Provident Announces Record 2011 Third Quarter Results, Updated 2011 Adjusted EBITDA Guidance and the November Cash Dividend
All values are in Canadian dollars.
CALGARY, Nov. 9, 2011 /PRNewswire/ – Provident Energy Ltd. (Provident)
(TSX-PVE; NYSE-PVX) today announced its 2011 third quarter interim
financial and operating results, updated 2011 adjusted EBITDA guidance
and the November cash dividend.
“Very strong NGL pricing and demand has resulted in record third quarter
and nine month year-to-date EBITDA” said President and Chief Executive
Officer, Doug Haughey. “Our outlook for the NGL industry remains
positive and we continue to be encouraged by our growing portfolio of
fee-for-service based growth opportunities around our Redwater West and
Empress East facilities.”
Third Quarter Summary
Third quarter financial statements are reported under International
Financial Reporting Standards.
-- Gross operating margin grew by 38 percent to $86 million in the
third quarter of 2011, up from $62 million in 2010, driven by
stronger NGL product pricing, higher frac spreads and increased
Empress East sales volumes.
-- Adjusted EBITDA(1)was $70 million for the third quarter of
2011, an increase of 32 percent from $53 million in 2010. The
increase reflects higher operating margins from both Redwater
West and Empress East, which increased contributions by 52
percent and 64 percent, respectively, partially offset by
higher realized losses on financial derivative instruments.
-- Adjusted funds flow from continuing operations(2) increased 44
percent to $63 million ($0.23 per share) in the third quarter
of 2011, compared to $44 million ($0.16 per unit) in 2010,
largely due to the 38 percent increase in gross operating
margin.
-- Dividends paid to shareholders totaled $0.14 per share
resulting in a payout ratio of 61 percent of adjusted funds
flow from continuing operations, net of sustaining capital, for
the third quarter of 2011.
-- Total debt at September 30, 2011 was $521 million. Provident
continues to maintain its financial flexibility with
approximately $289 million of capacity remaining under its $500
million revolving term credit facility. Subsequent to the
quarter, Provident completed an extension of its revolving term
credit facility extending the term from June 28, 2013 to
October 14, 2014.
-- Total debt to Adjusted EBITDA(1) for the twelve months ended
September 30, 2011 was a ratio of 1.9 to one compared to 2.1 to
one for the year ended December 31, 2010.
-- Capital expenditures were $28 million during the third quarter
of 2011 and $75 million year-to-date. Capital expenditures were
primarily directed towards cavern development and terminalling
infrastructure at the Corunna facility, cavern and brine pond
development at the Redwater facility, as well as Provident's
pipeline replacement/expansion projects in northeast British
Columbia.
_________________________________________
(1) Adjusted EBITDA is earnings before interest, taxes,
depreciation, amortization, and other non-cash items - see
"Reconciliation of Non-GAAP measures" in the 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.
2011 Adjusted EBITDA Guidance
Given strong year-to-date performance and Provident’s positive outlook
for the balance of 2011, it is anticipated that Provident’s 2011
Adjusted EBITDA will be in the upper portion of its guidance range of
$245 million to $285 million. This guidance is subject to market and
operational assumptions including normal weather conditions and is
based, in part, on average price assumptions for October through
December 2011 of U.S. WTI crude of $91.00/bbl, AECO natural gas of
$3.40/GJ, a Cdn/U.S. dollar exchange rate of $1.00 and a Mont Belvieu
propane price at 69 percent of crude oil. This guidance also assumes
that extraction premiums at Empress for the remainder of 2011 will be
near the high end of an updated range of between $6 and $9 per
gigajoule.
November 2011 Cash Dividend
The November cash dividend of $0.045 per share is payable on December
15, 2011 and will be paid to shareholders of record on November 23,
2011. The ex-dividend date will be November 21, 2011. Provident’s 2011
annualized dividend rate is $0.54 per common share. Based on the
current annualized dividend rate and the TSX closing price on November
8, 2011 of $9.31 Provident’s yield is approximately 5.8 percent.
For shareholders receiving their dividends in U.S. funds, the November
2011 cash dividend will be approximately US$0.044 per share based on an
exchange rate of 0.9862. 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 Third Quarter Conference Call
A conference call has been scheduled for Thursday, November 10, 2011 at
7:30 a.m. MDT (9:30 a.m. Eastern) to discuss Provident’s 2011 third
quarter results. 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
November 17, 2011 by dialing 403-451-9481 or 855-859-2056 and entering
passcode 20775448. 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, as well as other expectations, plans, goals, objectives,
information or statements about future events, conditions, results of
operations or performance that may constitute “forward-looking
statements” or “forward-looking information” under applicable
securities legislation. Such statements or information involve
substantial known and unknown risks and uncertainties, certain of which
are beyond Provident’s control, including the impact of general
economic conditions in Canada and the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified personnel or management, pipeline design and
construction, fluctuations in commodity prices, foreign exchange or
interest rates, stock market volatility and obtaining required
approvals of regulatory authorities. Such forward-looking 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, and project development activities. )
(Although Provident believes that the expectations reflected in such
forward-looking statements or information are reasonable, undue
reliance should not be placed on forward-looking statements because
Provident can give no assurance that such expectations will prove to be
correct. Forward-looking statements or information are based on current
expectations, estimates and projections that involve a number of risks
and uncertainties which could cause actual results to differ materially
from those anticipated by Provident and described in the
forward-looking statements or information.)
(The forward-looking statements or information contained in this news
release are made as of the date hereof and Provident undertakes no
obligation to update publicly or revise any forward-looking statements
or information, whether as a result of new information, future events
or otherwise unless so required by applicable securities laws. The
forward-looking statements or information contained in this news
release are expressly qualified by this cautionary statement.)
Consolidated financial and operational highlights
($ 000s except per
share data) Three monthsendedSeptember30, NinemonthsendedSeptember 30,
% %
2011 2010 Change 2011 2010 Change
Product sales and $
service revenue $ 450,849 363,767 24 $ 1,386,331 $ 1,202,832 15
Funds flow from
continuing $
operations(1) $ 62,790 43,642 44 $ 159,865 $ (80,853) -
Funds flow from
discontinued $
operations (1) $ - - - $ - $ (2,436) (100)
Funds flow from $
operations (1) $ 62,790 43,642 44 $ 159,865 $ (83,289) -
Adjusted EBITDA -
continuing $
operations (2) $ 69,528 52,538 32 $ 182,068 $ (72,423) -
Adjusted funds flow
from continuing $
operations(3) $ 62,790 43,642 44 $ 159,865 $ 130,119 23
Per weighted
average share -
basic and diluted
(4) $ 0.23 $ 0.16 44 $ 0.59 $ 0.49 20
Percent of adjusted
funds flow from
continuing
operations, net
of
sustainingcapital
spending,
paid out as
declared
dividends 61% 112% (46) 73% 113% (35)
Adjusted EBITDA
excluding buyout of
financial
derivative
instruments and
strategic review
and
restructuring
costs -
continuing
operations(2) $ 69,528 $ 52,538 32 $ 182,068 $ 138,549 31
Dividends to $
shareholders $ 36,609 47,990 (24) $ 109,382 $ 143,418 (24)
Per share $ 0.14 $ 0.18 (22) $ 0.41 $ 0.54 (24)
Non-cash
distribution in
connection with the
disposition of
the Upstream
business unit $ - $ - $ - $ 308,690
Per share $ - $ - $ - $ 1.16
Net income from
continuing $
operations $ 48,398 13,979 246 $ 76,632 $ 48,595 58
Per weighted
average share -
basic and diluted
(4) $ 0.18 $ 0.05 260 $ 0.28 $ 0.18 56
Net income (loss) $ 48,398 $ 8,979 439 $ 76,632 $ (82,886) -
Per weighted
average share -
basic and diluted
(4) $ 0.18 $ 0.03 500 $ 0.28 $ (0.31) -
Capital
expenditures from
continuing
operations:
- Growth $ 25,761 $ 10,063 156 $ 63,951 $ 18,283 250
- Sustaining $ 2,310 $ 902 156 $ 11,037 $ 3,096 256
Acquisitions -
continuing $
operations $ - 9 $ - $ 22,456
Weighted average
shares outstanding
(000s)
- basic and
diluted (4) 270,981 266,419 2 269,920 265,437 2
Provident Midstream
NGL sales volumes
(bpd) 94,709 95,388 (1) 101,067 100,833 -
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Consolidated
Asat As at
September 30, December 31,
($ 000s) 2011 2010 % Change
Capitalization
Long-term
debt
(including
current
portion) $ 521,227 $ 473,754 10
Shareholders' $ 581,414 $ 588,207 (1)
equity
(1) Represents cash flow from operations before changes in working
capital and site restoration expenditures.
(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 three and nine months ended September 30,
2011 compared to the same periods in 2010 and should be read in
conjunction with the accompanying interim consolidated financial
statements of Provident. This analysis has been prepared using
information available up to November 9, 2011.
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 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 and comparative
figures have been reclassified to conform with this presentation (see
note 18 of the interim 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 (DRIP) purchase 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 first, second and
third quarter 2011 interim 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”.
Significant events in 2010
The second quarter of 2010 included two significant events that impacted
the comparative results related to the second quarter and year-to-date
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 midstream business. This
transaction completed the sales process of the Upstream business and
the Upstream business unit is now 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 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 has retained certain
participating crude oil and natural gas swaps and NGL throughput and
inventory contracts that utilize financial derivative instruments based
directly on underlying NGL products.
“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”.
Recent developments
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 acquisition was funded by
approximately $8 million in cash and 945,000 Provident shares as well
as $4 million of assumed bank debt and working capital. Provident will
retain the option to purchase the remaining one-third interest in Three
Star after three years from the closing date.
Construction of a truck terminal at Cromer
On September 8, 2011, Provident announced the construction of a truck
unloading terminal located at Cromer, Manitoba. The terminal, plus
associated storage, will have an initial capacity of approximately
2,000 barrels per day of natural gas liquids production from the Bakken
area. The natural gas liquids from this terminal will be injected into
the Enbridge mainline for transport to Sarnia, Ontario. Provident
anticipates the project will cost approximately $10 million to complete
and will begin receiving volumes in the first quarter of 2012.
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 two underground storage caverns along with
associated pipeline and drying facilities at Provident’s Corunna
Facility located near Sarnia, Ontario. The total amount of storage
contracted under this agreement is 525,000 barrels with storage
services anticipated to commence in the first quarter 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 two underground storage caverns totaling
approximately one million barrels of storage capacity on a
fee-for-service basis. As part of the arrangement, Provident will
convert one of its existing product caverns and will re-configure one
of the five caverns currently under development at Redwater to
accommodate the storage of crude oil products. The caverns are
expected to be placed into crude oil service in the second quarter of
2012 and 2013, respectively.
Revolving term credit facility
Provident renegotiated an extension of its existing credit agreement
(the “Credit Facility”) as of 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
$75 million. The amended terms of the Credit Facility provide for a
revolving three year period expiring on October 14, 2014, from the
previous maturity date of June 28, 2013 (subject to customary extension
provisions).
Reconciliation of non-GAAP measures
Provident calculates earnings before interest, taxes, depreciation,
amortization, and other non-cash items (adjusted EBITDA) and adjusted
EBITDA excluding buyout of financial derivative instruments and
strategic review and restructuring costs within its MD&A disclosure.
These are non-GAAP measures. A reconciliation between these measures
and income from continuing operations before taxes follows:
Continuing
operations Three monthsendedSeptember30, Nine monthsended September 30,
% %
($ 000s) 2011 2010 Change 2011 2010 Change
Income before $
taxes $ 61,020 $ 9,077 572 $ 134,487 18,805 615
Adjusted for:
Financing
charges 8,559 8,777 (2) 31,918 21,742 47
Unrealized gain
offsetting
buyout of
financial
derivative
instruments - - - - (177,723) (100)
Unrealized
(gain) loss on
financial
derivative
instruments (16,677) 26,641 - (24,291) 40,235 -
Depreciation
and
amortization 10,475 11,380 (8) 31,714 32,831 (3)
Unrealized
foreign
exchange gain
and other (1,109) (4,477) (75) (834) (5,026) (83)
Loss on
revaluation of
conversion
feature of
convertible
debentures 4,097 - - 5,300 - -
Non-cash share
based
compensation
expense
(recovery) 3,163 1,140 177 3,774 (3,287) -
Adjusted EBITDA 69,528 52,538 32 182,068 (72,423) -
Adjusted for:
Realized loss
on buyout of
financial
derivative
instruments - - - - 199,059 (100)
Strategic
review and
restructuring
costs - - - - 11,913 (100)
Adjusted EBITDA
excluding
buyout of
financial
derivative
instruments
and strategic
review and
restructuring $
costs $ 69,528 $ 52,538 32 $ 182,068 138,549 31
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 Three monthsended September30, NinemonthsendedSeptember 30,
% %
($ 000s) 2011 2010 Change 2011 2010 Change
Cash provided
by (used in) -
operating
activities $ 11,583 $ (14,226) - $ 114,525 $ (166,700)
Change in
non-cash
operating (44)
working
capital 51,207 57,868 (12) 45,340 81,370
Site
restoration
expenditures -
discontinued
operations - - - - 2,041 (100)
Funds flow
from -
operations 62,790 43,642 44 159,865 (83,289)
Funds flow
from (100)
discontinued
operations - - - - 2,436
Realized loss
on buyout of
financial
derivative
instruments - - - - 199,059 (100)
Strategic
review and (100)
restructuring
costs - - - - 11,913
Adjusted funds
flow from 23
continuing
operations $ 62,790 $ 43,642 44 $ 159,865 $ 130,119
Â
Funds flow from continuing operations and dividends
Three months ended Nine months ended
September30, September30,
($ 000s, % %
except per 2011 2010 Change 2011 2010 Change
share data)
Funds flow
from
continuing
operationsand
dividends
Funds flow
from $ 62,790 $ 43,642 44 $ $ (80,853) -
continuing 159,865
operations
Adjusted
funds flow
from $ 62,790 $ 43,642 44 $ 159,865 $ 130,119 23
continuing
operations(1)
Per
weighted
average $ 0.23 $ 0.16 44 $ 0.59 $ 0.49 20
share
- basic and
diluted (2)
Declared $ 36,609 $ 47,990 (24) $ $ 143,418 (24)
dividends 109,382
Per share $ 0.14 $ 0.18 (22) $ 0.41 $ 0.54 (24)
Percent of
adjusted
funds flow
from
continuing
operations,
net of 61% 112% (46) 73% 113% (35)
sustaining
capital
spending,
paid out as
declared
dividends
(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.
For the three and nine months ended September 30, 2011, adjusted funds
flow from continuing operations increased by 44 percent and 23 percent,
respectively, over the same periods in 2010. The increases are
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 the second quarter of
2010.
Declared dividends in the first nine months of 2011 totaled $109.4
million, 73 percent of adjusted funds flow from continuing operations,
net of sustaining capital spending. In the comparable period of 2010,
declared distributions were $143.4 million, 113 percent of adjusted
funds flow from continuing operations, net of sustaining capital
spending.
In addition to cash distributions, Provident also made a non-cash
distribution to unitholders in the second quarter of 2010 relating to
the disposition of Provident’s Upstream business. This distribution was
valued at $308.7 million or $1.16 per unit (see note 18 of the interim
consolidated financial statements).
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. See “Forward-looking information” in this MD&A for
additional information regarding assumptions and risks in respect of
Provident’s forward-looking information.
Provident anticipates that 2011 adjusted EBITDA will be in the upper
portion of its guidance range of $245 million to $285 million. This
guidance is subject to market and operational assumptions including
normal weather conditions and is based, in part, on average price
assumptions for October through December 2011 of U.S. WTI crude of
$91.00/bbl, AECO natural gas of $3.40/GJ, a Cdn/U.S. dollar exchange
rate of $1.00 and a Mont Belvieu propane price at 69 percent of crude
oil. This guidance also assumes that extraction premiums at Empress for
the remainder of 2011 will be near the high end of an updated range of
between $6 and $9 per gigajoule.
Provident continues to move forward with its expanded 2011 capital
program and has deployed approximately $75 million of capital
year-to-date, including $64 million on growth capital projects and $11
million of sustaining capital. During the third quarter, Provident
commenced construction of a newly announced NGL truck unloading
terminal at Cromer, Manitoba and commissioned its new 16 spot
multi-commodity rail loading and offloading terminal at the Provident
Corunna Storage and Terminalling Facility. Subsequent to the quarter,
on October 3, 2011, Provident also closed the acquisition of a
two-thirds interest in Three Star Trucking Ltd.
Execution of the remainder of Provident’s 2011 capital program is
currently proceeding as planned. In the fourth quarter of 2011,
construction of the Septimus to Younger Pipeline is expected to be
completed and Provident anticipates putting into service a new pipeline
to replace an aging section of the Taylor to Boundary Lake pipeline on
the Liquids Gathering System. Overall, it is anticipated that certain
2011 projects may be completed under budget. In addition, due to
scheduling considerations, a small percentage of planned 2011 capital
may be deferred to the first quarter of 2012. This capital deferral is
not expected to materially impact the start-up dates of any of
Provident’s capital projects.
In addition to advancing its capital program, over the past few weeks
Provident has announced long-term storage arrangements for its
underground storage facilities at Redwater and Corunna. These
arrangements will underpin a significant portion of the company’s 2012
capital program with stable long-term fee-based arrangements.
Over the next two years, Provident currently plans to deploy
approximately $280 million in growth capital, $135 million and $145
million in 2012 and 2013, respectively. Management further estimates a
future annual growth capital run rate of approximately $100 million to
$125 million beyond 2013. For Redwater West, Provident’s growth
opportunities are associated with the increased liquids-rich natural
gas drilling in the Montney, BC area and growing activity levels in the
Alberta oilsands, both of which have significantly increased the demand
for NGL infrastructure and logistics services. For Empress East,
increasing liquids-rich drilling in the Appalachian shale plays in the
United States as well as the Company’s expanding footprint as a crude
oil and NGL services provider in the Bakken area has provided Provident
with opportunities to take part in the increasing demand for
transportation and storage services. Sustaining capital expenditures
for 2012 and beyond are expected to average between $10 million and $15
million annually.
Provident’s 2012 capital program of approximately $135 million will be
allocated as follows:
1. Redwater West Storage Development
At Redwater, Provident will deploy approximately $95 million on
the continued development of underground storage caverns and
related cavern infrastructure. Provident currently has five
caverns in various stages of development which will come into
service over the next three years. Over the past several weeks,
Provident has entered into long-term underground storage
arrangements for approximately 2.0 million barrels of storage
capacity at Redwater. These long-term arrangements will underpin
Provident's cavern development program with stable fee-based cash
flows and serve to demonstrate the increasing demand for
underground hydrocarbon storage in the greater Fort Saskatchewan
area. In the future, one of these five development caverns may
become designated as a replacement cavern.
2. Redwater West Expansion & Optimization
Provident will spend approximately $6 million on initiatives
around its Younger fractionation facility and Liquids Gathering
System to optimize Younger plant operating capacity and further
enhance Redwater West supply. Over the past several months,
Provident has experienced a significant increase in gas supply to
Younger which has stemmed from the increased liquids-rich natural
gas drilling in the Montney area in BC. Completion of the Septimus
to Younger pipeline, which is scheduled for the fourth quarter of
2011, will further augment gas supply into the Younger facility.
A further $18 million of capital has been allocated for the
initial phase of a planned expansion and optimization of the
Redwater facility. The first phase of the expansion is expected
to increase fractionation capacity at Redwater by approximately
8,000 barrels per day, and will allow Provident to process
additional NGLs expected from the Younger facility and from
Provident's NGL capture areas around its Liquids Gathering System,
as well as additional NGLs that may be received via the Pembina
Pipeline System. Additional details around subsequent expansion
phases, including fractionation capacity and capital costs, are
expected to be released in 2012.
3. Corunna Facility Enhancements
For 2012, Provident has allocated approximately $10 million of
capital for projects associated with its storage and terminalling
facilities at Corunna, Ontario. In the first quarter of 2012,
Provident will begin providing additional storage and terminalling
services under a long-term agreement with a major industrial
customer in the Sarnia area. Additional capital will be spent to
increase storage capacity and enhance service capabilities at
Corunna in order to meet new demand arising from increasing levels
of liquids-rich natural gas drilling in the Appalachian shale
plays in the United States and strong petrochemical and refining
activity in the Sarnia area.
4. Bakken Development
The remaining $6 million of capital will be directed towards
expanding Provident's crude oil and NGL footprint in the Bakken
area. In the first quarter of 2012, Provident will complete the
construction of its truck unloading terminal facility at Cromer,
Manitoba and will begin receiving NGL mix supply which will be
injected into the Enbridge mainline for transportation to Sarnia,
Ontario. Through its subsidiary, Three Star Trucking Ltd.,
Provident is also planning to purchase additional trucking units
to expand its crude oil hauling operations and diversify into NGL
and diluents trucking and other service offerings.
The very strong NGL industry fundamentals which have contributed to
robust NGL pricing and demand over the past few months are expected to
continue throughout the remainder of 2011. However, it is expected that
2012 will trend towards more normal market conditions. Provident
continues to be encouraged by the business development opportunities
that have emerged around all of its facilities in response to
accelerating growth in the Montney and Appalachian natural gas plays,
the Bakken oil play, and the Alberta oilsands.
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.Â
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.
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.
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 margins are
summarized in the following table:
Midstream
business Threemonths ended September Nine months ended September
reference 30, 30,
prices
2011 2010 % Change 2011 2010 % Change
WTI crude oil
(US$ per $ 89.76 $ 76.20 18 $ 95.48 $ 77.65 23
barrel)
Exchange rate
(from US$ to 0.98 1.04 (6) 0.98 1.04 (6)
Cdn$)
WTI crude oil
expressed in $ 87.99 $ 79.18 11 $ 93.37 $ 80.43 16
Cdn$ per
barrel
AECO natural
gas monthly $ 3.53 $ 3.52 - $ 3.55 $ 4.11 (14)
index (Cdn$
per gj)
Frac Spread 24.9 22.5 11 26.3 19.6 34
Ratio (1)
Mont Belvieu
Propane (US$ $ 1.54 $ 1.07 44 $ 1.48 $ 1.13 31
per US
gallon)
Mont Belvieu
Propane
expressed as 72% 59% 22 65% 61% 7
a percentage
of WTI
Market Frac
Spread in $ 56.09 $ 37.78 48 $ 53.42 $ 38.31 39
Cdn$ per
barrel(2)
(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 third quarter of 2011 was
significantly stronger than in the third quarter of 2010. The average
third quarter 2011 WTI crude oil price was US$89.76 per barrel,
representing an increase of 18 percent compared to the third quarter of
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 the third quarter of 2011 compared to the third quarter of 2010.
Propane prices were also stronger than in the comparative period,
reflecting the increase in crude oil prices combined with lower North
American supply resulting from above average exports and stronger
demand from the petrochemical sector. The Mont Belvieu propane price
averaged US$1.54 per U.S. gallon (72 percent of WTI) in the third
quarter of 2011, compared to US$1.07 per U.S. gallon (59 percent of
WTI) in the third quarter of 2010. Butane and condensate sales prices
were also much improved in the third quarter of 2011, also reflective
of higher crude oil prices and steady petrochemical and oilsands demand
for these products.
The third quarter 2011 AECO natural gas price averaged $3.53 per gj
which is consistent with $3.52 per gj during the third quarter of
2010. 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. 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. Recent strength in NGL
pricing 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.
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 $56.09 per barrel during the third quarter
of 2011, representing a 48 percent increase from $37.78 per barrel
during the third quarter of 2010. Higher frac spreads were a result of
higher NGL prices combined with a flat AECO natural gas price. While
Provident benefits directly from higher frac spreads at its Younger
facility, the benefit of higher market frac spreads in the third
quarter of 2011 was offset at Empress by continued high costs for
natural gas supply in the form of extraction premiums. Empress
extraction premiums increased approximately 50 percent when compared to
the third quarter of 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 the third quarter of 2011 compared
to the same quarter of 2010 at a rate of approximately 4.6 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.Â
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
57.5 million barrels as at the end of the third quarter of 2011,
representing a decrease of approximately 3.9 million barrels compared
to the prior year quarter, and are approximately 8.0 million barrels
below the five year historical average. Inventory levels are below the
five year historical average primarily due to the continued strong
demand from the petrochemical sector and above average propane exports
from the U.S. Gulf Coast primarily to Central and South American
markets. Canadian industry propane inventories were approximately 9.3
million barrels at the end of the third quarter of 2011, 0.6 million
barrels lower than the end of the third quarter of 2010 and 0.9 million
barrels lower than the historic five year average. Propane inventories
have decreased compared to the prior year quarter primarily due to
strong third quarter demand for propane in 2011.
Provident Midstream business performance
Provident Midstream results can be summarized as follows:
Three months ended Nine months ended
September30, September30,
(bpd) % %
2011 2010 Change 2011 2010 Change
Redwater West
NGL sales
volumes 52,675 58,834 (10) 56,308 59,749 (6)
Empress East
NGL sales
volumes 42,034 36,554 15 44,759 41,084 9
Provident
Midstream NGL
sales volumes 94,709 95,388 (1) 101,067 100,833 -
Three months ended Nine months ended
September30, September30,
($ 000s) % %
2011 2010 Change 2011 2010 Change
Redwater West $ $ $ $
margin 49,982 32,902 52 144,615 99,347 46
Empress East
margin 22,179 13,516 64 72,157 52,910 36
Commercial
Services
margin 13,549 15,570 (13) 43,057 47,375 (9)
Gross
operating
margin 85,710 61,988 38 259,829 199,632 30
Realized loss
on financial
derivative
instruments (12,071) (4,556) 165 (55,115) (34,459) 60
Cash general
and
administrative
expenses (7,317) (7,944) (8) (29,346) (28,107) 4
Other income
and realized
foreign
exchange 3,206 3,050 5 6,700 1,483 352
Adjusted
EBITDA
excluding
buyout of
financial
derivative
instruments
and strategic
review
and
restructuring
costs 69,528 52,538 32 182,068 138,549 31
Realized loss
on buyout of
financial
derivative
instruments - - - - (199,059) (100)
Strategic
review and
restructuring
costs - - - - (11,913) (100)
Adjusted $ $ $ $
EBITDA 69,528 52,538 32 182,068 (72,423) -
Gross operating margin
Midstream gross operating margin during the third quarter of 2011
totaled $85.7 million, an increase of 38 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 52 percent and 64 percent, respectively, partially offset by a
13 percent decrease in operating margin from Commercial Services.
The year-to-date margin was $259.8 million in 2011 which is 30 percent
higher than the year-to-date margin of $199.6 million in 2010.
Year-to-date margin reflects increased contributions from both Redwater
West and Empress East by 46 percent and 36 percent, respectively,
partially offset by a nine 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 third quarter 2011 operating margin for Redwater West was $50.0
million, an increase of 52 percent compared to $32.9 million in the
third quarter of 2010. Strong third quarter 2011 results 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 52,675 barrels per day in the third quarter of 2011, a
10 percent decrease compared to the third quarter of 2010. Lower NGL
sales volumes can be largely attributed to a decrease in sales volumes
for ethane and condensate in the third quarter of 2011 compared to the
third quarter of 2010. Third quarter 2011 ethane sales were curtailed
as the Younger plant underwent a regularly scheduled maintenance
turnaround project over the end of the second and beginning of the
third quarter of 2011 whereby the plant was either idle or operating at
significantly less than capacity for a period of approximately two
weeks during the third quarter. 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 margin in the quarter despite the
decrease in sales volumes.
Product operating margins for propane, butane and condensate were higher
in the third quarter of 2011 relative to the comparative period
primarily due to more favourable market pricing. Mt. Belvieu pricing
for propane, butane and condensate have increased by 44 percent,
41percent and 40 percent, respectively, in the third quarter of 2011
compared to the third quarter of 2010.
Year-to-date operating margin increased to $144.6 million in 2011 from
$99.3 million in 2010, an increase of 46 percent. The year-to-date
increase is primarily due to a stronger NGL pricing environment in 2011
when compared to 2010. Mt. Belvieu pricing for propane, butane and
condensate has increased 31 percent, 27 percent and 36 percent,
respectively, year-to-date 2011 compared to year-to-date 2010. Higher
operating margins were partially offset by a six percent reduction in
Redwater West sales volumes which are primarily associated with
reductions in condensate railcar imports from the U.S. Gulf Coast for
sale in the western Canadian market.
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 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 was $22.2 million in the third
quarter of 2011 compared to $13.5 million in the same quarter of 2010.Â
The 64 percent increase was due to increased sales volumes associated
with strong demand for propane in the third quarter of 2011 when
compared to the same quarter of 2010 as well as strong refinery demand
for butane in the third quarter of 2011. Overall, Empress East NGL
sales volumes averaged 42,034 barrels per day, a 15 percent increase
compared to the third quarter of 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.
Year-to-date gross operating margin of $72.2 million in 2011 represents
a 36 percent increase compared to a year-to-date margin of $52.9
million in 2010. The increase in year-to-date margin was primarily
attributable to a 21 percent increase in propane-plus sales volumes
combined with a 17 percent increase in propane-plus per unit revenues.Â
Higher volume sales and per unit revenues on propane-plus products were
driven by increases in market pricing for all propane-plus NGL products
and were partially offset by increased extraction premiums paid to
purchase natural gas in the Empress market. Sales volumes are higher
than in the prior year as a result of higher demand for propane and
butane in central Canada and the eastern United States in the third
quarter of 2011 compared to the prior year quarter.
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 for four underground storage caverns, two
at the Redwater facility and two at the Provident Corunna facility.Â
Subsequent to the end of the quarter, Provident announced a long-term
storage agreement for crude oil storage at the Redwater facility
utilizing two additional underground storage caverns.
Commercial Services operating margin in the third quarter of 2011 was
$13.5 million, representing a decrease of 13 percent compared to the
same period in 2010. Year-to-date 2011, the Commercial Services margin
was $43.1 million, a decrease of nine percent compared to $47.4 million
in 2010. The decrease in margin was primarily associated with
decreased condensate terminalling revenues as a result of the
completion in mid-2010 of the Enbridge Southern Lights pipeline, which
transports condensate from the United States to the Edmonton area.
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 the second quarter of 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.
Third quarter 2011 adjusted EBITDA excluding buyout of financial
derivative instruments and strategic review and restructuring costs
increased to $69.5 million from $52.5 million in the third quarter of
2010. Year-to-date adjusted EBITDA excluding buyout of financial
derivative instruments and strategic review and restructuring costs
increased to $182.1 million from $138.5 million in 2010. The increases
reflect higher gross operating margins from both Redwater West and
Empress East, partially offset by higher realized losses on financial
derivative instruments under the commodity price risk management
program. In addition, the third quarter of 2011 includes other income
of $2.1 million ($6.4 million year-to-date) related to payments
received from third parties relating to certain contractual volume
commitments at the Empress facilities.
Capital expenditures
Capital expenditures for the third quarter of 2011 totaled $28.1 million
and $75.0 million year-to-date. During 2011, $64.0 million of capital
spending was primarily directed towards cavern development and
terminalling infrastructure at the Provident Corunna facility near
Sarnia, Ontario, cavern and brine pond development at the Redwater
fractionation facility in Redwater, Alberta as well as various pipeline
improvements and developments. An additional $11.0 million was
directed to sustaining capital activities and office related capital
including $6.6 million associated with the replacement of the Taylor to
Boundary Lake Pipeline.
Midstream capital expenditures for the third quarter of 2010 totaled
$11.0 million and $21.4 million year-to-date. During 2010, $18.3
million was spent on growth projects including the construction of a
truck rack at the Provident Empress plant, continued development of
cavern storage at Redwater, and development activities relating to the
Provident Corunna facility. In addition, $3.1 million was spent on
sustaining capital requirements and office related capital.
Net income (loss)
Three months ended Nine months ended
Consolidated September30, September30,
($ 000s,
except per %
share data) 2011 2010 Change 2011 2010 % Change
Net income
from
continuing
operations $ 48,398 $ 13,979 246 $ 76,632 $ 48,595 58
Net loss
from
discontinued
operations - (5,000) (100) - (131,481) (100)
Net income
(loss) $ 48,398 $ 8,979 439 $ 76,632 $ (82,886) -
Per weighted
average
share
- basic and
diluted (1) $ 0.18 $ 0.03 500 $ 0.28 $ (0.31) -
(1) Based on weighted average number of shares outstanding and
includes dilutive impact of convertible debentures.
In the third quarter of 2011, Provident recorded net income of $48.4
million compared to net income of $9.0 million in the comparable 2010
quarter. Net income in the third quarter of 2010 was impacted by a net
loss from discontinued operations of $5.0 million related to
post-closing adjustments attributed to the sale of the Upstream
business in the second quarter of 2010.
Net income from continuing operations for the third quarter of 2011 was
$48.4 million, compared to $14.0 million in the third quarter of 2010.
Higher adjusted EBITDA combined with the positive impact of the change
in unrealized gain on financial derivative instruments was partially
offset by higher deferred income tax expense.
The year-to-date net income from continuing operations was $76.6 million
in 2011, compared to $48.6 million in 2010. Higher adjusted EBITDA,
combined with the impact of the two identified significant events in
2010 and the change in unrealized gain on financial derivative
instruments, was partially offset by higher financing and income tax
expenses. Net loss from discontinued operations was $131.5 million and
is attributed to the sale of the Upstream business in the second
quarter of 2010.
Taxes
Continuing Three months ended Nine months ended September30,
operations September30,
($ 000s) 2011 2010 % Change 2011 2010 % Change
Current
tax $ 97 $ (1,015) - $ 208 $ (11,094) -
expense
(recovery)
Deferred
income tax 12,525 (3,887) - 57,647 (18,696) -
expense
(recovery)
$ 12,622 $ (4,902) - $ 57,855 $ (29,790) -
The current tax expense for the three and nine months ended September
30, 2011 was $0.1 million (2010 – $1.0 million recovery) and $ 0.2
million (2010 – $11.1 million recovery), respectively. The current tax
recovery in 2010 was attributed to lower earnings subject to tax in the
U.S. Midstream operations allowing the recovery of taxes paid in prior
periods. The lower earnings in 2010 were generated primarily by the
realized loss on buyout of financial derivative instruments.
For the nine months ended September 30, 2011, deferred income tax
expense was $57.6 million compared to a recovery of $18.7 million in
the same period of 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 has increased by $22.3 million when compared to
the previous Canadian GAAP amount (see note 5 of the interim
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 $24
million. The deferred tax recovery in 2010 was primarily driven by
losses created by deductions at the incorporated subsidiary level under
the previous Trust structure.
Financing charges
Continuing Three months ended Nine months ended September30,
operations September30,
($ 000s,
except as 2011 2010 % Change 2011 2010 % Change
noted)
Interest on $ 2,457 $ 2,661 (8) $ 6,808 $ 6,685 2
bank debt
Interest on
convertible 4,960 3,996 24 16,036 12,086 33
debentures
7,417 6,657 11 22,844 18,771 22
Less:
Capitalized (739) - - (739) - -
borrowing
costs
Less:
Discontinued - - - - (2,501) (100)
operations
portion
Total cash
financing $ 6,678 $ 6,657 - $ 22,105 $ 16,270 36
charges
Weighted
average
interest rate 5.0% 5.0% - 5.3% 4.6% 15
on all
long-term
debt
Loss on
purchase of - - - 3,342 - -
convertible
debentures
Accretion and
other
non-cash 1,881 2,120 (11) 6,471 6,966 (7)
financing
charges
Less:
Discontinued - - - - (1,494) (100)
operations
portion
Total
financing $ 8,559 $ 8,777 (2) $ 31,918 $ 21,742 47
charges
Financing charges for the third quarter of 2011 were similar to the
prior year, however, on a year-to-date basis financing charges have
increased relative to 2010. Interest on bank debt is lower in the
third quarter of 2011 as Provident had less debt drawn on its revolving
credit facility. On a year-to-date basis, interest on bank debt is
similar to 2010 with lower debt levels being offset by higher borrowing
rates. Interest on convertible debentures for the third quarter and
year-to-date was higher than in the prior year reflecting a higher face
value outstanding, partially offset by a reduced average coupon rate on
the convertible debentures. 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 during May 2011. In addition, the prior period
includes an allocation of interest expense and associated financing
charges to discontinued operations.
In the third quarter of 2011, Provident commenced capitalizing borrowing
costs attributable to the construction of assets that take a
substantial period of time to get ready for their intended use. This
reduced the Company’s total recognized financing charges in the third
quarter of 2011 by $0.7 million (2010 – nil).
Commodity price risk management program
Provident’s 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.
Management continues to actively monitor commodity price 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. Also, subject to market
conditions, Provident may add additional positions as appropriate for
up to 24 months. A summary of Provident’s current financial derivative
positions, including Frac volume, midstream margin, interest rate,
electricity, and foreign exchange contracts, is available on
Provident’s website at www.providentenergy.com/bus/riskmanagement/commodity.cfm.
A summary of Provident’s risk management contracts executed during the
third quarter of 2011 is contained in the following table.
Activity in the Third Quarter:
Volume
Year Product (Buy)/Sell Terms Effective Period
2011 Crude Oil 2,201 Bpd US $86.71 per bbl October 1 -
(2) (7) December 31
Natural Gas (8,000) Gjpd Cdn $3.50 per gj October 1 -
(3) (6) December 31
Propane 3,696 Bpd US $1.5512 per October 1 -
gallon (4) (6) December 31
Condensate (2,201) Bpd US $2.225 per October 1 -
gallon (5) (7) December 31
Sell US October 1 -
Foreign Exchange $26,222,040 per December 31
month @ 0.9862
(8)
2012 Crude Oil 2,217 Bpd US $86.71 per bbl January 1 -
(2) (7) September 30
Natural Gas (14,000) Gjpd Cdn $3.68 per gj January 1 - March
(3) (6) 31
Propane 6,099 Bpd US $1.5682 per January 1 - March
gallon(4) (6) 31
Condensate (2,217) Bpd US $2.225 per January 1 -
gallon (5) (7) September 30
Sell US January 1 - March
Foreign Exchange $24,641,529 per 31
month @ 0.9862
(8)
(1)The above table represents transactions entered into over the third
quarter of 2011.
(2)Crude Oil contracts are settled against NYMEX WTI calendar average.
(3)Natural Gas contracts are settled against AECO monthly index.
(4)Propane contracts are settled against Mont Belvieu C3 TET.
(5)Condensate contracts are settled against Belvieu NON-TET Natural
Gasoline.
(6)Midstream Frac Spread contracts.
(7)Midstream margin contracts executed to manage price exposure in
physical sales contracts.
(8) US Dollar forward contracts are settled against the Bank of Canada
noon rate average. Selling notional US dollars for Canadian dollars at
a fixed exchange rate results in a fixed Canadian dollar price for the
hedged commodity.
Settlement of commodity contracts
The following table summarizes the impact of financial derivative
contracts settled during the three and nine months ended September 30,
2011 and 2010. The table excludes the impact of the Midstream
derivative contract buyout of financial derivative instruments incurred
in the second quarter of 2010 which is presented separately on the
consolidated statement of operations.
Three months ended September 30, Nine months ended September 30,
Realized
loss on
financial
derivative
instruments 2011 2010 2011 2010
($ 000s Volume Volume Volume Volume
except (1) (1) (1) (1)
volumes)
Crude oil $ 1,625 0.8 $ (1,263) 0.5 $ (8,336) 1.7 $ (12,414) 1.7
Natural gas (2,243) 6.1 (3,149) 3.3 (7,935) 18.3 (25,128) 10.6
NGL's
(includes
propane,
butane) (13,086) 1.6 (336) - (41,841) 3.7 818 0.4
Foreign 874 459 1,472 2,631
exchange
Electricity 1,084 (154) 1,947 446
Interest (325) (113) (422) (812)
rate
Realized
loss on
financial
derivative
instruments $ (12,071) $ (4,556) $ (55,115) $ (34,459)
(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 on financial derivative instruments for the third
quarter of 2011 was $12.1 million compared to $4.6 million in the
comparable 2010 quarter. The majority of the realized loss in the
third quarter of 2011 was driven by NGL derivative sales contracts
settling at a contracted price lower than current NGL market prices.
The comparable third quarter 2010 realized loss was driven mostly by
natural gas derivative purchase contracts settling at a contracted
price higher than the market natural gas prices during the settlement
period.
Liquidity and capital resources
($ 000s) September 30,2011 December 31, 2010 % Change
Long-term debt -
revolving term credit $ 206,482 $ 72,882 183
facility
Long-term debt -
convertible debentures 314,745 400,872 (21)
(including current
portion)
Working capital surplus
(excluding financial (123,157) (79,633) 55
derivative instruments)
Net debt $ 398,070 $ 394,121 1
Shareholders' equity (at 581,414 588,207 (1)
book value)
Total capitalization at $ 979,484 $ 982,328 -
book value
Total net debt as a
percentage of total book 41% 40% 3
value capitalization
Midstream revenues are received at various times throughout the month.
Provident’s working capital position is affected by commodity price
changes as well as by seasonal fluctuations that reflect changing
inventory balances in the Midstream business. 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 (“DRIP”) purchase plan, external
lines of credit and access to equity 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.
Long-term debt and working capitalÂ
Provident renegotiated an extension of its existing credit agreement
(the “Credit Facility”) as of 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, from the previous maturity
date of June 28, 2013, (subject to customary extension provisions)
secured by all of the assets of the Company and its subsidiaries.
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 September 30, 2011, Provident had drawn $210.8 million (including
$1.8 million presented as a bank overdraft in accounts payable and
accrued liabilities) or 42 percent of its Credit Facility (December 31,
2010 – $75.5 million or 15 percent). Included in the carrying value at
September 30, 2011 were financing costs of $1.7 million (December 31,
2010 – $2.4 million). At September 30, 2011 the effective interest rate
of the outstanding Credit Facility was 3.5 percent (December 31, 2010 -
4.1 percent). At September 30, 2011 Provident had $57.3 million in
letters of credit outstanding (December 31, 2010 – $47.9 million) that
guarantee Provident’s performance under certain commercial and other
contracts.
The following table shows the change in Provident’s working capital
position.
As at As at
($ 000s) September 30, 2011 December 31, 2010 Change
Current Assets
Cash and cash $ - $ 4,400 $ (4,400)
equivalents
Accounts 183,296 206,631 (23,335)
receivable
Petroleum product 161,848 106,653 55,195
inventory
Prepaid expenses
and other current 5,110 2,539 2,571
assets
Financial
derivative 37,404 487 36,917
instruments
Current
Liabilities
Accounts payable
and accrued 218,100 227,944 9,844
liabilities
Cash distribution 8,997 12,646 3,649
payable
Current portion
of convertible - 148,981 148,981
debentures
Financial
derivative 63,717 37,849 (25,868)
instruments
Working capital $ 96,844 $ (106,710) $ 203,554
surplus (deficit)
The ratio of long-term debt to adjusted EBITDA from continuing
operations for the twelve months ended September 30, 2011 was 1.9 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. The conversion resulted in the
reorganization of the Trust into a publicly traded, dividend-paying
corporation under the name “Provident Energy Ltd.” Pursuant to the
conversion, unitholders exchanged all of their trust units for common
shares on a one-for-one basis (see notes 1 and 12 of the interim
consolidated financial statements).
Under Provident’s DRIP purchase plan 1.3 million shares were issued or
are to be issued in the third quarter of 2011 representing proceeds of
$10.3 million (2010 – 1.3 million trust units for proceeds of $8.5
million).
At September 30, 2011 management and directors held less than one
percent of the outstanding common shares.
Capital related expenditures and funding
Three months ended
September30, Nine months ended September30,
% %
($ 000s) 2011 2010 Change 2011 2010 Change
Capital
related
expenditures
Capital
expenditures $ (28,071) $ (10,965) 156 $ (74,988) $ (21,379) 251
Site
restoration
expenditures
-
discontinued
operations - - - - (2,041) (100)
Buyout of
financial
derivative
instruments - - - - (199,059) (100)
Acquisitions - (9) (100) - (22,456) (100)
Net capital
related
expenditures $ (28,071) $ (10,974) 156 $ (74,988) $ (244,935) (69)
Funded by
Funds flow
from
operations
net of
declared
dividends to
shareholders
and DRIP
proceeds $ 36,434 $ 4,181 771 $ 76,391 $ (5,507) -
Proceeds on
sale of
assets - 3,300 (100) - 3,300 (100)
Proceeds on
sale of
discontinued
operations - (5,000) (100) - 106,779 (100)
Cash
provided by
investing
activities
from
discontinued
operations - - - - 170,710 (100)
Issuance of
convertible
debentures,
net of issue
costs - - - 164,950 - -
Repayment of
debentures - - - (249,784) - -
Increase in
long-term
debt 35,080 60,020 (42) 132,869 38,511 245
Change in
working
capital,
including
cash (43,443) (51,527) (16) (49,438) (68,858) (28)
Net capital
related
expenditure
funding $ 28,071 $ 10,974 156 $ 74,988 $ 244,935 (69)
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 in West Central Alberta and the investment in Emerge
Oil and Gas Inc. 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 nine
months ended September 30, 2011, Provident recorded share based
compensation expense from continuing operations of $11.3 million (2010
– $3.6 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 the period of 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. At September 30, 2011, the current
portion of the liability totaled $13.9 million (December 31, 2010 -
$7.4 million) and the long-term portion totaled $7.8 million (December
31, 2010 – $10.4 million).
Discontinued operations (Provident Upstream)
On June 29, 2010, Provident completed a strategic transaction in which
Provident combined the remaining Provident Upstream business with
Midnight Oil Exploration Ltd. (“Midnight”) to form Pace Oil & Gas Ltd.
pursuant to a plan of arrangement under the Business Corporations Act
(Alberta). Under the arrangement, Midnight acquired all outstanding
shares of Provident Energy Resources Inc., a wholly-owned subsidiary of
Provident Energy Trust which held all of the producing oil and gas
properties and reserves associated with Provident’s Upstream business.
Effective in the second quarter of 2010, Provident’s Upstream business
is accounted for as discontinued operations.
Dividends and distributions
The following table summarizes dividends and distributions paid as
declared by Provident since inception:
Distribution / Dividend Amount
Per share / unit (Cdn$) (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
Total inception to December 31, 2010 Cash
Distributions and Capital Distribution $ 16.40 $ 13.09
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
Total 2011 Cash Dividends paid as declared $ 0.405 $ 0.414
* Exchange rate based on the Bank of Canada noon rate on the payment
date.
Change in accounting policies
(i) Recent accounting pronouncements
The International Accounting Standards Board (“IASB”) issued a number of
new accounting pronouncements including 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 27 – Separate Financial Statements and IAS 28 – Investments in Associates. 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 9, which requires application for annual
periods beginning on or after January 1, 2015, with earlier adoption
permitted. The Company has not yet assessed the impact of these
standards.
(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 first, second and third quarter 2011 interim 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 interim consolidated financial statements. Significant
accounting policies and related accounting judgments, estimates, and
assumptions can be found in notes 3 and 4 of the interim 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 interim
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 gas products 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 commodity price 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.
Share trading activity
The following table summarizes the share trading activity of Provident
for each quarter in the nine months ended September 30, 2011 on both
the Toronto Stock Exchange and the New York Stock Exchange:
Q1 Q2 Q3
TSE - PVE (Cdn$)
High $ 9.03 $ 9.06 $ 8.84
Low $ 7.62 $ 7.70 $ 6.84
Close $ 9.03 $ 8.62 $ 8.58
Volume (000s) 31,800 29,039 27,238
NYSE - PVX (US$)
High $ 9.30 $ 9.48 $ 9.19
Low $ 7.78 $ 7.85 $ 6.90
Close $ 9.27 $ 8.93 $ 8.16
Volume (000s) 75,349 83,855 85,031
 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 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 commodity price
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; 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; 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.
Quarterly table
Financial information by
quarter (IFRS)
($ 000s except for per share
and operating amounts) 2011
First Second Third Year-to-
Quarter Quarter Quarter Date
Product sales and service
revenue $ 519,100 $ 416,382 $ 450,849 $ 1,386,331
Funds flow from continuing
operations (1) $ 53,585 $ 43,490 $ 62,790 $ 159,865
Funds flow from continuing
operations per share
- basic and diluted (4) $ 0.20 $ 0.16 $ 0.23 $ 0.59
Adjusted EBITDA - continuing
operations (2) $ 61,242 $ 51,298 $ 69,528 $ 182,068
Adjusted funds flow from
continuing operations(3) $ 53,585 $ 43,490 $ 62,790 $ 159,865
Adjusted funds flow from
continuing operations per
share
- basic and diluted(4) $ 0.20 $ 0.16 $ 0.23 $ 0.59
Adjusted EBITDA excluding
buyout of financial
derivative
instruments and strategic
review and restructuring
costs
- continuing operations(2) $ 61,242 $ 51,298 $ 69,528 $ 182,068
Net (loss) income $ (11,985) $ 40,219 $ 48,398 $ 76,632
Net (loss) income per share
- basic and diluted (4) $ (0.04) $ 0.15 $ 0.18 $ 0.28
Shareholder dividends $ 36,324 $ 36,449 $ 36,609 $ 109,382
Dividends per share $ 0.14 $ 0.14 $ 0.14 $ 0.41
Provident Midstream NGL
sales volumes (bpd) 116,864 91,872 94,709 101,067
(1)Represents cash flow from operations before changes in working
capital.
(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
operationsper
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)Represents cash flow from operations before changes in working
capital and site restoration expenditures.
(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 (Canadian GAAP) (1)
($ 000s except
for per unit and
operating
amounts) 2009
First Second Third Fourth Annual
Quarter Quarter Quarter Quarter Total
Product sales
and service
revenue $ 477,056 $ 333,354 $ 339,661 $ 480,420 $ 1,630,491
Funds flow from
continuing
operations (2) $ 57,349 $ 14,456 $ 24,859 $ 51,190 $ 147,854
Funds flow from
continuing
operations per
unit
- basic and
diluted $ 0.22 $ 0.06 $ 0.09 $ 0.19 $ 0.57
Adjusted EBITDA
- continuing
operations (3) $ 65,095 $ 20,383 $ 25,569 $ 57,182 $ 168,229
Adjusted funds
flow from
continuing
operations(4) $ 57,623 $ 21,858 $ 24,859 $ 52,769 $ 157,109
Adjusted funds
flow from
continuing
operations per
unit
- basic and
diluted $ 0.22 $ 0.08 $ 0.09 $ 0.20 $ 0.60
Adjusted EBITDA
excluding buyout
of financial
derivative
instruments and
strategic review
and
restructuring
costs -
continuing
operations(3) $ 65,369 $ 27,785 $ 25,569 $ 58,761 $ 177,484
Net (loss)
income $ (40,284) $ (80,061) $ 51,663 $ (20,338) $ (89,020)
Net (loss)
income per unit
- basic and
diluted $ (0.16) $ (0.31) $ 0.20 $ (0.08) $ (0.34)
Unitholder
distributions $ 54,511 $ 47,012 $ 47,238 $ 47,456 $ 196,217
Distributions
per unit $ 0.21 $ 0.18 $ 0.18 $ 0.18 $ 0.75
Provident
Midstream NGL
sales volumes
(bpd) 141,669 102,799 98,229 111,912 113,528
(1)The financial information for 2009 is presented in Canadian GAAP as
these periods are prior to the January 1, 2010 transition date for
IFRS.
(2)Represents cash flow from operations before changes in working
capital and site restoration expenditures.
(3)Adjusted EBITDA is earnings before interest, taxes, depreciation,
amortization and other non-cash items - see "Reconciliation of Non-GAAP
measures".
(4)Adjusted funds flow from continuing operations excludes realized
loss on buyout of financial derivative instruments and strategic review
and restructuring costs.
PROVIDENT ENERGY LTD.
CONSOLIDATEDSTATEMENTS OF
FINANCIAL POSITION
Canadian dollars (000s)
(unaudited)
As at As at As at
September 30, December 31, January 1,
2011 2010 2010
Assets
Current assets
Cash and cash $ - $ 4,400 $ 7,187
equivalents
Accounts receivable 183,296 206,631 216,786
Petroleum product 161,848 106,653 58,779
inventory (note 6)
Prepaid expenses and 5,110 2,539 4,803
other current assets
Financial derivative 37,404 487 5,314
instruments (note 15)
Assets held for sale - - 186,411
(note 18)
387,658 320,710 479,280
Non-current assets
Investments - - 18,733
Exploration and
evaluation assets (note - - 24,739
18)
Property, plant and 907,230 833,790 1,422,156
equipment (note 7)
Intangible assets (note 109,913 118,845 132,478
8)
Goodwill (note 9) 100,409 100,409 100,409
Deferred income taxes 15,027 72,699 -
(note 14)
$ 1,520,237 $ 1,446,453 $ 2,177,795
Liabilities
Current liabilities
Accounts payable and $ 218,100 $ 227,944 $ 221,417
accrued liabilities
Cash dividends payable 8,997 12,646 13,468
Current portion of
convertible debentures - 148,981 -
(note 10)
Financial derivative 63,717 37,849 86,441
instruments (note 15)
Liabilities held for - - 2,792
sale (note 18)
290,814 427,420 324,118
Non-current liabilities
Long-term debt -
revolving term credit 206,482 72,882 264,776
facility (note 10)
Long-term debt -
convertible debentures 314,745 251,891 240,486
(note 10)
Decommissioning 80,108 57,232 127,800
liabilities (note 11)
Long-term financial
derivative instruments 29,617 29,187 103,403
(notes 10 and 15)
Other long-term
liabilities (notes 11 17,057 19,634 12,496
and 13)
Deferred income taxes - - 37,765
(note 14)
938,823 858,246 1,110,844
Shareholders' equity
Share capital (note 12) 2,892,225 - -
Unitholders' contributions - 2,866,268 2,834,177
(note 12)
Contributed surplus 684 684 684
Accumulated deficit (2,311,495) (2,278,745) (1,767,910)
581,414 588,207 1,066,951
$ 1,520,237 $ 1,446,453 $ 2,177,795
 The accompanying notes are an integral part of these interim
consolidated financial statements.
PROVIDENTENERGY LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE
INCOME (LOSS)
Canadian dollars (000s
except per share
amounts)
(unaudited)
Three monthsended Ninemonths ended
September 30, September30,
2011 2010 2011 2010
Product sales and
service revenue (note
16) $ 450,849 $ 363,767 $ 1,386,331 $ 1,202,832
Realized loss on buyout
of financial derivative
instruments (note 15) - - - (199,059)
Unrealized gain
offsetting buyout of
financial
derivative instruments
(note 15) - - - 177,723
Gain (loss) on
financial derivative
instruments
(note 15) 4,606 (31,197) (30,824) (74,694)
455,455 332,570 1,355,507 1,106,802
Expenses
Cost of goods sold
(note 6) 355,113 292,799 1,097,718 977,008
Production, operating
and maintenance 4,729 5,371 15,344 13,748
Transportation 5,297 3,609 13,440 12,444
Depreciation and
amortization 10,475 11,380 31,714 32,831
General and
administrative 10,480 9,084 33,120 24,820
Strategic review and
restructuring - - - 11,913
Financing charges 8,559 8,777 31,918 21,742
Loss on revaluation
of conversion feature
of convertible
debentures (note 15) 4,097 - 5,300 -
Other income and
foreign exchange
(note 17) (4,315) (7,527) (7,534) (6,509)
394,435 323,493 1,221,020 1,087,997
Income from continuing
operations before
taxes 61,020 9,077 134,487 18,805
Current tax expense
(recovery) 97 (1,015) 208 (11,094)
Deferred tax expense
(recovery) (note 14) 12,525 (3,887) 57,647 (18,696)
12,622 (4,902) 57,855 (29,790)
Net income from
continuing operations 48,398 13,979 76,632 48,595
Net loss from
discontinued operations
(note 18 ) - (5,000) - (131,481)
Net income (loss) and
comprehensive income
(loss)
for the period $ 48,398 $ 8,979 $ 76,632 $ (82,886)
Net income from
continuing operations
- basic and diluted $ 0.18 $ 0.05 $ 0.28 $ 0.18
Net income (loss) per
share
- basic and diluted $ 0.18 $ 0.03 $ 0.28 $ (0.31)
The accompanying notes are an integral part of these interim
consolidated financial statements.
PROVIDENT ENERGY LTD.
CONSOLIDATED STATEMENTS
OF CASH FLOWS
Canadian dollars (000s)
(unaudited)
Three months ended Nine months ended
September 30, September30,
2011 2010 2011 2010
Cash provided by (used
in) operatingactivities
Net income for the
period from
continuing operations $ 48,398 $ 13,979 $ 76,632 $ 48,595
Add (deduct) non-cash
items:
Depreciation and
amortization 10,475 11,380 31,714 32,831
Non-cash financing
charges and other 1,918 2,166 6,581 5,518
Loss on purchase of
convertible
debentures (note 10) - - 3,342 -
Non-cash share based
compensation expense
(recovery) 3,163 1,140 3,774 (3,287)
Unrealized gain
offsetting buyout of
financial
derivative
instruments (note 15) - - - (177,723)
Unrealized (gain)
loss on financial
derivative
instruments
(note 15) (16,677) 26,641 (24,291) 40,235
Loss on revaluation
of conversion feature
of
convertible
debentures (note 15) 4,097 - 5,300 -
Unrealized foreign
exchange gain and
other (1,109) (4,477) (834) (5,026)
Gain on sale of
assets (note 17) - (3,300) - (3,300)
Deferred tax expense
(recovery) 12,525 (3,887) 57,647 (18,696)
Continuing operations 62,790 43,642 159,865 (80,853)
Discontinued operations - - - (2,436)
62,790 43,642 159,865 (83,289)
Site restoration
expenditures related to
discontinued operations - - - (2,041)
Change in non-cash
operating working
capital (51,207) (57,868) (45,340) (81,370)
11,583 (14,226) 114,525 (166,700)
Cash provided by (used
for) financing
activities
Issuance of
convertible
debentures, net of
issue costs (note 10) - - 164,950 -
Repayment of
debentures - - (249,784) -
Increase in long-term
debt 35,080 60,020 132,869 38,511
Declared dividends to
shareholders (36,609) (47,990) (109,382) (143,418)
Issue of shares, net
of issue costs 10,253 8,529 25,908 22,141
Change in non-cash
financing working
capital 36 (389) (3,649) (403)
8,760 20,170 (39,088) (83,169)
Cash (used for)
providedby investing
activities
Capital expenditures (28,071) (10,965) (74,988) (21,379)
Acquisitions - (9) - (22,456)
Proceeds on sale of
assets - 3,300 - 3,300
Proceeds on sale of
discontinued
operations - (5,000) - 106,779
Change in non-cash
investing working
capital (900) 6,730 (4,849) 5,728
Investing activities
from discontinued
operations - - - 170,710
(28,971) (5,944) (79,837) 242,682
Decrease incash and
cash equivalents (8,628) - (4,400) (7,187)
Cash and cash
equivalents, beginning
of period 8,628 - 4,400 7,187
Cash and cash
equivalents, end of
period $ - $ - $ - $ -
Supplemental disclosure
of cash flow
information
Cash interest paid
including debenture
interest $ 2,458 $ 5,828 $ 21,673 $ 19,291
Cash taxes received $ (941) $ (1,872) $ (2,133) $ (780)
The accompanying notes are an integral part of these interim
consolidated financial statements.
PROVIDENT
ENERGY LTD.
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Canadian
Dollars
(000s)
(unaudited)
Share Unitholders' Contributed Accumulated Total
capital contributions surplus deficit equity
Balance -
December 31,
2010 $ - $ 2,866,268 $ 684 $ (2,278,745) $ 588,207
Cancelled on
conversion to
a corporation
effective
January 1,
2011 (2,866,268) (2,866,268)
Issued on
conversion to
a corporation
effective
January 1,
2011 2,866,268 2,866,268
Net income
and
comprehensive
income for
the period - - - 76,632 76,632
Proceeds on
issuance of
shares (note
12) 25,908 - - - 25,908
Debenture
conversions
(note 12) 49 - - - 49
Dividends - - - (109,382) (109,382)
Balance -
September 30,
2011 $ 2,892,225 $ - $ 684 $ (2,311,495) $ 581,414
Balance -
January 1,
2010 $ - $ 2,834,177 $ 684 $ (1,767,910) $ 1,066,951
Net loss and
comprehensive
loss for the
period - - - (82,886) (82,886)
Proceeds on
issuance of
trust units - 22,141 - - 22,141
Cash
distributions - - - (143,418) (143,418)
Capital
distribution
in connection
with the sale
of the
Upstream
business
(note 18) - - - (308,690) (308,690)
Balance -
September 30,
2010 $ - $ 2,856,318 $ 684 $ (2,302,904) $ 554,098
The accompanying notes are an integral part of these interim
consolidated financial statements.Â
Notes to the Interim Consolidated Financial Statements
(Tabular amounts in Cdn $ 000′s, except share and per share amounts)
(unaudited)
For the periods ended September 30, 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 (DRIP) purchase 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.
The Company’s financial results for any individual quarter are not
necessarily indicative of results to be expected for the full year.
Interim period revenues and earnings are typically sensitive to weather
and market conditions. In particular, demand and pricing for NGL
products is typically seasonal and tends to result in periods of lower
sales volumes during the second and third quarters as inventory is
built up for sales in peak demand periods in the fourth quarter and
first quarter of the following year when sales volumes are typically
higher.
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 (“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 interim consolidated financial statements have been prepared in
accordance with IFRS applicable to the preparation of interim financial
statements, including IAS 34 - Interim Financial Reporting and IFRS 1 - First-time Adoption of International Financial Reporting Standards. 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 interim consolidated financial statements
are based on IFRS issued and outstanding as of November 9, 2011, the
date the Board of Directors approved the statements. Any subsequent
changes to IFRS that are given effect in the Company’s annual
consolidated financial statements for the year ended December 31, 2011
could result in restatement of these interim consolidated financial
statements including the transition adjustments recognized on
change-over to IFRS.
The interim consolidated financial statements should be read in
conjunction with the Company’s Canadian GAAP annual consolidated
financial statements for the year ended December 31, 2010.
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 18 – 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.
All intercompany transactions, balances and unrealized gains and losses
from intercompany transactions are eliminated on consolidation.
ii) Financial instrumentsÂ
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, plus, in the case of investments not at fair value through
profit or loss, directly attributable transaction costs.
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 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.Â
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 accounts receivables are included
in this financial asset category.
c)Â Â Â Â Â Cash and cash equivalents
Cash and cash equivalents include short-term investments with an
original maturity of three months or less when purchased.
Financial Liabilities
a)Â Â Â Â Â 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 classified as held for trading.Â
Gains and losses on liabilities held for trading are recognized in
profit and loss.
b)Â Â Â Â Â Other 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 distribution payable, long-term debt and convertible
debentures are included within this financial liability category (also
see item xiv).
iii)Â Â Â Â Â 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.
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 in the storage caverns 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 equipment 5 - 6 years
Computer hardware & software 3 - 4 years
Leasehold improvements & other 10 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â Leases
Operating lease payments are recognized as an expense in the statement
of operations on a straight-line basis over the lease term.
vii)Â Â Â Â Â 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)Â Â Â Â Â 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.
ix)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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 diluted calculation.
xiii)Â Â Â Â Â 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)Â Â Â Â Â 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.
On initial recognition, convertible debentures with a cash conversion
option are measured using a method whereby the fair value of the
embedded financial derivative instrument is measured using an option
pricing model, with the residual amount allocated to the debt
component.
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, the convertible debentures without a cash conversion
feature are measured using the residual method whereby the debt
component was recognized at fair value, with the conversion feature as
the residual.
Subsequent to initial recognition, the debt portion, net of issue costs,
is accounted for at amortized cost using the effective interest rate
method, whereby the residual value of the debt is accreted up to the
face value of the debentures. For 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
statement of operations. Upon conversion, the corresponding portions of
the debt and equity are removed from those captions and transferred to
share capital.
xv)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â Accounting standards issued but not yet applied
International Financial Reporting Standards
The International Accounting Standards Board (“IASB”) issued a number of
new accounting pronouncements including 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 27 – Separate Financial Statements and IAS 28 – Investments in Associates. 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 9, which requires application for annual
periods beginning on or after January 1, 2015, with earlier adoption
permitted. The Company has not yet assessed the impact of these
standards.
4. Significant accounting judgments, 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 can only be
determined by draining of the caverns. By their very nature, these
estimates are subject to measurement uncertainty and the effect on the
financial statements of future periods could be material.
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 cost, 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 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 required in relation to
discount rates. As a result, there could be significant adjustments to
the provisions established which would affect future financial results.
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
works 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. The assumptions are discussed in note 13. Actual payments
made on settlement may differ from estimates and the difference could
be material.
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. By
their nature, these estimates are subject to measurement uncertainty
and the effect on the financial statements of future periods could be
material.
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 three and nine
months ended September 30, 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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
liability 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â The following is a reconciliation of the consolidated statements of
financial position, including shareholders’ equity, as previously reported under Canadian GAAP to IFRS:
($000's) December 31, 2010 September 30, 2010 January 1, 2010
Note CDN GAAP Adj IFRS CDN GAAP Adj IFRS CDN GAAP Adj IFRS
Assets
Current assets
Cash and cash 4,400 - 4,400 - - - 7,187 - 7,187
equivalents
Accounts 206,631 - 206,631 187,589 - 187,589 216,786 - 216,786
receivable
Petroleum
product A 83,868 22,785 106,653 132,544 20,832 153,376 37,261 21,518 58,779
inventory
Prepaid
expenses and 2,539 - 2,539 4,958 - 4,958 4,803 - 4,803
other current
assets
Financial
derivative 487 - 487 76 - 76 5,314 - 5,314
instruments
Assets held I - - - - - - - 186,411 186,411
for sale
297,925 22,785 320,710 325,167 20,832 345,999 271,351 207,929 479,280
Investments - - - - - - 18,733 - 18,733
Exploration and
evaluation I - - - - - - - 24,739 24,739
assets
Property, plant A,
and equipment B, 832,250 1,540 833,790 813,471 1,692 815,163 2,025,044 (602,888) 1,422,156
D,I
Intangible 118,845 - 118,845 122,253 - 122,253 132,478 - 132,478
assets
Goodwill 100,409 - 100,409 100,409 - 100,409 100,409 - 100,409
Deferred income G 50,375 22,324 72,699 35,636 14,967 50,603 - - -
taxes
1,399,804 46,649 1,446,453 1,396,936 37,491 1,434,427 2,548,015 (370,220) 2,177,795
Liabilities
Current
liabilities
Accounts
payable and 227,944 - 227,944 193,327 - 193,327 221,417 - 221,417
accrued
liabilities
Cash
dividends 12,646 - 12,646 13,065 - 13,065 13,468 - 13,468
payable
Current
portion of 148,981 - 148,981 148,243 - 148,243 - - -
convertible
debentures
Financial
derivative 37,849 - 37,849 27,179 - 27,179 86,441 - 86,441
instruments
Liabilities I - - - - - - - 2,792 2,792
held for sale
427,420 - 427,420 381,814 - 381,814 321,326 2,792 324,118
Long-term debt
- revolving 72,882 - 72,882 303,530 - 303,530 264,776 - 264,776
term credit
facility
Long-term debt
- convertible 251,891 - 251,891 95,677 - 95,677 240,486 - 240,486
debentures
Decommissioning B, I 22,057 35,175 57,232 21,695 34,987 56,682 61,464 66,336 127,800
liabilities
Long-term
financial C 19,601 9,586 29,187 17,495 - 17,495 103,403 - 103,403
derivative
instruments
Other long-term F 18,735 899 19,634 21,703 3,428 25,131 12,496 - 12,496
liabilities
Deferred income G,I - - - - - - 162,665 (124,900) 37,765
taxes
812,586 45,660 858,246 841,914 38,415 880,329 1,166,616 (55,772) 1,110,844
Shareholders'
equity
Unitholders' 2,866,268 - 2,866,268 2,856,318 - 2,856,318 2,834,177 - 2,834,177
contributions
Convertible
debentures C 25,092 (25,092) - 15,940 (15,940) - 15,940 (15,940) -
equity
component
Contributed C 2,953 (2,269) 684 2,953 (2,269) 684 2,953 (2,269) 684
surplus
Accumulated H 28,350 17,285 (296,239)
deficit (2,307,095) (2,278,745) (2,320,189) (2,302,904) (1,471,671) (1,767,910)
587,218 989 588,207 555,022 (924) 554,098 1,381,399 (314,448) 1,066,951
1,399,804 46,649 1,446,453 1,396,936 37,491 1,434,427 2,548,015 (370,220) 2,177,795
Â
iii)Â Â Â Â Â The following is a reconciliation of the consolidated statements of
operations as previously reported under Canadian GAAP to IFRS:
Year ended Three months ended Nine months ended
($000s) December 31, 2010 September 30, 2010 September 30, 2010
Notes CDN GAAP Adj IFRS CDN Adj IFRS CDN GAAP Adj IFRS
GAAP
Product sales
and service 1,746,557 - 1,746,557 363,767 - 363,767 1,202,832 - 1,202,832
revenue
Realized loss on
buyout of
financial - - - - - - (199,059) - (199,059)
derivative
instruments
Unrealized gain
offsetting
buyout of - - - - - - 177,723 - 177,723
financial
derivative
instruments
Loss on
financial (124,800) - (124,800) (31,197) - (31,197) (74,694) - (74,694)
derivative
instruments
1,621,757 - 1,621,757 332,570 - 332,570 1,106,802 - 1,106,802
Expenses
Cost of goods A 1,397,901 (1,266) 1,396,635 292,443 356 292,799 976,322 686 977,008
sold
Production,
operating and 18,504 - 18,504 5,371 - 5,371 13,748 - 13,748
maintenance
Transportation 18,442 - 18,442 3,609 - 3,609 12,444 - 12,444
Depreciation
and D, E 45,718 (1,243) 44,475 11,878 (498) 11,380 33,606 (775) 32,831
amortization
General and 36,671 - 36,671 9,084 - 9,084 24,820 - 24,820
administrative
Strategic
review and 13,782 - 13,782 - - - 11,913 - 11,913
restructuring
Financing B, E 29,723 2,528 32,251 8,045 732 8,777 19,948 1,794 21,742
charges
Loss on
revaluation of
conversion C - 433 433 - - - - - -
feature of
convertible
debentures
Gain on sale
of assets,
foreign (3,826) - (3,826) (7,527) - (7,527) (6,509) - (6,509)
exchange and
other
1,556,915 452 1,557,367 322,903 590 323,493 1,086,292 1,705 1,087,997
Income from
continuing 64,842 (452) 64,390 9,667 (590) 9,077 20,510 (1,705) 18,805
operations
before taxes
Current tax (6,956) - (6,956) (1,015) - (1,015) (11,094) - (11,094)
recovery
Deferred
income tax G (31,694) (9,177) (40,871) (3,242) (645) (3,887) (16,876) (1,820) (18,696)
recovery
(38,650) (9,177) (47,827) (4,257) (645) (4,902) (27,970) (1,820) (29,790)
Net income for the
period from continuing 103,492 8,725 112,217 13,924 55 13,979 48,480 115 48,595
operations
Net loss from
discontinued I (438,587) 315,864 (122,723) (5,000) - (5,000) (444,890) 313,409 (131,481)
operations
Net (loss)
income and
comprehensive (335,095) 324,589 (10,506) 8,924 55 8,979 (396,410) 313,524 (82,886)
(loss) income
for the period
Â
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 impact on cost of goods sold
of an additional $0.7 million for the nine months ended September 30,
2010 and a reduction 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. 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 earnings for the nine months ended September 30, 2010 and
annual 2010 earnings was additional accretion expense of $0.5 million
and $0.7 million, respectively.
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 contributed
surplus, 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 $0.5 million for the
nine months ended September 30, 2010 and $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
$1.3 million for the nine months ended September 30, 2010 and $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 of four percent which resulted in Provident recording an
adjustment of $3.4 million as at September 30, 2010 and $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. For the nine months ended September 30, 2010, the impact of
IFRS differences on deferred taxes related to continuing operations was
an additional recovery of $1.8 million. 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 December31 September30 January1
Accumulated deficit as
reported under Canadian $ (2,307.1) $ (2,320.2) $ (1,471.7)
GAAP
IFRS transition
adjustments increase
(decrease) on opening
statement of financial
position related to
continuing operations:
Petroleum product A 0.4 0.4 0.4
inventory
Decommissioning B (11.1) (11.1) (11.1)
liabilities
Convertible C 18.2 18.2 18.2
debentures
Other long-term F (0.9) (0.9) (0.9)
liabilities
Deferred income taxes G 13.1 13.1 13.1
19.7 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 I (391.5) (391.5) (391.5)
properties
Decommissioning I (36.1) (36.1) (36.1)
liabilities
Deferred income taxes I 111.7 111.7 111.7
(315.9) (315.9) (315.9)
Total net impact on
opening statement of $ (296.2) $ (296.2) $ (296.2)
financial position
IFRS transition
adjustments increase
(decrease) net income
from continuing
operations:
Cost of goods sold A $ 1.3 $ (0.7) $ -
Loss on financial
derivative C (0.4) - -
instruments
Depreciation and D, E 1.2 0.8 -
amortization
Financing charges B, E (2.5) (1.8) -
Deferred income taxes G 9.1 1.8 -
8.7 0.1 -
IFRS transition
adjustments increase
(decrease) net income
from discontinued
operations:
Depletion expense I 40.2 40.2 -
Loss on sale of oil I (8.1) (8.1) -
and gas properties
Loss on sale of
discontinued I 296.0 293.5 -
operations
Deferred income taxes I (12.2) (12.2) -
315.9 313.4 -
Total net impact on $ 324.6 $ 313.5 $ -
statement of operations
Accumulated deficit as $ (2,278.7) $ (2,302.9) $ (1,767.9)
reported under IFRS
Â
I.     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 December 31 September 30 January 1
operations ($ Note
millions)
IFRS transition
adjustments
increase (decrease)
on opening
statement
of financial
position:
Impairment on (391.5) (391.5) (391.5)
Upstream oil and 1 $ $ $
gas properties
Decommissioning 2 (36.1) (36.1) (36.1)
liabilities
Deferred income 5 111.7 111.7 111.7
taxes
(315.9) (315.9) (315.9)
IFRS adjustments
increase (decrease)
net income on
statement
of operations:
Depletion expense 1 40.2 40.2 -
Loss on sale of (8.1) (8.1) -
oil and gas 3
properties
Loss on sale of 296.0 293.5 -
discontinued 6
operations
Deferred income 5 (12.2) (12.2) -
taxes
315.9 313.4 -
Net impact on $ - $ (2.5) $ (315.9)
accumulated deficit
Â
1)Â Â Â Â Â 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 nine months ended September 30, 2010 and 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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 were incurred in the nine months ended
September 30, 2010 and for the year ended December 31, 2010 primarily
as a result of lower depletion expense under IFRS.
6)Â Â Â Â Â 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 $293.5 million and $296.0 million,
net of tax, for the nine months ended September 30, 2010 and year ended
December 31, 2010, respectively.
6. 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 three and nine months ended September 30, 2011,
the Company recognized $355.1 million (2010 – $292.8 million) and $1.1
billion (2010 – $977.0 million), respectively, of product inventory as
an expense in cost of goods sold. 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. For the nine months ended
September 30, 2011 and 2010, no write-down or reversal of write-downs
of inventories were recognized in the consolidated statement of
operations.
7. Property, plant and equipment
Office Oil &
Midstream equipment natural gas
($000s) assets &other Subtotal properties Total
Cost:
Balance as at $ 886,442 $ 47,174 $ 933,616 $ 2,682,180 $ 3,615,796
January 1, 2010
Additions 55,768 920 56,688 38,444 95,132
Acquisitions 22,456 - 22,456 5,117 27,573
Disposals - (2,603) (2,603) (2,725,741) (2,728,344)
Balance as at
December 31, 964,666 45,491 1,010,157 - 1,010,157
2010
Additions 73,766 512 74,278 - 74,278
Capitalized
interest, net 711 - 711 - 711
of recoveries
Change in
decommissioning 21,159 - 21,159 - 21,159
provision
Other - 74 74 - 74
Removal of
fully (1,765) (23,601) (25,366) - (25,366)
depreciated
assets
Balance as at
September 30, $ 1,058,537 $ 22,476 $ 1,081,013 $ - $ 1,081,013
2011
Accumulated
depletion and
depreciation:
Balance as at $ 116,656 $ 27,786 $ 144,442 $ 2,049,198 $ 2,193,640
January 1, 2010
Depletion and
depreciation 25,729 7,056 32,785 123,940 156,725
for the period
Disposals - (860) (860) (2,173,138) (2,173,998)
Balance as at
December 31, 142,385 33,982 176,367 - 176,367
2010
Depreciation 18,733 4,049 22,782 - 22,782
for the period
Removal of
fully (1,765) (23,601) (25,366) - (25,366)
depreciated
assets
Balance as at
September 30, $ 159,353 $ 14,430 $ 173,783 $ - $ 173,783
2011
Net book value:
Net book value
as at January $ 769,786 $ 19,388 $ 789,174 $ 632,982 $ 1,422,156
1, 2010
Net book value
as at December $ 822,281 $ 11,509 $ 833,790 $ - $ 833,790
31, 2010
Net book value
as at September $ 899,184 $ 8,046 $ 907,230 $ - $ 907,230
30, 2011
Â
Capitalized borrowing costs
The amount of borrowing costs directly attributable to the construction
of assets that take a substantial period of time to get ready for their
intended use capitalized during the period ended September 30, 2011 was
$0.7 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.
Septimus to Younger pipeline project
On March 2, 2011, Provident announced an agreement between Provident
Energy Ltd., AltaGas Ltd. (“AltaGas”), and a senior producer, to
construct a 16-inch rich gas pipeline from a Montney gas plant to the
AltaGas/Provident Younger deep cut natural gas processing facility in
northeastern British Columbia. Under the agreement, Provident and
AltaGas will each own a 30 percent interest in the project. The 25
kilometre pipeline will serve as a trunk line to support the gathering
of up to 250 million cubic feet per day of natural gas from the
liquids-rich Montney area. The estimated cost to complete the pipeline
is approximately $30 million, of which Provident has committed to spend
$9 million.
Construction of a truck terminal at Cromer
On September 8, 2011, Provident announced the construction of a truck
unloading terminal located at Cromer, Manitoba. The terminal, plus
associated storage, will have an initial capacity of approximately
2,000 barrels per day of natural gas liquids production from the Bakken
area. The natural gas liquids from this terminal will be injected into
the Enbridge mainline for transport to Sarnia, Ontario. Provident
anticipates the project will cost approximately $10 million to complete
and will begin receiving volumes in the first quarter of 2012.
8. Intangible assets
Midstream
contracts and Other
customer intangible
($000s) relationships assets Total
Cost:
Balance as at January 1, $ 183,100 $ 16,308 $ 199,408
2010
Balance as at December 31, 183,100 16,308 199,408
2010
Removal of fully amortized (21,100) - (21,100)
assets
Balance as at September 30, $ 162,000 $ 16,308 $ 178,308
2011
Accumulated amortization:
Balance as at January 1, $ 61,862 $ 5,068 $ 66,930
2010
2010 amortization 13,200 433 13,633
Balance as at December 31, 75,062 5,501 80,563
2010
Amortization for the 8,611 321 8,932
period
Removal of fully amortized (21,100) - (21,100)
assets
Balance as at September 30, $ 62,573 $ 5,822 $ 68,395
2011
Net book value:
Net book value as at $ 121,238 $ 11,240 $ 132,478
January 1, 2010
Net book value as at $ 108,038 $ 10,807 $ 118,845
December 31, 2010
Net book value as at $ 99,427 $ 10,486 $ 109,913
September 30, 2011
Useful life (years) 15 12 -15
Remaining amortization 9.25 9.25
period (years)
Â
9. Goodwill
Provident performed a goodwill impairment test at January 1, 2010 and
December 31, 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
10 year period. Key assumptions upon which management based its
determinations of the recoverable amount for the goodwill in 2010
include operating margins which are projected to increase by
approximately 3% by 2020, attributable to capital expenditures and
expected growth in the fee-for-service business, combined with a
positive commodity pricing outlook and a weighted average discount rate
of 10.5%. The forecast included future commodity price assumptions
based on forward commodity price curves effective at December 31, 2010
with the assumption that prices will stabilize at approximately
US$92.00/bbl for WTI crude oil and $5.00/mmbtu for AECO natural gas by
2014 and increase at inflationary rates thereafter.
10. Long-term debt
As at As at
September 30, 2011 December 31, 2010
Revolving term credit $ 206,482 $ 72,882
facility
Convertible debentures 314,745 251,891
Current portion of - 148,981
convertible debentures
314,745 400,872
Total $ 521,227 $ 473,754
Â
i)Â Â Â Â Â Revolving term credit facility
Provident renegotiated an extension of its existing credit agreement
(the “Credit Facility”) as of 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, from the previous maturity
date of June 28, 2013, (subject to customary extension provisions)
secured by all of the assets of the Company and its subsidiaries.
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 September 30, 2011, Provident had drawn $210.8 million
(including $1.8 million presented as a bank overdraft in accounts
payable and accrued liabilities) or 42 percent of its Credit Facility
(December 31, 2010 – $75.5 million or 15 percent). Included in the
carrying value at September 30, 2011 were financing costs of $1.7
million (December 31, 2010 – $2.4 million). At September 30, 2011 the
effective interest rate of the outstanding Credit Facility was 3.5
percent (December 31, 2010 – 4.1 percent). At September 30, 2011
Provident had $57.3 million in letters of credit outstanding (December
31, 2010 – $47.9 million) that guarantee Provident’s performance under
certain commercial and other contracts.
ii)Â Â Â Â Â Convertible debentures
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.
The debt component of the debentures was initially recorded at fair
value of $164.1 million ($156.6 million, net of issue costs). The
difference between the fair value and net proceeds of $8.4 million
represents the conversion feature of the debentures 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 repurchase 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 nine months
ended September 30, 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 September 30, 2011 were
financing costs of $14.0 million (December 31, 2010 – $9.0 million).Â
The following table details each outstanding convertible debenture.
As at As at
Convertible September 30, 2011 December 31, 2010
Debentures
($000s Conversion
except price per
conversion Carrying Face Carrying Face Maturity share(2)
pricing) value(1) value value value date
6.5% April
Convertible $ - $ - 148,981 $ 149,980 30, 2011 $ 12.40
Debentures
6.5% Aug. 31,
Convertible - - 96,084 98,999 2012 11.56
Debentures
5.75% Dec. 31,
Convertible 157,377 172,500 155,807 172,500 2017 10.60
Debentures
5.75% Dec. 31,
Convertible 157,368 172,500 - - 2018 12.55
Debentures
$ 314,745 $ 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 15).
11. 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.
Three months ended Nine months ended September
September 30, 30,
($000s) 2011 2010 2011 2010
Carrying
amount, $ 58,377 $ 56,132 $ 57,232 $ 127,800
beginning of
period
Acquisitions - - - 3,902
Dispositions -
discountinued - - - (65,184)
operations
Increase in
liabilities
incurred - - - 220
during the
period
Settlement of
liabilities
during the - - - (2,041)
period
- discontinued
operations
Transfer to
other
long-term - - - (18,194)
liabilities
(1)
Accretion of
liability - 572 550 1,717 1,613
continuing
operations
Accretion of
liability - - - - 1,494
discontinued
operations
Change in 21,159 - 21,159 7,072
estimate
Carrying
amount, end of $ 80,108 $ 56,682 $ 80,108 $ 56,682
period
(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.
12. 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.”
i)Â Â Â Â Â Share capital
Number of Amount
Common Shares shares (000s)
Issued on conversion to a corporation 268,765,492 $ 2,866,268
effective January 1, 2011
Issued pursuant to the dividend 2,865,408 22,681
reinvestment plan
To be issued pursuant to the dividend 382,789 3,227
reinvestment plan
Debenture conversions 4,325 49
Balance at September 30, 2011 272,018,014 $ 2,892,225
Â
Provident has an unlimited number of common shares authorized for
issuance.
ii)Â Â Â Â Â Unitholders’ contributions
Number of Amount
Trust Units units (000s)
Balance at January 1, 2010 264,336,636 $ 2,834,177
Issued pursuant to the distribution 4,002,565 28,635
reinvestment plan
To be issued pursuant to the 426,291 3,456
distribution reinvestment plan
Balance at December 31, 2010 268,765,492 $ 2,866,268
Cancelled on conversion to a (268,765,492) (2,866,268)
corporation effective January 1, 2011
Balance at September 30, 2011 - $ -
The basic and diluted per share amounts for the three months ended
September 30, 2011 were calculated based on the weighted average number
of shares outstanding of 270,980,788 (2010 – 266,418,768).
The basic and diluted per share amounts for the nine months ended
September 30, 2011 were calculated based on the weighted average number
of shares outstanding of 269,920,292 (2010 – 265,436,507).
13. Share based compensation
i)Â Â Â Â Â 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 September 30,
2011, $13.9 million (December 31, 2010 – $7.4 million) is included in
accounts payable and accrued liabilities for this plan and $7.8 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.
Three months ended Nine months ended September
September 30, 30,
2011 2010 2011 2010
General and $ 3,182 $ 1,140 $ 10,467 $ 3,593
administrative
Production,
operating and
maintenance
expense
(recovery) 261 (34) 829 48
$ 3,443 $ 1,106 $ 11,296 $ 3,641
Â
The following table provides a continuity of the Company’s RSU and PSU
plans:
Units outstanding RSUs PSUs
Opening balance, January 1, 2011 1,175,008 2,443,581
Grants 542,999 470,069
Reinvested through notional dividends 59,869 115,209
Exercised (560,215) (722,082)
Forfeited (14,454) (11,636)
Ending balance September 30, 2011 1,203,207 2,295,141
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At September 30, 2011, all RSUs and PSUs have been valued at a share
price of $8.58 and, as at September 30, 2011 each PSU has been valued
using a multiplier of 1.25, 1.35, and 1.00, for the 2009, 2010, and
2011 grants, respectively.
14. Income taxes
Prior to conversion to a corporation effective January 1, 2011, IFRS
requires temporary differences at the Trust level to be reflected at
the highest rate at which individuals would be taxed on undistributed
profits. Upon corporate conversion, deferred tax balances are
determined using the applicable statutory rate for corporations.
Income tax expense is recognized based on management’s best estimate of
the weighted average annual income tax rate expected for the full
financial year. The estimated average rate used for the nine months
ended September 30, 2011 and 2010 was 27.5 percent and 33.5 percent,
respectively.
15. Financial instruments
The following table is a summary of the net financial derivative
instruments liability:
As at September 30, As at December 31,
($ 000s) 2011 2010
Crude oil (31,799) 28,313
Natural gas 19,642 19,102
NGL's (includes propane, 30,780 10,363
butane)
Foreign exchange 11,959 (28)
Electricity (1,134) (421)
Interest 3,224 (366)
Conversion feature of 23,258 9,586
convertible debentures
Total $ 55,930 $ 66,549
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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 losses of $4.1 million
(2010 – nil) and $5.3 million (2010 – nil) on the revaluation on the
conversion feature of convertible debentures for the three and nine
months ended September 30, 2011, respectively.
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 cost of $199.1 million. The carrying value of these
specific contracts at March 31, 2010 was a liability of $177.7 million
resulting in an offsetting unrealized gain in the second quarter of
2010. The buyout of Provident’s forward mark-to-market positions
allowed Provident to refocus its Commodity Price Risk Management
Program on forward selling a portion of actual produced NGL products
and inventory to lock-in margins for terms of up to two years.
Provident has retained certain participating crude oil and natural gas
swaps and NGL throughput and inventory contracts that utilize financial
derivative instruments based directly on underlying NGL products.
The following table summarizes the impact of the gain (loss) on
financial derivative instruments during the three and nine months ended
September 30, 2011 and 2010. The loss on revaluation of conversion
feature of convertible debentures, realized loss on buyout of financial
derivative instruments, and unrealized gain offsetting buyout of
financial derivative instruments are not included in the table as these
items are separately disclosed on the consolidated statement of
operations.
Gain (loss) Three months ended September 30, Nine months ended September 30,
on
financial
derivative 2011 2010 2011 2010
instruments
($ 000s Volume Volume Volume Volume
except (1) (1) (1) (1)
volumes)
Realized
loss on
financial
derivative
instruments
Crude oil $ 1,625 0.8 $ (1,263) 0.5 $ (8,336) 1.7 $ 1.7
(12,414)
Natural (2,243) 6.1 (3,149) 3.3 (7,935) 18.3 10.6
gas (25,128)
NGL's
(includes 1.6 (336) - 3.7 818 0.4
propane, (13,086) (41,841)
butane)
Foreign 874 459 1,472 2,631
exchange
1,084 (154) 1,947 446
Electricity
Interest (325) (113) (422) (812)
rate
(4,556)
(12,071) (55,115) (34,459)
Unrealized
gain (loss)
on
financial
derivative
instruments 16,677 (26,641) 24,291 (40,235)
Gain (loss)
on
financial
derivative
instruments $ 4,606 $ (31,197) $ (30,824) $ (74,694)
(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.
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16. Product sales and service revenue
For the three and nine months ended September 30, 2011, included in
product sales and service revenue is $60.7 million (2010 – $34.2
million) and $176.7 million (2010 – $132.4 million), respectively,
associated with the U.S. midstream operations.
17. Other income and foreign exchange
Other income and foreign exchange is comprised of:
Other income Three months ended Nine months ended September
and foreign September 30, 30,
exchange
($ 000s) 2011 2010 2011 2010
Realized (gain)
loss on foreign $ (1,094) $ 548 $ (258) $ 2,115
exchange
Gain on sale of - (3,300) - (3,300)
assets
Other income (2,112) (298) (6,442) (298)
(3,206) (3,050) (6,700) (1,483)
Unrealized
(gain) loss on (1,111) 425 (886) (124)
foreign
exchange
Gain on
termination of - (4,900) - (4,900)
agreement
Other 2 (2) 52 (2)
(1,109) (4,477) (834) (5,026)
Total $ (4,315) $ (7,527) $ (7,534) $ (6,509)
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For the three and nine months ended September 30, 2011, Provident
recognized other income of $2.1 million and $6.4 million, respectively,
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 balance
sheet 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.
18. 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.
(“Pace”) pursuant to a plan of arrangement under the Business
Corporations Act (Alberta) (the “Arrangement”) 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. 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 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 future 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.
Three months ended Nine months ended September
September 30, 30,
Net loss from
discontinued 2011 2010 2011 2010
operations
(000's)
Production
revenue, net of $ - $ - $ - $ 76,581
royalties
Loss from
discontinued - - - (112,702)
operations before
taxes
Loss on sale of
discontinued - (5,000) - (88,548)
operations
Current tax - - - (1)
expense
Future income tax - - - 69,770
recovery
Net loss from
discontinued $ - $ (5,000) $ - $ (131,481)
operations for
the period
Per unit
basic and diluted $ - $ (0.02) $ - $ (0.50)
(1)For the three and nine months ended September 30, 2010,
interest expense of nil and $2.5 million, respectively, 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.
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)Â Â Â Â Â Financial instrumentsÂ
Financial Assets
a)Â Â Â Â Â 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)Â Â Â Â Â 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, is 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)Â Â Â Â Â 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 income statement 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)Â Â Â Â Â 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)Â Â Â Â Â 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)Â Â Â Â Â 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.Â
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.
19. Subsequent events
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 acquisition was funded by
approximately $8 million in cash and 945,000 Provident shares as well
as $4 million of assumed bank debt and working capital. Provident will
retain the option to purchase the remaining one-third interest in Three
Star after three years from the closing date.
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SOURCE Provident Energy Ltd.
