Canada Dividend Investor: PVE - <span class="simulate_din_font">Provident Announces Record Fourth Quarter, Record 2011 Annual Results, Updated Hedging Position and the March Cash Dividend</span> (CAD 0.045)

Canada Dividend Investor

Tuesday, March 6, 2012

PVE - <span class="simulate_din_font">Provident Announces Record Fourth Quarter, Record 2011 Annual Results, Updated Hedging Position and the March Cash Dividend</span> (CAD 0.045)

No comments:

Post a Comment

Company: Provident Energy Ltd.
Stock Name: PVE
Amount: CAD 0.045
Announcement Date: 06/03/2012
Record Date: 15/03/2012

Dividend Detail:

All values are in Canadian dollars.

CALGARY, March 6, 2012 /CNW/ - Provident Energy Ltd. (Provident) (TSX:
PVE) (NYSE: PVX) today announced its 2011 fourth quarter interim and
audited 2011 annual financial and operating results, updated hedging
information and the March cash dividend.

"Provident delivered record fourth quarter and record 2011 Adjusted
EBITDA⁽¹⁾, driven by very strong NGL market fundamentals and our aggressive
business development efforts," said President and Chief Executive
Officer, Doug Haughey. "Furthermore, with the significant increase in
growth capital deployment opportunities, we are well positioned to
drive new fee-for-service earnings in the future."

Fourth Quarter Summary

Gross operating margin grew by seven percent to $122 million in the
fourth quarter of 2011, up from $113 million in the fourth quarter of
2010, reflecting higher operating margins from both Redwater West and
Empress East, which increased contributions by 13 percent and three
percent, respectively, due to strong NGL per unit margins. This was
partially offset by a five percent decrease in contribution from
Commercial Services.

Adjusted EBITDA⁽¹⁾was $100 million for the fourth quarter of 2011, an increase of 14
percent from $88 million in the fourth quarter of 2010 reflecting
higher gross operating margin combined with lower realized losses on
financial derivative instruments.

Adjusted funds flow from continuing operations⁽²⁾ increased 22 percent to $93 million ($0.34 per share) in the fourth
quarter of 2011, compared to $76 million ($0.28 per unit) in the fourth
quarter of 2010, largely due to the seven percent increase in gross
operating margin, combined with lower realized losses on financial
derivative instruments and lower current tax expense.

Dividends paid to shareholders totaled $0.14 per share resulting in a
payout ratio of 45 percent ofadjusted funds flow from continuing
operations⁽²⁾ for the fourth quarter of 2011, net of sustaining capital expenditures.

Capital expenditures were $59 million during the fourth quarter of 2011
compared to $26 million in the fourth quarter of 2010. During the
fourth quarter of 2011, Provident completed several key projects
including the Septimus to Younger and Taylor to Boundary Lake pipeline
projects as well as construction of a significant portion of the Cromer
truck terminal.

On October 3, 2011, Provident completed the acquisition of a two-thirds
interest in Three Star Trucking Ltd., a Saskatchewan based oilfield
hauling company serving Bakken-area crude oil producers. The
acquisition expands Provident's footprint within the Bakken area,
establishing a strong crude oil presence and providing opportunities to
enhance its NGL and diluents logistics services businesses.

2011 Financial Summary

2011 financial statements are reported under International Financial
Reporting Standards.

Gross operating margin grew by 22 percent to $381 million in 2011, up
from $313 million in 2010, due to higher contributions from both
Redwater West and Empress East, which increased by 33 percent and 23
percent, respectively, reflecting stronger year-over-year NGL per unit
margins.

Adjusted EBITDA⁽¹⁾ was a record $282 million for 2011, an increase of 25 percent from $227
million in 2010. The increase reflects higher gross operating margin,
partially offset by higher realized losses on financial derivative
instruments under the market risk management program.

Adjusted funds flow from continuing operations⁽²⁾ increased 23 percent to $253 million ($0.93 per share) in 2011,
compared to $206 million ($0.77 per unit) in 2010, largely due to the
22 percent increase in gross operating margin partially offset by
higher realized losses on financial derivative instruments and a
current income tax recovery in 2010.

Dividends paid to shareholders totaled $0.54 per share resulting in a
payout ratio of 63 percent of adjusted funds flow from continuing
operations⁽²⁾ for 2011, net of sustaining capital expenditures.

Total debt at December 31, 2011 was $510 million compared to $474
million at December 31, 2010. Provident continues to maintain its
financial flexibility with approximately $310 million of capacity
remaining under its $500 million revolving term credit facility.

Total debt to Adjusted EBITDA⁽¹⁾ for year ended December 31, 2011 was a ratio of 1.8 to 1 compared to
2.1 to 1 for the year ended December 31, 2010.

Capital expenditures from continuing operations were $134 million in
2011, an increase of 91 percent from the $70 million spent in 2010. In
2011, Provident spent approximately $113 million on growth projects and
$21 million on sustaining capital requirements. Capital expenditures
were primarily directed towards cavern development and terminalling
infrastructure at the Corunna facility, cavern and brine pond
development at the Redwater facility and Provident's pipeline
replacement/expansion projects in northeast British Columbia.

_________________________________________________

⁽¹⁾

Adjusted EBITDA from continuing operations is earnings before interest,
taxes, depreciation, amortization, and other non-cash items - see
"Reconciliation of Non-GAAP measures" in the Management Discussion and
Analysis (MD&A). Adjusted EBITDA presented above is from continuing
operations and excludes the buyout of financial derivative instruments
and strategic review and restructuring costs in 2010.

⁽²⁾

Adjusted funds flow from continuing operations excludes realized loss on
buyout of financial derivative instruments and strategic review and
restructuring costs in 2010 - see "Reconciliation of Non-GAAP measures"
in the MD&A.

Updated Hedging Disclosure

Provident has released updated current hedging disclosure including a
volume and weighted average hedge price summary for NGL frac spread
volumes and a summary of all current financial derivative positions on
its website at www.providentenergy.com/bus/riskmanagement/commodity.cfm. The updated information reflects Provident's hedge positions and
forward-market indications at February 29, 2012. For 2012, Provident
has hedged approximately 66 percent of its estimated NGL frac spread
sales volumes and approximately 68 percent of its estimated frac spread
natural gas input volumes.

Recent Developments

On January 16, 2012, Provident announced it had entered into an
agreement with Pembina Pipeline Corporation (Pembina) for Pembina to
acquire all of the issued and outstanding common shares of Provident by
way of a plan of arrangement under the Business Corporations Act
(Alberta). Under the terms of the arrangement, Provident shareholders
will receive 0.425 of a Pembina share for each Provident share held.
This transaction will combine two organizations with complementary
strategies and assets that will be a leading player in the North
American energy infrastructure sector with an estimated enterprise
value of approximately $10 billion. Pending shareholder approval from
both Provident and Pembina shareholders and regulatory approval of the
acquisition, Pembina has announced its intention to increase its
monthly dividend from $0.13 per share per month ($1.56 annualized) to
$0.135 per share per month ($1.62 annualized). The acquisition is
expected to be completed on or about April 1, 2012.

March 2012 Cash Dividend

The March cash dividend of $0.045 per share is payable on April 13, 2012
and will be paid to shareholders of record on March 19, 2012. The
ex-dividend date will be March 16, 2012. Payment of the March cash
dividend will not be affected by the closing of the acquisition by
Pembina on or about April 1, 2012. Provident's current 2012 annualized
dividend rate is $0.54 per common share. Based on the current
annualized dividend rate and the TSX closing price on March 5, 2012 of
$11.55 Provident's yield is approximately 4.7 percent.

For shareholders receiving their dividends in U.S. funds, the March 2012
cash dividend will be approximately US$0.045 per share based on an
exchange rate of 0.9936. The actual U.S. dollar dividend will depend on
the Canadian/U.S. dollar exchange rate on the payment date and will be
subject to applicable withholding taxes.

2011 Fourth Quarter Conference Call

A conference call has been scheduled for Wednesday, March 7, 2012 at
8:00 a.m. MT (10:00 a.m. Eastern) to discuss Provident's results for
the 2011 fourth quarter and year ended December 31, 2011. To
participate, please dial 647-427-7450 or 888-231-8191 approximately 10
minutes prior to the conference call. An archived recording of the call
will be available for replay until March 14, 2012 by dialing
514-807-9274 or 855-859-2056 and entering passcode 43799676. Provident
will also provide a replay of the call on its website at www.providentenergy.com.

Provident Energy Ltd. is a Calgary-based corporation that owns and
manages a natural gas liquids midstream business. Provident's Midstream
facilities are strategically located in Western Canada and in the
premium NGL markets in Eastern Canada and the U.S. Provident provides
monthly cash dividends to its shareholders and trades on the Toronto
Stock Exchange and the New York Stock Exchange under the symbols PVE
and PVX, respectively.

This news release contains certain forward-looking statements concerning
Provident and the arrangement involving Pembina, 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,
obtaining required approvals of regulatory authorities and the failure
to complete the arrangement. 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.

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, project development activities and
certain matters relating to the arrangement.

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 and operational highlights

($ 000s except per share data)		Three months ended December 31,					Year ended December 31,
			2011		2010	% Change		2011		2010	% Change

Product sales and service revenue		$	569,547	$	543,725	5	$	1,955,878	$	1,746,557	12

Funds flow from continuing operations⁽¹⁾		$	92,767	$	74,133	25	$	252,632	$	(6,720)	-
Funds flow from discontinued operations ⁽¹⁾		$	-	$	-	-	$	-	$	(2,436)	(100)
Funds flow from operations ⁽¹⁾		$	92,767	$	74,133	25	$	252,632	$	(9,156)	-
Adjusted EBITDA - continuing operations ⁽²⁾		$	100,360	$	86,342	16	$	282,428	$	13,919	1,929

Adjusted funds flow from continuing operations ⁽³⁾		$	92,767	$	76,002	22	$	252,632	$	206,121	23
	Per weighted average share - basic	$	0.34	$	0.28	21	$	0.93	$	0.77	21
	Per weighted average share - diluted ⁽⁴⁾	$	0.34	$	0.27	26	$	0.93	$	0.77	21
Percent of adjusted funds flow from continuing operations, net of sustaining capital spending, paid out as declared dividends			45%		67%	(33)		63%		96%	(34)
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs - continuing operations ⁽²⁾		$	100,360	$	88,211	14	$	282,428	$	226,760	25

Dividends to shareholders		$	36,905	$	48,221	(23)	$	146,287	$	191,639	(24)
	Per share	$	0.14	$	0.18	(25)	$	0.54	$	0.72	(25)
Net income from continuing operations		$	20,585	$	63,622	(68)	$	97,217	$	112,217	(13)
	Per weighted average share - basic	$	0.08	$	0.24	(66)	$	0.36	$	0.42	(14)
	Per weighted average share - diluted⁽⁴⁾	$	0.08	$	0.23	(65)	$	0.36	$	0.42	(14)
Net income (loss)		$	20,585	$	72,380	(72)	$	97,217	$	(10,506)	-
	Per weighted average share - basic	$	0.08	$	0.27	(70)	$	0.36	$	(0.04)	-
	Per weighted average share - diluted ⁽⁴⁾	$	0.08	$	0.26	(69)	$	0.36	$	(0.04)	-
Capital expenditures from continuing operations:
	Growth	$	49,063	$	22,873	115	$	113,014	$	63,612	78
	Sustaining	$	10,064	$	3,510	187	$	21,101	$	6,606	219
Acquisitions - continuing operations		$	15,458	$	-		$	15,458	$	-
Weighted average shares outstanding (000s)
	basic		273,183		267,709	2		270,742		266,008	2
	diluted ⁽⁴⁾		273,183		297,743	(8)		270,742		266,008	2
Provident Midstream NGL sales volumes (bpd)			115,714		121,627	(5)		104,759		106,075	(1)

Consolidated
		As at December 31,		As at December 31,
($ 000s)		2011		2010		% Change
Capitalization
	Long-term debt (including current portion)	$	509,921	$	473,754	8
	Shareholders' equity	$	579,058	$	588,207	(2)

⁽¹⁾	Based on cash flow from operations before changes in working capital and site restoration expenditures - see "Reconciliation of Non-GAAP measures".
⁽²⁾	Adjusted EBITDA is earnings before interest, taxes, depreciation, amortization, and other non-cash items - see "Reconciliation of Non-GAAP measures".
⁽³⁾	Adjusted funds flow from continuing operations excludes realized loss on buyout of financial derivative instruments and strategic review and restructuring costs.
⁽⁴⁾	Includes dilutive impact of convertible debentures.

Management's Discussion & Analysis

The following analysis provides a detailed explanation of Provident's
operating results for the quarter and year ended December 31, 2011
compared to the quarter and year ended December 31, 2010 and should be
read in conjunction with the accompanying consolidated financial
statements of Provident. This analysis has been prepared using
information available up to March 6, 2012.

Provident operates a midstream business in Canada and the United States
and extracts, processes, markets, transports and offers storage of
natural gas liquids (NGLs) within the integrated facilities at Younger
in British Columbia, Redwater and Empress in Alberta, Kerrobert and
Alida in Saskatchewan, Sarnia in Ontario, Superior in Wisconsin and
Lynchburg in Virginia. Effective in the second quarter of 2010,
Provident's Canadian oil and natural gas production business
("Provident Upstream" or "COGP") was accounted for as discontinued
operations (see note 23 of the consolidated financial statements). As a
result of Provident's conversion from an income trust to a corporation,
effective January 1, 2011, references to "common shares", "shares",
"share based compensation", "shareholders", "performance share units",
"PSUs", "restricted share units", "RSUs", "premium dividend and
dividend reinvestment share purchase (DRIP) plan", and "dividends"
should be read as references to "trust units", "units", "unit based
compensation", "unitholders", "performance trust units", "PTUs",
"restricted trust units", "RTUs", "premium distribution, distribution
reinvestment (DRIP) and optional unit purchase plan", and
"distributions", respectively, for periods prior to January 1, 2011.

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 Company prepares its financial statements in accordance with
Canadian generally accepted accounting principles as set out in the
Handbook of the Canadian Institute of Chartered Accountants ("CICA
Handbook"). In 2010, the CICA Handbook was revised to incorporate
International Financial Reporting Standards ("IFRS"), and requires
publicly accountable enterprises to apply such standards effective for
years beginning on or after January 1, 2011. This adoption date
requires the restatement, for comparative purposes, of amounts reported
by Provident for the annual and quarterly periods within the year ended
December 31, 2010, including the opening consolidated statement of
financial position as at January 1, 2010. Provident's quarterly and
annual 2011 consolidated financial statements reflect this change in
accounting standards. For more information see "Change in accounting
policies".

The analysis refers to certain financial and operational measures that
are not defined in generally accepted accounting principles (GAAP) in
Canada. These non-GAAP measures include funds flow from operations,
adjusted funds flow from continuing operations, adjusted EBITDA and
further adjusted EBITDA to exclude realized loss on buyout of financial
derivative instruments and strategic review and restructuring costs.

Management uses funds flow from operations to analyze operating
performance. Funds flow from operations is reviewed, along with debt
repayments and capital programs in setting monthly dividends. Funds
flow from 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 IFRS. All references to funds flow from operations
throughout this report are based on cash provided by operating
activities before changes in non-cash working capital and site
restoration expenditures. See "Reconciliation of non-GAAP measures".

Management uses adjusted EBITDA to analyze the operating performance of
the business. Adjusted EBITDA as presented does not have any
standardized meaning prescribed by IFRS 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 IFRS. All
references to adjusted EBITDA throughout this report are based on
earnings before interest, taxes, depreciation, amortization, and other
non-cash items ("adjusted EBITDA"). See "Reconciliation of non-GAAP
measures".

Recent developments

Arrangement agreement with Pembina Pipeline Corporation

On January 15, 2012, Provident and Pembina Pipeline Corporation
("Pembina") entered into an agreement (the "Arrangement Agreement") for
Pembina to acquire all of the issued and outstanding common shares of
Provident by way of a plan of arrangement (the "Pembina Arrangement")
under the Business Corporations Act (Alberta).

Under the terms of the Arrangement Agreement, Provident shareholders
will receive 0.425 of a Pembina share for each Provident share held
(the "Provident Exchange Ratio"). Pembina will also assume all of the
rights and obligations relating to Provident's convertible debentures.
The conversion price of each class of convertible debentures will be
adjusted based on the Provident Exchange Ratio. Following closing of
the Pembina Arrangement, Pembina will be required to make an offer for
the Provident convertible debentures at 100 percent of their principal
values plus accrued and unpaid interest. The repurchase offer will be
made within 30 days of closing of the Pembina Arrangement. Should a
holder of the Provident convertible debentures elect not to accept the
repurchase offer, the debentures will mature as originally set out in
their respective indentures. Holders who convert their Provident
convertible debentures following completion of the Pembina Arrangement
will receive common shares of Pembina. In addition, Provident
immediately suspended its DRIP plan following the announcement of the
Pembina Arrangement.

The proposed transaction will be carried out by way of a court-approved
plan of arrangement and will require the approval of at least 66 2/3%
of holders of Provident shares represented in person or by proxy at a
special meeting of Provident shareholders to be held on March 27, 2012
to consider the Pembina Arrangement. The Pembina Arrangement is also
subject to obtaining the approval of a majority of the votes cast by
the holders of Pembina shares at a special meeting of Pembina
shareholders to be held on March 27, 2012 to consider the issuance of
Pembina shares in connection with the Pembina Arrangement. In addition
to shareholder and court approvals, the proposed transaction is subject
to applicable regulatory approvals and the satisfaction of certain
other closing conditions customary in transactions of this nature,
including compliance with the Competition Act (Canada) and the
acceptance of the Toronto Stock Exchange. Subject to receipt of all
required approvals, closing of the Pembina Arrangement is expected to
occur on or about April 1, 2012.

Acquisition of Three Star Trucking Ltd.

On October 3, 2011, Provident announced that it had completed the
acquisition of a two-thirds interest in Three Star Trucking Ltd.
("Three Star"), a Saskatchewan based oilfield hauling company serving
Bakken-area crude oil producers. The $15.5 million acquisition was
funded by approximately $7.9 million in cash and 944,828 Provident
shares. Provident has the option to purchase the remaining one-third
interest in Three Star after three years from the closing date.

Long-term storage agreements

On September 15, 2011, Provident announced that it had entered into
agreements with Nova Chemicals Corporation to provide approximately one
million barrels of product storage and other services at the Provident
Redwater Facility with staged on-stream dates in the third quarter of
2012 and first quarter of 2013.

On September 30, 2011, Provident announced that it had entered into a 10
year agreement with a major industrial company in the Sarnia area for
the contracting of 525,000 barrels of product storage at Provident's
Corunna Facility located near Sarnia, Ontario. The storage services are
anticipated to commence in the first half of 2012.

On October 6, 2011, Provident announced that it had entered into a 10
year crude oil storage agreement at its Redwater Facility with a major
producer and will be providing approximately one million barrels of
storage capacity on a fee-for-service basis. The storage services are
expected to commence on a staged basis with 50 percent beginning in the
second quarter of 2012 and the remainder in the second quarter of 2013.

Revolving term credit facility

Provident completed an extension of its existing credit agreement (the
"Credit Facility") on October 14, 2011, with National Bank of Canada as
administrative agent and a syndicate of Canadian chartered banks and
other Canadian and foreign financial institutions (the "Lenders").
Pursuant to the amended Credit Facility, the Lenders have agreed to
continue to provide Provident with a credit facility of $500 million
which, under an accordion feature, can be increased to $750 million at
the option of the Company, subject to obtaining additional
commitments. The amended Credit Facility also provides for a separate
Letter of Credit facility which was increased from $60 million to $75
million. The amended terms of the Credit Facility provide for a
revolving three year period expiring on October 14, 2014, from the
previous maturity date of June 28, 2013 (subject to customary extension
provisions).

Significant events in 2010

The second quarter of 2010 included two significant events that impacted
the comparative results related to earnings, adjusted EBITDA and funds
flow from operations significantly. First, Provident sold the remainder
of its Upstream business unit to move forward as a pure-play
infrastructure and logistics midstream business. This transaction
completed the sales process of the Upstream business and the Upstream
business unit is classified as discontinued operations. Strategic
review and restructuring costs associated with the continued divestment
of upstream properties, the final sale of Provident's Upstream business
and the related separation of the business units were also incurred in
the second quarter of 2010. See "Discontinued operations (Provident
Upstream)".

The second significant transaction was execution of a buyout of the
fixed price derivative contracts that related to the Midstream
business. In April, 2010, Provident completed a buyout of its existing
fixed price crude oil and natural gas swaps for a total realized cost
of $199.1 million. The carrying value of the specific contracts at
March 31, 2010 was a liability of $177.7 million, resulting in an
offsetting unrealized gain in the second quarter of 2010. The $199.1
million buyout represents a cash cost and reduces funds flow from
operations and adjusted EBITDA. The offsetting unrealized gain of
$177.7 million is not reflected in Provident's funds flow from
operations or adjusted EBITDA as it is a non-cash recovery. Provident
retained financial derivative option structures on crude oil and
natural gas products as well as contracts relating to the management of
physical contract exposure.

"Adjusted funds flow from continuing operations" and "Adjusted EBITDA
excluding buyout of financial derivative instruments and strategic
review and restructuring costs"

Two additional non-GAAP measures of "Adjusted funds flow from continuing
operations" and "Adjusted EBITDA excluding buyout of financial
derivative instruments and strategic review and restructuring costs"
have been provided and are also used in the calculation of certain
ratios. The adjusted non-GAAP measures are provided as an additional
measure to evaluate the performance of Provident's pure-play Midstream
infrastructure and logistics business and to provide additional
information to assess future funds flow and earnings generating
capability. See "Reconciliation of non-GAAP measures".

Fourth quarter highlights

The fourth quarter highlights section provides commentary on the fourth
quarter of 2011 results compared to the fourth quarter of 2010.
Definitions of terms used in this section, as appropriate, are defined
in the year over year section of Management's Discussion and Analysis
("MD&A").

Reconciliation of non-GAAP measures

Provident calculates earnings before interest, taxes, depreciation,
amortization and other non-cash items (adjusted EBITDA) and adjusted
EBITDA excluding buyout of financial derivative instruments and
strategic review and restructuring costs within its MD&A disclosure.
These are non-GAAP measures. A reconciliation between adjusted EBITDA
and income from continuing operations before taxes follows:

Continuing operations	Three months ended December 31,
($ 000s)		2011		2010	% Change

Income before taxes	$	31,216	$	45,585	(32)
Adjusted for:
Financing charges		9,364		10,509	(11)
Unrealized loss on financial derivative instruments		27,526		12,364	123
Depreciation and amortization		11,916		11,644	2
Unrealized foreign exchange loss and other		420		1,240	(66)
Loss on revaluation of conversion feature of convertible debentures and redemption liability		12,169		433	2710
Non-cash share based compensation expense		8,695		4,567	90
Adjusted EBITDA attributable to non-controlling interest		(946)		-	-
Adjusted EBITDA		100,360		86,342	16

Adjusted for:
Strategic review and restructuring costs		-		1,869	(100)
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs	$	100,360	$	88,211	14

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

Reconciliation of funds flow from operations	Three months ended December 31,
($ 000s)		2011		2010	% Change

Cash provided by operating activities	$	105,714	$	127,031	(17)
Change in non-cash operating working capital		(12,195)		(52,898)	(77)
Funds flow from operations attributable to non-controlling interest		(752)		-	-
Funds flow from operations		92,767		74,133	25

Strategic review and restructuring costs		-		1,869	(100)
Adjusted funds flow from continuing operations	$	92,767	$	76,002	22

Funds flow from continuing operations and dividends

		Three months ended December 31,
($ 000s, except per share data)			2011		2010	% Change
Funds flow from continuing operations and dividends
Funds flow from continuing operations		$	92,767	$	74,133	25
Adjusted funds flow from continuing operations⁽¹⁾		$	92,767	$	76,002	22
	Per weighted average share
	- basic	$	0.34	$	0.28	21
	- diluted ⁽²⁾	$	0.34	$	0.27	26
Declared dividends		$	36,905	$	48,221	(23)
	Per share	$	0.14	$	0.18	(25)
Percent of adjusted funds flow from continuing operations, net of sustaining capital spending, paid out as declared dividends			45%		67%	(33)

⁽¹⁾ Adjusted funds flow from operations excludes realized loss on buyout of
derivative instruments and strategic review and restructuring costs.

⁽²⁾ Includes dilutive impact of convertible debentures.

Fourth quarter 2011 adjusted funds flow from continuing operations was
$92.8 million, a 22 percent improvement from the $76.0 million recorded
in the fourth quarter of 2010. The increase is primarily due to a
seven percent increase in gross operating margin combined with lower
realized losses on financial derivative instruments and lower current
tax expense during the fourth quarter of 2011 compared to the fourth
quarter of 2010.

Declared dividends in the fourth quarter of 2011 totaled $36.9 million,
45 percent of adjusted funds flow from continuing operations, net of
sustaining capital spending. This compares to $48.2 million of
declared distributions in the fourth quarter of 2010, 67 percent of
adjusted funds flow from continuing operations, net of sustaining
capital spending.

Provident Midstream operating results review

Market environment

Provident's performance is closely tied to market prices for NGL and
natural gas, which can vary significantly from period to period. The
key reference prices impacting Midstream gross operating margins are
summarized in the following table:

Midstream business reference prices	Three months ended December 31,
			2011		2010	% Change

WTI crude oil (US$ per barrel)		$	94.06	$	85.17	10
Exchange rate (from US$ to Cdn$)			1.03		1.01	2
WTI crude oil expressed in Cdn$ per barrel		$	96.68	$	86.26	12

AECO natural gas monthly index (Cdn$ per gj)		$	3.29	$	3.39	(3)

Frac Spread Ratio⁽¹⁾			29.4		25.4	16

Mont Belvieu Propane (US$ per US gallon)		$	1.44	$	1.26	14
Mont Belvieu Propane expressed as a percentage of WTI			64%		62%	3

Market Frac Spread in Cdn$ per barrel⁽²⁾		$	58.41	$	46.25	26

⁽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 average spot prices at Mont Belvieu, weighted based on 65% propane, 25% butane, and 10% condensate, and the AECO monthly index price for natural gas.

The NGL pricing environment in the fourth quarter of 2011 was
significantly stronger than in the fourth quarter of 2010. The average
fourth quarter 2011 WTI crude oil price was US$94.06 per barrel,
representing an increase of 10 percent compared to the fourth quarter
of 2010. Propane prices were also stronger than in the prior year,
tracking the increase in crude oil prices and reflecting a
strengthening of propane prices relative to WTI. The Mont Belvieu
propane price averaged US$1.44 per U.S. gallon (64 percent of WTI) in
the fourth quarter of 2011, compared to US$1.26 per U.S. gallon (62
percent of WTI) in the fourth quarter of 2010. Butane and condensate
sales prices were also much improved in the fourth quarter of 2011,
reflective of higher crude oil prices and steady petrochemical and
oilsands demand for these products.

The fourth quarter 2011 AECO natural gas price averaged $3.29 per gj
compared to $3.39 per gj during the fourth quarter of 2010, a decrease
of three percent. While low natural gas prices are generally favorable
to NGL extraction and fractionation economics, a sustained period in a
low priced gas environment may impact the availability and overall cost
of natural gas and NGL mix supply in western Canada, as natural gas
producers may curtail drilling activities. However, strengthening NGL
pricing in 2011 has resulted in improved netbacks for producers
drilling in natural gas plays with higher levels of associated NGLs,
such as the Montney area in British Columbia. Increased focus on
liquids-rich natural gas drilling is beneficial to Provident supply,
particularly at Redwater. Continued softness in natural gas prices
have improved market frac spreads but have also caused increased
extraction premiums paid for natural gas supply in western Canada,
particularly at Empress.

Market frac spreads averaged $58.41 per barrel during the fourth quarter
of 2011, representing a 26 percent increase from $46.25 per barrel
during the fourth quarter of 2010. Higher frac spreads were a result
of higher NGL sales prices combined with a lower AECO natural gas
price. The benefit to Provident of higher market frac spreads in the
fourth quarter of 2011 was offset by increased costs for natural gas
supply in the form of extraction premiums. Empress extraction premiums
have increased by approximately 10 percent in the fourth quarter of
2011 relative to the prior year quarter. Higher premiums are primarily
a result of reduced volumes of natural gas flowing past the Empress
straddle plants and increased competition for NGLs as a result of
higher frac spreads. In the fourth quarter of 2011, natural gas
throughput at the Empress Eastern border averaged approximately 4.4 bcf
per day, approximately 10 percent lower than in the fourth quarter of
2010. Lower natural gas throughput directly impacts production at the
Empress facilities which in turn reduces the supply of propane-plus
available for sale in Sarnia and in surrounding eastern markets.
Tighter supply at Sarnia may have a positive impact on eastern sales
prices relative to other major propane hubs during periods of high
demand.

Provident Midstream business performance

Provident Midstream results are summarized as follows:

	Three months ended December 31,
(bpd)		2011		2010	% Change

Redwater West NGL sales volumes		66,866		72,672	(8)
Empress East NGL sales volumes		48,848		48,955	-
Provident Midstream NGL sales volumes		115,714		121,627	(5)


	Three months ended December 31,
($ 000s)		2011		2010	% Change

Redwater West margin	$	68,641	$	60,861	13
Empress East margin		37,282		36,055	3
Commercial Services margin		15,623		16,428	(5)
Gross operating margin		121,546		113,344	7
Realized loss on financial derivative instruments		(11,406)		(16,406)	(30)
Cash general and administrative expenses		(9,244)		(7,284)	27
Other income and realized foreign exchange		410		(1,443)	-
EBITDA attributable to non-controlling interest		(946)		-	-
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs		100,360		88,211	14
Strategic review and restructuring costs		-		(1,869)	(100)
Adjusted EBITDA	$	100,360	$	86,342	16

Gross operating margin

Midstream gross operating margin during the fourth quarter of 2011
totaled $121.5 million, an increase of seven percent compared to the
same period in the prior year. The increase in operating margin is the
result of a higher contribution from both Redwater West and Empress
East by 13 percent and three percent, respectively, partially offset by
a five percent decrease in operating margin from Commercial Services.

Redwater West

The fourth quarter 2011 operating margin for Redwater West was $68.6
million, an increase of 13 percent compared to $60.9 million in the
fourth quarter of 2010. Strong fourth quarter 2011 results were
primarily a result of stronger prices for NGLs partially offset by a
decrease in sales volumes. In addition, the fourth quarter 2010
operating margin included $4.1 million representing a product gain
resulting from volume testing performed at the NGL mix caverns.
Overall, Redwater West NGL sales volumes averaged 66,866 bpd in the
fourth quarter of 2011, a decrease of eight percent compared to the
prior year quarter. Lower NGL sales volumes can be largely attributed
to a decrease in sales volumes for condensate. Condensate sale volumes
decreased compared to the prior year quarter as Provident imported less
condensate via railcar from the U.S. Gulf Coast for sale into the
western Canadian market. Margins on imported condensate supply tend to
be lower than product supplied through western Canadian NGL mix or
product extracted at Younger due to the significant transportation
costs incurred on imported product. Decreases in sales volumes were
more than offset by significant improvements in condensate market
pricing, resulting in a higher product operating margin despite the
decrease in sales volumes.

Product operating margins for butane increased in the fourth quarter of
2011 as increased market prices more than offset a slight decrease in
sales volumes due to reduced demand from refiners and blenders of crude
oil as compared to the fourth quarter of 2010. Product operating
margins for propane were lower in the fourth quarter of 2011 as warm
weather in western Canada softened demand compared to the prior year
quarter, while costs increased as inventories accumulated in the third
quarter of 2011, at higher market prices, were sold in the fourth
quarter of 2011. Ethane margins were comparable to the prior year
quarter.

Empress East

Empress East gross operating margin was $37.3 million in the fourth
quarter of 2011 compared to $36.1 million in the same quarter of 2010.
The three percent increase was primarily associated with significant
increases in the market price for condensate as lower production and
sales volumes of condensate in Empress East were offset by significant
market price increases partially driven by a 10 percent increase in WTI
in the fourth quarter of 2011 compared to the prior year quarter. The
product operating margin increase for condensate was partially offset
by a slightly lower product operating margin for propane as weaker
demand, primarily driven by mild temperatures in central Canada, led to
lower sales volumes. Lower demand from refiners for butane was offset
by significant market price increases resulting in a consistent product
operating margin for butane in the fourth quarter of 2011 compared to
the fourth quarter of 2010. Overall, Empress East sales volumes
averaged 48,848 bpd, consistent with the sales volume in the fourth
quarter of 2010. The positive impacts of higher sales prices and frac
spreads for Empress East were partially offset by increased premiums
paid to purchase natural gas in the Empress market.

Commercial Services

Operating margin in the fourth quarter of 2011 was $15.6 million,
representing a decrease of five percent compared to the same period in
2010. The decrease in margin was primarily associated with decreased
condensate terminalling revenues partly as a result of the termination
of a multi-year condensate storage and terminalling services agreement
in 2010 as well as the completion in mid-2010 of the Enbridge Southern
Lights pipeline, which transports condensate from the United States to
the Edmonton area. This decrease was partially offset by increases in
margin related to third party storage and the acquisition of Three
Star.

Earnings before interest, taxes, depreciation, amortization, and
non-cash items ("adjusted EBITDA")

Fourth quarter 2011 adjusted EBITDA excluding buyout of financial
derivative instruments and strategic review and restructuring costs
increased to $100.4 million from $88.2 million in the fourth quarter of
2010 reflecting higher gross operating margin combined with lower
realized losses on financial derivative instruments.

Capital expenditures

Provident substantially increased its 2011 growth capital expenditures
when compared to 2010. In the fourth quarter of 2011, Provident
incurred total capital expenditures of $59.1 million compared to $26.4
million in the prior year quarter. Driven by substantial demand for
new storage services at Redwater, Provident deployed $20.2 million
(2010 - $6.5 million) of capital on cavern and brine pond development
at the Redwater facility, $12.8 million (2010 - $1.7 million) was
directed to the growth-related portions of the Taylor to Boundary Lake
and the Septimus to Younger pipeline projects, and $3.7 million (2010 -
$12.2 million) of expenditures were incurred for storage and
terminalling infrastructure development at the Provident Corunna
facility. An additional $7.5 million (2010 - nil) was directed toward
the construction of a truck terminal in Cromer, Manitoba while $4.8
million (2010 - $2.5 million) was spent on various infrastructure
improvements. Finally, an additional $10.1 million (2010 - $3.5
million) was directed towards sustaining capital activities and office
related capital, including $6.5 million (2010 - $1.7 million) related
to the sustaining portion of the Taylor to Boundary Lake pipeline.

Net income

Consolidated		Three months ended December 31,
($ 000s, except per share data)			2011		2010	% Change

Net income from continuing operations		$	20,585	$	63,622	(68)
Net income from discontinued operations			-		8,758	(100)
Net income		$	20,585	$	72,380	(72)
Per weighted average share ⁽¹⁾
	- basic	$	0.08	$	0.27	(70)
	- diluted⁽²⁾	$	0.08	$	0.26	(69)

⁽¹⁾ Based on weighted average number of shares outstanding.

⁽²⁾ Includes the dilutive impact of convertible debentures.

Net income from continuing operations for the fourth quarter of 2011 was
$20.6 million, compared to $63.6 million in the fourth quarter of
2010. Higher adjusted EBITDA was more than offset by higher unrealized
losses on financial derivative instruments and higher income tax
expense. Net income in the fourth quarter of 2010 was impacted by net
income from discontinued operations of $8.8 million related to
post-closing adjustments attributed to the sale of the Upstream
business in the second quarter of 2010.

Taxes

Continuing operations	Three months ended December 31,
($ 000s)		2011		2010	% Change

Current tax expense	$	446	$	4,138	(89)
Deferred income tax expense (recovery)		10,185		(22,175)	-
	$	10,631	$	(18,037)	-

Current tax expense was $0.4 million in the fourth quarter of 2011
compared to an expense of $4.1 million in the fourth quarter of 2010.
The fourth quarter 2011 current tax expense was driven by earnings
generated in the Company's recently acquired subsidiary, Three Star,
that is in excess of allowable tax pool claims. The fourth quarter
2010 current tax expense was attributed to new IRS guidance that
restricted the application of a portion of the tax loss carryback in
the U.S. Midstream operations related to the recovery of income taxes
paid in prior periods. This provided for a deferred tax benefit,
thereby increasing the current income tax expense and deferred income
tax recovery in the fourth quarter of 2010. The tax losses were
generated primarily by the realized loss on buyout of the financial
derivative instruments incurred in the second quarter of 2010.

The 2011 fourth quarter future income tax expense was $10.2 million
compared to a deferred income tax recovery of $22.2 million in the
fourth quarter of 2010. The deferred income tax expense in the fourth
quarter of 2011 resulted primarily from the use of existing tax pools
to offset earnings from Provident's Canadian midstream business. The
deferred income tax recovery in the fourth quarter of 2010 resulted in
part from the movement from current taxes to deferred income taxes due
to the new IRS guidance that restricted the application of a portion of
the tax loss carryback in the U.S. Midstream operations related to the
recovery of taxes paid in prior periods as discussed above. The
remaining change in the deferred income tax recovery resulted from
losses created by deductions at the incorporated subsidiary level under
the previous Trust structure.

Financing charges

Continuing operations	Three months ended December 31,
($ 000s, except as noted)		2011		2010	% Change

Interest on bank debt	$	2,990	$	2,631	14
Interest on convertible debentures		4,999		5,452	(8)
		7,989		8,083	(1)
Less: Capitalized borrowing costs		(609)		-	-
Total cash financing charges	$	7,380	$	8,083	(9)

Weighted average interest rate on all long-term debt		4.9%		5.5%	(11)
Accretion and other non-cash financing charges		1,984		2,426	(18)
Total financing charges	$	9,364	$	10,509	(11)

Financing charges for the fourth quarter of 2011 have decreased in
comparison to the fourth quarter of 2010. Interest on bank debt is
higher in the fourth quarter of 2011 as Provident had more debt drawn
on its revolving credit facility, partially offset by lower borrowing
rates. Interest on convertible debentures for the fourth quarter of
2011 was lower than in the comparable period in 2010 reflecting the
refinancing of the 6.5% convertible debentures with the issuance of two
new series of 5.75% convertible debentures in late 2010 and 2011,
combined with a reduced average coupon rate on the outstanding
convertible debentures in 2011.

In addition, in 2011 Provident has capitalized borrowing costs
attributable to the construction of assets, such as storage caverns and
related facilities, which take a substantial period of time to get
ready for their intended use. This reduced the Company's total
recognized financing charges in the fourth quarter of 2011 by $0.6
million (2010 - nil).

Market risk management program

A summary of Provident's risk management contracts executed during the
fourth quarter of 2011 is contained in the following table.

Activity in the Fourth Quarter:

Midstream
		Volume
Year	Product	(Buy)/Sell		Terms	Effective Period

2012	Crude Oil	1,224	Bpd	US $97.40 per bbl ^{(3) (6)}	April 1 - December 31
		1,216	Bpd	US $92.75 per bbl ^{(3) (6)}	January 1 - December 31
		978	Bpd	Cdn $101.82 per bbl ^{(3) (6)}	July 1 - December 31
	Natural Gas	(30,311)	Gjpd	Cdn $3.26 per gj ^{(2) (6)}	January 1 - December 31
	Propane	2,083	Bpd	US $1.4685 per gallon ^{(4) (6)}	January 1 - February 29
	Normal Butane	2,445	Bpd	US $1.7434 per gallon ^{(5) (6)}	January 1 - December 31
	Foreign Exchange			Sell US $2,633,333 per month @ 1.016 ⁽⁷⁾	January 1 - June 30
				Sell US $5,785,714 per month @ 0.996 ⁽⁷⁾	January 1 - July 31
				Sell US $5,144,444 per month @ 0.996 ⁽⁷⁾	January 1 - September 30
				Sell US $2,666,667 per month @ 1.042 ⁽⁷⁾	April 1 - December 31
				Sell US $2,875,000 per month @ 1.050 ⁽⁷⁾	January 1 - December 31

2013	Crude Oil	1,700	Bpd	US $96.65 per bbl ^{(3) (6)}	January 1 - March 31
	Foreign Exchange			Sell US $5,000,000 per month @ 1.050 ⁽⁷⁾	January 1 - March 31

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

	Interest Rate	$ 50,000,000	Notional (Cdn$)	Pay Average Fixed rate of 1.124% ⁽⁸⁾	July 1 2013 - September 30, 2014

⁽¹⁾						The above table represents transactions entered into over the fourth quarter of 2011.
⁽²⁾						Natural Gas contracts are settled against AECO monthly index.
⁽³⁾						Crude Oil contracts are settled against NYMEX WTI calendar average.
⁽⁴⁾						Propane contracts are settled against Mont Belvieu C3 TET.
⁽⁵⁾						Normal Butane contracts are settled against Belvieu NC4 NON TET and Belvieu NC4 TET.
⁽⁶⁾						Frac spread contracts.
⁽⁷⁾						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 underlying commodity.
⁽⁸⁾						Interest rate forward contract settles monthly against 1M CAD BA CDOR

Settlement of market risk management contracts

The following table summarizes the impact of financial derivative
contracts settled during the fourth quarters of 2011 and 2010 that were
included in realized loss on financial derivative instruments.

			Three months ended December 31,
Realized loss on financial derivative instruments			2011			2010
($ 000s except volumes)				Volume ⁽¹⁾			Volume ⁽¹⁾

Frac spread related
	Crude oil	$	(809)	0.1	$	(2,929)	0.3
	Natural gas		(4,760)	6.4		(4,721)	6.4
	Propane		2,409	1.1		(6,738)	1.1
	Butane		(851)	0.4		(4,301)	0.4
	Condensate		(967)	0.2		(596)	0.2
	Foreign exchange		(3,677)			1,135
	Sub-total frac spread related		(8,655)			(18,150)
Corporate
	Electricity		680			(79)
	Interest rate		(321)			(35)
Management of exposure embedded in physical contracts			(3,110)	1.0		1,858	0.2
Realized loss on financial derivative instruments		$	(11,406)		$	(16,406)
⁽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.

The realized loss for the fourth quarter of 2011 was $11.4 million
compared to $16.4 million in the comparable 2010 quarter. The majority
of the realized loss in the fourth quarter of 2011 was driven by
natural gas purchase derivative contracts settling at a contracted
price higher than the market natural gas prices, foreign exchange
contracts settling at a contracted rate lower than the average market
rates, as well as crude oil derivative sales contracts settling at
contracted crude oil prices lower than the crude oil market prices
during the settlement period. The comparable 2010 realized loss was
driven mostly by NGL derivative sales contracts settling at a
contracted price lower than the market NGL prices during the settlement
period, natural gas purchase derivative contracts in the Midstream
business settling at a contracted price higher than the market natural
gas prices during the settlement period as well as crude oil derivative
sales contracts settling at contracted crude oil prices lower than the
crude oil market prices during the settlement period.

2011 Year end results

Reconciliation of non-GAAP measures

Provident calculates earnings before interest, taxes, depreciation,
amortization, and other non-cash items (adjusted EBITDA) and adjusted
EBITDA excluding buyout of financial derivative instruments and
strategic review and restructuring costs within its MD&A disclosure.
These are non-GAAP measures. A reconciliation between these measures
and income from continuing operations before taxes follows:

Continuing operations	Year ended December 31,
($ 000s)		2011		2010	% Change

Income before taxes	$	165,703	$	64,390	157
Adjusted for:
Financing charges		41,282		32,251	28
Unrealized gain offsetting buyout of financial derivative instruments		-		(177,723)	(100)
Unrealized loss on financial derivative instruments		3,235		52,599	(94)
Depreciation and amortization		43,630		44,475	(2)
Unrealized foreign exchange gain and other		(414)		(3,786)	(89)
Loss on revaluation of conversion feature of convertible debentures and redemption liability		17,469		433	3,934
Non-cash share based compensation expense		12,469		1,280	874
Adjusted EBITDA attributable to non-controlling interest		(946)		-	-
Adjusted EBITDA		282,428		13,919	1,929

Adjusted for:
Realized loss on buyout of financial derivative instruments		-		199,059	(100)
Strategic review and restructuring costs		-		13,782	(100)
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs	$	282,428	$	226,760	25

The following table reconciles funds flow from operations and adjusted
funds flow from continuing operations with cash provided by (used in)
operating activities:

Reconciliation of funds flow from operations	Year ended December 31,
($ 000s)		2011		2010	% Change

Cash provided by (used in) operating activities	$	220,239	$	(39,669)	-
Change in non-cash operating working capital		33,145		28,472	16
Site restoration expenditures - discontinued operations		-		2,041	(100)
Funds flow from operations attributable to non-controlling interest		(752)		-	-
Funds flow from operations		252,632		(9,156)	-
Funds flow from discontinued operations		-		2,436	(100)
Realized loss on buyout of financial derivative instruments		-		199,059	(100)
Strategic review and restructuring costs		-		13,782	(100)
Adjusted funds flow from continuing operations	$	252,632	$	206,121	23

Funds flow from continuing operations and dividends

		Year ended December 31,
($ 000s, except per share data)			2011		2010	% Change
Funds flow from continuing operations and dividends
Funds flow from continuing operations		$	252,632	$	(6,720)	-
Adjusted funds flow from continuing operations⁽¹⁾		$	252,632	$	206,121	23
	Per weighted average share
	- basic and diluted ⁽²⁾	$	0.93	$	0.77	21
Declared dividends		$	146,287	$	191,639	(24)
	Per share	$	0.54	$	0.72	(25)
Percent of adjusted funds flow from continuing operations, net of sustaining capital spending, paid out as declared dividends			63%		96%	(34)
⁽¹⁾Adjusted funds flow from operations excludes realized loss on buyout of financial derivative instruments and strategic review and restructuring costs.
⁽²⁾Includes dilutive impact of convertible debentures.

Funds flow from continuing operations includes the impact of the
Midstream financial derivative contract buyout, as well as strategic
review and restructuring costs associated with the separation and
divestment of Provident's Upstream business and the corporate
conversion. Adjusted funds flow from continuing operations is
presented as a measure to evaluate the performance of Provident's
pure-play Midstream infrastructure business and to provide additional
information to assess future funds flow generating capability.

For the year ended December 31, 2011, adjusted funds flow from
continuing operations was $252.6 million, 23 percent above the $206.1
million in 2010. The increase is attributed to a significant increase
in gross operating margin partially offset by higher realized losses on
financial derivative instruments and a current income tax recovery in
2010.

Declared dividends in 2011 totaled $146.3 million, 63 percent of
adjusted funds flow from continuing operations, net of sustaining
capital spending. This compares to $191.6 million of declared
distributions in the comparable period of 2010, 96 percent of adjusted
funds flow from continuing operations, net of sustaining capital
spending.

Outlook

The following outlook contains forward-looking information regarding
possible events, conditions or results of operations in respect of
Provident 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 Provident and described in the forward-looking
information. In addition, the following outlook for 2012, including
Provident's anticipated capital program, is provided by Provident only
and does not reflect the completion of the proposed acquisition of
Provident by Pembina as described in "Recent developments" in this MD&A
or the intentions of Pembina following closing of the acquisition. See
"Forward-looking information" in this MD&A for additional information
regarding assumptions and risks in respect of Provident's
forward-looking information.

Provident delivered record adjusted EBITDA in 2011 and exceeded all of
its key performance objectives:

Provident generated year-over-year adjusted EBITDA growth of 25 percent;

Provident exited 2011 with a total debt to adjusted EBITDA ratio of
approximately 1.8 to 1, less than its target of 2.5 to 1; and

Provident paid out $146 million in dividends and achieved a payout ratio
of adjusted funds flow from continuing operations, net of sustaining
capital spending, of 63 percent, well below its target of 80 percent.

Provident deployed approximately $134 million of capital in 2011,
comprised of $113 million of new growth capital and $21 million of
sustaining capital. 2011 growth capital spending increased 78 percent
over 2010 and reflects Provident's success in developing new
fee-for-service growth projects around its midstream assets. Provident
completed several key projects in the fourth quarter including
completion of the Septimus to Younger pipeline, completion of the
Taylor to Boundary Lake pipeline replacement and is in the final stages
of tie-in of its NGL truck unloading terminal at Cromer, Manitoba. In
addition, on October 3, 2011, Provident completed the acquisition of a
two-thirds interest in Three Star, a Saskatchewan based oilfield
hauling company serving Bakken-area crude oil producers.

The Taylor to Boundary lake pipeline project included construction to
upgrade and replace an aging section of the Taylor to Boundary Lake
pipeline on the Liquids Gathering System. A significant portion of the
new pipeline segment was placed into service during the second quarter
of 2011 with the final leg of the pipeline completed in the fourth
quarter of 2011. The goal of replacing the aging sections of this
pipeline was to ensure continued safe operation and to increase Younger
throughput from growing Montney development.

For 2012, Provident announced a $135 million growth capital program and
approximately $10 million to $15 million of sustaining capital. The
growth capital for 2012 is anticipated to be allocated as follows:

Provident expects to deploy approximately $95 million on the continued
development of underground storage caverns and related infrastructure
at Redwater, reflecting strong producer demand for storage of diluents
and/or crude oil to enhance operational efficiencies. Provident
continues to have more demand for storage services at Redwater than it
can currently provide, and indications are that demand for hydrocarbon
storage continues to grow.

Provident expects to spend approximately $6 million on projects around
its Younger fractionation facility and Liquids Gathering System to
optimize Younger plant operating capacity and further enhance Redwater
West supply.

Approximately $18 million of capital has been allocated to the initial
phase of a planned debottlenecking and optimization of the Redwater NGL
facility, which is expected to increase throughput capacity by
approximately 7,500 bpd.

For 2012, Provident allocated approximately $10 million of capital for
projects associated with its storage and terminalling facilities at
Corunna, Ontario.

Provident allocated approximately $6 million of capital towards
expanding Provident's crude oil and NGL footprint in the Bakken area,
including activities around its Cromer truck terminal and projects
completed through its subsidiary, Three Star.

In terms of the NGL market outlook:

Warm weather at the end of the fourth quarter 2011 reduced the demand
for propane, which is primarily used to meet winter heating demand.
The unseasonably warm trend has continued into the first quarter of
2012. This has resulted in lower propane sales and pricing so far in
the first quarter of 2012. Despite this short-term softness, propane
industry fundamentals for the future remain strong with high propane
exports from North America and strong petrochemical margins where
propane is used as feedstock.

Spot Alberta natural gas prices are currently about 40 percent lower
than they were in the fourth quarter of 2011, which has led to
significantly lower production costs for NGLs at Empress and Younger.

Increasing heavy oil production in Alberta continues to increase the
demand for condensate and butane as a diluent and butane as a solvent
in SAGD operations. Provident continues to see very strong demand for
fractionation, storage and ancillary services.

Empress extraction premiums are near the midpoint of a $6 to $9 per
gigajoule range.

Based on current market conditions, Provident's expectation is that
first quarter 2012 adjusted EBITDA will be near first quarter 2011
levels. For 2012, Provident has hedged approximately 66 percent of its
estimated NGL frac spread sales volumes and approximately 68 percent of
its estimated frac spread natural gas input volumes.

Provident has contracted with a third party engineering firm to develop
a detailed cost estimate on the twinning of its ethane-plus Redwater
NGL Facility. The increasing production of NGL mix in the Western
Canadian Sedimentary Basin would be the primary source of volumes for
the 65,000 bpd fractionation expansion. If there is a sufficient level
of customer commitment and Board of Director approval by mid-2012, the
facility could be in operation by mid-2014.

Subsequent to the end of the fourth quarter 2011, Pembina and Provident
announced an agreement whereby Pembina would acquire all of the issued
and outstanding shares of Provident. Under the terms of the
Arrangement Agreement, Provident shareholders will receive 0.425 of a
Pembina share for each Provident share held. The proposed transaction
will be carried out by a court-approved plan of arrangement and require
the approval of both Provident and Pembina shareholders. Provident
will hold its special meeting to approve the transaction on March 27,
2012, at 9:00 a.m. (MT) in the Ballroom at the Metropolitan Conference
Center, 333 - 4 Avenue SW, Calgary, Alberta. The transaction is
expected to close on or about April 1, 2012, subject to receipt of all
shareholder and regulatory approvals and the satisfaction of all other
closing conditions.

Dividends and distributions

The following table summarizes dividends and distributions paid as
declared by Provident since inception:

	Distribution / Dividend Amount
Per share / unit			(Cdn$)		(US$)*
2001 Cash Distributions paid as declared - March 2001 - December 2001		$	2.54	$	1.64
2002 Cash Distributions paid as declared			2.03		1.29
2003 Cash Distributions paid as declared			2.06		1.47
2004 Cash Distributions paid as declared			1.44		1.10
2005 Cash Distributions paid as declared			1.44		1.20
2006 Cash Distributions paid as declared			1.44		1.26
2007 Cash Distributions paid as declared			1.44		1.35
2008 Cash Distributions paid as declared			1.38		1.29
2009 Cash Distributions paid as declared			0.75		0.67
2010 Cash Distributions paid as declared			0.72		0.72
Inception to December 31, 2010 - Cash Distributions paid as declared		$	15.24	$	11.99
Capital Distribution - June 29, 2010		$	1.16	$	1.10

2011 Cash Dividends paid as declared
Record Date	Payment Date
January 20, 2011	February 15, 2011	$	0.045	$	0.046
February 24, 2011	March 15, 2011		0.045		0.046
March 22, 2011	April 15, 2011		0.045		0.047
April 20, 2011	May 13, 2011		0.045		0.046
May 26, 2011	June 15, 2011		0.045		0.046
June 22, 2011	July 15, 2011		0.045		0.047
July 20, 2011	August 15, 2011		0.045		0.046
August 24, 2011	September 15, 2011		0.045		0.046
September 21, 2011	October 14, 2011		0.045		0.044
October 24, 2011	November 15, 2011		0.045		0.044
November 23, 2011	December 15, 2011		0.045		0.044
December 21, 2011	January 13, 2012		0.045		0.044
Total 2011 Cash Dividends paid as declared		$	0.540	$	0.546
Total inception to December 31, 2011 Cash Distributions/Dividends and Capital Distribution		$	16.940	$	13.636
* Exchange rate based on the Bank of Canada noon rate on the payment date.

Provident Midstream operating results review

The Midstream business

Provident's Midstream business extracts, processes, stores, transports
and markets NGLs and offers these services to third party customers.
In order to aid in the understanding of the business, this MD&A
provides information about the associated business activities of the
Midstream operation comprising Redwater West, Empress East and
Commercial Services. The assets are integrated across Canada and the
U.S., and are also used to generate fee-for-service income. The
business is supported by an integrated supply, marketing and
distribution function that contributes to the overall operating margin
of the Company.

Redwater West is comprised of the following core assets:

100 percent ownership of the Redwater NGL 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, multi-product truck loading facilities, 7.8 million gross barrels
of salt cavern storage, and a 80,000 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 contracted fractionation capacity at other
facilities.

43.3 percent direct ownership and 100 percent control of all products
from the nameplate capacity 750 mmcfd Younger NGL extraction plant
located at Taylor in northeastern British Columbia. The Younger plant
supplies local markets as well as Provident's Redwater 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 facility.

A rail car fleet of approximately 500 rail cars under long-term lease
agreement.

Empress East 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 55,000 bpd debutanizer at Empress, Alberta.

50 percent ownership in both the 150,000 bpd Kerrobert pipeline and 1.6
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 10,000 bpd depropanizer.

In Sarnia, Ontario, 16.5 percent ownership of a nameplate capacity
150,000 bpd fractionators and 1.7 mmbbl of raw product storage
capacity, as well as 18.0 percent of 5.7 mmbbl of finished product
storage and a rail, truck and pipeline terminalling facility. An
additional 150,000 bbls of specification product storage capacity is
also contracted in the Sarnia area.

100 percent ownership of the Provident Corunna storage facility. The
1,000 acre site has an active cavern storage capacity of 12.8 million
barrels, consisting of 4.8 million barrels of hydrocarbon storage and
8.0 million barrels currently used for brine storage. The facility also
includes 13 pipeline connections and a rail offloading facility.

A propane distribution terminal at Lynchburg, Virginia.

A rail car fleet of approximately 400 rail cars under long-term lease
agreement.

Commercial Services includes services such as fractionation, storage,
NGL terminalling, loading and offloading that are provided to third
parties on a cost of service or a fee basis utilizing assets at
Provident's Redwater facility. In addition, pipeline tariff income is
generated from Provident's ownership of the LGS 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 these activities have little
direct exposure to market price volatility and are thus relatively
stable. The assets used to generate this fee-for-service income are
also employed to generate proprietary income in Redwater West and
Empress East. Commercial Services also includes operating results from
Three Star, a Saskatchewan based oilfield hauling company serving
Bakken area crude oil producers, of which a two-thirds interest was
acquired in October 2011.

Provident's integrated marketing and distribution arm has offices in
Calgary, Alberta, Sarnia, Ontario, and Houston, Texas and operates
under the brand name Kinetic. Rather than selling NGLs produced by the
Redwater West and Empress East 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 during lower priced periods which can then be 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 arbitrage trading margins by taking advantage of
trading opportunities created by locational price differentials.

Long-term contracts

Provident has several long-term contracts in place to help ensure
product availability and to secure long-term revenue streams. These
contracts include:

A long-term purchase agreement for NGL mix at the Younger NGL extraction
plant.

A significant portion of the available propane, butane and condensate
("propane-plus") fractionation capacity at the Redwater fractionation
facility 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.

A portion of Provident's 80,000 bpd capacity of condensate rail
off-loading is under long-term contracts.

A significant portion of the condensate storage capacity of 500,000
barrels at the Provident Redwater facility is sold under long-term
contracts to various third parties.

A long-term significant propane sales contract at the Provident Redwater
facility.

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.

Agreements with Nova Chemicals Corporation for storage at the Provident
Redwater facility.

A 10-year crude oil storage agreement, totaling approximately one
million barrels of storage capacity, at the Provident Redwater facility
with a major producer on a fee-for-service basis.

A 10-year agreement with a major industrial company in the Sarnia area
for storage and the use of associated pipeline and drying facilities at
the Provident Corunna facility on a fee-for-service basis.

Market environment

Provident's performance is closely tied to market prices for NGLs and
natural gas, which can vary significantly from period to period. The
key reference prices impacting Midstream gross operating margin are
summarized in the following table:

Midstream business reference prices	Year ended December 31,
		2011		2010	% Change

WTI crude oil (US$ per barrel)	$	95.12	$	79.53	20
Exchange rate (from US$ to Cdn$)		0.99		1.03	(4)
WTI crude oil expressed in Cdn$ per barrel	$	94.21	$	81.92	15

AECO natural gas monthly index (Cdn$ per gj)	$	3.48	$	3.93	(11)

Frac Spread Ratio ⁽¹⁾		27.0		20.9	29

Mont Belvieu Propane (US$ per US gallon)	$	1.47	$	1.17	26
Mont Belvieu Propane expressed as a percentage of WTI		65%		62%	5

Market Frac Spread in Cdn$ per barrel⁽²⁾	$	54.67	$	40.30	36

⁽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 average spot prices at Mont Belvieu, weighted based on 65% propane, 25% butane, and 10% condensate, and the AECO monthly index price for natural gas.

The pricing environment for NGLs in 2011 was significantly stronger than
in 2010. The average 2011 WTI crude oil price was US$95.12 per barrel,
representing an increase of 20 percent compared to US$79.53 per barrel
in 2010. The impact of higher WTI crude oil prices was partially
offset by the strengthening of the Canadian dollar relative to the U.S.
dollar in 2011 compared to 2010. Propane prices were also stronger
than in the comparative period, reflecting the increase in crude oil
prices combined with lower North American propane supply for much of
2011 resulting from above average exports and stronger demand from the
petrochemical sector. The Mont Belvieu propane price averaged US$1.47
per U.S. gallon (65 percent of WTI) in 2011, compared to US$1.17 per
U.S. gallon (62 percent of WTI) in 2010. Butane and condensate sales
prices were also much improved in 2011, also reflective of higher crude
oil prices and steady petrochemical and oilsands demand for these
products.

The 2011 AECO natural gas price averaged $3.48 per gj compared to $3.93
per gj during 2010, a decrease of 11 percent. While low natural gas
prices are generally favorable to NGL extraction and fractionation
economics, a sustained period in a low priced gas environment may
impact the availability and overall cost of natural gas and NGL mix
supply in western Canada, as natural gas producers may curtail drilling
activities. However, strengthening NGL pricing in 2011 has resulted in
improved netbacks for producers drilling in natural gas plays with
higher levels of associated NGLs, such as the Montney area in British
Columbia. Increased focus on liquids-rich natural gas drilling is
beneficial to Provident supply, particularly at Redwater. Continued
softness in natural gas prices has improved market frac spreads but has
also caused an increase in extraction premiums paid for natural gas
supply in western Canada, particularly at Empress.

The margins generated from Provident's extraction operations at Empress,
Alberta and Younger, British Columbia are determined primarily by "frac
spreads", which represent the difference between the selling prices for
propane-plus and the input cost of the natural gas required to produce
the respective NGL products. Frac spreads 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 U.S. dollar foreign exchange
rate. Traditionally, a higher frac spread ratio and higher crude oil
prices will result in stronger extraction margins. Differentials
between propane-plus and crude oil prices, as well as location price
differentials will also impact frac spreads. Natural gas extraction
premiums and costs relating to transportation, fractionation, storage
and marketing are not included within frac spreads, however these costs
are included when determining operating margin.

Market frac spreads averaged $54.67 per barrel in 2011, representing a
36 percent increase from $40.30 per barrel in 2010. Higher frac
spreads were a result of higher NGL prices combined with a lower AECO
natural gas price. While Provident benefits directly from higher frac
spreads at its Younger facility, the benefit of higher market frac
spreads in 2011 was offset at Empress by continued high costs for
natural gas supply in the form of extraction premiums. Empress
extraction premiums in 2011 increased approximately 30 percent when
compared to 2010 and, are primarily a result of low volumes of natural
gas flowing past the Empress straddle plants and increased competition
for NGLs as a result of higher frac spreads. Empress border flow was
relatively flat in 2011 compared to 2010 at an average rate of
approximately 4.8 bcf per day. Lower natural gas throughput directly
impacts production at the Empress facilities which in turn reduces the
supply of propane-plus available for sale in Sarnia and in surrounding
eastern markets. Tighter supply at Sarnia may have a positive impact on
eastern sales prices relative to other major propane hubs during
periods of high demand.

Provident partially mitigates the impact of lower natural gas based NGL
supply at Empress through the purchase of NGL mix supply in western
Canada. Provident purchases NGL mix which is transported to the truck
rack at the Provident Empress facility. The NGL mix is then
transported to the premium-priced Sarnia market for fractionation and
sale. Provident also purchases NGL mix supply from other Empress plant
owners as well as in the Edmonton market. While gross operating margins
benefit from additional NGL mix supply, per unit margins are impacted
as margins earned on frac spread gas extraction are typically higher
than margins earned on NGLs purchased on a mix basis.

Industry propane inventories in the United States were approximately
55.2 million barrels at the end of 2011, which is approximately 1.5
million barrels above the five year historical average. Inventory
levels are above the five year historical average primarily due to the
mild winter temperatures across the United States in the fourth quarter
of 2011 that has reduced demand for propane. Year end 2011 Canadian
industry propane inventories were approximately 7.5 million barrels,
1.8 million barrels higher than the historic five year average.
Propane inventories in Canada are at high levels primarily due to mild
winter temperatures in central Canada in the fourth quarter of 2011
that has reduced demand for propane.

Provident Midstream business performance

Provident Midstream results are summarized as follows:

	Year ended December 31,
(bpd)		2011		2010	% Change

Redwater West NGL sales volumes		58,969		63,006	(6)
Empress East NGL sales volumes		45,790		43,069	6
Provident Midstream NGL sales volumes		104,759		106,075	(1)


	Year ended December 31,
($ 000s)		2011		2010	% Change

Redwater West margin	$	213,256	$	160,208	33
Empress East margin		109,439		88,965	23
Commercial Services margin		58,680		63,803	(8)
Gross operating margin		381,375		312,976	22
Realized loss on financial derivative instruments		(66,521)		(50,865)	31
Cash general and administrative expenses		(38,590)		(35,391)	9
Other income and realized foreign exchange		7,110		40	17,675
Adjusted EBITDA attributable to non-controlling interest		(946)		-	-
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs		282,428		226,760	25
Realized loss on buyout of financial derivative instruments		-		(199,059)	(100)
Strategic review and restructuring costs		-		(13,782)	(100)
Adjusted EBITDA	$	282,428	$	13,919	1,929

Gross operating margin

Midstream gross operating margin was $381.4 million for the year ended
December 31, 2011 compared to $313.0 million in 2010. The 22 percent
increase was the result of a higher contribution from both Redwater
West and Empress East by 33 percent and 23 percent, respectively,
partially offset by an eight percent decrease in operating margin from
Commercial Services.

Redwater West

Provident purchases NGL mix from various natural gas producers and
fractionates it into finished products at the Redwater fractionation
facility near Edmonton, Alberta. Redwater West also includes natural
gas supply volumes from the Younger NGL extraction plant located at
Taylor in northeastern British Columbia. The Younger plant supplies
specification NGLs to local markets as well as NGL mix supply to the
Fort Saskatchewan area for fractionation and sale. The feedstock for
Redwater West has a significant portion of NGL mix rather than natural
gas, therefore frac spreads have a smaller impact on operating margin
than in Empress East.

Also located at the Redwater facility is Provident's industry leading
rail-based condensate terminal, which serves the heavy oil industry and
its need for diluent. Provident's condensate terminal is the largest of
its size in western Canada. Income generated from the condensate
terminal and caverns which relates to third-party terminalling and
storage is included within Commercial Services, while income relating
to proprietary condensate marketing activities remains within Redwater
West.

The operating margin for Redwater West in 2011 was $213.3 million, an
increase of 33 percent compared to $160.2 million in 2010. Stronger
2011 results when compared to 2010 were primarily due to stronger
market prices for all NGL products as well as higher frac spreads at
Younger. Overall, Redwater West NGL sales volumes averaged 58,969
barrels per day in 2011, a six percent decrease compared to 2010.
Lower NGL sales volumes can be largely attributed to a decrease in
sales volumes for condensate in 2011 compared to 2010. Condensate sale
volumes decreased compared to the prior year as Provident imported less
condensate via railcar from the U.S. Gulf Coast for sale into the
western Canadian market. Margins on imported condensate supply tend to
be lower than product supplied through western Canadian NGL mix or
product extracted at Younger due to the significant transportation
costs incurred on imported product. Decreases in sales volumes were
more than offset by significant improvements in condensate market
pricing, resulting in a higher product operating margin despite the
decrease in sales volumes.

Product operating margins for propane and butane were higher in 2011
relative to the comparative period primarily due to more favourable
market pricing. Mt. Belvieu pricing for propane and butane both
increased by 26 percent in 2011 compared to 2010. The ethane product
margin increased slightly in 2011 compared to 2010 primarily associated
with increased sales volumes.

Empress East

Provident extracts NGLs from natural gas at the Empress straddle plants
and sells ethane and condensate in the western Canadian marketplace
while transporting propane and butane to Sarnia, Ontario for
fractionation and sale into markets in central Canada and the eastern
United States. The margin in the business is determined primarily by
frac spreads. 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.

Empress East gross operating margin in 2011 was $109.4 million compared
to $89.0 million in 2010. The 23 percent increase was due to increased
sales volumes primarily driven by strong demand for propane in 2011
when compared to 2010 as well as strong refinery demand for butane in
2011. While condensate sales volumes were lower in 2011 compared to
2010 the decrease was more than offset by the significant increase in
condensate market prices, primarily driven by the 20 percent increase
in WTI. Overall, Empress East NGL sales volumes averaged 45,790
barrels per day, a six percent increase compared to 2010. Stronger
market prices for propane-plus products and consistently low gas prices
resulted in higher frac spreads which was also beneficial to gross
operating margin. The positive impacts of strong demand, higher NGL
sales prices and a lower AECO natural gas price were partially offset
by increased extraction premiums paid to purchase natural gas in the
Empress market.

Commercial Services

Provident also utilizes its assets to generate income from
fee-for-service contracts to provide fractionation, storage, NGL
terminalling, loading and offloading services. Income from pipeline
tariffs from Provident's ownership in NGL pipelines is also included in
this activity. During the third quarter of 2011, Provident announced
long-term storage agreements at both the Redwater facility and
Provident's Corunna facility. In the fourth quarter, Provident
announced a long-term storage agreement for crude oil storage at the
Redwater facility. In addition, in the fourth quarter of 2011
Provident completed the acquisition of a two-thirds interest in Three
Star, a Saskatchewan based oilfield hauling company serving Bakken area
crude oil producers.

The gross operating margin for commercial services in 2011 was $58.7
million, a decrease of eight percent compared to $63.8 million in
2010. The decrease in margin was primarily associated with decreased
condensate terminalling revenues partly as a result of the termination
of a multi-year condensate storage and terminalling services agreement
in 2010 as well as the completion in mid-2010 of the Enbridge Southern
Lights pipeline, which transports condensate from the United States to
the Edmonton area. This decrease was partially offset by increases in
margin related to third party storage as well as due to the acquisition
of Three Star.

Earnings before interest, taxes, depreciation, amortization, accretion,
and non-cash items ("adjusted EBITDA")

Adjusted EBITDA includes the impact of the Midstream financial
derivative contract buyout, as well as strategic review and
restructuring costs incurred in 2010, associated with the separation of
the business units. Management has presented a metric excluding these
items as an additional measure to evaluate Provident's performance in
the period and to assess future earnings generating capability.

Adjusted EBITDA excluding buyout of financial derivative instruments and
strategic review and restructuring costs increased to $282.4 million
from $226.8 million in 2010. The increase reflects higher gross
operating margin from both Redwater West and Empress East, partially
offset by higher realized losses on financial derivative instruments
under the market risk management program. In addition, 2011 includes
other income of $6.4 million related to payments received from third
parties relating to certain contractual volume commitments at the
Empress facilities.

Capital expenditures

Provident substantially increased its 2011 growth capital expenditures
when compared to 2010. In 2011, Provident incurred total capital
expenditures of $134.1 million compared to $70.2 million in the prior
year. Driven by substantial demand for new storage services at
Redwater, Provident deployed $34.5 million (2010 - $17.8 million) of
capital on cavern and brine pond development at the Redwater facility,
$22.1 million (2010 - $2.0 million) was directed to the growth-related
portions of the Taylor to Boundary Lake and the Septimus to Younger
pipeline projects, and $39.3 million (2010 - $37.4 million) of
expenditures were directed towards storage and terminalling
infrastructure development at the Provident Corunna facility. An
additional $9.2 million (2010 - nil) was directed toward the
construction of a truck terminal in Cromer, Manitoba while $7.9 million
(2010 - $6.4 million) was spent on various other infrastructure
improvements. Finally, an additional $21.1 million (2010 - $6.6
million) was directed towards sustaining capital activities and office
related capital, including $13.1 million (2010 - $2.0 million) related
to the Taylor to Boundary Lake pipeline.

Net income (loss)

Consolidated		Year ended December 31,
($ 000s, except per share data)			2011		2010	% Change

Net income from continuing operations		$	97,217	$	112,217	(13)
Net loss from discontinued operations			-		(122,723)	(100)
Net income		$	97,217	$	(10,506)	-
Per weighted average share
	- basic and diluted⁽¹⁾	$	0.36	$	(0.04)	-
⁽¹⁾ Based on weighted average number of shares outstanding and includes dilutive impact of convertible debentures.

In 2011, Provident recorded net income of $97.2 million. The net loss
of $10.5 million in 2010 includes a net loss from discontinued
operations of $122.7 million attributed to the sale of the Upstream
business in the second quarter of 2010.

Net income from continuing operations was $97.2 million in 2011,
compared to $112.2 million in 2010. Higher adjusted EBITDA, combined
with the impact of the two identified significant events in 2010 and
the change in unrealized financial derivative instruments, was more
than offset by higher financing, share based compensation and income
tax expenses.

Taxes

Continuing operations	Year ended December 31,
($ 000s)		2011		2010	% Change

Current tax expense (recovery)	$	654	$	(6,956)	-
Deferred income tax expense (recovery)		67,832		(40,871)	-
	$	68,486	$	(47,827)	-

The current tax expense in 2011 of $0.7 million (2010 - $7.0 million
recovery) is mainly attributed to earnings generated in the Company's
recently acquired subsidiary, Three Star, that is in excess of allowed
tax pool claims. The current tax recovery in 2010 was attributed to
applying tax loss carrybacks allowing the recovery of taxes paid in
prior periods. The tax losses in 2010 were generated primarily by the
realized loss on buyout of financial derivative instruments in the
second quarter of 2010.

Deferred income tax expense for 2011 was $67.8 million compared to a
recovery of $40.9 million in 2010. As a result of Provident's adoption
of IFRS, the balance of deferred income taxes on the December 31, 2010
statement of financial position increased by $22.3 million when
compared to the previous Canadian GAAP amount (see note 5 of the
consolidated financial statements). This IFRS difference is primarily
due to the tax rate applied to temporary differences associated with
SIFT entities. Under previous Canadian GAAP, Provident used the rate
expected to be in effect when the timing differences reverse. However,
under IFRS, Provident is required to use the highest rate applicable
for undistributed earnings in these entities. Upon conversion to a
corporation on January 1, 2011, these timing differences are now
measured under IFRS using a corporate tax rate and, as a result, the
majority of the IFRS difference at December 31, 2010 for deferred
income taxes has reversed through first quarter 2011 net earnings,
resulting in incremental deferred tax expense of approximately $24
million. The remaining deferred tax expense in 2011 relates to the use
of existing tax pools to offset earnings generated in the year. The
deferred tax recovery in 2010 was primarily driven by losses created by
deductions at the incorporated subsidiary level under the previous
Trust structure.

At December 31, 2011 Provident has approximately $900 million of tax
pools and non-capital losses available to claim against taxable income
in future years.

Financing charges

Continuing operations	Year ended December 31,
($ 000s, except as noted)		2011		2010	% Change

Interest on bank debt	$	9,798	$	9,316	5
Interest on convertible debentures		21,035		17,538	20
		30,833		26,854	15
Less: Capitalized borrowing costs		(1,348)		-	-
Less: Discontinued operations portion		-		(2,501)	(100)
Total cash financing charges	$	29,485	$	24,353	21

Weighted average interest rate on all long-term debt		5.2%		4.8%	8
Loss on purchase of convertible debentures		3,342		-	-
Accretion and other non-cash financing charges		8,455		9,392	(10)
Less: Discontinued operations portion		-		(1,494)	(100)
Total financing charges	$	41,282	$	32,251	28

Financing charges for 2011 have increased relative to 2010. Interest on
bank debt is higher in 2011 as average borrowing rates on Provident's
revolving credit facility were higher than in 2010. Interest on
convertible debentures for 2011 was also higher than in the prior year
reflecting a higher face value outstanding, partially offset by a
reduced average coupon rate on the convertible debentures outstanding.
Financing charges also increased in 2011 as a result of losses
recognized on the re-purchase of 6.5% convertible debentures in
February 2011 and the redemption of the remaining 6.5% convertible
debentures in May 2011. In addition, the prior year includes an
allocation of interest expense and associated financing charges to
discontinued operations.

In 2011, Provident has capitalized borrowing costs attributable to the
construction of assets, such as storage caverns and related facilities,
which take a substantial period of time to get ready for their intended
use. This reduced the Company's total recognized financing charges in
2011 by $1.3 million (2010 - nil).

Market risk management program

Provident's market risk management program utilizes financial derivative
instruments to provide protection against commodity price volatility
and protect a base level of operating cash flow. Provident has entered
into financial derivative contracts through March 2013 to protect the
relationship between the purchase cost of natural gas and the sales
price of propane, butane and condensate and to protect the relationship
between NGLs and crude oil in physical sales contracts. 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 Provident uses include put
and call options, 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 April 2010, Provident completed the buyout of all fixed price crude
oil and natural gas swaps associated with the Midstream business for a
total cost of $199.1 million. The buyout of Provident's forward mark
to market positions allowed Provident to refocus its market risk
management program on protecting margins on a portion of its frac
spread production and managing physical contract exposure for a period
of up to two years.

Management continues to actively monitor market risk and continues to
mitigate its impact through financial risk management activities.
Subject to market conditions including adequate liquidity, Provident's
intention is to hedge approximately 50 percent of its forecasted
natural gas production volumes and forecasted NGL sales volumes on a
rolling 12 month basis. Subject to market conditions, Provident may add
additional positions as appropriate for up to 24 months.

Settlement of market risk management contracts

The following table summarizes the impact of financial derivative
contracts settled during the years ended December 31, 2011 and 2010.
The table excludes the impact of the Midstream derivative contract
buyout of financial derivative instruments incurred in the second
quarter of 2010 which is presented separately on the consolidated
statement of operations.

			Year ended December 31,
Realized loss on financial derivative instruments			2011			2010
($ 000s except volumes)				Volume ⁽¹⁾			Volume ⁽¹⁾

Frac spread related
	Crude oil	$	(6,186)	0.4	$	(17,315)	2.0
	Natural gas		(12,695)	24.7		(29,849)	16.9
	Propane		(36,630)	3.9		(9,819)	1.6
	Butane		(7,909)	1.2		(4,889)	0.6
	Condensate		(4,833)	0.6		(504)	0.2
	Foreign exchange		(2,205)			3,766
	Sub-total frac spread related		(70,458)			(58,610)
Corporate
	Electricity		2,627			367
	Interest rate		(743)			(847)
Management of exposure embedded in physical contracts			2,053	3.0		8,225	0.6
Realized loss on financial derivative instruments		$	(66,521)		$	(50,865)

⁽¹⁾	The above table represents aggregate 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.

The realized loss for the year ended December 31, 2011 was $66.5 million
compared to a realized loss of $50.9 million in 2010. The majority of
the realized loss in 2011 was driven by NGL derivative sales contracts
settling at a contracted price lower than current NGL market prices,
natural gas derivative purchase contracts settling at a contracted
price higher than the market natural gas prices, as well as crude oil
derivative sales contracts settling at a contracted price lower than
the crude oil market prices during the settlement period. The
comparable 2010 realized loss was driven mostly by natural gas
derivative purchase contracts settling at a contracted price higher
than the market natural gas prices, crude oil derivative sales
contracts settling at contracted crude oil prices lower than the crude
oil market prices during the settlement period, as well as NGL
derivative sales contracts settling at a contracted price lower than
the current NGL market prices.

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

			As at		As at
			December 31,		December 31,
($ 000s)			2011		2010
Frac spread related
	Crude oil	$	10,196	$	16,733
	Natural gas		30,579		19,113
	Propane		(4,784)		16,246
	Butane		2,969		4,755
	Condensate		3,100		2,099
	Foreign exchange		3,747		(28)
	Sub-total frac spread related		45,807		58,918
Management of exposure embedded in physical contracts			12,878		(1,168)
Corporate
	Electricity		(734)		(421)
	Interest rate		2,246		(366)
Other financial derivatives
	Conversion feature of convertible debentures		36,958		9,586
	Redemption liability related to acquisition of Three Star		7,548		-
Net financial derivative instruments liability		$	104,703	$	66,549

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, 2011 through September 30,
2014 (with the exception of the conversion feature of convertible
debentures, which is associated with long-term debt maturing in 2017
and 2018). The balances are required to be recognized in the financial
statements under generally accepted accounting principles. These
financial derivative instruments were generally 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 instruments are actually settled.

For convertible debentures containing a cash conversion option, the
conversion feature is measured at fair value through profit and loss at
each reporting date, with any unrealized gains or losses arising from
fair value changes reported in the consolidated statement of
operations. This resulted in Provident recording a loss of
approximately $19.0 million (2010 - nil) on the revaluation of the
conversion feature of convertible debentures on the consolidated
statement of operations.

Under IFRS, Provident is required to value the put option on the shares
held by the non-controlling interest of its subsidiary, Three Star.
This resulted in the recognition on acquisition of approximately $9.1
million as a redemption liability with an offsetting debit to other
equity based on the present value of the redemption amount. Provident
is also required to measure the fair value of this put option each
reporting date. This resulted in Provident recording a gain of
approximately $1.5 million (2010 - nil) on the consolidated statement
of operations.

Liquidity and capital resources

		As at		As at
Consolidated		December 31,		December 31,
($ 000s)		2011		2010	% Change

Long-term debt - bank facilities and other⁽¹⁾	$	194,135	$	72,882	166
Long-term debt - convertible debentures⁽¹⁾		315,786		400,872	(21)
Working capital surplus (excluding financial derivative instruments)		(97,561)		(79,633)	23
Net debt	$	412,360	$	394,121	5

Shareholders' equity (at book value)		579,058		588,207	(2)
Total capitalization at book value	$	991,418	$	982,328	1

Total net debt as a percentage of total book value capitalization		42%		40%	5
⁽¹⁾Includes current portion of long-term debt.

Midstream revenues are received at various times throughout the month.
Provident's working capital position is affected by commodity price
changes, seasonal fluctuations that reflect changing inventory balances
in the Midstream business and by the timing of Provident's capital
expenditure program. Typically, Provident's inventory levels will
increase in the second and third quarters when product demand is lower,
and will decrease during the fourth and first quarters when product
demand is at its highest. Provident relies on funds flow from
operations, proceeds received under its Premium Dividend and Dividend
Reinvestment purchase ("DRIP") plan, external lines of credit and
access to capital markets to fund capital programs and acquisitions.

Substantially all of Provident's accounts receivable are due from
customers in the oil and gas, petrochemical and refining 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
($ 000s)		Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years

Long-term debt - bank facilities and other ^{(1) (2) (3)}	$	214,552	$	15,718	$	198,834	$	-	$	-
Long-term debt - convertible debentures ⁽³⁾		473,944		19,838		39,675		39,675		374,756
Operating lease obligations		160,447		14,117		30,248		34,052		82,030
Total	$	848,943	$	49,673	$	268,757	$	73,727	$	456,786
⁽¹⁾ The terms of the Canadian credit facility have a revolving three year period expiring on October 14, 2014.
⁽²⁾ Includes current portion of long-term debt.
⁽³⁾ Includes associated interest and principal payments.

Long-term debt and working capital

The amended terms of the Credit Facility provide for a revolving three
year period expiring on October 14, 2014, from the previous maturity
date of June 28, 2013, (subject to customary extension provisions)
secured by substantially all of the assets of Provident. Provident may
draw on the facility by way of Canadian prime rate loans, U.S. base
rate loans, banker's acceptances, LIBOR loans, or letters of credit.

As at December 31, 2011, Provident had drawn $190.1 million (including
$3.6 million presented as a bank overdraft in accounts payable and
accrued liabilities) or 38 percent of its Credit Facility (December 31,
2010 - $75.5 million or 15 percent). At December 31, 2011 the effective
interest rate of the outstanding Credit Facility was 3.3 percent
(December 31, 2010 - 4.1 percent). At December 31, 2011, Provident had
$60.1 million in letters of credit outstanding (December 31, 2010 -
$47.9 million) that guarantee Provident's performance under certain
commercial and other contracts.

On October 3, 2011, Provident completed the acquisition of a two-thirds
interest in Three Star. Three Star's long-term debt is secured by the
vehicles and trailers of the subsidiary and matures over a period of
between two to five years. In addition, Three Star has an operating
line of credit (presented in accounts payable and accrued liabilities)
which is secured by substantially all of the assets of Three Star other
than the vehicles and trailers which are pledged as security for the
subsidiary's long-term debt. As at December 31, 2011, Three Star had
drawn $18.0 million, including $9.2 million, $0.9 million, and $7.9
million presented as current portion of long-term debt, long-term debt
- bank facilities and other, and a bank overdraft in accounts payable
and accrued liabilities, respectively, on the consolidated statement of
financial position. At December 31, 2011, the effective interest rate
of the subsidiary's outstanding long-term debt was 4.9 percent.

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

		As at		As at
		December 31,		December 31,
($ 000s)		2011		2010		Change
Current Assets
Cash and cash equivalents	$	-	$	4,400	$	(4,400)
Accounts receivable		230,457		206,631		23,826
Petroleum product inventory		147,378		106,653		40,725
Prepaid expenses and other current assets		4,559		2,539		2,020
Financial derivative instruments		4,571		487		4,084

Current Liabilities
Accounts payable and accrued liabilities		276,480		227,944		(48,536)
Cash distribution payable		8,353		12,646		4,293
Current portion of long-term debt		9,199		148,981		139,782
Financial derivative instruments		56,901		37,849		(19,052)
Working capital surplus (deficit)	$	36,032	$	(106,710)	$	142,742

The ratio of long-term debt to adjusted EBITDA from continuing
operations for the year ended December 31, 2011 was 1.8 to one compared
to annual 2010 long-term debt to adjusted EBITDA from continuing
operations excluding buyout of financial derivative instruments and
strategic review and restructuring costs of 2.1 to one.

Share capital

On January 1, 2011, Provident Energy Trust (the "Trust") completed a
conversion from an income trust structure to a corporate structure
pursuant to a plan of arrangement on the basis of one common share of
Provident Energy Ltd. in exchange for each unit held in the Trust (see
notes 1 and 13 of the consolidated financial statements). The
conversion resulted in the reorganization of the Trust into a publicly
traded, dividend-paying corporation under the name "Provident Energy
Ltd."

Under Provident's Premium Distribution, Distribution Reinvestment
purchase (DRIP) plan, 4.5 million shares were issued or are to be
issued in 2011 representing proceeds of $37.1 million (2010 - 4.4
million units for proceeds of $32.1 million).

At December 31, 2011 management and directors held less than one percent
of the outstanding common shares.

Capital related expenditures and funding

	Year ended December 31,
($ 000s)		2011		2010	% Change

Capital related expenditures
Capital expenditures	$	(134,115)	$	(70,218)	91
Site restoration expenditures - discontinued operations		-		(2,041)	(100)
Buyout of financial derivative instruments		-		(199,059)	(100)
Acquisitions		(7,852)		-	-
Net capital related expenditures	$	(141,967)	$	(271,318)	(48)

Funded by
Funds flow from operations net of declared dividends to shareholders and DRIP proceeds	$	144,198	$	30,355	375
Proceeds on sale of assets		3		3,300	(100)
Proceeds on sale of discontinued operations		-		106,779	(100)
Cash provided by investing activities from discontinued operations		-		170,710	(100)
Issuance of convertible debentures, net of issue costs		164,950		164,654	-
Repayment of debentures		(249,784)		-	-
Increase (decrease) in long-term debt		109,893		(192,380)	-
Change in working capital, including cash		(27,293)		(12,100)	126
Net capital related expenditure funding	$	141,967	$	271,318	(48)

Provident has funded its net capital expenditures with funds flow from
operations, DRIP proceeds and long-term debt. In 2010, cash provided
by investing activities from discontinued operations, which includes
proceeds on sale of assets from the first quarter sales of oil and
natural gas assets as well as cash proceeds from the second quarter
sale of the remaining Upstream business, were applied to Provident's
revolving term credit facility.

Share based compensation

Share based compensation includes expenses or recoveries associated with
Provident's restricted and performance share plan. Share based
compensation is recorded at the estimated fair value of the notional
shares granted. Compensation expense associated with the plan is
recognized in earnings over the vesting period of each grant. The
expense or recovery associated with each period is recorded as non-cash
share 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, 2011, Provident recorded share based compensation
expense from continuing operations of $20.7 million (2010 - $8.4
million) and made related cash payments of $6.7 million (2010 - $6.9
million). The expense was higher in 2011 as a result of an increase in
Provident's share trading price upon which the compensation is based
and due to recoveries in the second quarter of 2010 from staff
reductions resulting in cancelled and exercised units. The cash cost
was included as part of severance in strategic review and restructuring
costs in 2010. At December 31, 2011, the current portion of the
liability totaled $20.0 million (December 31, 2010 - $7.4 million) and
the long-term portion totaled $11.5 million (December 31, 2010 - $10.4
million).

Discontinued operations (Provident Upstream)

On June 29, 2010, Provident completed a strategic transaction in which
Provident combined the remaining Provident Upstream business with
Midnight Oil Exploration Ltd. ("Midnight") to form Pace Oil & Gas Ltd.
pursuant to a plan of arrangement under the Business Corporations Act
(Alberta). Under the arrangement, Midnight acquired all outstanding
shares of Provident Energy Resources Inc., a wholly-owned subsidiary of
Provident Energy Trust which held all of the producing oil and gas
properties and reserves associated with Provident's Upstream business.
Effective in the second quarter of 2010, Provident's Upstream business
was accounted for as discontinued operations (see note 23 of the
consolidated financial statements).

Control environment

Internal control over financial reporting

Management is responsible for establishing and maintaining adequate
internal control over financial reporting, as defined in Rules 13a -
15(f) and 15d - 15(f) under the United States Exchange Act of 1934, as
amended (the "Exchange Act").

Management, including the Chief Executive Officer ("CEO") and the Chief
Financial Officer ("CFO"), has conducted an evaluation of Provident's
internal control over financial reporting based on criteria established
in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).

Based on management's assessment as at December 31, 2011, management has
concluded that Provident's internal control over financial reporting is
effective. See "Management's Report on Internal Control over Financial
Reporting".

Due to its inherent limitations, internal control over financial
reporting is not intended to provide absolute assurance that a
misstatement of Provident's financial statements would be prevented or
detected. Further, the evaluation of the effectiveness of internal
control over financial reporting was made as of a specific date, and
continued effectiveness in future periods is subject to the risks that
controls may become inadequate.

No changes were made in Provident's internal control over financial
reporting during the fiscal year ended December 31, 2011 that have
materially affected or are reasonably likely to materially affect
Provident's internal control over financial reporting.

Disclosure controls and procedures

An evaluation, as of December 31, 2011, of the effectiveness of the
design and operation of Provident's disclosure controls and procedures,
as defined in Rule 13a - 15(e) and 15d - 15(e) under the Exchange Act,
was carried out by management including the CEO and the CFO. Based on
that evaluation, the CEO and CFO have concluded that the design and
operation of Provident's disclosure controls and procedures were
effective to ensure that information required to be disclosed by
Provident in reports that it files or submits to Canadian and United
States security authorities are (i) recorded, processed, summarized and
reported within the time periods specified by Canadian and United
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 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.

Significant accounting judgements, estimates and assumptions

The preparation of financial statements requires management to make
judgments, estimates and assumptions based on currently available
information that affect the reported amounts of assets, liabilities and
contingent liabilities at the date of the consolidated financial
statements and reported amounts of revenues and expenses during the
reporting period. Estimates and judgments are continuously evaluated
and are based on management's experience and other factors, including
expectations of future events that are believed to be reasonable under
the circumstances. However, actual results could differ from those
estimated. By their very nature, these estimates are subject to
measurement uncertainty and the effect on the financial statements of
future periods could be material.

In the process of applying the Company's accounting policies, management
has made the following judgments, estimates, and assumptions which have
the most significant effect on the amounts recognized in the
consolidated financial statements:

Inventory

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 within
storage caverns can only be determined by draining of the caverns.

Impairment indicators

The recoverable amounts of cash generating units and individual assets
have been determined based on the higher of value in use calculations
and fair values less costs to sell. These calculations require the use
of estimates and assumptions.

Goodwill is tested for impairment annually and at other times when
impairment indicators exist. Impairment is determined for goodwill by
assessing the recoverable amount of the group of cash generating units
that comprise the Midstream business to which the goodwill relates. In
assessing goodwill for impairment, it is reasonably possible that the
commodity price assumptions, sales volumes, supply costs, discount
rates, and tax rates may change which may then impact the recoverable
amount of the group of cash generating units which comprise the
Midstream business and may then require a material adjustment to the
carrying value of goodwill.

For the Midstream business, it is also reasonably possible that these
assumptions may change which may then impact the recoverable amounts of
the cash generating units and may then require a material adjustment to
the carrying value of its tangible and intangible assets. The Company
monitors internal and external indicators of impairment relating to its
tangible and intangible assets.

Decommissioning and restoration costs

Decommissioning and restoration costs will be incurred by the Company at
the end of the operating life of certain of the Company's facilities
and properties. The ultimate decommissioning and restoration costs are
uncertain and cost estimates can vary in response to many factors
including changes to relevant legal and regulatory requirements, the
emergence of new restoration techniques or experience at other
production sites. The expected timing and amount of expenditure can
also change, for example, in response to changes in laws and
regulations or their interpretation. In determining the amount of the
provision, assumptions and estimates are also required in relation to
discount rates.

The decommissioning provisions have been created based on Provident's
internal estimates. Assumptions, based on the current economic
environment, have been made which management believe are a reasonable
basis upon which to estimate the future liability. These estimates are
reviewed regularly to take into account any material changes to the
assumptions. However, actual decommissioning costs will ultimately
depend upon future market prices for the necessary decommissioning work
required which will reflect market conditions at the relevant time.

Income taxes

The Company follows the liability method for calculating deferred income
taxes. Differences between the amounts reported in the financial
statements of the Company and its subsidiaries and their respective tax
bases are applied to tax rates in effect to calculate the deferred tax
liability. In addition, the Company recognizes the future tax benefit
related to deferred income tax assets to the extent that it is probable
that the deductible temporary differences will reverse in the
foreseeable future. Assessing the recoverability of deferred income
tax assets requires the Company to make significant estimates related
to the expectations of future cash flows from operations and the
application of existing tax laws in each jurisdiction. To the extent
that future cash flows and taxable income differ significantly from
estimates, the ability of the Company to realize the deferred tax
assets and liabilities recorded at the balance sheet date could be
impacted. Additionally, future changes in tax laws in the
jurisdictions in which the Company operates could limit the ability of
the Company to obtain tax deductions in future periods.

Contingencies

By their nature, contingencies will only be resolved when one or more
future events occur or fail to occur. The assessment of contingencies
inherently involves the exercise of significant judgment and estimates
of the outcome of future events.

Share based compensation

The Company uses the fair value method of valuing compensation expense
associated with the Company's share based compensation plan whereby
notional shares are granted to employees. Estimating fair value
requires determining the most appropriate valuation model for a grant
of equity instruments, which is dependent on the terms and conditions
of the grant.

Financial derivative instruments

The Company's financial derivative instruments are initially recognized
on the statement of financial position at fair value based on
management's estimate of commodity prices, share price and associated
volatility, foreign exchange rates, interest rates, and the amounts
that would have been received or paid to settle these instruments prior
to maturity given future market prices and other relevant factors.

Property, plant and equipment and intangible assets

Midstream facilities, including natural gas liquids storage and
terminalling facilities and natural gas liquids processing and
extraction facilities are carried at cost and depreciated over the
estimated service lives of the assets. Intangible assets are amortized
over the estimated useful lives of the assets. Capital assets related
to pipelines and office equipment are carried at cost and depreciated
over their economic lives.

Management periodically reviews the estimated useful lives of property,
plant and equipment and intangible assets. These estimates are based on
management's experience and other factors, including expectations of
future events that are believed to be reasonable under the
circumstances. However, actual results could differ from those
estimated.

Change in accounting policies

(i)	Recent accounting pronouncements

	The International Accounting Standards Board ("IASB") issued a number of new accounting pronouncements including IFRS 7 - Financial Instruments: Disclosures, IFRS 9 - Financial Instruments, IFRS 10 - Consolidated Financial Statements, IFRS 11 - Joint Arrangements, IFRS 12 - Disclosure of Interests in Other Entities, and IFRS 13 - Fair Value Measurement as well as related amendments to IAS 1 - Presentation of Financial Statements, IAS 27 - Separate Financial Statements, IAS 28 - Investments in Associates and IAS 32 - Financial Instruments: Presentation. These standards are required to be applied for accounting periods beginning on or after January 1, 2013, with earlier adoption permitted, with the exception of IFRS 7, which is applicable for annual periods beginning on or after July 1, 2011 with earlier adoption permitted, IAS 1, which is effective for annual periods beginning on or after July 1, 2012 with earlier adoption permitted, IFRS 9, which requires application for annual periods beginning on or after January 1, 2015, with earlier adoption permitted and IAS 32, which is applicable for annual periods beginning on or after January 1, 2014, and is required to be applied retrospectively. The Company has not yet assessed the impact of these standards (see note 3(xvii) of the consolidated financial statements).

(ii)	International Financial Reporting Standards (IFRS)

	The Company prepares its financial statements in accordance with Canadian generally accepted accounting principles as set out in the Handbook of the Canadian Institute of Chartered Accountants ("CICA Handbook"). In 2010, the CICA Handbook was revised to incorporate International Financial Reporting Standards ("IFRS"), and requires publicly accountable enterprises to apply such standards effective for years beginning on or after January 1, 2011. This adoption date requires the restatement, for comparative purposes, of amounts reported by Provident for the annual and quarterly periods within the year ended December 31, 2010, including the opening consolidated statement of financial position as at January 1, 2010.

	Provident's quarterly and annual 2011 consolidated financial statements reflect this change in accounting standards. Provident's basis of preparation and adoption of IFRS is described in note 2 of the consolidated financial statements. Significant accounting policies and related accounting judgments, estimates, and assumptions can be found in notes 3 and 4 of the consolidated financial statements. The effect of the Company's transition to IFRS, including transition elections, and reconciliations of the statements of financial position and the statements of operations between previous Canadian GAAP and IFRS is presented in note 5 to the consolidated financial statements.

Business risks

The midstream industry is subject to risks that can affect the amount of
cash flow from operations available for the payment of dividends to
shareholders, 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;

the impact of governmental regulation on Provident;

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 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 marketing business is subject to competition from
other marketing firms;

exposure to commodity price, exchange rate and interest rate
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;

reliance on significant customers;

non-performance risk by counterparties;

government, legislation and regulatory risk;

changes to environmental and other regulations; and

environmental, health and safety risks.

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 disciplined market risk management program to mitigate the
impact that volatile commodity prices have on cash flow available for
the payment of dividends;

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. In addition,
there are risks associated with the Pembina Arrangement. Readers are
referred to the joint information circular of Provident and Pembina
dated February 17, 2012 relating to the Pembina Arrangement, which is
available at www.sedar.com, for a detailed discussion of the risks relating to the Pembina
Arrangement.

Share trading activity

The following table summarizes the share trading activity of Provident
for each quarter in the year ended December 31, 2011 on both the
Toronto Stock Exchange and the New York Stock Exchange:

		Q1		Q2		Q3		Q4
TSE - PVE (Cdn$)
High	$	9.03	$	9.06	$	8.84	$	10.03
Low	$	7.62	$	7.70	$	6.84	$	7.92
Close	$	9.03	$	8.62	$	8.58	$	9.85
Volume (000s)		31,800		29,039		27,238		27,275
NYSE - PVX (US$)
High	$	9.30	$	9.48	$	9.19	$	9.88
Low	$	7.78	$	7.85	$	6.90	$	7.42
Close	$	9.27	$	8.93	$	8.16	$	9.69
Volume (000s)		75,349		83,855		85,031		80,146

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 Provident'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. Forward-looking
information in this MD&A includes, but is not limited to, business
strategy and objectives, capital expenditures, acquisition and
disposition plans and the timing thereof, operating and other costs,
budgeted levels of cash dividends 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 Provident. 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
Provident 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:

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

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

the special meeting dates in respect of the Pembina Arrangement;

the anticipated closing date of the Pembina Arrangement;

the offer by Pembina for Provident's convertible debentures following
the Pembina Arrangement;

the emergence of accretive growth opportunities;

the ability to achieve an appropriate level of monthly cash dividends;

the impact of Canadian governmental regulation on Provident;

the existence, operation and strategy of the market risk management
program;

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

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

the level of capital expenditures;

currency, exchange and interest rates;

the performance characteristics of Provident's business;

the growth opportunities associated with the Provident's business;

the availability and amount of tax pools available to offset Provident's
cash taxes; and

the nature of contractual arrangements with third parties in respect of
Provident's business.

Although Provident 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. Provident cannot
guarantee future results, levels of activity, performance, or
achievements. Moreover, neither Provident 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 Provident'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;

interest payable on notes issued in connection with acquisitions;

governmental regulation in North America of the energy 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;

failure to realize the anticipated benefits of acquisitions;

competition for, among other things, capital reserves 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;

failure to complete the Pembina Arrangement; 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, Provident has made
assumptions regarding, among other things:

future natural gas, crude oil and NGL prices;

the ability of Provident 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 Provident conducts its business;

the impact of increasing competition;

Provident's ability to obtain financing on acceptable terms;

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

the timely receipt of any required regulatory approvals;

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

currency, exchange and interest rates;

certain matters relating to the Pembina Arrangement;

timely receipt of required regulatory and court approvals in respect of
the Pembina Arrangement;

the satisfaction of closing conditions in respect of the Pembina
Arrangement; and

the ability of Provident to successfully market its NGL 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
Provident 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 share data)			2011		2010		2009⁽³⁾
Product sales and service revenue		$	1,955,878	$	1,746,557	$	1,630,491
Net income (loss)			97,217		(10,506)		(89,020)
	Per share - basic and diluted⁽¹⁾		0.36		(0.04)		(0.34)
Total assets			1,588,692		1,446,453		2,548,015
Long-term financial liabilities ⁽²⁾			662,846		430,826		682,625
Declared dividends per share		$	0.54	$	0.72	$	0.75
⁽¹⁾ Includes dilutive impact of convertible debentures.
⁽²⁾ Includes long-term debt, decommissioning liabilities, long-term financial derivative instruments and other long-term liabilities.
⁽³⁾ The financial information for 2009 is presented in previous Canadian GAAP as this period is prior to the January 1, 2010 transition date for IFRS.

Quarterly table

Financial information by quarter (IFRS)
($ 000s except for per share and operating amounts)		2011
			First		Second		Third		Fourth		Annual
			Quarter		Quarter		Quarter		Quarter		Total

Product sales and service revenue		$	519,100	$	416,382	$	450,849	$	569,547	$	1,955,878
Funds flow from continuing operations ⁽¹⁾		$	53,585	$	43,490	$	62,790	$	92,767	$	252,632
Funds flow from continuing operations per share
	- basic and diluted ⁽⁴⁾	$	0.20	$	0.16	$	0.23		0.34	$	0.93
Adjusted EBITDA - continuing operations ⁽²⁾		$	61,242	$	51,298	$	69,528	$	100,360	$	282,428

Adjusted funds flow from continuing operations ⁽³⁾		$	53,585	$	43,490	$	62,790	$	92,767	$	252,632
Adjusted funds flow from continuing operations per share
	- basic and diluted ⁽⁴⁾	$	0.20	$	0.16	$	0.23	$	0.34	$	0.93
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs
	- continuing operations ⁽²⁾	$	61,242	$	51,298	$	69,528	$	100,360	$	282,428

Net (loss) income		$	(11,985)	$	40,219	$	48,398	$	20,585	$	97,217
Net (loss) income per share
	- basic and diluted ⁽⁴⁾	$	(0.04)	$	0.15	$	0.18	$	0.08	$	0.36
Shareholder dividends		$	36,324	$	36,449	$	36,609	$	36,905	$	146,287
Dividends per share		$	0.14	$	0.14	$	0.14	$	0.14	$	0.54
Provident Midstream NGL sales volumes (bpd)			116,864		91,872		94,709		115,714		104,759
⁽¹⁾Based on cash flow from operations before changes in working capital - see "Reconciliation of Non-GAAP measures".
⁽²⁾Adjusted EBITDA is earnings before interest, taxes, depreciation, amortization, and other non-cash items - see "Reconciliation of Non-GAAP measures".
⁽³⁾Adjusted funds flow from continuing operations excludes realized loss on buyout of financial derivative instruments and strategic review and restructuring costs.
⁽⁴⁾Includes dilutive impact of convertible debentures.

Quarterly table

Financial information by quarter (IFRS)
($ 000s except for per unit and operating amounts)		2010
			First		Second		Third		Fourth		Annual
			Quarter		Quarter		Quarter		Quarter		Total

Product sales and service revenue		$	472,940	$	366,125	$	363,767	$	543,725	$	1,746,557
Funds flow from continuing operations ⁽¹⁾		$	46,839	$	(171,334)	$	43,642	$	74,133	$	(6,720)
Funds flow from continuing operations per unit
	- basic	$	0.18	$	(0.65)	$	0.16		0.28	$	(0.03)
	- diluted	$	0.18	$	(0.65)	$	0.16		0.27	$	(0.03)
Adjusted EBITDA - continuing operations ⁽²⁾		$	51,442	$	(176,403)	$	52,538	$	86,342	$	13,919

Adjusted funds flow from continuing operations ⁽³⁾		$	47,325	$	39,152	$	43,642	$	76,002	$	206,121
Adjusted funds flow from continuing operations per unit
	- basic	$	0.18	$	0.15	$	0.16		0.28	$	0.77
	- diluted ⁽⁴⁾	$	0.18	$	0.15	$	0.16		0.27	$	0.77
Adjusted EBITDA excluding buyout of financial derivative instruments and strategic review and restructuring costs
	- continuing operations ⁽²⁾	$	51,928	$	34,083	$	52,538	$	88,211	$	226,760

Net (loss) income		$	(50,921)	$	(40,944)	$	8,979	$	72,380	$	(10,506)
Net (loss) income per unit
	- basic	$	(0.19)	$	(0.15)	$	0.03		0.27	$	(0.04)
	- diluted ⁽⁴⁾	$	(0.19)	$	(0.15)	$	0.03		0.26	$	(0.04)
Unitholder distributions		$	47,634	$	47,794	$	47,990	$	48,221	$	191,639
Distributions per unit		$	0.18	$	0.18	$	0.18		0.18	$	0.72
Provident Midstream NGL sales volumes (bpd)			113,279		94,030		95,388		121,627		106,075
⁽¹⁾Based on cash flow from operations before changes in working capital and site restoration expenditures - see "Reconciliation of Non-GAAP measures".
⁽²⁾Adjusted EBITDA is earnings before interest, taxes, depreciation, amortization, and other non-cash items - see "Reconciliation of Non-GAAP measures".
⁽³⁾Adjusted funds flow from continuing operations excludes realized loss on buyout of financial derivative instruments and strategic review and restructuring costs.
⁽⁴⁾Includes dilutive impact of convertible debentures.

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
Company. 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, 2011, 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 Company's internal control over financial
reporting as of December 31, 2011, has been audited by
PricewaterhouseCoopers LLP, independent auditors, as stated in their
report which appears herein.

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The management of Provident is responsible for the information included
in the consolidated financial statements and Management's Discussion
and Analysis. 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 Management's Discussion and Analysis is consistent with
that presented in the financial statements.

PricewaterhouseCoopers LLP, Chartered Accountants, appointed by the
shareholders, 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
statements and Management's Discussion and Analysis and reports its
findings to the Board of Directors for its consideration in approving
the financial statements.

PROVIDENT ENERGY LTD.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
Canadian dollars (000s)

			As at		As at		As at
			December 31,		December 31,		January 1,
			2011		2010		2010
Assets
Current assets
	Cash and cash equivalents	$	-	$	4,400	$	7,187
	Accounts receivable		230,457		206,631		216,786
	Petroleum product inventory (note 7)		147,378		106,653		58,779
	Prepaid expenses and other current assets		4,559		2,539		4,803
	Financial derivative instruments (note 16)		4,571		487		5,314
	Assets held for sale (note 23)		-		-		186,411
			386,965		320,710		479,280
Non-current assets
	Investments		-		-		18,733
	Exploration and evaluation assets (note 23)		-		-		24,739
	Property, plant and equipment (note 8)		984,217		833,790		1,422,156
	Intangible assets (note 9)		107,118		118,845		132,478
	Goodwill (note 10)		107,430		100,409		100,409
	Deferred income taxes (note 15)		2,962		72,699		-
		$	1,588,692	$	1,446,453	$	2,177,795
Liabilities
Current liabilities
	Accounts payable and accrued liabilities	$	276,480	$	227,944	$	221,417
	Cash dividends payable		8,353		12,646		13,468
	Current portion of long-term debt (note 11)		9,199		148,981		-
	Financial derivative instruments (note 16)		56,901		37,849		86,441
	Liabilities held for sale (note 23)		-		-		2,792
			350,933		427,420		324,118
Non-current liabilities
	Long-term debt - bank facilities and other (note 11)		184,936		72,882		264,776
	Long-term debt - convertible debentures (note 11)		315,786		251,891		240,486
	Decommissioning liabilities (note 12)		85,055		57,232		127,800
	Long-term financial derivative instruments (notes 11 and 16)		52,373		29,187		103,403
	Other long-term liabilities (notes 12 and 14)		20,551		19,634		12,496
	Deferred income taxes (note 15)		-		-		37,765
	Commitments (note 21)
			1,009,634		858,246		1,110,844

Shareholders' equity
Equity attributable to owners of the parent
	Share capital (note 13)		2,911,024		-		-
	Unitholders' contributions (note 13)		-		2,866,268		2,834,177
	Other equity		(8,370)		684		684
	Accumulated deficit		(2,328,241)		(2,278,745)		(1,767,910)
			574,413		588,207		1,066,951
	Non-controlling interest (note 6)		4,645		-		-
			579,058		588,207		1,066,951
		$	1,588,692	$	1,446,453	$	2,177,795

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

On behalf of the Board of Directors:

"Signed"	"Signed"

John B. Zaozirny, Q.C.	Grant D. Billing, CA
Director	Director

PROVIDENT ENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
Canadian dollars (000s except per share amounts)


			Year ended
			December 31,
			2011		2010

Product sales and service revenue (note 18)		$	1,955,878	$	1,746,557
Realized loss on buyout of financial derivative instruments (note 16)			-		(199,059)
Unrealized gain offsetting buyout of financial derivative instruments (note 16)			-		177,723
Loss on financial derivative instruments (note 16)			(69,756)		(103,464)
			1,886,122		1,621,757

Expenses
	Cost of goods sold (note 7)		1,517,070		1,396,635
	Production, operating and maintenance		37,432		18,504
	Transportation		20,001		18,442
	Depreciation and amortization		43,630		44,475
	General and administrative (note 14)		51,059		36,671
	Strategic review and restructuring (note 22)		-		13,782
	Financing charges		41,282		32,251
	Loss on revaluation of conversion feature of convertible debentures and redemption liability (note 16)		17,469		433
	Other income and foreign exchange (note 20)		(7,524)		(3,826)
			1,720,419		1,557,367

Income from continuing operations before taxes			165,703		64,390

Current tax expense (recovery) (note 15)			654		(6,956)
Deferred tax expense (recovery) (note 15)			67,832		(40,871)
			68,486		(47,827)
Net income and comprehensive income from continuing operations			97,217		112,217
Net income (loss) and comprehensive income (loss) from discontinued operations (note 23)			-		(122,723)
Net income (loss) and comprehensive income (loss)		$	97,217	$	(10,506)

Net income (loss) and comprehensive income (loss) attributable to:
	Owners of the parent	$	96,791	$	(10,506)
	Non-controlling interest		426		-
		$	97,217	$	(10,506)

Per share amounts attributable to the equity holders of the Company: Net income per share from continuing operations
	- basic and diluted	$	0.36	$	0.42
Net income (loss) per share
	- basic and diluted	$	0.36	$	(0.04)

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

PROVIDENT ENERGY LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Canadian dollars (000s)

				Year ended
				December 31,
				2011		2010
Cash provided by (used in) operating activities
	Net income for the year from continuing operations		$	97,217	$	112,217
	Add (deduct) non-cash items:
		Depreciation and amortization		43,630		44,475
		Non-cash financing charges and other		8,603		7,956
		Loss on purchase of convertible debentures (note 11)		3,342		-
		Non-cash share based compensation expense		12,469		1,280
		Unrealized gain offsetting buyout of financial derivative instruments (note 16)		-		(177,723)
		Unrealized loss on financial derivative instruments (note 16)		3,235		52,599
		Loss on revaluation of conversion feature of convertible debentures and redemption liability (note 16)		17,469		433
		Unrealized foreign exchange gain and other (note 20)		(414)		(3,786)
		Loss (gain) on sale of assets (note 20)		1		(3,300)
		Deferred tax expense (recovery)		67,832		(40,871)
	Continuing operations			253,384		(6,720)
	Discontinued operations			-		(2,436)
				253,384		(9,156)
	Site restoration expenditures related to discontinued operations			-		(2,041)
	Change in non-cash operating working capital			(33,145)		(28,472)
				220,239		(39,669)

Cash used for financing activities
	Issuance of convertible debentures, net of issue costs (note 11)			164,950		164,654
	Repayment of debentures (note 11)			(249,784)		-
	Increase (decrease) in long-term debt			109,893		(192,380)
	Declared dividends to shareholders			(146,287)		(191,639)
	Issue of shares, net of issue costs (note 13)			37,101		32,091
	Change in non-cash financing working capital			(4,293)		(822)
				(88,420)		(188,096)

Cash (used for) provided by investing activities
	Capital expenditures			(134,115)		(70,218)
	Acquisition (note 6)			(7,852)		-
	Proceeds on sale of assets			3		3,300
	Proceeds on sale of discontinued operations (note 23)			-		106,779
	Change in non-cash investing working capital			5,745		14,407
	Investing activities from discontinued operations			-		170,710
				(136,219)		224,978

Decrease in cash and cash equivalents				(4,400)		(2,787)
Cash and cash equivalents, beginning of year				4,400		7,187
Cash and cash equivalents, end of year			$	-	$	4,400

Supplemental disclosure of cash flow information
	Cash interest paid including debenture interest		$	35,307	$	25,448
	Cash taxes received		$	(1,465)	$	(2,576)

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

PROVIDENT ENERGY LTD.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Canadian Dollars (000s)


		Share capital		Unitholders' contributions		Other equity		Accumulated deficit		Subtotal		Non-controlling interest		Total equity

Balance - December 31, 2010	$	-	$	2,866,268	$	684	$	(2,278,745)	$	588,207	$	-	$	588,207
Cancelled on conversion to a corporation effective January 1, 2011 (note 13)				(2,866,268)						(2,866,268)				(2,866,268)
Issued on conversion to a corporation effective January 1, 2011 (note 13)		2,866,268								2,866,268				2,866,268
Equity associated with redemption liability of non wholly-owned subsidiary (note 6)						(9,054)				(9,054)				(9,054)
Non-controlling interest on acquisition (note 6)												4,219		4,219
Net income and comprehensive income for the year								96,791		96,791		426		97,217
Proceeds on issuance of shares (note 13)		37,124								37,124				37,124
Shares issued on acquisition of subsidiary (notes 6 and 13)		7,606								7,606				7,606
Debenture conversions (notes 11 and 13)		49								49				49
Dividends								(146,287)		(146,287)				(146,287)
Share issue costs		(23)								(23)				(23)
Balance - December 31, 2011	$	2,911,024	$	-	$	(8,370)	$	(2,328,241)	$	574,413	$	4,645	$	579,058


Balance - January 1, 2010	$	-	$	2,834,177	$	684	$	(1,767,910)	$	1,066,951	$	-	$	1,066,951
Net loss and comprehensive loss for the period								(10,506)		(10,506)				(10,506)
Proceeds on issuance of trust units				32,091						32,091				32,091
Cash distributions								(191,639)		(191,639)				(191,639)
Capital distribution in connection with the sale of the Upstream business (note 23)								(308,690)		(308,690)				(308,690)
Balance - December 31, 2010	$	-	$	2,866,268	$	684	$	(2,278,745)	$	588,207	$	-	$	588,207

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

Notes to the Consolidated

Financial Statements

(Tabular amounts in Cdn $ 000s, except share and per share amounts)

December 31, 2011

1. Structure of the Company

Provident Energy Ltd. (the "Company" or "Provident") is incorporated
under the Business Corporations Act (Alberta) and domiciled in Canada.
The address of its registered office is 2100, 250 - 2nd Street S.W.
Calgary, Alberta. Provident owns and manages a natural gas liquids
("NGL") midstream business and was established as a result of the
conversion from an income trust structure, Provident Energy Trust (the
"Trust"), to a corporate structure pursuant to a plan of arrangement.
The conversion resulted in the reorganization of the Trust into a
publicly traded, dividend-paying corporation under the name "Provident
Energy Ltd." effective January 1, 2011. Under the plan of arrangement,
former holders of trust units of the Trust received one common share in
Provident Energy Ltd. in exchange for each trust unit held in the
Trust.

Pursuant to the conversion, the Company acquired, directly and
indirectly, the same assets and business that the Trust owned
immediately prior to the effective time of the conversion and assumed
all of the obligations of the Trust. In accordance with the
conversion, the Trust was dissolved effective January 1, 2011 and
thereafter ceased to exist. The principal undertakings of Provident
Energy Ltd. and its predecessor Provident Energy Trust are collectively
referred to as "the Company" or "Provident" and include the accounts of
Provident and its subsidiaries and partnerships.

The conversion was accounted for on a continuity of interests basis.
Accordingly, the consolidated financial statements reflect the
financial position, results of operations and cash flows as if
Provident Energy Ltd. had always carried on the business formerly
carried on by the Trust. As a result of Provident's conversion from an
income trust to a corporation, effective January 1, 2011, references to
"common shares", "shares", "share based compensation", "shareholders",
"performance share units", "PSUs", "restricted share units", "RSUs",
"premium dividend and dividend reinvestment share purchase (DRIP)
plan", and "dividends" were formerly referred to as "trust units",
"units", "unit based compensation", "unitholders", "performance trust
units", "PTUs", "restricted trust units", "RTUs", "premium
distribution, distribution reinvestment (DRIP) and optional unit
purchase plan", and "distributions", respectively, for periods prior to
January 1, 2011.

2. Basis of preparation and adoption of IFRS

The Company prepares its financial statements in accordance with
Canadian generally accepted accounting principles as set out in the
Handbook of the Canadian Institute of Chartered Accountants ("CICA
Handbook"). In 2010, the CICA Handbook was revised to incorporate
International Financial Reporting Standards as issued by the
International Accounting Standards Board ("IFRS"), and requires
publicly accountable enterprises to apply such standards effective for
years beginning on or after January 1, 2011. Accordingly, the Company
commenced reporting on this basis in the March 31, 2011 interim
consolidated financial statements and for periods thereafter. In the
financial statements, the term "Canadian GAAP" refers to Canadian GAAP
before the adoption of IFRS.

These consolidated financial statements have been prepared in accordance
with IFRS. Subject to certain transition elections disclosed in note 5,
the Company has consistently applied the same accounting policies in
its opening IFRS statement of financial position at January 1, 2010 and
throughout all of the periods presented, as if these policies had
always been in effect. Note 5 discloses the impact of the transition to
IFRS on the Company's reported financial position and financial
performance, including the nature and effect of significant changes in
accounting policies from those used in the Company's consolidated
financial statements for the year ended December 31, 2010.

The policies applied in these consolidated financial statements are
based on IFRS issued and outstanding as of March 6, 2012, the date the
Board of Directors approved the statements.

3. Significant accounting policies

The following accounting policies apply to the continuing operations of
the Company. Policies applicable to the former Upstream oil and gas
operations are disclosed in note 23 - Discontinued operations.

i)	Principles of consolidation

	The consolidated financial statements include the accounts of Provident Energy Ltd. and all direct and indirect subsidiaries and partnerships which Provident controls by having the power to govern the financial and operating policies. These entities are fully consolidated from the date on which control is obtained by Provident. All intercompany transactions, balances, income and expenses, profits and losses and unrealized gains and losses from intercompany transactions are eliminated on consolidation.

	Non-controlling interests represent equity interests in subsidiaries owned by outside parties. The share of net assets of subsidiaries attributable to non-controlling interests is presented as a separate component of equity. Their share of net income and comprehensive income is also recognized in this separate component of equity. Changes in the Company's ownership interest in subsidiaries that do not result in a loss of control are accounted for as equity transactions.

ii)	Financial instruments

	Financial assets and liabilities are classified as financial assets or liabilities at fair value through profit or loss, loans and receivables, held to maturity investments, available for sale financial assets, or other financial liabilities, as appropriate. When financial assets and liabilities are initially recognized, they are measured at fair value.

	Provident determines the classification of its financial assets at initial recognition. The Company's financial assets include cash and cash equivalents, accounts receivable, financial derivative instruments and investments.

	Financial Assets

	a)	Financial assets at fair value through profit or loss

		Financial assets at fair value through profit or loss includes financial assets held for trading and financial assets designated upon initial recognition at fair value through profit or loss. Financial assets are classified as held for trading if they are acquired for the purpose of selling in the near term. The Company's financial derivative instruments, including embedded derivatives, are also classified as held for trading. Gains or losses on financial derivative instruments are recognized in profit or loss.

	b)	Loans and receivables

		Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. After initial measurement, loans and receivables are subsequently carried at amortized cost using the effective interest method less any allowance for impairment. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in the income statements when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company's cash and cash equivalents and accounts receivables are included in this financial asset category.

	Financial Liabilities

	a)	Financial liabilities at fair value through profit or loss

		Financial liabilities at fair value include financial liabilities held for trading and financial liabilities designated upon initial recognition at fair value through profit or loss. Financial liabilities are classified as held for trading if they are acquired for the purpose of selling in the near term. Financial derivative instruments, including embedded derivatives, are also classified as held for trading. Gains and losses on liabilities held for trading are recognized in profit and loss.

	b)	Other financial liabilities

		Other liabilities are recorded initially at fair value of the consideration received less any related transaction costs. Subsequent to initial recognition, the balances are measured at amortized cost using the effective interest method. Gains and losses are recognized in the income statement when the liabilities are derecognized and through amortization expense recorded as financing charges. The Company's accounts payable, accrued liabilities other than share based compensation, cash dividends payable, long-term debt and convertible debentures are included within this financial liability category (also see item xiv).

iii)	Property, plant & equipment

	The initial cost of an asset comprises its purchase price or construction costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation, and for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net in profit or loss.

	Midstream assets

	Midstream facilities, including natural gas liquids storage facilities and natural gas liquids processing and extraction facilities are carried at cost less accumulated depreciation and accumulated impairment losses and are depreciated at a component level on a straight-line basis over the estimated service lives of the assets, which range from 25 to 35 years. Capital assets related to pipelines are carried at cost less accumulated depreciation and accumulated impairment losses and are depreciated at a component level using the straight-line method over their economic lives of approximately 35 years. Vehicles and equipment of the Company's subsidiary, Three Star Trucking Ltd. are carried at cost less accumulated depreciation and accumulated impairment losses, and are depreciated on a 20 percent declining balance basis over their estimated useful lives.

	Minimum NGL product and cavern bottoms

	The minimum NGL product is the minimum volume of NGL product needed as a permanent inventory to maintain adequate reservoir pressures and deliverability rates throughout the withdrawal season within the Company's owned assets. All tanks, caverns or other storage reservoirs require a minimum level of product to maintain a minimum pressure. Below this minimum pressure, products cannot be readily extracted for sale. Minimum NGL product and cavern bottoms within the Company's owned assets are presented as part of Midstream assets within property, plant and equipment and are not depreciated.

	Pipeline fills

	Pipeline fills represent the petroleum based product purchased for the purpose of charging the pipeline system and partially filling the petroleum product storage tanks with an appropriate volume of petroleum products to enable the commercial operation of the facilities and pipeline for all Company owned pipelines and tanks. Pipeline fills within Provident's pipelines are presented as part of Midstream assets within property, plant and equipment and are not depreciated. Holdings of pipeline fills in third party carriers are recorded as product inventory.

	Office equipment and other

	Office equipment and other assets are carried at cost less accumulated depreciation and accumulated impairment losses and are generally depreciated on a straight-line basis over their estimated useful lives. The estimated useful lives for office equipment and other assets are as follows:

	Office equipment5 - 6 years Computer hardware & software3 - 4 years Leasehold improvement & other10 years

	Major maintenance and repairs, inspection, turnarounds and derecognition

	Major maintenance and turnarounds are tracked on a project basis and reviewed by management for potential capitalization. These costs are depreciated on a straight-line basis over a period which represents the estimated period before the next planned maintenance or turnaround. All other maintenance costs are expensed as incurred. Expenditures on major maintenance or repairs comprise the cost of replacement parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated and is now written off is replaced and it is probable that future economic benefits associated with the item will flow to the Company, the expenditure is capitalized. In instances where an asset part is not separately considered a component, the replacement value is used to estimate the carrying amount of the replaced assets, and the previous carrying amount is immediately expensed.

	Impairment of property, plant and equipment

	For operating assets, the impairment test is performed at the cash generating unit level and for office equipment and other assets, the impairment test is performed at the individual asset level. A cash generating unit is determined to be the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets.

	Values of assets are reviewed for impairment when indicators of such impairment exist. If any indication of impairment exists, an estimate of the asset's recoverable amount is calculated. The recoverable amount is determined as the higher of the fair value less costs to sell for the asset and the asset's value in use. If the carrying amount of the asset exceeds its recoverable amount, the asset is deemed impaired and an impairment loss is recognized in profit or loss so as to reduce the carrying amount of the asset to its recoverable amount.

	For assets excluding goodwill, an assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the Company makes an estimate of the recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset's recoverable amount since the last impairment loss was recognized. If that is the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in profit or loss.

iv)	Intangible assets

	Intangible assets acquired separately are recognized at cost upon initial recognition. The cost of intangible assets acquired in a business combination is fair value as at the date of acquisition. Following initial recognition, the cost model is applied requiring the intangible asset to be carried at cost less any accumulated amortization and accumulated impairment losses. Provident will assess whether the useful lives of intangible assets are finite or indefinite. Intangible assets with finite useful lives are assessed for impairment whenever there is an indication that the intangible asset may be impaired and amortized on a straight-line basis over the estimated useful lives of the assets, which range from a period of 12 to 15 years. The amortization expense of intangible assets with finite lives is recognized in depreciation and amortization expense in profit or loss.

	Gains or losses arising from derecognition of an intangible asset are measured as the difference between the net disposal proceeds, if any, and the carrying amount of the asset and are recognized in profit or loss when the asset is derecognized.

v)	Joint arrangements

	A joint arrangement exists when a contractual arrangement exists that establishes shared decision making over the joint activities. Joint control is defined as the contractually agreed sharing of the power to govern the financial and operating policies of a venture so as to obtain benefits from its activities.

	Joint operations

	A joint operation involves the use of assets and other resources of the Company and other venturers rather than the establishment of a corporation, partnership, or other entity. The Company recognizes in its financial statements the assets it controls and the liabilities it incurs and its share of the revenue and expenses from the sale of goods or services by the joint operation arrangement.

	Joint assets

	A joint asset involves joint control and offers joint ownership by the Company and other venturers of assets contributed to or acquired for the purpose of the joint arrangement, without the formation of a corporation, partnership, or other entity. The Company accounts for its share of the joint assets, its share of jointly incurred liabilities with other venturers, any revenue from the sale or use of its share of the output of the joint asset, and any expenses incurred in relation to its interest in the joint asset from the sale of goods or services by the joint asset.

vi)	Leases

	Operating lease payments are recognized as an expense in the statement of operations on a straight-line basis over the lease term.

vii)	Borrowing costs

	Borrowing costs directly attributable to the construction of assets that take a substantial period of time to get ready for their intended use are capitalized as part of the cost of the respective assets. All other borrowing costs are expensed in the period they occur. Borrowing costs consist of interest and other costs that the Company incurs in connection with the borrowing of funds. The capitalization rate used to determine the amount of borrowing costs to be capitalized is the weighted average interest rate applicable to the Company's outstanding borrowings during the period.

viii)	Product inventory

	Inventories of product are valued at the lower of cost and net realizable value based on market prices. Cost is determined using the weighted average costing method and comprises direct purchase costs, costs of production, extraction and fractionation costs, and transportation costs. The amount of any write-down of inventories to net realizable value and all losses of inventories are recognized as an expense and included in cost of goods sold in the period the write-down or loss occurs. Any reversals of write-downs are also included in cost of goods sold.

ix)	Goodwill

	Goodwill is initially measured at cost which represents the excess of the cost of an acquired enterprise over the net of the amounts assigned to assets acquired and liabilities assumed. After initial recognition, goodwill is measured at cost less any accumulated impairment losses.

	Goodwill does not generate cash flows independently of other assets or groups of assets, and often contributes to the cash flows of multiple cash generating units. As a result, for the purpose of impairment testing, goodwill is monitored at the operating business level.

	When a cash generating unit is disposed of, goodwill associated with the operation is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the disposed operation.

	Goodwill is not amortized. Rather, Provident assesses goodwill for impairment at least annually and when circumstances indicate that the carrying value may be impaired. Impairment is determined for goodwill by assessing the recoverable amount of the group of cash generating units that comprise the Midstream business to which the goodwill relates. The recoverable amount is determined based on a fair value less cost to sell calculation using cash flow projections from financial forecasts. If the carrying amount exceeds the recoverable amount of the group of cash generating units that comprise the Midstream business, an impairment loss is recognized. Impairment losses relating to goodwill cannot be reversed in future periods. Provident performs its annual impairment test of goodwill as at December 31.

x)	Decommissioning liabilities

	A decommissioning liability is recognized when the Company has a present legal or constructive obligation to dismantle and remove a facility or an item of property, plant and equipment and restore the site on which it is located, and when a reliable estimate of that liability can be made. Normally an obligation arises for a new facility upon construction or installation. An obligation for decommissioning may also crystallize during the period of operation of a facility through a change in legislation or a decision to terminate operations.

	When a liability for decommissioning cost is recognized, a corresponding amount equivalent to the provision is also recognized as part of the cost of the related property, plant and equipment. The amount recognized represents management's estimate of the present value of the estimated future expenditures of dismantling, demolition and disposal of the facilities, remediation and restoration of the surface land as well as an estimate of the future timing of the costs to be incurred. These costs are subsequently depreciated as part of the costs of the facility or item of property, plant and equipment. Any changes in the estimated timing of the decommissioning or decommissioning cost estimates are accounted for prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment.

	The Company uses a nominal risk free discount rate. The accretion of the decommissioning liability is included as a financing charge.

xi)	Share based compensation

	Provident uses the fair value method of valuing the compensation plans whereby notional shares are granted to employees. The fair value of these notional shares is estimated and recorded as share 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. The fair value measurement is determined at each reporting date using information available at that date.

xii)	Share dilution

	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 dilution calculation.

xiii)	Income taxes

	Current income tax

	Current income tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted at the end of the reporting period, and include any adjustment to tax payable in respect of previous years.

	Deferred income tax

	Provident follows the liability method for calculating deferred income taxes. Differences between the amounts reported in the financial statements of the Company and its corporate subsidiaries and their respective tax bases are applied to tax rates in effect to calculate the deferred tax asset or liability. The effect of any change in income tax rates is recognized in the current period income or equity, as appropriate.

	Deferred tax assets are recognized for deductible temporary differences and the carry-forward of unused tax losses and unused tax credits to the extent that it is probable that taxable profits will be available against which the unused tax losses/credits can be utilized.

	Deferred income tax liabilities are provided in full for all taxable temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements.

	Deferred income tax assets and liabilities are measured at the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted by the balance sheet date. Discounting of deferred tax assets and liabilities is not permitted.

	Deferred income tax relating to items recognized directly in equity is recognized in equity and not in the consolidated statement of operations.

xiv)	Convertible debentures

	The Company's convertible debentures are compound financial instruments consisting of a financial liability and an embedded conversion feature. In accordance with IAS 39, the embedded derivatives are required to be separated from the host contracts and accounted for as stand-alone instruments.

	Debentures containing a cash conversion option allow Provident to pay cash to the converting holder of the debentures, at the option of the Company. As such, the conversion feature is presented as a financial derivative liability within long-term financial derivative instruments. Debentures without a cash conversion option are settled in shares on conversion, and therefore the conversion feature is presented within equity, in accordance with its contractual substance.

	On initial recognition and at each reporting date, the embedded conversion feature is measured using a method whereby the fair value is measured using an option pricing model. Subsequent to initial recognition, any unrealized gains or losses arising from fair value changes are recognized through profit or loss in the statement of operations at each reporting date. On initial recognition, the debt component, net of issue costs, is recorded as a financial liability and accounted for at amortized cost. Subsequent to initial recognition, the debt component is accreted to the face value of the debentures using the effective interest rate method. Upon conversion, the corresponding portions of the debt and equity are removed from those captions and transferred to share capital.

xv)	Revenue recognition

	Revenue associated with the sale of product 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.

xvi)	Foreign currency translation

	The consolidated financial statements are presented in Canadian dollars, which is Provident's functional and presentation currency. Provident's subsidiaries with foreign operations have a functional currency of Canadian dollars. Transactions in foreign currencies are initially recorded at the functional currency rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the functional currency rate of exchange at the balance sheet date, non-monetary items measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions, and revenues and expenses are translated using the exchange rates as at the dates of the initial transactions, with the exception of depreciation and amortization 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.

xvii)	Accounting standards and amendments issued but not yet applied

	International Financial Reporting Standards

	Unless otherwise noted, the following revised standards and amendments are effective for annual periods beginning on or after January 1, 2013 with earlier application permitted. The Company has not yet assessed the impact of these standards and amendments or determined whether it will early adopt them.

	a)	IFRS 9 - Financial Instruments, was issued in November 2009 and addresses classification and measurement of financial assets. It replaces the multiple category and measurement models in IAS 39 for debt instruments with a new mixed measurement model having only two categories: amortized cost and fair value through profit or loss. IFRS 9 also replaces the models for measuring equity instruments. Such instruments are either recognized at fair value through profit or loss or at fair value through other comprehensive income. Where equity instruments are measured at fair value through other comprehensive income, dividends are recognized in profit or loss to the extent that they do not clearly represent a return of investment; however, other gains and losses (including impairments) associated with such instruments remain in accumulated comprehensive income indefinitely.

		Requirements for financial liabilities were added to IFRS 9 in October 2010 and they largely carried forward existing requirements in IAS 39 - Financial Instruments - Recognition and Measurement, except that fair value changes due to credit risk for liabilities designated at fair value through profit and loss are generally recorded in other comprehensive income. IFRS 9 requires application for annual periods beginning on or after January 1, 2015, with earlier adoption permitted.

	b)	IFRS 10 - Consolidated Financial Statements, requires an entity to consolidate an investee when it has power over the investee, is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. Under existing IFRS, consolidation is required when an entity has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. IFRS 10 replaces SIC-12, Consolidation - Special Purpose Entities and parts of IAS 27 - Consolidated and Separate Financial Statements.

	c)	IFRS 11 - Joint Arrangements, requires a venturer to classify its interest in a joint arrangement as a joint venture or joint operation. Joint ventures will be accounted for using the equity method of accounting whereas for a joint operation the venturer will recognize its share of the assets, liabilities, revenue and expenses of the joint operation. Under existing IFRS, entities have the choice to proportionately consolidate or equity account for jointly controlled entities. IFRS 11 supersedes IAS 31 - Interests in Joint Ventures, and SIC-13, Jointly Controlled EntitiesNon-monetary Contributions by Venturers.

	d)	IFRS 12 - Disclosure of Interests in Other Entities, establishes disclosure requirements for interests in other entities, such as subsidiaries, joint arrangements, associates, and unconsolidated structured entities. The standard carries forward existing disclosures and also introduces significant additional disclosure that address the nature of, and risks associated with, an entity's interests in other entities.

	e)	IFRS 13 - Fair Value Measurement, is a comprehensive standard for fair value measurement and disclosure for use across all IFRS standards. The new standard clarifies that fair value is the price that would be received to sell an asset, or paid to transfer a liability in an orderly transaction between market participants, at the measurement date. Under existing IFRS, guidance on measuring and disclosing fair value is dispersed among the specific standards requiring fair value measurements and does not always reflect a clear measurement basis or consistent disclosures.

	f)	There have been amendments to existing standards, including IAS 27 - Separate Financial Statements ("IAS 27"), and IAS 28 - Investments in Associates and Joint Ventures ("IAS 28"). IAS 27 addresses accounting for subsidiaries, jointly controlled entities and associates in non-consolidated financial statements. IAS 28 has been amended to include joint ventures in its scope and to address the changes in IFRS 10 - 13.

	g)	IAS 1 - Presentation of Financial Statements, has been amended to require entities to separate items presented in Other Comprehensive Income ("OCI") into two groups, based on whether or not items may be recycled in the future. Entities that choose to present OCI items before tax will be required to show the amount of tax related to the two groups separately. The amendment is effective for annual periods beginning on or after July 1, 2012, with earlier application permitted.

	h)	IFRS 7 - Financial Instruments: Disclosures, has been amended to include additional disclosure requirements in the reporting of transfer transactions and risk exposures relating to transfers of financial assets and the effect of those risks on an entity's financial position, particularly those involving securitization of financial assets. The amendment is applicable for annual periods beginning on or after July 1, 2011, with earlier application permitted.

	i)	IAS 32 - Financial Instruments: Presentation, has been amended to clarify requirements for offsetting of financial assets and financial liabilities. The amendment is applicable for annual periods beginning on or after January 1, 2014, and is required to be applied retrospectively.

4. Significant accounting judgments, estimates and assumptions

Inventory

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 within storage
caverns can only be determined by draining of the caverns.

Impairment indicators

Decommissioning and restoration costs

Income taxes

Contingencies

Share based compensation

Financial derivative instruments

Property, plant and equipment and intangible assets

5. Transition to IFRS

Provident has prepared its financial statements in accordance with
Canadian GAAP for all periods up to and including the year ended
December 31, 2010. These financial statements for the year ended
December 31, 2011 comply with IFRS applicable for periods beginning on
or after January 1, 2011 and the significant accounting policies
meeting those requirements are described in note 3.

The effect of the Company's transition to IFRS are summarized in this
note as follows:

i)	Transition elections;
ii)	Reconciliation of the consolidated statements of financial position, including shareholders' equity, as previously reported under Canadian GAAP to IFRS; and
iii)	Reconciliation of the consolidated statements of operations as previously reported under Canadian GAAP to IFRS.

i)	Transition elections

	Provident has prepared its IFRS opening consolidated statement of financial position as at January 1, 2010, its date of transition to IFRS. In the preparation of this opening statement of financial position, IFRS 1 allows first-time adopters certain exemptions from the general requirement to apply IFRS retrospectively. Provident has applied the following transition exceptions and exemptions to full retrospective application of IFRS:

	a)	Business combinations - Provident has elected not to apply IFRS 3 retrospectively to business combinations that occurred prior to transition to IFRS on January 1, 2010. Rather, the Company has elected to apply IFRS 3 relating to business combinations prospectively from January 1, 2010. As such previous Canadian GAAP balances relating to business combinations entered into before that date, including goodwill, have been carried forward without adjustment.

	b)	Changes in decommissioning, restoration and similar liabilities - IFRIC 1 Changes in Existing Decommissioning, Restoration and Similar Liabilities requires specified changes in a decommissioning, restoration or similar liabilities to be added to or deducted from the cost of the asset to which it relates. The adjusted depreciable amount of the asset is then depreciated prospectively over its remaining useful life. However, IFRS 1 allows Provident to measure decommissioning, restoration and similar liabilities as at the date of transition to IFRS in accordance with IAS 37 rather than reflecting the impact of changes in such liabilities that occurred before the date of transition to IFRS.

	c)	Property, plant and equipment - The deemed cost of oil and natural gas properties at January 1, 2010, the date of transition to IFRS, was determined by reference to IFRS 1 - First-time Adoption of International Financial Reporting Standards. Upon adoption, the Company has elected to apply the full cost exemption to measure oil and gas assets in the development or production phases by allocating the carrying value determined under Canadian GAAP to cash generating units pro rata using proved and probable reserve values on the date of transition. In addition, any differences arising from the adoption of IFRS from previous Canadian GAAP for decommissioning liabilities related to the Upstream business have been recognized in accumulated deficit on the transition date in accordance with IFRS 1.

	d)	Arrangements containing leases - IFRS 1 allows a first-time adopter to apply the transitional provisions in IFRIC 4 - Determining whether an Arrangement contains a Lease, which allows a first-time adopter to determine whether an arrangement existing at the date of transition to IFRS contains a lease on the basis of facts and circumstances existing at that date. As a first-time adopter, Provident made the same determination of whether an arrangement contained a lease in accordance with previous Canadian GAAP as that required by IFRIC 4 but at a date other than that required by IFRIC 4.

ii)	The following is a reconciliation of the consolidated statements of financial position, including Shareholders' equity, as previously reported under Canadian GAAP to IFRS:


($ 000s)			December 31, 2010			January 1, 2010
		Note	CDN GAAP	Adj	IFRS	CDN GAAP	Adj	IFRS
Assets
Current assets
	Cash and cash equivalents		4,400	-	4,400	7,187	-	7,187
	Accounts receivable		206,631	-	206,631	216,786	-	216,786
	Petroleum product inventory	A	83,868	22,785	106,653	37,261	21,518	58,779
	Prepaid expenses and other current assets		2,539	-	2,539	4,803	-	4,803
	Financial derivative instruments		487	-	487	5,314	-	5,314
	Assets held for sale	I	-	-	-	-	186,411	186,411
			297,925	22,785	320,710	271,351	207,929	479,280

Investments			-	-	-	18,733	-	18,733
Exploration and evaluation assets		I	-	-	-	-	24,739	24,739
Property, plant and equipment		A, B, D, I	832,250	1,540	833,790	2,025,044	(602,888)	1,422,156
Intangible assets			118,845	-	118,845	132,478	-	132,478
Goodwill			100,409	-	100,409	100,409	-	100,409
Deferred income taxes		G	50,375	22,324	72,699	-	-	-
			1,399,804	46,649	1,446,453	2,548,015	(370,220)	2,177,795
Liabilities
Current liabilities
	Accounts payable and accrued liabilities		227,944	-	227,944	221,417	-	221,417
	Cash dividends payable		12,646	-	12,646	13,468	-	13,468
	Current portion of long-term debt		148,981	-	148,981	-	-	-
	Financial derivative instruments		37,849	-	37,849	86,441	-	86,441
	Liabilities held for sale	I	-	-	-	-	2,792	2,792
			427,420	-	427,420	321,326	2,792	324,118

Long-term debt - bank facilities and other			72,882	-	72,882	264,776	-	264,776
Long-term debt - convertible debentures			251,891	-	251,891	240,486	-	240,486
Decommissioning liabilities		B, I	22,057	35,175	57,232	61,464	66,336	127,800
Long-term financial derivative instruments		C	19,601	9,586	29,187	103,403	-	103,403
Other long-term liabilities		F	18,735	899	19,634	12,496	-	12,496
Deferred income taxes		G, I	-	-	-	162,665	(124,900)	37,765
			812,586	45,660	858,246	1,166,616	(55,772)	1,110,844

Shareholders' equity
Unitholders' contributions			2,866,268	-	2,866,268	2,834,177	-	2,834,177
Convertible debentures equity component		C	25,092	(25,092)	-	15,940	(15,940)	-
Other equity		C	2,953	(2,269)	684	2,953	(2,269)	684
Accumulated deficit		H	(2,307,095)	28,350	(2,278,745)	(1,471,671)	(296,239)	(1,767,910)
			587,218	989	588,207	1,381,399	(314,448)	1,066,951
			1,399,804	46,649	1,446,453	2,548,015	(370,220)	2,177,795

iii)The following is a reconciliation of the consolidated statement of
operations as previously reported under Canadian GAAP to IFRS:


			Year ended
($ 000s)			December 31, 2010
		Notes	CDN GAAP	Adj	IFRS

Product sales and service revenue			1,746,557	-	1,746,557
Realized loss on buyout of financial derivative instruments			(199,059)	-	(199,059)
Unrealized gain offsetting buyout of financial derivative instruments			177,723	-	177,723
Loss on financial derivative instruments			(103,464)	-	(103,464)
			1,621,757	-	1,621,757

Expenses
	Cost of goods sold	A	1,397,901	(1,266)	1,396,635
	Production, operating and maintenance		18,504	-	18,504
	Transportation		18,442	-	18,442
	Depreciation and amortization	D, E	45,718	(1,243)	44,475
	General and administrative		36,671	-	36,671
	Strategic review and restructuring		13,782	-	13,782
	Financing charges	B, E	29,723	2,528	32,251
	Loss on revaluation of conversion feature of convertible debentures	C	-	433	433
	Other income and foreign exchange		(3,826)	-	(3,826)
			1,556,915	452	1,557,367
Income from continuing operations before taxes			64,842	(452)	64,390
	Current tax recovery		(6,956)	-	(6,956)
	Deferred income tax recovery	G	(31,694)	(9,177)	(40,871)
			(38,650)	(9,177)	(47,827)
Net income for the year from continuing operations			103,492	8,725	112,217
Net loss from discontinued operations		I	(438,587)	315,864	(122,723)
Net loss and comprehensive loss for the year			(335,095)	324,589	(10,506)

Explanatory notes to the IFRS 1 transition adjustments:

Note: The following items address the transition adjustments applicable
to continuing operations. For a description of the transition
adjustments applicable to discontinued operations, see item I.

A.	Petroleum product inventory - Product inventory required to be stored in third party pipelines as pipeline fill was recorded in property, plant and equipment ("PP&E") under previous Canadian GAAP. Under IFRS, these amounts are recorded as part of petroleum product inventory. Upon transition to IFRS, $21.5 million has been transferred from PP&E to petroleum product inventory. The additional inventory has been processed through the inventory costing calculations with a corresponding reduction on cost of goods sold of $1.3 million for the year ended December 31, 2010. Inventory required for linefill and cavern bottoms in assets owned by Provident remains capitalized in PP&E.

B.	Decommissioning liabilities - The amounts recorded under previous Canadian GAAP were the estimated future cash flows discounted at the Company's average credit-adjusted risk free rate of seven percent. Under IFRS, the amounts are discounted using a risk free rate of four percent at January 1, 2010 and December 31, 2010. Provident recorded an adjustment to increase the decommissioning liabilities for continuing operations by $34.4 million with an offsetting increase in PP&E of $23.3 million and accumulated deficit of $11.1 million representing the pre-2010 earnings impact of this adjustment. The impact of this adjustment on 2010 annual earnings was additional accretion expense $0.7 million.

C.	Convertible debentures equity component - Under previous Canadian GAAP, the portion of initial value associated with the conversion feature of a convertible debenture is classified as a separate component of equity. As a consequence of Provident's status as an income Trust in 2010, IFRS requires the conversion feature of convertible debentures to be classified as a financial instrument on transition and marked-to-market each reporting period. Since the conversion feature of the debentures outstanding on January 1, 2010 was sufficiently out-of-the-money, the fair value of this feature was determined to be nil. As a result, the Canadian GAAP balance of the equity component of convertible debentures at January 1, 2010 of $15.9 million, as well as $2.3 million of related balances in other equity, have been reclassified to accumulated deficit on the transition date.

	In addition, in the fourth quarter of 2010, a new convertible debenture was issued by Provident. Under previous Canadian GAAP, the portion of the initial value of the debenture associated with the conversion feature of $9.2 million was recorded as a separate component of equity. Under IFRS, the value of this conversion feature has been reclassified to long-term financial derivative instruments in the statement of financial position. Under IFRS, Provident is also required to mark-to-market this conversion feature at each reporting period, which resulted in the Company recording an unrealized loss of approximately $0.4 million in the fourth quarter of 2010 in loss on revaluation of conversion feature of convertible debentures in the statement of operations with a corresponding offset to long-term financial derivative instruments.

D.	Depreciation and amortization - IFRS requires that depreciation be calculated at a component level, which resulted in additional depreciation expense from continuing operations of $0.7 million for the year ended December 31, 2010.

E.	Financing charges - Under IFRS, accretion expense associated with decommissioning liabilities is recorded as a financing charge. Under previous Canadian GAAP, accretion expense from continuing operations of $1.9 million for the year ended December 31, 2010 related to asset retirement obligations was recorded under depletion, depreciation and accretion expense. Accordingly, these amounts have been reclassified from depletion, depreciation and accretion expense to financing charges. As a result of this change, the caption depletion, depreciation and accretion expense has been changed to be depreciation and amortization expense.

	The balances recorded under previous Canadian GAAP as interest on bank debt and interest and accretion on convertible debentures are now included under financing charges under IFRS.

F.	Other long-term liabilities - Included in other long-term liabilities are obligations associated with residual Upstream properties. Under previous Canadian GAAP, these obligations were calculated using an average credit-adjusted risk free rate of seven percent. Under IFRS, the obligations are discounted using a risk free rate which resulted in Provident recording an adjustment of $0.9 million as at December 31, 2010.

G.	Deferred income taxes - The transition adjustment associated with continuing operations was $13.1 million. This IFRS difference is primarily due to the tax rate applied to temporary differences associated with SIFT entities. Under previous Canadian GAAP, Provident used the rate expected to be in effect when the timing differences reverse. However, under IFRS, Provident is required to use the highest rate applicable for undistributed earnings in these entities. In addition, IFRS requires the calculation of deferred taxes related to foreign exchange differences on balances denominated in foreign currencies. The 2010 annual net income from continuing operations impact of IFRS differences on deferred taxes was an additional recovery of $9.2 million, resulting in a total adjustment of $22.3 million at December 31, 2010.

	Upon conversion to a corporation on January 1, 2011, all timing differences are now measured under IFRS using a corporate tax rate and, as a result, the majority of the IFRS differences at December 31, 2010 for deferred income taxes has reversed through first quarter 2011 net earnings as a deferred tax expense.

H.	Accumulated deficit - The following is a summary of transition adjustments to the Company's accumulated deficit from Canadian GAAP to IFRS:


			2010
($ millions)		Note		December 31		January 1

Accumulated deficit as reported under Canadian GAAP			$	(2,307.1)	$	(1,471.7)
IFRS transition adjustments increase (decrease) on opening statement of financial position related to continuing operations:
	Petroleum product inventory	A		0.4		0.4
	Decommissioning liabilities	B		(11.1)		(11.1)
	Convertible debentures	C		18.2		18.2
	Other long-term liabilities	F		(0.9)		(0.9)
	Deferred income taxes	G		13.1		13.1
				19.7		19.7

IFRS transition adjustments increase (decrease) on opening statement of financial position related to discontinued operations:
	Impairment on Upstream oil and gas properties	I		(391.5)		(391.5)
	Decommissioning liabilities	I		(36.1)		(36.1)
	Deferred income taxes	I		111.7		111.7
				(315.9)		(315.9)
Total net impact on opening statement of financial position			$	(296.2)	$	(296.2)

IFRS transition adjustments increase (decrease) net income from continuing operations:
	Cost of goods sold	A	$	1.3	$	-
	Loss on financial derivative instruments	C		(0.4)		-
	Depreciation and amortization	D, E		1.2		-
	Financing charges	B, E		(2.5)		-
	Deferred income taxes	G		9.1		-
				8.7		-
IFRS transition adjustments increase (decrease) net income from discontinued operations:
	Depletion expense	I		40.2		-
	Loss on sale of oil and gas properties	I		(8.1)		-
	Loss on sale of discontinued operations	I		296.0		-
	Deferred income taxes	I		(12.2)		-
				315.9		-
Total net impact on statement of operations			$	324.6	$	-
Accumulated deficit as reported under IFRS			$	(2,278.7)	$	(1,76\

Discontinued operations - There are a number of IFRS adjustments associated with the Upstream
business impacting both the statement of financial position on the date
of transition, January 1, 2010 and 2010 net earnings from discontinued
operations. However, the total impact of the combined differences
related to the Upstream business on Provident's equity balance at
December 31, 2010 was nil. Explanatory notes to the IFRS 1 transition
reconciliations for discontinued operations are summarized in the
following table:


			2010
Discontinued operations ($ millions)		Note		December 31		January 1
IFRS transition adjustments increase (decrease) on opening statement of financial position:
	Impairment on Upstream oil and gas properties	1	$	(391.5)	$	(391.5)
	Decommissioning liabilities	2		(36.1)		(36.1)
	Deferred income taxes	5		111.7		111.7
				(315.9)		(315.9)
IFRS adjustments increase (decrease) net income on statement of operations:
	Depletion expense	1		40.2		-
	Loss on sale of oil and gas properties	3		(8.1)		-
	Loss on sale of discontinued operations	6		296.0		-
	Deferred income taxes	5		(12.2)		-
				315.9		-
Net impact on accumulated deficit			$	-	$	(315.9)

1)	Property, plant and equipment - On transition to IFRS, Provident elected to use the IFRS 1 exemption for its Upstream oil & gas assets, allowing for the allocation of historical book values as reported under previous Canadian GAAP to the individual cash generating units on a pro rata basis. If this election is made, each of the cash generating units is required to be tested for impairment. Any impairment loss is recorded in accumulated deficit on the transition date. Accordingly, Provident recorded a $391.5 million impairment loss on transition to IFRS. The lower carrying value for the Upstream assets on transition resulted in a lower loss on sale of the business in the second quarter of 2010 compared to previous Canadian GAAP.

	In addition, upon transition to IFRS, Provident had the option to continue to calculate depletion similar to previous Canadian GAAP using a reserve base of only proved reserves or to use proved plus probable reserves. Provident has elected to use proved plus probable reserves under IFRS. The combination of a lower carrying value due to the impairment loss on transition and the larger depletion base resulted in lower depletion charges related to the Upstream business under IFRS of $40.2 million for the year ended December 31, 2010. This difference is also offset in the loss on sale of the Upstream business in the second quarter of 2010.

2)	Decommissioning liabilities - The amounts recorded under previous Canadian GAAP were the estimated future cash flows discounted at the Company's average credit-adjusted risk free rate of seven percent. Under IFRS, the amounts are discounted using a risk free rate of four percent. The adjustment related to the Upstream business, was an increase of the decommissioning liabilities by $36.1 million with the offset to accumulated deficit.

3)	Assets held for sale - IFRS requires that assets held for sale, be presented separately on the statement of financial position. Previous Canadian GAAP made an exception to this rule for certain upstream oil and gas related transactions. The sale of West Central Alberta assets held in the Upstream business was announced in December 2009. Therefore, assets and associated decommissioning liabilities of $186.4 million and $2.8 million, respectively, related to this transaction have been presented separately on the statement of financial position, at their fair value, determined with reference to the negotiated sales price adjusted for earnings between December 31, 2009 and the date of closing on March 1, 2010. This transaction resulted in a loss on sale of $8.1 million in the first quarter of 2010.

4)	Exploration and evaluation ("E&E") expenditures - IFRS requires that E&E expenditures be presented separately from PP&E on the statement of financial position. Provident has segregated approximately $24.7 million of its PP&E in accordance with the IFRS 1 full cost exemption as at January 1, 2010. In the first and second quarters of 2010, an additional $0.8 million and $0.2 million was incurred, respectively, which also was classified as E&E. The costs consist primarily of land that relates to Upstream undeveloped properties which has not been depleted but rather is assessed for impairment when indicators suggest the possibility of impairment.

5)	Taxes - The transition adjustment for deferred income taxes on transition to IFRS is primarily due to changes in the carrying amount of Upstream assets on the January 1, 2010 statement of financial position and the corresponding impact on temporary differences used to determine the deferred income tax balance. As a result, an adjustment of $111.7 million was recorded with an offset amount recorded in accumulated deficit. Additionally, a reduction in deferred income tax recoveries of $12.2 million was incurred for the year ended December 31, 2010 primarily as a result of lower depletion expense under IFRS.

6)	Loss on sale of discontinued operations - The loss on sale of discontinued operations was impacted by each of the IFRS adjustments 1 through 5 listed above, resulting in an IFRS adjustment to the loss on sale of discontinued operations of $296.0 million, net of tax, for the year ended December 31, 2010.

6. Acquisition

Acquisition of Three Star Trucking Ltd.

On October 3, 2011, Provident acquired a two-thirds ownership interest
in Three Star Trucking Ltd. ("Three Star") for consideration of 944,828
Provident common shares with an ascribed value of $7.6 million and cash
consideration of $7.9 million. Three Star is a Saskatchewan based
oilfield hauling company serving Bakken-area crude oil producers.
Provident retains the option to purchase the remaining one-third
interest in Three Star after three years from the closing date.

The following table summarizes the consideration paid for Three Star,
the fair value of assets acquired, liabilities assumed and the
non-controlling interest at the acquisition date.

Consideration
	Cash	$	7,852
	Shares		7,606
Total consideration		$	15,458

Recognized amounts of identifiable assets acquired and liabilities assumed
	Working capital	$	2,350
	Property, plant and equipment		22,530
	Deferred income taxes		(1,879)
	Long-term debt		(10,345)
	Redemption liability		(9,054)
	Other equity		9,054
Total identifiable net assets			12,656

Non-controlling interest			(4,219)
Goodwill			7,021
Total		$	15,458

Acquisition-related costs of $0.1 million have been charged to general
and administrative expenses in the consolidated statement of
operations.

The fair value of the 944,828 common shares issued as part of the
consideration paid for Three Star was based on the closing share price
on October 3, 2011.

On acquisition, the non-controlling interest was measured at the
proportionate interest in the identifiable net assets. No goodwill was
attributed to non-controlling interest on acquisition.

Provident has the option to purchase (and the non-controlling interest
has the right to sell) the remaining one-third interest in Three Star
after the third anniversary of the acquisition date (October 3, 2014).
The put price to be paid by Provident for the residual interest upon
exercise is based on a multiple of Three Star's earnings during the
three-year period prior to exercise, adjusted for associated capital
expenditures and debt. On acquisition, Provident recorded a $9.1
million redemption liability associated with this put option with an
offset to other equity. The redemption liability will be accreted and
subsequently fair valued at each reporting date with changes in the
value flowing through profit and loss. At December 31, 2011 the fair
value of the redemption liability was determined to be $7.5 million,
resulting in an unrealized gain of $1.5 million for the year ended
December 31, 2011 recorded in loss on revaluation of conversion feature
of convertible debentures and redemption liability on the consolidated
statement of operations.

The revenue included in the consolidated statement of operations since
October 3, 2011 contributed by Three Star was $19.8 million, of which
$13.2 million and $6.6 million were attributable to the owners of the
parent and non-controlling interest, respectively. In addition, net
income included in the consolidated statement of operations since
October 3, 2011 contributed by Three Star was $1.3 million, of which
$0.9 million and $0.4 million were attributable to the owners of the
parent and non-controlling interest, respectively.

7. Petroleum product inventory

When inventories are sold, the carrying amount of those inventories is
recognized as an expense in the period in which the related revenue is
recognized. For the year ended December 31, 2011, the Company
recognized $1,517 million (2010 - $1,397 million) of product inventory
as an expense in cost of goods sold.

8. Property, plant and equipment

($ 000s)		Midstream assets		Office equipment & other		Subtotal		Oil & natural gas properties		Total
Cost:
Balance as at January 1, 2010	$	886,442	$	47,174	$	933,616	$	2,682,180	$	3,615,796
Additions		74,445		673		75,118		31,152		106,270
Acquisitions		-		-		-		5,117		5,117
Change in decommissioning provision		3,902		-		3,902		7,292		11,194
Disposals & Other		(123)		(2,356)		(2,479)		(2,725,741)		(2,728,220)
Balance as at December 31, 2010		964,666		45,491		1,010,157		-		1,010,157
Additions		131,954		813		132,767		-		132,767
Acquisitions		22,530		-		22,530		-		22,530
Capitalized interest		1,348		-		1,348		-		1,348
Change in decommissioning provision		25,494		-		25,494		-		25,494
Removal of fully depreciated assets		(1,765)		(23,601)		(25,366)		-		(25,366)
Disposals & Other		(13)		193		180		-		180
Balance as at December 31, 2011	$	1,144,214	$	22,896	$	1,167,110	$	-	$	1,167,110

Accumulated depletion and depreciation:
Balance as at January 1, 2010	$	116,656	$	27,786	$	144,442	$	2,049,198	$	2,193,640
Depletion and depreciation for the period		25,729		7,056		32,785		123,940		156,725
Disposals		-		(860)		(860)		(2,173,138)		(2,173,998)
Balance as at December 31, 2010		142,385		33,982		176,367		-		176,367
Depreciation for the period		26,522		5,381		31,903		-		31,903
Removal of fully depreciated assets		(1,765)		(23,601)		(25,366)		-		(25,366)
Disposals & Other		(11)		-		(11)		-		(11)
Balance as at December 31, 2011	$	167,131	$	15,762	$	182,893	$	-	$	182,893

Net book value:
Net book value as at January 1, 2010	$	769,786	$	19,388	$	789,174	$	632,982	$	1,422,156
Net book value as at December 31, 2010	$	822,281	$	11,509	$	833,790	$	-	$	833,790
Net book value as at December 31, 2011	$	977,083	$	7,134	$	984,217	$	-	$	984,217

As at December 31, 2011, Midstream assets include land of $4.9 million
(December 31, 2010 - $4.9 million) and products required for line-fill
and cavern bottoms of $22.8 million (2010 - $22.8 million) which are
excluded from costs subject to depreciation.

Capitalized borrowing costs

The amount of borrowing costs directly attributable to the construction
of assets, such as storage caverns and related facilities, which take a
substantial period of time to get ready for their intended use
capitalized during the period ended December 31, 2011 was $1.3 million
(2010 - nil). The rate used to calculate the amount of borrowing costs
capitalized was the weighted average interest rate applicable to the
Company's outstanding borrowings during the period.

9. Intangible assets

($ 000s)		Midstream contracts and customer relationships		Other intangible assets		Total
Cost:
Balance as at January 1, 2010	$	183,100	$	16,308	$	199,408
Balance as at December 31, 2010		183,100		16,308		199,408
Removal of fully amortized assets		(21,100)		-		(21,100)
Balance as at December 31, 2011	$	162,000	$	16,308	$	178,308

Accumulated amortization:
Balance as at January 1, 2010	$	61,862	$	5,068	$	66,930
2010 amortization		13,200		433		13,633
Balance as at December 31, 2010		75,062		5,501		80,563
Amortization for the period		11,298		429		11,727
Removal of fully amortized assets		(21,100)		-		(21,100)
Balance as at December 31, 2011	$	65,260	$	5,930	$	71,190

Net book value:
Net book value as at January 1, 2010	$	121,238	$	11,240	$	132,478
Net book value as at December 31, 2010	$	108,038	$	10,807	$	118,845
Net book value as at December 31, 2011	$	96,740	$	10,378	$	107,118

Useful life (years)		15		12 -15
Remaining amortization period (years)		9		9

10. Goodwill

During the year ended December 31, 2011, goodwill increased by $7.0
million related to the acquisition of Three Star (see note 6).

Provident performed goodwill impairment tests at December 31, 2011 and
2010, as well as at January 1, 2010, which determined that the
recoverable amount of the group of cash generating units that comprise
the Midstream business was in excess of the respective carrying value.
Accordingly, no write-down of goodwill was required. The recoverable
amount was determined based on a fair value less costs to sell
calculation using cash flow projections from financial forecasts
approved by management covering a 15 year period with a terminal growth
rate of 2% thereafter. Key assumptions upon which management based its
determinations of the recoverable amount for the goodwill in 2011
include operating margins which are projected to increase by
approximately 2% per annum, on average, attributable to capital
expenditures and expected growth in the fee-for-service business,
combined with a weighted average discount rate of 9%. The forecast
included future commodity price assumptions based on independent third
party estimates effective at December 31, 2011 of US$100.05/bbl for WTI
crude oil in 2012 with an average escalation rate of 2% per annum until
2026 and $3.60/mcf for AECO natural gas in 2012 with an average
escalation rate of 6% per annum until 2026.

11. Long-term debt

		As at		As at
		December 31,		December 31,
($ 000s)		2011		2010
Current portion of convertible debentures	$	-	$	148,981
Current portion of long-term debt of subsidiary		9,199		-
Current portion of long-term debt		9,199		148,981

Revolving term credit facility		184,019		72,882
Long-term debt of subsidiary		917		-
Long-term debt - bank facilities and other		184,936		72,882

Long-term debt - convertible debentures		315,786		251,891
Total	$	509,921	$	473,754

i)	Revolving term credit facility

	Provident completed an extension of its existing credit agreement (the "Credit Facility") on October 14, 2011, with National Bank of Canada as administrative agent and a syndicate of Canadian chartered banks and other Canadian and foreign financial institutions (the "Lenders"). Pursuant to the amended Credit Facility, the Lenders have agreed to continue to provide Provident with a credit facility of $500 million which, under an accordion feature, can be increased to $750 million at the option of the Company, subject to obtaining additional commitments. The amended Credit Facility also provides for a separate Letter of Credit facility which has been increased from $60 million to $75 million.

	The amended terms of the Credit Facility provide for a revolving three year period expiring on October 14, 2014 (subject to customary extension provisions), secured by substantially all of the assets of Provident. Provident may draw on the facility by way of Canadian prime rate loans, U.S. base rate loans, banker's acceptances, LIBOR loans, or letters of credit. As at December 31, 2011, Provident had drawn $190.1 million (including $3.6 million presented as a bank overdraft in accounts payable and accrued liabilities) or 38 percent of its Credit Facility (December 31, 2010 - $75.5 million or 15 percent). Included in the carrying value at December 31, 2011 were financing costs of $2.2 million (December 31, 2010 - $2.4 million). At December 31, 2011, the effective interest rate of the outstanding Credit Facility was 3.3 percent (December 31, 2010 - 4.1 percent). At December 31, 2011, Provident had $60.1 million in letters of credit outstanding (December 31, 2010 - $47.9 million) that guarantee Provident's performance under certain commercial and other contracts.

ii)	Long-term debt of subsidiary

	On October 3, 2011, Provident completed the acquisition of a two-thirds interest in Three Star. Three Star's long-term debt is secured by the vehicles and trailers owned by the subsidiary and matures over a period of between two to five years. In addition, Three Star has an operating line of credit (presented in accounts payable and accrued liabilities) which is secured by substantially all of the assets of Three Star other than the vehicles and trailers which are pledged as security for the subsidiary's long-term debt. As at December 31, 2011, Three Star had drawn $18.0 million, including $9.2 million, $0.9 million, and $7.9 million presented as current portion of long-term debt, long-term debt - bank facilities and other, and a bank overdraft in accounts payable and accrued liabilities, respectively, on the consolidated statement of financial position. At December 31, 2011, the effective interest rate of the subsidiary's outstanding long-term debt was 4.9 percent.

iii)	Convertible debentures

	In November 2010, Provident issued $172.5 million aggregate principal amount of convertible unsecured subordinated debentures ($164.7 million, net of issue costs). The debentures bear interest at 5.75% per annum, payable semi-annually in arrears on June 30 and December 31 each year commencing June 30, 2011 and mature on December 31, 2017. The debentures may be converted into equity at the option of the holder at a conversion price of $10.60 per share prior to the earlier of December 31, 2017 and the date of redemption, and may be redeemed by Provident under certain circumstances. Upon conversion of the 5.75% debentures, Provident may elect to pay the holder cash at the option of Provident. At issuance, $163.3 million was recorded related to the debt component of the debentures ($155.5 million, net of issue of costs) and the conversion feature of the debentures was valued at $9.2 million and was recorded as a long-term financial derivative instrument.

	On January 13, 2011, in connection with the corporate conversion, Provident Energy Ltd. announced an offer to purchase for cash its 6.5% convertible debentures maturing on August 31, 2012 (the "C series") and its 6.5% convertible debentures maturing on April 30, 2011 (the "D series") at a price equal to 101 percent of their principal amounts plus accrued interest. The offer was completed on February 21, 2011 and resulted in Provident taking up and cancelling $4.1 million principal amount of C series debentures and $81.3 million principal amount of D series debentures. The transaction resulted in Provident recognizing a loss on repurchase of $1.2 million in financing charges in the consolidated statement of operations. The total offer price, including accrued interest, was funded by Provident Energy Ltd.'s existing revolving term credit facility.

	On April 30, 2011 the remaining D series debentures, with a principal amount of $68.6 million matured as scheduled. Provident funded the maturity through the revolving term credit facility.

	In May 2011, Provident issued $172.5 million aggregate principal amount of convertible unsecured subordinated debentures ($165.0 million, net of issue costs). The debentures bear interest at 5.75% per annum, payable semi-annually in arrears on June 30 and December 31 each year commencing December 31, 2011 and mature on December 31, 2018. The debentures may be converted into equity at the option of the holder at a conversion price of $12.55 per share prior to the earlier of December 31, 2018 and the date of redemption, and may be redeemed by Provident under certain circumstances. Upon conversion of the 5.75% debentures, Provident may elect to pay the holder cash at the option of Provident. At issuance, $164.1 million was recorded related to the debt component of the debentures ($156.6 million, net of issue costs) and the conversion feature of the debentures was valued at $8.4 million and was recorded as a long-term financial derivative instrument.

	On May 25, 2011, Provident redeemed all of the outstanding aggregate principal amount of the C series 6.5% convertible debentures at a redemption price equal to $1,000 in cash per $1,000 principal amount, plus accrued interest. The redemption resulted in Provident taking up and cancelling the remaining outstanding $94.9 million principal amount of C series debentures. Provident recognized a loss on the redemption of $2.1 million in financing charges in the consolidated statement of operations. The total redemption, including accrued interest, was funded by Provident Energy Ltd.'s existing revolving term credit facility.

	Provident may elect to satisfy interest and principal obligations on the convertible debentures by the issuance of shares. For the year ended December 31, 2011, $50 thousand of the face value of debentures were converted to shares at the election of debenture holders (2010 - nil). Included in the carrying value at December 31, 2011 were financing costs of $13.4 million (December 31, 2010 - $9.0 million). At December 31, 2011, the fair value of convertible debentures, including the conversion feature, was approximately $357 million (December 31, 2010 - $424 million). The following table details each outstanding convertible debenture.

		As at				As at
Convertible Debentures		December 31, 2011				December 31, 2010
($ 000s except conversion pricing)		Carrying value ⁽¹⁾		Face value		Carrying value⁽¹⁾		Face value	Maturity date		Conversion price per share⁽²⁾
6.5% Convertible Debentures	$	-	$	-		148,981	$	149,980	April 30, 2011	$	12.40
6.5% Convertible Debentures		-		-		96,084		98,999	Aug. 31, 2012		11.56
5.75% Convertible Debentures		157,914		172,500		155,807		172,500	Dec. 31, 2017		10.60
5.75% Convertible Debentures		157,872		172,500		-		-	Dec. 31, 2018		12.55
	$	315,786	$	345,000	$	400,872	$	421,479
⁽¹⁾ Excluding the conversion feature of convertible debentures.
⁽²⁾ The debentures may be converted into shares at the option of the holder of the debenture at the conversion price per share.

The conversion feature of convertible debentures is presented at fair
value as a long-term financial derivative instrument on the
consolidated statement of financial position (see note 16).

12. Decommissioning liabilities

Provident's decommissioning liabilities are based on its net ownership
in property, plant and equipment and represents management's estimate
of the costs to abandon and reclaim those assets as well as an estimate
of the future timing of the costs to be incurred. Estimated cash flows
have been discounted at Provident's nominal risk free rate and an
inflation rate of two percent has been estimated for future years. In
the third quarter of 2011, Provident adjusted the nominal risk free
rate from four percent down to three percent, to reflect recent
interest rate changes in long-term benchmark bond yields. The
resulting adjustment of $21.2 million is presented as a change in
estimate. In 2011, decommissioning liabilities increased by $4.3
million (2010 - $0.2 million) related to future obligations associated
with capital expenditures incurred during the year.

The total undiscounted amount of future cash flows required to settle
the decommissioning liabilities is estimated to be $218.9 million (2010
- $207.3 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 decommissioning liabilities are expected to occur subsequent to the
closure of the facilities and related assets. Settlement of these
liabilities is expected to occur in 23 to 35 years.

		As at		As at
		December 31,		December 31,
($ 000s)		2011		2010
Carrying amount, beginning of year	$	57,232	$	127,800
Acquisitions		-		3,902
Dispositions - discountinued operations		-		(65,184)
Increase in liabilities incurred during the year		4,335		220
Settlement of liabilities during the year - discontinued operations		-		(2,041)
Transfer to other long-term liabilities ⁽¹⁾		-		(18,194)
Accretion of liability - continuing operations		2,329		2,163
Accretion of liability - discontinued operations		-		1,494
Change in estimate		21,159		7,072
Carrying amount, end of year	$	85,055	$	57,232
⁽¹⁾ Commencing on June 30, 2010, obligations associated with residual Upstream properties have been classified as other long-term liabilities on the statement of financial position.

13. Share capital

On January 1, 2011, the Trust completed a conversion from an income
trust structure to a corporate structure pursuant to a plan of
arrangement on the basis of one common share in Provident Energy Ltd.
in exchange for each trust unit held in the Trust. The conversion
resulted in the reorganization of the Trust into a publicly traded,
dividend-paying corporation under the name "Provident Energy Ltd."

Provident's Premium Dividend and Dividend Reinvestment purchase ("DRIP")
plan provides shareholders with a means to automatically reinvest sums
received on account of dividends on shares. Pursuant to the corporate
conversion, the company assigned the DRIP to Provident Energy Ltd.
("PEL DRIP"). As a result, all existing participants in the DRIP were
deemed to be participants in the PEL DRIP without any further action on
their part and holders of common shares may participate in the PEL DRIP
with respect to any cash dividends declared and paid by Provident
Energy Ltd. on the common shares.

On October 3, 2011, Provident completed the acquisition of a two-thirds
interest in Three Star. The acquisition was partially funded by
issuing 944,828 common shares at a price of $8.05.

i)Share capital

Common Shares	Number of shares		Amount (000s)
Issued on conversion to a corporation effective January 1, 2011	268,765,492	$	2,866,268
Issued to acquire Three Star	944,828		7,606
Issued pursuant to the dividend reinvestment plan	4,070,265		33,157
To be issued pursuant to the dividend reinvestment plan	407,724		3,967
Debenture conversions	4,325		49
Share issue costs	-		(23)
Balance at December 31, 2011	274,192,634	$	2,911,024

Provident has an unlimited number of common shares authorized for
issuance.

ii)Unitholders' contributions

Trust Units	Number of units		Amount (000s)
Balance at January 1, 2010	264,336,636	$	2,834,177
Issued pursuant to the distribution reinvestment plan	4,002,565		28,635
To be issued pursuant to the distribution reinvestment plan	426,291		3,456
Balance at December 31, 2010	268,765,492	$	2,866,268
Cancelled on conversion to a corporation effective January 1, 2011	(268,765,492)		(2,866,268)
Balance at December 31, 2011	-	$	-

The basic and diluted per share amounts for the year ended December 31,
2011 were calculated based on the weighted average number of shares
outstanding of 270,741,572 (2010 - 266,008,193).

14. Share based compensation

Restricted/Performance share units

Certain employees of Provident are granted restricted share units (RSUs) and/or performance share units (PSUs), both of which entitle the employee to receive cash compensation in relation to the value of a specific number of underlying notional share units. The grants are based on criteria designed to recognize the long-term value of the employee to the organization. RSUs typically vest evenly over a period of three years commencing at the grant date. Payments are made on the anniversary dates of the RSU to the employees entitled to receive them on the basis of a cash payment equal to the value of the underlying notional share units. PSUs vest three years from the date of grant and can be increased to a maximum of double the PSUs granted or a minimum of nil PSUs depending on the Company's performance based on certain benchmarks.

The fair value estimate associated with the RSUs and PSUs is expensed in the statement of operations over the vesting period. At December 31, 2011, $20.0 million (December 31, 2010 - $7.4 million) is included in accounts payable and accrued liabilities for this plan and $11.5 million (December 31, 2010 - $10.4 million) is included in other long-term liabilities. The following table reconciles the expense recorded for RSUs and PSUs.

	Year ended December 31,
		2011		2010
General and administrative	$	19,162	$	8,160
Production, operating and maintenance		1,491		288
	$	20,653	$	8,448

The following table provides a continuity of the Company's RSU and PSU
plans:

Units outstanding	RSUs	PSUs
Opening balance January 1, 2010	1,576,123	3,959,122
Grants	672,155	1,385,636
Reinvested through notional dividends	105,956	328,868
Exercised	(857,751)	(2,873,270)
Forfeited	(321,475)	(356,775)
Ending balance December 31, 2010	1,175,008	2,443,581
Grants	550,065	470,069
Reinvested through notional dividends	77,378	147,227
Exercised	(562,028)	(722,082)
Forfeited	(16,579)	(21,039)
Ending balance December 31, 2011	1,223,844	2,317,756

At December 31, 2011, all RSUs and PSUs have been valued using
Provident's share price and each PSU has been valued using a multiplier
of 1.25, 1.40, and 1.20, for the 2009, 2010, and 2011 grants,
respectively.

15. Income taxes

Income tax expense (recovery)		Year ended December 31,
($ 000s)		2011		2010

Current tax expense (recovery):
Current tax on profits for the year	$	654	$	(6,956)
Total current tax expense (recovery)		654		(6,956)

Deferred tax expense (recovery):
Origination and reversal of timing differences		67,832		(40,871)
Total deferred tax expense (recovery)		67,832		(40,871)
Income tax expense (recovery)	$	68,486	$	(47,827)

The income tax provision differs from the expected amount calculated by
applying the Company's combined federal and provincial/state income tax
rate of 26.83 percent (2010 - 33.35 percent) as follows:

Reconciliation between provision for income taxes and pre-tax income			Year ended December 31,
($ 000s)			2011		2010

Income from continuing operations before tax		$	165,703	$	64,390
Tax rate			26.83%		33.35%
			44,458		21,474
Tax effects:
	True up		-		-
	Foreign rate differences		-		-
	Rate change due to corporate conversion		24,030		-
	Income not subject to tax - income of the Trust		-		(74,056)
	Other		(2)		4,755
Income tax expense (recovery)		$	68,486	$	(47,827)

The analysis of deferred tax assets and deferred tax liabilities is as
follows:

		As at		As at
		December 31,		December 31,
($ 000s)			2011		2010
Deferred tax assets:
	Deferred tax asset to be recovered after more than 12 months	$	131,872	$	153,900
	Deferred tax asset to be recovered within 12 months		32,000		51,050

Deferred tax liabilities:
	Deferred tax liability to be recovered after more than 12 months		(160,444)		(130,662)
	Deferred tax liability to be recovered within 12 months		(466)		(1,589)
Deferred income taxes		$	2,962	$	72,699

The components of the deferred tax assets and deferred tax liabilities
are as follows:

			As at		As at
			December 31,		December 31,
($ 000s)			2011		2010
Deferred tax asset:
	Decomissioning liabilities	$	23,052	$	16,447
	Loss carryforward		114,808		144,587
	Tax credits		177		16,452
	Financial derivative instruments		18,752		23,526
	Other deductible temporary differences		9,666		14,081
Gross deferred tax asset			166,455		215,093
Valuation allowance			(2,583)		(10,143)
Total deferred tax asset		$	163,872	$	204,950

Deferred tax liability:
	Property, plant and equipment	$	(157,105)	$	(125,873)
	Other taxable temporary differences		(3,805)		(6,378)
Total deferred tax liability		$	(160,910)	$	(132,251)
Deferred income taxes		$	2,962	$	72,699

The movement of the deferred income tax account is as follows:

			Year ended December 31,
($ 000s)			2011		2010
Deferred income tax asset (liability)
	Opening balance, beginning of year	$	72,699	$	(37,765)
	(Expense) recovery from the statement of operations		(67,832)		40,871
	Change related to discontinued operations		-		69,770
	Foreign exchange differences		(26)		(177)
	Acquisition of subsidiary, Three Star		(1,879)		-
Deferred income taxes, end of year		$	2,962	$	72,699

Included in the future income tax asset is estimated non-capital loss
carry forwards that expire in 2026 through 2030. Provident's valuation
allowance applies to other temporary differences that reduce the amount
recorded to the expected amount to be realized.

As at December 31, 2011, the aggregate temporary differences associated
with investments in subsidiaries for which no deferred tax liabilities
have been recognized is $244.3 million (December 31, 2010 - $242.6
million). The amount and timing of reversals of temporary differences
depends on Provident's future operating results, acquisitions and
dispositions of assets and liabilities, and dividend policy. A
significant change in any of the preceding assumptions could materially
affect Provident's estimate of the deferred tax balance.

Prior to conversion to a corporation effective January 1, 2011, IFRS
required temporary differences at the Trust level to be reflected at
the highest rate at which individuals would be taxed on undistributed
profits. Upon corporate conversion, deferred tax balances are
determined using the applicable statutory rate for corporations.

16. 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 Committee ("RMC") oversees execution of the
program and regular reports are provided to the Audit Committee and
Board of Directors.

Provident has established and implemented market risk management
strategies, policies and limits that are monitored by Provident's Risk
Management group. The derivative instruments Provident 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.

The market risk management program is designed to protect a base level
of operating cash flow in order to support cash dividends and capital
programs. The market risk management program manages commodity price
volatility, as well as fluctuating interest and foreign exchange
rates. Provident utilizes a variety of financial instruments to
protect margins on a portion of its frac spread production and sales,
and to manage physical contract exposure for periods of up to two
years. As well, the Provident market risk management strategy reduces
foreign exchange risk due to the exposure arising from the conversion
of U.S. dollars into Canadian dollars.

Fair Values

Fair value measurement of assets and liabilities recognized on the
consolidated statement of financial position are categorized into
levels within a fair value hierarchy based on the nature of valuation
inputs. 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 have been classified as
Level 2 instruments with the exception of the redemption liability
related to the acquisition of the Company's subsidiary, Three Star,
which is classified as a Level 3 instrument. The financial instruments
are carried at fair value as at December 31, 2011 and 2010. The fair
values of Level 2 financial derivative instruments are determined by
reference to independent monthly forward settlement prices, interest
rate yield curves, currency rates, quoted market prices for Provident's
shares, and volatility rates at the period-end dates.

The redemption liability related to Three Star is classified as a Level
3 instrument, as the fair value is determined by using inputs that are
not based on observable market data. The liability represents a put
option, held by the non-controlling interest of Three Star, to sell the
remaining one-third of the business to Provident after the third
anniversary of the acquisition date (October 3, 2014). The put price
to be paid by Provident for the residual interest upon exercise is
based on a multiple of Three Star's earnings during the three year
period prior to exercise, adjusted for associated capital expenditures
and debt based on management estimates. These estimates are subject to
measurement uncertainty and the effect on the financial statements of
future periods could be material.

Financial instruments classified as Level 3	Year ended December 31,
($ 000s)		2011		2010
Redemption liability, beginning of year	$	-	$	-
Acquisition of Three Star (note 6)		9,054		-
Accretion of liability		26		-
Gain on revaluation		(1,532)		-
Redemption liability, end of year	$	7,548	$	-

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.

As at December 31, 2011 ($ 000s)		Held for Trading		Loans and Receivables		Other Liabilities		Total Carrying Value

Assets
Accounts receivable	$	-	$	230,457	$	-	$	230,457
Financial derivative instruments - current assets		4,571		-		-		4,571
	$	4,571	$	230,457	$	-	$	235,028

Liabilities
Accounts payable and accrued liabilities	$	-	$	-	$	276,480	$	276,480
Cash dividends payable		-		-		8,353		8,353
Current portion of long-term debt		-		-		9,199		9,199
Financial derivative instruments - current liabilities		56,901		-		-		56,901
Long-term debt - bank facilities and other		-		-		184,936		184,936
Long-term debt - convertible debentures		-		-		315,786		315,786
Financial derivative instruments - long-term liabilities		52,373		-		-		52,373
Other long-term liabilities		-		-		20,551		20,551
	$	109,274	$	-	$	815,305	$	924,579

As at December 31, 2010 ($ 000s)		Held for Trading		Loans and Receivables		Other Liabilities		Total Carrying Value

Assets
Cash and cash equivalents	$	-	$	4,400	$	-	$	4,400
Accounts receivable		-		206,631		-		206,631
Financial derivative instruments - current assets		487		-		-		487
	$	487	$	211,031	$	-	$	211,518

Liabilities
Accounts payable and accrued liabilities	$	-	$	-	$	227,944	$	227,944
Cash dividends payable		-		-		12,646		12,646
Current portion of long-term debt		-		-		148,981		148,981
Financial derivative instruments - current liabilities		37,849		-		-		37,849
Long-term debt - bank facilities and other		-		-		72,882		72,882
Long-term debt - convertible debentures		-		-		251,891		251,891
Financial derivative instruments - long-term liabilities		29,187		-		-		29,187
Other long-term liabilities		-		-		19,634		19,634
	$	67,036	$	-	$	733,978	$	801,014

Except as disclosed in note 11 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, 2011.

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

			As at		As at
			December 31,		December 31,
($ 000s)			2011		2010

Frac spread related
	Crude oil	$	10,196	$	16,733
	Natural gas		30,579		19,113
	Propane		(4,784)		16,246
	Butane		2,969		4,755
	Condensate		3,100		2,099
	Foreign exchange		3,747		(28)
	Sub-total frac spread related		45,807		58,918
Management of exposure embedded in physical contracts			12,878		(1,168)
Corporate
	Electricity		(734)		(421)
	Interest rate		2,246		(366)
Other financial derivatives
	Conversion feature of convertible debentures		36,958		9,586
	Redemption liability related to acquisition of Three Star		7,548		-
Net financial derivative instruments liability		$	104,703	$	66,549

For convertible debentures containing a cash conversion option, the
conversion feature is measured at fair value through profit and loss at
each reporting date, with any unrealized gains or losses arising from
fair value changes reported in the consolidated statement of
operations. This resulted in Provident recording a loss of
approximately $19.0 million (2010 - $0.4 million) on the revaluation on
the conversion feature of convertible debentures on the consolidated
statement of operations.

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 is
generally comprised of price risk, currency risk and interest rate
risk.

a)Price risk

The decisions to enter into financial derivative positions and to
execute the market 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 the business managers in the decision
making process. Strategies are selected based on their ability to help
Provident provide stable cash flow and dividends per share rather than
to simply lock in a specific commodity price.

Commodity price volatility and market location differentials 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 spreads. Frac
spreads are the difference between the selling prices for propane-plus
and the input cost of the natural gas required to produce the
respective NGL products.

Provident responds to these risks using a market risk management program
to protect margins on a portion of its frac spreads production and
sales, and to manage physical contract exposure for periods of up to
two years while retaining some ability to participate in a widening
margin environment. Subject to market conditions, Provident's
intention is to hedge approximately 50 percent of its production and
sales volumes exposed to frac spreads on a rolling 12 month basis.
Also, subject to market conditions, Provident may add additional
positions as appropriate for up to 24 months.

b)Currency risk

Provident's commodity 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.

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

Provident's revolving term credit facilities bear interest at a floating
rate. Using debt levels as at December 31, 2011, 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 $1.0 million (2010 - $0.4 million). Provident 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 tables show the impact on (loss) gain on financial
derivative instruments if the underlying risk variables of the
financial derivative instruments changed by a specified amount, with
other variables held constant.

As at December 31, 2011 ($ 000s)				+ Change		- Change

Frac spread related
	Crude oil	(WTI +/- $5.00 per bbl)	$	(7,255)	$	7,333
	Natural gas	(AECO +/- $1.00 per gj)		20,349		(20,346)
	NGLs (includes propane, butane)	(Belvieu +/- US $0.10 per gal)		(10,033)		10,033
	Foreign exchange ($U.S. vs $Cdn)	(FX rate +/- $ 0.05)		(14,217)		14,217

Management of exposure embedded in physical contracts
	Crude oil	(WTI +/- $5.00 per bbl)		(5,647)		5,647
	NGLs (includes propane, butane and condensate)	(Belvieu +/- US $0.10 per gal)		4,908		(4,908)

Corporate
	Interest rate	(Rate +/- 50 basis points)		1,599		(1,599)
	Electricity	(AESO +/- $5.00 per MW/h)		218		(218)

Conversion feature of convertible debentures		(Provident share price +/- $0.50 per share)	$	(7,077)	$	6,487

As at December 31, 2010 ($ 000s)				+ Change		- Change

Frac spread related
	Crude oil	(WTI +/- $5.00 per bbl)	$	(9,964)	$	9,892
	Natural gas	(AECO +/- $1.00 per gj)		22,264		(22,272)
	NGLs (includes propane, butane)	(Belvieu +/- US $0.10 per gal)		(9,160)		9,330
	Foreign exchange ($U.S. vs $Cdn)	(FX rate +/- $ 0.05)		(2,839)		2,840

Management of exposure embedded in physical contracts
	Crude oil	(WTI +/- $5.00 per bbl)		(5,506)		5,509
	NGLs (includes propane, butane and condensate)	(Belvieu +/- US $0.10 per gal)		2,480		(2,482)

Corporate
	Interest rate	(Rate +/- 50 basis points)		2,392		(2,392)
	Electricity	(AESO +/- $5.00 per MW/h)		435		(435)

Conversion feature of convertible debentures		(Provident share price +/- $0.50 per share)	$	(1,827)	$	1,654

Liquidity Risk

Liquidity risk is the risk Provident will not be able to meet its
financial obligations as they come due. Provident'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 Provident'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 17.

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

As at December 31, 2011		Payment due by period
($ 000s)		Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
Accounts payable and accrued liabilities	$	276,480	$	276,480	$	-	$	-	$	-
Cash dividends payable		8,353		8,353		-		-		-
Financial derivative instruments - current		56,901		56,901		-		-		-
Long-term debt - bank facilities and other ^{(1) (2) (3)}		214,552		15,718		198,834		-		-
Long-term debt - convertible debentures⁽²⁾		473,944		19,838		39,675		39,675		374,756
Long-term financial derivative instruments		52,373		-		15,415		-		36,958
Other long-term liabilities ⁽²⁾		21,917		2,205		14,357		2,327		3,028
Total	$	1,104,520	$	379,495	$	268,281	$	42,002	$	414,742
⁽¹⁾The terms of the credit facility have a revolving three year period expiring on October 14, 2014.
⁽²⁾Includes associated interest or accretion and principal payments.
⁽³⁾Includes current portion of long-term debt.

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 exposure 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 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. The carrying value of accounts receivable reflects
management's assessment of the associated credit risks. As at December
31, 2011 amounts past due and not impaired included in accounts
receivable is $7.2 million (December 31, 2010 - nil).

Settlement of financial derivative contracts

Midstream financial derivative contract buyout

In April 2010, Provident completed the buyout of all fixed price crude
oil and natural gas swaps associated with the Midstream business for a
total realized loss of $199.1 million. The carrying value of these
specific contracts at March 31, 2010 was a liability of $177.7 million
resulting in an offsetting unrealized gain in the second quarter of
2010. The buyout of Provident's forward mark-to-market positions allows
Provident to refocus its market risk management program on protecting
margins on a portion of its frac spread production and managing
physical contract exposure for a period of up to two years.

The following table summarizes the impact of the loss on financial
derivative instruments during the years ended December 31, 2011 and
2010. The loss on revaluation of conversion feature of convertible
debentures and redemption liability, realized loss on buyout of
financial derivative instruments and unrealized gain offsetting buyout
of financial derivative instruments are not included in the table as
these items are separately disclosed on the consolidated statement of
operations.

		Year ended December 31,
Loss on financial derivative instruments		2011			2010
($ 000s except volumes)				Volume ⁽¹⁾			Volume ⁽¹⁾
Realized loss on financial derivative instruments
Frac spread related
	Crude oil	$	(6,186)	0.4	$	(17,315)	2.0
	Natural gas		(12,695)	24.7		(29,849)	16.9
	Propane		(36,630)	3.9		(9,819)	1.6
	Butane		(7,909)	1.2		(4,889)	0.6
	Condensate		(4,833)	0.6		(504)	0.2
	Foreign exchange		(2,205)			3,766
	Sub-total frac spread related		(70,458)			(58,610)
Corporate
	Electricity		2,627			367
	Interest rate		(743)			(847)
Management of exposure embedded in physical contracts			2,053	3.0		8,225	0.6
			(66,521)			(50,865)
Unrealized loss on financial derivative instruments			(3,235)			(52,599)
Loss on financial derivative instruments		$	(69,756)		$	(103,464)
⁽¹⁾ The above table represents aggregate 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.

The financial derivative contracts in place at December 31, 2011 are
summarized in the following tables:

Midstream
		Volume
Year	Product	(Buy)/Sell		Terms	Effective Period
2012	Crude Oil	1,507	Bpd	US $97.57 per bbl ^{(3) (10)}	January 1 - December 31
		5,548	Bpd	US $95.43 per bbl ^{(3) (11)}	January 1 - March 31
		2,217	Bpd	US $86.71 per bbl ^{(3) (12)}	January 1 - September 30
		1,421	Bpd	US $93.95 per bbl ^{(3) (10)}	January 1 - December 31
		978	Bpd	Cdn $101.82 per bbl ^{(3) (10)}	July 1 - December 31
		1,445	Bpd	Participating Swap Cdn $85.19 per bbl (Average Participation 27% above the floor price)	February 1 - December 31
		1,352	Bpd	Participating Swap US $72.22 per bbl (Average Participation 51% above the floor price)	March 1 - December 31
	Natural Gas	(44,057)	Gjpd	Cdn $3.53 per gj^{(2) (10)}	January 1 - December 31
		(9,578)	Gjpd	Participating Swap Cdn $8.55 per gj (Average Participation 28% below the ceiling price)	February 1 - December 31
	Propane	7,473	Bpd	US $1.55 per gallon ^{(4) (10)}	January 1 - March 31
		(3,297)	Bpd	US $1.0094 per gallon ^{(4) (11)}	January 1 - March 31
		(989)	Bpd	US $1.3375 per gallon^{(5) (11)}	January 1 - March 31
	Normal Butane	(2,654)	Bpd	US $1.7352 per gallon ^{(6) (11)}	January 1 - March 31
		2,445	Bpd	US $1.7434 per gallon ^{(6) (10)}	January 1 - December 31
	ISO Butane	(1,454)	Bpd	US $1.7807 per gallon ^{(7) (11)}	January 1 - March 31
	Condensate	(2,217)	Bpd	US $2.225 per gallon ^{(8) (12)}	January 1 - September 30
	Foreign Exchange			Sell US $24,641,529 per month @ 0.9862 ⁽¹³⁾	January 1 - March 31
				Sell US $2,633,333 per month @ 1.016 ⁽¹³⁾	January 1 - June 30
				Sell US $5,785,714 per month @ 0.996 ⁽¹³⁾	January 1 - July 31
				Sell US $5,144,444 per month @ 0.996 ⁽¹³⁾	January 1 - September 30
				Sell US $2,875,000 per month @ 1.050 ⁽¹³⁾	January 1 - December 31
				Sell US $2,016,783 per month @ 1.0119 ⁽¹³⁾	March 1 - March 31
				Sell US $1,041,721 per month @ 0.9413⁽¹³⁾	April 1 - October 31
				Sell US $2,666,667 per month @ 1.042 ⁽¹³⁾	April 1 - December 31
				Sell US $681,260 per month @ 0.9850 ⁽¹³⁾	May 1 - October 31
				Sell US $1,437,986 per month @ 0.9659 ⁽¹³⁾	July 1 - December 31
				Sell US $1,634,227 per month @ 0.9829 ⁽¹³⁾	October 1 - December 31
				Sell US $1,420,538 per month @ 0.9995⁽¹³⁾	November 1 - December 31
2013	Crude Oil	1,700	Bpd	US $96.65 per bbl ^{(3) (10)}	January 1 - March 31
		1,250	Bpd	Participating Swap Cdn $84.90 per bbl (Average Participation 25% above the floor price)	January 1 - March 31
		758	Bpd	Participating Swap US $85.62 per bbl (Average Participation 30% above the floor price)	January 1 - March 31
	Natural Gas	(15,000)	Gjpd	Cdn $4.58 per gj ^{(2) (10)}	January 1 - March 31
		(9,524)	Gjpd	Participating Swap Cdn $8.87 per gj (Average Participation 22% below the ceiling price)	January 1 - March 31
	Foreign Exchange			Sell US $1,651,990 per month @ 0.9829 ⁽¹³⁾	January 1 - January 31
				Sell US $1,397,250 per month @ 0.9995 ⁽¹³⁾	January 1 - March 31
				Sell US $5,000,000 per month @ 1.050⁽¹³⁾	January 1 - March 31

Corporate
			Volume
Year	Product		(Buy)/Sell		Terms	Effective Period
	Electricity		(5)	MW/h	Cdn $62.00 per MW/h ⁽⁹⁾	January 1 2012 - December 31 2012
	Interest Rate	$	180,000,000	Notional (Cdn$)	Pay Average Fixed rate of 1.877% ⁽¹⁴⁾	October 1 2011 - June 30 2013
		$	50,000,000	Notional (Cdn$)	Pay Average Fixed rate of 1.124% ⁽¹⁴⁾	July 1 2013 - September 30 2014

⁽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⁾							Crude Oil contracts are settled against NYMEX WTI Calendar Average.
⁽⁴⁾							Propane contracts are settled against Belvieu C3 TET.
⁽⁵⁾							Propane contracts are settled against Conway C3.
⁽⁶⁾							Normal Butane contracts are settled against Belvieu NC4 NON TET & Belvieu NC4 TET.
⁽⁷⁾							ISO Butane contracts are settled against Belvieu IC4 NON TET.
⁽⁸⁾							Condensate contracts are settled against Belvieu NON-TET Natural Gasoline.
⁽⁹⁾							Electricity contracts are settled against the hourly price of Electricity as published by the AESO in $/MWh.
⁽¹⁰⁾							FRAC spread contracts.
⁽¹¹⁾							Management of physical contract exposure - NGL Product contracts.
⁽¹²⁾							Management of physical contract exposure - Rail contracts.
⁽¹³⁾							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 underlying commodity.
⁽¹⁴⁾							Interest rate forward contract settles monthly against 1M CAD BA CDOR.

17. Capital management

Provident considers its total capital to be comprised of net debt and
shareholders' 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, 2011 and December 31, 2010 were as follows:

		As at		As at
		December 31,		December 31,
($ 000s)		2011		2010
Working capital surplus ⁽¹⁾	$	(97,561)	$	(79,633)
Long-term debt (including current portion)		509,921		473,754
Net debt		412,360		394,121
Shareholders' equity		579,058		588,207
Total capitalization	$	991,418	$	982,328

Net debt to total capitalization		42%		40%
⁽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 shareholder value by:

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

ensuring financing capacity for Provident's internal development
opportunities and acquisitions that are expected to add value to
shareholders.

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

On January 1, 2011, the Trust completed a conversion from an income
trust structure to a corporate structure pursuant to a plan of
arrangement. The conversion resulted in the reorganization of the
Trust into a publicly traded, dividend-paying corporation under the
name "Provident Energy Ltd."

18. Product sales and service revenue

For the year ended December 31, 2011, included in product sales and
service revenue is $259.6 million (2010 - $202.7 million) associated
with U.S. midstream sales.

19. Supplemental disclosures

Consolidated statements of operations presentation

The following table details the amount of total employee compensation
costs included in the cost of goods sold, production, operating and
maintenance, and general and administrative line items in the
consolidated statements of operations for the years ended December 31,
2011 and 2010:

Employee compensation costs	Year ended December 31,
($ 000s)		2011		2010
Salaries and short-term benefits⁽¹⁾	$	29,657	$	27,065
Share based compensation⁽¹⁾		20,653		8,448
Total	$	50,310	$	35,513
⁽¹⁾Excludes amounts classified as strategic review and restructuring in 2010.

Compensation of key management

Compensation awarded to key management included:

Remuneration of directors and senior management	Year ended December 31,
($ 000s)		2011		2010⁽¹⁾
Salaries and short-term benefits	$	4,744	$	4,589
Termination benefits		336		18,781
Share based compensation		5,783		2,943
Total	$	10,863	$	26,313
⁽¹⁾ For the year ended December 31, 2010, a portion of the expenses were included in discontinued operations.

Key management includes the Company's officers and directors.

20. Other income and foreign exchange

Other income and foreign exchange is comprised of:

Other income and foreign exchange	Year ended December 31,
($ 000s)		2011		2010
Realized (gain) loss on foreign exchange	$	(669)	$	3,425
Loss (gain) on sale of assets		1		(3,300)
Other		(6,442)		(165)
		(7,110)		(40)
Unrealized (gain) loss on foreign exchange		(473)		808
Gain on termination of agreement		-		(4,900)
Other		59		306
		(414)		(3,786)
Total	$	(7,524)	$	(3,826)

For the year ended December 31, 2011, Provident recognized other income
of $6.4 million from third parties relating to payments received for
certain contractual volume commitments at the Empress facilities.

During the third quarter of 2010, Provident agreed to terminate a
multi-year condensate storage and terminalling services agreement with
a third party in exchange for a parcel of land valued at $4.9 million.
The transaction was accounted for as a non-monetary transaction and
included in property, plant and equipment on the consolidated statement
of financial position with a corresponding gain included in "Other
income and foreign exchange" on the consolidated statement of
operations.

In the third quarter of 2010, Provident received proceeds of $3.3
million from the sale of certain asset-backed commercial paper
investments that had previously been written off. Provident recorded a
gain on sale in "Other income and foreign exchange" on the consolidated
statement of operations.

21. Commitments

Provident has entered into operating leases for offices that extend
through June 2022. However, a significant portion will be recovered
through subleases with third parties. In relation to the Midstream
business, 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, 2011		Payment due by period
($ 000s)		Total		Less than 1 year		1 to 3 years		3 to 5 years
Operating Leases
Office leases	$	60,781	$	12,003	$	24,234	$	24,544
Sublease recovery		(39,751)		(9,647)		(18,365)		(11,739)
		21,030		2,356		5,869		12,805
Rail tank cars		35,809		6,953		15,487		13,369
Younger plant		21,578		4,808		8,892		7,878
Total	$	78,417	$	14,117	$	30,248	$	34,052

22. Strategic review and restructuring

In 2010, Provident completed a strategic transaction to separate its
Upstream and Midstream businesses. An agreement was reached with
Midnight Oil Exploration Ltd. ("Midnight") to combine the remaining
Provident Upstream business with Midnight in a $416 million
transaction. Closing of this arrangement occurred on June 29, 2010. In
conjunction with this transaction and other initiatives, Provident
completed an internal reorganization to continue as a pure play, cash
distributing natural gas liquids (NGL) infrastructure and logistics
business which resulted in staff reductions at all levels of the
organization, including senior management.

On January 1, 2011, the Trust completed a conversion from an income
trust structure to a corporate structure pursuant to a plan of
arrangement. The conversion resulted in the reorganization of the Trust
into a publicly traded, dividend-paying corporation under the name
"Provident Energy Ltd."

For the year ended December 31, 2011, no strategic review and
restructuring costs were incurred (2010 - $31.7 million, of which $13.8
million were attributable to continuing operations). The costs were
comprised primarily of severance, consulting and legal costs related to
the sale of the Upstream business. In the fourth quarter of 2010, $1.9
million in costs were incurred related to Provident's reorganization
into a dividend paying corporation effective January 1, 2011.

23. Discontinued operations (Provident Upstream)

On June 29, 2010, Provident completed a strategic transaction in which
Provident combined the remaining Provident Upstream business with
Midnight to form Pace Oil & Gas Ltd. ("Pace") pursuant to a plan of
arrangement under the Business Corporations Act (Alberta) (the
"Midnight Arrangement"). Under the Midnight Arrangement, Midnight
acquired all outstanding shares of Provident Energy Resources Inc., a
wholly-owned subsidiary of Provident Energy Trust which held all of the
producing oil and gas properties and reserves associated with
Provident's Upstream business. Total consideration from the
transaction was $423.7 million, consisting of $115 million in cash and
approximately 32.5 million shares of Pace valued at $308.7 million at
the time of the closing. Associated transaction costs were $8.1
million. Under the terms of the Midnight Arrangement, Provident
unitholders divested a portion of each of their Provident units to
receive 0.12225 shares of Pace, which was recorded as a non-cash
distribution by the Trust, valued at $308.7 million. Provident
recorded a loss on sale of $79.8 million and $58.1 million in deferred
tax recovery related to this transaction. This transaction completed
the sale of the Provident Upstream business in a series of transactions
between September 2009 to June 2010.

The following table presents information on the net loss from
discontinued operations.

	Year ended December 31,
Net loss from discontinued operations ($ 000s)	2011		2010
Production revenue, net of royalties	$	-	$	76,581
Loss from discontinued operations before taxes and impact of sale of discontinued operations⁽¹⁾		-		(112,702)
Loss on sale of discontinued operations		-		(79,790)
Current tax expense		-		(1)
Deferred income tax recovery		-		69,770
Net loss from discontinued operations for the year	$	-	$	(122,723)
Per unit
- basic and diluted	$	-	$	(0.46)

⁽¹⁾	For the year ended December 31, 2010 interest expense of $2.5 million was allocated to discontinued operations on a prorata basis calculated as the proportion of net assets of the Upstream business to the sum of total net assets of the Trust plus long-term debt.

The carrying amounts of major classes of assets and liabilities included
as part of the Upstream business as at the date of the sale were as
follows:

Canadian dollars (000s)

Property, plant and equipment	$	568,880
Decommissioning liabilities		(65,184)
Other		(8,340)
	$	495,356

Assets held for sale

IFRS requires that assets held for sale be presented separately on the
statement of financial position. Previous Canadian GAAP made an
exception to this rule for certain upstream oil and gas related
transactions. The sale of West Central Alberta assets held in the
Upstream business was announced in December 2009. Therefore, assets and
associated decommissioning liabilities of $186.4 million and $2.8
million, respectively, related to this transaction have been presented
separately on the January 1, 2010 statement of financial position, at
their fair value, determined with reference to the negotiated sales
price adjusted for earnings between December 31, 2009 and the date of
closing on March 1, 2010. This transaction resulted in a loss on sale
of $8.1 million in the first quarter of 2010.

Additional accounting policies

Accounting policies solely related to Provident's Upstream business are
as follows:

i)	Financial instruments
	Financial Assets
	a)	Available for sale
		The Company's investments are classified as available for sale financial assets. A gain or loss on an available for sale financial asset shall be recognized directly in other comprehensive income, except for impairment losses and foreign exchange gains and losses. When the investment is derecognized or determined to be impaired, the cumulative gain or loss previously recorded in equity is recognized in profit or loss.

ii)	Property, plant & equipment
	Oil and natural gas properties
	Oil and natural gas properties are stated at cost, less accumulated depletion and depreciation and accumulated impairment losses. Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas properties only when they increase the future economic benefits embodied in the specific properties to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas properties represent costs incurred in developing proved and probable reserves and bringing in or enhancing production from such reserves and are accumulated on a cost centre basis.
	Development costs
	Expenditures on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, are capitalized within property, plant and equipment.
	Depletion
	The provision for depletion and depreciation for oil and natural gas assets is calculated, at a component level using the unit-of-production method based on current period production divided by the related share of estimated total proved and probable 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 Company includes estimated future costs for developing proved and probable reserves, and excludes estimated salvage values of tangible equipment and the cost of exploration and evaluation assets.
iii)	Exploration and Evaluation assets
	Pre-license costs
	General prospecting and evaluation costs incurred prior to having obtained the legal rights to explore an area are expensed directly to the statement of operations in the period in which they are incurred.
	Exploration and evaluation costs
	Once the legal right to explore has been acquired, all costs incurred to assess the technical feasibility and commercial viability of resources are capitalized as exploration and evaluation ("E&E") intangible assets until the drilling of the well is complete and the results have been evaluated. These costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable overhead and administration expenses, including remuneration of production personnel and supervisory management, the projected costs of retiring the assets (if any), and any activities in relation to evaluating the technical feasibility and commercial viability of extracting mineral resources. Such items are initially measured at cost. After initial recognition, the Company measures E&E costs using the cost model whereby the asset is carried at cost less accumulated impairment losses.
	Intangible exploration assets are not depleted and carried forward until the Company has determined the technical feasibility and commercial viability of extracting a mineral resource. If no reserves are found and management determines that the Company no longer intends to develop or otherwise extract value from the discovery, the costs are written off to profit or loss. Upon determination of proven and probable reserves, E&E assets attributable to those reserves are first tested for impairment at the cash generating unit level, and then reclassified to oil and natural gas properties, a separate category within property, plant and equipment. Once these costs have been transferred to property, plant and equipment, they are subject to impairment testing at the cash generating unit level similar to other oil and natural gas assets within property, plant and equipment.
iv)	Joint arrangements
	Certain of the Company's activities in the Upstream business were conducted through interests in jointly controlled assets and operations, where the Company has a direct ownership interest in and jointly control the assets and/or operations of the venture. Accordingly, the income, expenses, assets, and liabilities of these jointly controlled assets and operations are included in the consolidated financial statements of the Company in proportion to the Company's interest.
v)	Decommissioning liabilities
	For upstream operations, the amount recognized represents management's estimate of the present value of the estimated future expenditures to abandon and reclaim the Company's net ownership in wells and facilities determined in accordance with local conditions and requirements as well as an estimate of the future timing of the costs to be incurred.
	Decommissioning is likely to occur when the fields are no longer economically viable. This in turn depends on future oil and gas prices, which are inherently uncertain.
vi)	Significant accounting judgments, estimates and assumptions
	Reserves base
	The Company's reserves have been evaluated in accordance with the Canadian Oil and Gas Evaluation Handbook Volumes 1 and 2 ("COGEH") and comply with the standards that govern all aspects of reserves as prescribed in National Instrument 51-101 (NI 51-101). Under NI 51-101, proved reserves are defined as having a high degree of certainty to be recoverable. Probable reserves are defined as those reserves that are less certain to be recovered than proved reserves. The targeted levels of certainty, in aggregate, are at least 90 percent probability that the quantities recovered will equal or exceed the estimated proved reserves and at least 50 percent probability that the quantities recovered will equal or exceed the sum of the estimated proved plus probable reserves. Under NI 51-101 standards, proved plus probable are considered a "best estimate" of future recoverable reserves.
	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 Company 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. Future development costs are estimated using assumptions as to number of wells required to produce the reserves, the cost of such wells and associated production facilities, and other capital costs.
	Carrying value of oil and gas assets
	Oil and gas development and production properties are depreciated on a unit-of-production basis at a rate calculated by reference to proved plus probable reserves and incorporate the estimated future costs of developing and extracting those reserves.
	The calculation of unit-of production rate of amortization could be impacted to the extent that actual production in the future is different from current forecast production based on proved plus probable reserves. This would generally result from significant changes in any of the factors or assumptions used in estimating reserves and could include:

Changes in proved plus probable reserves;

The effect on proved plus probable reserves of differences between
actual commodity prices and commodity price assumptions; or

Unforeseen operational issues.

			Impairment indicators
			The recoverable amounts of cash generating units and individual assets have been determined based on the higher of value in use calculations and fair values less costs to sell. These calculations require the use of estimates and assumptions.
			For the Upstream business, it is reasonably possible that the commodity price assumptions may change which may then impact the estimated life of the field and may then require a material adjustment to the carrying value of its tangible and intangible assets. The Company monitors internal and external indicators of impairment relating to its tangible and intangible assets.
			Impairment of available for sale financial assets
			The Company classifies certain assets as available for sale and recognizes movements in their fair value in equity. Subsequent to initial recognition, when the fair value declines, management makes assumptions about the decline in value whether it is an impairment that should be recognized in profit or loss.

24.Subsequent event

Arrangement agreement with Pembina Pipeline Corporation

For further information:

Investor and Media Contact:
Raina Vitanov
Manager, Investor Relations
Ashley Nuell
Investor Relations & Communications Analyst
Phone (403) 231-6710
Email:info@providentenergy.com

Corporate Head Office:
2100, 250 - 2^nd Street SW
Calgary, Alberta T2P 0C1
Phone: (403) 296-2233
Toll Free: 1-800-587-6299
Fax: (403) 264-5820
www.providentenergy.com

Douglas J. Haughey

Chief Executive Officer

Brent C. Heagy

Chief Financial Officer

Calgary, Alberta

March 6, 2012