Provident Energy Trust
TSX : PVE.UN
NYSE : PVX

Provident Energy Trust

March 11, 2010 20:12 ET

Provident Announces 2009 Annual and Fourth Quarter Results, 2009 Reserves Information and March Cash Distribution

CALGARY, ALBERTA--(Marketwire - March 11, 2010) -

All values are in Canadian dollars and conversions of natural gas volumes to barrels of oil equivalent (boe) are at 6:1 unless otherwise indicated.

Provident Energy Trust (Provident) (TSX:PVE.UN) (NYSE:PVX) today announced its 2009 fourth quarter interim and audited 2009 annual financial and operating results, 2009 reserves information and the March cash distribution of $0.06 per unit. A summary of Provident's 2009 year-end oil and natural gas reserves is available on Provident's website at www.providentenergy.com. Provident's statement of reserves data and other oil and gas information and accompanying reports under National Instruments 51-101 have been filed on SEDAR and are available under Provident's issuer profile at www.sedar.com.

"We are proud of Provident's accomplishments in 2009," said Provident's President and Chief Executive Officer, Tom Buchanan. "Provident generated cash flow of $264 million and achieved a payout ratio of 74 percent. In addition, we successfully repositioned the Upstream business for higher impact growth through the sale of approximately 6,200 boed of non-strategic properties. In Midstream, we focused on expansion of our infrastructure assets through both strategic acquisitions and internal development. Provident also improved its flexibility, efficiency and competitiveness by reducing debt and streamlining the organizational structure. As a result, Provident is very well positioned to execute value-driven growth opportunities in both business units."

2009 Summary

- Consolidated funds flow from continuing operations decreased 49 percent to $264 million ($1.01 per unit) in 2009, compared to $518 million ($2.03 per unit) in 2008, due primarily to significantly lower commodity prices, higher extraction premiums and reduced oil and gas production, reflecting the sale of non-strategic upstream assets and natural declines.

- Unitholder distributions totaled $0.75 per unit resulting in a payout ratio of 74 percent for 2009, compared to 68 percent in 2008 when Provident distributed $1.38 per unit.

- Bank debt was reduced by 48 percent to $265 million at the end of 2009, from $505 million at the end of 2008. At December 31, 2009, Provident had a total capacity of $1.03 billion in its revolving term credit facility. Following the recent completion of the West Central Alberta asset disposition, Provident's outstanding bank debt is approximately $80 million and the credit facility now has a total capacity of $980 million.

Provident Midstream

- Earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (adjusted EBITDA) from Provident Midstream was $182 million for 2009, down 14 percent from $213 million in 2008. This decline reflects lower natural gas liquids (NGL) product margins, higher extraction premiums at Empress and lower sales volumes, caused by a decrease in natural gas flows and reduced demand for NGL year over year.

- Provident grew its stable fee-for-service margin in 2009, increasing gross operating margin from the commercial services business line by 37 percent to $64 million from $47 million in 2008. This increase reflects incremental condensate storage revenue, increased handling activity at Provident's recently expanded condensate rail offloading facility and higher third-party processing fees at the Redwater facility.

- Provident acquired an additional 6.15 percent interest in the Sarnia fractionation facility (operated by BP Canada) for $18.5 million. The purchase increases Provident's ownership in the facility to 16.5 percent and enhances the propane-plus fractionation capacity in the Empress East System by approximately 7,400 barrels per day (bpd).

- Provident completed construction of two new fully contracted caverns at its Redwater facility, adding 1 million barrels (mmbbl) of NGL storage capacity, increasing total net capacity at Redwater to approximately 6 mmbbl. Provident also completed a 15,000 bpd expansion of the condensate rail terminal at Redwater, increasing the total rail offloading capacity of the facility to approximately 75,000 bpd.

- In November 2009, Provident announced an agreement for the purchase of a hydrocarbon storage facility in Corunna, Ontario. Located in close proximity to Provident's Sarnia operations, the 1,000 acre site has an active cavern storage capacity of 12.1 mmbbl, 13 pipeline connections and a small rail offloading facility. The transaction is expected to close in the second quarter of 2010 and Provident intends to spend additional capital to increase the utilization of the facility for both commercial and operational storage.

Provident Upstream

- During the second half of 2009, Provident Upstream undertook an asset rationalization initiative designed to reposition Provident's portfolio for growth by monetizing non-core properties. Provident divested non-strategic assets in Southeast and Southwest Saskatchewan and Lloydminster for total consideration of $323 million. Proceeds from these divestitures were used to repay long term debt.

- During the first quarter of 2010, Provident completed the sale of its West Central Alberta operating area for cash consideration of $177 million, after normal closing adjustments. Proceeds from this sale have also been applied to the revolving term credit facility.

- Production decreased 22 percent to approximately 21,600 barrels of oil equivalent per day (boed) in 2009, down from approximately 27,700 boed in 2008 due to the disposition of non-strategic assets, natural declines and the impact of the reduced 2009 capital program.

- Funds flow from operations in the Upstream business was $102 million in 2009 a decrease of 70 percent from $339 million in 2008, reflecting substantially lower oil and natural gas prices and lower production compared to the previous year.

- Capital spending totaled $91 million in 2009, down 57 percent from $209 million in 2008. The 2009 capital program was focused primarily on crude oil drilling and completion activities, facilities in Northwest Alberta and the implementation of the waterflood enhanced recovery program in the Peace River Arch / Dixonville area. During the year, Provident drilled 12.3 net oil and natural gas wells with a 98 percent success rate.

- Total proved plus probable oil and gas reserves at year-end decreased 29 percent to 70 mmboe from 98 mmboe in 2008, primarily due to asset dispositions and production during the year. Total proved plus probable reserve life index (RLI) increased to 12.5 years in 2009 from 10.0 years in 2008. Total proved plus probable reserves adjusted to exclude the West Central Alberta assets that were sold in the first quarter of 2010 are 56 mmboe, while proved plus probable RLI following this disposition is 14.6 years.

- Finding and development (F&D) costs, excluding revisions and including future development costs (FDC) were $13.01 per boe of proved reserves in 2009 and $18.87 per boe of proved reserves when revisions are included. F&D costs, excluding revisions and including FDC were $12.71 per boe of proved plus probable reserves in 2009 and were not determinable for proved plus probable reserves when revisions are included, as downward probable reserve revisions exceeded additions.

- Three year average finding, development and acquisition (FD&A) costs, excluding revisions and including FDC were $39.09 per boe of proved reserves in 2009 and $41.67 per boe of proved reserves when revisions are included. Three year average FD&A costs, excluding revisions and including FDC were $23.06 per boe for proved plus probable reserves in 2009 and $32.68 per boe of proved plus probable reserves when revisions are included.

2009 Fourth Quarter Summary

"Provident delivered strong results in the fourth quarter of 2009," said Tom Buchanan. "We achieved a fourth quarter payout ratio of 62 percent, reflecting a substantial recovery in year-over-year NGL prices and the continuing growth in Provident's commercial services business line."

- Funds flow from operations decreased 7 percent to $76 million ($0.29 per unit) in the quarter, compared to $82 million ($0.32 per unit) in the fourth quarter of 2008, reflecting stronger margins in the Midstream business unit offset by lower production and funds flow in the Upstream business unit.

- Payout ratio was 62 percent in the fourth quarter of 2009, an improvement from 95 percent in the fourth quarter of 2008.

- Provident Midstream delivered adjusted EBITDA of $61 million in the fourth quarter of 2009, up 62 percent from $38 million in the fourth quarter of 2008, reflecting stronger NGL margins and increased fee-for-service revenues, partially offset by lower sales volumes.

- Provident Upstream oil and natural gas production decreased 38 percent to approximately 16,800 boed in the fourth quarter of 2009, from approximately 26,800 boed in the fourth quarter of 2008, due primarily to the sale of non-strategic assets during the last half of the year and natural declines.

- Provident Upstream delivered funds flow from operations of $21 million in the fourth quarter of 2009, down 56 percent from $47 million in the fourth quarter of 2008 due to lower production and natural gas prices, partially offset by higher crude oil prices.

March 2010 Cash Distribution

The March cash distribution of $0.06 per unit is payable on April 15, 2010 and will be paid to unitholders of record as of March 22, 2010. The ex-distribution date will be March 18, 2010. The Trust's current annualized cash distribution rate is $0.72 per trust unit. Based on the current annualized cash distribution rate and the TSX closing price on March 11, 2009 of $8.58, Provident's yield is approximately 8 percent.

For unitholders receiving their cash distribution in U.S. funds, the March 2010 cash distribution will be approximately US$0.06 per unit based on an exchange rate of 0.9742. The actual U.S. dollar cash distribution will depend on the Canadian/U.S. dollar exchange rate on the payment date and will be subject to applicable withholding taxes.

2010 Outlook

Provident actively monitors commodity prices and overall market conditions on an ongoing basis and will continue to utilize available cash flow and manage capital resources to achieve a prudent balance between capital expenditures, distributions and long term debt.

Provident Midstream has a capital budget of approximately $86 million for 2010, an increase of 135 percent compared to the 2009 capital program. The Trust plans to allocate approximately $17 million of this budget towards the expansion and construction of rail and truck terminalling infrastructure at the Corunna storage facility near Sarnia, upon completion of the acquisition. Provident anticipates that these upgrades will enhance operating flexibility and commercial opportunities at Sarnia. At Redwater, Provident will direct approximately $15 million towards advancing a 500,000 barrel condensate cavern that will be commissioned in early 2011, begin work on a second cavern of equal size slated for completion in 2012 and construct a brine pond to facilitate future cavern operations. Also at Redwater, approximately $18 million will be allocated to a debottlenecking initiative to increase overall propane-plus fractionation capacity by 8,000 bpd. Provident also plans to undertake a $4 million flare stack recovery initiative to capture and consume certain byproduct gases, increasing efficiency and reducing emissions. Provident also plans to direct approximately $3 million to construct a 12-truck offloading facility to add an additional option for receiving NGL supply at the Provident Empress Plant. The remainder of the Midstream 2010 capital budget will be used for additional expansion opportunities, facility optimization initiatives and normal course facility maintenance at Redwater, Empress and Sarnia.

Key drivers influencing the Midstream business include access to and cost of NGL mix and natural gas feedstock, power and fuel costs, and the demand for finished products including ethane, propane, butane and condensate. In 2010, as available propane-plus supply tightens relative to demand, pricing differentials in Eastern markets where Provident sells the majority of its Empress East production, may increase relative to other major propane hubs including Mont Belvieu and Conway.

Provident's Upstream Business unit has a capital budget for 2010 of $52 million and plans to drill, recomplete or workover approximately 53 net oil and natural gas wells. Key initiatives in 2010 include approximately $6 million allocated towards the continuing development of the prospective Pekisko oil opportunity in Northwest Alberta where Provident is utilizing horizontal wells and multi-stage fracs. In 2010, the Trust is drilling two gross Pekisko wells with the participation of a 50 percent joint venture partner, as well as optimizing Provident's existing Pekisko wells. Additionally, approximately $12 million will be directed towards the drilling, workover and recompletion of up to 27 net wells targeting oil and natural gas in the Northwest Alberta core area. Provident plans to allocate $16 million to the Peace River Arch / Dixonville core area, with approximately $7 million directed towards implementing the second phase of the water flood for enhanced recovery of Montney "C" crude oil at Dixonville, where Provident will drill two net wells, convert an existing well to a water injector and install four liners. Incremental production is expected to be added gradually as the reservoir responds to the water flood over the next 18 months. Provident will also drill an additional three net oil wells in the Peace River Arch area. Approximately $17 million of the capital budget will be directed toward drilling and optimization activities in the Southern Alberta core area where Provident plans to participate in the drilling, workover or recompletion of approximately 17 net oil and natural gas wells. The reminder of the 2010 capital budget will be allocated to other minor initiatives.

Oil and natural gas production in 2010 is expected to average between 9,500 and 10,500 boed and will be weighted approximately 65 percent natural gas and 35 percent crude oil and liquids. The third-party pipeline operator has indicated to Provident that the previously announced pipeline disruption in Northwest Alberta should be resolved prior to the end of the first quarter. Intermittent volume curtailments are expected while the operator completes the remaining remediation work on the pipeline.

Provident Energy Trust is a Calgary-based, open-ended energy income trust that owns and manages a natural gas liquids (NGL) midstream services and marketing business and an oil and gas production business. Provident's oil and gas portfolio is located in some of the most stable and predictable producing regions in Western Canada. Provident's Midstream facilities are also strategically located in Western Canada and in the premium NGL markets in Eastern Canada and the U.S. Provident provides monthly cash distributions to its unitholders and trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbols PVE.UN and PVX, respectively.

This document contains certain forward-looking statements concerning Provident, as well as other expectations, plans, goals, objectives, information or statements about future events, conditions, results of operations or performance that may constitute "forward-looking statements" or "forward-looking information" under applicable securities legislation. Such statements or information involve substantial known and unknown risks and uncertainties, certain of which are beyond Provident's control, including the impact of general economic conditions in Canada and the United States, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, pipeline design and construction, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required approvals of regulatory authorities.

Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to other assumptions identified in this news release, assumptions have been made regarding, among other things, commodity prices, operating conditions, capital and other expenditures, and project development activities.

Although Provident believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Provident can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Provident and described in the forward-looking statements or information.

The forward-looking statements or information contained in this news release are made as of the date hereof and Provident undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless so required by applicable securities laws. The forward-looking statements or information contained in this news release are expressly qualified by this cautionary statement.



Consolidated financial highlights

Consolidated
($ 000s except Three months ended Year ended
per unit data) December 31, December 31,
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% %
2009 2008 Change 2009 2008 Change
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Revenue (net
of royalties
and financial
derivative
instruments)
from
continuing
operations $469,359 $1,019,320 (54) $1,711,483 $3,239,163 (47)
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Funds flow
from Provident
Upstream
operations(1) $ 20,882 $ 47,187 (56) $ 102,156 $ 338,640 (70)
Funds flow
from Provident
Midstream
operations(1) 55,458 34,592 60 161,850 178,982 (10)
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Funds flow
from
continuing
operations(1) $ 76,340 $ 81,779 (7) $ 264,006 $ 517,622 (49)
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Per weighted
average unit -
basic and
diluted $ 0.29 $ 0.32 (9) $ 1.01 $ 2.03 (50)
Distributions to
unitholders $ 47,456 $ 77,324 (39) $ 196,217 $ 352,291 (44)
Per unit $ 0.18 $ 0.30 (40) $ 0.75 $ 1.38 (46)
Percent of
funds flow
from
continuing
operations
paid out as
declared
distributions 62% 95% (35) 74% 68% 9
Net (loss)
income $(20,338) $ (43,248) (53) $ (89,020) $ 157,392 -
Per weighted
average unit -
basic and
diluted $ (0.08) $ (0.17) (53) $ (0.34) $ 0.62 -
Capital
expenditures
(continuing
operations) $ 18,694 $ 54,903 (66) $ 127,369 $ 246,947 (48)
Acquisitions
(continuing
operations) $ 56 $ 4,632 $ 18,833 $ 25,843
Proceeds on
sale of assets
(continuing
operations)
(2) $ 84,097 $ 38 $ 322,720 $ 1,662
Proceeds on
sale of
discontinued
operations,
net of tax $ - $ 19,044 $ - $ 457,906
Weighted
average trust
units
outstanding
(000s)
- basic and
diluted (3) 263,482 257,526 2 261,540 255,177 2
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Consolidated
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As at December 31,
($ 000s) 2009 2008 % Change
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Capitalization
Long-term debt (including
current portion) $ 505,262 $ 765,679 (34)
Unitholders' equity $ 1,381,399 $ 1,636,347 (16)
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(1) Represents cash flow from continuing operations before changes in
working capital and site restoration expenditures. Effective in the
first quarter of 2008, Provident's USOGP business was accounted for as
discontinued operations.
(2) Proceeds on sale of assets in 2009 include cash proceeds as well as
$17.0 million of shares in Emerge Oil & Gas Inc. received on sale of
Lloydminster properties.
(3) Includes dilutive impact of unit options and convertible debentures.


Operational highlights
Three months ended Year ended
December 31, December 31,
----------------------------------------------------------------------------
% %
2009 2008 Change 2009 2008 Change
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Oil and Gas Production -
continuing operations
Daily production -
Provident Upstream
Crude oil (bpd) 5,533 12,307 (55) 8,875 12,473 (29)
Natural gas liquids
(bpd) 1,072 1,134 (5) 1,121 1,203 (7)
Natural gas (mcfd) 60,992 80,450 (24) 69,575 84,039 (17)
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Provident Upstream oil
equivalent (boed) (1) 16,770 26,849 (38) 21,592 27,683 (22)
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Average realized price
from continuing
operations
(before realized
financial derivative
instruments)
Crude oil blend ($/bbl) $ 66.03 $ 47.33 40 $ 54.15 $ 82.79 (35)
Natural gas liquids
($/bbl) $ 59.25 $ 47.64 24 $ 44.40 $ 76.88 (42)
Natural gas ($/mcf) $ 4.36 $ 6.63 (34) $ 3.86 $ 8.23 (53)
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Oil equivalent
($/boe) (1) $ 41.42 $ 43.58 (5) $ 37.00 $ 65.64 (44)
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Field netback from
continuing operations
(3) (before
realized financial
derivative instruments)
($/boe) $ 18.83 $ 21.21 (11) $ 16.57 $ 39.85 (58)
Field netback from
continuing operations
(3) (including realized
financial derivative
instruments) ($/boe) $ 19.70 $ 24.54 (20) $ 18.65 $ 38.75 (52)
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Midstream
Provident Midstream NGL
sales volumes (bpd) 111,912 120,222 (7) 113,528 119,649 (5)
Adjusted EBITDA
(000s) (2) $ 60,855 $ 37,666 62 $182,317 $212,761 (14)
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(1) Provident reports oil equivalent production converting natural gas to
oil on a 6:1 basis.
(2) Adjusted EBITDA is earnings before interest, taxes, depletion,
depreciation, accretion and other non-cash items - see "Reconciliation
of non-GAAP measures".
(3) Field netback from continuing operations is a non-GAAP measure - see
"Provident Upstream segment review - operating netback".


Management's Discussion & Analysis

The following analysis provides a detailed explanation of Provident's operating results for the quarter and year ended December 31, 2009 compared to the quarter and year ended December 31, 2008 and should be read in conjunction with the consolidated financial statements of Provident. This analysis has been prepared using information available up to March 11, 2010.

Provident Energy Trust has diversified investments in certain segments of the energy value chain. Provident currently operates in two key business segments: Canadian crude oil and natural gas production ("Provident Upstream"), and Provident Midstream. Provident's Upstream business produces crude oil and natural gas from four operating areas in the western Canadian sedimentary basin. During 2009, Provident completed the sale of Upstream properties in Southeast Saskatchewan, Southwest Saskatchewan and Lloydminster. Subsequent to December 31, 2009, Provident sold the Upstream properties in the West Central Alberta operating area, reducing Provident's Upstream activities to three operating areas, and extracts, processes, markets, transports and offers storage of natural gas liquids within the integrated facilities at Younger in British Columbia, Redwater and Empress in Alberta, Kerrobert in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and Lynchburg in Virginia. Effective in the first quarter of 2008, Provident's United States oil and natural gas production ("USOGP") business was accounted for as discontinued operations. The USOGP business was sold in 2008.

This analysis commences with a summary of the consolidated financial and operating results followed by segmented reporting on the Upstream business unit and the Midstream business unit. The reporting focuses on the financial and operating measurements management uses in making business decisions and evaluating performance.

This analysis contains forward-looking information and statements. See "Forward-looking information" at the end of the analysis for further discussion.

The analysis refers to certain financial and operational measures that are determined to not be in accordance with generally accepted accounting principles (GAAP) in Canada. These non-GAAP measures include funds flow from continuing operations, adjusted EBITDA and operating netbacks.

Management uses funds flow from continuing operations to analyze operating performance. Funds flow from continuing operations is reviewed, along with debt repayments and capital programs in setting monthly distributions. Funds flow from continuing operations as presented is not intended to represent cash flow from operations or operating profits for the period nor should it be viewed as an alternative to cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds flow from continuing operations throughout this report are based on cash provided by operating activities before changes in non-cash working capital, site restoration expenditures and cash provided by operating activities from discontinued operations. See "reconciliation of non-GAAP measures".

Management uses adjusted EBITDA to analyze the operating performance of each business unit. Adjusted EBITDA as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Adjusted EBITDA as presented is not intended to represent cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with Canadian GAAP. All references to adjusted EBITDA throughout this report are based on earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items ("adjusted EBITDA"). See "reconciliation of non-GAAP measures".

Field operating netback as presented does not have a standardized meaning prescribed by Canadian GAAP and may not be comparable with calculations of similar measures of other entities. See "Provident Upstream segment review- operating netback".

Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth quarter of 2009 results compared to the fourth quarter of 2008. Definitions of terms used in this section, as appropriate, are defined in the year over year section of the Management's Discussion and Analysis following later in this press release.



Funds flow from continuing operations and cash distributions

Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2009 2008 % Change
----------------------------------------------------------------------------
Funds flow from continuing
operations and Distributions
Funds flow from continuing
operations $ 76,340 $ 81,779 (7)
Per weighted average unit from
continuing operations
- basic and diluted (1) $ 0.29 $ 0.32 (9)
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Declared distributions $ 47,456 $ 77,324 (39)
Per unit 0.18 $ 0.30 (40)
Percent of funds flow from
continuing operations paid out
as declared distributions 62% 95% (35)
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(1) Includes dilutive impact of unit options and convertible debentures.


Fourth quarter 2009 funds flow from continuing operations was $76.3 million, seven percent below the $81.8 million recorded in the fourth quarter of 2008. Provident Upstream's 2009 fourth quarter funds flow from operations was $20.9 million, a 56 percent decrease from the $47.2 million recorded in the comparable 2008 quarter. The lower Upstream funds flow reflects strategic divestments in the Upstream business unit that closed in the third and fourth quarters of 2009.

The Provident Midstream business unit added $55.4 million to fourth quarter 2009 funds flow from operations, 60 percent above the $34.6 million recorded in the comparable 2008 quarter. The Midstream business unit performance reflects higher operating margins in the fourth quarter of 2009. The fourth quarter of 2009 Provident Midstream margins benefitted from a stronger pricing environment than in the fourth quarter of 2008.

Declared distributions in the fourth quarter of 2009 totaled $47.5 million, 62 percent of funds flow from continuing operations. This compares to $77.3 million of declared distributions in fourth quarter of 2008, 95 percent of funds flow from continuing operations.



Net loss

Consolidated Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2009 2008 % Change
----------------------------------------------------------------------------

Net loss $ (20,338) $ (43,248) (53)
Per weighted average unit
- basic (1) and diluted (2) $ (0.08) $ (0.17) (53)
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(1) Based on weighted average number of trust units outstanding.

(2) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan and convertible debentures.


In the fourth quarter of 2009, Provident recorded a net loss of $20.3 million compared to a loss of $43.2 million in the comparable 2008 quarter.

The Provident Upstream business segment net loss of $20.6 million, in the fourth quarter of 2009 compared to a 2008 fourth quarter net loss of $421.5 million. The majority of the 2008 fourth quarter net loss was due to a non-cash goodwill impairment charge of $416.9 million. The largest contributors to the remaining quarter over quarter change were a $29.3 million decrease in adjusted EBITDA and a $28.4 million reduction in unrealized gain on financial derivative instruments offset by lower DD&A and increased future income tax recoveries.

The Provident Midstream segment had a net income of $0.3 million in the fourth quarter of 2009, compared to $359.2 million in the fourth quarter of 2008. Improved adjusted EBITDA of $60.9 million in the fourth quarter of 2009 compared to $37.7 million in the fourth quarter of 2008 and a $64.8 million reduction in future tax expense were more than offset by a $415.7 million change in unrealized gains (losses) on financial derivative instruments from a gain in the fourth quarter of 2008 of $377.7 million to a loss in the fourth quarter of 2009 of $38.0 million. In addition, a $12.4 million intangible asset impairment charge was recorded in DD&A in the fourth quarter of 2009.

Provident's net income figures are affected by the requirement to "mark-to-market" all financial derivative instruments at the end of the period and report these unrealized gains or losses as part of current period net income. Because Provident's commodity price risk management program currently extends over three years into the future in the Midstream segment, net earnings can show substantial quarterly variation that is not necessarily related to current operations.

Reconciliation of non-GAAP measures

The Trust calculates earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (adjusted EBITDA) within its segment disclosure. Adjusted EBITDA is a non-GAAP measure. A reconciliation between adjusted EBITDA and loss from continuing operations before taxes follows:



Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Loss from continuing operations
before taxes $ (46,013) $ (13,880) 232
Adjusted for:
Cash interest 5,613 9,998 (44)
Unrealized loss (gain) on financial
derivative instruments 40,080 (404,023) -
Goodwill impairment - 416,890 -
Depletion, depreciation and
accretion and other non-cash
expenses 81,591 78,438 4
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Adjusted EBITDA $ 81,271 $ 87,423 (7)
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The following table reconciles funds flow from continuing operations with
cash provided by operating activities:

Reconciliation of funds flow from
continuing operations Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Cash provided by operating
activities $ 92,692 $ 150,032 (38)
Change in non-cash operating
working capital from continuing
operations (15,697) (70,677) (78)
Site restoration expenditures (655) 2,424 (127)
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Funds flow from continuing
operations 76,340 81,779 (7)
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Taxes

Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Capital tax expense $ 268 $ 485 (45)
Current tax expense (recovery) 1,198 (4,453) -
Future income tax (recovery)
expense (27,141) 52,379 -
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$ (25,675) $ 48,411 -
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The current tax expense was $1.2 million in the fourth quarter of 2009 compared to a recovery in the fourth quarter of 2008 of $4.5 million. The 2009 expense was driven by earnings in Provident's Canadian Midstream business in excess of allowed tax pool claims. The recoveries in 2008 were driven by lower earnings subject to tax in the US Midstream operations allowing the recovery of taxes accrued or paid in prior periods.

The 2009 fourth quarter future income tax recovery of $27.1 million compares to an expense of $52.4 million in the fourth quarter of 2008. The future income tax recovery in the fourth quarter of 2009 was a result of losses created by interest and royalty deductions at the incorporated subsidiary level as well as the unrealized loss on financial derivative instruments. The future income tax expense in the fourth quarter of 2008 resulted primarily from future taxes calculated on the unrealized gains on financial derivative instruments while the goodwill impairment charge was not tax affected.



Interest expense

Continuing operations Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except as noted) 2009 2008 % Change
----------------------------------------------------------------------------

Interest on bank debt $ 1,567 $ 5,015 (69)
Interest on convertible debentures 4,046 4,983 (19)
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Total cash interest $ 5,613 $ 9,998 (44)
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Weighted average interest rate on
all long-term debt 3.6% 5.1% (29)

Debenture accretion and other
non-cash interest expense 1,091 1,465 (26)
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Total interest expense $ 6,704 $ 11,463 (42)
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Interest expense decreased for the quarter as compared to the same quarter in 2008 due to significantly lower debt levels and lower market interest rates. The lower debt levels reflect the strategic asset dispositions that closed in the third and fourth quarters of 2009.

Commodity price risk management program

A summary of Provident's risk management contracts executed during the fourth quarter of 2009 is contained in the following tables.



Activity in the Fourth Quarter:

Midstream

Volume
Year Product (Buy)/Sell Terms Effective Period
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2010 Crude Oil (1,588) Bpd US $77.75 per bbl (7) January 1- March 31
Propane 1,683 Bpd US $1.076 per January 1- March 31
gallon (4)(7)
1,695 Bpd US $1.155 per January 1
gallon (4)(8) - February 28
Normal Butane 833 Bpd US $1.353 per January 1
gallon (5)(7) - March 31
Electricity (10) MW/hpd Cdn $47.475 per January 1
MW/h (6) - December 31
2011 Natural Gas (4,152)Gjpd Cdn $7.33 per gj January 1
- December 31
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(1) The above table represents a number of transactions entered into over
the fourth quarter 2009.

(2) Natural gas contracts are settled agains AECO monthly index.

(3) Crude Oil contracts are settled against NYMEX WTI calendar average.

(4) Propane contracts are settled against Belvieu C3 TET.

(5) Normal butane contracts are settled against Belvieu NC4 NON-TET.

(6) Electricity contracts are settled against the hourly price of
electricity as published by the AESO I $/MWh.

(7) Conversion of Crude Oil BTU contracts to liquids.

(8) Midstream inventory price stabilization contracts.


Settlement of commodity contracts

The following table summarizes the impact of financial derivative contracts settled during the fourth quarters of 2009 and 2008 that were included in realized (loss) gain on financial derivative instruments.



Realized (loss) gain on financial Three months ended December 31,
derivative instruments 2009 2008
----------------------------------------------------------------------------
($ 000s except volumes) Volume (1) Volume (1)
----------------------------------------------------------------------------

Provident Upstream
Crude Oil $ 326 0.1 $ 6,089 0.4
Natural gas 1,017 2.1 2,130 1.9

Provident Midstream
Crude Oil (5,630) 1.0 (4,123) 1.3
Natural gas (21,333) 5.4 (13,046) 6.7
NGL's (includes propane, butane) (1,729) 0.4 34,203 0.2
Foreign Exchange 1,045 - (1,763) -
Electricity (188) - 827 -

Corporate
Interest Rate (2) (545) - - -
----------------------------------------------------------------------------

Realized (loss) gain on financial
derivative instruments $(27,037) $ 24,317 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents aggregate net volumes that were bought/sold
over the periods. Crude oil and NGL volumes are listed in millions of
barrels and natural gas is listed in millions of gigajoules.
(2) Realized gains and losses on coporate related interest rate contracts
are allocated to the reporting segments for segmented reporting
purposes.


The realized loss for the fourth quarter of 2009 was $27.0 million compared to a realized gain of $24.3 million in the comparable 2008 quarter. The realized loss in the fourth quarter of 2009 was driven by natural gas derivative purchase contracts in the midstream business settling at a contracted price higher than the current market gas prices. The comparable 2008 realized gain was driven mostly by NGL derivative sales contracts in the midstream business settling at contracted NGL prices higher than the NGL's market prices during the settlement period.

In addition, the Trust recorded a loss of $17 thousand (2008 - $21.6 million gain) on corporate foreign exchange contracts. The amounts were included in foreign exchange loss (gain) and other on the consolidated statement of operations and were allocated to the reporting segments.

Provident Upstream segment review

Upstream asset dispositions

On November 30, 2009, Provident closed the sale of its predominately heavy oil assets in the Lloydminster operating area to a private company, Emerge Oil & Gas Inc. for total consideration of $84.0 million, consisting of $67.0 million in cash and $17.0 million in equity. Net disposition proceeds were applied to Provident's revolving term credit facility. Production on the date the disposition was announced was approximately 2,200 boed.

On December 23, 2009, Provident announced that it had reached an agreement with Storm Ventures International Inc. to sell the oil and natural gas assets in the West Central Alberta operating area. Production on the date of announcement for these properties totaled approximately 5,000 boed. The transaction closed on March 1, 2010. Proceeds from the transaction of $177 million were applied to Provident's revolving term credit facility.



Crude oil and natural gas liquids prices

The following prices are net of transportation expense.

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ per bbl) 2009 2008 % Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 76.19 $ 58.73 30
Exchange rate (from US$ to
Cdn$) 1.06 1.21 (12)
WTI expressed in Cdn$ $ 80.48 $ 71.21 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing before
financial derivative
instruments
Crude oil $ 66.03 $ 47.33 40
Natural gas liquids $ 59.25 $ 47.64 24
----------------------------------------------------------------------------
Crude oil and natural gas
liquids $ 64.93 $ 47.36 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the fourth quarter of 2009, Provident's realized oil and natural gas liquids price, prior to the impact of financial derivative instruments, increased by 37 percent to $64.93 per barrel compared to $47.36 per barrel in the fourth quarter of 2008. The increase was related to narrower differentials and a 30 percent higher US$ WTI crude oil price partially offset by a stronger Canadian dollar.



Natural gas price

The following prices are net of transportation expense.

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
(Cdn$ per mcf) 2009 2008 % Change
----------------------------------------------------------------------------

AECO monthly index $ 4.23 $ 6.78 (38)
Corporate natural gas price per
mcf before financial derivative
instruments $ 4.36 $ 6.63 (34)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident's fourth quarter 2009 realized natural gas price, prior to the impact of financial derivative instruments, decreased 34 percent as compared to the fourth quarter of 2008. Provident's gas portfolio includes aggregator contracts sold on a term basis that can differ from the benchmark price and sells to the spot market on monthly or daily indices and receives prices which take into account heat content. Provident's realized prices and changes in price can therefore differ from benchmark indices.



Production

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Daily production
Crude oil (bpd) 5,533 12,307 (55)
Natural gas liquids (bpd) 1,072 1,134 (5)
Natural gas (mcfd) 60,992 80,450 (24)
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 16,770 26,849 (38)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.


Production decreased 38 percent to 16,770 boed during the fourth quarter of 2009 as compared to 26,849 boed in the comparable quarter of 2008. The decrease reflects approximately 4,000 boed of production sold prior to the start of the fourth quarter of 2009 and the sale of approximately 2,200 boed of predominately heavy oil production that closed on November 30, 2009. The reduced volumes in the remaining core areas were impacted by lower capital expenditures in 2009 on drilling and optimization activities as well as capital directed at longer term plays that did not result in immediate production additions. The result was that production additions did not offset the natural production declines.

In the third quarter of 2009, Provident reported the impact a third party natural gas pipeline outage was having on the deliverability of its Northwest Alberta natural gas production. In the fourth quarter of 2009, operational steps carried out by Provident resulted in nearly full deliverability of the natural gas. Provident has received indication from the third party operator that repairs on this line should be completed prior to the end of the first quarter of 2010.

In Dixonville, three more crude oil wells were converted to water injectors in the fourth quarter as part of the phase one expansion, bringing the total wells converted to 21 in 2009. Production from these wells in the fourth quarter of 2008 was approximately 500 bpd. The approval for the phase two expansion was received in January 2010 and an application for phase three was submitted in February 2010. Production growth in Dixonville is expected to increase as the waterflood matures with incremental production expected gradually over the next 18 months.

Production for the fourth quarter of 2009 was weighted 61 percent natural gas, and 39 percent crude oil and natural gas liquids. This compared to fourth quarter 2008 production weighted 50 percent natural gas and 50 percent crude oil and natural gas liquids.



Provident Upstream's production summarized by operating areas is as follows:

Three months ended December 31,
----------------------------------------------------------------------------
Provident Upstream 2009 2008 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
West Central Alberta 4,931 6,005 (18)
Southern Alberta 4,449 4,990 (11)
Northwest Alberta 3,664 4,283 (14)
Dixonville 2,297 3,750 (39)
----------------------------------------------------------------------------
15,341 19,028 (19)
Other (2) 1,429 7,821 (82)
----------------------------------------------------------------------------
16,770 26,849 (38)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.
(2) Includes Southeast Saskatchewan and Southwest Saskatchewan operating
areas that were sold on September 30, 2009 and Lloydminster operating
area that was sold on November 30, 2009.


Revenue and royalties

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf
data) 2009 2008% Change
----------------------------------------------------------------------------

Oil
Revenue $ 33,613 $ 53,592 (37)
Realized gain on financial
derivative instruments 326 6,089 (95)
Royalties (6,808) (9,159) (26)
----------------------------------------------------------------------------
Net revenue $ 27,131 $ 50,522 (46)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 53.30 $ 44.62 19
Royalties as a percentage of
revenue 20.3% 17.1%

Natural gas
Revenue $ 24,458 $ 49,088 (50)
Realized gain on financial
derivative instruments 1,017 2,130 (52)
Royalties (1,568) (7,643) (79)
----------------------------------------------------------------------------
Net revenue $ 23,907 $ 43,575 (45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per mcf) $ 4.26 $ 5.89 (28)
Royalties as a percentage of
revenue 6.4% 15.6%

Natural gas liquids
Revenue $ 5,841 $ 4,970 18
Royalties (1,599) (1,299) 23
----------------------------------------------------------------------------
Net revenue $ 4,242 $ 3,671 16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 43.01 $ 35.19 22
Royalties as a percentage of
revenue 27.4% 26.1%

Total
Revenue $ 63,912 $ 107,650 (41)
Realized gain on financial
derivative instruments 1,343 8,219 (84)
Royalties (9,975) (18,101) (45)
----------------------------------------------------------------------------
Net revenue $ 55,280 $ 97,768 (43)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 35.83 $ 39.58 (9)
Royalties as a percentage of
revenue 15.6% 16.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses and the realized gain (loss)
on financial derivative instruments excludes the impact of corporate
interest rate swap gains/losses allocated to Provident Upstream.


In the fourth quarter of 2009, Provident Upstream production revenue was $63.9 million, a decrease of 41 percent from $107.7 million in 2008. A 38 percent decrease in production and a 34 percent decrease in realized natural gas price, partially offset by a 37 percent increase in crude oil and natural gas liquids prices accounts for the change. Royalties, which are price sensitive and affected by production rates, decreased as a percentage of revenue mainly due to significantly lower natural gas prices. The preceding factors, as well as the $6.9 million decrease in realized gain on financial derivative instruments account for net revenue of $55.3 million in the fourth quarter of 2009, 43 percent below the $97.8 million recorded in the fourth quarter of 2008. Net revenue per boe in the fourth quarter of 2009 was $35.83 per boe, a decrease of nine percent from $39.58 per boe in the fourth quarter of 2008.



Production expenses

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

Production expenses $ 24,889 $ 37,159 (33)
Production expenses (per boe) $ 16.13 $ 15.04 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Fourth quarter 2009 production expenses decreased 33 percent to $24.9 million from $37.2 million in the comparable 2008 quarter. The decrease was primarily due to the disposition of approximately 4,000 boed of production in the Southeast and Southwest Saskatchewan operating areas on September 30, 2009 and approximately 2,200 boed in the Lloydminster area on November 30, 2009. On a per boe basis, quarter over quarter production expenses increased by seven percent to $16.13 per boe from $15.04 per boe in the comparable 2008 quarter. The operating cost per boe increase in the remaining core areas recognize fixed costs being allocated over fewer produced barrels of oil equivalent.

Operating netback

Operating netback as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be comparable with calculations of similar measures of other entities.



Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ per boe) 2009 2008 % Change
----------------------------------------------------------------------------
Netback per boe
Gross production revenue $ 41.42 $ 43.58 (5)
Royalties (6.46) (7.33) (12)
Operating costs (16.13) (15.04) 7
----------------------------------------------------------------------------
Field operating netback 18.83 21.21 (11)
Realized gain on financial
derivative instruments 0.87 3.33 (74)
----------------------------------------------------------------------------

Operating netback after
realized financial derivative
instruments $ 19.70 $ 24.54 (20)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident Upstream operating netbacks have transportation expense netted against gross production revenue.

The fourth quarter 2009 field operating netback decreased 11 percent to $18.83 per boe from $21.21 per boe in the comparable quarter in 2008. The five percent drop in gross production revenue per boe reflects both the 34 percent decrease in natural gas prices combined with Provident's increased weighting of natural gas production to 61 percent of the production base from 50 percent in the comparable quarter in 2008. Royalties, which are price sensitive, decreased 12 percent on a per boe basis reflecting the significantly lower natural gas prices. The fourth quarter 2009 operating netback after financial derivative instruments decreased by 20 percent to $19.70 per boe from $24.54 per boe reflecting the preceding factors as well as the 2009 fourth quarter gain on financial derivative instruments of $0.87 per boe compared to $3.33 per boe in the comparable quarter in 2008.



General and administrative

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

Cash general and administrative $ 5,371 $ 7,472 (28)
Non-cash unit based compensation 2,774 (3,040) -
----------------------------------------------------------------------------
$ 8,145 $ 4,432 84

Cash general and administrative
(per boe) $ 3.48 $ 3.02 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Cash general and administrative expenses for Provident Upstream in the fourth quarter decreased 28 percent to $5.4 million from $7.5 million recorded in the 2008 comparable quarter. On a per boe basis the cash general and administrative expenses recorded in fourth quarter 2009 increased 15 percent to $3.48 from $3.02 in the fourth quarter of 2008. The decrease in total cash general and administrative expense reflects staff reductions and cost cutting measures implemented within the organization. The increase in the per boe amount is attributable to the reduced production that has been impacted by the asset dispositions and production declines that reflect the reduced capital program.

The non-cash unit based compensation was an expense of $2.8 million in the fourth quarter of 2009 contrasts with a $3.0 million decrease in the expense in the fourth quarter of 2008. The 2009 expense and the 2008 reduction were due primarily to changes in Provident Trust unit trading prices at the end of the respective periods. In 2009, the trust unit price was on an upward trend in the fourth quarter compared to a downward trend in the comparable 2008 quarter.



Capital expenditures

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 476 $ 7,055
Drilling and recompletions 8,264 28,763
Facilities and equipment 4,533 10,682
Office and other 150 (4,067)
----------------------------------------------------------------------------
Total additions $ 13,423 $ 42,433
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
West central Alberta $ 1,223 $ 3,383
Southern Alberta 1,821 6,113
Northwest Alberta 3,049 22,561
Dixonville 6,681 7,291
----------------------------------------------------------------------------
$ 12,774 $ 39,348
Other (1) 649 3,085
----------------------------------------------------------------------------
Total additions $ 13,423 $ 42,433
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions $ 56 $ 4,632
Property dispositions (2) $ 84,097 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Southeast Saskatchewan and Southwest Saskatchewan operating
areas that were sold on September 30, 2009 and Lloydminster operating
area that was sold on November 30, 2009.
(2) Property dispositions include cash proceeds on sale of assets as well
as $17.0 million of shares in Emerge Oil & Gas Inc. received on sale of
Lloydminster properties.


In the fourth quarter of 2009, Provident Upstream successfully executed its capital program by spending $12.8 million on its four operating areas. In Dixonville, the waterflood enhanced oil recovery program is proceeding as planned with fourth quarter spending of $6.7 million on facility expansion and upgrade activities related to the conversion of the crude oil producing wells into water injectors. In Northwest Alberta, $3.1 million was primarily spent on equipment and facility work associated with the start up of the 2009/2010 winter drilling program, directed towards the emerging Pekisko opportunity. The $3.0 million of capital spent in the Southern and West Central Alberta included 1.3 net wells drilled and ongoing completion, tie-ins, recompletions, facility upgrades and production optimization activities. In addition $0.6 million was spent on other non-core operating areas and corporate assets.



Depletion, depreciation and accretion (DD&A)

Provident Upstream Three months ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

DD&A $ 51,604 $ 76,527 (33)
DD&A (per boe) $ 33.45 $ 30.98 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------


DD&A charges in the fourth quarter of 2009 were down 33 percent to $51.6 million compared to $76.5 million in the fourth quarter of 2008. The lower charges reflect a 38 percent decrease in production volumes in the fourth quarter of 2009 compared to the fourth quarter of 2008. This was partially offset by an eight percent increase in the per boe rate of $33.45 per boe for the fourth quarter of 2009 compared to $30.98 per boe for the fourth quarter of 2008. The per boe increase was primarily a result of 2008 and 2009 capital expenditures on longer term projects at Dixonville and the Pekisko play in Northwest Alberta. In the short term, these expenditures add costs to the depletable base without the addition of further proved reserves. The addition of more proved reserves associated with these projects would have a favorable impact on DD&A per boe.

Accretion expense associated with asset retirement obligations was $0.8 million in the fourth quarter of 2009 compared to $0.9 million in the fourth quarter of 2008.

Provident Midstream business segment review

The Midstream business

The Midstream business unit extracts, processes, stores, transports and markets natural gas liquids (NGL) for Provident and offers these services to third party customers.

The Provident Midstream segment contains three business lines:

Empress East

Redwater West

Commercial Services

Market environment

Performance of the Midstream business unit is closely tied to market prices for NGL products and natural gas, which can vary significantly from period to period. The key reference prices impacting Midstream operating margins are summarized in the following table:



Midstream business reference prices Three months ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------

WTI (US$ per barrel) $ 76.19 $ 58.73 30
Exchange rate (from US$ to Cdn$) 1.06 1.21 (12)
WTI expressed in Cdn$ per barrel $ 80.48 $ 71.21 13

AECO monthly index (Cdn$ per gj) $ 4.01 $ 6.43 (38)

Frac Spread Ratio (1) 20.1 11.1 81

Mont Belvieu Propane (US$ per
US gallon) $ 1.09 $ 0.80 36
Mont Belvieu Propane expressed
as a percentage of WTI 60% 57% 5

Market Frac Spread in Cdn$ per
barrel (2) $ 37.51 $ 16.34 130
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Frac spread ratio is the ratio of WTI expressed in Canadian dollars per
barrel to the AECO monthly index (Cdn$ per gj).
(2) Market frac spread is determined using weighted average spot prices at
Mont Belvieu for propane, butane, and condensate and the AECO monthly
index price for natural gas.


The NGL pricing environment has improved in recent months, and is significantly stronger than in the fourth quarter of 2008. The average fourth quarter 2009 WTI crude oil price of US$76.19 per barrel strengthened by approximately 12 percent relative to the third quarter of 2009. In contrast, as a result of the weakening economy, during 2008 the WTI price fell by 50 percent to US$58.73 per barrel from the third to fourth quarter. As oil prices are highly correlated with NGL product prices, a rapid decline in the WTI price can have significant impact on margins as NGL product inventories which are built in a stronger pricing environment are then sold into a lower priced market. Conversely, a period of increasing WTI prices can have a positive effect on margins. Propane prices as a percentage of WTI crude have also improved over the last several months, increasing from lows of under 50 percent during the 2009 summer months to an average of 60 percent in the fourth quarter of 2009. Propane prices as a percentage of WTI are also stronger relative the prior year quarter which averaged 57 percent. As a result of higher crude oil prices and higher propane prices relative to WTI, the 2009 fourth quarter Mont Belvieu propane price averaged US$1.09 per US gallon, a 36 percent increase over the fourth quarter of 2008. The stronger propane percentages relative to WTI experienced in the fourth quarter of 2009 have continued into the first quarter of 2010 with Mont Belvieu propane trading at an average of 71 percent of WTI during the months of January and February.

Natural gas prices also strengthened over the fourth quarter of 2009, however prices were still significantly lower than in the prior year. AECO natural gas averaged $4.01 per gj in the fourth quarter of 2009 compared to $6.43 per gj during the fourth quarter of 2008. While lower natural gas prices are generally favorable to NGL extraction and fractionation economics, a sustained period in a low price environment could have an impact on the availability and overall cost of natural gas and NGL mix supply in western Canada, if natural gas producers elect to shut-in production or reduce drilling activities.

Market frac spreads increased to an average of $37.51 per barrel during the fourth quarter of 2009. Market frac spreads were also significantly higher than the prior year quarter where a sharp decline in NGL product prices and higher relative natural gas prices reduced market frac spreads to $16.34 per barrel. The benefit of these higher market frac spreads to Provident was tempered by the increased cost of purchasing natural gas supply in western Canada, particularly at Empress. Over the past several months Empress extraction premiums have significantly increased as a result of reduced volumes of natural gas flowing past the Empress straddle plants. In the fourth quarter of 2009, natural gas throughput at the Empress Eastern border averaged approximately 4.4 bcf per day, a decrease of approximately 27 percent compared to the same period in 2008. While extraction premiums have been excluded from the calculation of market frac spreads, they are included, along with other costs, when determining actual extraction operating margins. Lower natural gas throughput at the Empress facilities reduced propane-plus inventories currently available for sale in Sarnia and in surrounding eastern markets. In 2010, as available propane-plus supply tightens relative to demand, pricing differentials in these eastern markets where Provident sells the majority of its Empress East production, may increase relative to other major propane hubs including Mont Belvieu and Conway.

At the end of 2009, industry propane inventories in the United States were approximately 49 million barrels, a decrease of 11 percent compared to the prior year, and approximately seven million barrels below the five year historical average. United States propane inventories have fallen significantly from a high of approximately 75 million barrels at the end of September 2009 when inventories exceeded the five year historical average by approximately 10 million barrels, driven by above average propane withdrawals during the fourth quarter of 2009 which represent the first months of the winter heating season. Ending 2009 Canadian industry propane inventories of approximately five million barrels were in-line with the prior year, but lower than the five year average of approximately six million barrels.



Midstream business performance

Midstream business unit results can be summarized as follows:

Three months ended December 31,
----------------------------------------------------------------------------
(bpd) 2009 2008 % Change
----------------------------------------------------------------------------

Provident Midstream NGL sales
volumes 111,912 120,222 (7)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Three months ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Empress East margin $ 32,522 $ 900 3,514
Redwater West margin 45,518 4,142 999
Commercial Services margin 18,596 12,095 54
----------------------------------------------------------------------------
Gross operating margin 96,636 17,137 464
Realized (loss) gain on
financial derivative
instruments (28,244) 16,098 -
Cash general and administrative
expenses (6,229) (7,380) (16)
Strategic review and
restructuring expenses (217) (1,038) (79)
Foreign exchange (loss) gain
and other (1,091) 12,849 -
----------------------------------------------------------------------------
Provident Midstream Adjusted
EBITDA $ 60,855 $ 37,666 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

Midstream gross operating margin during the fourth quarter of 2009 was very strong, totaling $96.6 million, an increase of $79.5 million compared to the same period in 2008. The increase was predominantly due to significantly higher propane-plus per unit margins realized in both the Empress East and Redwater West business lines, partially offset by a seven percent reduction in NGL sales volumes. A higher contribution from the Commercial Services business line has also increased gross operating margin in the fourth quarter of 2009 relative to the prior year.

The Empress East business line:

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in central Canada and the eastern United States. Demand for propane is seasonal and results in inventory that generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year. The margin in this business is determined primarily by the "frac spread", which represents the difference between the selling prices for propane-plus and the input cost of the natural gas required to produce the respective NGL products. The frac spread can change significantly from period to period depending on the relationship between crude oil and natural gas prices (the "frac spread ratio"), absolute commodity prices, and changes in the Canadian to US dollar foreign exchange rate. Traditionally a higher frac spread ratio and higher crude oil prices will result in stronger business line margins. Differentials between propane-plus and crude oil prices, as well as locational price differentials will also impact the frac spread. Natural gas extraction premiums and costs relating to transportation, fractionation, storage and marketing are not included within the frac spread, however these costs are included in the business line operating margin.

Empress East gross operating margin was $32.5 million in the fourth quarter of 2009 compared to $0.9 million in the same quarter of 2008. This $31.6 million increase was primarily due to significantly higher per unit margins, partially offset by lower propane-plus sales volumes. Increased per unit margins were predominantly a result of much higher frac spreads relative to the prior year. In addition, during 2008, the unit cost of product available for sale was much higher, reflecting inventories that were primarily built up in the second and third quarters when the natural gas price averaged $8.81 per gj. These factors were partially offset by an increase in the extraction premiums paid to purchase natural gas in the fourth quarter of 2009. Over the past several months, extraction premiums at Empress have more than doubled as a result of lower eastern gate gas flows through the Empress facilities. Eastern gate gas supply in the fourth quarter of 2009 was impacted by lower natural gas drilling activity in western Canada throughout the year, shut-in natural gas production, and narrower natural gas pricing differentials between AECO and Chicago.

Fourth quarter 2009 propane-plus sales volumes were 22 percent lower than in the fourth quarter of 2008 primarily as a result of lower term sales for propane-plus. Empress East term sales arrangements are typically entered into for the NGL contract year which runs from April 1 to March 31 of the following year. During 2009, due to the expiry of Provident's lease for fractionation capacity at Sarnia on the first of April, it was expected that Empress East propane-plus processing capacity for the NGL contract year would be reduced by 6,000 bpd and term sales commitments were therefore reduced accordingly. In August 2009, Provident was successful in replacing the 6,000 bpd of expired leased fractionation capacity by purchasing approximately 7,400 bpd of additional fractionation capacity at Sarnia. The benefits of this incremental capacity are expected to be realized in the coming months, particularly as new sales arrangements are negotiated for the upcoming NGL contract year. Full realization of the benefits from this incremental capacity at Sarnia could be impacted by the availability and the cost of future supply at Empress.

The Redwater West business line:

The Redwater West business line purchases an NGL mix from various natural gas producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread has a smaller impact on margin than in the Empress East business line. The Redwater facility also has the largest and industry-leading rail-based condensate terminal in western Canada, which serves the heavy oil industry and its need for diluent. Year over year, Provident has considerably increased its condensate market presence at Redwater through marketing, third-party terminalling and, most recently, storage. During the third quarter of 2009, two 500,000 barrel storage caverns were placed into condensate service at Redwater. Income generated from the condensate terminal and caverns which relates to third-party terminalling and storage is included within the Commercial Services business line.

In the fourth quarter of 2009, the operating margin for Redwater West was $45.5 million (2008 - $4.1 million) an increase of $41.4 million. The significant increase in margin was primarily due to a significant increase in propane-plus unit margins. Over the past several months propane-plus selling prices have steadily increased resulting in lower priced inventories being sold into higher priced markets. In contrast, during the last quarter of 2008, propane-plus prices fell sharply resulting in higher priced inventory being sold into a significantly lower priced market. Redwater West propane-plus selling prices in the fourth quarter of 2009 increased by 14 percent relative to the prior year reflecting higher market prices for NGL. Cost of goods sold, on a per unit basis, was three percent lower than the fourth quarter of 2008 reflecting the higher carrying values of propane-plus inventories relative to sales prices in the prior year.

The increase in propane-plus unit margins was partially offset by an eight percent reduction in Redwater West propane-plus sales volumes. Propane-plus volumes in the fourth quarter of 2009 were lower than the fourth quarter of 2008 as a result of lower NGL product supply. In the fourth quarter of 2009, Redwater West was most impacted by declining natural gas production in northwest Alberta and northeastern British Columbia.

The Commercial Services business line:

The Commercial Services business line generates income from fee-for-service contracts to provide fractionation, storage, LPG terminalling, loading and offloading services. Income from pipeline tariffs from Provident's ownership in NGL pipelines is also included in this business line. In the fourth quarter of 2009, the margin for this business line increased by 54 percent to $18.6 million compared to the same period in 2008. The increased margin was mostly due to increased fee based revenues associated with the condensate terminalling facility and incremental storage revenues from the Provident's recently completed condensate storage caverns.

Operations - Midstream NGL sales volumes

Midstream sold 111,912 bpd in the fourth quarter of 2009, down seven percent when compared with 120,222 bpd in the fourth quarter of 2008. The reduction in volumes primarily represents the decrease in propane-plus volumes in both Empress East and Redwater West.

Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items ("adjusted EBITDA") and funds flow from operations

Fourth quarter 2009 adjusted EBITDA increased 62 percent to $60.9 million from $37.7 million in the fourth quarter 2008 reflecting higher operating margins for all three business lines, partially offset by a higher realized loss on financial derivative instruments. The $28.2 million realized loss on financial derivative instruments was driven by natural gas derivative purchase contracts that settled at current market prices that were lower than the original derivative contract prices. The comparable quarter in 2008 had a realized gain on financial derivative instruments of $16.1 million, driven primarily by NGL derivative sales contracts that settled at derivative contract prices that were higher than the market prices during the settlement period. The 2008 adjusted EBITDA amount also included gains on corporate foreign exchange contracts settled in the period, of which $16.2 million was allocated to the Midstream segment and was included in foreign exchange (loss) gain and other. Cash general and administrative expenses were lower in 2009 as a result of staff reductions and cost cutting measures implemented within the organization. Funds flow from operations for the fourth quarter of 2009 was $55.4 million, an increase of $20.8 million or 60 percent compared to $34.6 million in the fourth quarter of 2008. The increase in funds flow from operations reflected the higher adjusted EBITDA and lower interest expense.

Capital expenditures

Midstream capital expenditures for the fourth quarter of 2009 totaled $5.2 million. In the fourth quarter 2009, $3.7 million was spent primarily on the continued development of cavern storage and the condensate terminalling and storage facility. In addition, $1.3 million was spent on sustaining capital requirements, and $0.2 million was spent on office related capital.



2009 Year end results
Funds flow from continuing operations and cash distributions

Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2009 2008 % Change
----------------------------------------------------------------------------
Funds flow from continuing
operations and Distributions
Funds flow from continuing
operations $ 264,006 $ 517,622 (49)
Per weighted average unit from
continuing operations
- basic and diluted (1) $ 1.01 $ 2.03 (50)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Declared distributions $ 196,217 $ 352,291 (44)
Per unit 0.75 $ 1.38 (46)
Percent of funds flow from
continuing operations paid out
as declared distributions 74% 68% 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes dilutive impact of unit options and convertible debentures.


For the year ended December 31, 2009, funds flow from continuing operations decreased $253.6 million or 49 percent to $264.0 million from $517.6 million for 2008. On a per unit basis, funds flow from continuing operations decreased 50 percent in 2009 to $1.01 per unit from $2.03 per unit in 2008.

Provident Upstream contributed funds flow from operations of $102.2 million in 2009, a decrease of 70 percent when compared with $338.7 million from 2008. The decrease was predominantly due to significantly lower realized crude oil, natural gas liquids and natural gas prices combined with strategic asset dispositions resulting in lower volumes produced.

Provident Midstream added $161.8 million to 2009 funds flow from operations, compared with $179.0 million recorded in the year ended December 31, 2008. Midstream funds flow from operations reflects a decrease in adjusted EBITDA of $30.4 million or 14 percent. This decrease was driven by lower Empress East and Redwater West propane-plus sales volumes combined with lower Empress East propane-plus unit margins, reflective of the weaker pricing environment in the earlier part of 2009 compared to a very strong price environment in the earlier part of 2008. Reduced cash interest charges due to lower debt levels partially offset the reduction in adjusted EBITDA.

Declared distributions in 2009 totaled $196.2 million, 74 percent of funds flow from continuing operations. This compares to $352.3 million of declared distributions in 2008, 68 percent of funds flow from continuing operations. In previous years, Provident has paid out between 67 percent and 102 percent of its annual funds flow from continuing operations as distributions to unitholders.

Outlook

The following outlook contains forward-looking information regarding possible events, conditions or results of operations in respect of the Trust that is based on assumptions about future economic conditions and courses of action. There are a number of risks and uncertainties which could cause actual events or results to differ materially from those anticipated by the Trust and described in the forward-looking information. See "Forward-looking information" in this MD&A for additional information regarding assumptions and risks in respect of the Trust's forward-looking information.

Provident actively monitors commodity prices and overall market conditions on an ongoing basis and will continue to utilize available cash flow and manage capital resources to achieve a prudent balance between capital expenditures, distributions and long term debt.

Provident Midstream has a capital budget of approximately $86 million for 2010, an increase of 135 percent compared to the 2009 capital program. The Trust plans to allocate approximately $17 million of this budget towards the expansion and construction of rail and truck terminalling infrastructure at the Corunna storage facility near Sarnia, upon completion of the acquisition. Provident anticipates that these upgrades will enhance operating flexibility and commercial opportunities at Sarnia. At Redwater, Provident will direct approximately $15 million towards advancing a 500,000 barrel condensate cavern that will be commissioned in early 2011, begin work on a second cavern of equal size slated for completion in 2012 and construct a brine pond to facilitate future cavern operations. Also at Redwater, approximately $18 million will be allocated to a debottlenecking initiative to increase overall propane-plus fractionation capacity by 8,000 bpd. Provident also plans to undertake a $4 million flare stack recovery initiative to capture and consume certain byproduct gases, increasing efficiency and reducing emissions. Provident also plans to direct approximately $3 million to construct a 12-truck offloading facility to add an additional option for receiving NGL supply at the Provident Empress Plant. The remainder of the Midstream 2010 capital budget will be used for additional expansion opportunities, facility optimization initiatives and normal course facility maintenance at Redwater, Empress and Sarnia.

Key drivers influencing the Midstream business include access to and cost of NGL mix and natural gas feedstock, power and fuel costs, and the demand for finished products including ethane, propane, butane and condensate. In 2010, as available propane-plus supply tightens relative to demand, pricing differentials in Eastern markets where Provident sells the majority of its Empress East production, may increase relative to other major propane hubs including Mont Belvieu and Conway.

Provident's Upstream Business unit has a capital budget for 2010 of $52 million and plans to drill, recomplete or workover approximately 53 net oil and natural gas wells. Key initiatives in 2010 include approximately $6 million allocated towards the continuing development of the prospective Pekisko oil opportunity in Northwest Alberta where Provident is utilizing horizontal wells and multi-stage fracs. In 2010, the Trust is drilling two gross Pekisko wells with the participation of a 50 percent joint venture partner, as well as optimizing Provident's existing Pekisko wells. Additionally, approximately $12 million will be directed towards the drilling, workover and recompletion of up to 27 net wells targeting oil and natural gas in the Northwest Alberta core area. Provident plans to allocate $16 million to the Peace River Arch / Dixonville core area, with approximately $7 million directed towards implementing the second phase of the water flood for enhanced recovery of Montney "C" crude oil at Dixonville, where Provident will drill two net wells, convert an existing well to a water injector and install four liners. Incremental production is expected to be added gradually as the reservoir responds to the water flood over the next 18 months. Provident will also drill an additional three net oil wells in the Peace River Arch area. Approximately $17 million of the capital budget will be directed toward drilling and optimization activities in the Southern Alberta core area where Provident plans to participate in the drilling, workover or recompletion of approximately 17 net oil and natural gas wells. The reminder of the 2010 capital budget will be allocated to other minor initiatives.

Oil and natural gas production in 2010 is expected to average between 9,500 and 10,500 boed and will be weighted approximately 65 percent natural gas and 35 percent crude oil and liquids. The third-party pipeline operator has indicated to Provident that the previously announced pipeline disruption in Northwest Alberta should be resolved prior to the end of the first quarter. Intermittent volume curtailments are expected while the operator completes the remaining remediation work on the pipeline.



Distributions

The following table summarizes distributions paid as declared by the Trust
since inception:

Distribution Amount
Record Date Payment Date (Cdn$) (US$)(i)
----------------------------------------------------------------------------
2009
January 23, 2009 February 13, 2009 $ 0.09 0.07
February 23, 2009 March 13, 2009 0.06 0.05
March 24, 2009 April 15, 2009 0.06 0.05
April 22, 2009 May 15, 2009 0.06 0.05
May 21, 2009 June 15, 2009 0.06 0.05
June 22, 2009 July 15, 2009 0.06 0.05
July 22, 2009 August 14, 2009 0.06 0.05
August 24, 2009 September 15, 2009 0.06 0.06
September 22, 2009 October 15, 2009 0.06 0.06
October 22, 2009 November 13, 2009 0.06 0.06
November 24, 2009 December 15, 2009 0.06 0.06
December 22, 2009 January 15, 2010 0.06 0.06
----------------------------------------------------------------------------
2009 Cash Distributions paid as
declared $ 0.75 0.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2008 Cash Distributions paid as
declared 1.38 1.29
2007 Cash Distributions paid as
declared 1.44 1.35
2006 Cash Distributions paid as
declared 1.44 1.26
2005 Cash Distributions paid as
declared 1.44 1.20
2004 Cash Distributions paid as
declared 1.44 1.10
2003 Cash Distributions paid as
declared 2.06 1.47
2002 Cash Distributions paid as
declared 2.03 1.29
2001 Cash Distributions paid as
declared
- March 2001 - December 2001 2.54 1.64
----------------------------------------------------------------------------
Inception to December 31, 2009 -
Distributions paid as declared $ 14.52 11.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Exchange rate based on the Bank of Canada noon rate on the payment date.



For Canadian tax purposes, both 2009 and 2008 distributions were determined to be 100 percent taxable with no tax deferred return of capital in the hands of Canadian unitholders. Distributions received by U.S. resident unitholders in 2009 and 2008 were considered to be 100 percent qualified dividends with no tax deferred return of capital. In both Canada and the U.S., any tax-deferred portion would usually be treated as an adjustment to the cost base of the units. Unitholders or potential unitholders should consult their own legal or tax advisors as to their particular income tax consequences of holding Provident units.




Net (loss) income

Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per unit data) 2009 2008 % Change
----------------------------------------------------------------------------

Net (loss) income $ (89,020) $ 157,392 -
Per weighted average unit
- basic (1) and diluted (2) $ (0.34) $ 0.62 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Based on weighted average number of trust units outstanding.
(2) Based on weighted average number of trust units outstanding including
the dilutive impact of the unit option plan and convertible debentures.


Consolidated Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Provident Upstream net loss $ (110,567) $ (306,050) (64)
Provident Midstream net income 21,547 317,418 (93)
----------------------------------------------------------------------------
Net (loss) income from
continuing operations $ (89,020) $ 11,368 -
Net income from discontinued
operations (USOGP) - 146,024 (100)
----------------------------------------------------------------------------
Consolidated net (loss) income $ (89,020) $ 157,392 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Provident Upstream business segment's net loss in 2009 was $110.6 million, a $195.5 million improvement compared with year ended December 31, 2008 net loss of $306.0 million. The 2008 results included a $416.9 million non-cash goodwill impairment charge. Also contributing to the year over year change was the $244.5 million decrease in adjusted EBITDA, driven by a significantly lower price environment in 2009 and lower volumes as a result of strategic asset dispositions.

The Provident Midstream segment recorded net income of $21.5 million as compared to net income of $317.4 million in the year ended December 31, 2008. In 2009, Provident Midstream reported a $30.4 million, or a 14 percent decrease in adjusted EBITDA compared to 2008. Further contributing to the decrease in net income was a change in unrealized (loss) gain on financial derivative instruments from a gain in 2008 of $191.2 million to a loss in 2009 of $111.6 million. Under Canadian generally accepted accounting principles (Canadian GAAP), there is a requirement to "mark-to-market" all financial derivative instruments at a point in time and report these unrealized gains or losses as part of current period income. Because Provident's commodity price risk management program involves the use of financial derivative instruments with terms that currently extend over three years into the future in the Midstream segment, net earnings can show substantial variation that is not necessarily related to current operations. These factors were partially offset by future income tax recoveries in 2009 of $35.4 million compared to future income tax expense in 2008 of $20.6 million along with lower interest expense due to reduced interest rates and debt levels.

Net income from discontinued operations (USOGP) in 2008 was $146.0 million. The operations were sold in 2008.

Reconciliation of non-GAAP measures

The Trust calculates earnings before interest, taxes, depletion, depreciation, accretion and other non-cash items (adjusted EBITDA) within its segment disclosure. Adjusted EBITDA is a non-GAAP measure. A reconciliation between adjusted EBITDA and loss from continuing operations before taxes follows:



Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Loss from continuing operations
before taxes $ (193,564) $ (19,817) 877
Adjusted for:
Cash interest 26,989 50,793 (47)
Unrealized loss (gain) on
financial derivative
instruments 129,861 (221,468) -
Goodwill impairment - 416,890 -
Depletion, depreciation and
accretion and other non-cash
expenses 328,024 339,856 (3)
----------------------------------------------------------------------------
Adjusted EBITDA $ 291,310 $ 566,254 (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table reconciles funds flow from continuing operations with
cash provided by operating activities:

Reconciliation of funds flow
from continuing operations Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Cash provided by operating
activities $ 304,248 $ 674,426 (55)
Change in non-cash operating
working capital from
continuing operations (45,641) (52,684) (13)
Site restoration expenditures 5,399 6,381 (15)
Cash provided by operating
activities from discontinued
operations - (110,501) -
----------------------------------------------------------------------------
Funds flow from continuing
operations 264,006 517,622 (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Taxes

Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Capital tax expense $ 2,313 $ 3,109 (26)
Current tax expense (recovery) 237 (4,529) -
Future income tax recovery (107,094) (29,765) 260
----------------------------------------------------------------------------
$ (104,544) $ (31,185) 235
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital taxes in 2009 totaled $2.3 million, a decrease from the $3.1 million expense recorded in 2008. The decrease reflects the sale of Southeast Saskatchewan, Southwest Saskatchewan and Lloydminster operating areas in the latter half of 2009, which were the drivers behind the capital tax expense.

The current tax expense of $0.2 million in 2009 compared to a recovery of $4.5 million in 2008. The 2009 expense was driven by earnings in Provident's Canadian Midstream business in excess of allowed tax pool claims. The recoveries in 2008 were driven by lower earnings subject to tax in the U.S. Midstream operations allowing the recovery of taxes paid in prior periods.

For the year ended December 31, 2009, the future income tax recovery was $107.1 million, compared with a recovery of $29.8 million in 2008. In both 2009 and 2008, future income tax recoveries were recorded as a result of losses created by interest and royalty deductions at the incorporated subsidiary level. However in 2009, further adding to recoveries were unrealized losses on financial derivative instruments compared to future tax expense in 2008 relating to the unrealized gains on financial derivative instruments. In 2008, additional future income tax recoveries were recorded as a result of an internal structural reorganization. The goodwill impairment charge in 2008 had no impact on future income taxes.

The Trust has estimated its future income taxes based on estimates of results of operations and tax pool claims and cash distributions in the future. The Trust's estimate of its future income taxes will vary as these underlying estimates change and such variations may be material.

In June 2007, the Department of Finance (Canada) enacted legislation, effective for 2011, respecting the taxation of certain "specified investment flow-through" ("SIFT") trusts, including Provident, and SIFT partnerships (the "SIFT Tax"). Subsequent to 2010, to the extent the Trust receives taxable income the SIFT Tax would be payable by the Trust prior to paying its distributions. These distributions would generally be considered taxable dividends to unitholders with Canadian unitholders able to claim the dividend tax credit for units held in taxable accounts effectively lowering the personal tax rate on distributions received. Canadian investors who hold Trust units in a tax deferred account will not be able to claim the dividend tax credit. Distributions that are determined to be a return of capital would not be subject to the SIFT tax at the Trust and would continue to reduce the Canadian unitholders adjusted cost base. Distributions to U.S. residents after 2010 will be subject to Canadian withholding tax, consistent with the current treatment of Trust distributions while the current classification as qualified dividends or return of capital will be dependent on U.S. tax legislation.

In March 2009, legislation was enacted that amended the Income Tax Act including technical amendments to clarify certain aspects of the SIFT Tax and to provide rules to facilitate the conversion of existing SIFT trusts into corporations on a tax-deferred basis. A corporate conversion would be achieved through a Plan of Arrangement which must be approved by the Trust's Board of Directors and voted on by unitholders at a special meeting. Subsequent to a conversion to a corporation, Canadian shareholders would receive taxable dividends eligible for the dividend tax credit. The tax impact of the dividends may be different for shareholders depending on their jurisdiction and whether they are holding their investment in a taxable account or tax-deferred account. Dividends received by U.S. residents after 2010 could be treated as qualified dividends or return of capital, depending on U.S. tax legislation, while the Canadian withholding tax will be consistent with the current treatment for trust distributions. The Board of Directors and management continue to evaluate options, including a possible conversion to a corporation, to best position Provident beyond 2010 when the Trust will become subject to SIFT Tax.

At December 31, 2009 the Trust has approximately $1.2 billion of intangible, tangible and non-capital loss tax pools available to claim against taxable income under either a trust or corporate structure.



Interest expense

Continuing operations Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except as noted) 2009 2008 % Change
----------------------------------------------------------------------------

Interest on bank debt $ 9,634 $ 35,044 (73)
Interest on convertible
debentures 17,355 19,934 (13)
Discontinued operations portion - (4,185) (100)
----------------------------------------------------------------------------
Total cash interest $ 26,989 $ 50,793 (47)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average interest rate
on all long-term debt 3.6% 5.3% (32)

Debenture accretion and other
non-cash interest expense 4,828 5,239 (8)
----------------------------------------------------------------------------
Total interest expense $ 31,817 $ 56,032 (43)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense decreased in 2009 compared to 2008 due to lower debt levels and lower market interest rates. Cash proceeds from 2009 Upstream dispositions totaling $305.7 million as well as the sale of USOGP in 2008, amounting to $457.9 million, net of tax, were used to pay down debt.

Financial instruments

Commodity price risk management program

Provident's commodity price risk management program utilizes derivative instruments to provide protection against lower commodity prices and margins. The program reduces exposure to downside commodity price volatility and provides support for cash distributions, bank lending capacity, capital programs and acquisition and project economics. The program protects a percentage of Provident's oil and natural gas production against a decline in commodity prices while, with some products, allowing the Trust to participate in a rising commodity price environment. For the Midstream business unit the program provides price stabilization and protection of a percentage of inventory values and fractionation spread margin. The Program also reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars, interest rate risk and fixes a portion of Provident's input costs.

The commodity price derivative instruments the Trust uses include put and call options, costless collars, participating swaps, and fixed price products that settle against indexed referenced pricing.

Provident's credit policy governs the activities undertaken to mitigate non-performance risk by counterparties to financial derivative instruments. Activities undertaken include regular monitoring of counterparty exposure to approved credit limits, financial reviews of all active counterparties, utilizing International Swap Dealers Association (ISDA) agreements and obtaining financial assurances where warranted. In addition, Provident has a diversified base of available counterparties.

In the Midstream business, production margins are affected by the spread between the purchase cost of natural gas and sales price of propane, butane and condensate. Market conditions have not provided sufficient or adequate opportunity to directly manage propane, butane and condensate prices over the longer term. Prices for propane, butane and condensate historically have correlated with prices for crude oil. As a consequence, Provident has entered into natural gas, crude oil and foreign exchange financial derivative contracts through March 2013 in order to protect operating margins in the Midstream business. Short term financial derivative instruments directly fixing propane, butane, natural gasoline and electricity prices have also been executed.

Settlement of financial derivative contracts

The following table summarizes the impact of the financial derivative contracts settled during the years ended December 31, 2009 and 2008, included in realized loss on financial derivative instruments.




Realized gain (loss) on financial Year ended December 31,
derivative instruments 2009 2008
----------------------------------------------------------------------------
($ 000s except volumes) Volume (1) Volume (1)
----------------------------------------------------------------------------

Provident Upstream
Crude Oil $ 8,052 0.8 $ (11,113) 1.6
Natural gas 8,336 6.1 11 10.9

Provident Midstream
Crude Oil 29,007 4.1 (135,602) 4.2
Natural gas (95,188) 23.0 (16,978) 26.8
NGL's (includes propane, butane) 5,072 0.8 25,902 2.3
Foreign Exchange (3,505) - 5,387 -
Electricity (1,276) - 2,374 -

Corporate
Interest Rate (2) (1,137) - - -
----------------------------------------------------------------------------
Realized loss on financial
derivative instruments $(50,639) $(130,019) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents aggregate net volumes that were bought/sold
over the periods. Crude oil and NGL volumes are listed in millions of
barrels and natural gas is listed in millions of gigajoules.
(2) Realized gains and losses on corporate related interest rate contracts
are allocated to the reporting segments for segmented reporting
purposes.


The realized loss for the year ended December 31, 2009 was $50.6 million compared to a realized loss of $130.0 million in 2008. The realized loss in 2009 was driven by natural gas purchase derivative contracts in the midstream business settling at a contracted price higher than the current market natural gas prices, partially offset by crude oil derivative sales contracts in both business units settling at contracted crude oil prices higher than the crude oil market prices during the settlement period. The comparable 2008 realized loss was driven mostly by crude oil derivative sales contracts in the midstream business settling at contracted crude oil prices lower than the crude oil market prices during the settlement period.

In addition, the Trust recorded a loss of $0.2 million (2008 - $26.8 million gain) on corporate foreign exchange contracts. The amounts were included in foreign exchange loss (gain) and other on the consolidated statement of operations and were allocated to the reporting segments.



The following table is a summary of the net financial derivative instruments
liability:

As at December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008
----------------------------------------------------------------------------
Provident Upstream
Crude Oil $ 826 $ (12,521)
Natural Gas 1,545 (3,285)
Provident Midstream 181,890 70,476
Corporate 269 -
----------------------------------------------------------------------------
Total $ 184,530 $ 54,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The net liability in both periods represents unrealized "mark-to-market" opportunity costs related to financial derivative instruments with contract settlements ranging from January 1, 2010 through March 31, 2013. The balances are required to be recognized in the financial statements under generally accepted accounting principles. These financial derivative instruments were entered into in order to manage commodity prices and protect future Midstream product margins. Fluctuations in the market value of these instruments impact earnings prior to their settlement dates but have no impact on funds flow from operations until the instrument is actually settled.

Goodwill and intangible assets

Goodwill represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. As at December 31, 2009 and 2008, the goodwill balance of $100.4 million was related entirely to the Provident Midstream reporting unit.

Goodwill is assessed for impairment at least annually, and if an impairment exists, it would be charged to income in the period in which the impairment occurs. The impairment test includes a comparison of the net book value of the Trust's assets, by reporting units, to the estimated fair value of the reporting unit. In 2009, Provident engaged the services of a third-party evaluator to assist in determining fair value. Valuation methodologies included discounted cash flow, a transaction-based approach and a market-based approach, using trading multiples. Goodwill is not amortized.

The Trust performed its annual goodwill impairment test in the fourth quarter of 2009 and determined that no write-down of goodwill was required. In 2008, a goodwill impairment of $416.9 million was recorded in the upstream business unit.

Provident's intangible assets primarily relate to Midstream contracts and customer relationships. In 2009, the Trust recognized an impairment of $12.4 million on a specific Midstream marketing agreement. The Trust had been amortizing the agreement over a 15 year period. The Trust now expects that it is unlikely that the agreement will be renewed beyond March 31, 2011 on the same terms. In addition, during 2009, the volumes supplied to the Trust under this agreement were reduced as a result of certain property dispositions completed by the third party supplier. The impairment reflects a revision of the amortization period of this agreement and lower volume expectations for the remainder of the contract. The impairment was recognized in the statement of operations in depletion, depreciation, and accretion expense. The Trust does not expect the change in this contract to have a significant impact on volumes purchased in the Midstream business.



Liquidity and capital resources

Consolidated
----------------------------------------------------------------------------
December 31, December 31,
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Long-term debt - revolving
term credit facility $ 264,776 $ 504,685 (48)
Long-term debt-convertible
debentures (including current
portion) 240,486 260,994 (8)
Working capital surplus
(excluding financial
derivative instruments) (31,152) (39,041) (20)
----------------------------------------------------------------------------
Net debt $ 474,110 $ 726,638 (35)
----------------------------------------------------------------------------

Unitholders' equity (at
book value) 1,381,399 1,636,347 (16)
----------------------------------------------------------------------------
Total capitalization at
book value $ 1,855,509 $ 2,362,985 (21)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Total net debt as a
percentage of total book
value capitalization 26% 31% (16)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident operates two business units with similar but not identical monthly cash settlement cycles. Midstream revenues are received at various times throughout the month. Provident's working capital position is affected by seasonal fluctuations that reflect commodity price changes, drilling cycles in its oil and gas operations and inventory balances in its Midstream business unit. Provident relies on funds flow from continuing operations, external lines of credit and access to equity markets to fund capital programs and acquisitions.

As a result of the weakening of the global economy in 2008, oil and gas industry participants, including Provident, had been experiencing more restricted access to capital. Recent activity in the capital markets towards the end of 2009 has shown signs of improvement, however increased borrowing costs are still anticipated. Although Provident's core businesses have not changed, risk premiums have increased. Management believes that cash flows from operating activities and availability under existing bank facilities will be adequate to allow Provident to move forward with its budgeted 2010 capital program. However, these issues will affect Provident as it reviews financing alternatives for future capital expenditures and potential acquisition opportunities.

Substantially all of Provident's accounts receivable are due from customers and joint venture partners in the oil and gas and midstream services and marketing industries and are subject to credit risk. Provident partially mitigates associated credit risk by limiting transactions with certain counterparties to limits imposed by Provident based on management's assessment of the creditworthiness of such counterparties. In certain circumstances, Provident will require the counterparties to provide payment prior to delivery, letters of credit and/or parental guarantees. The carrying value of accounts receivable reflects management's assessment of the associated credit risks.



Contractual obligations

Consolidated Payment due by period
----------------------------------------------------------------------------
Less More
than 1 1 to 3 3 to 5 than 5
($ millions) Total year years years years
----------------------------------------------------------------------------
Long-term debt - revolving
term credit facility (1)
(2) $ 270.2 $ 3.7 $ 266.5 $ - $ -
Long-term debt -
convertible debentures (2) 279.2 16.2 263.0 - -
Operating lease obligations 164.0 18.1 30.0 21.7 94.2
----------------------------------------------------------------------------
Total $ 713.4 $ 38.0 $ 559.5 $ 21.7 $ 94.2
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The terms of the Canadian credit facility have a revolving three year
period expiring on May 30, 2011. (2) Includes associated interest and
principal payments.


Long-term debt and working capital

In 2009, Provident's Canadian term credit facility was reduced by $95 million to $1.03 billion due to the asset dispositions in the Upstream business unit. On March 1, 2010, Provident closed the previously announced sale of West Central Alberta oil and natural gas assets. As a result of this sale, Provident's Canadian term credit facility was reduced by an additional $50 million to $980 million.

As at December 31, 2009 Provident had drawn on 26 percent of its term credit facility as compared to 45 percent drawn as at December 31, 2008. The decrease in the level of bank debt was a result of the application of proceeds from the Upstream strategic property dispositions.

At December 31, 2009 Provident had letters of credit guaranteeing Provident's performance under certain commercial and other contracts that totaled $27.2 million, increasing bank line utilization to 28 percent. The guarantees at December 31, 2008 totaled $35.2 million.



The following table shows the change in Provident's working capital
position:

As at December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 Change
----------------------------------------------------------------------------
Current Assets
Cash and cash equivalents $ 7,187 $ 4,629 $ 2,558
Accounts receivable 216,786 244,485 (27,699)
Petroleum product inventory 37,261 46,160 (8,899)
Prepaid expenses and other current
assets 4,803 7,886 (3,083)
Financial derivative instruments 5,314 16,708 (11,394)

Current Liabilities
Accounts payable and accrued
liabilities 221,417 244,031 22,614
Cash distribution payable 13,468 20,088 6,620
Current portion of convertible
debentures - 24,871 24,871
Financial derivative instruments 86,441 13,693 (72,748)
----------------------------------------------------------------------------
Working capital (deficit) surplus $ (49,975) $ 17,185 $ (67,160)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The ratio of net debt (as calculated under "Liquidity and capital resources") to funds flow from continuing operations in 2009 was 1.8 to one, compared to 1.4 to one in 2008. The increase reflects a decrease in net debt offset by lower funds flow from operations. On a segmented basis, using allocated debt balances as disclosed in note 20 to the consolidated financial statements, the Provident Upstream business had a ratio of net debt to funds flow from operations in 2009 of 1.6 to one (2008 - 0.7 to one). The ratio for the Provident Midstream business unit was 2.0 to one in 2009, compared to 2.7 to one in 2008.

Trust units

For the year ended December 31, 2009 the Trust issued no additional units on conversion of convertible debentures (2008 - six thousand units). No additional units were issued pursuant to the expired unit option plan for the year ended December 31, 2009 (2008 - 0.2 million units). Under Provident's Premium Distribution, Distribution Reinvestment (DRIP) and Optional Unit Purchase Plan program 5.2 million units were issued or are to be issued in 2009 representing proceeds of $28.1 million (2008 - 6.3 million units for proceeds of $53.8 million).

At December 31, 2009 management and directors held less than one percent of the outstanding trust units.



Capital related expenditures and funding

Continuing operations Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Capital related expenditures
Capital expenditures $ (127,369) $ (246,947) (48)
Site restoration expenditures (5,399) (6,381) (15)
Acquisitions (18,833) (25,843)
----------------------------------------------------------------------------
Net capital related expenditures $ (151,601) $ (279,171) (46)
----------------------------------------------------------------------------

Funded by
Funds flow from continuing
operations net of declared
distributions to unitholders $ 67,789 $ 165,331 (59)
Cash proceeds on sale of assets 305,720 1,662
Proceeds on sale of discontinued
operations, net of tax - 457,906
Decrease in long-term debt (265,245) (440,244) (40)
Issue of trust units, net of cost;
excluding DRIP - 1,672 -
DRIP proceeds 28,106 53,838 (48)
Change in working capital,
including cash, and change
in investments 15,231 39,006 (61)
----------------------------------------------------------------------------
Net capital related expenditure
funding $ 151,601 $ 279,171 (46)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident has funded its net capital expenditures with cash flow from operations and long-term debt. Proceeds on sale of assets were applied to Provident's revolving term credit facility.

Strategic review and restructuring expenses

The strategic review process was announced in February of 2008 with the objectives of optimizing business performance, facilitating business growth, improving overall access to and cost of capital, enhancing the valuation of Provident's component businesses and optimizing structure in response to the federal government decision to tax income trusts beginning in 2011. During this review, it was determined that the sale of the United States oil and natural gas production (USOGP) business was an important step in the process. Following the sale of USOGP, management and the board of directors evaluated the complete spectrum of strategic options available for Provident's remaining Canadian oil and gas production (Provident Upstream) and midstream (Provident Midstream) business units. After an extensive review, it was determined that in early 2009, in the context of the macroeconomic environment (characterized by low commodity prices and volatility in both equity and debt markets at that time), it was in the best interest of unitholders that Provident remain structured as a cash-distributing, diversified energy enterprise. Provident also completed an internal reorganization to improve the efficiency and competitiveness of the businesses. The internal reorganization was designed to improve the focus of each business unit, improve management's line of sight to the key performance measures in each business, and reduce general and administrative costs.

As the macroeconomic environment evolved throughout 2009, Provident determined it was appropriate to sell certain non-strategic Upstream producing oil and natural gas assets. In the third and fourth quarters of 2009, Provident sold $322.7 million of Upstream assets and in March of 2010, closed the sale of its West Central Alberta operating area for $177 million. The Board of Directors and management continue to evaluate options that will best position Provident beyond 2010 when the Trust distributions will become subject to tax. The reorganization and 2009 divestitures resulted in staff reductions at all levels of the organization, including senior management. For the year ended December 31, 2009, strategic review and restructuring costs were $12.3 million (2008 - $3.6 million). The costs are comprised primarily of severance, consulting and legal costs.

Unit based compensation

Unit based compensation includes expenses or recoveries associated with Provident's restricted and performance unit plan. Unit based compensation is recorded at the estimated fair value of the notional units granted. Compensation expense associated with the plans is recognized in earnings over the vesting period of each plan. The expense or recovery associated with each period is recorded as non-cash unit based compensation (a component of general and administrative expense). A portion relating to operational employees at field and plant locations is also allocated to operating expense. For the year ended December 31, 2009, Provident recorded unit based compensation expense of $18.4 million (2008 - $4.4 million) and made related cash payments of $11.5 million (2008 - $8.3 million), of which $3.3 is included in strategic review and restructuring expense. The expense was higher in 2009 as a result of a higher Provident trust unit trading price, upon which the compensation is based. At December 31, 2009, the current portion of the liability totaled $12.2 million (December 31, 2008 - $9.4 million) and the long-term portion totaled $12.5 million (December 31, 2008 - $8.6 million).

Provident Upstream segment review

Upstream asset dispositions

On September 30, 2009, Provident completed a sale of the operating areas of Southeast and Southwest Saskatchewan for net proceeds of $225.7 million and a separate sale of a minor property in the Lloydminster area for $12.8 million. Production on the date of announcement for these operating areas totaled approximately 4,000 boed.

On November 30, 2009, Provident closed the sale of the remaining properties in the Lloydminster operating area to a private company, Emerge Oil & Gas Inc. for total consideration of $84.0 million, consisting of $67.0 million in cash and $17.0 million in equity of the acquirer. Production on the date of announcement for these properties totaled approximately 2,200 boed.

Net proceeds from these dispositions have been applied to Provident's revolving term credit facility.

On December 23, 2009, Provident announced that it had reached an agreement with Storm Ventures International Inc. to sell the oil and natural gas assets in the West Central Alberta operating area. Production on the date of announcement for these properties totaled approximately 5,000 boed. The transaction closed on March 1, 2010. Proceeds from the transaction of $177 million were applied to Provident's revolving term credit facility.



Crude oil and natural gas liquids prices

The following realized prices are net of transportation expense.

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ per bbl) 2009 2008 % Change
----------------------------------------------------------------------------

Oil per barrel
WTI (US$) $ 61.80 $ 99.65 (38)
Exchange rate (from US$ to Cdn$) 1.14 1.07 7
WTI expressed in Cdn$ $ 70.54 $ 106.33 (34)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Realized pricing before financial
derivative instruments
Crude oil $ 54.15 $ 82.79 (35)
Natural gas liquids $ 44.40 $ 76.88 (42)
----------------------------------------------------------------------------
Crude oil and natural gas liquids $ 53.05 $ 82.27 (36)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2009 Provident's realized crude oil and natural gas liquids price, prior to the impact of financial derivative instruments, decreased by 36 percent to average $53.05 compared to $82.27 in 2008. The 2009 decrease related to a 38 percent decrease in US$ WTI crude oil price, partially offset by an increase in U.S. to Canadian dollar exchange rate.



Natural gas price

The following prices are net of transportation expense.

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
(Cdn$ per mcf) 2009 2008 % Change
----------------------------------------------------------------------------

AECO monthly index $ 4.14 $ 8.12 (49)
Corporate natural gas price per mcf
before financial
derivative instruments $ 3.86 $ 8.23 (53)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2009 Provident's realized natural gas price, excluding financial derivative instruments, decreased 53 percent as compared to 2008, comparable to the decrease in the benchmark AECO monthly index price. Provident's gas portfolio includes aggregator contracts sold on a term basis that can differ from the benchmark price and sells to the spot market on monthly or daily indices and receives prices which take into account heat content. Provident's realized prices and changes in prices can therefore differ from benchmark indices.



Production

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------
Daily production
Crude oil (bpd) 8,875 12,473 (29)
Natural gas liquids (bpd) 1,121 1,203 (7)
Natural gas (mcfd) 69,575 84,039 (17)
----------------------------------------------------------------------------
Oil equivalent (boed) (1) 21,592 27,683 (22)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.


For the year ended December 31, 2009, Provident Upstream production averaged 21,592 boed, a 22 percent decrease compared to 27,683 boed in 2008. Production levels for 2009 were lower as a result of strategic upstream asset dispositions. Production from the properties sold averaged 4,953 boed in 2009 compared to 8,075 boed in 2008. Further contributing to the decrease in daily production were natural declines that were larger than the production additions from capital expenditures. The lower commodity price environment resulted in reduced capital spending compared to 2008, as well, the nature of the 2009 capital expenditures was focused on longer term plays. The majority of the capital spent in 2009 was spent on Northwest Alberta facilities and pipelines for the emerging Pekisko resource play and on Dixonville's waterflood program. These longer term plays do not result in immediate production gains but are key to position Provident Upstream for future growth.

In Dixonville, 21 crude oil wells were converted to water injectors in 2009 as part of the phase one expansion. Production from these wells in 2008 was approximately 500 bpd. The approval for the phase two expansion was received in January 2010 and an application for phase three was submitted in February 2010. Production growth in Dixonville is expected to increase as the waterflood matures with incremental production expected gradually over the next 18 months.

Production for 2009 was weighted 54 percent natural gas and 46 percent crude oil and natural gas liquids. This compared to 2008 production weighted 51 percent natural gas and 49 percent crude oil and natural gas liquids. Year end 2009 exit-rate production was approximately 15,200 boed, including approximately 5,100 boed related to the West Central Alberta operating area which was subsequently sold on March 1, 2010.



Provident Upstream production summarized by operating areas is as follows:

Year ended December 31,
----------------------------------------------------------------------------
Provident Upstream 2009 2008 % Change
----------------------------------------------------------------------------
Daily Production - by area (boed) (1)
West Central Alberta 5,401 6,271 (14)
Southern Alberta 4,629 4,883 (5)
Northwest Alberta 3,771 4,690 (20)
Dixonville 2,838 3,764 (25)
----------------------------------------------------------------------------
16,639 19,608 (15)
Other (2) 4,953 8,075 (39)
----------------------------------------------------------------------------
21,592 27,683 (22)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Provident reports equivalent production converting natural gas to oil on
a 6:1 basis.
(2) Includes Southeast Saskatchewan and Southwest Saskatchewan operating
areas that were sold on September 30, 2009 and Lloydminster operating
area that was sold November 30, 2009.

Revenue and royalties
Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s except per boe and mcf data) 2009 2008 % Change
----------------------------------------------------------------------------

Oil
Revenue $ 175,408 $ 377,976 (54)
Realized gain (loss) on financial
derivative instruments 8,052 (11,113) -
Royalties (31,468) (69,897) (55)
----------------------------------------------------------------------------
Net revenue $ 151,992 $ 296,966 (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 46.92 $ 65.05 (28)
Royalties as a percentage of
revenue 17.9% 18.5%
Natural gas
Revenue $ 98,011 $ 253,183 (61)
Realized gain on financial
derivative instruments 8,336 11 75,682
Royalties (4,826) (44,715) (89)

Net revenue $ 101,521 $ 208,479 (51)
----------------------------------------------------------------------------
Net revenue (per mcf) $ 4.00 $ 6.78 (41)
Royalties as a percentage of
revenue 4.9% 17.7%
Natural gas liquids
Revenue $ 18,166 $ 33,857 (46)
Royalties (5,281) (8,528) (38)
----------------------------------------------------------------------------
Net revenue $ 12,885 $ 25,329 (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per barrel) $ 31.49 $ 57.53 (45)
Royalties as a percentage of
revenue 29.1% 25.2%

Total
Revenue $ 291,585 $ 665,016 (56)
Realized gain (loss) on financial
derivative instruments 16,388 (11,102) -
Royalties (41,575) (123,140) (66)
----------------------------------------------------------------------------
Net revenue $ 266,398 $ 530,774 (50)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net revenue (per boe) $ 33.80 $ 52.39 (35)
Royalties as a percentage of
revenue 14.3% 18.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note: the above revenue, net revenue and net revenue per boe figures are
presented net of transportation expenses and the realized gain (loss) on
financial derivative instruments excludes the impact of corporate interest
rate swap gains/losses allocated to Provident Upstream.


For the year ended December 31, 2009 Provident Upstream production revenue was $291.6 million, a decrease of 56 percent from $665.0 million in 2008. The decrease in revenue was a result of a 44 percent decrease in prices per boe due to lower realized crude oil, natural gas liquids, and natural gas prices as well as a 22 percent decrease in production. Royalties, which are price sensitive and affected by production rates, decreased as a percentage of revenue mainly due to significantly lower natural gas prices. Alberta natural gas crown royalties were also reduced to reflect the impact of prior year capital expenditures spent on natural gas facilities within the province. The preceding factors as well as the $16.4 million realized gain on financial derivative instruments compared to a $11.1 million realized loss in 2008, account for net revenue of $266.4 million in 2009, 50 percent lower than the $530.8 million recorded in 2008.

Net revenue per boe in 2009 decreased 35 percent to $33.80 from $52.39 in 2008 resulting primarily from lower realized product prices, lower royalties and a gain on financial derivative instruments in 2009 compared to a loss in 2008.



Provident Upstream

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

Production expenses $ 119,437 $ 138,173 (14)
Production expenses (per boe) $ 15.15 $ 13.64 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2009 production expenses decreased 14 percent to $119.4 million from $138.2 million and increased by 11 percent on a per boe basis to $15.15 per boe from $13.64 per boe in the prior year. The decrease in total costs was primarily due to a decrease in production. On a per boe basis, the increase was primarily due to fixed costs being allocated over fewer produced barrels of oil equivalent production. Operating costs in the Dixonville area continue to be incurred throughout the waterflood expansion program. In addition, the 2008 per boe production expense of $13.64 benefitted from a full year of production from Southeast Saskatchewan which incurred lower average operating costs in 2008.

Operating netback

Operating netback as presented does not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be comparable with calculations of similar measures of other entities.



Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ per boe) 2009 2008 % Change
----------------------------------------------------------------------------
Netback per boe
Gross production revenue $ 37.00 $ 65.64 (44)
Royalties (5.28) (12.15) (57)
Operating costs (15.15) (13.64) 11
----------------------------------------------------------------------------
Field operating netback 16.57 39.85 (58)
Realized gain (loss) on financial
derivative instruments 2.08 (1.10) -
----------------------------------------------------------------------------

Operating netback after realized
financial derivative instruments $ 18.65 $ 38.75 (52)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident Upstream operating netbacks have transportation expense netted against gross production revenue.

The 2009 field operating netback of $16.57 per boe was 58 percent below the $39.85 per boe for the prior year. The 44 percent decrease in year over year realized crude oil, natural gas liquids, and natural gas prices and 11 percent higher operating costs per boe partially offset by the 57 percent decrease in royalties on a per boe basis result in the significantly lower field operating netback. The 2009 operating netbacks after financial derivative instruments decreased by 52 percent to $18.65 from $38.75 in the prior year due to the preceding factors as well as the realized gain on financial derivative instruments of $2.08 per boe compared to a realized loss of $1.10 per boe in the prior year.



General and administrative

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

Cash general and administrative $ 30,725 $ 34,242 (10)
Non-cash unit based compensation 3,101 (2,199) -
----------------------------------------------------------------------------
$ 33,826 $ 32,043 6

Cash general and administrative (per
boe) $ 3.90 $ 3.39 15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2009, cash general and administrative expenses were $30.7 million (2008 - $34.2 million), a decrease of 10 percent. The decrease in cash general and administrative expenses reflected staff reductions and cost cutting measures implemented within the organization. On a per boe basis, cash general and administrative expenses in 2009 increased 15 percent to $3.90 per boe from $3.39 per boe in 2008.

The non-cash unit based compensation was an expense of $3.1 million in 2009 and a decrease in expense of $2.2 million in 2008. Non-cash unit based compensation was higher in 2009 as the unit based compensation, once granted, fluctuates based on changes in the trading prices of the Provident Trust units which increased in 2009 over the ending trading price in 2008.



Capital expenditures

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008
----------------------------------------------------------------------------

Capital expenditures - by category
Geological, geophysical and land $ 4,323 $ 25,474
Drilling and recompletions 59,307 146,992
Facilities and equipment 25,953 34,514
Office and other 1,154 2,167
----------------------------------------------------------------------------
Total additions $ 90,737 $ 209,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital expenditures - by area
West central Alberta $ 5,547 $ 10,326
Southern Alberta 7,917 19,852
Northwest Alberta 36,692 79,445
Dixonville 26,440 60,339
----------------------------------------------------------------------------
$ 76,596 $ 169,962
Other (1) 14,141 39,185
----------------------------------------------------------------------------
Total additions $ 90,737 $ 209,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Property acquisitions $ 333 $ 25,843
Property dispositions (2) $ 322,720 $ 1,662
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes Southeast Saskatchewan and Southwest Saskatchewan operating
areas that were sold on September 30, 2009 and Lloydminster operating
area that was sold on November 30, 2009.
(2) Property dispositions include cash proceeds on sale of assets as well
as $17.0 million of shares in Emerge Oil & Gas Inc. received on sale of
Lloydminster properties


In 2009, Provident Upstream successfully executed its capital program by spending $76.6 million on its four remaining operating areas as well as spending $12.7 million in the year on assets that were subsequently divested. Internal development activities on the four remaining operating areas included 10.7 net wells drilled for the year, including three water source wells, with a 98 percent success rate. In addition, 4.6 net wells were drilled in areas that were subsequently divested. Provident's drilling activities in 2009 were focused on its Pekisko crude oil resource play and the Dixonville waterflood project. Provident spent $36.7 million in Northwest Alberta, primarily on drilling and completion activities for the emerging Pekisko oil resource play, which included 3.0 net wells drilled, the infrastructure and tie-in activities associated with the 2008/2009 winter drilling program and preparation work to start the 2009/2010 winter drilling program. Facility and pipeline work in Northwest Alberta included work to provide infrastructure for the emerging Pekisko opportunity. Provident spent $26.4 million in Dixonville, primarily on the waterflood program which included drilling 2.0 net wells as well as 3.0 net water source wells, completion activities, and the conversion of 21 oil producing wells into water injectors. In Southern Alberta, $7.9 million was primarily spent on drilling activity and recompletions, which included 2.0 net wells drilled, and on facility upgrades and infrastructure work. The $5.6 million of capital in the West Central Alberta operating area was spent on drilling, completion, tie-ins, recompletions, facility upgrades and production optimization activities. In addition, $1.4 million was spent on office and non core properties.



Depletion, depreciation and accretion (DD&A)

Provident Upstream Year ended December 31,
----------------------------------------------------------------------------
($ 000s, except per boe data) 2009 2008 % Change
----------------------------------------------------------------------------

DD&A $ 259,545 $ 304,909 (15)
DD&A (per boe) $ 32.93 $ 30.09 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


DD&A charges in 2009 were down 15 percent to $259.5 million compared to $304.9 million in 2008. The lower charges reflect reduced production volumes compared to 2008, partially offset by an increase in the per boe DD&A rate. The rate of $32.93 per boe increased nine percent for 2009 compared to $30.09 per boe in 2008. The per boe increase was primarily as a result of 2008 and 2009 capital expenditures on longer term projects at Dixonville and the Pekisko play in Northwest Alberta. In the short term, these expenditures add costs to the depletable base without the addition of further proved reserves. The addition of more proved reserves associated with these projects would have a favourable impact on DD&A per boe.

In 2009, DD&A also includes accretion expense associated with asset retirement obligation of $3.1 million (2008 - $3.4 million).

Provident Midstream business segment review

The Midstream business

The Midstream business unit extracts, processes, stores, transports and markets natural gas liquids (NGL) for Provident and offers these services to third party customers. The Provident Midstream segment contains three business lines:

Empress East

Redwater West

Commercial Services

The Empress East business line is comprised of the following core assets:

- Approximately 2.0 Bcfd in extraction capacity at Empress, Alberta. This is the combination of 67.5 percent ownership of the 1.2 Bcfd capacity Provident Empress NGL extraction plant, 33.0 percent ownership in the 2.7 Bcfd capacity BP Empress 1 Plant, 12.4 percent ownership in the 1.1 Bcfd capacity ATCO Plant and 8.3 percent ownership in the 2.4 Bcfd capacity Spectra Plant.

- 100 percent ownership of a 50,000 bpd debutanizer at Empress, Alberta.

- 50 percent ownership in the 130,000 bpd Kerrobert pipeline and 2.5 mmbbl underground storage facility near Kerrobert, Saskatchewan which facilitates injection of NGLs into the Enbridge pipeline system. Along the Enbridge pipeline system in Superior, Wisconsin, Provident holds an 18.3 percent ownership of a 300,000 barrel storage staging facility and 18.3 percent ownership of a 6,600 bpd depropanizer.

- In Sarnia, Ontario, 16.5 percent ownership of an approximately 150,000 bpd fractionator, 1.7 mmbbl of raw product storage capacity, and 18.0 percent of 5.0 mmbbl of finished product storage and a rail, truck and pipeline terminalling facility. An additional 500,000 bbls of specification product storage is also leased in the Sarnia area.

- A propane distribution terminal at Lynchburg, Virginia.

- A rail car fleet of approximately 300 rail cars under long-term lease agreement.

The Redwater West business line is comprised of the following core assets:

- 100 percent ownership of the Redwater NGL fractionation facility, incorporating a 65,000 bpd fractionation, storage and transportation facility that includes 12 pipeline receipt and delivery points, railcar loading facilities with direct access to CN rail and indirect access to CP rail, two propane truck loading facilities, seven million gross barrels of salt cavern storage, and a 75,000 bpd condensate rail offloading facility with a 500 railcar storage yard. The Redwater facility is the only facility in western Canada that can fractionate a high-sulphur ethane-plus mix.

- Approximately 7,000 bpd of leased fractionation capacity at other facilities.

- 43.3 percent direct ownership and 100 percent control of all products from the 38,500 bpd Younger NGL extraction plant located at Taylor in northeastern British Columbia. The Younger plant supplies local markets as well as Provident's Redwater fractionation facility near Edmonton.

- 100 percent ownership of the 565 kilometer proprietary Liquids Gathering System ("LGS") that runs along the Alberta-British Columbia border providing access to a highly active basin for liquids-rich natural gas exploration and exploitation. Provident also has long-term shipping rights on the Pembina pipeline system that extends the product delivery transportation network through to the Redwater fractionation facility.

- A rail car fleet of approximately 700 rail cars under long-term lease agreement.

The Empress East and Redwater West business lines are supported by Provident's integrated marketing arm which has offices in Calgary, Alberta, Sarnia, Ontario, and Houston, Texas and operates under the brand name Kinetic. Rather than selling NGL produced by the Empress East and Redwater West facilities at the plant gate, the marketing and logistics group utilizes Provident's integrated suite of transportation, storage and logistics assets to access markets across North America. Due to its broad marketing scope, Provident's NGL products are priced based on multiple pricing indices. These indices generally correspond with the four major NGL trading hubs in North America which are located in Mont Belvieu, Texas, Conway, Kansas, Edmonton, Alberta, and Sarnia, Ontario. Mont Belvieu, the largest NGL trading center, serves as the reference point for NGL pricing in North America. By strategically building inventories of specification products which are then distributed into premium-priced markets across North America during periods of high seasonal demand, Provident is able to optimize the margins it earns from its extraction and fractionation operations. Provident's marketing group also generates margins by taking advantage of locational price differentials and arbitrage trading opportunities. Margins generated through marketing activities are included within the Empress East and Redwater West business lines.

The Commercial Services business line:

The Commercial Services business line includes services such as fractionation, storage, LPG terminalling, loading and offloading that are provided to third parties at Provident's Redwater facility on a fee basis. Year over year, Provident has significantly enhanced its Commercial Services platform at Redwater by adding incremental terminalling capacity at its condensate rail terminal and, most recently, through the addition of condensate storage capabilities. During the third quarter of 2009, two new 500,000 barrel storage caverns at Redwater were placed into condensate service, and a third condensate storage cavern is currently under construction. The Commercial Services business line also includes pipeline tariff income from Provident's ownership of the Liquids Gathering System in Northwest Alberta which flows into Pembina's pipeline from LaGlace to Redwater. Provident also collects tariff income from its 50 percent ownership in the Kerrobert Pipeline which transports NGLs from Empress to Kerrobert for injection into the Enbridge pipeline for delivery to Sarnia. Provident owns a debutanizer at its Empress facility, which removes condensate from the NGL mix for sale as a diluent to blend with heavy oil. This service is provided to a major energy company on a long term cost of service basis. Earnings from this business line of the Midstream segment have little direct exposure to market price volatility and are thus relatively stable.

Long term contracts

At the Redwater fractionation facility, a significant portion of the available propane, butane and condensate ("propane-plus") fractionation capacity is contracted through a long term fee for service arrangement with third parties.

The ethane produced from Provident's facilities at Empress and Redwater is largely sold under long term contracts.

In 2006 and early 2007, Provident commissioned a condensate rail off-loading terminal at Redwater with current capacity of 75,000 bpd, a significant portion of which is under long term contracts with two major energy producers.

Provident has two 500,000 barrel caverns used for condensate storage at Redwater. The majority of the condensate storage capacity is sold under long term contracts to various third parties, a number of which are major energy producers, with terms averaging from two to five years.

Provident has a long term contract on a cost of service basis for the majority of its 50,000 bbl/d Empress debutanizer facility with a major energy producer.

Market environment

Performance of the Midstream business unit is closely tied to market prices for NGL products and natural gas, which can vary significantly from period to period. The key reference prices impacting Midstream operating margins are summarized in the following table:



Midstream business reference prices Year ended December 31,
----------------------------------------------------------------------------
2009 2008 % Change
----------------------------------------------------------------------------

WTI (US$ per barrel) $ 61.80 $ 99.65 (38)
Exchange rate (from US$ to Cdn$) 1.14 1.07 7
WTI expressed in Cdn$ per barrel $ 70.54 $ 106.33 (34)

AECO monthly index (Cdn$ per gj) $ 3.92 $ 7.71 (49)

Frac Spread Ratio (1) 18.0 13.8 30

Mont Belvieu Propane (US$ per US
gallon) $ 0.84 $ 1.41 (40)
Mont Belvieu Propane expressed as a
percentage of WTI 57% 60% (5)

Market Frac Spread in Cdn$ per barrel
(2) $ 28.61 $ 35.35 (19)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Frac spread ratio is the ratio of WTI expressed in Canadian dollars per
barrel to the AECO monthly index (Cdn$ per gj).
(2) Market frac spread is determined using weighted average spot prices at
Mont Belvieu for propane, butane, and condensate and the AECO monthly
index price for natural gas.


Market conditions created a challenging environment for NGL operations in 2009. WTI crude oil prices averaged US$61.80 per barrel in 2009 as compared to US$99.65 per barrel in 2008, a 38 percent reduction. WTI crude prices, which largely drive NGL pricing, declined sharply in the last quarter of 2008 in response to the slowing world economy. This decline continued into 2009 when WTI prices fell below US$35.00 per barrel during the first quarter of 2009 before recovering to an average of US$76.19 per barrel in the fourth quarter. This is in stark contrast to the first nine months of 2008 where WTI prices reached record levels of over US$140 per barrel. Propane prices relative to WTI were also lower in 2009 with Mont Belvieu propane averaging 57 percent of WTI as compared to 60 percent of WTI in 2008. Propane prices relative to WTI were lowest during the second and third quarters of 2009 as a result of weaker product demand and above average levels of propane inventory in the North American marketplace.

Natural gas prices were also significantly impacted by the economic slow down. AECO natural gas prices averaged $3.92 per gj in 2009 as compared to $7.71 per gj in 2008, and reached lows of below $2.00 per gj during the month of September before recovering to exit the year at approximately $5.50 per gj. While lower natural gas prices are generally favorable to NGL extraction and fractionation economics, a sustained period in a low price environment can have an adverse impact on the availability and cost of natural gas and NGL mix supply if natural gas producers elect to shut-in production or reduce drilling activities. The impact of lower supply could be partially mitigated through an increase in NGL prices if demand for product exceeds available supply.

Market frac spreads, a key driver of NGL extraction economics, averaged $28.61 per barrel in 2009 as compared to $35.35 per barrel in 2008. Lower market frac spreads were the result of lower NGL prices, offset by much lower prices for natural gas. Extraction premiums paid to acquire the natural gas also have an impact on NGL extraction economics. While extraction premiums are excluded from the calculation of market frac spreads, they are included, along with other costs, when determining actual extraction operating margins. Over the past several months, Empress extraction premiums significantly increased as a result of reduced volumes of natural gas flowing past the Empress straddle plants. During 2009, natural gas throughput at the Empress Eastern border averaged approximately 5.2 bcf per day, a decrease of approximately 17 percent compared to the prior year. Lower natural gas throughput at the Empress facilities reduced propane-plus inventories currently available for sale in Sarnia and in surrounding eastern markets. In 2010, as available propane-plus supply tightens relative to demand, pricing differentials in these eastern markets where Provident sells the majority of its Empress East production, may increase relative to other major propane hubs including Mont Belvieu and Conway.

At the end of 2009, industry propane inventories in the United States were approximately 49 million barrels, a decrease of 11 percent compared to the prior year, and approximately seven million barrels below the five year historical average. For most of 2009, United States industry propane inventories exceeded the five year average, peaking at over 18 million barrels above the five year average during the month of June. United States industry propane inventories have fallen significantly since that period, driven primarily by above average propane withdrawals during the fourth quarter and the start of the winter heating season. Ending 2009 Canadian industry propane inventories of approximately five million barrels were in-line with the prior year, but lower than the five year average of approximately six million barrels.



Midstream business performance

Midstream business unit results can be summarized as follows:

Year ended December 31,
----------------------------------------------------------------------------
(bpd) 2009 2008 % Change
----------------------------------------------------------------------------

Provident Midstream NGL sales
volumes 113,528 119,649 (5)
----------------------------------------------------------------------------

Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008 % Change
----------------------------------------------------------------------------

Empress East Margin $ 95,633 $ 157,976 (39)
Redwater West Margin 127,404 142,836 (11)
Commercial Services Margin 63,746 46,541 37
----------------------------------------------------------------------------
Gross operating margin 286,783 347,353 (17)
Realized loss on financial
derivative instruments (66,743) (118,917) (44)
Cash general and administrative
expenses (31,297) (33,845) (8)
Strategic review and restructuring
expenses (4,624) (1,683) 175
Foreign exchange (loss) gain and
other (1,802) 19,853 -
----------------------------------------------------------------------------
Provident Midstream EBITDA $ 182,317 $ 212,761 (14)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Gross operating margin

Midstream gross operating margin was $286.8 million for the year ended December 31, 2009 compared to $347.4 million in 2008. The 17 percent decrease was due to lower operating margins from the Empress East and Redwater West business lines, partially offset by a 37 percent increase in contribution from the Commercial Services business line.

The Empress East business line:

The Empress East business line extracts NGLs from natural gas at the Empress straddle plants and sells finished products into markets in central Canada and the eastern United States. Demand for propane is seasonal and results in inventory that generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year. The margin in this business is determined primarily by the "frac spread", which represents the difference between the selling prices for propane-plus and the input cost of the natural gas required to produce the respective NGL products. The frac spread can change significantly from period to period depending on the relationship between crude oil and natural gas prices (the "frac spread ratio"), absolute commodity prices, and changes in the Canadian to US dollar foreign exchange rate. Traditionally a higher frac spread ratio and higher crude oil prices will result in stronger business line margins. Differentials between propane-plus and crude oil prices, as well as locational price differentials will also impact the frac spread. Natural gas extraction premiums and costs relating to transportation, fractionation, storage and marketing are not included within the frac spread, however these costs are included in the business line operating margin.

In 2009, the gross operating margin for Empress East was $95.6 million (2008 - $158.0 million), a reduction of 39 percent. Lower operating margins were the result of lower realized propane-plus unit margins and a 19 percent decrease in propane-plus sales volumes. Realized per unit margins have decreased from the prior year due to lower frac spreads which are reflective of the market pricing environment. Per unit margins were also impacted by an increase in natural gas extraction premiums, particularly during the second half of 2009. In recent months, extraction premiums more than doubled as a result of lower eastern gas flows through the Empress facilities. Eastern gate gas supply has been impacted in 2009 by lower natural gas drilling activity in western Canada, shut-in production, and narrower natural gas pricing differentials between AECO and Chicago.

The 19 percent decrease in sales volumes was the result of lower propane-plus term sales and lower product availability. In the beginning of 2009, Provident reduced its term sales commitments for the upcoming NGL contract year as a result of the pending expiry of its fractionation capacity lease at Sarnia on the first of April 2009, which was expected to reduce Empress East processing capacity by 6,000 bpd during the 2009/10 NGL year which runs from April, 2009 through to March, 2010. In August, Provident was successful in restoring this reduced capacity by purchasing approximately 7,400 bpd of additional fractionation capacity at Sarnia. As Provident moves into 2010, it expects to realize additional benefits from the incremental capacity, particularly as new term sales arrangements are negotiated for the upcoming NGL contract year which begins on April 1, 2010. Full realization of the benefits of the incremental capacity at Sarnia will be impacted by the availability and cost of supply at Empress.

The Redwater West business line:

The Redwater West business line purchases an NGL mix from various producers and fractionates it into finished products at the Redwater fractionation facility near Edmonton, Alberta. Because the feedstock for this business line is primarily NGL mix rather than natural gas, the frac spread has a smaller impact on margin than in the Empress East business line. The Redwater facility also has the largest and industry-leading rail-based condensate terminal in western Canada which serves the heavy oil industry and its need for diluent. Income generated from the condensate terminal and caverns which relates to third-party terminalling and storage is included within the Commercial Services business line, while income relating to proprietary condensate marketing activities remains within the Redwater West business line.

In 2009, the operating margin for Redwater West was $127.4 million (2008 - $142.8 million) a decrease of 11 percent. The decrease was primarily a result of lower margins from ethane and condensate sales, partially offset by higher margins on propane. Ethane margins were lower than in the prior year as a result of lower sales volumes and lower per unit margins, which were impacted by lower sales prices and by month over month falling natural gas prices during the first three quarters of 2009. The decrease in condensate margins was the result of lower realized per unit margins. Incremental demand for condensate for use as diluent was much stronger in 2008 which resulted in much higher premiums relative to WTI being paid for condensate in the Edmonton marketplace. Condensate premiums relative to WTI in the Edmonton area averaged approximately US$6.00 per bbl in 2008 as compared to a discount of approximately US$0.80 per bbl in 2009. Margins earned from propane sales were higher than in the prior year predominantly as a result of the stronger pricing environment in the fourth quarter of 2009 relative to the fourth quarter of 2008. Butane margins in 2009 were similar to the prior year with higher per unit margins offsetting lower sales volumes. On a combined basis, Redwater West propane-plus selling prices decreased by 34 percent relative to the prior year reflecting the decline in average market prices for NGL. Cost of goods sold, on a per unit basis, were 39 percent lower than 2008 reflecting lower market prices for NGL and natural gas supply.

Propane-plus volumes were three percent lower than in the prior year primarily as a result of lower butane sales. Lower butane sales were the result of changing market conditions, which impacted the availability of butane supply. Propane and condensate sales volumes were similar to the prior year.

The Commercial Services business line:

The Commercial Services business line generates income from fee-for-service contracts to provide fractionation, storage, LPG terminalling, loading and offloading services. The growth in this business segment has been primarily driven by the expansion of Provident's condensate terminalling and storage facilities at Redwater. Income from pipeline tariffs from Provident's ownership in NGL pipelines is also included in this business line. In 2009, the margin for this business line was $63.7 million (2008 - $46.5 million). The 2009 operating margin was 37 percent higher than 2008 mostly due to increased fee based revenues associated with the condensate terminalling facility, higher third party processing fees and incremental storage revenues from Provident's condensate storage caverns which were placed into service during the third quarter.

Operations - Midstream NGL sales volumes

Provident Midstream sold 113,528 bpd in 2009, down five percent when compared with 119,649 bpd in 2008. The reduction in volumes primarily represents the decrease in propane-plus volumes in both Empress East and Redwater West.

Earnings before interest, taxes, depletion, depreciation, accretion, and other non-cash items ("adjusted EBITDA") and funds flow from operations

For 2009, adjusted EBITDA decreased 14 percent to $182.3 million from $212.8 million in 2008 reflecting lower operating margins for the Empress East and Redwater West business lines, partially offset by a lower realized loss on financial derivative instruments and lower cash general and administrative expenses. The $66.7 million realized loss on financial derivative instruments was driven by natural gas derivative purchase contracts that settled at current market prices that were lower than the original derivative contract prices. The comparable 2008 amounts had a larger realized loss on financial derivative instruments, driven primarily by crude oil derivative sales contracts settling at prices considerably higher than the original derivative contract crude oil prices. The 2008 adjusted EBITDA amount also included gains on corporate foreign exchange contracts settled in the period, of which $20.1 million was allocated to the Midstream segment and was included in foreign exchange (loss) gain and other. Cash general and administrative expenses were lower in 2009 as a result of staff reductions and cost cutting measures implemented within the organization. Funds flow from operations for 2009 was $161.8 million, a decrease of $17.2 million or 10 percent compared to $179.0 million in 2008. The decrease in funds flow from operations reflects the lower adjusted EBITDA, partially offset by significantly lower interest expense.

Capital expenditures

Provident Midstream capital expenditures for 2009 totaled $36.6 million. In 2009, $31.1 million was spent primarily on the continued development of cavern storage, the condensate terminalling and storage facility and pre-development activities relating to the Michigan depropanizer. In addition, $2.7 million was spent on sustaining capital requirements, $2.1 million was added to capitalized linefill and $0.7 million was spent on office related capital.

Midstream asset acquisitions

On August 12, 2009, Provident purchased an additional 6.15 percent interest in the Sarnia fractionation facilities for $14.8 million and a deferred payment of $3.7 million for a facility enhancement planned for 2010. This acquisition increased Provident's ownership in the Sarnia fractionator, effective August 1, 2009, to approximately 16.5 percent, increasing propane-plus fractionation capacity in the Empress East system by approximately 7,400 bpd to 20,000 bpd in total. This acquisition replaced the 6,000 bpd of formerly leased capacity at Sarnia that expired on April 1, 2009. As a result of this transaction, Provident has deferred construction of its previously announced depropanizer facility in Michigan.

In November 2009, Provident announced an agreement to purchase a commercial storage facility in Corunna, Ontario for an undisclosed amount. The facility is located in close proximity to Provident's existing operations in Sarnia, Ontario. The 1,000 acre site has an active cavern storage capacity of 12.1 million barrels, consisting of 5.0 million barrels of hydrocarbon storage and 7.1 million barrels currently used for brine storage. The facility also includes 13 pipeline connections and a small rail offloading facility. The transaction is expected to close by the end of the second quarter of 2010.

Discontinued operations (USOGP)

In February, 2008 the Trust announced a strategic process respecting the decision to dispose of the operations that comprise the United States oil and natural gas production (USOGP) business. Effective in the first quarter of 2008, Provident's USOGP business was accounted for as discontinued operations. The USOGP business was sold in June and August of 2008.

Quicksilver Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against BreitBurn Energy Partners, L.P. (the MLP), certain of its directors (including three Provident nominees), and Provident. The MLP was part of the USOGP business. The claim relates to a transaction between the MLP and Quicksilver and certain other MLP matters. Quicksilver alleges, among other things, that it was induced to enter into a contribution agreement pursuant to which it contributed assets to the MLP by false representations as to Provident's relationship with the MLP. The transaction involved the issuance by the MLP to Quicksilver of approximately U.S. $700 million of units of the MLP. In February 2010, Provident agreed to settle all existing litigation with Quicksilver. Provident expects the cost of the lawsuit and settlement will be covered by insurance.

Disclosure Controls and Procedures: U.S. Sarbanes-Oxley Act

In 2002, the United States Congress enacted the Sarbanes-Oxley Act (SOX), which requires that issuers that are required to file reports with the United States Securities and Exchange Commission must assess and report upon the effectiveness of their "internal control over financial reporting" as of the end of each fiscal year. As an entity listed on the New York Stock Exchange, Provident is subject to the rules. See "Management's Report on Internal Control Over Financial Reporting" and "Independent Auditors' Report".

As of December 31, 2009, an evaluation of the effectiveness of Provident's "disclosure controls and procedures" (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the "Exchange Act")) was carried out by the management of Provident, with the participation of the Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"). Based upon that evaluation, the CEO and CFO have concluded that as of December 31, 2009, Provident's disclosure controls and procedures are effective to ensure that information required to be disclosed by Provident in reports that it files or submits to Canadian and United States securities authorities are (i) recorded, processed, summarized and reported within the time periods specified by Canadian and Unites States securities laws and (ii) accumulated and communicated to Provident's management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while the CEO and CFO believe that Provident's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Provident's disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Provident will continue to periodically evaluate its disclosure controls and procedures and internal controls over financial reporting and will make modifications from time to time as deemed necessary.

During the year ended December 31, 2009, there were no changes in Provident's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Provident's internal control over financial reporting.

Foreign ownership

Based on information received from our transfer agent and financial intermediaries in January 2010, an estimated 85 percent of our outstanding trust units are held by non-residents. However, this estimate may not be accurate as it is based on certain assumptions and data from the securities industry that does not have a well-defined methodology to determine the residency of beneficial holders of securities.

The Trust qualifies as a Mutual Fund Trust under the Canadian Income Tax Act because substantially all the value of its asset portfolio is derived from non-taxable Canadian properties, comprised principally of royalties and interest on inter-company debt. Provident monitors on an ongoing basis the value of its asset portfolio to confirm that substantially all of the value of its asset portfolio is derived from non-taxable Canadian properties.

On September 17, 2003, Canadian unitholders approved an amendment to the Trust's Trust Indenture providing that residency restriction provisions need not be enforced while the Trust continues to qualify as a Mutual Fund Trust under Canadian tax legislation. To allow Provident to remain a Mutual Fund Trust and to execute a business plan that maximizes unitholder returns without regard to the types of assets the Trust may hold, the approved amendment provides for Provident's Board of Directors to have sole discretion to determine whether and when it is appropriate to reduce or limit the number of trust units held by non-residents of Canada.

Critical accounting estimates

Provident's significant accounting policies are described in note 2 to the consolidated financial statements. Certain accounting policies include critical accounting estimates. These policies require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain. These accounting policies could result in materially different results should the underlying assumptions or conditions change.

Management assumptions are based on Provident's historical experience, management's experience, and other factors that, in management's opinion, are relevant and appropriate. Management assumptions may change over time, as further experience is gained or as operating conditions change.

The Trust's financial and operating results incorporate certain estimates including:

- depletion, depreciation and accretion based on estimated oil and gas reserves;

- future recoverable value of property, plant and equipment and goodwill (see "Goodwill and intangible assets") based on estimated future cash flows;

- value of asset retirement obligations based on estimated future costs and timing of expenditures;

- fair values of derivative contracts that are subject to fluctuation depending upon underlying commodity prices and foreign exchange rates (see note 14 to the consolidated financial statements); and

- income taxes based on estimates of future income and tax pool claims (see "Taxes").

Property, plant and equipment

Provident follows the full cost method of accounting, whereby all costs associated with the acquisition and development of oil and natural gas reserves are capitalized and accumulated in one cost centre as all of the oil and natural gas assets are in Canada. Utilization of the full cost method of accounting requires the use of management estimates and assumptions for amounts recorded for depletion and depreciation of property, plant and equipment as well as for the ceiling test.

The provision for depletion and depreciation is calculated using the unit of production method based on current production divided by Provident's share of estimated total proved oil and natural gas reserve volumes before royalties. The recoverability of the assets are tested by comparing the carrying value to the sum of the undiscounted cash flows expected. If the carrying value is not recoverable the assets are written down to their fair value.

Proved reserves are an estimate, under existing reserve evaluation polices, of volumes that can reasonably be expected to be economically recoverable under existing technology and economic conditions. Changes in underlying assumptions or economic conditions could have a material impact on Provident's financial results. To mitigate these risks, management utilizes McDaniel & Associates Consultants Ltd. and AJM Petroleum Consultants, independent engineering firms, to evaluate Provident's reserves.

Estimates of future production, oil and natural gas prices and future costs used in the ceiling test are, by their very nature, subject to uncertainty and changes in underlying assumptions could have a material impact on Provident's financial results.

Asset retirement obligation

Under the asset retirement obligation (ARO) standard, the fair value of asset retirement obligations is recorded as a liability on a discounted basis, when incurred. The value of the related assets is increased by the same amount as the liability and depreciated over the useful life of the asset. Over time the liability is adjusted for the change in present value of the liability or as a result of changes to either the timing or amount of the original estimate of undiscounted future cash flows.

The ARO standard requires that management make estimates and assumptions regarding future liabilities and cash flows involving environmental reclamation and remediation. Such assumptions are inherently uncertain and subject to change over time due to factors such as historical experience, changes in environmental legislation or improved technologies. Changes in underlying assumptions, based on the above noted factors, could have a material impact on Provident's financial results.

Change in accounting policies

(i) Goodwill and intangible assets

In the first quarter of 2009, the Trust adopted CICA Handbook section 3064 "Goodwill and Intangible assets" which supersedes section 3062 "Goodwill and other Intangible assets" and section 3450 "Research and Development". This new section established standards for the recognition, measurement and disclosure of goodwill and intangible assets. The adoption of this standard did not have a material impact on the Trust's consolidated financial statements.

(ii) Business combinations

In December of 2008, the CICA released Handbook section 1582 "Business Combinations", which replaces existing guidance under section 1581 "Business Combinations". The new standard is intended to converge with International Financial Reporting Standards. Under section 1582, the purchase price in a business combination is based on the fair value of shares exchanged at the market price on the acquisition date. Under the existing standard, the purchase price is based on the market price of shares over a reasonable period before and after the date of acquisition is agreed upon and announced. This new standard also requires that all acquisition costs be expensed as incurred. Currently, these costs may be capitalized as part of the purchase price. In addition, the new guidance addresses contingent liabilities, which will be required to be recognized at fair value on acquisition and subsequently remeasured at each reporting period until settled. Under the current standard, only contingent liabilities that are payable are recognized. This new section requires that negative goodwill to be recognized in earnings immediately rather than the existing standard of reducing non-current assets in the purchase price allocation. The new standard applies prospectively to business combinations on or after January 1, 2011 with earlier adoption permitted. The Trust is currently assessing the impact of the new standard.

(iii) International Financial Reporting Standards (IFRS)

During 2008, the Canadian Accounting Standards Board (AcSB) confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) in place of Canadian GAAP for interim and annual reporting purposes. The required changeover date is for fiscal years beginning on or after January 1, 2011.

In 2008, Provident commenced the process to transition from current Canadian GAAP to IFRS. A project plan and a project team were established. The project team is led by finance management and includes representatives from various areas of the organization as necessary to plan for a smooth transition to IFRS.

The project plan consists of three phases: initiation, detailed assessment and design and implementation. Provident has completed the first phase, which involved the development of a detailed timeline for assessing resources and training and the completion of a high level review of the major differences between current Canadian GAAP and IFRS. Education and training sessions for employees throughout the organization and discussions with Provident's external auditors have been held and will continue throughout the subsequent phases. Regular reporting on the project plan is provided to Provident's senior management and to the Audit Committee of the Board of Directors.

During 2009, Provident was engaged in the detailed assessment and design phase of the project. The detailed assessment and design phase involves a comprehensive analysis of the impact of the IFRS differences identified in the initial scoping assessment. In addition, an initial evaluation of IFRS 1 transition exemptions, as further described below, and an analysis of financial systems has been performed.

During the implementation phase which began in the first quarter of 2010, Provident will execute the required changes to business processes, financial systems, accounting policies, IT systems, disclosure controls and internal controls over financial reporting as discussed below. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to Provident's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&A.

First -Time Adoption of IFRS:

IFRS 1, "First-Time Adoption of International Financial reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate for Provident, which at this time include the following:

- Business Combinations - IFRS 1 would allow Provident to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations that occurred prior to transition to IFRS. The IFRS business combination rules converge with the new CICA Handbook section 1582 that is also effective for Provident on January 1, 2011, however, early adoption is permitted.

- Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option to value the Upstream PP&E assets at their deemed cost being the Canadian GAAP net book value assigned to these assets as at the date of transition, January 1, 2010. This amendment is permissible for entities, such as Provident, who currently follow the full cost accounting guideline under Canadian GAAP that accumulates all oil and gas assets into one cost centre. Under IFRS, Provident's PP&E assets must be divided into smaller cost centres. The net book value of the assets on the date of transition will be allocated to the new cost centres on the basis of Provident's reserve volumes or values at that point in time.

The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect the Trust's reported financial position and results of operations. At this time, Provident has identified key differences that will impact the financial statements as follows:

- Presentation of Exploration and Evaluation ("E&E") expenditures separate from PP&E - Upon transition to IFRS, Provident will present all E&E expenditures as a separate component on the Consolidated Balance Sheet. This will include the book value for Provident's land that relates to undeveloped properties. E&E assets will not be depleted and must be assessed for impairment when indicators suggest the possibility of impairment.

- Calculation of depletion expense for Upstream PP&E assets - Upon transition to IFRS, Provident has the option to calculate depletion using a reserve base of proved reserves or both proved and probable reserves, as compared to the Canadian GAAP method of calculating depletion using only proved reserves. Provident has not concluded at this time which method for calculating depletion will be used.

- Impairment of long-term assets - Under IFRS, impairment of long-term assets must be calculated at a more granular level than what is currently required under Canadian GAAP. Impairment calculations will be performed at the cash generating unit level for both Upstream and Midstream long-term assets.

- Due to the recent withdrawal of the exposure draft on IAS 12 Income Taxes in November 2009 and the issuance of the exposure draft on IAS 37 Provisions, Contingent Liabilities and Contingent Assets in January 2010, management is still determining the impact of these revised standards on its IFRS transition.

In addition to accounting policy differences, Provident's transition to IFRS will impact the internal controls over financial reporting, disclosure controls and procedures and IT systems as follows:

- Internal controls over financial reporting - As the review of Provident's accounting policies is completed, an assessment will be made to determine changes required to ensure the continued integrity of Provident's internal controls over financial reporting. As an example, additional controls will be implemented for the IFRS 1 changes such as the allocation of Provident's PP&E as well as the process for re-classifying Provident's E&E expenditures from PP&E. This assessment will be an ongoing process through 2010 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.

- IT systems - Provident is finalizing the system updates required in order to ready the Trust for IFRS reporting. The modifications while not significant are, however, deemed critical in order to allow for reporting of both Canadian GAAP and IFRS statements in 2010 as well as the modifications required to track PP&E costs and E&E costs with a more granular level of detail for IFRS reporting. Additional system modifications may be required based on final policy choices.

- Disclosure controls and procedures - Information relating to Provident's transition to IFRS, as well as the progress in completing the implementation phase described above, will continue to be communicated to senior management and the Board of Directors and reported on in Provident's annual and interim filings, including its MD&A. As a result, Provident's disclosure controls and procedures will ensure that stakeholders are provided with sufficient information to assist in understanding the impact of the IFRS transition on Provident.

Business risks

The trust industry is subject to risks that can affect the amount of funds flow from operations available for distribution to unitholders, and the ability to grow. These risks include but are not limited to:

- capital markets, credit and liquidity risks and the ability to finance future growth; and

- the impact of Canadian governmental regulation on Provident, including the effect of the legislated tax on trust distributions.

The oil and natural gas industry is subject to numerous risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

- fluctuations in commodity price, exchange rates and interest rates;

- government and regulatory risk in respect of royalty and income tax regimes;

- changes to environmental regulations;

- operational risks that may affect the quality and recoverability of reserves;

- geological risk associated with accessing and recovering new quantities of reserves;

- transportation risk in respect of the ability to transport oil and natural gas to market;

- competition for exploration prospects and the development of new sources of production;

- declining oil and natural gas reserves and production;

- marketability of oil and natural gas;

- the ability to attract and retain employees; and

- environmental, health and safety risks.

The midstream industry is also subject to risks that can affect the amount of cash flow available for distribution to unitholders and the ability to grow. These risks include but are not limited to:

- operational matters and hazards including the breakdown or failure of equipment, information systems or processes, the performance of equipment at levels below those originally intended, operator error, labour disputes, disputes with owners of interconnected facilities and carriers and catastrophic events such as natural disasters, fires, explosions, fractures, acts of eco-terrorists and saboteurs, and other similar events, many of which are beyond the control of the Trust or Provident;

- the Midstream NGL assets are subject to competition from other gas processing plants, and the pipelines and storage, terminal and processing facilities are also subject to competition from other pipelines and storage, terminal and processing facilities in the areas they serve, and the gas products marketing business is subject to competition from other marketing firms;

- exposure to commodity price fluctuations;

- reduction in the volume of throughput or the level of demand;

- the ability to attract and retain employees;

- increasing operating and capital costs;

- regulatory intervention in determining processing fees and tariffs; and

- reliance on significant customers.

Provident strives to minimize these business risks by:

- employing and empowering management and technical staff with extensive industry experience and providing competitive remuneration;

- adhering to a strategy of acquiring, developing and optimizing quality, low-risk reserves in areas where we have technical and operational expertise;

- developing a diversified, balanced asset portfolio that generally offers developed operational infrastructure, year-round access and close proximity to markets;

- adhering to a disciplined Commodity Price Risk Management Program to mitigate the impact that volatile commodity prices have on cash flow available for distribution;

- marketing crude oil and natural gas to a diverse group of customers, including aggregators, industrial users, well-capitalized third-party marketers and spot market buyers;

- marketing natural gas liquids and related services to selected, credit worthy customers at competitive rates;

- maintaining a competitive cost structure to maximize cash flow and profitability;

- maintaining prudent financial leverage and developing strong relationships with the investment community and capital providers;

- adhering to strict guidelines and reporting requirements with respect to environmental, health and safety practices; and

- maintaining an adequate level of property, casualty, comprehensive and directors' and officers' insurance coverage.

Readers should be aware that the risks set forth herein are not exhaustive. Readers are referred to Provident's annual information form, which is available at www.sedar.com, for a detailed discussion of risks affecting Provident.

Unit trading activity

The following table summarizes the unit trading activity of the Provident units for each of the four quarters in the year ended December 31, 2009 on both the Toronto Stock Exchange and the New York Stock Exchange:



Q1 Q2 Q3 Q4
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TSE - PVE.UN (Cdn$)
High $ 6.61 $ 6.50 $ 6.46 $ 7.36
Low $ 2.90 $ 4.50 $ 4.69 $ 5.64
Close $ 4.81 $ 5.82 $ 6.20 $ 7.08
Volume (000s) 21,878 22,810 17,610 18,346
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NYSE - PVX (US$)
High $ 5.60 $ 5.70 $ 6.08 $ 6.99
Low $ 2.23 $ 3.55 $ 4.00 $ 5.19
Close $ 3.72 $ 4.92 $ 5.76 $ 6.72
Volume (000s) 92,576 83,525 72,040 103,991
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Forward-looking information

This MD&A contains forward-looking information under applicable securities legislation. Statements which include forward-looking information relate to future events or the Trust's future performance. Such forward-looking information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. All statements other than statements of historical fact are forward-looking information. In some cases, forward-looking information can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. Statements relating to "reserves" or "resources" are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Forward looking information in this MD&A includes, but is not limited to, business strategy and objectives, reserve quantities and the discounted present value of future net cash flows from such reserves, net revenue, future production levels, capital expenditures, exploration plans, development plans, acquisition and disposition plans and the timing thereof, operating and other costs, royalty rates, budgeted levels of cash distributions and the performance associated with Provident's natural gas midstream, NGL processing and marketing business. Specifically, the "Outlook" section in this MD&A may contain forward-looking information about prospective results of operations, financial position or cash flows of the Trust. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual events or results to differ materially from those anticipated by the Trust and described in the forward-looking information. In addition, this MD&A may contain forward-looking information attributed to third party industry sources. Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking information will not occur. Forward-looking information in this MD&A includes, but is not limited to, statements with respect to:

- the Trust's ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets;

- the Trust's acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom;

- sustainability and growth of production and reserves through prudent management and acquisitions;

- the emergence of accretive growth opportunities;

- the ability to achieve an appropriate level of monthly cash distributions;

- the impact of Canadian governmental regulation on the Trust;

- the existence, operation and strategy of the commodity price risk management program;

- the approximate and maximum amount of forward sales and hedging to be employed;

- changes in oil and natural gas prices and the impact of such changes on cash flow after financial derivative instruments;

- the level of capital expenditures devoted to development activity rather than exploration;

- the sale, farming out or development using third party resources to exploit or produce certain exploration properties;

- the use of development activity and acquisitions to replace and add to reserves;

- the quantity of oil and natural gas reserves and oil and natural gas production levels;

- currency, exchange and interest rates;

- the performance characteristics of Provident's midstream, NGL processing and marketing business;

- the growth opportunities associated with the midstream, NGL processing and marketing business; and

- the nature of contractual arrangements with third parties in respect of Provident's midstream, NGL processing and marketing business.

Although the Trust believes that the expectations reflected in the forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. The Trust can not guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Trust nor any other person assumes responsibility for the accuracy and completeness of the forward-looking information. Some of the risks and other factors, some of which are beyond the Trust's control, which could cause results to differ materially from those expressed in the forward-looking information contained in this MD&A include, but are not limited to:

- general economic and credit conditions in Canada, the United States and globally;

- industry conditions associated with the NGL services, processing and marketing business;

- fluctuations in the price of crude oil, natural gas and natural gas liquids;

- uncertainties associated with estimating reserves;

- royalties payable in respect of oil and gas production;

- interest payable on notes issued in connection with acquisitions;

- income tax legislation relating to income trusts, including the effect of legislation taxing trust income;

- governmental regulation in North America of the oil and gas industry, including income tax and environmental regulation;

- fluctuation in foreign exchange or interest rates;

- stock market volatility and market valuations;

- the impact of environmental events;

- the need to obtain required approvals from regulatory authorities;

- unanticipated operating events which can reduce production or cause production to be shut-in or delayed;

- failure to realize the anticipated benefits of acquisitions;

- competition for, among other things, capital reserves, undeveloped lands and skilled personnel;

- failure to obtain industry partner and other third party consents and approvals, when required;

- risks associated with foreign ownership;

- third party performance of obligations under contractual arrangements; and

- the other factors set forth under "Business risks" in this MD&A.

Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. With respect to developing forward-looking information contained in this MD&A, the Trust has made assumptions regarding, among other things:

- future natural gas and crude oil prices;

- the ability of the Trust to obtain qualified staff and equipment in a timely and cost-efficient manner to meet demand;

- the regulatory framework regarding royalties, taxes and environmental matters in which the Trust conducts its business;

- the impact of increasing competition;

- the Trust's ability to obtain financing on acceptable terms;

- the general stability of the economic and political environment in which the Trust operates;

- the timely receipt of any required regulatory approvals;

- the ability of the operator of the projects which the Trust has an interest in to operate the field in a safe, efficient and effective manner;

- field production rates and decline rates;

- the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration;

- the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Trust to secure adequate product transportation;

- currency, exchange and interest rates; and

- the ability of the Trust to successfully market its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Forward-looking information contained in this MD&A is made as of the date hereof and the Trust undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this MD&A is expressly qualified by this cautionary statement.

Additional information

Additional information concerning Provident can be accessed under Provident's public filings at www.sedar.com and www.sec.gov/edgar.shtml, as well as on Provident's website at www.providentenergy.com.



Selected annual financial measures

($ 000s except per unit data) 2009 2008 2007
----------------------------------------------------------------------------
Revenue from continuing
operations (net of royalties and
financial derivative instruments) $ 1,711,483 $ 3,239,163 $ 2,038,515
Net (loss) income (89,020) 157,392 30,434
Per unit - basic and diluted (0.34) 0.62 0.13
Total assets 2,548,015 3,074,069 5,758,792
Long-term financial liabilities
from continuing operations (1) 682,625 867,232 1,382,921
Declared distributions per unit. $ 0.75 $ 1.38 $ 1.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes long-term debt, asset retirement obligation, long-term
financial derivative instruments and other long-term liabilities.


Quarterly table

Segmented information by quarter
----------------------------------------------------------------------------
($ 000s except for per unit
and operating amounts) 2009
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial - consolidated
Revenue $ 470,769 $ 305,923 $ 465,432 $ 469,359 $1,711,483
Funds flow from
continuing operations $ 84,281 $ 48,516 $ 54,869 $ 76,340 $ 264,006
Funds flow from
continuing operations
per unit - basic and
diluted $ 0.32 $ 0.19 0.21 0.29 $ 1.01
Net (loss) income $ (40,284)$ (80,061) $ 51,663 $ (20,338)$ (89,020)
Net (loss) income per
unit - basic and
diluted $ (0.16)$ (0.31) $ 0.20 $ (0.08)$ (0.34)
Unitholder
distributions $ 54,511 $ 47,012 $ 47,238 $ 47,456 $ 196,217
Distributions per unit $ 0.21 $ 0.18 $ 0.18 $ 0.18 $ 0.75
----------------------------------------------------------------------------

Provident Upstream
Cash revenue $ 72,242 $ 78,883 $ 69,208 $ 57,263 $ 277,596
Earnings before interest,
DD&A, taxes and other
non-cash items $ 25,119 $ 33,114 $ 30,344 $ 20,416 $ 108,993
Funds flow from
operations $ 22,827 $ 30,022 $ 28,425 $ 20,882 $ 102,156
Net loss $ (38,154)$ (29,885) $(21,879)$ (20,649)$ (110,567)
----------------------------------------------------------------------------

Provident Midstream
Cash revenue $ 487,820 $ 314,537 $309,215 $ 452,176 $1,563,748
Earnings before interest,
DD&A, taxes and other
non-cash items $ 69,927 $ 24,416 $ 27,119 $ 60,855 $ 182,317
Funds flow from
operations $ 61,454 $ 18,494 $ 26,444 $ 55,458 $ 161,850
Net (loss) income $ (2,130)$ (50,176) $ 73,542 $ 311 $ 21,547
----------------------------------------------------------------------------

Operating
Oil and gas production
Crude oil (bpd) 10,710 10,035 9,276 5,533 8,875
Natural gas liquids (bpd) 1,138 1,105 1,169 1,072 1,121
Natural gas (mcfd) 76,260 75,735 65,525 60,992 69,575
Oil equivalent (boed) 24,558 23,763 21,366 16,770 21,592
----------------------------------------------------------------------------
Average selling price net
of transportation expense
(Cdn$)
Crude oil per bbl $ 36.23 $ 59.03 $ 62.06 $ 66.03 $ 54.15
(before realized financial
derivative instruments)
Crude oil per bbl $ 42.31 $ 60.61 $ 62.56 $ 66.67 $ 56.63
(including realized
financial derivative
instruments)
Natural gas liquids
per barrel $ 41.13 $ 38.14 $ 39.76 $ 59.25 $ 44.40
Natural gas per mcf $ 4.75 $ 3.40 $ 2.90 $ 4.36 $ 3.86
(before realized financial
derivative instruments)
Natural gas per mcf $ 5.26 $ 3.62 $ 3.28 $ 4.54 $ 4.19
(including realized
financial derivative
instruments)
----------------------------------------------------------------------------

Provident Midstream
Provident Midstream NGL
sales volumes (bpd) 141,669 102,799 98,229 111,912 113,528
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Quarterly table

Segmented information by quarter
----------------------------------------------------------------------------
($ 000s except for per unit
and operating amounts) 2008
----------------------------------------------------------------------------
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
----------------------------------------------------------------------------
Financial - consolidated
Revenue (continuing
operations) $ 702,215 $ 420,220 $1,097,408 $1,019,320 $3,239,163
Funds flow from
Continuing
operations $ 130,394 $ 165,470 $ 139,979 $ 81,779 $ 517,622
Funds flow from
continuing
operations per
unit - basic $ 0.52 $ 0.65 $ 0.55 $ 0.32 $ 2.03
Funds flow from
continuing
operations per
unit - diluted $ 0.52 $ 0.65 $ 0.51 $ 0.32 $ 2.03
Net income (loss) $ 33,616 $(184,081)$ 351,105 $ (43,248)$ 157,392
Net income (loss)
per unit - basic $ 0.13 $ (0.72)$ 1.37 $ (0.17)$ 0.62
Net income (loss)
per unit - diluted $ 0.13 $ (0.72)$ 1.29 $ (0.17)$ 0.62
Unitholder
distributions $ 91,117 $ 91,662 $ 92,188 $ 77,324 $ 352,291
Distributions per
unit $ 0.36 $ 0.36 $ 0.36 $ 0.30 $ 1.38
----------------------------------------------------------------------------

Oil and gas production
(continuing operations)
Cash revenue $ 122,815 $ 164,442 $ 158,400 $ 101,437 $ 547,094
Earnings before
interest, DD&A, taxes
and other non-cash
items $ 75,348 $ 117,132 $ 111,256 $ 49,757 $ 353,493
Funds flow from
operations $ 71,142 $ 112,869 $ 107,442 $ 47,187 $ 338,640
Net income (loss) $ 9,591 $ 28,935 $ 76,881 $ (421,457)$ (306,050)
----------------------------------------------------------------------------

Provident Midstream
Cash revenue $ 641,673 $ 662,315 $ 652,753 $ 513,860 $2,470,601
Earnings before
interest, DD&A,
taxes and other
non-cash items $ 75,987 $ 61,769 $ 37,339 $ 37,666 $ 212,761
Funds flow from
operations $ 59,252 $ 52,601 $ 32,537 $ 34,592 $ 178,982
Net income (loss) $ 15,516 $(290,230)$ 232,966 $ 359,166 $ 317,418
----------------------------------------------------------------------------

Operating
Oil and gas production
(continuing operations)
Crude oil (bpd) 12,287 12,494 12,805 12,307 12,473
Natural gas liquids
(bpd) 1,307 1,178 1,195 1,134 1,203
Natural gas (mcfd) 83,970 86,130 85,628 80,450 84,039
Oil equivalent (boed) 27,589 28,027 28,271 26,849 27,683
----------------------------------------------------------------------------

Average selling price
net of transportation
expense
(continuing operations)
(Cdn$)
Crude oil per bbl $ 75.06 $ 105.13 $ 102.66 $ 47.33 $ 82.79
(before realized
financial derivative
instruments)
Crude oil per bbl $ 71.54 $ 98.68 $ 97.61 $ 52.71 $ 80.36
(including realized
financial derivative
instruments)
Natural gas liquids
per barrel $ 72.85 $ 94.59 $ 91.72 $ 47.64 $ 76.88
Natural gas per mcf $ 7.61 $ 9.98 $ 8.60 $ 6.63 $ 8.23
(before realized
financial derivative
instruments)
Natural gas per mcf $ 7.74 $ 9.73 $ 8.45 $ 6.92 $ 8.23
(including realized financial derivative instruments)
----------------------------------------------------------------------------

Provident Midstream
Provident Midstream
NGL sales volumes
(bpd) 136,320 110,826 111,313 120,222 119,649
----------------------------------------------------------------------------
----------------------------------------------------------------------------


MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Provident is responsible for establishing and maintaining adequate internal control over financial reporting for the Trust. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, we have concluded that as of December 31, 2009, our internal control over financial reporting was effective.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The effectiveness of the Trust's internal control over financial reporting as of December 31, 2009, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

"Signed"

Thomas W. Buchanan, Chief Executive Officer

"Signed"

Mark N. Walker, Chief Financial Officer

Calgary, Alberta

March 11, 2010

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of Provident is responsible for the information included in this Annual Report. The financial statements have been prepared in accordance with accounting principles generally accepted in Canada and in accordance with accounting policies detailed in the notes to the financial statements. Where necessary, the statements include amounts based on management's informed judgments and estimates. Financial information in the Annual Report is consistent with that presented in the financial statements.

PricewaterhouseCoopers LLP, Chartered Accountants, appointed by the unitholders, have audited the financial statements and conducted a review of internal accounting policies and procedures to the extent required by generally accepted auditing standards, and performed such tests as they deemed necessary to enable them to express an opinion on the financial statements.

The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its responsibility for financial reporting and internal control. The Audit Committee is composed of three independent directors. The Audit Committee reviews the financial content of the Annual Report and reports its findings to the Board of Directors for its consideration in approving the financial statements.

"Signed"

Thomas W. Buchanan, Chief Executive Officer

"Signed"

Mark N. Walker, Chief Financial Officer

Calgary, Alberta

March 11, 2010


Independent Auditors' Report


To the Unitholders of Provident Energy Trust

We have completed integrated audits of Provident Energy Trust's (the "Trust") 2009 and 2008 consolidated financial statements and of its internal control over financial reporting as at December 31, 2009. Our opinions, based on our audits, are presented below.

Consolidated Financial statements

We have audited the accompanying consolidated balance sheets of Provident Energy Trust as at December 31, 2009 and December 31, 2008, and the related consolidated statements of operations and accumulated income, comprehensive and accumulated other comprehensive income and cash flows for each of the years then ended. These consolidated financial statements are the responsibility of the Trust's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits of the Trust's consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Trust as at December 31, 2009 and December 31, 2008 and the results of its operations and its cash flows for each of the years then ended in accordance with Canadian generally accepted accounting principles.

Internal control over financial reporting

We have also audited Provident Energy Trust's internal control over financial reporting as at December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Trust's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Trust's internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as at December 31, 2009 based on criteria established in Internal Control - Integrated Framework issued by the COSO.

"Signed"

Chartered Accountants
March 11, 2010



PROVIDENT ENERGY TRUST CONSOLIDATED BALANCE SHEETS
Canadian dollars (000s)

As at As at
December 31, December 31
2009 2008
----------------------------
Assets
Current assets
Cash and cash equivalents $ 7,187 $ 4,629
Accounts receivable 216,786 244,485
Petroleum product inventory 37,261 46,160
Prepaid expenses and other current assets 4,803 7,886
Financial derivative instruments (note 14) 5,314 16,708
----------------------------------------------------------------------------
271,351 319,868

Investments and other long term assets 18,733 14,218
Long-term financial derivative instruments
(note 14) - 735
Property, plant and equipment (note 6) 2,025,044 2,480,503
Intangible assets (note 7) 132,478 158,336
Goodwill (note 8) 100,409 100,409
----------------------------------------------------------------------------
$ 2,548,015 $ 3,074,069
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 221,417 $ 244,031
Cash distributions payable 13,468 20,088
Current portion of convertible debentures
(note 9) - 24,871
Financial derivative instruments (note 14) 86,441 13,693
----------------------------------------------------------------------------
321,326 302,683

Long-term debt - revolving term credit
facility (note 9) 264,776 504,685
Long-term debt - convertible debentures
(note 9) 240,486 236,123
Asset retirement obligation (note 10) 61,464 59,432
Long-term financial derivative instruments
(note 14) 103,403 58,420
Other long-term liabilities (note 12) 12,496 8,572
Future income taxes (note 13) 162,665 267,807

Unitholders' equity
Unitholders' contributions (note 11) 2,834,177 2,806,071
Convertible debentures equity component 15,940 17,198
Contributed surplus (note 11) 2,953 1,695
Accumulated other comprehensive loss - (2,183)
Accumulated income 337,014 426,034
Accumulated cash distributions (1,808,685) (1,612,468)
----------------------------------------------------------------------------
1,381,399 1,636,347
----------------------------------------------------------------------------
$ 2,548,015 $ 3,074,069
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


On behalf of the Board of Directors:
"Signed" "Signed"
M.H. (Mike) Shaikh, FCA Thomas W. Buchanan, FCA
Director Director


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
Canadian dollars (000s except per unit amounts)

Year ended
December 31,
----------------------------
2009 2008
----------------------------

Revenue
Revenue $ 1,891,983 $ 3,147,714
Realized loss on financial derivative
instruments (50,639) (130,019)
Unrealized (loss) gain on financial
derivative instruments (129,861) 221,468
----------------------------------------------------------------------------
1,711,483 3,239,163

Expenses
Cost of goods sold 1,305,191 2,206,427
Production, operating and maintenance 133,969 153,111
Transportation 35,467 37,120
Depletion, depreciation and accretion 312,709 343,315
Goodwill impairment (note 8) - 416,890
General and administrative (note 12) 68,348 63,281
Strategic review and restructuring (note 16) 12,257 3,632
Interest on bank debt 9,860 36,088
Interest and accretion on convertible
debentures 21,957 19,944
Foreign exchange loss (gain) and other 5,289 (20,828)
----------------------------------------------------------------------------
1,905,047 3,258,980
----------------------------------------------------------------------------

Loss from continuing operations before taxes (193,564) (19,817)
----------------------------------------------------------------------------

Capital tax expense 2,313 3,109
Current tax expense (recovery) 237 (4,529)
Future income tax recovery (note 13) (107,094) (29,765)
----------------------------------------------------------------------------
(104,544) (31,185)
----------------------------------------------------------------------------
Net (loss) income from continuing operations (89,020) 11,368
----------------------------------------------------------------------------
Net income from discontinued operations (note 17) - 146,024
----------------------------------------------------------------------------
Net (loss) income for the year (89,020) 157,392
----------------------------------------------------------------------------
Accumulated income, beginning of year $ 426,034 $ 268,642
----------------------------------------------------------------------------
Accumulated income, end of year $ 337,014 $ 426,034
----------------------------------------------------------------------------
Net (loss) income from continuing operations
per unit
- basic and diluted $ (0.34) $ 0.04
----------------------------------------------------------------------------
Net (loss) income per unit
- basic and diluted $ (0.34) $ 0.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF CASH FLOWS
Canadian dollars (000s)

Year ended
December 31,
----------------------------
2009 2008
----------------------------

Cash provided by operating activities
Net (loss) income for the year from
continuing operations $ (89,020) $ 11,368
Add (deduct) non-cash items:
Depletion, depreciation and accretion 312,709 343,315
Goodwill impairment (note 8) - 416,890
Non-cash interest expense and other 4,952 5,291
Non-cash unit based compensation expense
(recovery) (note 12) 6,326 (4,117)
Unrealized loss (gain) on financial
derivative instruments 129,861 (221,468)
Unrealized foreign exchange loss (gain) and
other 4,161 (3,892)
Loss on sale of investment 2,111 -
Future income tax recovery (107,094) (29,765)
----------------------------------------------------------------------------
264,006 517,622

Site restoration expenditures (5,399) (6,381)
Change in non-cash operating working capital 45,641 52,684
Cash provided by operating activities from
discontinued operations - 110,501
----------------------------------------------------------------------------
304,248 674,426
----------------------------------------------------------------------------

Cash used for financing activities
Decrease in long-term debt (265,245) (440,244)
Distributions to unitholders (196,217) (352,291)
Issue of trust units 28,106 55,510
Change in non-cash financing working capital (6,620) (5,028)
Financing activities from discontinued
operations - (47,511)
----------------------------------------------------------------------------
(439,976) (789,564)
----------------------------------------------------------------------------

Cash provided by investing activities
Capital expenditures (127,369) (246,947)
Acquisitions (note 4) (18,833) (25,843)
Proceeds on sale of assets (note 5) 305,720 1,662
Proceeds on sale of discontinued operations,
net of tax - 457,906
Decrease (increase) in investments 625 (792)
Change in non-cash investing working capital (21,857) (3,229)
Investing activities from discontinued
operations - (69,810)
----------------------------------------------------------------------------
138,286 112,947
----------------------------------------------------------------------------

Increase (decrease) in cash and cash
equivalents 2,558 (2,191)
Cash and cash equivalents, beginning of year 4,629 6,820
----------------------------------------------------------------------------
Cash and cash equivalents, end of year $ 7,187 $ 4,629
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental disclosure of cash flow
information
Cash interest paid including debenture
interest $ 27,826 $ 63,490
Cash taxes paid $ 3,199 $ 210,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


PROVIDENT ENERGY TRUST
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
COMPREHENSIVE INCOME
Canadian dollars (000s)

Year ended
December 31,
----------------------------
2009 2008
----------------------------

Net (loss) income $ (89,020) $ 157,392
----------------------------------------------------------------------------

Other comprehensive income, net of taxes
Foreign currency translation adjustments - 10,315
Reclassification adjustment for foreign
currency losses included in net income - 57,062
Reclassification adjustment of loss on
available-for-sale investment included
in net income 2,111 -
Unrealized gain (loss) on available-for-sale
investments (net of taxes) 72 (372)
----------------------------------------------------------------------------
2,183 67,005
----------------------------------------------------------------------------

Comprehensive (loss) income $ (86,837) $ 224,397
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated other comprehensive loss, beginning
of year (2,183) (69,188)
Other comprehensive income 2,183 67,005
----------------------------------------------------------------------------
Accumulated other comprehensive loss, end of
year $ - $ (2,183)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated income, end of year 337,014 426,034
Accumulated cash distributions, end of year (1,808,685) (1,612,468)
----------------------------------------------------------------------------
Retained earnings (deficit), end of year (1,471,671) (1,186,434)
Accumulated other comprehensive loss, end of
year - (2,183)
----------------------------------------------------------------------------
Total retained earnings (deficit) and
accumulated other comprehensive loss, end of
year $(1,471,671) $(1,188,617)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


Notes to the Consolidated

Financial Statements

(Tabular amounts in Cdn $ 000's, except unit and per unit amounts, and as noted)

December 31, 2009

1. Structure of the Trust

Provident Energy Trust (the "Trust" or "Provident") is an open-end unincorporated investment trust created under the laws of Alberta pursuant to a trust indenture dated January 25, 2001, amended from time to time. The beneficiaries of the Trust are the unitholders. The Trust was established to hold, directly and indirectly, all types of petroleum and natural gas and energy related assets, including without limitation facilities of any kind, oil sands interests, electricity or power generating assets and pipeline, gathering, processing and transportation assets. The Trust commenced operations March 6, 2001.

Cash flow is provided to the Trust from properties owned and operated by directly and indirectly owned subsidiaries of the Trust. Cash flow is paid to the Trust by way of royalty payments, interest payments, principal debt repayments and dividends or partnership distributions. The cash payments received by the Trust are subsequently distributed to the unitholders monthly.

2. Significant accounting policies

i) Principles of consolidation and investments

The consolidated financial statements include the accounts of the Trust, including the consolidated accounts of all wholly and partially owned subsidiaries, and are presented in accordance with Canadian generally accepted accounting principles. Investments subject to significant influence are accounted for using the equity method. Certain comparative figures have been reclassified to conform to the current year presentation.

ii) Financial instruments

All financial instruments, including derivatives, are recognized on the Trust's Consolidated Balance Sheet. Derivatives are measured at fair value with unrealized gains and losses reported in net income. Investments in equity instruments that are not quoted in an active market are recorded at cost. Investments in equity instruments that are quoted in an active market are measured at fair value, with reference to published price quotations, and unrealized gains and losses are reported in AOCI. The Trust's other financial instruments (accounts receivable, accounts payable and accrued liabilities, cash distributions payable, and long-term debt) are measured at amortized cost using the effective interest rate method. Transaction costs are included with the associated financial instruments and amortized accordingly.

iii) Cash and cash equivalents

Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with an original maturity of three months or less when purchased.

iv) Property, plant & equipment and intangible assets

The Trust follows the full cost method of accounting for oil and natural gas exploration and development activities. Costs associated with the acquisition and development of oil and natural gas reserves are capitalized and accumulated in one cost centre as all of the oil and natural gas assets are in Canada. Such costs include lease acquisition, lease rentals on non-producing properties, geological and geophysical activities, drilling of productive and non-productive wells, and tangible well equipment. Gains or losses on the disposition of oil and gas properties are not recognized unless the resulting change to the depletion and depreciation rate is 20 percent or more. All other property, plant and equipment, including midstream assets, are recorded at cost. Expenditures relating to renewals or betterments that improve the productive capacity or extend the life of property, plant and equipment are capitalized. Maintenance and repairs are expensed as incurred. Products required for line-fill and cavern bottoms are presented as part of property, plant and equipment and are stated at the lower of historic cost and net realizable value and are not depreciated.

a) Depletion, depreciation and accretion

The provision for depletion and depreciation for oil and natural gas assets is calculated using the unit-of-production method based on current production divided by the Trust's share of estimated total proved oil and natural gas reserve volumes, before royalties. Production and reserves of natural gas and associated liquids are converted at the energy equivalent ratio of 6,000 cubic feet of natural gas to one barrel of oil. In determining its depletion base, the Trust includes estimated future costs for developing proved reserves, and excludes estimated salvage values of tangible equipment and the cost of unproved properties.

Midstream facilities, including natural gas liquids storage facilities and natural gas liquids processing and extraction facilities are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 30 to 40 years. Intangible assets are amortized over the estimated useful lives of the assets, which range from 15 months to 15 years. Capital assets related to pipelines and office equipment are carried at cost and depreciated using the straight-line method over their economic lives.

b) Impairment

Oil and natural gas assets accounted for using the full cost method are subject to a ceiling test. The ceiling test calculation is performed by comparing the carrying value of the assets to the sum of the undiscounted proved reserve cash flows using future price estimates. If the carrying value is not recoverable, the assets are written down to their fair value. Fair value is determined by the future cash flows from the proved plus probable reserves discounted at the Trust's risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment.

For Midstream property, plant and equipment, and intangible assets, an impairment loss is recognized when the carrying amount exceeds the fair value.

v) Joint venture

Provident conducts many of its activities through joint ventures and the accounts reflect only Provident's proportionate interest in such activities.

vi) Inventory

Inventories of products are valued at the lower of average cost and net realizable value based on market prices.

vii) Goodwill

Goodwill, which represents the excess of cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed, is assessed at least annually for impairment. To assess impairment, the fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit's assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit's goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impaired amount. Goodwill is not amortized.

viii) Asset retirement obligation

Under the asset retirement obligation ("ARO") standard the fair value of a liability for an ARO is recorded in the period where a reasonable estimate of the fair value can be determined. When the liability is recorded, the carrying amount of the related asset is increased by the same amount of the liability. The asset recorded is depleted over the useful life of the asset. Additions to asset retirement obligations due to the passage of time are recorded as accretion expense. Actual expenditures incurred are charged against the obligation.

ix) Unit based compensation

The Trust uses the fair value method of valuing compensation expense associated with the Trust's unit option plan. Under the fair value method the amount to be recognized as expense is determined at the time the options are issued and is recognized in earnings over the vesting period of the options with a corresponding increase in contributed surplus.

The Trust has established other unit based compensation plans whereby notional units are granted to employees. The fair value of these notional units is estimated and recorded as non-cash unit based compensation (a component of general and administrative expenses). A portion relating to operational employees at field and plant locations is allocated to operating expense. The offsetting amount is recorded as accrued liabilities or other long-term liabilities. A realization of the expense and a resulting reduction in cash provided by operating activities occurs when a cash payment is made.

x) Trust unit calculations

The Trust applies the treasury stock method to determine the dilutive effect of trust unit rights and trust unit options. Under the treasury stock method, outstanding and exercisable instruments that will have a dilutive effect are included in per unit - diluted calculations, ordered from most dilutive to least dilutive.

The dilutive effect of convertible debentures is determined using the "if-converted" method whereby the outstanding debentures at the end of the period are assumed to have been converted at the beginning of the period or at the time of issue if issued during the year. Amounts charged to income or loss relating to the outstanding debentures are added back to net income for the diluted calculation. The units issued upon conversion are included in the denominator of per unit - basic calculations from the date of issue.

xi) Income taxes

Provident follows the liability method for calculating income taxes. Differences between the amounts reported in the financial statements of the corporate subsidiaries and their respective tax bases are applied to tax rates in effect to calculate the future tax liability. The effect of any change in income tax rates is recognized in the current period income.

The Trust is a taxable entity under the Income Tax Act (Canada) and is currently taxable only on income that is not distributed or distributable to the unitholders. As the Trust distributes all of its taxable income to the unitholders and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for current income taxes has been made in the Trust.

In 2007, the Canadian government enacted Bill C-52, Budget Implementation Act 2007. This bill contains legislation to tax publicly traded trusts, commencing in 2011. As a result of this legislation, the Trust records the future income tax effect of the temporary differences on its flow through entities that are expected to reverse subsequent to 2010.

xii) Revenue recognition

Revenue associated with the sales of Provident's natural gas, natural gas liquids ("NGLs") and crude oil owned by Provident is recognized when title passes from Provident to its customer.

Revenues associated with the services provided where Provident acts as agent are recorded on a net basis when the services are provided. Revenues associated with the sale of natural gas liquids storage services are recognized when the services are provided.

xiii) Foreign currency translation

The accounts of self-sustaining foreign operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates, while revenue and expenses are translated using average rates for the period. Translation gains and losses related to self-sustaining operations are deferred and included as a component of accumulated other comprehensive income. A proportionate amount of the gain or loss is recognized in net income when there has been a reduction in the net investment.

The accounts of integrated foreign operations are translated using the temporal method, under which monetary assets and liabilities are translated at the period-end exchange rate, other assets and liabilities at the historical rates, and revenues and expenses at the rates for the period, except depreciation, depletion and accretion which is translated on the same basis as the related assets. Translation gains and losses are included in income in the period in which they arise.

xiv) Use of estimates

The preparation of financial statements requires management to make estimates based on currently available information. Actual results could differ from those estimated. In particular, management makes estimates for amounts recorded for depletion and depreciation of the property, plant and equipment, financial derivative instruments, asset retirement obligation, unit based compensation and income taxes. The ceiling test uses factors such as estimated reserves, production rates, estimated future petroleum and natural gas prices and future costs. Due to the inherent limitations in metering and the physical properties of storage caverns and pipelines, the determination of precise volumes of natural gas liquids held in inventory at such locations is subject to estimation. Actual inventories of natural gas liquids can only be determined by draining of the caverns. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.

The estimation of oil and gas reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity prices, and the timing of future expenditures. The Trust expects reserve estimates to be revised based on the results of future drilling activity, testing, production levels, and economics of recovery based on cash flow forecasts.

3. Changes in accounting policies and practices

A. Changes in accounting policies

Goodwill and intangible assets

In the first quarter of 2009, the Trust adopted CICA Handbook section 3064 "Goodwill and Intangible assets" which supersedes section 3062 "Goodwill and other Intangible assets" and section 3450 "Research and Development". This new section established standards for the recognition, measurement and disclosure of goodwill and intangible assets. The adoption of this standard did not have a material impact on the Trust's consolidated financial statements.

B. Recent accounting pronouncements

International Financial Reporting Standards

During 2008, the Canadian Accounting Standards Board (AcSB) confirmed that publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) in place of Canadian GAAP for interim and annual reporting purposes. The required changeover date is for fiscal years beginning on or after January 1, 2011. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to Provident's adoption of IFRS, management's plan is subject to change based on new facts and circumstances.

Business combinations

In December of 2008, the CICA released Handbook section 1582 "Business Combinations", which replaces existing guidance under section 1581 "Business Combinations". The new standard is intended to converge with International Financial Reporting Standards. Under section 1582, the purchase price in a business combination is based on the fair value of shares exchanged at the market price on the acquisition date. Under the existing standard, the purchase price is based on the market price of shares over a reasonable period before and after the date of acquisition is agreed upon and announced. This new standard also requires that all acquisition costs be expensed as incurred. Currently, these costs may be capitalized as part of the purchase price. In addition, the new guidance addresses contingent liabilities, which will be required to be recognized at fair value on acquisition and subsequently remeasured at each reporting period until settled. Under the current standard, only contingent liabilities that are payable are recognized. This new section requires that negative goodwill to be recognized in earnings immediately rather than the existing standard of reducing non-current assets in the purchase price allocation. The new standard applies prospectively to business combinations on or after January 1, 2011 with earlier adoption permitted. The Trust is currently assessing the impact of the new standard.

4. Acquisitions

In August of 2009, the Trust purchased an additional 6.15 percent interest in the Sarnia fractionation and storage facility for a cash payment of $14.8 million and a deferred payment of $3.7 million for a facility enhancement planned for 2010. This increased the Trust's ownership in the Sarnia fractionator, effective August 1, 2009, to approximately 16.5 percent, enhancing propane-plus fractionation capacity in the Empress East system of the Midstream segment by approximately 7,400 barrels per day.

In 2008, Provident spent $25.8 million acquiring additional working interests in Provident Upstream operating areas.

5. Sale of assets

On September 30, 2009, Provident completed a sale of the operating areas of Southeast and Southwest Saskatchewan for net proceeds of $225.7 million and a separate sale of a minor property in the Lloydminster area for $12.8 million. The proceeds from the sales were credited against the full cost pool of oil and natural gas properties included in property, plant and equipment on the Trust's balance sheet. No gain or loss was recognized on these transactions.

On November 30, 2009, Provident completed a sale of its oil and natural gas assets in the Lloydminster area for net proceeds of $84.0 million. The sale proceeds are comprised of $67.0 million in cash and $17.0 million in equity of the acquirer. The proceeds from the sales were credited against the full cost pool of oil and natural gas properties included in property, plant and equipment on the Trust's balance sheet. No gain or loss was recognized on this transaction.



6. Property, plant and equipment

Accumulated
depletion and Net Book
As at December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Oil and natural gas properties $ 2,893,330 $ 1,657,694 $ 1,235,636
Midstream assets 883,840 113,820 770,020
Office equipment 47,174 27,786 19,388
----------------------------------------------------------------------------
Total $ 3,824,344 $ 1,799,300 $ 2,025,044
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated
depletion and Net Book
As at December 31, 2008 Cost depreciation value
----------------------------------------------------------------------------
Oil and natural gas properties $ 3,125,360 $ 1,411,997 $ 1,713,363
Midstream assets 827,172 87,674 739,498
Office equipment 44,678 17,036 27,642
----------------------------------------------------------------------------
Total $ 3,997,210 $ 1,516,707 $ 2,480,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Costs associated with unproved properties and major development projects excluded from costs subject to depletion as at December 31, 2009 totaled $24.7 million (December 31, 2008 - $93.1 million). Midstream assets include $43.9 million (2008 - $41.8 million) for products required for line-fill and cavern bottoms.

An impairment test calculation was performed on property, plant and equipment at December 31, 2009 in which the estimated undiscounted future net cash flows based on estimated future prices associated with the proved reserves exceeded the carrying amount of oil and gas property, plant and equipment.



The following table outlines prices used in the impairment test at December
31, 2009:

Oil Gas NGL
----------------------------------------------------------------------------

Year $/bbl $/mcf $/bbl
2010 $ 65.83 $ 6.04 $ 56.19
2011 $ 67.42 $ 6.78 $ 59.77
2012 $ 68.82 $ 7.20 $ 63.57
2013 $ 71.34 $ 7.53 $ 67.13
2014 $ 75.09 $ 7.91 $ 71.56
Thereafter (1) 2% 2% 2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Percentage change represents the increase in each year after 2014 to the
end of the reserve life.


7. Intangible assets

Accumulated Net Book
As at December 31, 2009 Cost amortization value
----------------------------------------------------------------------------

Midstream contracts and customer
relationships $ 183,100 61,862 $ 121,238
Other intangible assets -
Midstream 16,308 5,068 11,240
----------------------------------------------------------------------------
Total $ 199,408 $ 66,930 $ 132,478
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Accumulated Net Book
As at December 31, 2008 Cost amortization value
----------------------------------------------------------------------------

Midstream contracts and customer
relationships $ 183,100 37,255 $ 145,845
Other intangible assets -
Midstream 16,308 3,817 12,491
----------------------------------------------------------------------------
Total $ 199,408 $ 41,072 $ 158,336
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In 2009, the Trust recognized an impairment of $12.4 million on a specific Midstream marketing agreement. The Trust had been amortizing the agreement over a 15 year period. The Trust now expects that it is unlikely that the agreement will be renewed beyond March 31, 2011 on the same terms. In addition, during 2009, the volumes supplied to the Trust under this agreement were reduced as a result of certain property dispositions completed by the third party supplier. The impairment reflects a revision of the amortization period of this agreement and lower volume expectations for the remainder of the contract. The impairment was recognized in the statement of operations in depletion, depreciation, and accretion expense.

8. Goodwill

Goodwill represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. As at December 31, 2009 and 2008, the goodwill balance of $100.4 million related entirely to the Provident Midstream reporting unit. In 2008, it was determined that goodwill relating to the Provident Upstream business unit was impaired and a goodwill impairment of $416.9 million was recorded.

Goodwill is assessed for impairment at least annually, and if an impairment exists, it would be charged to income in the period in which the impairment occurs. The impairment test includes a comparison of the net book value of the Trust's assets, by reporting units, to the estimated fair value of the reporting unit. In 2009, Provident engaged the services of a third-party evaluator to assist in determining fair value. Valuation methodologies included discounted cash flow, a transaction-based approach and a market-based approach, using trading multiples. Goodwill is not amortized.

The Trust performed its annual goodwill impairment test in the fourth quarter of 2009 and indicated that the fair value of the Midstream reporting unit was in excess of the respective carrying value, therefore no write down of goodwill was required.



9. Long-term debt

As at As at
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Revolving term credit facility $ 264,776 $ 504,685
----------------------------------------------------------------------------
Convertible debentures 240,486 260,994
Current portion of convertible debentures - (24,871)
----------------------------------------------------------------------------
240,486 236,123
----------------------------------------------------------------------------
Total $ 505,262 $ 740,808
----------------------------------------------------------------------------
----------------------------------------------------------------------------


i) Revolving term credit facility

In 2009, the Trust's Canadian term credit facility was reduced by $95 million to $1,030 million (2008 - $1,125 million) due to the asset dispositions in the Upstream business unit. Based on the terms and conditions of the credit facility, Provident has access to $959 million of the total facility. The borrowing capacity of the term credit facility is re-measured quarterly. Provident may draw on the credit facility by way of Canadian prime rate loans, U.S. base rate loans, banker's acceptances, letters of credit or LIBOR loans. At December 31, 2009, $265.0 million was drawn on this facility.

The credit facility is with a syndicate of banks and is secured by the Trust's Midstream assets and Canadian oil and gas properties. The terms of the credit facility have a revolving three year period expiring on May 30, 2011.

At December 31, 2009 the effective interest rate of the outstanding credit facility was 1.4 percent (2008 - 3.3 percent). At December 31, 2009 Provident had $27.2 million in letters of credit outstanding (2008 - $35.2 million) that guarantee Provident's performance under certain commercial and other contracts.

ii) Convertible debentures

The Trust may elect to satisfy interest and principal obligations by the issue of trust units. For the year ended December 31, 2009, no debentures were converted to trust units at the election of debenture holders (2008 - face value of $0.1 million). Upon maturity in 2009, the Trust repaid $25.1 million to the holders of its 8.0 percent convertible debentures (2008 - $19.9 million to the holders of 8.75 percent convertible debentures), and the balance of the equity component of the 8.0 percent convertible debentures, amounting to $1.3 million (2008 - $1.0 million, related to the 8.75 percent convertible debentures that matured in 2008), was transferred to contributed surplus. Included in the carrying value at December 31, 2009 were financing costs of $3.0 million. At December 31, 2009, the fair value of the convertible debentures approximates the face value of the instruments. The following table details each outstanding convertible debenture.




Convertible As at As at
Debentures December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
($000s
except Conversion
conversion Carrying Face Carrying Face Price per
pricing) Value (1) Value Value (1) Value Maturity Date unit (2)
----------------------------------------------------------------------------
6.5%
Convertible
Debentures $146,028 $149,980 $143,212 $149,980 April 30, 2011 14.75
6.5%
Convertible
Debentures 94,458 98,999 92,911 98,999 Aug. 31, 2012 13.75
8.0%
Convertible
Debentures - - 24,871 25,109 July 31, 2009 12.00
----------------------------------------------------------------------------
$240,486 $248,979 $260,994 $274,088
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excluding equity component of convertible debentures
(2) The debentures may be converted into trust units at the option of the
holder of the debenture at the conversion price per unit


10. Asset retirement obligation

The Trust's asset retirement obligation is based on the Trust's net ownership in wells, facilities and the midstream assets and represents management's estimate of the costs to abandon and reclaim those wells, facilities and midstream assets as well as an estimate of the future timing of the costs to be incurred. Estimated cash flows have been discounted at the Trust's average credit-adjusted risk free rate of seven percent and an inflation rate of two percent has been estimated for future years.

The total undiscounted amount of future cash flows required to settle asset retirement obligations related to oil and gas operations is estimated to be $307.0 million (2008 - $348.5 million). Payments to settle oil and gas asset retirement obligations occur over the operating lives of the assets estimated to be over the next 47 years.

The total undiscounted amount of future cash flows required to settle the midstream asset retirement obligations is estimated to be $195.5 million (2008 - $166.1 million). The estimated costs include such activities as dismantling, demolition and disposal of the facilities as well as remediation and restoration of the surface land. Payments to settle the midstream asset retirement obligations are expected to occur subsequent to the closure of the facilities and related assets. Settlement of these obligations is expected to occur in 28 to 38 years.



Year ended December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008
----------------------------------------------------------------------------
Carrying amount, beginning of year $ 59,432 $ 43,886
Acquisitions 875 440
Change in estimate 10,992 15,759
Increase in liabilities incurred during the year 856 1,289
Settlement of liabilities during the year (5,399) (6,381)
Decrease in liabilities due to sale of assets (9,550) -
Accretion of liability 4,258 4,439
----------------------------------------------------------------------------
Carrying amount, end of year $ 61,464 $ 59,432
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. Unitholders' contributions

The Trust has authorized capital of an unlimited number of common voting trust units.

Trust units are redeemable at any time on demand by the holders thereof. Upon receipt of a redemption request by the Trust, the holder is entitled to receive a price per trust unit (the "Market Redemption Price") equal to the lesser of: (i) 90 percent of the simple average of the closing price of the trust units on the principal market on which the trust units are quoted for trading during the 10 trading day period commencing immediately after the date on which the trust units are surrendered for redemption; and (ii) the closing market price on the principal market on which the trust units are quoted for trading on the date that the trust units are surrendered for redemption.

The aggregate Market Redemption Price payable by the Trust in respect of any trust units surrendered for redemption during any calendar month shall be satisfied by way of a cash payment on the last day of the following month. Total cash payments for redemption are limited to an annual maximum of $250,000. Any excess over the maximum may be satisfied by distributing notes having an aggregate principal amount equal to the aggregate Market Redemption Price of the trust units tendered for redemption.

i) 2009 activity

In 2009, the Trust issued 5.2 million units related to Provident's DRIP program. The increase in unitholders' contributions associated with these activities was $28.1 million.

ii) 2008 activity

In 2008, the Trust issued 6.5 million units related to Provident's DRIP program, conversion of convertible debentures to units and units issued pursuant to Provident's Unit Option Plan. The increase in unitholders' contributions associated with these activities was $55.7 million.



Year ended December 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Number of Amount Number of Amount
Trust Units units (000s) units (000s)
----------------------------------------------------------------------------
Balance at beginning of
year 259,087,789 $ 2,806,071 252,634,773 $ 2,750,374
Issued pursuant to unit
option plan - - 191,448 1,790
Issued pursuant to the
distribution reinvestment
plan 4,913,799 25,732 5,600,810 50,667
To be issued pursuant to
the distribution
reinvestment plan 335,048 2,374 655,142 3,171
Debenture conversions - - 5,616 69
----------------------------------------------------------------------------
Balance at end of year 264,336,636 $ 2,834,177 259,087,789 $ 2,806,071
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The basic and diluted per trust unit amounts for 2009 were calculated based on the weighted average number of units outstanding of 261,540,079 (2008 - 255,177,346).



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

Year ended December 31,
2009 2008
----------------------------------------------------------------------------
Contributed surplus, beginning of the year $ 1,695 $ 801
Benefit on options exercised charged to
unitholders' contributions - (117)
Transferred from convertible debentures equity
component on maturity (see note 9) 1,258 1,011
----------------------------------------------------------------------------
Contributed surplus, end of year $ 2,953 $ 1,695
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. Unit based compensation

Restricted/Performance units

Certain employees of the Trust are granted restricted trust units (RTUs) and/or performance trust units (PTUs), both of which entitle the employee to receive cash compensation in relation to the value of a specific number of underlying notional trust units. The grants are based on criteria designed to recognize the long term value of the employee to the organization. RTUs vest evenly over a period of three years commencing at the grant date. Payments are made on the anniversary dates of the RTU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional units. PTUs vest three years from the date of grant and can be increased to a maximum of double the PTUs granted or a minimum of nil PTUs depending on the Trust's annualized total unitholder return.

The fair value estimate associated with the RTUs and PTUs is expensed in the statement of operations over the vesting period. At December 31, 2009, $12.2 million (2008 - $9.4 million) is included in accounts payable and accrued liabilities for this plan and $12.5 million (2008 - $8.6 million) is included in other long-term liabilities.



The following table reconciles the expense recorded for RTUs and PTUs.

Year ended December 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Cash general and administrative $ 8,213 $ 8,287
Non-cash unit based compensation
(included in general and administrative) 6,326 (4,117)
Strategic review and restructuring expenses
(note 16) 3,254 -
Production, operating and maintenance expense 607 266
----------------------------------------------------------------------------
$ 18,400 $ 4,436
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following table provides a continuity of the Trust's RTU and PTU plans:

RTUs PTUs
----------------------------------------------------------------------------
Opening balance January 1, 2008 849,672 2,478,037
Grants 559,301 1,092,697
Reinvested through notional distributions 144,838 423,750
Exercised (374,474) (551,062)
Cancelled (39,502) (43,092)
----------------------------------------------------------------------------
Ending balance December 31, 2008 1,139,835 3,400,330
Grants 911,263 1,813,312
Reinvested through notional distributions 218,283 569,119
Exercised (530,556) (1,602,482)
Cancelled (162,702) (221,157)
----------------------------------------------------------------------------
Ending balance December 31, 2009 1,576,123 3,959,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------

At December 31, 2009, all RTUs and PTUs have been valued at market prices.


13. Income taxes

The future income tax liability is comprised of the following:

Year ended December 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Property, plant and equipment in excess of tax
value $ 343,095 $ 378,663
Asset retirement obligation (15,502) (16,863)
Financial derivative instruments (55,240) (15,123)
Non-capital losses (105,811) (68,414)
Capital losses (49,114) (46,544)
Other (15,863) (22,294)
Valuation allowance 61,100 58,382
----------------------------------------------------------------------------
$ 162,665 $ 267,807
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Trust's valuation allowance applies to capital losses and other temporary differences that reduce the amount recorded to the expected amount to be realized.

The amount and timing of reversals of temporary differences depends on the Trust's future operating results, acquisitions and dispositions of assets and liabilities, and distribution policy. A significant change in any of the preceding assumptions could materially affect the Trust's estimate of the future tax liability.

The income tax provision differs from the expected amount calculated by applying the Trust's combined federal and provincial/state income tax rate of 29.51 percent (2008 - 30.96 percent) as follows:



Year ended December 31,
----------------------------------------------------------------------------
2009 2008
----------------------------------------------------------------------------
Expected income tax recovery, from continuing
operations $ (57,121) $ (6,135)
Increase (decrease) resulting from:
Goodwill impairment (permanent difference) - 124,992
Income of the Trust and other (50,237) (142,169)
Capital taxes 2,313 3,109
Witholding tax 1,172 (498)
Income tax rate differences (671) (10,484)
----------------------------------------------------------------------------
Income tax recovery, from continuing operations $ (104,544) $ (31,185)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


14. Financial instruments

Risk Management overview

Provident has a comprehensive Enterprise Risk Management program that is designed to identify and manage risks that could negatively affect its business, operations or results. The program's activities include risk identification, assessment, response, control, monitoring and communication.

Provident's Risk Management group executes the program with oversight from the Risk Management Committee ("RMC"), which provides regular reports to the Audit Committee and Board of Directors.

Provident has established and implemented Risk Management strategies, policies and limits that are monitored by Provident's Risk Management group. The derivative instruments the Trust uses include put and call options, costless collars, participating swaps, and fixed price products that settle against indexed referenced pricing. The purchase of put option contracts effectively create a floor price for the commodity, while allowing for full participation if prices increase. The purchase of call options allow for a commodity to be purchased at a fixed price at the option of the contract holder. Costless collars are contracts that provide a floor and a ceiling price and allowing participation within a set range. Participating swaps are contracts that provide a floor and also provide a ceiling for a certain percentage of the volume of the contract. Fixed price swaps are contracts that specify a fixed price at which a certain volume of product will be bought or sold at in the future.

The Risk Management group monitors risk exposure by generating and reviewing mark-to-market reports and counterparty credit exposure of Provident's outstanding derivative contracts. Additional monitoring activities include reviewing available derivative positions, regulatory changes and bank and analyst reports.

Provident's commodity price risk management program utilizes derivative instruments to provide for protection against lower commodity prices and product margins, as well as fluctuating interest and foreign exchange rates. Provident may also use derivative instruments to protect acquisition economics. The program is designed to stabilize cash flows in order to support cash distributions, capital programs and bank financing. The risk management strategy protects a percentage of Provident's oil and natural gas production against a decline in commodity prices. Provident seeks to use products that allow participation in a rising commodity price environment where possible and economic. The program provides price stabilization and protection of a percentage of inventory values and fractionation spread margin associated with the midstream business unit. As well, the Provident risk management strategy reduces foreign exchange risk due to the exposure arising from the conversion of U.S. dollars into Canadian dollars.

Fair Values

During 2009, CICA Handbook Section 3862, Financial Instruments - Disclosures ("Section 3862"), was amended to require disclosures about the inputs to fair value measurements, including their classification within a hierarchy that prioritizes the inputs to fair value measurement. The three levels of the fair value hierarchy are:

- Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

- Level 2 - Inputs other than quoted prices that are observable for the asset or liability either directly or indirectly; and

- Level 3 - Inputs that are not based on observable market data.

Provident's financial derivative instruments are the only financial instrument carried at fair value as at December 31, 2009 and are Level 2 instruments. The fair values of financial derivative instruments are determined by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, and volatility rates at the period-end dates. All of Provident's financial derivative instruments are executed in liquid markets.

Provident has also reflected management's assessment of nonperformance risk, including credit risk, into the fair value measurement. In evaluating the credit risk component of nonperformance risk, Provident has considered prevailing market credit spreads.



Total
As at December 31, Held for Available Loans and Other Carrying
2009 Trading for Sale Receivables Liabilities Value
----------------------------------------------------------------------------
Assets
Cash and cash
equivalents $ 7,187 $ - $ - $ - $ 7,187
Accounts receivable - - 216,786 - 216,786
Financial derivative
instruments
- current assets 5,314 - - - 5,314
Investments and other
long-term assets - 18,733 - - 18,733
----------------------------------------------------------------------------
$ 12,501 $ 18,733 $ 216,786 $ - $ 248,020
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities
Accounts payable and
accrued liabilities $ - $ - $ - $ 221,417 $ 221,417
Cash distributions
payable - - - 13,468 13,468
Financial derivative
instruments
- current liabilities 86,441 - - - 86,441
Long-term debt -
revolving term credit
facilities - - - 264,776 264,776
Long-term debt -
convertible
debentures - - - 240,486 240,486
Financial derivative
instruments
- long -term
liabilities 103,403 - - - 103,403
Other long-term
liabilities - - - 12,496 12,496
----------------------------------------------------------------------------
$ 189,844 $ - $ - $ 752,643 $ 942,487
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Except as disclosed in note 9 in connection with the convertible debentures, there were no significant differences between the carrying value of these financial instruments and their estimated fair value as at December 31, 2009.



The following table is a summary of the net financial derivative instruments
liability:

As at As at
December 31, December 31,
----------------------------------------------------------------------------
($ 000s) 2009 2008
----------------------------------------------------------------------------
Provident Upstream
Crude Oil $ 826 $ (12,521)
Natural Gas 1,545 (3,285)
Provident Midstream 181,890 70,476
Corporate 269 -
----------------------------------------------------------------------------
Total $ 184,530 $ 54,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Market Risk

Market risk is the risk that the fair value of a financial instrument will fluctuate because of changes in market prices. Market risk generally comprises of price risk, currency risk and interest rate risk.

a) Price risk

Commodity Price Risk Management Program

The decisions to enter into financial derivative positions and to execute the risk management strategy are made by senior officers of Provident who are also members of the RMC. The RMC receives input and commodity expertise from each business unit in the decision making process. Strategies are selected based on their ability to help Provident provide stable cash flow and distributions per unit rather than to simply lock in a specific price per barrel of oil or cubic foot of natural gas.

Upstream

Provident's risk management program employs derivative instruments, such as puts and participating swaps, to protect a floor level of Provident's revenue on a portion of the oil and gas sold. These instruments may enable Provident to retain various levels of participation to the extent oil and gas prices rise.

The major identified risks for the Upstream business line are commodity price volatility and market location and product quality differentials. Provident addresses these risks using a risk management program designed to protect a portion of its cash flow in order to support continued unitholder distributions, capital programs and bank financing.

Midstream

Commodity price volatility and market location differentials also affect the Midstream business. In addition, Midstream is exposed to possible price declines between the time Provident purchases natural gas liquid (NGL) feedstock and sells NGL products, and to narrowing frac spread ratios. Frac spread ratio is the ratio between crude oil prices and natural gas prices. There is also a differential between NGL product prices (propane, butane and condensate) and crude oil prices.

Provident responds to these risks using a risk management program that protects a margin or floor level of operating income on a portion of its NGL inventory and production, while retaining some ability to participate in a widening margin environment. For the longer-term, Provident uses crude oil contracts in place of NGLs. Provident may replace these contracts with NGL product contracts as market conditions allow. This strategy enables Provident to mitigate commodity price risk related to its NGL production business up to approximately four years into the future.

b) Currency risk

Provident's oil, natural gas and NGL sales are exposed to both positive and negative effects of fluctuations in the Canadian/U.S. exchange rate. Provident manages this exposure by matching a significant portion of the cash costs that it expects with revenues in the same currency. As well, Provident uses derivative instruments to manage the U.S. cash requirements of its business lines.

Provident regularly sells or purchases forward a portion of expected U.S. cashflows. Provident's strategy also manages the exposure it has to fluctuations in the U.S./Canadian dollar exchange rate when the underlying commodity price is based upon a U.S. index price. Provident may also use derivative products that provide for protection against a stronger Canadian dollar, while allowing it to participate if the currency weakens relative to the U.S. dollar.

c) Interest rate risk

The Trust's revolving term credit facilities bear interest at a floating rate. Using debt levels as at December 31, 2009, an increase/decrease of 50 basis points in the lender's base rate would result in an increase/decrease of annual interest expense of approximately $1.3 million. The Trust has mitigated this risk by entering into interest rate financial derivative contracts for a portion of the outstanding long term debt. The contracts settle against Canadian Bankers Acceptance CDOR rates.

Financial derivative sensitivity analysis

The following table shows the impact on unrealized gain (loss) on financial derivative instruments if the underlying risk variables of the financial derivative instruments changed by a specified amount, with other variables held constant.



($ 000s) + Change - Change
----------------------------------------------------------------------------
Provident Upstream
Crude Oil (WTI +/- $10.00 per bbl) $ (259) $ 490
Natural Gas (AECO +/- $1.00 per gj) (1,326) 2,915
Foreign exchange (FX rate +/- $0.01) (202) 203
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Provident Midstream
Frac spread related
Crude Oil (WTI +/- $10.00 per bbl) $(74,887) $ 75,054
Natural Gas (AECO +/- $1.00 per gj) 46,731 (46,565)
NGL's (includes propane,
butane) (Belvieu +/- US $0.15 per gal) (1,488) 1,487
Foreign Exchange ($U.S.
vs $Cdn) (FX rate +/- $ 0.01) (1,386) 1,385

Inventory, margin and
other
Crude Oil (WTI +/- $10.00 per bbl) (4,389) 4,388
NGL's (includes propane,
butane, natural
gasoline) (Belvieu +/- US $0.15 per gal) 2,633 (2,632)
Electricity (AESO +/- $5.00 per MW/h 437 (437)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate
Interest Rate (Rate +/- 50 basis points) $ 1,765 $ (1,765)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Liquidity Risk

Liquidity risk is the risk the Trust will not be able to meet its financial obligations as they come due. The Trust's approach to managing liquidity risk is to ensure that it always has sufficient cash and credit facilities to meet its obligations when due, without incurring unacceptable losses or damage to the Trust's reputation.

Management typically forecasts cash flows for a period of twelve months to identify financing requirements. These requirements are then addressed through a combination of committed and demand credit facilities and access to capital markets, as discussed in note 15.



The following table outlines the timing of the cash outflows relating to
financial liabilities.

As at December 31, 2009 Payment due by period
----------------------------------------------------------------------------
Less than 1 to 3 3 to 5
($000s) Total 1 year years years
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 221,417 $ 221,417 $ - $ -
Cash distributions payable 13,468 13,468 - -
Financial derivative instruments -
current 86,441 86,441 - -
Long-term debt - revolving term
credit facilities (1) 270,256 3,710 266,546 -
Long-term debt - convertible
debentures (2) 279,138 16,184 262,954 -
Long-term financial derivative
instruments 103,403 - 101,578 1,825
Other long-term liabilities 12,496 - 12,496 -
----------------------------------------------------------------------------
Total $ 986,619 $ 341,220 $ 643,574 $ 1,825
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The terms of the Canadian credit facility have a revolving three year
period expiring on May 30, 2011.
(2) Includes associated interest and principal payments.


Credit Risk

Provident's Credit Policy governs the activities undertaken to mitigate the risks associated with counterparty (customer) non-payment. The Policy requires a formal credit review for counterparties entering into a commodity contract with Provident. This review determines an approved credit limit. Activities undertaken include regular monitoring of counterparty exposures to approved credit limits, financial review of all active counterparties, utilizing master netting arrangements and International Swap Dealers Association (ISDA) agreements and obtaining financial assurances where warranted. Financial assurances include guarantees, letters of credit and cash. In addition, Provident has a diversified base of creditors.

Substantially all of the Trust's accounts receivable are due from customers and joint venture partners in the oil and gas and midstream services and marketing industries and are subject to credit risk. The Trust partially mitigates associated credit risk by limiting transactions with certain counterparties to limits imposed by the Trust based on management's assessment of the creditworthiness of such counterparties. The carrying value of accounts receivable reflects management's assessment of the associated credit risks.

Settlement of financial derivative contracts

The following table summarizes the impact of financial derivative contracts settled during the years ended December 31, 2009 and 2008 that are included in realized loss on financial derivative instruments.




Realized gain (loss) on financial Year ended December 31,
derivative instruments 2009 2008
----------------------------------------------------------------------------
($ 000s except volumes) Volume (1) Volume (1)
----------------------------------------------------------------------------
Provident Upstream
Crude Oil $ 8,052 0.8 $ (11,113) 1.6
Natural gas 8,336 6.1 11 10.9

Provident Midstream
Crude Oil 29,007 4.1 (135,602) 4.2
Natural gas (95,188) 23.0 (16,978) 26.8
NGL's (includes propane, butane) 5,072 0.8 25,902 2.3
Foreign Exchange (3,505) - 5,387 -
Electricity (1,276) - 2,374 -

Corporate
Interest Rate (2) (1,137) - - -
----------------------------------------------------------------------------

Realized loss on financial
derivative instruments $(50,639) - $(130,019)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents aggregate net volumes that were bought/sold
over the periods. Crude oil and NGL volumes are listed in millions of
barrels and natural gas is listed in millions of gigajoules.
(2) Realized gains and losses on corporate related interest rate contracts
are allocated to the reporting segments for segmented reporting
purposes.


In addition, the Trust recorded a loss of $0.2 million (2008 - $26.8 million gain) on corporate foreign exchange contracts. The amounts are included in foreign exchange loss (gain) and other on the consolidated statement of operations and are allocated to the reporting segments.



The contracts in place at December 31, 2009 are summarized in the following
tables:

Provident Upstream

Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2010 Natural 13,359 Gjpd Puts Cdn $4.79 per gj (3) January 1 -
Gas December 31
5,000 Gjpd Participating Swap Cdn $4.50 per gj April 1 -
(Average Participation 75% above October 31
the floor price)
Crude 1,200 Bpd Puts US $60.00 per bbl (5) January 1 -
Oil December 31
Foreign Sell US $1,691,667 per month @ January 1 -
Exchange 1.115 (14) December 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Provident Midstream

Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------
2010 Crude Oil (1,588) Bpd US $77.75 per bbl (11) January 1 -
March 31
6,272 Bpd Cdn $73.19 per bbl January 1 -
December 31
500 Bpd US $66.65 per bbl January 1 -
December 31
1,000 Bpd US $71.97 per bbl (13) January 1 -
December 31
1,750 Bpd Costless Collar US $61.63 January 1 -
floor, US $66.56 ceiling December 31
462 Bpd Participating Swap Cdn January 1 -
$76.98 per bbl (Average December 31
Participation 37% above
the floor price)
857 Bpd Participating Swap US January 1 -
$74.88 per bbl (Average December 31
Participation 48% above
the floor price)
Natural Gas (48,315) Gjpd Cdn $7.77 per gj January 1 -
December 31
(5,756) Gjpd Participating Swap Cdn $7.77 January 1 -
per gj (Average December 31
Participation 28% below
the ceiling price)
Propane 875 Bpd US $0.75 per gallon (7) January 1 -
March 31
1,683 Bpd US $1.076 per gallon (6) (11) January 1 -
March 31
1,695 Bpd US $1.155 per gallon (6) (12) January 1 -
February 28
Natural (1,000) Bpd US $1.41 per gallon (9) (13) January 1 -
Gasoline December 31
Normal (1,500) Bpd US $0.76 per gallon (8) (13) January 1 -
Butane March 31
833 Bpd US $1.353 per gallon (8) (11) January 1 -
March 31
Electricity (10) MW/hpd Cdn $47.475 per MW/h (10) January 1 -
December 31
Foreign Sell US $826,875 per month January 1 -
Exchange @ 1.1578 (14) March 31
Sell US $4,773,059 per month January 1 -
@ 1.1110 (14) December 31
Sell US $582,821 per month January 1 -
@ 1.0159 (14) August 31
Sell US $1,420,921 per month July 1 -
@ 0.9781 (14) August 31
Sell US $587,903 per month July 1 -
@ 1.0165 (14) November 30
Sell US $2,254,103 per month September 1 -
@ 0.9578 (14) October 31
Sell US $2,394,058 per month September 1 -
@ 1.0154 (14) November 30
Sell US $629,673 per month November 1 -
@ 1.0165 (14) December 31

2011 Crude Oil 5,534 Bpd Cdn $71.73 per bbl January 1 -
December 31
1,005 Bpd Costless Collar US $60.64 January 1 -
floor, US $73.45 ceiling September 30
416 Bpd Participating Swap Cdn October 1 -
$84.38 per bbl (Average December 31
Participation 25% above
the floor price)
250 Bpd Participating Swap US January 1 -
$63.00 per bbl (Average December 31
Participation 64% above
the floor price)
Natural Gas (41,747) Gjpd Cdn $7.32 per gj January 1 -
December 31
(2,337) Gjpd Participating Swap Cdn October 1 -
$8.28 per gj (Average December 31
Participation 25% below
the ceiling price)
Foreign Sell US $479,063 per month January 1 -
Exchange @ 0.9725 (14) December 31
Sell US $980,417 per month January 1 -
@ 1.0805 (14) June 30
Sell US $3,588,000 per month July 1 -
@ 1.0918 (14) September 30

2012 Crude Oil 3,637 Bpd Cdn $72.57 per bbl January 1 -
December 31
1,445 Bpd Participating Swap Cdn February 1 -
$85.19 per bbl (Average December 31
Participation 27% above
the floor price)
1,352 Bpd Participating Swap US March 1 -
$72.22 per bbl (Average December 31
Participation 51% above
the floor price)
Natural Gas (25,717) Gjpd Cdn $7.24 per gj January 1 -
December 31
(9,578) Gjpd Participating Swap Cdn February 1 -
$8.55 per gj (Average December 31
Participation 28% below
the ceiling price)
Foreign Sell US $2,016,783 per month March 1 -
Exchange @ 1.0119 (14) March 31
Sell US $1,041,721 per month April 1 -
@ 0.9413 (14) October 31
Sell US $681,260 per month May 1 -
@ 0.9850 (14) October 31
Sell US $1,437,986 per month July 1 -
@ 0.9659 (14) December 31
Sell US $1,634,227 per month October 1 -
@ 0.9829 (14) December 31
Sell US $1,420,538 per month November 1 -
@ 0.9995 (14) December 31

2013 Crude Oil 250 Bpd Cdn $75.32 per bbl January 1 -
January 31
Participating Swap Cdn January 1 -
1,250 Bpd $84.90 per bbl (Average March 31
Participation 25% above
the floor price)
758 Bpd Participating Swap US January 1 -
$85.62 per bbl (Average March 31
Participation 30% above
the floor price)
Natural Gas (7,025) Gjpd Cdn $7.19 per gj January 1 -
January 31
(9,524) Gjpd Participating Swap Cdn January 1 -
$8.87 per gj (Average March 31
Participation 22% below
the ceiling price)
Foreign Sell US $1,651,990 per month January 1 -
Exchange @ 0.9829 (14) January 31
Sell US $1,397,250 per month January 1 -
@ 0.9995 (14) March 31
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Corporate
Volume Effective
Year Product (Buy)/Sell Terms Period
----------------------------------------------------------------------------

Interest $200,000,000 Notional (Cdn$) Pay Average Fixed Jan 1 2010 -
Rate rate of 1.1885% (15) May 31 2011
$ 50,000,000 Notional (Cdn$) Pay Average Fixed Jan 1 2010 -
rate of 1.1950% (16) May 31 2011

----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The above table represents a number of transactions entered into over an
extended period of time.
(2) Natural gas contracts are settled against AECO monthly index.
(3) Natural gas put options provide a "floor" price for the gas quantities
contracted. Floor price is strike less premium. Provident receives
market price above the "floor".
(4) Crude Oil contracts are settled against NYMEX WTI calendar average.
(5) Crude oil put options provide a "floor" price for the oil quantities
contracted. Floor price is strike less premium. Provident receives
market price above the "floor".
(6) Propane contracts are settled against Belvieu C3 TET.
(7) Propane contracts are settled against Conway In-Well C3.
(8) Normal Butane contracts are settled against Belvieu NC4 NON-TET.
(9) Natural Gasoline contracts are settled against Belevieu NON-TET Natural
Gasoline.
(10) Electricity contracts are settled against the hourly price of
electricity as published by the AESO in $/MWh.
(11) Conversion of Crude Oil BTU contracts to liquids.
(12) Midstream inventory price stabilization contracts.
(13) Midstream buy/sell contracts.
(14) US Dollar forward contracts are settled against the Bank of Canada noon
rate average. Selling notional US dollars for Canadian dollars at a
fixed exchange rate results in a fixed Canadian dollar price for the
hedged commodity.
(15) Interest rate forward contract settles quarterly against 1M CAD BA CDOR
interest rate.
(16) Interest rate forward contract settles quarterly against 3M CAD BA CDOR
interest rate.


15. Capital management

Provident considers its total capital to be comprised of net debt and Unitholders' Equity. Net debt is comprised of long-term debt and working capital surplus, excluding balances for the current portion of financial derivative instruments. The balance of these items at December 31, 2009 and December 31, 2008 were as follows:



As at As at
December 31, December 31,
----------------------------------------------------------------------------
($000s) 2009 2008
----------------------------------------------------------------------------
Working capital surplus (1) $ (31,152) $ (39,041)
Long-term debt (including current portion) 505,262 765,679
----------------------------------------------------------------------------
Net debt 474,110 726,638
Unitholders' equity 1,381,399 1,636,347
----------------------------------------------------------------------------
Total capitalization $ 1,855,509 $ 2,362,985
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net debt to total capitalization 26% 31%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The working capital surplus excludes balances for the current portion of
financial derivative instruments.


Provident's primary objective for managing capital is to maximize long-term Unitholder value by:

- providing an appropriate return to unitholders relative to the risk of Provident's underlying assets; and

- ensuring financing capacity for Provident's internal development opportunities and acquisitions of energy related assets that are expected to add value to our Unitholders.

Provident makes adjustments to its capital structure based on economic conditions and the Trust's planned requirements. Provident has the ability to adjust its capital structure by issuing new equity or debt, controlling the amount it returns to unitholders, and making adjustments to its capital expenditure program. Provident relies on cash flow from operations, external lines of credit and access to equity markets to fund capital programs and acquisitions.

The Trust is subject to certain capital growth restrictions as a result of the Canadian trust tax legislation passed in June 2007 and effective January 1, 2011. The restrictions provide that "normal growth" would include equity growth within certain "safe harbour" limits, measured by reference to the Trust's market capitalization as of the end of trading on October 31, 2006. These rules limit the amount of Unitholders' capital that can be issued by the Trust in 2010. If the maximum equity growth allowed is exceeded, the Trust may be subject to trust taxation prior to 2011. The Trust has $2.2 billion remaining under these safe harbour limits for normal growth capital allowed in 2010.

16. Strategic review and restructuring expenses

In February, 2008 the Trust announced a strategic review process to evaluate all of Provident's business segments. During the review, it was determined that the sale of the United States oil and natural gas production (USOGP) business was an important step in the process (see note 17). In 2009, Provident completed an internal reorganization to improve the efficiency and competitiveness of the businesses and identified certain non-strategic assets for divestiture (see notes 5 and 19). The reorganization and divestitures resulted in staff reductions at all levels of the organization, including senior management. For the year ended December 31, 2009, strategic review and restructuring costs were $12.3 million (2008 - $3.6 million). The costs are comprised primarily of severance, consulting and legal costs.

17. Discontinued operations (USOGP)

Effective in the first quarter of 2008, Provident's USOGP business was accounted for as discontinued operations. The USOGP business was sold in June and August of 2008.

Quicksilver Resources Inc. ("Quicksilver") filed a lawsuit on October 31, 2008 against BreitBurn Energy Partners, L.P. (the MLP), certain of its directors (including three Provident nominees), and Provident. The MLP was part of the USOGP business. The claim relates to a transaction between the MLP and Quicksilver and certain other MLP matters. Quicksilver alleges, among other things, that it was induced to enter into a contribution agreement pursuant to which it contributed assets to the MLP by false representations as to Provident's relationship with the MLP. The transaction involved the issuance by the MLP to Quicksilver of approximately U.S. $700 million of units of the MLP. In February of 2010, Provident agreed to settle all existing litigation with Quicksilver. The cost of settlement is covered by insurance.



The following table shows information about net income from USOGP.

Net income from discontinued operations Year ended December 31,
----------------------------------------------------------------------------
Canadian dollars (000's) 2009 2008
----------------------------------------------------------------------------
Revenue $ - $ 303,146
----------------------------------------------------------------------------
Loss from discontinued operations before
taxes, non-controlling interests and impact
of sale of discontinued operations - (237,233)
Gain on sale of discontinued operations - 263,618
Foreign exchange loss related to sale of
discontinued operations - (57,062)
Current tax expense - (178,708)
Future income tax recovery - 151,975
Non-controlling interests - 203,434
----------------------------------------------------------------------------
Net income from discontinued operations $ - $ 146,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------


18. Commitments

Provident has entered into operating leases for offices that extend through June 2022. In relation to the Midstream segment, Provident is committed to minimum lease payments under the terms of various tank car leases for five years. Additionally, under an arrangement to use a third party interest in the Younger Plant, Provident has a commitment to make payments calculated with reference to a number of variables including return on capital.



Future minimum lease payments under non-cancelable operating leases are as
follows:

As at December 31, 2009 Payment due by period
----------------------------------------------------------------------------
Less than
($ millions) Total 1 year 1 to 3 years 3 to 5 years
----------------------------------------------------------------------------
Operating Leases
Office leases $ 29.7 $ 5.9 $ 11.5 $ 12.3
Rail tank cars 22.0 8.3 11.1 2.6
Younger plant 18.1 3.9 7.4 6.8
----------------------------------------------------------------------------
Total $ 69.8 $ 18.1 $ 30.0 $ 21.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


19. Subsequent event

Upstream asset disposition

On March 1, 2010, the Trust closed its previously announced sale of oil and natural gas assets in West Central Alberta for cash consideration of $177 million, after closing adjustments. The transaction had an effective date of October 1, 2009. The proceeds from the sale will be credited against the full cost pool of oil and natural gas properties included in property, plant and equipment on the Trust's balance sheet. No gain or loss will be recognized on this transaction. On closing, Provident's Canadian term credit facility and Provident's access to the total facility were reduced by $50 million to $980 million and $909 million respectively.

20. Segmented information

The Trust's business activities are conducted through two business segments: Canadian oil and natural gas production ("Provident Upstream") and Provident Midstream.

Provident Upstream includes exploitation, development and production of crude oil and natural gas reserves. Provident Midstream includes processing, extraction, transportation, loading, storage and marketing of natural gas liquids.

Geographically the Trust operates in Canada in the Upstream business segment and in Canada and the USA in the Midstream business.



Year ended December 31, 2009
------------------------------------------
Provident Provident
Upstream Midstream (1) Total
----------------------------------------------------------------------------

Revenue
Gross production revenue $ 303,067 $ - $ 303,067
Royalties (41,575) - (41,575)
Product sales and service
revenue - 1,630,491 1,630,491
Realized gain (loss) on
financial derivative
instruments 16,104 (66,743) (50,639)
----------------------------------------------------------------------------
277,596 1,563,748 1,841,344
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 1,305,191 1,305,191
Production, operating and
maintenance 119,437 14,532 133,969
Transportation 11,482 23,985 35,467
Foreign exchange loss (gain)
and other (674) 1,802 1,128
General and administrative 30,725 31,297 62,022
Strategic review and
restructuring 7,633 4,624 12,257
----------------------------------------------------------------------------
168,603 1,381,431 1,550,034
----------------------------------------------------------------------------

Earnings before interest,
taxes, depletion, depreciation,
accretion and other non-cash
items 108,993 182,317 291,310
Other revenue
Unrealized (loss) gain on
financial derivative
instruments (18,251) (111,610) (129,861)
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 259,545 53,164 312,709
Goodwill impairment - - -
Interest on bank debt 2,465 7,395 9,860
Interest and accretion on
convertible debentures 5,489 16,468 21,957
Unrealized foreign exchange
loss (gain) and other 66 4,095 4,161
Non-cash unit based
compensation expense (recovery) 3,101 3,225 6,326
Capital tax expense 2,313 - 2,313
Current tax expense (recovery) 12 225 237
Future income tax (recovery)
expense (71,682) (35,412) (107,094)
----------------------------------------------------------------------------
201,309 49,160 250,469
----------------------------------------------------------------------------

Net (loss) income for the year $ (110,567) $ 21,547 $ (89,020)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Provident Midstream segment is product sales and service
revenue of $202.8 million associated with U.S. midstream operations.


As at and for the year ended
December 31, 2009
------------------------------------------
Provident Provident
Upstream Midstream Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and equipment
net $ 1,248,238 $ 776,806 $ 2,025,044
Intangible assets - 132,478 132,478
Goodwill - 100,409 100,409
Capital expenditures
Capital Expenditures 90,737 36,632 127,369
Acquisitions 333 18,500 18,833
Cash proceeds on sale of
assets 305,720 - 305,720
Working capital
Accounts receivable 37,582 179,204 216,786
Petroleum product inventory - 37,261 37,261
Accounts payable and accrued
liabilities 71,078 150,339 221,417
Long-term debt - revolving term
credit facilities 66,194 198,582 264,776
Long-term debt - convertible
debentures 60,121 180,365 240,486
Asset retirement obligation 42,264 19,200 61,464
Financial derivative
instruments liability $ 2,438 $ 182,092 $ 184,530
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Year ended December 31, 2008
-------------------------------------------
Provident Provident
Upstream Midstream (1) Total
----------------------------------------------------------------------------

Revenue
Gross production revenue $ 681,336 $ - $ 681,336
Royalties (123,140) - (123,140)
Product sales and service
revenue - 2,589,518 2,589,518
Realized gain (loss) on
financial derivative
instruments (11,102) (118,917) (130,019)
----------------------------------------------------------------------------
547,094 2,470,601 3,017,695
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Expenses
Cost of goods sold - 2,206,427 2,206,427
Production, operating and
maintenance 138,173 14,938 153,111
Transportation 16,320 20,800 37,120
Foreign exchange loss (gain) and
other 2,917 (19,853) (16,936)
General and administrative 34,242 33,845 68,087
Strategic review and
restructuring 1,949 1,683 3,632
----------------------------------------------------------------------------
193,601 2,257,840 2,451,441
----------------------------------------------------------------------------

Earnings before interest, taxes,
depletion, depreciation,
accretion and other non-cash
items 353,493 212,761 566,254
Other revenue
Unrealized (loss) gain on
financial derivative instruments 30,230 191,238 221,468
----------------------------------------------------------------------------

Other expenses
Depletion, depreciation and
accretion 304,909 38,406 343,315
Goodwill impairment 416,890 - 416,890
Interest on bank debt 9,022 27,066 36,088
Interest and accretion on
convertible debentures 4,986 14,958 19,944
Unrealized foreign exchange loss
(gain) and other 4,296 (8,188) (3,892)
Non-cash unit based compensation
expense (recovery) (2,199) (1,918) (4,117)
Management charge - discontinued
operations (689) - (689)
Capital tax expense 3,109 - 3,109
Current tax expense (recovery) (212) (4,317) (4,529)
Future income tax (recovery)
expense (50,339) 20,574 (29,765)
----------------------------------------------------------------------------
689,773 86,581 776,354
----------------------------------------------------------------------------

Net (loss) income for the year
from continuing operations $ (306,050) $ 317,418 $ 11,368
Net income from discontinued
operations (note 17) 146,024
----------------------------------------------------------------------------
Net income for the year $ 157,392
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Included in the Midstream segment is product sales and service revenue
of $307.9 million associated with U.S. operations.


As at and for the year ended
December 31, 2008
-------------------------------------------
Provident Provident
Upstream Midstream Total
----------------------------------------------------------------------------
Selected balance sheet items
Capital assets
Property, plant and equipment
net $ 1,731,331 $ 749,172 $ 2,480,503
Intangible assets - 158,336 158,336
Goodwill - 100,409 100,409
Capital expenditures
Capital Expenditures 209,147 37,800 246,947
Acquisitions 25,843 - 25,843
Cash proceeds on sale of assets 1,662 - 1,662
Goodwill impairment (416,890) - (416,890)
Working capital
Accounts receivable 60,839 183,646 244,485
Petroleum product inventory - 46,160 46,160
Accounts payable and accrued
liabilities 114,152 129,879 244,031
Long-term debt - revolving term
credit facilities 126,171 378,514 504,685
Long-term debt - convertible
debentures 59,031 177,092 236,123
Asset retirement obligation 43,651 15,781 59,432
Financial derivative instruments
(asset) liability $ (15,806) $ 70,476 $ 54,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------


21. Reconciliation of financial statements to United States generally accepted accounting principles (U.S. GAAP)

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP"). Any differences in accounting principles to U.S. GAAP as they pertain to the accompanying financial statements are not material except as described below. All adjustments are measurement differences. Disclosure items are not noted.



Consolidated Statements of Earnings - U.S. GAAP

For the year ended December 31, (Cdn $000s) 2009 2008
----------------------------------------------------------------------------

Net (loss) income as reported $ (89,020) $ 157,392
Adjustments
Depletion, depreciation and accretion (a) 173,581 79,558
Depletion, depreciation and accretion - ceiling
test impairment (a) - (813,983)
Goodwill impairment (g) - 416,890
Future income tax (expense) recovery (a) (b) (54,706) 180,161
Gain on sale of discontinued operations - (8,983)
Other adjustments to net income from discontinued
operations - 2,976
----------------------------------------------------------------------------
Net income - U.S. GAAP $ 29,855 $ 14,011
Other comprehensive income 2,183 67,005
----------------------------------------------------------------------------
Comprehensive income 32,038 81,016
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) from continuing operations per
unit - basic and diluted $ 0.11 $ (0.49)
Net income per unit - basic and diluted $ 0.11 $ 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Condensed Consolidated Balance Sheet

As at December 31, (Cdn$ 000s) 2009 2008
----------------------------------------------------------------------------
Canadian Canadian
GAAP U.S. GAAP GAAP U.S. GAAP
----------------------------------------------------------------------------
Assets
Deferred financing
charges (e) $ - $ 2,956 $ - $ 4,921
Property, plant and
equipment (a) 2,025,044 916,683 2,480,503 1,198,561
Goodwill (g) 100,409 517,299 100,409 517,299

Liabilities and unitholders'
equity
Current portion of convertible
debentures (d) (e) - - 24,871 24,934
Long-term debt - revolving
term credit facilities (e) 264,776 264,776 504,685 504,912
Long-term debt - convertible
debentures (d) (e) 240,486 243,442 236,123 240,754
Future income tax liability
(asset) (a) (b) 162,665 (119,168) 267,807 (68,733)
Units subject to
redemption (f) - 1,855,405 - 1,381,352
Unitholders' equity (f) (g) 1,381,399 (883,644) 1,636,347 (273,517)
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(a) Under the Canadian cost recovery ceiling test the recoverability of the oil and natural gas assets is tested by comparing the carrying value of the assets to the sum of the undiscounted proved reserve cash flows expected using future price estimates. If the carrying value is not recoverable, the assets are written down to their fair value determined by comparing the future cash flows from the proved plus probable reserves discounted at the Trust's risk free interest rate. Any excess carrying value of the assets on the balance sheet above fair value would be recorded in depletion, depreciation and accretion expense as a permanent impairment. Under U.S. GAAP, companies utilizing the full cost method of accounting for oil and natural gas activities perform a ceiling test using discounted future net revenue from proved oil and natural gas reserves discounted at 10 percent. For 2009, prices used in the U.S. GAAP ceiling tests are those that represent an average of the prices on the first day of each month in the calendar year. For 2008, prices used in the U.S. GAAP ceiling test were those in effect at the end of 2008. The amounts recorded for depletion and depreciation have been adjusted in the periods as a result of differences in write down amounts recorded pursuant to U.S. GAAP compared to Canadian GAAP.

In computing its consolidated net earnings for U.S. GAAP purposes, the Trust recorded no additional depletion in 2009 (2008 - $814.0 million) and no additional future income tax recovery (2008 - $214.3 million) as a result of the application of the ceiling test.

(b) The Canadian liability method of accounting for income taxes in CICA handbook Section 3465 "Income taxes" is similar to the requirements for U.S. GAAP, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in Provident's financial statements or tax returns. Pursuant to U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates. In addition, U.S. GAAP uses a single model to address uncertainty in tax positions and clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. U.S. GAAP also provides guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosures and transitions as well as specifically scopes out accounting for contingencies

(c) The consolidated statements of cash flows and operations and accumulated income are prepared in accordance with Canadian GAAP and conform in all material respects with U.S. GAAP except for that U.S. GAAP requires disclosure on the consolidated statement of operations when depreciation, depletion and amortization are excluded from cost of goods sold. This disclosure has not been noted on the face of the consolidated statement of operations.

(d) In 2009, the FASB issued FSP APB-14-1 that altered the way convertible debentures should be accounted for under U.S. GAAP. The impact to Provident is that the balances recorded for long term debt - convertible debentures and unitholder's equity no longer have a difference when compared to Canadian GAAP. These changes were retroactive, therefore the comparative 2008 figures have been adjusted.

(e) U.S. GAAP requires debt issue costs to be recorded as deferred charges. Under Canadian GAAP, these costs are recorded against long-term debt.

(f) Under U.S. GAAP, a redemption feature of equity instruments exercisable at the option of the holder requires that such equity be excluded from classification as permanent equity and be reported as temporary equity at the equity's redemption value. Changes in redemption value in the period (2009 - $445.9 million increase; 2008 - $982.6 million decrease) are recorded to accumulated earnings. Under Canadian GAAP, such equity instruments are considered to be permanent equity and are presented as unitholder's equity. The Trust's units have a redemption feature, which qualify them to be considered under this guidance.

(g) Under both Canadian and U.S. GAAP, goodwill is tested for impairment at least annually. Both GAAP's require that the fair value of the reporting unit be determined and compared to the book value of the reporting unit. Under Canadian GAAP, this resulted in no impairment being recorded (2008 - $416.9 million). Under U.S. GAAP the book value of the reporting unit was lower than the Canadian GAAP book value, primarily due to ceiling test impairments. Using the lower book value under U.S. GAAP results in no goodwill impairment in both periods.

Recent U.S. Accounting Pronouncements

Non-controlling interests in consolidated financial statements

As of January 1, 2009 Provident adopted ASC 810-10. ASC 810-10 requires the non-controlling ownership interests in subsidiaries held by parties other than the parent be clearly presented in the consolidated balance sheet within equity, but separate from the parent's equity and the amount of consolidated net income attributable to the parent and the non-controlling interest be clearly identified and presented on the face of the consolidated statement of operations. Changes in the parent's ownership interest should be accounted for consistently as equity transactions. If a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary should be initially recorded at fair value and the gain or loss on the deconsolidation of the subsidiary is measured using the fair value of any non-controlling equity investment rather than the carrying amount of the retained investment.. The adoption of this statement has not had a material impact on the Trust's financial statements.

Oil and gas reporting disclosure

During 2008, the United States Securities and Exchange Commission adopted revisions to its oil and gas reporting disclosures contained in Regulation S-K and Regulation S-X. These revisions change the price basis for calculating reserves from a single-day, year-end price to a monthly average price based on the first day of each month. These revisions have impacted the reserves in the Trust's accounting for depletion and its calculation of the ceiling test under U.S. GAAP.

Contact Information

  • Provident Energy Trust
    Investor and Media Contact:
    Dallas McConnell
    Director, Investor Relations
    (403) 231-6710
    info@providentenergy.com
    or
    Corporate Head Office:
    2100, 250 - 2nd Street SW
    Calgary, Alberta T2P 0C1
    (403) 296-2233 or Toll Free: 1-800-587-6299
    (403) 262-5973 (FAX)
    www.providentenergy.com