund is a conventional oil and gas royalty
trust and its units are listed on The Toronto Stock Exchange under the
symbol "SHN.UN".

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Shiningbank Energy Income Fund
    David M. Fitzpatrick
    President and CEO
    (403) 268-7477 or Toll Free 1-866-268-7477
    or
    Shiningbank Energy Income Fund
    Bruce K. Gibson
    Vice President and CFO
    (403) 268-7477 or Toll Free 1-866-268-7477
    or
    Shiningbank Energy Income Fund
    Debbie Carver
    Investor Relations
    (403) 268-7477 or Toll Free 1-866-268-7477
    (403) 268-7499 (FAX)
    Email: irinfo@shiningbank.com
    Website: www.shiningbank.com