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Pembina Pipeline Corporation announces fourth quarter and annual results

   Pembina Pipeline Corporation announces fourth quarter and annual results

PR Newswire

CALGARY, Mar. 1, 2013

Record adjusted EBITDA and adjusted cash flow from operating activities per
share

All financial figures are in Canadian dollars unless noted otherwise. This
report contains forward-looking statements and information that are based on
Pembina Pipeline Corporation's ("Pembina" or the "Company") current
expectations, estimates, projections and assumptions in light of its
experience and its perception of historic trends. Actual results may differ
materially from those expressed or implied by these forward-looking
statements. Please see "Forward-Looking Statements & Information" in the
accompanying Management's Discussion & Analysis ("MD&A") for more details.
This report also refers to financial measures that are not defined by
Generally Accepted Accounting Principles ("GAAP"). For more information about
the measures which are not defined by GAAP, see "Non-GAAP Measures" of the
accompanying MD&A.

CALGARY, Mar. 1, 2013 /PRNewswire/ - On April 2, 2012 Pembina completed its
acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The
amounts disclosed herein for the three and twelve month periods ending
December 31, 2012 reflect results of the post-Acquisition Pembina from April
2, 2012. together with results of Legacy Pembina excluding Provident ("Legacy
Pembina"), from January 1 through April 1, 2012, if applicable. The
comparative figures reflect solely the 2011 results of Legacy Pembina. For
further information with respect to the Acquisition, please refer to Note 5 of
the Consolidated Financial Statements for the year ended December 31, 2012.

Financial & Operating Overview

                                                                
                                   3 Months Ended
                                     December 31   12 Months Ended
($ millions, except where noted)     (unaudited)     December 31
                                  2012 2011 2012 2011
Revenue                               1,265.7      468.1    3,427.4    1,676.0
Operating margin^(1)                    222.1      105.9      676.2      417.1
Gross profit                            172.1       87.2      538.7      354.3
Earnings for the period                  81.3       45.0      225.0      165.7
Earnings per share - basic and           0.28 0.27       0.87 0.99
diluted (dollars)
Adjusted EBITDA^(1)                     199.0       88.2      590.1      368.6
Cash flow from operating                139.5       73.8      359.8      285.5
activities
Adjusted cash flow from operating       172.3       66.0      493.8      305.8
activities^(1)
Adjusted cash flow from operating        0.59 0.39       1.91 1.83
activities per share^(1)
Dividends declared                      118.4       65.4      417.6      261.2
Dividends per common share         0.41 0.39 1.61 1.56
(dollars)

^(1)Refer to "Non-GAAP Measures."

Fourth Quarter and Year End 2012 Financial Highlights

  *Consolidated operating margin during the fourth quarter of 2012 increased
    to $222.1 million compared to $105.9 million during the same period of the
    prior year. Full year operating margin totalled $676.2 million compared to
    $417.1 million in 2011. Both the 2012 fourth quarter and full year
    operating margin were the highest in the Company's history. Operating
    margin is a non-GAAP measure; see "Non-GAAP Measures."
  *During the fourth quarter of 2012, Pembina generated operating margin of
    $57.9 million from its Conventional Pipelines business, $29.6 million from
    Oil Sands & Heavy Oil and $14.4 million from Gas Services. For these three
    businesses, operating margin was positively impacted by increased volumes,
    as discussed below, and gas processed through Pembina's new Musreau deep
    cut facility. The Company's Midstream business also saw a significant
    increase in operating margin to $119.5 million, which includes results
    generated by the assets acquired through the Acquisition. The performance
    of Pembina's Midstream business was somewhat tempered by a continued soft
    NGL pricing environment. These softer prices resulted from excess industry
    inventory levels due to decreased propane demand, which was caused by the
    relatively warm 2011/12 winter across North America and a mild start to
    the 2012/2013 winter season.
  *For the full year of 2012, operating margin generated by Pembina's
    businesses was as follows: Conventional Pipelines increased to $209.3
    million compared to $181.5 million in 2011; Oil Sands & Heavy Oil
    contributed $116.8 million compared to $90.9 million during the prior
    year; Gas Services totalled $59 million for 2012 compared to $49.1 million
    in 2011; and Midstream's operating margin for 2012 was $288.5 million
    compared to $93.2 million in the previous year. The significant variance
    in Midstream's operating margin is primarily due to results generated by
    the acquired Provident assets.
  *Operationally, Pembina experienced one of the strongest years in its
    history. Conventional Pipelines transported an average of 456.3 mbpd in
    2012, 10 percent more than 2011 when average volumes were 413.9 mbpd.
    Notably, fourth quarter 2012 volumes in this business averaged 480.2 mbpd,
    an increase of almost 14 percent over the fourth quarter of 2011. Gas
    Services also saw an increase in volumes of 8 percent, with the Cutbank
    Complex processing an average of 275.2 MMcf/d during 2012 compared to
    253.8 MMcf/d in 2011.
  *The Company's earnings were $81.3 million ($0.28 per share) for the fourth
    quarter of 2012 compared to $45 million ($0.27 per share) for the fourth
    quarter of 2011. Earnings were $225 million ($0.87 per share) for the year
    ended December 31, 2012 compared to $165.7 million ($0.99 per share)
    during the same period of 2011. These increases were due to both the
    Acquisition as well as increased volumes transported and processed, as
    mentioned above, and were impacted by unrealized gains/losses on
    commodity-related derivative financial instruments. Per share metrics were
    also impacted by the Acquisition.
  *Pembina generated record adjusted EBITDA of $199 million during the fourth
    quarter of 2012 compared to $88.2 million during the fourth quarter of
    2011 (adjusted EBITDA is a non-GAAP measure; see "Non-GAAP Measures").
    Adjusted EBITDA for the year ended December 31, 2012 was $590.1 million
    compared to $368.6 million for 2011. The increase in quarterly and full
    year 2012 adjusted EBITDA was due to strong results from each of Pembina's
    legacy businesses, new assets and services having been brought on-stream,
    and the completion of the Acquisition.
  *Cash flow from operating activities was $139.5 million ($0.48 per share)
    for the fourth quarter of 2012 compared to $73.8 million ($0.44 per share)
    for the same period in 2011, and was $359.8 million ($1.39 per share) for
    the year ended December 31, 2012 compared to $285.5 million ($1.71 per
    share) during the prior year. These increases were primarily due to higher
    EBITDA, which was somewhat offset by acquisition-related expenses, higher
    interest expenses and an increase in working capital which was partially
    associated with the integration of Provident.
  *Adjusted cash flow from operating activities was a record $172.3 million
    ($0.59 per share) for the fourth quarter of 2012 compared to $66 million
    ($0.39 per share) for the fourth quarter of 2011 (adjusted cash flow from
    operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). For
    the full year, adjusted cash flow from operating activities was the
    highest in the Company's history at $493.8 million ($1.91 per share) in
    2012 compared to $305.8 million ($1.83 per share) in 2011.
  *As of April 2, 2012, following the close of the Acquisition, the Company
    increased its monthly dividend rate by 3.8 percent to $0.135 per share per
    month (or $1.62 annualized) from $0.13 per share per month (or $1.56
    annualized). This marks the ninth dividend increase since Pembina began
    trading publicly in 1997.

2012 Year in Review & Growth Update

2012 marked a pivotal year in Pembina's history. With the Acquisition of
Provident in April of 2012, Pembina launched a new chapter as a much larger,
more financially flexible and diversified company. With assets along the
majority of the liquids hydrocarbon value chain, Pembina is now a truly
integrated energy infrastructure company with the scale and scope necessary to
meet the growing needs of Canada's and North America's oil and gas industry.
The Acquisition provided for a stronger balance sheet, more robust cash flow
and the ability to strategically pursue larger, more complex growth projects.
Pembina is very well positioned from a geological perspective to capture the
broader range of opportunities resulting from the Acquisition.

Integration of Provident's assets, business processes and procedures is
substantially complete. Pembina is now operating on a single enterprise-wide
financial system and all staff are integrated within their respective
departments.

While the Acquisition has brought with it new opportunities, Pembina's core
focus remains unchanged: pursuing responsible growth, safe and reliable
operations, and delivering long-term and sustainable returns for our
shareholders. This is evident in the many growth-related accomplishments
Pembina achieved throughout the year, which we expect will provide attractive
cash flows in the years ahead:

  *Pembina has undertaken numerous expansions on its Conventional Pipeline
    systems to accommodate increased customer demand due to strong drilling
    results and increased field liquids extraction by producers in areas of
    Alberta including Dawson Creek, Grande Prairie, Kaybob and Fox Creek.

       *The expansion has been split into two phases. During the first phase,
         the Company completed a re-contracting initiative in 2012 on existing
         and new volumes on the Northern NGL System (the Peace and Northern
         pipelines) to underpin the system's Phase 1 NGL expansion.
       *The Company is nearing completion of the Phase 1 NGL expansion, which
         is expected to cost $30  million and add approximately 17 thousand
         barrels per day ("mbpd") of additional NGL capacity to the Northern
         NGL System in the second quarter of 2013. 
       *The Phase 1 Peace high vapour pressure ("HVP") expansion, which
         requires seven new or upgraded pump stations and associated pipeline
         reinforcement work from west of Fox Creek to Fort Saskatchewan, will
         add NGL capacity of approximately 35 mbpd. Pembina expects to
         commission three of the pump stations by August 2013, and the
         remaining four stations by October 2013 at an estimated cost of $70 
         million.
       *The Phase 1 low vapour pressure ("LVP") expansion requires three
         upgraded pump stations and associated pipeline reinforcement work
         between Fox Creek and Edmonton, Alberta, and will provide an
         additional 40 mbpd of crude oil and condensate capacity on this
         segment. Pembina expects to commission one of the three pump stations
         by June 2013, and the remaining two stations by October 2013 at an
         estimated cost of $30  million.

  *On February 13, 2013, Pembina announced that it had reached its
    contractual threshold to proceed with its previously announced plans to
    significantly expand its crude oil and condensate throughput capacity on
    its Peace Pipeline system by 55 mbpd ("Phase 2 LVP Expansion"):

       *The Phase 2 LVP Expansion is expected to accommodate increased
         producer crude oil and condensate volumes due to strong drilling
         results in the Dawson Creek, Grande Prairie and Kaybob/Fox Creek
         areas of Alberta. Pembina expects the total cost of the Phase 2 LVP
         Expansion to be approximately $250 million (including the mainline
         expansion and tie-ins). Subject to obtaining regulatory and
         environmental approvals, Pembina anticipates being able to bring the
         expansion into service by late-2014. Once complete, this expansion
         will increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd.
         The Phase 2 LVP Expansion is underpinned by long-term fee-for-service
         agreements with area producers. The combined LVP expansions will
         increase capacity by 61 percent from current levels.

  *The Company is actively working to accelerate the timing of its second
    previously announced NGL expansion (a portion of which is subject to
    reaching commercial arrangements with its customers and receipt of
    environmental and regulatory approvals):

       *The Phase 2 NGL Expansion to the Company's Northern NGL System will
         increase capacity from 167 mbpd to 220 mbpd. Pembina expects this
         expansion to cost approximately $415 million (including the mainline
         expansion and tie-ins) and to be complete in early to mid-2015.

  *In addition, in 2012:

       *Pembina completed and brought into service two expansions at its
         existing Gas Services assets at its Cutbank Complex - the 205 MMcf/d
         Musreau deep cut and the 50 MMcf/d Musreau shallow cut expansion;
       *Pembina entered into a long-term arrangement for the remaining 50
         MMcf/d of capacity at its Saturn liquids extraction facility,
         bringing total contracted capacity to 100 percent;
       *Pembina received the required environmental and regulatory approvals,
         and awarded construction contracts, for the pipeline portions of the
         Resthaven and Saturn projects and began construction on both during
         the fall and winter of 2012/2013;
       *Pembina successfully completed and commissioned an 8,000 bpd
         expansion at its Redwater fractionator on schedule and under budget
         in September 2012;
       *Pembina increased the capacity of its Drayton Valley pipeline (which
         serves the Cardium play) from 145 mbpd to 195 mbpd by refurbishing an
         existing pump station;
       *The Company began construction on a joint venture full-service
         terminal in the Judy Creek, Alberta area which has an estimated
         project completion date of April 2013; and,
       *In September of 2012, Pembina brought the first of seven
         fee-for-service caverns into service at its Redwater site. Three
         additional caverns are completed and Pembina is in the process of
         preparing them for service. Pembina expects to be able to bring two
         caverns into service in March 2013, and the third cavern into service
         in June 2013.

  *Pembina continues to advance preliminary engineering and work on its
    proposed 73 mbpd ethane plus fractionator at its Redwater site and is
    soliciting customer support for the project.
  *The Company is investigating offshore propane export opportunities that
    would allow it to leverage its existing assets and provide a solution for
    Canadian producers.

Pembina also secured financing in 2012 to support its long-term objectives.
The Company increased its credit facility from $800 million prior to closing
of the Acquisition to $1.5 billion post-close. This, along with the offering
of $450 million of 10-year senior unsecured medium-term notes due 2022 with an
annual interest rate of 3.77%, which closed in October, provides Pembina
increased flexibility to pursue its capital plans.

"2012 was a very successful year for Pembina. We delivered steady operational
and financial results, increased our dividend and made substantial progress on
a number of capital projects across our business to support our customers and
help secure returns for our investors," said Bob Michaleski, Pembina's Chief
Executive Officer. "With the integration of Provident substantially complete,
we are looking to the future and are excited to grow in ways that would not
have been possible on a stand-alone basis. 2013 will be about demonstrating
the benefits of our fully integrated platform post-Acquisition, and we've
kicked the year off on the right foot with our recent announcement to proceed
with our Phase 2 LVP Expansion."

"Our approved 2013 capital spending plan is the largest in the Company's
history - totalling $965 million - and we are confident in our ability to
execute on it," added Michaleski. "Including the 2013 capital spending plan,
we have approximately $4 billion in unrisked growth opportunities which are in
line with our core strengths. Our team will be focused on achieving
disciplined growth and securing projects with the most attractive cash flows
and return on capital, all while minimizing overall risk."

Mick Dilger, Pembina's President and Chief Operating Officer commented on
Pembina's operational, safety and environmental performance during the past
year: "2012 was a very successful year in terms of continuing to offer safe
and reliable services. We exited the year with improved overall safety
performance metrics compared to 2011, which is in part due to the initiation
of a safety culture improvement project alongside our robust integrity
management program. For 2013 and beyond, Pembina remains committed to being
the industry neighbour of choice. That means our people are highly committed
to doing the right thing each and every day and are focused on reliability, no
harm to the environment and personal safety."

2012 Online Annual Report

Pembina has published an online annual report on its website at
www.pembina.com under "Investor Centre" which is supplementary to its annual
management's discussion and analysis, financial statements and notes. This
interactive report includes an overview of 2012 results, as well as videos
featuring Pembina's senior executives as they discuss the Company's future
prospects.

While the online annual report will not be printed, investors and other
stakeholders may obtain a hard copy of Pembina's annual management's
discussion and analysis, financial statements and notes by mail by contacting
Investor Relations at investor-relations@pembina.com.

Conference Call & Webcast

Pembina will host a conference call on March 4, 2013 at 8 a.m. MT (10 a.m. ET)
to discuss details related to the 2012 fourth quarter and full year. The
conference call dial in numbers for Canada and the U.S. are 647-427-7450 or
888-231-8191. A live webcast of the conference call can be accessed on
Pembina's website under "Investor Centre - Presentation & Events," or by
entering
http://event.on24.com/r.htm?e=570212&s=1&k=126357DBB613EBB2DF3D9565F6C32327 in
your web browser.

Hedging Information

Pembina has posted updated hedging information on its website,
www.pembina.com, under "Investor Centre - Hedging".

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis ("MD&A") of the financial
and operating results of Pembina Pipeline Corporation ("Pembina" or the
"Company") is dated March 1, 2013 and is supplementary to, and should be read
in conjunction with, Pembina's audited consolidated annual financial
statements for the years ended December 31, 2012 and 2011 ("Consolidated
Financial Statements"). All dollar amounts contained in this MD&A are
expressed in Canadian dollars unless otherwise noted.

Management is responsible for preparing the MD&A. This MD&A has been reviewed
and recommended by the Audit Committee of Pembina's Board of Directors and
approved by its Board of Directors.

This MD&A contains forward-looking statements (see "Forward-Looking Statements
& Information") and refers to financial measures that are not defined by
Generally Accepted Accounting Principles ("GAAP"). For more information about
the measures which are not defined by GAAP, see "Non-GAAP Measures."

On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd.
("Provident") (the "Acquisition"). The amounts disclosed herein for the three
and twelve month periods ending December 31, 2012 reflect results of the
post-Acquisition Pembina from April 2, 2012 together with results of legacy
Pembina excluding Provident ("Legacy Pembina"), from January 1 through April
1, 2012, if applicable. The comparative figures reflect solely the 2011
results of Legacy Pembina. The results of the business acquired through the
Acquisition are reported as part of the Company's Midstream business. For
further information with respect to the Acquisition, please refer to Note 5 of
the Consolidated Financial Statements for the year ended December 31, 2012.

About Pembina

Calgary-based Pembina Pipeline Corporation is a leading transportation and
midstream service provider that has been serving North America's energy
industry for nearly 60 years. Pembina owns and operates: pipelines that
transport conventional and synthetic crude oil and natural gas liquids
produced in western Canada; oil sands, heavy oil and diluent pipelines; gas
gathering and processing facilities; and, an oil and natural gas liquids
infrastructure and logistics business. With facilities strategically located
in western Canada and in natural gas liquids markets in eastern Canada and the
U.S., Pembina also offers a full spectrum of midstream and marketing services
that spans across its operations. Pembina's integrated assets and commercial
operations enable it to offer services needed by the energy sector along the
hydrocarbon value chain.

Pembina is a trusted member of the communities in which it operates and is
committed to generating value for its investors by running its businesses in a
safe, environmentally responsible manner that is respectful of community
stakeholders.

Strategy

Pembina's goal is to provide highly competitive and reliable returns to
investors through monthly dividends while enhancing the long-term value of its
shares. To achieve this, Pembina's strategy is to:

  *Preserve value by providing safe, responsible, cost-effective and reliable
    services;
  *Diversify Pembina's asset base along the hydrocarbon value chain by
    providing integrated service offerings which enhance profitability;
  *Pursue projects or assets that are expected to generate increased cash
    flow per share and capture long-life, economic hydrocarbon reserves; and
  *Maintain a strong balance sheet through the application of prudent
    financial management to all business decisions.

Pembina is structured into four businesses: Conventional Pipelines, Oil Sands
& Heavy Oil, Gas Services and Midstream, which are described in their
respective sections of this MD&A.

Common Abbreviations

The following is a list of abbreviations that may be used in this MD&A:

Measurement                       Other  
bbl        barrel                 AECO  Alberta gas trading price
mmbbls     millions of barrels    AESO  Alberta Electric Systems Operator
bpd        barrels per day        B.C.  British Columbia
mbpd       thousands of barrels   DRIP  Premium Dividend™ and Dividend
            per day                         Reinvestment Plan
mboe/d     thousands of barrels   Frac  Fractionation
            of oil equivalent
            per day
MMcf/d     millions of cubic      IFRS  International Financial Reporting
            feet per day                    Standards
bcf/d      billions of cubic      NGL   Natural gas liquids
            feet per day
MW/h       megawatts per hour     NYMEX New York Mercantile Exchange
GJ         gigajoule              NYSE  New York Stock Exchange
km         kilometre              TET   Indicates product in the Texas
                                            Eastern Products Pipeline at Mont
                                            Belvieu, Texas (Non-TET refers to
                                            product in a location at Mont
                                            Belvieu other than in the Texas
                                            Eastern Products pipeline)
                                 TSX   Toronto Stock Exchange
                                 U.S.  United States
                                 WCSB  Western Canadian Sedimentary Basin
                                 WTI   West Texas Intermediate (crude oil
                                            benchmark price)

Financial & Operating Overview

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except where noted)   2012 2011 2012 2011
Average throughput - Conventional       480.2      422.8      456.3      413.9
Pipelines (mbpd)
Contracted capacity - Oil Sands &       870.0      870.0      870.0      870.0
Heavy Oil (mbpd)
Average processing volume - Gas          46.0       45.3       45.9       42.3
Services (mboe/d) net to
Pembina^(1)
NGL sales volume - NGL Midstream        115.8             97.7^(3)          
(mbpd)
Revenue                               1,265.7      468.1    3,427.4    1,676.0
Operations                               86.0       55.1      271.6      191.9
Cost of goods sold, including           968.6      308.0    2,475.0    1,072.3
product purchases
Realized gain (loss) on                  11.0        0.9      (4.6)        5.3
commodity-related derivative
financial instruments
Operating margin^(2)                    222.1      105.9      676.2      417.1
Depreciation and amortization            47.8       19.6      173.6       68.0
included in operations
Unrealized gain (loss) on               (2.2)        0.9       36.1        5.2
commodity-related derivative
financial instruments
Gross profit                            172.1       87.2      538.7      354.3
Deduct/(add)                                                              
    General and administrative          27.3       21.0       97.5       62.2
     expenses
    Acquisition-related and other        0.5        0.8       24.7        1.4
     expense
    Net finance costs                   35.7       22.1      115.1       91.9
    Share of loss (profit) of            0.2      (1.5)        1.1      (5.8)
     investments in equity
     accounted investee,
     net of tax
Income tax expense (reduction)           27.1      (0.2)       75.3       38.9
Earnings for the period                  81.3       45.0      225.0      165.7
Earnings per share - basic and           0.28       0.27       0.87       0.99
diluted (dollars)
Adjusted earnings^(2)                   115.8       43.7      283.7      208.9
Adjusted earnings per share^(2)          0.40       0.26       1.10       1.25
Adjusted EBITDA^(2)                     199.0       88.2      590.1      368.6
Cash flow from operating                139.5       73.8      359.8      285.5
activities
Cash flow from operating                 0.48       0.44       1.39       1.71
activities per share
Adjusted cash flow from operating       172.3       66.0      493.8      305.8
activities^(2)
Adjusted cash flow from operating        0.59       0.39       1.91       1.83
activities per share^(2)
Dividends declared                      118.4       65.4      417.6      261.2
Dividends per common share               0.41       0.39       1.61       1.56
(dollars)
Capital expenditures                    254.7      148.9      584.3      527.6
Total enterprise value ($                11.0        6.6       11.0        6.6
billions) ^(2)
Total assets ($ billions)                 8.3        3.3        8.3        3.3

^(1)Gas Services processing volumes converted to mboe/d from MMcf/d at 6:1
ratio.
^(2)Refer to "Non-GAAP Measures."
^(3)Represents per day volumes since the closing of the Acquisition.

Revenue, net of cost of goods sold, increased over 85 percent to $297.1
million during the fourth quarter of 2012 from $160.1 million during the same
period of 2011. Full year revenue, net of cost of goods sold, in 2012 was
$952.4 million compared to $603.7 million in 2011. Revenue was higher in 2012
than the comparative periods in 2011 primarily due to the addition of results
generated by the assets acquired through the Acquisition, which are reported
in the Company's Midstream business, as well as improved performance in each
of Pembina's legacy businesses, as discussed in further detail below.

Operating expenses were $86 million during the fourth quarter and $271.6
million for the full year in 2012 compared to $55.1 million and $191.9 million
during the same periods in 2011. The increases were primarily due to
additional costs associated with the growth in Pembina's asset base since the
Acquisition and higher variable costs in each of the Company's businesses
because of increased volumes.

Operating margin was $222.1 million during the fourth quarter, up almost 110
percent from the same period last year when operating margin totalled $105.9
million (operating margin is a Non-GAAP measure; see "Non-GAAP Measures"). For
the year ended December 31, 2012, operating margin was $676.2 million compared
to $417.1 million for the full year of 2011. These increases were primarily
due to higher revenue, as discussed above.

Realized and unrealized gains/losses on commodity-related derivative financial
instruments resulting from Pembina's market risk management program are
primarily related to outstanding positions acquired on the closing of the
Acquisition (see "Market Risk Management Program" and Note 27 to the
Consolidated Financial Statements). The unrealized gain on commodity-related
derivative financial instruments was $36.1 million for 2012 reflecting changes
in the future NGL and natural gas price indices between April 2, 2012 and
December 31, 2012 (see "Business Environment").

Depreciation and amortization (operational) increased to $47.8 million during
the fourth quarter of 2012 compared to $19.6 million during the same period in
2011 and $173.6 million for the year ended December 31, 2012 compared to $68
million in 2011. Both the quarterly and full year increases reflect
depreciation on new capital additions including those assets acquired through
the Acquisition.

The increases in revenue and operating margin contributed to gross profit of
$172.1 million during the fourth quarter and $538.7 million for the full year
of 2012 compared to $87.2 million and $354.3 million for the same periods of
2011.

General and administrative expenses ("G&A") of $27.3 million were incurred
during the fourth quarter of 2012 compared to $21 million during the fourth
quarter of 2011. The increase, year-over-year, for the three month period was
mainly due to the addition of employees who joined Pembina through the
Acquisition, an increase in salaries and benefits for existing and new
employees, and increased rent for expanded office space. Full year 2012 G&A
totaled $97.5 million compared to $62.2 million incurred during 2011. The
primary driver of the year-over-year increase in G&A was a $19.8 million
increase in salaries, benefits and consulting costs, $3 million increase in
rent and $3.6 million in corporate depreciation. In addition, every $1 change
in share price is expected to change Pembina's annual share-based incentive
expense by $1.2 million.

Pembina generated adjusted EBITDA of $199 million during the fourth quarter of
2012 compared to $88.2 million during the fourth quarter of 2011 (adjusted
EBITDA is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for
the full year of 2012 was $590.1 million compared to $368.6 million in 2011.
The increase in quarterly and full year adjusted EBITDA was due to strong
results from each of Pembina's legacy businesses, new assets and services
having been brought on-stream, and the growth of Pembina's operations since
completion of the Acquisition.

The Company's earnings were $81.3 million ($0.28 per share) during the fourth
quarter of 2012 compared to $45 million ($0.27 per share) during the fourth
quarter of 2011 and $225 million ($0.87 per share) for the full year of 2012
compared to $165.7 million ($0.99 per share) in 2011. These increases were the
result of the Acquisition of Provident as well as improved performance in each
of the Company's legacy businesses. Per share metrics were also impacted by
the Acquisition.

Adjusted earnings were $115.8 million ($0.40 per share) during the fourth
quarter of 2012 compared to $43.7 million ($0.26 per share) during the fourth
quarter of 2011 (adjusted earnings is a Non-GAAP measure; see "Non-GAAP
Measures"). For the full year of 2012, adjusted earnings totalled $283.7
million ($1.10 per share) compared to $208.9 million ($1.25 per share) in
2011. The increases in adjusted earnings were primarily due to higher
operating margin, as discussed above, which was partially offset by increased
depreciation and amortization (operational) resulting from a larger asset
base, and higher G&A and finance costs.

Cash flow from operating activities was $139.5 million ($0.48 per share)
during the fourth quarter of 2012 and $359.8 million ($1.39 per share) for the
full year in 2012 compared to $73.8 million ($0.44 per share) and $285.5
million ($1.71 per share), respectively, for the comparative periods of 2011.
The increases in cash flow from operating activities was primarily due to an
increase in adjusted EBITDA, which was somewhat offset by acquisition-related
expenses, higher interest expenses and an increase in working capital, which
was partially associated with the integration of Provident.

Adjusted cash flow from operating activities was $172.3 million ($0.59 per
share) during the fourth quarter of 2012, an increase of more than 160
percent, compared to $66.0 million ($0.39 per share) during the fourth quarter
of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure;
see "Non-GAAP Measures"). Adjusted cash flow from operating activities was a
record $493.8 million ($1.91 per share) during 2012 compared to $305.8 million
($1.83 per share) during 2011 and was largely driven by strong performance in
each of Pembina's businesses.

Operating Results

                                                                                      
                        3 Months Ended
                           December 31                           12 Months Ended
                           (unaudited)                             December 31
                  2012             2011             2012             2011
               Net  Operating   Net  Operating   Net  Operating   Net  Operating
($ millions) Revenue^(1) Margin^(2) Revenue^(1) Margin^(2) Revenue^(1) Margin^(2) Revenue^(1) Margin^(2)
Conventional        99.2       57.9        75.8       41.6       338.8      209.3       296.2      181.5
Pipelines
Oil Sands &         45.8       29.6        39.7       27.3       172.4      116.8       134.9       90.9
Heavy Oil
Gas Services        23.3       14.4        19.1       13.0        88.3       59.0        71.5       49.1
Midstream          128.8      119.5        25.5       23.4   352.9^(3)  288.5^(3)       101.1       93.2
Corporate                      0.7                   0.6                   2.6                   2.4
Total              297.1      222.1       160.1      105.9       952.4      676.2       603.7      417.1

^(1) Midstream revenue is net of $975 million in cost of goods sold,
      including product purchases, for the quarter ended December 31, 2012
      (quarter ended December 31, 2011: $308 million) and $2,494.5 million in
      cost of goods sold, including product purchases, for the twelve months
      ended December 31, 2012 (twelve months ended December 31, 2011: $1,072.3
      million).
^(2) Refer to "Non-GAAP Measures."
^(3) Includes results from operations generated by the acquired assets from
      Provident since closing of the Acquisition on April 2, 2012.

Conventional Pipelines

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except where noted)   2012 2011 2012 2011
Average throughput (mbpd)               480.2      422.8      456.3      413.9
Revenue                                  99.2       75.8      338.8      296.2
Operations                               42.1       35.5      129.6      119.1
Realized gain on commodity-related        0.8        1.3        0.1        4.4
derivative financial instruments
Operating margin^(1)                     57.9       41.6      209.3      181.5
Depreciation and amortization             7.8       11.1       44.0       41.6
included in operations
Unrealized gain (loss) on                 0.8      (0.9)      (9.0)        3.7
commodity-related derivative
financial instruments
Gross profit                             50.9       29.6      156.3      143.6
Capital expenditures                     88.1       24.9      187.3       72.0

^(1)Refer to "Non-GAAP Measures."

Business Overview

Pembina's Conventional Pipelines business comprises a well-maintained and
strategically located 7,850 km pipeline network that extends across much of
Alberta and B.C. It transports approximately half of Alberta's conventional
crude oil production, about thirty percent of the NGL produced in western
Canada, and virtually all of the conventional oil and condensate produced in
B.C. This business' primary objective is to generate sustainable operating
margin while pursuing opportunities for increased throughput and revenue.
Conventional Pipelines endeavours to maintain and/or improve operating margin
by capturing incremental volumes, expanding its pipeline systems, managing
revenue and following a disciplined approach to its operating expenses.

Operational Performance: Throughput

During the fourth quarter of 2012, Conventional Pipelines' throughput averaged
480.2 mbpd, consisting of an average of 352.5 mbpd of crude oil and condensate
and 127.7 mbpd of NGL. This was primarily due to continued production growth
from regional resource plays in the Cardium (oil), Deep Basin Cretaceous
(NGL), Montney (oil/NGL) and Beaverhill Lake (oil) formations and represents
an increase of 14 percent compared to the same period of 2011, when average
throughput was 422.8 mbpd. Producer production growth also contributed to a 10
percent increase in throughput for the full year of 2012 compared to 2011.

Financial Performance

During the fourth quarter of 2012, Conventional Pipelines generated revenue of
$99.2 million compared to $75.8 million in the same quarter of the previous
year. For 2012, revenue was $338.8 million compared to $296.2 million during
2011. The 31 and 14 percent increases during the respective 2012 periods were
primarily due to strong volumes generated by newly connected facilities on
Pembina's Conventional Pipelines systems, as well as many deliveries being
received at higher toll locations along the Company's pipeline network.

Quarterly operating expenses increased to $42.1 million compared to $35.5
million in the fourth quarter of 2011 due to higher variable costs associated
with increased throughput as well as integrity and geotechnical expenditures.
Operating expenses for 2012 increased to $129.6 million from $119.1 million in
the same period last year. This nine percent year-over-year increase was
because of the same factors that impacted quarterly operating expenses.

As a result of higher revenue, operating margin for the fourth quarter of 2012
was $57.9 million compared to $41.6 million during the same period of 2011.
Full year revenue in 2012, which was offset slightly by an increase in
operating expenses, increased to $209.3 million compared to $181.5 million for
2011.

Depreciation and amortization included in operations was $7.8 million during
the fourth quarter of 2012 compared to $11.1 million during the fourth quarter
of 2011. This decrease is due to a credit made to depreciation because of a
re-measurement reduction in the decommissioning provision in excess of the
carrying amount of the related asset. Depreciation and amortization included
in operations for the year ended December 31, 2012 was $44 million, up from
$41.6 million in 2011 due to capital additions.

For the three months ended December 31, 2012, Pembina recognized an unrealized
gain on commodity-related derivative financial instruments of $0.8 million
compared to an unrealized loss of $0.9 million in the fourth quarter of 2011.
For the full year of 2012, Pembina recognized an unrealized loss on
commodity-related derivative financial instruments of $9 million compared to
an unrealized gain of $3.7 million for 2011. The 2012 unrealized loss is the
result of Pembina's forward fixed-price power purchase program which is
designed to mitigate operating costs fluctuations.

For the three and twelve months ended December 31, 2012, gross profit was
$50.9 million and $156.3 million, respectively, compared to $29.6 million and
$143.6 million, respectively, during the same periods in 2011. Higher
operating margin in 2012 was partially offset by increased depreciation and
amortization and unrealized losses on commodity-related derivative financial
instruments.

Capital expenditures for the fourth quarter of 2012 totalled $88.1 million
compared to $24.9 million during the fourth quarter of 2011, and were $187.3
million during the year compared to $72 million in 2011. The majority of the
spending in 2012 related to the expansion of certain pipeline assets as
described below.

New Developments: Conventional Pipelines

During 2012, Pembina saw increased volumes on its Conventional Pipelines due
to the continued revitalization of many of the plays near its systems. The
trend towards increased exploration, drilling and production in the WCSB has
escalated over the past several years, with plays such as the Alberta Deep
Basin, Cardium, Montney, Swan Hills and Duvernay being further developed by
producers and offering improved recoveries with the use of innovative
technology. Some of these plays were once considered mature or unviable, and
others were relatively unexplored; by using horizontal drilling and
multi-stage hydraulic fracturing technology, these tight and previously
uneconomic portions of reservoirs began to represent attractive opportunities.
For Pembina, this producer activity has meant an increase in crude oil and NGL
volumes transported on its Conventional Pipeline systems and the need to
complete expansions of select segments to accommodate customer demand.

  *Pembina is pursuing numerous expansions on its Conventional Pipeline
    systems to accommodate the increased customer demand mentioned above in
    areas of Alberta including Dawson Creek, Grande Prairie, Kaybob and Fox
    Creek.

       *The expansion has been split into two phases. During the first phase,
         the Company completed a re-contracting initiative in 2012 on existing
         and new volumes on the Northern NGL System (the Peace and Northern
         pipelines) to underpin the system's Phase 1 NGL expansion.
       *The Company is nearing completion of the Phase 1 NGL expansion, which
         is expected to cost $30 million and add approximately 17 mbpd of
         additional NGL capacity to the Northern NGL System in the second
         quarter of 2013. 
       *The Phase 1 Peace high vapour pressure ("HVP") expansion, which
         requires seven new or upgraded pump stations and associated pipeline
         reinforcement work from west of Fox Creek to Fort Saskatchewan, will
         add NGL capacity of approximately 35 mbpd. Pembina expects to
         commission three of the pump stations by August 2013, and the
         remaining four stations by October 2013 at an estimated cost of $70
         million.
       *The Phase 1 Peace low vapour pressure ("LVP") expansion requires
         three upgraded pump stations and associated pipeline reinforcement
         work between Fox Creek and Edmonton, Alberta, and will provide an
         additional 40 mbpd of crude oil and condensate capacity on this
         segment. Pembina expects to commission one of the three pump stations
         by June 2013, and the remaining two stations by October 2013 at an
         estimated cost of $30 million.

  *On February 13, 2013, Pembina announced that it had reached its
    contractual threshold to proceed with its previously announced plans to
    significantly expand its crude oil and condensate throughput capacity on
    its Peace Pipeline system by 55 mbpd ("Phase 2 LVP Expansion"):

       *The Phase 2 LVP Expansion is expected to accommodate increased
         producer crude oil and condensate volumes due to strong drilling
         results in the Dawson Creek, Grande Prairie and Kaybob/Fox Creek
         areas of Alberta. Pembina expects the total cost of the Phase 2 LVP
         Expansion to be approximately $250 million (including the mainline
         expansion and tie-ins). Subject to obtaining regulatory and
         environmental approvals, Pembina anticipates being able to bring the
         expansion into service by late-2014. Once complete, this expansion
         will increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd.
         The Phase 2 LVP Expansion is underpinned by long-term fee-for-service
         agreements with area producers. The combined LVP expansions will
         increase capacity by 61 percent from current levels.

  *The Company is actively working to accelerate the timing of its second
    previously announced NGL expansion (a portion of which is subject to
    reaching commercial arrangements with its customers and receipt of
    environmental and regulatory approvals):

       *The Phase 2 NGL Expansion to the Company's Northern NGL System will
         increase capacity from 167 mbpd to 220 mbpd. Pembina expects this
         expansion to cost approximately $415 million (including the mainline
         expansion and tie-ins) and to be complete in early to mid-2015.

  *Conventional Pipelines is also constructing the pipeline components of the
    Company's Saturn and Resthaven gas plant projects. These two pipeline
    projects will gather NGL from the gas plants for delivery to Pembina's
    Peace Pipeline system. Pembina has received the required environmental and
    regulatory approvals, has awarded construction contracts and has begun
    construction on both projects.

Oil Sands & Heavy Oil

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except where noted)   2012 2011 2012 2011
Capacity under contract (mbpd)          870.0      870.0      870.0      870.0
Revenue                                  45.8       39.7      172.4      134.9
Operations                               16.2       12.4       55.6       44.0
Operating margin^(1)                     29.6       27.3      116.8       90.9
Depreciation and amortization             5.0        4.9       19.8       12.8
included in operations
Gross profit                             24.6       22.4       97.0       78.1
Capital expenditures                     18.3       47.8       30.4      191.7

^(1)Refer to "Non-GAAP Measures."

Business Overview

Pembina plays an important role in supporting Alberta's oil sands and heavy
oil industry. Pembina is the sole transporter of crude oil for Syncrude Canada
Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources Ltd.'s Horizon
Oil Sands operation (via the Horizon Pipeline) to delivery points near
Edmonton, Alberta. Pembina also owns and operates the Nipisi and Mitsue
Pipelines, which provide transportation for producers operating in the Pelican
Lake and Peace River heavy oil regions of Alberta, and the Cheecham Lateral
which transports synthetic crude to oil sands producers operating southeast of
Fort McMurray, Alberta. The Oil Sands & Heavy Oil business operates
approximately 1,650 km of pipeline and has 870 mbpd of capacity under
long-term, extendible contracts which provide for the flow-through of
operating expenses to customers. As a result, operating margin from this
business is proportionate to the amount of capital invested and is
predominantly not sensitive to fluctuations in operating expenses or actual
throughput.

Financial Performance

The Oil Sands & Heavy Oil business realized revenue of $45.8 million in the
fourth quarter of 2012 compared to $39.7 million in the fourth quarter of
2011. This 15 percent increase is primarily due to higher flow-through
operating expenses as well as higher operating margin from the Syncrude and
Nipisi pipelines. Full year revenue in 2012 was $172.4 million compared to
$134.9 million for 2011, largely because of contributions from the Nipisi and
Mitsue pipelines which were placed into service in June and July of 2011.

Operating expenses in Pembina's Oil Sands & Heavy Oil business were $16.2
million during the fourth quarter of 2012 compared to $12.4 million during the
fourth quarter of 2011, and $55.6 million for the full year of 2012 compared
to $44 million in 2011. These increases primarily reflect additional operating
expenses related to higher volumes being transported on the Nipisi and Mitsue
pipelines compared to the same periods of the prior year.

For the three and twelve months ended December 31, 2012, operating margin
increased to $29.6 million and $116.8 million compared to $27.3 million and
$90.9 million, respectively, during the same periods in 2011. This is
primarily due to incremental contribution from the Nipisi and Mitsue
pipelines.

Depreciation and amortization included in operations for the fourth quarter of
2012 totalled $5 million compared to $4.9 million during the same period of
the prior year, and $19.8 million for the twelve months of 2012 compared to
$12.8 million during 2011. These increases primarily reflect the additional
Nipisi and Mitsue depreciation and amortization included in operations.

For the three and twelve months ended December 31, 2012, gross profit was
$24.6 million and $97 million, primarily due to higher operating margin as
discussed above, compared to $22.4 million and $78.1 million, respectively,
during the same periods of 2011.

For the year ended December 31, 2012, capital expenditures within the Oil
Sands & Heavy Oil business totalled $30.4 million and were primarily related
to Nipisi and Mitsue post-construction clean-up costs and the construction of
additional pump stations on these pipelines. This compares to $191.7 million
spent during the same period in 2011, the majority of which related to
completing the two projects.

New Developments: Oil Sands & Heavy Oil

In 2013, Pembina plans to spend approximately $45 million to increase capacity
on the Nipisi and Mitsue pipelines by 12 mbpd and 4 mbpd, respectively, while
also increasing connectivity in the Edmonton area.

Pembina continues to actively work with customers on oil sands and heavy oil
related solutions. With the Acquisition of Provident, the Company has
increased its access to diluent supply and can offer customers condensate and
butane products from various sources including Pembina's conventional pipeline
systems, the Redwater fractionator, rail imports and truck racks.

Gas Services

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except where noted)   2012 2011 2012 2011
Average processing volume (MMcf/d)      276.0      271.5      275.2      253.8
net to Pembina
Average processing volume (mboe/d)       46.0       45.3       45.9       42.3
^(1) net to Pembina
Revenue                                  23.3       19.1       88.3       71.5
Operations                                8.9        6.1       29.3       22.4
Operating margin^(2)                     14.4       13.0       59.0       49.1
Depreciation and amortization             3.7        2.6       14.5        9.9
included in operations
Gross profit                             10.7       10.4       44.5       39.2
Capital expenditures                     77.2       66.4      162.8      136.5

^(1)Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio.
^(2)Refer to "Non-GAAP Measures."

Business Overview

Pembina's operations include a growing natural gas gathering and processing
business. Located approximately 100 km south of Grande Prairie, Alberta,
Pembina's key revenue-generating Gas Services assets form the Cutbank Complex
which comprises three sweet gas processing plants with 425 MMcf/d of
processing capacity (368 MMcf/d net to Pembina), a 205 MMcf/d ethane plus
extraction facility, as well as approximately 350 km of gathering pipelines.
The Cutbank Complex is connected to Pembina's Peace Pipeline system and serves
an active exploration and production area in the WCSB. Pembina has initiated
construction on two projects in its Gas Services business, the Saturn and
Resthaven enhanced NGL extraction facilities, to meet the growing needs of
producers in west central Alberta.

Financial Performance

Gas Services recorded an increase in revenue of 22 percent during the fourth
quarter of 2012, contributing $23.3 million compared to $19.1 million in the
fourth quarter of 2011. For the full year of 2012, revenue was $88.3 million
compared to $71.5 million in 2011. These increases primarily reflect higher
processing volumes at Pembina's Cutbank Complex. Average processing volumes,
net to Pembina, were 276 MMcf/d during the fourth quarter of 2012,
approximately 2 percent higher than the 271.5 MMcf/d processed during the
fourth quarter of the previous year. Full year volumes averaged 275.2 MMcf/d,
up approximately 8 percent from 2011 when average volumes were 253.8 MMcf/d.

During the fourth quarter of 2012, operating expenses were $8.9 million
compared to $6.1 million incurred in the fourth quarter of 2011. Full year
operating expenses in 2012 totalled $29.3 million, up from $22.4 million
during the prior year. The quarterly and full year increases were mainly due
to variable costs incurred to process higher volumes at the Cutbank Complex as
well as additional costs associated with running the Musreau shallow cut
expansion and deep cut facilities.

As a result of processing higher volumes at the Cutbank Complex and additional
processing associated with the Musreau deep cut facility, Gas Services
realized operating margin of $14.4 million in the fourth quarter compared to
$13 million during the same period of the prior year. On a full year basis,
Gas Services generated $59 million in operating margin in 2012 compared to
$49.1 million in 2011. Of the $9.9 million increase, the Musreau deep cut
facility contributed $6.7 million.

Depreciation and amortization included in operations during the fourth quarter
of 2012 totalled $3.7 million, up from $2.6 million during the same period of
the prior year, primarily due to higher in-service capital balances from
additions to the Cutbank Complex (including the Musreau feep cut facility and
shallow cut expansion). For the same reason, depreciation and amortization
included in operations totalled $14.5 million in 2012 compared to $9.9 million
in 2011.

For the three months ended December 31, 2012, gross profit was $10.7 million
compared to $10.4 million in the same period of 2011, and was $44.5 million
for the full year of 2012 compared to $39.2 million in 2011. These increases
reflect higher operating margin during the periods which was partially offset
by increased depreciation and amortization included in operations as discussed
above.

For the year ended December 31, 2012, capital expenditures within Gas Services
totalled $162.8 million compared to $136.5 million during the same period of
2011. This increase was because of the spending required to complete the
Musreau deep cut facility, the expansion of the shallow cut facility at the
Cutbank Complex as well as capital expenditures incurred to progress the
Saturn and Resthaven enhanced NGL extraction facilities.

New Developments: Gas Services

Pembina continues to see significant growth opportunities resulting from the
trend towards liquids-rich natural gas drilling and the extraction of valuable
NGL from natural gas in the WCSB. Pembina expects the expansions detailed
below (some of which were completed in 2012) to bring the Company's Gas
Service's processing capacity to 903 MMcf/d (net). This includes enhanced NGL
extraction capacity of approximately 535 MMcf/d (net). These volumes would be
processed on a contracted, fee-for-service basis and are expected to result in
approximately 45 mbpd of incremental NGL to be transported for additional toll
revenue on Pembina's conventional pipelines by early 2014.

During the year, Pembina completed two expansions at its Musreau gas plant,
part of the Cutbank Complex: the 205 MMcf/d enhanced NGL extraction deep cut
facility and the 50 MMcf/d shallow cut expansion. With these two expansions in
place, the Cutbank Complex now has an aggregate raw shallow gas processing
capacity of 425 MMcf/d (368 MMcf/d net to Pembina), an increase of 13 percent
net to Pembina.

Pembina's Gas Services business is also constructing two new fully contracted
facilities and associated infrastructure: the Saturn facility - a $200 million
200 MMcf/d enhanced NGL extraction facility (includes conventional pipeline
tie-ins) in the Berland area of west central Alberta; and, the Resthaven
facility - a $230 million 200 MMcf/d combined shallow cut and deep cut NGL
extraction facility (includes conventional pipeline tie-ins) in the Resthaven,
Alberta area.

Pembina expects the Saturn facility and associated pipelines to be in service
in the fourth quarter of 2013. Once operational, Pembina expects the Saturn
facility will have the capacity to extract up to 13.5 mbpd of NGL.

For the Resthaven facility, Pembina is modifying and expanding an existing gas
plant, and is constructing a pipeline to transport the extracted NGL from the
Resthaven facility to its Peace Pipeline system. Pembina will own
approximately 65 percent of the Resthaven facility and 100 percent of the NGL
pipeline. Pembina expects the Resthaven facility and associated pipelines to
be in service in the third quarter of 2014 due to potential scope changes from
the original project. Once operational, Pembina expects the Resthaven facility
will have the capacity to extract up to 13 mbpd of NGL.

Construction on both facilities is underway, with over 95 percent of the major
equipment ordered and on-site at the Saturn facility and over 80 percent of
the major equipment ordered for the Resthaven facility.

Midstream^(1)

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)   December 31^(2)
($ millions, except where noted)   2012 2011 2012 2011
Revenue                               1,103.7      333.5    2,847.4    1,173.5
Operations                               19.4        1.7       59.7        8.8
Cost of goods sold, including           975.0      308.0    2,494.5    1,072.4
product purchases
Realized gain (loss) on commodity        10.2      (0.4)      (4.7)        0.9
related derivative financial
instruments
Operating margin^(3)                    119.5       23.4      288.5       93.2
Depreciation and amortization            31.3        0.9       95.3        3.6
included in operations
Unrealized gain (loss) on               (3.0)        1.7       45.1        1.4
commodity-related derivative
financial instruments
Gross profit                             85.2       24.2      238.3       91.0
Capital expenditures                     77.4        4.6      204.0      111.5

^(1)Share of profit from equity accounted investees not included in these
results.
^(2)Includes results from NGL midstream since the closing of the Acquisition.
^(3)Refer to "Non-GAAP Measures."

Business Overview

Pembina offers customers a comprehensive suite of midstream products and
services through its Midstream business as follows:

  *Crude oil midstream targets oil and diluent-related opportunities from key
    sites across Pembina's network, which comprises 15 truck terminals
    (including one capable of emulsion treating and water disposal),
    terminalling at downstream hub locations, storage, and the Pembina Nexus
    Terminal ("PNT"). PNT includes: 21 inbound pipelines connections, 13
    outbound pipelines connections, an excess of 1.2 million bpd of crude oil
    and condensate connected to the terminal, and 310,000 barrels of surface
    storage.
  *NGL midstream, which Pembina acquired through the Acquisition, includes
    two NGL operating systems, Redwater West and Empress East:

       *The Redwater West NGL system includes the Younger extraction and
         fractionation facility in B.C.; the recently expanded 73,000 bpd
         Redwater NGL fractionator, 6.8 mmbbls of cavern storage and
         terminalling facilities at Redwater, Alberta; and, third party
         fractionation capacity in Fort Saskatchewan, Alberta.
       *The Empress East NGL system includes a 2.1 bcf/d interest in the
         straddle plants at Empress, Alberta; 20,000 bpd of fractionation
         capacity as well as 1.1 mmbbls of cavern storage in Sarnia, Ontario;
         and, approximately 5 mmbbls of hydrocarbon storage at Corunna,
         Ontario.

Financial Performance

In the Midstream business, revenue, net of cost of goods sold, grew to $128.8
million during the fourth quarter of 2012 from $25.5 million during the fourth
quarter of 2011. Full year revenue, net of cost of goods sold, in 2012 was
$352.9 million compared to $101.1 million in 2011. These increases were
primarily due to the addition of the NGL midstream business acquired through
the Acquisition and increased activity on Pembina's pipeline systems.

Operating expenses during the fourth quarter of 2012 were $19.4 million
compared to $1.7 million in the fourth quarter of 2011, and were $59.7 million
for the full year 2012 compared to $8.8 million in 2011. Operating expenses
for the quarter and the year were higher due to the increase in Midstream's
asset base since the Acquisition.

Operating margin was $119.5 million during the fourth quarter of 2012 compared
to $23.4 million during the fourth quarter of 2011. Operating margin for the
2012 year was $288.5 million compared to $93.2 million in 2011. These
increases were largely due to the same factors that contributed to the
increase in revenue, net of cost of goods sold, as discussed above.

Depreciation and amortization included in operations during the fourth quarter
of 2012 totalled $31.3 million compared to $0.9 million during the same period
of the prior year. Full year 2012 depreciation and amortization included in
operations totalled $95.3 million compared to $3.6 million in 2011. Both
increases reflect the additional Midstream assets since the closing of the
Acquisition.

For the three months ended December 31, 2012, unrealized losses on
commodity-related derivative financial instruments were $3 million. For the
full year, there was a gain of $45.1 million. These amounts reflect
fluctuations in the future NGL and natural gas price indices during the
periods (see "Market Risk Management Program" and Note 27 to the Consolidated
Financial Statements).

For the three and twelve months ended December 31, 2012, gross profit in this
business increased to $85.2 million and $238.3 million, respectively, from
$24.2 million and $91 million, respectively, during the same periods in 2011.
This is due to the addition of assets acquired through the Acquisition and
higher operating margin generated by Pembina's legacy midstream operations.

For the year ended December 31, 2012, capital expenditures within the
Midstream business totalled $204 million and were primarily related to cavern
development and associated infrastructure as well as fractionation capacity
expansion at the Redwater facility by approximately 8,000 bpd. This compares
to capital expenditures of $111.5 million during 2011, which included the
acquisition of a terminalling and storage facility near Edmonton, Alberta and
linefill for the Peace Pipeline.

Crude Oil Midstream

Operating margin for the Company's crude oil midstream activities during the
fourth quarter of 2012 was $44.7 million compared to $23.4 million during the
fourth quarter of 2011. For the year ended December 31, 2012, operating margin
was $132.1 million, representing an increase of 42 percent from $93.2 million
in the same period last year. Strong fourth quarter and full year 2012 results
were primarily due to higher volumes and increased activity on Pembina's
pipeline systems, wider margins, as well as opportunities associated with
enhanced connectivity at the PNT added in the first quarter of 2012.
Throughput at the crude oil midstream truck terminals increased by 18 percent
compared to the end of 2011 to exit 2012 at 80,000 bpd.

NGL Midstream

Operating margin for Pembina's NGL midstream activities was $74.8 million for
the fourth quarter and $156.4 million year-to-date since the closing of the
Acquisition, including a $5.8 million year-to-date realized loss on
commodity-related derivative financial instruments (see "Market Risk
Management Program").

NGL sales volumes during the fourth quarter of 2012 were 115.8 mbpd and 97.7
mbpd since the closing of the Acquisition.

Redwater West

Redwater West purchases NGL mix from various natural gas and NGL producers and
fractionates it into finished products at fractionation facilities near Fort
Saskatchewan, Alberta. Redwater West also includes NGL production from the
Younger NGL extraction and fractionation plant (Taylor, B.C.) that provides
specification NGL to B.C. markets. Also located at the Redwater facility are
Pembina's industry-leading rail-based terminal and more than 6.8 mmbbls of
underground hydrocarbon cavern storage, both of which service Pembina's
proprietary and customer needs. Pembina's condensate terminal is the largest
of its kind in western Canada.

Operating margin during the fourth quarter of 2012, excluding realized losses
from commodity-related derivative financial instruments, was $49.1 million.
Year-to-date since closing of the Acquisition, operating margin, excluding
realized losses from commodity-related derivative financial instruments, was
$131.9 million. Realized propane margins were impacted by weak 2012 market
prices and decreased gas volumes at the Younger plant during the year.
Overall, Redwater West NGL sales volumes averaged 59.1 mbpd since closing of
the Acquisition.

Empress East

Empress East extracts NGL mix from natural gas at the Empress straddle plants
and purchases NGL mix from other producers/suppliers. Ethane and condensate
are generally fractionated out of the NGL mix at Empress and sold into Alberta
markets. The remaining NGL mix is transported by pipelines to Sarnia, Ontario
for fractionation and storage of specification products. Propane and butane
are sold into central Canadian and eastern U.S. markets. Demand for propane is
seasonal; inventory 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 during the winter heating season.

Operating margin during the fourth quarter of 2012, excluding realized losses
from commodity-related derivative financial instruments, was $16.5 million.
Year-to-date since closing of the Acquisition, operating margin, excluding
realized losses from commodity-related derivative financial instruments, was
$30.3 million. Results were impacted by low sales volumes, soft 2012 propane
prices and high extraction premiums, but were offset by strong refinery demand
for butane and low AECO natural gas prices since the Acquisition. Overall,
Empress East NGL sales volumes averaged 38.6 mbpd since closing of the
Acquisition.

New Developments: Midstream

As a result of the Acquisition, Pembina's midstream asset base has grown
substantially. Future prospects related to this business now span across the
crude oil and NGL value chains. The capital being deployed in the Midstream
business is primarily directed towards fee-for-service projects which are
expected to continue to increase its stability and predictability.

Pembina continues to advance a number of initiatives, as follows:

  *As part of its full service terminal ("FST") development program, Pembina
    will be putting two new facilities into service in 2013. This includes a
    joint venture FST in the Judy Creek area of Alberta to serve the
    production from Beaverhill Lake and Swan Hills and a second FST that
    serves producers in the Cynthia area west of Drayton Valley. Pembina
    continues to advance other prospects for approval in 2013 and development
    in 2014.
  *During 2013, Pembina will enhance the connectivity of PNT, both to third
    party infrastructure and to the Company's own facilities between Edmonton
    and Fort Saskatchewan. Pembina will be adding a truck terminal and
    constructing storage which will come on stream in 2015. Pembina will also
    commission the first phase of a crude oil rail loading facility. This
    latter project will capitalize on synergies between capabilities and
    expertise acquired with Provident and the crude oil midstream business.
  *During 2012, Pembina successfully completed and commissioned an 8,000 bpd
    expansion at the Redwater fractionator, which required a 20-day
    turn-around of the facility in September. The project was completed on
    schedule and under budget. Also at Redwater, Pembina is currently in
    discussions with customers and completing preliminary engineering work to
    advance its proposed new 73,000 bpd ethane plus fractionator at its site.
    This fractionator would essentially duplicate the existing fractionator,
    and is being pursued by the Company to help ease anticipated fractionation
    capacity constraints in the Fort Saskatchewan, Alberta area.
  *In September of 2012, Pembina brought the first of seven fee-for-service
    caverns into service at its Redwater site. Three additional caverns are
    completed and Pembina is in the process of preparing them for service.
    Pembina expects to be able to bring two caverns into service in March
    2013, and the third cavern into service in June 2013.
  *During the second quarter, Pembina entered into an agreement with a joint
    venture partner and a third-party producer to tie in its production of up
    to 60 MMcf/d and backstop a $12 million natural gas lateral connection to
    the Younger plant by the first quarter of 2013. Pembina's share of NGL
    extracted from this expanded gathering footprint will be incremental
    supply to Pembina's marketing portfolio in both Taylor, B.C. and Fort
    Saskatchewan, Alberta.
  *Given the oversupply of propane in western Canada and North America at
    large, and the associated pricing imbalance, Pembina is investigating
    opportunities for offshore propane export which would leverage its
    existing assets and help provide a solution for Canadian producers.

Market Risk Management Program

Pembina is exposed to frac spread risk, which is the difference between the
selling price for propane-plus liquids and the input cost of natural gas
required to produce respective NGL products. Pembina has a risk management
program and uses derivative financial instruments to mitigate frac spread
risk, when possible, to safeguard a base level of operating cash flow that
covers the input cost of natural gas. Pembina has entered into derivative
financial swap contracts to protect the frac spread and product margin, and to
manage exposure to power costs, interest rates and foreign exchange rates.

Pembina's credit policy mitigates risk of non-performance by counterparties of
its derivative financial instruments. Activities undertaken to reduce risk
include: regularly monitoring counterparty exposure to approved credit limits;
financial reviews of all active counterparties; entering into International
Swap Dealers Association agreements; and, obtaining financial assurances where
warranted. In addition, Pembina has a diversified base of available
counterparties.

Management continues to actively monitor commodity price risk and mitigate its
impact through financial risk management activities. A summary of Pembina's
current financial derivative positions is available on Pembina's website at
www.pembina.com.

A summary of Pembina's risk management contracts executed during the fourth
quarter of 2012 is contained in the following table:

Transactions entered into during the fourth quarter

                                                             
Year Commodity      Description                   Volume    Effective
                                                  (Buy)/Sell      Period
2013 Natural Gas    CDN $3.29 per gj^(1)(6)        (19,500) gjpd  April 1 -
                                                                  October 31
     Crude Oil      US $89.32 per bbl^(2)(6)            675 bpd   April 1 -
                                                                  October 31
                   CDN $86.43 per bbl^(2)(8)        10,150 bpd   January 1 -
                                                                  January 31
    Propane        US $0.955 per gallon^(3)(6)         528 bpd   April 1 -
                                                                  December 31
     Normal Butane  US $1.507 per gallon^(4)(6)         500 bpd   April 1 -
                                                                  October 31
     ISO Butane     US $1.636 per gallon^(5)(6)         250 bpd   April 1 -
                                                                  October 31
     Foreign        Sell US $8,400,000 @                        April 1 -
     Exchange       0.9956^(7)                                    October 31
                   Sell US $20,850,000 @                       April 1 -
                    0.9979^(7)                                    December 31
2014 Propane        US $0.955 per gallon^(3)(6)         745 bpd   January 1 -
                                                                  March 31
     Foreign        Sell US $2,700,000 @                        January 1 -
     Exchange       0.9979^(7)                                    March 31

^(1) Natural gas contracts are settled against Canadian Gas Price Reporter
      AECO's monthly index.
^(2) Crude oil contracts are settled against NYMEX WTI calendar average in
      U.S. or CDN dollars.
^(3) Propane contracts are settled against OPIS Mont Belvieu C3 TET.
^(4) Normal butane contracts are settled against OPIS Mont Belvieu NC4 NON
      TET.
^(5) ISO butane contracts are settled against OPIS Mont Belvieu IC4 NON TET.
^(6) Frac spread contracts entered into to manage revenue and costs
      associated with natural gas based supply arrangements.
^(7) U.S. dollar forward contracts are settled against the Bank of Canada
      noon rate average. Selling notional U.S. dollars for Canadian dollars at
      a fixed exchange rate results in a fixed Canadian dollar price for the
      underlying commodity.
^(8) Product margin contracts entered into to protect margins on commodity
      contracts.

The following table summarizes the impact of commodity-related derivative
financial contracts settled during 2012 and 2011 which were included in the
realized gain/loss on commodity-related derivative financial instruments:

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions)                       2012 2011 2012 2011
Realized gain (loss) on                                                   
commodity-related derivative
financial instruments
Frac spread related                       5.7                (4.5)          
Product margin                            4.2      (0.4)      (0.2)        0.9
Power                                     1.1        1.3        0.1        4.4
Realized gain (loss) on                  11.0        0.9      (4.6)        5.3
commodity-related derivative
financial instruments

The realized gain on commodity-related derivative financial instruments for
the fourth quarter of 2012 was $11 million compared to a realized gain of $0.9
million in the comparable period of 2011. The majority of the realized gain in
the fourth quarter of 2012 was driven by NGL derivative sales contracts
settling at contracted prices higher than the current NGL market prices during
the settlement period and was partially offset by natural gas derivative
purchase contracts settling at contracted prices higher than the market
natural gas prices during the settlement period. For the year ended December
31, 2012, the Company recognized a realized loss on commodity-related
derivative financial instruments of $4.6 million which reflects natural gas
derivative purchase contracts settling at contracted prices higher than the
market natural gas prices during the settlement period.

For more information on financial instruments and financial risk management,
see Note 27 to the Consolidated Financial Statements.

Business Environment

                                                         
                 3 Months Ended           12 Months Ended
                   December 31               December 31
                    2012   2011       %      2012  2011        % Change
                                  Change
WTI crude oil      $88.18 $94.06     (6)    $94.21      $95.12             (1)
(U.S. $ per
bbl)
Exchange rate       $0.99  $1.03       3     $1.00 $0.99 (1)
(from U.S.$ to
Cdn$)
WTI crude oil      $87.31 $96.68    (10)    $94.12      $94.21               
(expressed in
Cdn$ per bbl)
                                                                       
AECO natural        $2.90  $3.29    (12)     $2.28       $3.48            (34)
gas index (Cdn$
per GJ)
                                                                       
Mont Belvieu        $0.88  $1.44    (39)     $1.00       $1.47            (32)
Propane (U.S.$
per U.S.
gallon)
Mont Belvieu    42%    64%    (34) 45%   65%            (31)
Propane
expressed as a
percentage of
WTI
                                                                       
Market Frac        $38.61 $58.41    (34)    $44.70      $54.67            (18)
Spread in Cdn$
per bbl^(1)

^(1) Market frac spread is determined using average spot prices at Mont
      Belvieu, weighted based on 65 percent propane, 25 percent butane and 10
      percent condensate, and the AECO monthly index price for natural gas.

Overall, weaker commodity markets impacted the performance of broader market
indices. During the fourth quarter of 2012, the S&P TSX Composite Index saw a
one percent increase compared to the previous quarter, with the value of the
Index also realizing a four percent increase over 2011.

The Canadian dollar declined modestly against the U.S. dollar during most of
the fourth quarter, averaging $0.99 per U.S. dollar; however, it was stronger
than an average value of $1.03 per U.S. dollar during the fourth quarter of
2011.

With respect to commodity prices:

  *The benchmark WTI oil price exited 2012 at U.S. $91.82/bbl, with prices
    remaining range-bound after recovering from lows set earlier in the year.
    The Canadian heavy crude oil benchmark differential, Western Canadian
    Select, compared to WTI widened significantly in the fourth quarter as
    infrastructure constraints were aggravated by continued production growth
    from the WCSB. Compared to $17.17 per barrel differential in 2011, the
    Western Canadian Select differential averaged $25.23 in 2012.
  *Natural gas prices posted strong gains in the fourth quarter as more
    seasonal temperatures returned to North America. An abnormally warm
    2011/2012 winter depressed pricing through the first half of 2012
    resulting in a full year average of $2.28 compared to $3.48 in 2011. While
    low natural gas prices are generally favourable for NGL extraction and
    fractionation economics, a sustained low gas price could impact the
    availability and overall cost of natural gas and NGL mix supply in western
    Canada with the potential for natural gas producers to elect to shut-in
    production or reduce drilling activities.
  *NGL prices in the fourth quarter of 2012 were mixed across products and
    continued to be negatively impacted by a warm 2011/2012 winter and
    increasing production. This resulted in a North American supply-demand
    imbalance.

       *In the U.S., industry propane/propylene inventories were
         approximately 66.7 million barrels at the end of 2012 (approximately
         15.9 million barrels or 31 percent above the five-year historical
         average for this period).
       *In Canada, industry propane inventories increased to 8.7 million
         barrels at the end of 2012 (2.5 million barrels, or 40 percent
         higher, than the historic five-year average).
       *This over-supply continues to exert pressure on prices, where the
         Mont Belvieu propane price averaged U.S. $0.88 per U.S. gallon (42
         percent of WTI) in the fourth quarter of 2012 and U.S. $1.00 per U.S.
         gallon (44 percent of WTI) for the full year, significantly below its
         five-year average of 58 percent of WTI.
       *Butane and condensate sales prices were robust in the fourth quarter;
         however, price levels remained below those of 2011.
       *Market frac spreads averaged $38.61 per barrel and $44.70 per barrel
         during the fourth quarter and full year of 2012, respectively,
         compared to $58.41 per barrel and $54.67 per barrel during the same
         periods of the prior year. The market frac spread does not include
         extraction premiums, operating/transportation/storage costs and
         regional sales prices.

The outlook for the energy infrastructure sector in the WCSB remains positive
for all of Pembina's businesses. Strong activity levels within the oil sands
region represent opportunities for the Company to leverage existing assets to
capitalize on additional growth opportunities. Pembina also continues to
benefit from the combination of relatively high oil prices and low natural gas
prices, which has resulted in oil and gas producers continuing to extract the
liquids value from their natural gas production and favouring liquids-rich
natural gas plays over dry natural gas. Pembina's Conventional Pipelines, Gas
Services and Midstream businesses are well-positioned to capitalize on the
increased activity levels in key NGL-rich producing basins. Crude oil and NGL
plays being developed in the vicinity of Pembina's pipelines include the
Cardium, Montney, Cretaceous, Duvernay and Swan Hills. While recent weaknesses
in NGL prices and crude oil differentials as well as an inflationary cost
environment have resulted in some producers scaling back activity in the WCSB,
Pembina expects to see a continued positive growth profile for energy
infrastructure.

Non-Operating Expenses

G&A

Pembina incurred G&A (including corporate depreciation and amortization) of
$27.3 million during the fourth quarter of 2012 compared to $21 million during
the fourth quarter of 2011. G&A for the year was $97.5 million compared to
$62.2 million in 2011. The increase in G&A compared to the prior year is
mainly due to the addition of employees who joined Pembina through the
Acquisition, an increase in salaries and benefits for existing and new
employees, and increased rent for expanded office space. In addition, every $1
change in share price is expected to change Pembina's annual share-based
incentive expense by $1.2 million.

Depreciation & Amortization (operational)

Operational depreciation and amortization increased to $47.8 million during
the fourth quarter of 2012 compared to $19.6 million during the same period in
2011. For the year ended December 31, 2012, operational depreciation and
amortization was $173.6 million, up from $68 million last year. Both increases
reflect depreciation on new property, plant and equipment and depreciable
intangibles including those assets acquired through the Acquisition.

Acquisition-Related and Other

Acquisition-related and other expenses during the fourth quarter of 2012 were
$0.5 million compared to $0.8 million in 2011. For the year ended December 31,
2012, acquisition-related and other expenses were $24.7 million which includes
acquisition expenses of $15.9 million and $8.2 million due to the required
make whole payment for the redemption of the senior secured notes from the
first quarter of the year. See "Liquidity and Capital Resources."

Net Finance Costs

Net finance costs in the fourth quarter of 2012 were $35.7 million compared to
$22.1 million in the fourth quarter of 2011. Net finance costs for the full
year of 2012 totalled $115.1 million compared to $91.9 million in 2011. The
increases primarily relate to a $16.2 million year-over-year increase in loans
and borrowings interest expense due to higher debt balances and an increase in
interest on convertible debentures totalling $17.9 million, due to the
debentures assumed on closing of the Acquisition. These factors were offset by
an $11.7 million increase in the change in the fair value of
non-commodity-related derivative financial instruments for the year when
compared to the same period in 2011. (See Notes 21 and 27 to the Consolidated
Financial Statements for the year ended December 31, 2012.) Beginning in the
second quarter of 2012, the change in fair value of commodity-related
derivative financial instruments was reclassified from net finance costs to
gain/loss on commodity-related derivative financial instruments and is
included in operational results.

Income Tax Expense

Deferred income tax expense arises from the difference between the accounting
and tax basis of assets and liabilities. An income tax expense of $27.1
million was recorded in the fourth quarter of 2012 compared to a reduction of
$0.2 million in the fourth quarter of 2011. Income tax expense in 2012
totalled $75.3 million compared to $38.9 million in 2011, which includes
changes in estimates from the prior year.

Pension Liability

Pembina maintains a defined contribution plan and non-contributory defined
benefit pension plans covering employees and retirees. The defined benefit
plans include a funded registered plan for all employees and an unfunded
supplemental retirement plan for those employees affected by the Canada
Revenue Agency maximum pension limits. At the end of 2012, the pension plans
carried a deficit of $27.6 million compared to a deficit of $15.8 million at
the end of 2011. At December 31, 2012, plan obligations amounted to $128
million (2011: $105.2 million) compared to plan assets of $100.4 million
(2011: $89.4 million). In 2012, the pension plans' expense was $7.2 million
(2011: $4.7 million). Contributions to the pension plans totaled $10 million
in 2012 and $8 million in 2011.

In 2013, contributions to the pension plans are expected to be $12.6 million
and pension plans' expenses are anticipated to be $10.6 million. Management
anticipates a long-term return on the pension plans' assets of 5.8 percent and
an annual increase in compensation of 4 percent, which are consistent with
current industry standards.

Liquidity & Capital Resources

                                                           
($ millions)                               December 31, 2012 December 31, 2011
Working capital                                         62.7 (343.7)^(1)
Variable rate debt^(2)                                                      
       Bank debt                                      525.0             313.8
       Variable rate debt swapped to                (380.0)           (200.0)
        fixed
Total variable rate debt outstanding                   145.0             113.8
(average rate of 2.94%)
Fixed rate debt^(2)                                                         
       Senior secured notes                                             58.0
       Senior unsecured notes                         642.0             642.0
       Senior unsecured term debt                      75.0              75.0
       Senior unsecured medium-term note              250.0             250.0
        1
       Senior unsecured medium-term note              450.0                 
        2
       Subsidiary debt                                  9.3                 
       Variable rate debt swapped to                  380.0             200.0
        fixed
Total fixed rate debt outstanding (average           1,806.3           1,225.0
of 4.90%)
Convertible debentures^(2)                             644.3             299.8
Finance lease liability                                  5.8               5.6
Total debt and debentures outstanding                2,601.4           1,644.2
Cash and unutilized debt facilities                  1,032.3             235.1

^(1)As at December 31, 2011, working capital includes $310 million of
current, non-revolving, unsecured credit facilities.
^(2)Face value.

Pembina anticipates cash flow from operating activities will be more than
sufficient to meet its short-term operating obligations and fund its targeted
dividend level. In the short-term, Pembina expects to source funds required
for capital projects from cash and cash equivalents and unutilized debt
facilities totalling $1,032.3 million as at December 31, 2012. In addition,
based on its successful access to financing in the debt and equity markets
during the past several years, Pembina believes it would likely continue to
have access to funds at attractive rates. Pembina also has reinstated its DRIP
as of the January 25, 2012 dividend record date to help fund its ongoing
capital program (see "Trading Activity and Total Enterprise Value" for further
details). Management remains satisfied that the leverage employed in Pembina's
capital structure is sufficient and appropriate given the characteristics and
operations of the underlying asset base.

Management may make adjustments to Pembina's capital structure as a result of
changes in economic conditions or the risk characteristics of the underlying
assets. To maintain or modify Pembina's capital structure in the future,
Pembina may renegotiate new debt terms, repay existing debt, seek new
borrowing and/or issue equity.

In connection with the closing of the Acquisition on April 2, 2012, Pembina
increased its $800 million facility to $1.5 billion for a term of five years.
Upon closing of the Acquisition, Pembina used the facility, in part, to repay
Provident's revolving term credit facility of $205 million. Further, Pembina
renegotiated its operating facility to $30 million from $50 million.

Pembina's credit facilities at December 31, 2012 consisted of an unsecured
$1.5 billion revolving credit facility due March 2017 and an operating
facility of $30 million due July 2013. Borrowings on the revolving credit
facility and the operating facility bear interest at prime lending rates plus
nil percent to 1.25 percent or Bankers' Acceptances rates plus 1.00 percent to
2.25 percent. Margins on the credit facilities are based on the credit rating
of Pembina's senior unsecured debt. There are no repayments due over the term
of these facilities. As at December 31, 2012, Pembina had $525 million drawn
on bank debt, $0.1 million in letters of credit and $27.3 million in cash,
leaving $1,032.3 million of unutilized debt facilities on the $1,530 million
of established bank facilities. Pembina also had an additional $14.3 million
in letters of credit issued in a separate demand letter of credit facility.
Other debt includes $75 million in senior unsecured term debt due 2014; $175
million in senior unsecured notes due 2014; $267 million in senior unsecured
notes due 2019; $200 million in senior unsecured notes due 2021; $250 million
in senior unsecured medium-term notes due 2021; and $450 million in senior
unsecured medium-term notes due 2022. On April 30, 2012, the senior secured
notes were redeemed. Pembina has recognized $8.2 million due to the associated
make whole payment, which has been included in acquisition-related and other
expenses in the first quarter of the year. At December 31, 2012, Pembina had
loans and borrowing (excluding amortization, letters of credit and finance
lease liabilities) of $1,951.3 million. Pembina's senior debt to total capital
at December 31, 2012 was 28 percent.

Offering of Medium-Term Notes

On October 22, 2012, Pembina closed the offering of $450 million principal
amount of senior unsecured medium-term notes ("Notes"). The Notes have a fixed
interest rate of 3.77% per annum, paid semi-annually, and will mature on
October 24, 2022. The net proceeds from the offering of the Notes were used to
repay a portion of Pembina's existing credit facility. Standard & Poor's
Rating Services ("S&P") and DBRS Limited ("DBRS") have assigned credit ratings
of BBB to the Notes.

Credit Ratings

The following information with respect to Pembina's credit ratings is provided
as it relates to Pembina's financing costs and liquidity. Specifically, credit
ratings affect Pembina's ability to obtain short-term and long-term financing
and the cost of such financing. A reduction in the current ratings on
Pembina's debt by its rating agencies, particularly a downgrade below
investment grade ratings, could adversely affect Pembina's cost of financing
and its access to sources of liquidity and capital. In addition, changes in
credit ratings may affect Pembina's ability to, and the associated costs of,
entering into normal course derivative or hedging transactions. Credit ratings
are intended to provide investors with an independent measure of credit
quality of any issues of securities. The credit ratings assigned by the rating
agencies are not recommendations to purchase, hold or sell the securities nor
do the ratings comment on market price or suitability for a particular
investor. Any rating may not remain in effect for a given period of time or
may be revised or withdrawn entirely by a rating agency in the future if in
its judgement circumstances so warrant.

DBRS rates Pembina's senior unsecured notes 'BBB'. S&P's long-term corporate
credit rating on Pembina is 'BBB'.

Assumption of rights related to the Series E and Series F Debentures

On closing of the Acquisition on April 2, 2012, Pembina assumed all of the
rights and obligations of Provident relating to the 5.75 percent convertible
unsecured subordinated debentures maturing December 31, 2017 (TSX: PPL.DB.E),
and the 5.75 percent convertible unsecured subordinated debentures maturing
December 31, 2018 (TSX: PPL.DB.F). Outstanding Series E and Series F
debentures at April 2, 2012 were $345 million. As of December 31, 2012, $344.6
million of the debentures are still outstanding.

Capital Expenditures

                                                       
                         3 Months Ended
                            December 31   12 Months Ended
                            (unaudited)     December 31
($ millions)              2012 2011 2012 2011
Development capital                                              
  Conventional Pipelines       88.1       24.9      187.3       72.0
  Oil Sands & Heavy Oil        18.3       47.8       30.4      191.7
  Gas Services                 77.2       66.4      162.8      136.5
  Midstream                    77.4        4.6      204.0      111.5
Corporate/other projects       (6.3)        5.2      (0.2)       15.9
Total development capital      254.7      148.9      584.3      527.6

During 2012, capital expenditures were $584.3 million compared to $527.6
million in 2011. In the comparable period in 2011, the Company's capital
expenditures included the construction of the Nipisi and Mitsue pipelines, the
acquisition of midstream assets in the Edmonton, Alberta area (related to
PNT), linefill for the Peace Pipeline system as well as construction of the
Musreau deep cut facility.

The majority of the capital expenditures in the fourth quarter and full year
of 2012 were in Pembina's Conventional Pipelines, Gas Services and Midstream
businesses. Conventional Pipelines' capital was incurred to progress the
Northern NGL Expansion and on various new connections. Gas Services' capital
was deployed to complete the Musreau deep cut facility and the expansion of
the shallow cut facility at the Cutbank Complex, as well as to progress the
Saturn and Resthaven enhanced NGL extraction facilities. Midstream's capital
expenditures were primarily directed towards cavern development and related
infrastructure as well as the 8,000 bpd expansion at the Redwater facility.

Contractual Obligations at December 31, 2012

                                                                  
($ millions)                           Payments Due By Period
                                     Less than                           After
Contractual Obligations        Total    1 year 1 - 3 years 3 - 5 years 5 years
Operating and finance leases   293.0      25.4        55.5        58.8   153.6
Loans and borrowings^(1)     2,446.7      80.6       368.9       637.2 1,360.0
Convertible debentures^(1)     903.5      39.2        78.9       251.7   533.7
Construction commitments       362.8     324.2        38.6                  
Provisions^(2)                 361.7       0.5         5.5        25.9   330.1
Total contractual            4,367.7     469.9       546.8       973.6 2,377.4
obligations

^(1)Excluding deferred financing costs.
^(2)Includes discounted constructive and legal obligations included in the
decommissioning provision.

Pembina is, subject to certain conditions, contractually committed to the
construction and operation of the Saturn facility and the Resthaven facility.
See "Forward-Looking Statements & Information."

The contractual obligations noted above have changed significantly since
December 31, 2011, due primarily to the assumption of the contractual
obligations of Provident as a result of the Acquisition.

Critical Accounting Estimates

The preparation of the Consolidated Financial Statements in conformity with
IFRS requires management to make judgments, estimates and assumptions that are
based on the circumstances and estimates at the date of the financial
statements and affect the application of accounting policies and the reported
amounts of assets, liabilities, income and expenses. Actual results may differ
from these estimates.

Judgments, estimates and underlying assumptions are reviewed on an ongoing
basis. Revisions to accounting estimates are recognized in the period in which
the estimates are revised and in any future periods affected.

The following judgment and estimation uncertainties are those management
considers material to the Company's financial statements:

Judgments

(i)Business combinations

Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires management to make
judgments about future possible events. The assumptions with respect to
determining the fair value of property, plant and equipment and intangible
assets acquired generally require the most judgment.

(ii)Componentization

The componentization of the Company's assets are based on management's
judgment of which components constitute a significant cost in relation to the
total cost of an asset and whether these components have similar or dissimilar
patterns of consumption and useful lives for purposes of calculating
depreciation and amortization.

(iii)Depreciation and amortization

Depreciation and amortization of property, plant and equipment and intangible
assets are based on management's judgment of the most appropriate method to
reflect the pattern of an asset's future economic benefit expected to be
consumed by the Company. Among other factors, these judgments are based on
industry standards and historical experience.

Estimates

(i)Inventory

Due to the inherent limitations in metering and the physical properties of
storage caverns and pipelines, the determination of precise volumes of NGL
held in inventory at such locations is subject to estimation. Actual
inventories of NGL within storage caverns can only be determined by draining
the caverns.

(ii)Financial derivative instruments

The Company's financial derivative instruments are 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.

(iii)Business Combinations

Estimates of future cash flows, forecast prices, interest rates and discount
rates are made in determining the fair value of assets acquired and
liabilities assumed for allocation of the purchase price. Changes in any of
the assumptions or estimates used in determining the fair value of acquired
assets and liabilities could impact the amounts assigned to assets,
liabilities, intangibles and goodwill in the purchase price analysis. Future
net earnings can be affected as a result of changes in future depreciation and
amortization, asset or goodwill impairment.

(iv)Defined benefit obligations

The calculation of the defined benefit obligation is sensitive to many
estimates, but most significantly the discount rate applied.

(v)Provisions and contingencies

Provisions recognized are based on management's judgment about assessing
contingent liabilities and timing, scope and amount of liabilities. Management
uses judgment in determining the likelihood of realization of contingent
assets and liabilities to determine the outcome of contingencies.

Based on the long-term nature of the decommissioning provision, the biggest
uncertainties in estimating the provision are the discount rates used, the
costs that will be incurred and the timing of when these costs will occur. In
addition, in determining the provision it is assumed the Company will utilize
technology and materials that are currently available.

(vi)Share-based payments

Compensation costs pursuant to the share-based compensation plans are subject
to estimated fair values, forfeiture rates and the future attainment of
performance criteria.

(vii)Deferred taxes

The calculation of the deferred tax asset or liability is based on assumptions
about the timing of many taxable events and the enacted or substantively
enacted rates anticipated to apply to income in the years in which temporary
differences are expected to be realized or reversed.

(viii)Depreciation and amortization

Estimated useful lives of property, plant and equipment is based on
management's assumptions and estimates of the physical useful lives of the
assets, the economic life, which may be associated with the reserve life and
commodity type of the production area, in addition to the estimated residual
value.

Changes in Accounting Principles and Practices

Subsequent to the Acquisition, Pembina reviewed and compared legacy
Provident's accounting policies with the Company's existing policies and
determined there were no significant differences.

New standards and interpretations not yet adopted

Certain new standards, interpretations, amendments and improvements to
existing standards were issued by the IASB or International Financial
Reporting Interpretations Committee ("IFRIC") for accounting periods beginning
after January 1, 2013. The Company has reviewed these and determined that the
following:

IFRS 7 Financial Instruments: Disclosures - in December 2011, the IASB issued
amendments to IFRS 7 which outline disclosures that are required for any
financial assets or liabilities that are offset in accordance with IAS 32. The
amendments to this standard are required to be adopted for periods beginning
January 1, 2013. The adoption of these amendments is not expected to have a
material impact on the Company's Financial Statements.

IFRS 9 Financial Instruments - in November 2009 and revised in October 2010
the IASB issued IFRS 9. This standard replaces the current multiple
classification and measurement model for financial assets and liabilities with
a proposed single model for only two classification categories: amortized cost
and fair value. The standard is currently required to be adopted for periods
beginning January 1, 2015. The extent of the impact of adoption of this
standard has not yet been determined.

IFRS 10 Consolidated Financial Statements - in May 2011, the IASB issued IFRS
10 which provides additional guidance to determine whether an entity should be
included within the consolidated financial statements of Pembina. The guidance
applies to all investees, including special purpose entities. The standard is
required to be adopted for periods beginning January 1, 2013. The adoption of
this standard is not expected to have a material impact on the Company's
Financial Statements.

IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which
presents a new model for the financial reporting of joint arrangements. The
new model determines whether an entity should account for joint arrangements
using proportionate consolidation or the equity method with emphasis on the
substance rather than legal form of a joint arrangement. The standard is
required to be adopted for periods beginning January 1, 2013. The adoption of
this standard is not expected to have a material impact on the Company's
Financial Statements.

IFRS 12 Disclosure of Interests in Other Entities - in June 2011, the IASB
issued IFRS 12 which provides guidance on the disclosure requirements for
subsidiaries, joint arrangements, associates and unconsolidated structured
entities. The standard is required to be adopted for periods beginning January
1, 2013. The adoption of this standard is not expected to have a material
impact on the Company's Financial Statements.

IFRS 13 Fair Value Measurement - in June 2011, the IASB issued IFRS 13 to
provide specific guidance for all standards where IFRS requires or permits
fair value measurement. The standard defines fair value and provides guidance
on disclosures about fair value measurements. The standard is required to be
adopted for periods beginning January 1, 2013. The adoption of this standard
is not expected to have a material impact on the Company's Financial
Statements.

IAS 19 Employee Future Benefits - in June 2011, the IASB issued amendments to
IAS 19 which limit the way actuarial gains and losses can be recorded and the
way finance costs can be calculated, along with requirements for additional
disclosures for defined benefit plans. The amendments to this standard are
required to be adopted for periods beginning January 1, 2013. The adoption of
these amendments is not expected to have a material impact on the Company's
Financial Statements.

IAS 32 Financial Instruments: Presentation - in December 2011, the IAS issued
amendments which clarify matters regarding offsetting financial assets and
financial liabilities. The amendments to this standard are required to be
adopted for periods beginning January 1, 2014. The Company is currently
evaluating the impact that these amendments will have on its results of
operations and financial position.

Controls and Procedures

As part of the requirements mandated by the Canadian securities regulatory
authorities under National Instrument 52-109 - Certification of Disclosure in
Issuers' Annual and Interim Filings ("NI 52-109"), Pembina's Chief Executive
Officer ("CEO") and the Chief Financial Officer ("CFO") have evaluated the
design and operation of Pembina's disclosure controls and procedures ("DC&P"),
as such term is defined in NI 52-109, as at December 31, 2012. Based on that
evaluation, the CEO and the CFO concluded that Pembina's DC&P was effective as
at December 31, 2012.

The CEO and CFO are also responsible for establishing and maintaining internal
controls over financial reporting ("ICFR"), as such term is defined in NI
52-109. These controls are designed to provide reasonable assurance regarding
the reliability of Pembina's financial reporting and compliance with GAAP.
Pembina's CEO and CFO have evaluated the design and operational effectiveness
of such controls as at December 31, 2012. Based on the evaluation of the
design and operating effectiveness of Pembina's ICFR, the CEO and the CFO
concluded that Pembina's ICFR was effective as at December 31, 2012.

Changes in internal control over financial reporting

During 2012, there have been no changes to the Company's internal control over
financial reporting that have materially affected, or are reasonably likely to
materially affect, the Company's internal control over financial reporting,
except as noted below.

In accordance with the provisions of NI 52-109, management, including the CEO
and CFO, have limited the scope of their design of the Company's DC&P and ICFR
to exclude controls, policies and procedures of Provident. Pembina acquired
the assets of Provident and its subsidiaries on April 2, 2012. Provident's
contribution to the Company's Consolidated Financial Statements for the
quarter and year ended December 31, 2012 were approximately 36 percent and 32
percent of consolidated revenue, respectively, and approximately 11 percent
and 24 percent of consolidated pre-tax earnings, respectively.

Additionally, as at December 31, 2012, Provident's current assets and current
liabilities were approximately 59 percent and 44 percent of consolidated
current assets and liabilities, respectively, and its non-current assets and
non-current liabilities were approximately 57 percent and 34 percent of
consolidated non-current assets and non-current liabilities, respectively.

The scope limitation is primarily based on the time required to assess
Provident's DC&P and ICFR in a manner consistent with the Company's other
operations.

Further details related to the Acquisition are disclosed in Note 5 in the
Notes to the Company's Consolidated Financial Statements for the year ended
December 31, 2012.

Trading Activity and Total Enterprise Value^(1)

                                                          
                                             As at and for the 12
                                                   months ended
($ millions, except where     February 26, December 31, 2012 December 31, 2011
noted)                            2013^(2)
Trading volume and value                                                   
   Total volume (shares)      19,509,172       180,317,622        75,574,785
   Average daily volume          500,235           718,397           325,753
    (shares)
   Value traded                    568.7     5,021.6     1,947.7
Shares outstanding            294,924,568       293,226,473       167,908,271
(shares)
Closing share price                 28.89       28.46       29.66
(dollars)
Market value                                                               
   Shares                        8,520.4     8,345.2     4,980.2
   5.75% convertible       334.0^(3)   332.7^(4)   326.8^(5)
    debentures (PPL.DB.C)
   5.75% convertible            205.3^(6)         201.4^(7)                 
    debentures (PPL.DB.E)
   5.75% convertible       193.5^(8)   191.0^(9)                 
    debentures (PPL.DB.F)
Market capitalization             9,253.2     9,070.3     5,306.9
Senior debt                       1,932.0     1,942.0     1,338.1
Total enterprise                 11,185.2    11,012.3     6,645.0
value^(10)

^(1)Trading information in this table reflects the activity of Pembina
securities on the TSX only.

^(2)Based on 39 trading days from January 2, 2013 to February 26, 2013,
inclusive.

^(3)$299.7 million principal amount outstanding at a market price of $111.42
at February 26, 2013 and with a conversion price of $28.55.

^(4)$299.7 million principal amount outstanding at a market price of $111.00
at December 31, 2012 and with a conversion price of $28.55.

^(5)$300.0 million principal amount outstanding at a market price of $102.95
at December 31, 2011 and with a conversion price of $28.55.

^(6)$172.1 million principal amount outstanding at a market price of $119.36
at February 26, 2013 and with a conversion price of $24.94.

^(7)$172.1 million principal amount outstanding at a market price of $117.00
at December 31, 2012 and with a conversion price of $24.94.

^(8)$172.4 million principal amount outstanding at a market price of $112.20
at February 26, 2013 and with a conversion price of $29.53.

^(9)$172.4 million principal amount outstanding at a market price of $110.75
at December 31, 2012 and with a conversion price of $29.53.

^(10)Refer to "Non-GAAP Measures."

As indicated in the previous table, Pembina's total enterprise value was $11
billion at December 31, 2012, and the Company's issued and outstanding shares
rose to 293.2 million at the end of 2012 compared to 167.9 million at the end
of 2011 primarily due to shares issued pursuant to the Acquisition.

Dividends

On April 12, 2012, following closing of the Acquisition, Pembina announced a
3.8 percent increase in its monthly dividend rate to $0.135 per share per
month (or $1.62 annualized) from $0.13 per share per month previously (or
$1.56 annualized). Pembina is committed to providing increased shareholder
returns over time by providing stable dividends and, where appropriate,
further increases in Pembina's dividend, subject to compliance with applicable
laws and the approval of Pembina's Board of Directors. Pembina has a history
of delivering dividend increases once supportable over the long-term by the
underlying fundamentals of Pembina's businesses as a result of, among other
things, accretive growth projects or acquisitions (see "Forward-Looking
Statements & Information").

Dividends are payable if, as, and when declared by Pembina's Board of
Directors. The amount and frequency of dividends declared and payable is at
the discretion of the Board of Directors which will consider earnings, capital
requirements, the financial condition of Pembina and other relevant factors.

Eligible Canadian investors may benefit from an enhanced dividend tax credit
afforded to the receipt of dividends, depending on individual circumstances.
Dividends paid to eligible U.S. investors should qualify for the reduced rate
of tax applicable to long-term capital gains but investors are encouraged to
seek independent tax advice in this regard.

DRIP

Pembina reinstated its DRIP effective as of January 25, 2012. Eligible Pembina
shareholders have the opportunity to receive, by reinvesting the cash
dividends declared payable by Pembina on their shares, either (i) additional
common shares at a discounted subscription price equal to 95 percent of the
Average Market Price (as defined in the DRIP), pursuant to the "Dividend
Reinvestment Component" of the DRIP, or (ii) a premium cash payment (the
"Premium Dividend™") equal to 102 percent of the amount of reinvested
dividends, pursuant to the "Premium Dividend™ Component" of the DRIP.
Additional information about the terms and conditions of the DRIP can be found
at www.pembina.com.

Participation in the DRIP for the full year of 2012 was approximately 58
percent of common shares outstanding for proceeds of approximately $218.7
million.

Listing on the NYSE

On April 2, 2012, Pembina listed its common shares, including those issued
under the Acquisition, on the NYSE under the symbol "PBA."

Risk Factors

Pembina's value proposition is based on maintaining a very low risk profile.
In addition to contractually eliminating the majority of its business risk,
Pembina has formal risk management policies, procedures and systems designed
to mitigate any residual risks, such as market price risk, credit risk and
operational risk. Certain of the risks associated with Pembina's business are
discussed below. For a full discussion of these and other risk factors
affecting the business and operation of Pembina and its operating
subsidiaries, readers are referred to Pembina's Annual Information Form, an
electronic copy of which is available at www.pembina.com or on Pembina's SEDAR
profile at www.sedar.com. Shareholders and prospective investors should
carefully consider these risk factors before investing in Pembina's
securities, as each of these risks may negatively affect the trading price of
Pembina's securities, the amount of dividends paid to shareholders and the
ability of Pembina to fund its debt obligations, including debt obligations
under its outstanding convertible debentures and any other debt securities
that Pembina may issue from time to time.

RISKS INHERENT IN PEMBINA'S BUSINESS

Operational Risks

Operational risks include: pipeline leaks, the breakdown or failure of
equipment, information systems or processes; the performance of equipment at
levels below those originally intended (whether due to misuse, unexpected
degradation or design, construction or manufacturing defects); spills at truck
terminals and hubs; failure to maintain adequate supplies of spare parts;
operator error; labour disputes; disputes with interconnected facilities and
carriers; operational disruptions or apportionment on third-party systems or
refineries which may prevent the full utilization of the Company's pipelines;
and catastrophic events such as natural disasters, fires, explosions,
fractures, acts of terrorists and saboteurs; and, other similar events, many
of which are beyond the control of Pembina. The occurrence or continuance of
any of these events could increase the cost of operating Pembina's assets or
reduce revenue, thereby impacting earnings.

Pembina is committed to preserving customer and shareholder value by
proactively managing operational risk through safe and reliable operations.
Senior managers are responsible for the daily supervision of operational risk
by ensuring appropriate policies and procedures are in place within their
business units and internal controls are operating efficiently. Pembina also
has an extensive program to manage system integrity, which includes the
development and use of in-line inspection tools and various other leak
detection technologies. Maintenance, excavation and repair programs are
directed to the areas of greatest benefit, and pipe is replaced or repaired as
required. Pembina also maintains comprehensive insurance coverage for
significant pipeline leaks and has a comprehensive security program designed
to reduce security-related risks. While Pembina feels the level of insurance
is adequate, it may not be sufficient to cover all potential losses.

Midstream Business

Pembina's Midstream business includes product storage terminalling and hub
services. These activities expose Pembina to certain risks including that
Pembina may experience volatility in revenue due to variations in commodity
prices. Primarily, Pembina enters into contracts to purchase and sell crude
oil at floating market prices. The prices of products that are marketed by
Pembina are subject to fluctuations as a result of such factors as seasonal
demand changes, general economic conditions, changes in crude oil markets and
other factors. Pembina manages its risk exposure by balancing purchases and
sales to lock-in margins. Notwithstanding Pembina's management of price and
quality risk, marketing margins for crude oil can vary and has varied
significantly from period to period and this could have an adverse effect on
the results of Pembina's commercial Midstream business and Pembina's overall
results of operations. To assist in effectively smoothing that variability,
Midstream is investing in assets that have a fee-based revenue component, and
looking to expand this approach going forward.

The Midstream business is exposed to possible price declines between the time
Pembina purchases NGL feedstock and sells NGL products, and to narrowing frac
spreads. Frac spread is the difference between the selling prices for NGL
products and the input cost of the natural gas required to produce the
respective NGL products. The frac spread can change significantly from period
to period depending on the relationship between crude oil and natural gas
prices (the "frac spread ratio"), absolute commodity prices, and changes in
the Canadian to U.S. dollar foreign exchange rate. There is also a
differential between NGL product prices and crude oil prices which can change
prices received and margins realized for midstream products separate from frac
spread ratio changes. The amount of profit or loss made on the extraction
portion of the NGL midstream business will generally increase or decrease with
the frac spread. This exposure could result in material variability of cash
flow generated by the NGL midstream business, which could negatively affect
Pembina and the cash dividends of Pembina.

Reputation

Reputational risk is the potential for negative impacts that could result from
the deterioration of Pembina's reputation with key stakeholders. The potential
for harming Pembina's corporate reputation exists in every business decision,
and all risks can have an impact on reputation, which in turn can negatively
impact Pembina's business and its securities. Reputational risk cannot be
managed in isolation from other forms of risk. Credit, market, operational,
insurance, liquidity, and regulatory and legal risks must all be managed
effectively to safeguard Pembina's reputation. Negative impacts from a
compromised reputation could include revenue loss, reduction in customer base,
delays in regulatory approvals on growth projects, and decreased value of
Pembina's securities.

Pembina's reputation as a reliable and responsible energy services provider
with consistent financial performance and long-term financial stability is one
of its most valuable assets. Key to effectively building and maintaining
Pembina's reputation is fostering a culture that promotes integrity and
ethical conduct. Ultimate responsibility for Pembina's reputation lies with
the executive team, who examines reputational risk and issues as part of all
business decisions. Nonetheless, every employee and representative of Pembina
has a responsibility to contribute in a positive way to its reputation. This
means ensuring ethical practices are followed at all times, interactions with
our stakeholders are positive, and compliance with applicable policies,
legislation and regulations. Reputational risk is most effectively managed
when every individual works continuously to protect and enhance Pembina's
reputation.

Environmental Costs & Liabilities

Pembina's operations, facilities and petroleum product shipments are subject
to extensive national, regional and local environmental, health and safety
laws and regulations governing, among other things, discharges to air, land
and water, the handling and storage of petroleum compounds and hazardous
materials, waste disposal, the protection of employee health, safety and the
environment, and the investigation and remediation of contamination. Pembina's
facilities could experience incidents, malfunctions or other unplanned events
that result in spills or emissions in excess of permitted levels and result in
personal injury, fines, penalties or other sanctions and property damage.
Pembina could also incur liability in the future for environmental
contamination associated with past and present activities and properties.
Pembina's facilities and pipelines must maintain a number of environmental and
other permits from various governmental authorities in order to operate, and
these facilities are subject to inspection from time to time. Failure to
maintain compliance with these requirements could result in operational
interruptions, fines or penalties, or the need to install potentially costly
pollution control technology.

While Pembina believes its current operations are in compliance with all
applicable environmental and safety regulations, there can be no assurance
that substantial costs or liabilities will not be incurred. Moreover, it is
possible that other developments, such as increasingly strict environmental
and safety laws, regulations and enforcement policies thereunder, claims for
damages to persons or property resulting from Pembina's operations, and the
discovery of pre-existing environmental liabilities in relation to any of
Pembina's existing or future properties or operations, could result in
significant costs and liabilities to Pembina. In addition, the costs of
environmental liabilities in relation to spill sites of which Pembina is
currently aware could be greater than Pembina currently anticipates, and any
such differences could be substantial. If Pembina were not able to recover the
resulting costs or increased costs through insurance or increased tariffs,
cash flow available to pay dividends to shareholders and to service
obligations under its convertible debentures and other debt obligations could
be adversely affected.

While Pembina maintains insurance in respect of damage caused by seepage or
pollution in an amount it considers prudent and in accordance with industry
standards, certain provisions of such insurance may limit the availability in
respect of certain occurrences unless they are discovered within fixed timed
periods. These periods can range from 72 hours to 30 days. Although Pembina
believes it has adequate leak detection systems in place to monitor a
significant spill of product, if Pembina is unaware of a problem or is unable
to locate the problem within the relevant time period, insurance coverage may
not be available. However, Pembina believes it has adequate leak detection
systems in place to detect and monitor a significant spill.

Pembina is committed to protecting the health and safety of employees,
contractors and the general public, and to sound environmental stewardship.
Pembina believes that prevention of incidents and injuries, and protection of
the environment, benefits everyone and delivers increased value to
shareholders, customers and employees.

Pembina has health, safety and environmental management systems and
established policies, programs and practices for conducting safe and
environmentally sound operations. Pembina conducts regular reviews and audits
to assess compliance with legislation and company policy.

Abandonment Costs

Pembina is responsible for compliance with all applicable laws and regulations
regarding the abandonment of its pipeline and other assets at the end of their
economic life, and these abandonment costs may be substantial. The proceeds of
the disposition of certain assets associated with Pembina's pipeline systems,
including, in respect of certain pipeline systems, linefill may be available
to offset abandonment costs. However, it is not possible to definitively
predict abandonment costs since they will be a function of regulatory
requirements at the time, and the value of Pembina's assets, including
linefill, may then be more or less than the abandonment costs. Pembina may, in
the future, determine it prudent or be required by applicable laws or
regulations to establish and fund one or more reclamation funds to provide for
payment of future abandonment costs. Such reserves could decrease cash flow
available for dividends to shareholders and to service obligations under
Pembina's outstanding convertible debentures and other debt obligations.

On May 26, 2009 the NEB issued its Reasons for Decision RH-2-2008 with respect
to the Land Matters Consultation Initiative - Stream 3 which dealt with
financial issues of pipeline abandonment for pipelines under the NEB's
jurisdiction. The NEB decided in principle to set an ultimate goal to have all
companies under its jurisdiction begin setting aside funds for the abandonment
of pipelines no later than 5 years from the date of the decision. The NEB
recommended an action plan to achieve this ultimate goal that would require
pipelines to submit to the NEB preliminary cost estimates and fund collection
mechanisms for pipeline abandonment prior to the setting aside of funds. In
November 2011, Pembina (and formally Provident) submitted preliminary cost
estimates totalling $11,350,000 to the NEB for its affected approximately 275
km segments of pipeline. Pembina is working towards a pipeline abandonment
fund collection plan and set aside mechanism to present to the NEB by May 31,
2013 prior to the setting aside of funds.

Reserve Replacement, Throughput and Product Demand

Pembina's Conventional Pipeline tariff revenue is based upon a variety of
tolling arrangements, including "ship or pay" contracts, cost of service
arrangements and market-based tolls. As a result, certain pipeline tariff
revenue is heavily dependent upon throughput levels of crude oil, NGL and
condensate. Future throughput on Pembina's crude oil and NGL pipelines and
replacement of oil and gas reserves in the service areas will be dependent
upon the success of producers operating in those areas in exploiting their
existing reserve bases and exploring for and developing additional reserves.
Without reserve additions, or expansion of the service areas, throughput on
such pipelines will decline over time as reserves are depleted. As oil and gas
reserves are depleted, production costs may increase relative to the value of
the remaining reserves in place, causing producers to shut-in production and
seek lower cost alternatives for transportation. If the level of tariffs
collected by Pembina decreases as a result, cash flow available for dividends
to shareholders, to service obligations under the convertible debentures and
the Company's other debt obligations could be adversely affected.

Over the long-term, Pembina's business will depend, in part, on the level of
demand for crude oil, condensate, NGL and natural gas in the markets served by
Pembina's crude oil and NGL pipelines and gas processing and gathering
infrastructure in which Pembina has an interest. The global events of 2008 and
2009 had a substantial downward effect on the demand for and prices of such
products. Although prices rebounded in 2010 and remained relatively strong
through 2012, Pembina cannot predict the impact of future economic conditions
on the energy and petrochemical industries or future demand for and prices of
natural gas, crude oil, condensate and NGL. Future prices of these products
are determined by supply and demand factors, including weather and general
economic conditions as well as political and other conditions in other oil and
natural gas regions, all of which are beyond Pembina's control.

The volumes of natural gas processed through Pembina's gas processing assets
and of NGL and other products transported in the pipelines depend on
production of natural gas in the areas serviced by the business and pipelines.
Without reserve additions, production will decline over time as reserves are
depleted and production costs may rise. Producers may shut-in production at
lower product prices or higher production costs. Producers in the areas
serviced by the business may not be successful in exploring for and developing
additional reserves, and the gas plants and the pipelines may not be able to
maintain existing volumes of throughput. Commodity prices may not remain at a
level which encourages producers to explore for and develop additional
reserves or produce existing marginal reserves. Lower production volumes will
also increase the competition for natural gas supply at gas processing plants
which could result in higher shrinkage premiums being paid to natural gas
producers.

The rate and timing of production from proven natural gas reserves tied into
the gas plants is at the discretion of the producers and is subject to
regulatory constraints. The producers have no obligation to produce natural
gas from these lands. Pembina's gas processing assets are connected to various
third-party trunkline systems. Operational disruptions or apportionment on
those third-party systems may prevent the full utilization of the business.

Over the long-term, business will depend, in part, on the level of demand for
NGL and natural gas in the geographic areas in which deliveries are made by
pipelines and the ability and willingness of shippers having access or rights
to utilize the pipelines to supply such demand. Pembina cannot predict the
impact of future economic conditions, fuel conservation measures, alternative
fuel requirements, governmental regulation or technological advances in fuel
economy and energy generation devices, all of which could reduce the demand
for natural gas and NGL.

Operating and Capital Costs

Operating and capital costs of Pembina's business may vary considerably from
current and forecast values and rates and represent significant components of
the cost of providing service. In general, as equipment ages, costs associated
with such equipment may increase over time. Dividends may be reduced if
significant increases in operating or capital costs are incurred.

Although operating costs are to be recaptured through the tariffs charged on
natural gas volumes processed and oil and NGL transported, respectively, to
the extent such charges escalate, producers may seek lower cost alternatives
or stop production of their natural gas.

Completion of the Resthaven Facility and Saturn Facility

The Resthaven facility and the Saturn facility are currently under development
by Pembina and the successful completion of these facilities is dependent on
numerous factors outside of Pembina's control. These factors include
completion of the construction of the Resthaven facility and Saturn facility
on schedule, as well as construction and labour costs that may change
depending on supply, demand and/or inflation. Under the agreements governing
the construction and operation of the Resthaven facility and the Saturn
facility, Pembina is obligated to construct the facilities and Pembina bears
the risk for its share of any cost overruns. While Pembina is not currently
aware of any significant cost overruns at the date hereof, any such cost
overruns in the future could reduce Pembina's expected return on the Resthaven
facility and the Saturn facility and adversely affect Pembina's results of
operations which, in turn, could reduce the level of cash available for
dividends to shareholders.

Expansion of the Peace/Northern NGL System

The Company has announced plans to expand throughput capacity on the
Peace/Northern NGL System (Phase I: 52,000, Phase 2: 55,000 bpd) and Peace
Crude and Condensate System (Phase I: 40,000 bpd and Phase 2: 55,000). The
successful completion of these expansions is dependent on numerous factors
outside of the Company's control. These factors include receipt of regulatory
approval and reaching long-term commercial arrangements with customers in
respect of certain portions of the expansions, completion of the construction
of the expansions on schedule, as well as construction costs that may change
depending on supply, demand and/or inflation. Any agreements with customers
entered into with respect to the expansions may require that the Company bears
the risk for any cost overruns and any such cost overruns could reduce the
Company's expected return on the expansions and adversely affect the Company's
results of operations which, in turn, could reduce the level of cash available
for dividends to shareholders. There is no certainty, nor can the Company
provide any assurance, that regulatory approval will be received or that
satisfactory commercial arrangements with customers will be reached where
needed on a timely basis or at all.

Possible Failure to Realize Anticipated Benefits of Acquisitions

As part of its ongoing strategy, Pembina has completed acquisitions, such as
the Provident Acquisition, and may complete additional acquisitions of assets
or other entities in the future. Achieving the benefits of completed and
future acquisitions depends in part on successfully consolidating functions
and integrating operations, procedures and personnel in a timely and efficient
manner, as well as Pembina's ability to realize the anticipated growth
opportunities and synergies from combining the acquired businesses and
operations with those of Pembina. The integration of acquired businesses and
entities requires the dedication of substantial management effort, time and
resources which may divert management's focus and resources from other
strategic opportunities and from operational matters during this process. The
integration process may result in the loss of key employees and the disruption
of ongoing business, customer and employee relationships that may adversely
affect Pembina's ability to achieve the anticipated benefits of any
acquisitions.

Competition

Pembina competes with other pipelines, midstream and marketing and gas
processing and handling services providers in its service areas as well as
other transporters of crude oil and NGL. The introduction of competing
transportation alternatives into the Company's service areas could potentially
have the impact of limiting the Company's ability to adjust tolls as it may
deem necessary. Additionally, potential pricing differentials on the
components of NGL may result in these components being transported by
competing gas pipelines. Pembina believes it is prepared for and determined to
meet these existing and potential competitive pressures.

Execution Risk

Pembina's ability to successfully execute the development of its organic
growth projects may be influenced by capital constraints, third-party
opposition, changes in shipper support over time, delays in or changes to
government and regulatory approvals, cost escalations, construction delays,
shortage and in-service delays. Pembina's growth plans may strain its
resources and may be subject to high cost pressures in the North American
energy sector. Early stage project risks include right-of-way procurement,
special interest group opposition, Aboriginal consultation, and environmental
and regulatory permitting. Cost escalations may impact project economics.
Construction delays due to slow delivery of materials, contractor
non-performance, weather conditions and shortages may impact project
development. Labour shortages and productivity issues may also affect the
successful completion of projects.

Pembina has a centralized and clearly defined governance structure and process
for all major projects with dedicated resources organized to lead and execute
each major project. Capital constraints and cost escalation risks are
mitigated through structuring of commercial agreements, typically where
shippers retain complete or a share of capital cost excess. Pembina's emphasis
on corporate social responsibility promotes generally positive relationships
with landowners, aboriginal groups and governments, which help to facilitate
right-of-way acquisition, permitting and scheduling. Detailed cost tracking
and centralized purchasing is used on all major projects to facilitate optimum
pricing and service terms. Strategic relationships have been developed with
suppliers and contractors. Compensation programs, communications and the
working environment are aligned to attract, develop and retain qualified
personnel.

Shipper and Processing Contracts

Throughput on Pembina's pipelines is or will be governed by transportation
contracts or tolling arrangements with various producers of petroleum
products. In addition, Pembina is party to numerous contracts of varying
durations in respect of its gas gathering, processing and fractionating
facilities. Any default by counterparties under such contracts or any
expirations of such contracts or tolling arrangements without renewal or
replacement may have an adverse effect on Pembina's business. Furthermore,
some of the contracts associated with its gas gathering, processing and
fractionating facilities are comprised of a mixture of firm and interruptible
service contracts and the revenue that Pembina earns on the contracts which
are based on interruptible service is dependent on the volume of natural gas
and NGL produced by producers in the relevant geographic areas and lower than
historical production volumes in these areas (for reasons such as low
commodity prices) may have an adverse effect on Pembina's revenue.

GENERAL RISK FACTORS

Risk Factors Relating to the Structure of Pembina and its Common Shares

Dilution of Shareholders

Pembina is authorized to issue, among other classes of shares, an unlimited
number of common shares for consideration and on terms and conditions as
established by the Board of Directors without the approval of the shareholders
in certain instances. The shareholders will have no pre-emptive rights in
connection with such further issues.

Risk Factors Relating to the Activities of Pembina and the Ownership of Common
Shares

The following is a list of certain risk factors relating to the activities of
Pembina and the ownership its common shares:

  *the level of Pembina's indebtedness from time to time could impair
    Pembina's ability to obtain additional financing on a timely basis to take
    advantage of business opportunities that may arise;
  *the uncertainty of future dividend payments by Pembina and the level
    thereof as Pembina's dividend policy and the funds available for the
    payment of dividends from time to time will be dependent upon, among other
    things, operating cash flow generated by Pembina and its subsidiaries,
    financial requirements for Pembina's operations and the execution of its
    growth strategy and the satisfaction of solvency tests imposed by the
    Alberta Business Corporations Act for the declaration and payment of
    dividends;
  *Pembina may make future acquisitions or may enter into financings or other
    transactions involving the issuance of securities of Pembina which may be
    dilutive; and
  *the risk that the market value of the common shares may materially
    deteriorate if Pembina is unable to meet its cash dividend targets or make
    cash dividends in the future.

Market Value of Common Shares and Other Securities

Pembina cannot predict at what price the common shares, convertible debentures
or other securities issued by Pembina will trade in the future. Common shares,
convertible debentures and other securities of Pembina will not necessarily
trade at values determined solely by reference to the underlying value of
Pembina's assets. One of the factors that may influence the market price of
such securities is the annual yield on the common shares and the convertible
debentures. An increase in market interest rates may lead purchasers of common
shares or convertible debentures to demand a higher annual yield and this
could adversely affect the market price of the common shares or convertible
debentures. In addition, the market price for the common shares and the
convertible debentures may be affected by changes in general market
conditions, fluctuations in the market for equity or debt securities and
numerous other factors beyond the control of Pembina.

Shareholders are encouraged to obtain independent legal, tax and investment
advice in their jurisdiction of residence with respect to the holding of
common shares.

Regulation

Legislation in Alberta and B.C. exists to ensure that producers have fair and
reasonable opportunities to produce, process and market their reserves. In
Alberta, the Energy Resources Conservation Board and in B.C., the British
Columbia Utilities Commission, may, on application and following a hearing
(and in Alberta with the approval of the Lieutenant Governor in Council),
declare the operator of a pipeline a common carrier of oil or NGL and, as
such, must not discriminate between producers who seek access to the pipeline.
Producers and shippers may also apply to the regulatory authorities for a
review of tariffs, and such tariffs may then be regulated if it is proven that
the tariffs are not just and reasonable. Applications by producers to have a
pipeline operator declared a common carrier are usually accompanied by an
application to have the tariffs set by the regulatory authorities. The extent
to which regulatory authorities in such instances can override existing
transportation or processing contracts has not been fully decided. The
potential for direct regulation of tolls, other than for the Company's
provincially regulated B.C. pipelines, while considered remote by the Company,
could result in toll levels that are less advantageous to the Company and
could impair the economic operation of such regulated pipeline systems.

Additional Financing and Capital Resources

The timing and amount of Pembina's capital expenditures, and the ability of
Pembina to repay or refinance existing debt as it becomes due, directly
affects the amount of cash dividends that Pembina pays to shareholders. Future
acquisitions, expansions of Pembina's pipeline systems and midstream
operations, other capital expenditures, including the capital expenditures
that Pembina has committed to in respect of the Resthaven facility, the Saturn
facility and the expansion of the Northern NGL System and the repayment or
refinancing of existing debt as it becomes due will be financed from sources
such as cash generated from operations, the issuance of additional shares or
other securities (including debt securities) of Pembina, and borrowings.
Dividends may be reduced, or even eliminated, at times when significant
capital or other expenditures are made. There can be no assurance that
sufficient capital will be available on terms acceptable to Pembina, or at
all, to make additional investments, fund future expansions or make other
required capital expenditures. To the extent that external sources of capital,
including the issuance of additional shares or other securities or the
availability of additional credit facilities, become limited or unavailable on
favourable terms or at all due to credit market conditions or otherwise, the
ability of Pembina to make the necessary capital investments to maintain or
expand its operations, to repay outstanding debt and to invest in assets, as
the case may be, may be impaired. To the extent Pembina is required to use
cash flow to finance capital expenditures or acquisitions or to repay existing
debt as it becomes due, the level of dividends to shareholders of Pembina may
be reduced.

Counterparty credit risk

Pembina is subject to counterparty credit risk arising out of its operations.
A majority of Pembina's accounts receivable are with customers in the oil and
gas industry and are subject to normal industry counterparty credit risk.
Counterparty credit risk is managed through credit approval and monitoring
procedures. The credit worthiness assessment takes into account available
qualitative and quantitative information about the counterparty, including,
but not limited to, financial status and external credit ratings. Depending on
the outcome of each assessment, guarantees or some other credit enhancement
may be requested as security. Pembina attempts to mitigate its exposure by
entering into contracts with customers that may permit netting or entitle
Pembina to lien or take product in-kind and/or allow for termination of the
contract on the occurrence of certain events of default. Each business segment
monitors outstanding accounts receivable on an ongoing basis. Historically,
Pembina has collected its accounts receivable in full.

Debt Service

At the end of 2012, Pembina had exposure to floating interest rates on $525
million in debt. This debt exposure is managed by using derivative financial
instruments. A one percent change in short-term interest rates would have an
annualized impact of $1.4 million on net cash flows. Variations in interest
rates and scheduled principal repayments, if required under the terms of the
banking agreements could result in significant changes in the amounts required
to be applied to debt service before payment of any dividends to Pembina's
shareholders. Certain covenants in the agreements with the lenders may also
limit payments by Pembina's operating subsidiaries. Although Pembina believes
that the existing credit facilities are sufficient, there can be no assurance
that the amount will be adequate for Pembina's financial obligations or that
additional funds can be obtained.

Pembina and its subsidiaries are permitted to borrow funds to finance the
purchase of pipelines and other energy infrastructure assets, to fund capital
expenditures and other financial obligations or expenditures in respect of
those assets and for working capital purposes. Amounts paid in respect of
interest and principal on debt incurred in respect of those assets reduce the
amount of cash flow available for dividends to shareholders. Variations in
interest rates and scheduled principal repayments for which Pembina may not be
able refinance at favourable rates or at all, could result in significant
changes in the amount required to be applied to service debt, which could have
detrimental effects on the amount of cash available for dividends to
shareholders. Certain covenants contained in the agreements with Pembina's
lenders may also limit dividend payments. Although Pembina believes the
existing credit facilities are sufficient for immediate requirements, there
can be no assurance that the amount will be adequate for the future financial
obligations of Pembina or that additional funds will be able to be obtained on
terms favourable to Pembina or at all.

The lenders under Pembina's unsecured credit facilities and senior notes have
also been provided with similar guarantees and subordination agreements. If
Pembina becomes unable to pay its debt service charges or otherwise commits an
event of default such as bankruptcy, payments to all of the lenders will rank
in priority to dividends to shareholders and payments to holders of
convertible debentures.

Pembina, on a consolidated basis, is also required to meet certain financial
covenants under the credit facilities and the senior notes and is subject to
customary restrictions on its operations and activities, including
restrictions on the granting of security, incurring indebtedness and the sale
of its assets.

Credit Ratings

Rating agencies regularly evaluate Pembina, basing their ratings of its
long-term and short-term debt on a number of factors. This includes Pembina's
financial strength as well as factors not entirely within its control,
including conditions affecting the industry in which Pembina operates
generally and the wider state of the economy. There can be no assurance that
one or more of Pembina's credit ratings will not be downgraded.

Pembina's borrowing costs and ability to raise funds are directly impacted by
its credit ratings. Credit ratings may be important to suppliers or
counterparties when they seek to engage in certain transactions. A credit
rating downgrade could potentially impair Pembina's ability to enter into
arrangements with suppliers or counterparties, to engage in certain
transactions, and could limit Pembina's access to private and public credit
markets and increase the costs of borrowing under its existing credit
facilities. A downgrade could also limit Pembina's access to debt markets and
increase its cost of borrowing.

The occurrence of a downgrade in Pembina's credit ratings could adversely
affect Pembina's ability to execute portions of its business strategy and
could have a material adverse effect on its liquidity, results of operations
and capital position.

Changes in Legislation

There can be no assurance that income tax laws, regulatory and environmental
laws or policies and government incentive programs relating to the pipeline or
oil and natural gas industry, will not be changed in a manner which adversely
affects Pembina or its shareholders or other securityholders.

Reliance on Management

Shareholders and other securityholders of Pembina will be dependent on senior
management and directors of Pembina in respect of the governance,
administration and management of all matters relating to Pembina and its
operations and administration. The loss of the services of key individuals
could have a detrimental effect on Pembina.

Potential Conflicts of Interest

Shareholders are dependent upon senior management of Pembina and the directors
of Pembina for the governance, administration and management of Pembina.
Additionally, certain directors and officers of Pembina may be directors or
officers of entities in competition to Pembina. As such, these directors or
officers of Pembina may encounter conflicts of interest in the administration
of their duties with respect to Pembina.

Litigation

Pembina and its various subsidiaries and affiliates are, in the course of
their business, subject to lawsuits and other claims. Defence and settlement
costs associated with such lawsuits and claims can be substantial, even with
respect to lawsuits and claims that have no merit. Due to the inherent
uncertainty of the litigation process, the resolution of any particular legal
proceeding could have a material adverse effect on the financial position or
operating results of Pembina.

Variations in Interest Rates and Foreign Exchange Rates

Variations in interest rates could result in a significant change in the
amount Pembina pays to service debt, potentially impacting dividends to
shareholders. Variations in the exchange rate for the Canadian dollar versus
the U.S. dollar could affect future dividends.

Selected Quarterly Operating Information

                                                                
                                 2012                    2011           2010
                           Q4    Q3    Q2    Q1    Q4    Q3    Q2    Q1    Q4
Average volume                                                       
(mbpd unless stated
otherwise)
Conventional Throughput  480.2 443.9 433.9 466.9 422.8 430.4 411.4 390.3 375.0
Oil Sands & Heavy        870.0 870.0 870.0 870.0 870.0 775.0 775.0 775.0 775.0
Oil^(1)
Gas Services Processing   46.0  45.8  47.5  44.1  45.3  43.6  40.9  39.4  42.1
(mboe/d)^(2)
NGL sales volume         115.8  86.7  90.4                              
(mboe/d)

^(1)Oil Sands & Heavy Oil throughput refers to contracted capacity.
^(2)Converted to mboe/d from MMcf/d at a 6:1 ratio.

Selected Quarterly Financial Information

                                                                      
                                 2012                          2011            2010
($ millions,               Q4          Q3     Q2    Q1    Q4    Q3    Q2    Q1    Q4
except where
noted)
Revenue               1,265.7       815.3  870.9 475.5 468.1 300.6 512.4 394.9 290.7
Operations               86.0        69.5   67.7  48.4  55.1  54.4  37.6  44.8  41.9
Cost of goods           968.6       565.5  641.9 299.1 308.0 145.8 364.3 254.2 161.8
sold including
product purchases
Realized gain            11.0       (2.8) (12.4) (0.3)   0.9   3.2 (0.2)   1.4 (0.8)
(loss) on
commodity-related
derivative
financial
instruments
Operating               222.1       177.5  148.9 127.7 105.9 103.6 110.3  97.3  86.2
margin^(1)
Depreciation and         47.8        51.6   52.5  21.7  19.6  17.8  15.8  14.8  15.6
amortization
included in
operations
Unrealized gain         (2.2)      (23.0)   64.8 (3.5)   0.9   0.7   3.3   0.3   1.8
(loss) on
commodity-related
derivative
financial
instruments
Gross profit            172.1       102.9  161.2 102.5  87.2  86.5  97.8  82.8  72.4
Adjusted                199.0       153.8  125.9 111.4  88.2  89.9 103.3  87.2  79.1
EBITDA^(1)
Cash flow from          139.5       130.9   24.1  65.3  73.8  87.7  49.5  74.5  54.6
operating
activities
Cash flow from           0.48        0.45   0.08  0.39  0.44  0.52  0.30  0.45  0.33
operating
activities per
common share ($
per share)
Adjusted cash           172.3       133.2   89.5  98.8  66.0  82.0  81.8  76.0  62.6
flow from
operating
activities^(1)
Adjusted cash            0.59        0.46   0.31  0.59  0.39  0.49  0.49  0.45  0.39
flow from
operating
activities per
common
share^(1)($ per
share)
Earnings for the         81.3        30.7   80.4  32.6  45.0  30.1  48.0  42.5  55.2
period
Earnings per                                                               
common share
($ per share)
    Basic               0.28        0.11   0.28  0.19  0.27  0.18  0.29  0.25  0.34
    Diluted             0.28        0.11   0.28  0.19  0.27  0.18  0.29  0.25  0.33
Common shares                                                              
outstanding
(millions):
    Weighted           291.9       289.2  285.3 168.3 167.4 167.6 167.3 167.0 165.0
     average
     (basic)
    Weighted           292.5       289.7  286.0 168.9 168.2 168.2 168.0 167.6 171.7
     average
     (diluted)
    End of             293.2       290.5  287.8 169.0 167.9 167.7 167.5 167.1 166.9
     period
Dividends               118.4       117.3  116.2  65.7  65.4  65.4  65.3  65.1  64.6
declared
Dividends per     0.405 0.405  0.405 0.390 0.390 0.390 0.390 0.390 0.390
common share($
per share)

^(1)Refer to "Non-GAAP measures."

During the above periods, Pembina's results were influenced by the following
factors and trends:

  *Increased oil production from customers operating in the Cardium and Deep
    Basin Cretaceous formations of west central Alberta, which has resulted in
    increased service offerings in these areas, as well as new connections and
    capacity expansions;
  *Increased liquids-rich natural gas production from producers in the WCBS
    (Deep Basin, Montney, Cardium and emerging Duvernay Shale plays), which
    has resulted in increased gas gathering and processing at the Company's
    gas services assets and additional associated NGL transported on its
    pipelines;
  *Revenue contribution from the Nipisi and Mitsue Pipelines, which were
    completed in June and July of 2011; and
  *The Acquisition of Provident, which closed on April 2, 2012 (for more
    details please see Note 5 of the Consolidated Financial Statements for the
    year ended December 31, 2012).

Selected Annual Financial Information

                                                              
($ millions, except where noted)              2012          2011          2010
Revenue                                    3,427.4 1,676.0 1,231.8
Earnings                                     225.0         165.7   175.8
             Per share - basic               0.87    0.99    1.08
             Per share - diluted             0.87    0.99    1.07
Total assets                               8,276.5 3,339.2 2,856.8
Long-term financial liabilities^(1)        3,004.7 1,752.9 1,599.4
Declared dividends per share ($ per share)    1.61    1.56    1.56

      Includes loans and borrowings, convertible debentures, long-term
^(1) derivative financial instrument, provisions and other long-term
      liabilities.

Additional Information

Additional information about Pembina and legacy Provident filed with Canadian
securities commissions and the United States Securities Commission ("SEC"),
including quarterly and annual reports, Annual Information Forms (filed with
the SEC under Form 40-F), Management Information Circulars and financial
statements can be found online at www.sedar.com, www.sec.gov and Pembina's
website at www.pembina.com.

Non-GAAP Measures

Throughout this MD&A, Pembina has used the following terms that are not
defined by GAAP but are used by Management to evaluate performance of Pembina
and its business. Since certain Non-GAAP financial measures may not have a
standardized meaning, securities regulations require that Non-GAAP financial
measures are clearly defined, qualified and reconciled to their nearest GAAP
measure. Concurrent with the Acquisition of Provident, certain Non-GAAP
measures definitions have changed from those previously used to better reflect
the changes in aspects of Pembina's business activities. Except as otherwise
indicated, these Non-GAAP measures are calculated and disclosed on a
consistent basis from period to period. Specific adjusting items may only be
relevant in certain periods.

Earnings before interest, taxes, depreciation and amortization ("EBITDA")

EBITDA is commonly used by Management, investors and creditors in the
calculation of ratios for assessing leverage and financial performance and is
calculated as results from operating activities plus share of profit from
equity accounted investees (before tax) plus depreciation and amortization
(included in operations and general and administrative expense) and unrealized
gains or losses on commodity-related derivative financial instruments.

Adjusted EBITDA is EBITDA excluding acquisition-related expenses in connection
with the Acquisition.

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except per share      2012 2011 2012 2011
amounts)
Results from operating activities       144.3       65.5      416.5      290.7
Share of profit from equity               2.0        3.2        6.2       12.9
accounted investees
(before tax, depreciation and
amortization)
Depreciation and amortization            49.5       20.4      179.4       70.2
Unrealized loss (gain) on                 2.2      (0.9)     (36.1)      (5.2)
commodity-related derivative
financial instruments
EBITDA                                  198.0       88.2      566.0      368.6
Add:                                                                      
Acquisition-related expenses              1.0                 24.1          
Adjusted EBITDA                         199.0       88.2      590.1      368.6
EBITDA per common share - basic          0.68       0.53       2.19       2.20
(dollars)
Adjusted EBITDA per common share -       0.68       0.53       2.28       2.20
basic (dollars)

Adjusted earnings

Adjusted earnings is commonly used by Management for assessing and comparing
financial performance each reporting period and is calculated as earnings
before tax excluding unrealized gains or losses on derivative financial
instruments and acquisition-related expenses in connection with the
Acquisition plus share of profit from equity accounted investees (before tax).

                                                               
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions, except per share      2012 2011 2012 2011
amounts)
Earnings before income tax and          108.5       43.3      301.3      198.8
equity accounted investees
Add (deduct):                                                             
Unrealized (gains) losses on fair         6.4      (1.6)     (40.2)        2.4
value of derivative financial
instruments
Share of (loss) profit of               (0.1)        2.0      (1.5)        7.7
investments in equity accounted
investees (before tax)
Acquisition-related expenses              1.0                 24.1          
Adjusted earnings                       115.8       43.7      283.7      208.9
Adjusted earnings per common share       0.40       0.26       1.10       1.25
- basic (dollars)

Adjusted cash flow from operating activities

Adjusted cash flow from operating activities is commonly used by Management
for assessing financial performance each reporting period and is calculated as
cash flow from operating activities plus the change in non-cash working
capital and excluding acquisition-related expenses.

                                                        
                                  3 Months Ended
                                     December 31      12 Months Ended
                                     (unaudited)     December 31
($ millions, except per share      2012 2011 2012 2011
amounts)
Cash flow from operating                139.5       73.8      359.8      285.5
activities
Add (deduct):                                                             
Change in non-cash working capital       31.8      (7.8)      109.9       20.3
Acquisition-related expenses              1.0                 24.1          
Adjusted cash flow from operating       172.3       66.0      493.8      305.8
activities
Adjusted cash flow from operating        0.59       0.39       1.91       1.83
activities per common share -
basic (dollars)

Operating margin

Operating margin is commonly used by Management for assessing financial
performance and is calculated as gross profit before depreciation and
amortization included in operations and unrealized gain/loss on
commodity-related derivative financial instruments.

Reconciliation of operating margin to gross profit:

                                                                
                                  3 Months Ended
                                     December 31   12 Months Ended
                                     (unaudited)     December 31
($ millions)                       2012 2011 2012 2011
Revenue                               1,265.7      468.1    3,427.4    1,676.0
Cost of sales:                                                            
 Operations                             86.0       55.1      271.6      191.9
 Cost of goods sold, including         968.6      308.0    2,475.0    1,072.3
  product purchases
 Realized gain (loss) on                11.0        0.9      (4.6)        5.3
  commodity-related derivative
  financial instruments
Operating margin                        222.1      105.9      676.2      417.1
Depreciation and amortization            47.8       19.6      173.6       68.0
included in operations
Unrealized gain (loss) on               (2.2)        0.9       36.1        5.2
commodity-related derivative
financial instruments
Gross profit                            172.1       87.2      538.7      354.3

Beginning in the second quarter of 2012, unrealized gain/loss on
commodity-related derivative financial instruments has been reclassified from
net finance costs to be included in gross profit.

Total enterprise value

Total enterprise value, in combination with other measures, is used by
Management and the investment community to assess the overall market value of
the business. Total enterprise value is calculated based on the market value
of common shares and convertible debentures at a specific date plus senior
debt.

Management believes these supplemental Non-GAAP measures facilitate the
understanding of Pembina's results from operations, leverage, liquidity and
financial positions. Investors should be cautioned that EBITDA, adjusted
EBITDA, adjusted earnings, adjusted cash flow from operating activities,
operating margin and total enterprise value should not be construed as
alternatives to net earnings, cash flow from operating activities or other
measures of financial results determined in accordance with GAAP as an
indicator of Pembina's performance. Furthermore, these Non-GAAP measures may
not be comparable to similar measures presented by other issuers.

Forward-Looking Statements & Information

In the interest of providing our securityholders and potential investors with
information regarding Pembina, including Management's assessment of our future
plans and operations, certain statements contained in this MD&A constitute
forward-looking statements or information (collectively, "forward-looking
statements") within the meaning of the "safe harbour" provisions of applicable
securities legislation. Forward-looking statements are typically identified by
words such as "anticipate", "continue", "estimate", "expect", "may", "will",
"project", "should", "could", "believe", "plan", "intend", "design", "target",
"undertake", "view", "indicate", "maintain", "explore", "entail", "schedule",
"objective", "strategy", "likely", "potential", "envision", "aim", "outlook",
"propose", "goal", "would", and similar expressions suggesting future events
or future performance.

By their nature, such forward-looking statements involve known and unknown
risks, uncertainties and other factors that may cause actual results or events
to differ materially from those anticipated in such forward-looking
statements. Pembina believes the expectations reflected in those
forward-looking statements are reasonable but no assurance can be given that
these expectations will prove to be correct and such forward-looking
statements included in this MD&A should not be unduly relied upon. These
statements speak only as of the date of the MD&A.

In particular, this MD&A contains forward-looking statements, including
certain financial outlook, pertaining to the following:

  *the future levels of cash dividends that Pembina intends to pay to its
    shareholders;
  *capital expenditure-estimates, plans, schedules, rights and activities and
    the planning, development, construction, operations and costs of
    pipelines, gas service facilities, terminalling, storage and hub
    facilities and other facilities or energy infrastructure, including, but
    not limited to, the Northern NGL System, the Peace HVP expansion between
    Fox Creed and Fort Saskatchewan, the LVP expansion between Fox Creek and
    Edmonton, Alberta, the Phase 2 LVP Expansion, the Phase 2 NGL Expansion,
    the joint venture full-service terminal in the Judy Creek area of Alberta
    area, the development program in the Cynthia area west of Drayton Valley,
    offshore export opportunities for propane, the Nipisi and Mitsue pipelines
    expansions, the Saturn facility and associated pipelines, the Resthaven
    facility and associated pipelines, the Nexus expansion, the Redwater
    expansion;
  *future expansion of Pembina's pipelines and other infrastructure;
  *pipeline, processing and storage facility and system operations and
    throughput levels;
  *oil and gas industry exploration and development activity levels;
  *Pembina's strategy and the development of new business initiatives;
  *growth opportunities;
  *expectations regarding Pembina's ability to raise capital and to carry out
    acquisition, expansion and growth plans;
  *treatment under government regulatory regimes including environmental
    regulations and related abandonment and reclamation obligations;
  *future G&A expenses at Pembina
  *increased throughput potential due to increased activity and new
    connections and other initiatives on Pembina's pipelines;
  *future cash flows, potential revenue and cash flow enhancements across
    Pembina's businesses and the maintenance of operating margins;
  *tolls and tariffs and transportation, storage and services commitments and
    contracts;
  *cash dividends and the tax treatment thereof;
  *operating risks (including the amount of future liabilities related to
    pipeline spills and other environmental incidents) and related insurance
    coverage and inspection and integrity programs;
  *the expected capacity, incremental volumes and in-services dates of
    proposed expansions and new developments, including the Northern NGL
    System, the Peace HVP expansion between Fox Creek and Fort Saskatchewan,
    the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP
    Expansion, the Phase 2 NGL Expansion, the Nipisi and Mitsue pipelines, the
    Saturn facility, the Resthaven facility and Nexus;
  *the possibility of offshore export opportunities for propane;
  *the possibility of renegotiating debt terms, repayment of existing debt,
    seeking new borrowing and/or issuing equity;
  *expectations regarding participation in Pembina's DRIP;
  *the expected impact of changes in share price on annual share-based
    incentive expense;
  *inventory and pricing levels in the North American liquids market;
  *Pembina's discretion to hedge natural gas and NGL volumes; and
  *competitive conditions.

Various factors or assumptions are typically applied by Pembina in drawing
conclusions or making the forecasts, projections, predictions or estimations
set out in forward-looking statements based on information currently available
to Pembina. These factors and assumptions include, but are not limited to:

  *the success of Pembina's operations;
  *prevailing commodity prices and exchange rates and the ability of Pembina
    to maintain current credit ratings;
  *the availability of capital to fund future capital requirements relating
    to existing assets and projects, including but not limited to future
    capital expenditures relating to expansion, upgrades and maintenance
    shutdowns;
  *future operating costs;
  *geotechnical and integrity costs associated with the Western System;
  *in respect of the proposed Saturn facility and the Resthaven facility and
    their estimated in-service dates; that all required regulatory and
    environmental approvals can be obtained on the necessary terms in a timely
    manner, that counterparties will comply with contracts in a timely manner;
    that there are no unforeseen events preventing the performance of
    contracts or the completion of such facilities; that such facilities will
    be fully supported by long-term firm service agreements accounting for the
    entire designed throughput at such facilities at the time of such
    facilities' completion; that there are no unforeseen construction costs
    related to the facilities; and that there are no unforeseen material costs
    relating to the facilities which are not recoverable from customers;
  *in respect of the expansion of NGL throughput capacity on the Northern NGL
    System and the crude throughput capacity on the Peace crude system and the
    estimated in-service dates with respect to the same; that Pembina will
    receive regulatory approval; that counterparties will comply with
    contracts in a timely manner; that there are no unforeseen events
    preventing the performance of contracts by Pembina; that there are no
    unforeseen construction costs related to the expansion; and that there are
    no unforeseen material costs relating to the pipelines that are not
    recoverable from customers;
  *in respect of the proposed expansion of Redwater; that Pembina will
    receive regulatory approval; that Pembina will reach satisfactory
    long-term arrangements with customers; that counterparties will comply
    with such contracts in a timely manner; that there are no unforeseen
    events preventing the performance of contracts by Pembina; that there are
    no unforeseen construction costs; and that there are no unforeseen
    material costs relating to the proposed fractionators that are not
    recoverable from customers;
  *in respect of other developments, expansions and capital expenditures
    planned, including the proposed expansion of a number of existing truck
    terminals and construction of new full-service terminals, the expectation
    of additional NGL and crude volumes being transported on the conventional
    pipelines, the proposed expansion plans to strengthen Pembina's
    transportation service options that it provides to producers developing
    the Cardium oil formation located in central Alberta, the installation of
    two remaining pump stations on the Nipisi and Mitsue pipelines, the
    development of seven-fee-for-service storage facilities at Redwater and
    the Redwater fractionator expansion that counterparties will comply with
    contracts in a timely manner; that there are no unforeseen events
    preventing the performance of contracts by Pembina; that there are no
    unforeseen construction costs; and that there are no unforeseen material
    costs relating to the developments, expansions and capital expenditures
    which are not recoverable from customers;
  *the future exploration for and production of oil, NGL and natural gas in
    the capture area around Pembina's conventional and midstream assets,
    including new production from the Cardium formation in western Alberta,
    the demand for gathering and processing of hydrocarbons, and the
    corresponding utilization of Pembina's assets;
  *in respect of the stability of Pembina's dividend; prevailing commodity
    prices, margins and exchange rates; that Pembina's future results of
    operations will be consistent with past performance and management
    expectations in relation thereto; the continued availability of capital at
    attractive prices to fund future capital requirements relating to existing
    assets and projects, including but not limited to future capital
    expenditures relating to expansion, upgrades and maintenance shutdowns;
    the success of growth projects; future operating costs; that
    counterparties to material agreements will continue to perform in a timely
    manner; that there are no unforeseen events preventing the performance of
    contracts; and that there are no unforeseen material construction or other
    costs related to current growth projects or current operations; and
  *prevailing regulatory, tax and environmental laws and regulations.

The actual results of Pembina could differ materially from those anticipated
in these forward-looking statements as a result of the material risk factors
set forth below:

  *the regulatory environment and decisions;
  *the impact of competitive entities and pricing;
  *labour and material shortages;
  *reliance on key alliances and agreements;
  *the strength and operations of the oil and natural gas production industry
    and related commodity prices;
  *non-performance or default by counterparties to agreements which Pembina
    or one or more of its affiliates has entered into in respect of its
    business;
  *actions by governmental or regulatory authorities including changes in tax
    laws and treatment, changes in royalty rates or increased environmental
    regulation;
  *fluctuations in operating results;
  *adverse general economic and market conditions in Canada, North America
    and elsewhere, including changes in interest rates, foreign currency
    exchange rates and commodity prices;
  *the failure to realize the anticipated benefits of the Acquisition;
  *the failure to complete remaining integration of the businesses of Pembina
    and Provident; and
  *the other factors discussed under "Risk Factors" in Pembina's Annual
    Information Form ("AIF") for the year ended December 31, 2012. Pembina's
    MD&A and AIF are available at www.pembina.com and in Canada under
    Pembina's company profile on www.sedar.com and in the U.S. on the
    Company's profile at www.sec.gov.

These factors should not be construed as exhaustive. Unless required by law,
Pembina does not undertake any obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. Any forward-looking statements contained herein are
expressly qualified by this cautionary statement.

MANAGEMENT'S RESPONSIBILITY

The Consolidated Financial Statements of Pembina Pipeline Corporation (the
"Company") are the responsibility of Pembina's management. The financial
statements have been prepared in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards Board,
using management's best estimates and judgments, where appropriate.

Management is responsible for the reliability and integrity of the financial
statements, the notes to the financial statements and other financial
information contained in this report. In the preparation of these financial
statements, estimates are sometimes necessary because a precise determination
of certain assets and liabilities is dependent on future events. Management
believes such estimates have been based on careful judgments and have been
properly reflected in the accompanying financial statements.

Management maintains a system of internal controls designed to provide
reasonable assurance that assets are safeguarded and that accounting systems
provide timely, accurate and reliable financial information.

The Board of Directors of the Company (the "Board") is responsible for
ensuring management fulfils its responsibilities for financial reporting and
internal control. The Board is assisted in exercising its responsibilities
through the Audit Committee, which consists of four non-management directors.
The Audit Committee meets periodically with management and the auditors to
satisfy itself that management's responsibilities are properly discharged, to
review the financial statements and to recommend approval of the financial
statements to the Board.

KPMG LLP, the independent auditors, have audited the Company's financial
statements in accordance with Canadian generally accepted auditing standards
and their report follows. The independent auditors have full and unrestricted
access to the Audit Committee to discuss their audit and their related
findings.

[signed]                        [signed]
                               
Robert B. Michaleski           Peter D. Robertson
Chief Executive Officer        Vice President, Finance & Chief Financial
                                  Officer
Pembina Pipeline Corporation   Pembina Pipeline Corporation
                               
March 1, 2013                 

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Pembina Pipeline Corporation

We have audited the accompanying consolidated financial statements of Pembina
Pipeline Corporation, which comprise the consolidated statement of financial
position as at December 31, 2012 and December 31, 2011, the consolidated
statements of comprehensive income, changes in equity and cash flows for the
years then ended, and notes, comprising a summary of significant accounting
policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these
consolidated financial statements in accordance with International Financial
Reporting Standards as issued by the International Accounting Standards Board,
and for such internal control as management determines is necessary to enable
the preparation of consolidated financial statements that are free from
material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial
statements based on our audits. We conducted our audits in accordance with
Canadian generally accepted auditing standards. Those standards require that
we comply with ethical requirements and plan and perform the audit to obtain
reasonable assurance about whether the consolidated financial statements are
free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the
amounts and disclosures in the consolidated financial statements. The
procedures selected depend on our judgment, including the assessment of the
risks of material misstatement of the consolidated financial statements,
whether due to fraud or error. In making those risk assessments, we consider
internal control relevant to the entity's preparation and fair presentation of
the consolidated financial statements in order to design audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the entity's internal control. An audit also
includes evaluating the appropriateness of accounting policies used and the
reasonableness of accounting estimates made by management, as well as
evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is
sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all
material respects, the consolidated financial position of Pembina Pipeline
Corporation as at December 31, 2012 and December 31, 2011, and its
consolidated financial performance and its consolidated cash flows for the
years then ended in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board.

[signed]

KPMG LLP

Calgary, Alberta

March 1, 2013

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

                                                                  
As at December 31
($ thousands)                                       Note        2012      2011
Assets                                                                     
Current assets
     Cash and cash equivalents                              27,336         
     Trade receivables and other                      6     331,692   148,267
     Derivative financial instruments                27       7,528     4,643
     Inventory                                             108,096    21,235
                                                           474,652   174,145
Non-current assets                                                         
     Property, plant and equipment                    7   5,014,542 2,747,530
     Intangible assets and goodwill                   8   2,622,677   243,904
     Investments in equity accounted investees        9     161,205   161,002
     Derivative financial instruments                27         343     1,807
     Other receivables                                6       3,080    10,814
                                                         7,801,847 3,165,057
Total Assets                                              8,276,499 3,339,202
Liabilities and Shareholders' Equity                                       
Current liabilities
     Bank indebtedness                                                  676
     Trade payables and accrued liabilities          11     344,740   166,646
     Dividends payable                                      39,586    21,828
     Loans and borrowings                            12      11,652   323,927
     Derivative financial instruments                27      15,932     4,725
                                                           411,910   517,802
Non-current liabilities                                                    
     Loans and borrowings                            12   1,932,774 1,012,061
     Convertible debentures                          13     609,968   289,365
     Derivative financial instruments                27      51,759    12,813
     Employee benefits                               25      28,623    16,951
     Share-based payments                                   17,239    14,060
     Deferred revenue                                        3,099     2,185
     Provisions                                      14     361,206   405,433
     Deferred tax liabilities                        10     584,489   106,915
                                                         3,589,157 1,859,783
Total Liabilities                                         4,001,067 2,377,585
Shareholders' Equity                                                       
Equity attributable to shareholders of the Company:                        
     Share capital                                   15   5,324,058 1,811,734
     Deficit                                           (1,027,678) (834,921)
     Accumulated other comprehensive income               (26,123)  (15,196)
                                                         4,270,257   961,617
Non-controlling interest                                      5,175         
Total Equity                                              4,275,432   961,617
Total Liabilities and Shareholders' Equity                8,276,499 3,339,202

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

                                                                
Year Ended December 31
($ thousands, except per share amounts)              Note      2012       2011
Revenue                                                16 3,427,402  1,676,050
Cost of sales                                          17 2,920,208  1,332,205
Gain on commodity-related derivative financial         27    31,529     10,471
instruments
Gross profit                                               538,723    354,316
                                                                          
  General and administrative                          18    97,488     62,191
  Acquisition-related and other expense                    24,748      1,429
                                                          122,236     63,620
                                                                          
Results from operating activities                          416,487    290,696
                                                                          
  Finance income                                          (6,611)    (1,374)
  Finance costs                                           121,751     93,301
  Net finance costs                                   21   115,140     91,927
                                                                          
Earnings before income tax and equity accounted            301,347    198,769
investees
                                                                          
  Share of loss (profit) of investments in equity           1,056    (5,766)
   accounted investees, net of tax
                                                                          
  Income tax expense                                  10    75,339     38,869
                                                                          
Earnings for the year                                      224,952    165,666
                                                                          
Other comprehensive income (loss)                                          
  Defined benefit plan actuarial losses                  (14,568)   (14,159)
  Income tax benefit                                  10     3,641      3,540
  Other comprehensive loss for the year               25  (10,927)   (10,619)
Total comprehensive income for the year                    214,025    155,047
Earnings attributable to:                                                  
  Shareholders of the Company                             224,844    165,666
  Non-controlling interest                                    108          
                                                          224,952    165,666
Total comprehensive income attributable to:                                
  Shareholders of the Company                             213,917    155,047
  Non-controlling interest                                    108          
                                                          214,025    155,047
Earnings per share attributable to shareholders of                         
the Company:
Basic and diluted earnings per share (dollars)         23      0.87 0.99

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

                                                                            
                     Attributable to Shareholders of the Company                        
                                             Accumulated
                                                   Other
                         Share             Comprehensive           Non-controlling     Total
($ thousands)   Note   Capital     Deficit        Income     Total        Interest    Equity
December 31,        1,794,536   (739,351)       (4,577) 1,050,608                1,050,608
2010
Total                                                                                
comprehensive
income for
period
  Earnings                      165,666                165,666                  165,666
Other                                                                                
comprehensive
income
  Defined        25                          (10,619)  (10,619)                 (10,619)
   benefit plan
   actuarial
   losses, net
   of tax
Total                            165,666      (10,619)   155,047                  155,047
comprehensive
income for the
year
Transactions                                                                         
with
shareholders of
the Company
  Share-based    15    16,978                            16,978                   16,978
   payment
   transactions
  Debenture      15       220                               220                      220
   conversions
   and other
  Dividends      15            (261,236)              (261,236)                (261,236)
   declared
Total                  17,198   (261,236)              (244,038)                (244,038)
transactions
with
shareholders of
the Company
December 31,        1,811,734   (834,921)      (15,196)   961,617                  961,617
2011
                                                                                    
Total                                                                                
comprehensive
income for
period
Earnings                         224,844                224,844             108   224,952
Other                                                                                
comprehensive
income
Defined benefit   25                          (10,927)  (10,927)                 (10,927)
plan actuarial
losses, net of
tax
Total                            224,844      (10,927)   213,917             108   214,025
comprehensive
income (loss)
for the year
Transactions                                                                         
with
shareholders of
the Company
Share-based       15     9,221                             9,221                    9,221
payment
transactions
Debenture         15       432                               432                      432
conversions and
other
Dividends         15            (417,601)              (417,601)                (417,601)
declared
Common shares      5 3,283,976                         3,283,976                3,283,976
issued on
acquisition
Dividend          15   218,695                           218,695                  218,695
reinvestment
plan
Total               3,512,324   (417,601)              3,094,723                3,094,723
transactions
with
shareholders of
the Company
Non-controlling    5                                                     5,067     5,067
interest
assumed on
acquisition
December 31,        5,324,058 (1,027,678)      (26,123) 4,270,257           5,175 4,275,432
2012

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                  
Year Ended December 31 ($ thousands)                  Note      2012      2011
Cash provided by (used in):                                                
Operating activities:                                                      
Earnings for the year                                       224,952   165,666
Adjustments for:                                                           
  Depreciation and amortization                        19   179,386    70,219
  Unrealized gain on commodity-related derivative         (36,100)   (5,176)
   financial instruments
  Net finance costs                                    21   115,140    91,927
  Share of loss (profit) of investments in equity            1,056   (5,766)
   accounted investees, net of tax
  Deferred income tax expense                          10    75,802    38,869
  Share-based payments expense                         26    17,028    18,651
  Employee future benefits expense                     25     7,225     4,825
  Other                                                      1,006       989
  Changes in non-cash working capital                  24 (109,881)  (20,297)
  Payments from equity accounted investees              9    17,428    16,869
  Decommissioning liability expenditures               14   (4,944)   (3,123)
  Employer future benefit contributions                25  (10,000)   (8,000)
  Net interest paid                                      (118,291)  (80,115)
Cash flow from operating activities                         359,807   285,538
Financing activities:                                                      
  Bank borrowings                                            6,861   153,137
  Repayment of loans and borrowings                       (61,332)  (90,596)
  Issuance of debt                                         450,000   250,000
  Financing fees                                           (7,343)   (1,774)
  Exercise of stock options                                  7,295    16,059
  Dividends paid (net of shares issued under the       15 (181,148) (261,102)
   Dividend Reinvestment Plan)
Cash flow from financing activities                         214,333    65,724
Investing activities:                                                      
  Net capital expenditures                               (546,820) (477,335)
  Contributions to equity accounted investees              (8,182)         
  Cash acquired on acquisition                               8,874         
Cash flow used in investing activities                    (546,128) (477,335)
Change in cash                                               28,012 (126,073)
Cash (bank indebtedness), beginning of year                   (676)   125,397
Cash and cash equivalents (bank indebtedness), end of        27,336     (676)
year

See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. REPORTING ENTITY

Pembina Pipeline Corporation ("Pembina" or the "Company") is an energy
transportation and service provider domiciled in Canada. The consolidated
financial statements ("Financial Statements") include the accounts of the
Company, its subsidiary companies, partnerships and any interests in
associates and jointly controlled entities as at and for the year ended
December 31, 2012. These Financial Statements present fairly the financial
position, financial performance and cash flows of the Company.

Pembina owns or has interests in pipelines that transport conventional crude
oil and natural gas liquids ("NGL"), oil sands and heavy oil pipelines, gas
gathering and processing facilities, and an NGL infrastructure and logistics
business. Facilities are located in Canada and in the U.S. Pembina also offers
midstream services that span across its operations.

2. BASIS OF PREPARATION

a.Statement of compliance

The Financial Statements have been prepared in accordance with International
Financial Reporting Standards ("IFRS"), as issued by the International
Accounting Standards Board ("IASB").

The Financial Statements were authorized for issue by the Board of Directors
on March 1, 2013.

b.Basis of measurement

The Financial Statements have been prepared on the historical cost basis
except for the following material items in the statement of financial
position:

  *derivative financial instruments are measured at estimated fair value; and
  *liabilities for cash-settled share-based payment arrangements are measured
    at estimated fair value.

c.Functional and presentation currency

The Financial Statements are presented in Canadian dollars, which is the
Company's functional currency. All financial information presented in Canadian
dollars has been disclosed in thousands except where noted.

d.Use of estimates and judgments

The preparation of the Financial Statements in conformity with IFRS requires
management to make judgments, estimates and assumptions that are based on the
circumstances and estimates at the date of the financial statements and affect
the application of accounting policies and the reported amounts of assets,
liabilities, income and expenses. Actual results may differ from these
estimates.

Judgments, estimates and underlying assumptions are reviewed on an ongoing
basis. Revisions to accounting estimates are recognized in the period in which
the estimates are revised and in any future periods affected.

The following judgment and estimation uncertainties are those management
considers material to the Company's financial statements:

Judgments

(i)Business combinations

Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires Management to make
judgments about future possible events. The assumptions with respect to
determining the fair value of property, plant and equipment and intangible
assets acquired generally require the most judgment.

(ii)Componentization

The componentization of the Company's assets are based on management's
judgment of what components constitute a significant cost in relation to the
total cost of an asset and whether these components have similar or dissimilar
patterns of consumption and useful lives for purposes of calculating
depreciation and amortization.

(iii)Depreciation and amortization

Depreciation and amortization of property, plant and equipment and intangible
assets are based on management's judgment of the most appropriate method to
reflect the pattern of an asset's future economic benefit expected to be
consumed by the Company. Among other factors, these judgments are based on
industry standards and historical experience.

Estimates

(i)Inventory

Due to the inherent limitations in metering and the physical properties of
storage caverns and pipelines, the determination of precise volumes of NGL
held in inventory at such locations is subject to estimation. Actual
inventories of NGL within storage caverns can only be determined by draining
of the caverns.

(ii)Financial derivative instruments

The Company's financial derivative instruments are 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.

(iii)Business Combinations

Estimates of future cash flows, forecast prices, interest rates and discount
rates are made in determining the fair value of assets acquired and
liabilities assumed for allocation of the purchase price. Changes in any of
the assumptions or estimates used in determining the fair value of acquired
assets and liabilities could impact the amounts assigned to assets,
liabilities, intangible assets and goodwill in the purchase price analysis.
Future net earnings can be affected as a result of changes in future
depreciation and amortization, asset or goodwill impairment.

(iv)Defined benefit obligations

The calculation of the defined benefit obligation is sensitive to many
estimates, but most significantly of which include the discount rate and
long-term rate of return on assets applied.

(v)Provisions and contingencies

Provisions recognized are based on management's judgment about assessing
contingent liabilities and timing, scope and amount of liabilities. Management
uses judgment in determining the likelihood of realization of contingent
assets and liabilities to determine the outcome of contingencies.

Based on the long-term nature of the decommissioning provision, the biggest
uncertainties in estimating the provision are the discount rates used, the
costs that will be incurred and the timing of when these costs will occur. In
addition, in determining the provision it is assumed that the Company will
utilize technology and materials that are currently available.

(vi)Share-based payments

Compensation costs pursuant to the share-based compensation plans are subject
to estimated fair values, forfeiture rates and the future attainment of
performance criteria.

(vii)Deferred taxes

The calculation of the deferred tax asset or liability is based on assumptions
about the timing of many taxable events and the enacted or substantively
enacted rated anticipated to apply to income in the years in which temporary
differences are expected to be realized or reversed.

(viii)Depreciation and amortization

Estimated useful lives of property, plant and equipment is based on
management's assumptions and estimates of the physical useful lives of the
assets, the economic life, which may be associated with the reserve life and
commodity type of the production area, in addition to the estimated residual
value.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies are set out below have been applied consistently to
all periods presented in these Financial Statements.

a.Basis of consolidation

i)Business combinations

The Company measures goodwill as the fair value of the consideration
transferred including the recognized amount of any non-controlling interest in
the acquiree, less the net recognized amount (generally fair value) of the
identifiable assets acquired and liabilities assumed, all measured as of the
acquisition date. When the excess is negative, a bargain purchase gain is
recognized immediately in profit or loss.

The Company elects on a transaction-by-transaction basis whether to measure
non-controlling interest at its fair value, or at its proportionate share of
the recognized amount of the identifiable net assets, at the acquisition date.

Non-controlling interests represent equity interests in subsidiaries owned by
outside parties. The share of net assets of subsidiaries attributable to
non-controlling interests is presented as a separate component of equity.
Their share of net income and other comprehensive income is also recognized in
this separate component of equity. Changes in the Company's ownership interest
in subsidiaries that do not result in a loss of control are accounted for as
equity transactions. Adjustments to non-controlling interests are based on a
proportionate amount of the net assets of the subsidiary. No adjustments are
made to goodwill and no gain or loss is recognized in profit or loss.

Transaction costs, other than those associated with the issue of debt or
equity securities, that the Company incurs in connection with a business
combination are expensed as incurred.

ii)Subsidiaries

Subsidiaries are entities controlled by the Company. The financial statements
of subsidiaries are included in the Financial Statements from the date that
control commences until the date that control ceases. The accounting policies
of subsidiaries are aligned with the policies adopted by the Company.

iii)Investments in associates and jointly controlled entities (equity
accounted investees)

Associates are those entities in which the Company has significant influence,
but not control or joint control, over the financial and operating policies.
Significant influence is presumed to exist when the Company holds between 20
and 50 percent of the voting power of another entity. Joint ventures are those
entities over whose activities the Company has joint control, established by
contractual agreement and requiring unanimous consent for strategic financial
and operating decisions.

The Financial Statements include the Company's share of the profit or loss and
other comprehensive income, after adjustments to align the accounting policies
with those of the Company, from the date that significant influence or joint
control commences until the date that significant influence or joint control
ceases. The Company's investments in its associates and joint ventures are
accounted for using the equity method and are recognized initially at cost,
including transaction costs.

When the Company's share of losses exceeds its interest in an equity accounted
investee, the carrying amount of that interest, including any long-term
investments, is reduced to nil, and the recognition of further losses is
discontinued except to the extent that the Company has an obligation or has
made payments on behalf of the investee.

iv)Jointly controlled operations

A jointly controlled operation is a joint venture carried on by each venture
using its own assets in pursuit of the joint operations. The Financial
Statements include the assets that the Company controls and the liabilities
that it incurs in the course of pursuing the joint operation, and the expenses
that the Company incurs and its share of the income that it earns from the
joint operation.

v)Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealized revenue and expenses
arising from intra-group transactions, are eliminated in preparing the
consolidated financial statements. Unrealized gains arising from transactions
with equity-accounted investees are eliminated against the investment to the
extent of the Company's interest in the investee. Unrealized losses are
eliminated in the same way as unrealized gains, but only to the extent that
there is no evidence of impairment.

vi)Foreign currency

Transactions in foreign currencies are translated to the Company's functional
currency, Canadian dollars, at exchange rates at the dates of the
transactions. Monetary assets and liabilities denominated in foreign
currencies at the reporting date are retranslated to the Company's functional
currency at the exchange rate at that date. The foreign currency gain or loss
on monetary items is the difference between amortized cost in the functional
currency at the beginning of the period, adjusted for effective interest and
payments during the period, and the amortized cost in foreign currency
translated at the exchange rate at the end of the reporting period.

Non-monetary assets and liabilities denominated in foreign currencies that are
measured at fair value are retranslated to the functional currency at the
exchange rate at the date that the fair value was determined. Non-monetary
items that are measured in terms of historical cost in a foreign currency are
translated using the exchange rate at the date of the transaction.

Foreign currency differences arising on retranslation are recognized in profit
or loss.

b.Inventories

Inventories are measured at the lower of cost and net realizable value and
consist primarily of crude oil and NGL. The cost of inventories is determined
using the weighted average costing method and includes direct purchase costs
and when applicable, costs of production, extraction, fractionation costs, and
transportation costs. Net realizable value is the estimated selling price in
the ordinary course of business less the estimated selling costs. All changes
in the value of the inventories are reflected in inventories and cost of
sales.

c.Financial instruments

Financial assets and liabilities are offset and the net amount presented in
the statement of financial position when, and only when, the Company has a
legal right to offset the amounts and intends either to settle on a net basis
or to realize the asset and settle the liability simultaneously.

i)Non-derivative financial assets

The Company initially recognizes loans and receivables and deposits on the
date that they are originated. All other financial assets (including assets
designated at fair value through profit or loss) are recognized initially on
the trade date at which the Company becomes a party to the contractual
provisions of the instrument.

The Company derecognizes a financial asset when the contractual rights to the
cash flows from the asset expire, or it transfers the rights to receive the
contractual cash flows on the financial asset in a transaction in which
substantially all the risks and rewards of ownership of the financial asset
are transferred. Any interest in transferred financial assets that is created
or retained by the Company is recognized as a separate asset or liability.

The Company classifies non-derivative financial assets into the following
categories:

Cash and cash equivalents

Cash and cash equivalents comprise cash balances, call deposits and short-term
investments with original maturities of ninety days or less that are subject
to an insignificant risk of changes in their fair value, and are used by the
Company in the management of its short-term commitments.

Trade and other receivables

Trade and other receivables are financial assets with fixed or determinable
payments that are not quoted in an active market. Such assets are recognized
initially at fair value plus any directly attributable transaction costs.
Subsequent to initial recognition, loans and receivables are measured at
amortized cost using the effective interest method less any impairment losses.

ii)Non-derivative financial liabilities

The Company initially recognizes debt securities issued and subordinated
liabilities on the date that they are originated. All other financial
liabilities (including liabilities designated at fair value through profit or
loss) are recognized initially on the trade date at which the Company becomes
a party to the contractual provisions of the instrument.

The Company derecognizes a financial liability when its contractual
obligations are discharged, cancelled or expire.

The Company's non-derivative financial liabilities are comprised of the
following: bank indebtedness, trade payables and accrued liabilities,
dividends payable, loans and borrowings including finance lease obligations
and the liability component of convertible debentures.

Such financial liabilities are recognized initially at fair value plus any
directly attributable transaction costs. Subsequent to initial recognition
these financial liabilities are measured at amortized cost using the effective
interest method.

Bank overdrafts that are repayable on demand and form an integral part of the
Company's cash management are included as a component of cash and cash
equivalents for the purpose of the statement of cash flows.

iii)Share capital

Common shares

Common shares are classified as equity. Incremental costs directly
attributable to the issue of common shares and share options are recognized as
a deduction from equity, net of any tax effects.

iv)Compound financial instruments

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 Pembina 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 derivative financial instruments. Debentures without a cash
conversion option are settled in shares on conversion, and therefore the
conversion feature is presented within equity, in accordance with its
contractual substance.

On initial recognition and at each reporting date, the embedded conversion
feature is measured using a method whereby the fair value is measured using an
option pricing model. Subsequent to initial recognition, any unrealized gains
or losses arising from fair value changes are recognized through profit or
loss in the statement of comprehensive income at each reporting date. If the
conversion feature is included in equity, it is not remeasured subsequent to
initial recognition. On initial recognition, the debt component, net of issue
costs, is recorded as a financial liability and accounted for at amortized
cost. Subsequent to initial recognition, the debt component is accreted to the
face value of the debentures using the effective interest rate method. Upon
conversion, the corresponding portions of the debt and equity are removed from
those captions and transferred to share capital.

v)Derivative financial instruments

The Company holds derivative financial instruments to manage its interest
rate, commodity, power costs and foreign exchange risk exposures as well as
cash conversion features on convertible debentures and a redemption liability.
Embedded derivatives are separated from the host contract and accounted for
separately if the economic characteristics and risks of the host contract and
the embedded derivative meet the definition of a derivative, and the combined
instrument is not measured at fair value through profit or loss. Derivatives
are recognized initially at fair value with attributable transaction costs
recognized in profit or loss as incurred. Subsequent to initial recognition,
derivatives are measured at fair value and changes in non-commodity-related
derivatives are recognized immediately in profit or loss in net finance costs
and changes in commodity-related derivatives are recognized immediately in
profit or loss in operating activities.

d.Property, plant and equipment

i)Recognition and measurement

Items of property, plant and equipment are measured at cost less accumulated
depreciation and accumulated impairment losses.

Cost includes expenditures that are directly attributable to the acquisition
of the asset. The cost of self-constructed assets includes the cost of
materials and direct labour, any other costs directly attributable to bringing
the assets to a working condition for their intended use, estimated
decommissioning provisions and borrowing costs on qualifying assets.

Cost also may include any gain or loss realized on foreign currency
transactions directly attributable to the purchase or construction of
property, plant and equipment. Purchased software that is integral to the
functionality of the related equipment is capitalized as part of that
equipment.

When parts of an item of property, plant and equipment have different useful
lives, they are accounted for as separate components of property, plant and
equipment.

The gain or loss on disposal of an item of property, plant and equipment is
determined by comparing the proceeds from disposal with the carrying amount of
property, plant and equipment, and are recognized within other expense
(income) in profit or loss.

ii)Subsequent costs

The cost of replacing a part of an item of property, plant and equipment is
recognized in the carrying amount of the item if it is probable that the
future economic benefits embodied within the part will flow to the Company,
and its cost can be measured reliably. The carrying amount of the replaced
part is derecognized. The cost of maintenance and repair expenses of the
property, plant and equipment are recognized in profit or loss as incurred.

iii)Depreciation

Depreciation is based on the cost of an asset less its residual value.
Significant components of individual assets, other than land, are assessed and
if a component has a useful life that is different from the remainder of the
asset, that component is depreciated separately.

Depreciation is recognized in profit or loss on a straight line or declining
balance basis, which most closely reflects the expected pattern of consumption
of the future economic benefits embodied in the asset. Pipeline assets and
facilities are generally depreciated using the straight line method over 3 to
75 years (an average of 47 years) or declining balance method at rates ranging
from 3 percent to 37 percent per annum (an average rate of 15 percent per
annum). Facilities and equipment are depreciated using straight line method
over 3 to 75 years (at an average rate of 35 years) or declining balance
method at rates ranging from 3 to 37 percent (at an average rate of 12 percent
per annum). Other assets are depreciated using the straight line method over 2
to 45 years (an average of 17 years) or declining balance method at rates
ranging from 3 percent to 37 percent (at an average rate of 2 percent per
annum). These rates are established to depreciate remaining net book value
over the economic lives or contractual duration of the related assets.

Leased assets are depreciated over the shorter of the lease term and their
useful lives unless it is reasonably certain that the Company will obtain
ownership by the end of the lease term.

Depreciation methods, useful lives and residual values are reviewed annually
and adjusted if appropriate.

e.Intangible assets

i)Goodwill

Goodwill that arises upon acquisitions is included in intangible assets. See
note 3(a)(i) for the policy on measurement of goodwill at initial recognition.

Subsequent measurement

Goodwill is measured at cost less accumulated impairment losses.

In respect of equity accounted investees, the carrying amount of goodwill is
included in the carrying amount of the investment, and an impairment loss on
such an investment is allocated to the investment and not to any asset,
including goodwill, that forms the carrying amount of the equity accounted
investee.

ii)Other intangible assets

Other intangible assets acquired individually by the Company and have finite
useful lives are recognized and measured at cost less accumulated amortization
and accumulated impairment losses.

iii)Subsequent expenditures

Subsequent expenditures are capitalized only when it increases the future
economic benefits embodied in the specific asset to which it relates. All
other expenditures are recognized in profit or loss as incurred.

iv)Amortization

Amortization is based on the cost of an asset less its residual value.

Amortization is recognized in profit or loss on a straight-line basis over the
estimated useful lives of intangible assets, other than goodwill, from the
date that they are available for use. The estimated useful lives of other
intangible assets with finite useful lives range from 3 to 25 years (at an
average of 17 years).

Amortization methods, useful lives and residual values are reviewed annually
and adjusted if appropriate.

f.Leased assets

Leases which the Company assumes substantially all the risks and rewards of
ownership are classified as finance leases. The leased asset is initially
recognized at an amount equal to the lower of its fair value and the present
value of the minimum lease payments. Subsequent to initial recognition, the
asset is accounted for in accordance with the accounting policy applicable to
that asset.

Other leases are operating leases and are not recognized in the Company's
statement of financial position.

g.Lease payments

Payments made under operating leases are recognized in profit or loss on a
straight-line basis over the term of the lease. Lease incentives received are
recognized as an integral part of the total lease expense, over the term of
the lease.

Minimum lease payments made under finance leases are apportioned between the
finance cost and the reduction of the outstanding liability. The finance cost
is allocated to each period during the lease term so as to produce a constant
periodic rate of interest on the remaining balance of the liability.
Contingent lease payments are accounted for by revising the minimum lease
payments over the remaining life.

i)Determining whether an arrangement contains a lease

At inception of an arrangement, the Company determines whether such an
arrangement is or contains a lease. A specific asset is the subject of a lease
if fulfilment of the arrangement is dependent on the use of that specified
asset. An arrangement conveys the right to use the asset if the arrangement
conveys to a lessee the right to control the use of the underlying asset.

At inception or upon reassessment of the arrangement, the Company separates
payments and other consideration required by such an arrangement into those
for the lease and those for other elements on the basis of their relative fair
values. If the Company concludes for a finance lease that it is impracticable
to separate the payments reliably, an asset and liability are recognized at an
amount equal to the fair value of the underlying asset. Subsequently, the
liability is reduced as payments are made and an imputed finance cost on the
liability is recognized using the Company's incremental borrowing rate.

h.Impairment

i)Non-derivative financial assets

A financial asset not carried at fair value through profit or loss is assessed
at each reporting date to determine whether there is objective evidence that
it is impaired. A financial asset is impaired if there is objective evidence
of impairment as a result of one or more events that occurred after the
initial recognition of the asset, and that a loss event had a negative effect
on the estimated future cash flows of that asset and the impact can be
estimated reliably.

Objective evidence that financial assets are impaired can include default or
delinquency by a debtor, restructuring of an amount due to the Company on
terms that the Company would not consider otherwise, indications that a debtor
or issuer will enter bankruptcy, adverse changes in the payment status of
borrowers or issuers in the Company, economic conditions that correlate with
defaults or the disappearance of an active market for a security or a
significant or prolonged decline in the fair value below cost.

Trade and other receivables ("Receivables")

The Company considers evidence of impairment for Receivables at both a
specific asset and collective level. All individually significant Receivables
are assessed for specific impairment. All individually significant Receivables
found not to be specifically impaired are then collectively assessed for any
impairment that has been incurred but not yet identified. Receivables that are
not individually significant are collectively assessed for impairment by
grouping together Receivables with similar risk characteristics.

In assessing collective impairment, the Company uses historical trends of the
probability of default, timing of recoveries and the amount of loss incurred,
adjusted for management's judgment as to whether current economic and credit
conditions are such that the actual losses are likely to be greater or less
than suggested by historical trends.

An impairment loss in respect of a financial asset measured at amortized cost
is calculated as the difference between its carrying amount and the present
value of the estimated future cash flows discounted at the asset's original
effective interest rate. Losses are recognized in profit or loss and reflected
in an allowance account against Receivables. Interest on the impaired asset
continues to be recognized through the unwinding of the discount. When a
subsequent event causes the amount of impairment loss to decrease, the
decrease in impairment loss is reversed through profit or loss.

ii)Non-financial assets

The carrying amounts of the Company's non-financial assets, other than line
fill and assets arising from employee benefits and deferred tax assets, are
reviewed at each reporting date to determine whether there is any indication
of impairment. If any such indication exists, then the asset's recoverable
amount is estimated.

For goodwill and intangible assets that have indefinite useful lives or that
are not yet available for use, the recoverable amount is estimated each year
at the same time. An impairment loss is recognized if the carrying amount of
an asset or its related Cash Generating Unit ("CGU") exceeds its estimated
recoverable amount.

The recoverable amount of an asset or CGU is the greater of its value in use
and its fair value less costs to sell. In assessing value in use, the
estimated future cash flows are discounted to their present value using a
pre-tax discount rate that reflects current market assessments of the time
value of money and the risks specific to the asset or CGU. For the purpose of
impairment testing, assets that cannot be tested individually are grouped
together into the smallest group of assets that generates cash inflows from
continuing use that are largely independent of the cash inflows of other
assets or CGUs. Subject to an operating segment ceiling test, for the purpose
of goodwill impairment testing, CGUs to which goodwill has been allocated are
aggregated so that the level at which impairment testing is performed reflects
the lowest level at which goodwill is monitored for internal purposes.
Goodwill acquired in a business combination is allocated to CGUs or groups of
CGUs that are expected to benefit from the synergies of the combination.

The Company's corporate assets do not generate separate cash inflows and are
utilized by more than one CGU. Corporate assets are allocated to CGUs on a
reasonable and consistent basis and tested for impairment as part of the
testing of the CGU to which the corporate asset is allocated. If there is an
indication that a corporate asset may be impaired, then the recoverable amount
is determined for the CGU to which the corporate asset belongs.

Impairment losses are recognized in profit or loss. An impairment loss is
recognized if the carrying amount of an asset or its CGU exceeds its estimated
recoverable amount. Impairment losses recognized in respect of CGUs are
allocated first to reduce the carrying amount of any goodwill allocated to the
CGU (group of CGUs), and then to reduce the carrying amounts of the other
assets in the CGU (group of CGUs) on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other
assets, impairment losses recognized in prior periods are assessed at each
reporting date for any indications that the loss has decreased or no longer
exists. An impairment loss is reversed if there has been a change in the
estimates used to determine the recoverable amount. An impairment loss is
reversed only to the extent that the asset's carrying amount does not exceed
the carrying amount that would have been determined, net of depreciation or
amortization, if no impairment loss had been recognized.

Goodwill that forms part of the carrying amount of an investment in an
associate is not recognized separately, and therefore is not tested for
impairment separately. Instead, the entire amount of the investment in an
associate is tested for impairment as a single asset when there is objective
evidence that the investment in an associate may be impaired.

i.Employee benefits

i)Defined contribution plans

A defined contribution plan is a post-employment benefit plan under which an
entity pays fixed contributions into a separate entity and will have no legal
or constructive obligation to pay further amounts. Obligations for
contributions to defined contribution pension plans are recognized as an
employee benefit expense in profit or loss in the periods during which
services are rendered by employees. Prepaid contributions are recognized as an
asset to the extent that a cash refund or a reduction in future payments is
available. Contributions to a defined contribution plan that are due more than
12 months after the end of the period in which the employees render the
service are discounted to their present value.

ii)Defined benefit pension plans

A defined benefit pension plan is a post-employment benefit plan other than a
defined contribution plan. The Company's net obligation in respect of Defined
Benefit Pension Plans ("Plans") is calculated separately for each plan by
estimating the amount of future benefit that employees have earned in return
for their service in the current and prior periods, discounted to determine
its present value. Unrecognized past service costs and the fair value of any
plan assets are deducted. The discount rate used to determine the present
value is comprised of the following: estimated returns for each major asset
class consistent with market conditions on the valuation date and the target
asset mix specified in the Plans investment policy, additional net returns
assumed to be achievable due to active equity management, implicit provision
for expenses determined as the average rate of investment and administrative
expenses paid by the Plans over the last five years, and a margin for adverse
deviations, based on the proportion of the Plans' assets invested in equities
in excess of the return expected on equities, over government bond yields.

The calculation is performed, at a minimum, every three years by a qualified
actuary using the actuarial cost method. When the calculation results in a
benefit to the Company, the recognized asset is limited to the total of any
unrecognized past service costs and the present value of economic benefits
available in the form of any future refunds from the plan or reductions in
future contributions to the plan. In order to calculate the present value of
economic benefits, consideration is given to any minimum funding requirements
that apply to any plan in the Company. An economic benefit is available to the
Company if it is realizable during the life of the plan or on settlement of
the plan liabilities.

When the benefits of a plan are improved, the portion of the increased benefit
relating to past service by employees is recognized in profit or loss on a
straight-line basis over the average period until the benefits become vested.
To the extent that the benefits vest immediately, the expense is recognized
immediately in profit or loss.

The Company recognizes all actuarial gains and losses arising from defined
benefit plans in other comprehensive income and expenses related to defined
benefit plans in personnel expenses in profit or loss.

The Company recognizes gains or losses on the curtailment or settlement of a
defined benefit plan when the curtailment or settlement occurs. The gain or
loss on curtailment comprises any resulting change in the fair value of plan
assets, change in the present value of defined benefit obligation and any
related actuarial gains or losses and past service cost that had not
previously been recognized.

iii)Other long-term employee benefits

The Company's net obligation in respect of long-term employee benefits other
than pension plans is the amount of future benefit that employees have earned
in return for their service in the current and prior periods is discounted to
determine its present value, and the fair value of any related assets is
deducted. The discount rate is comprised of the following: estimated returns
for each major asset class consistent with market conditions on the valuation
date and the target asset mix specified in the Plans investment policy,
additional net returns assumed to be achievable due to active equity
management, implicit provision for expenses determined as the average rate of
investment and administrative expenses paid from the Plans over the last five
years, and a margin for adverse deviations, based on the proportion of the
Plans assets invested in equities in excess return expected on equities, over
government yield bonds.

The calculation is performed using an actuary.

iv)Short-term employee benefits

Short-term employee benefit obligations are measured on an undiscounted basis
and are expensed as the related service is provided.

A liability is recognized for the amount expected to be paid under short-term
cash bonus if the Company has a present legal or constructive obligation to
pay this amount as a result of past service provided by the employee, and the
obligation can be estimated reliably.

v)Share-based payment transactions

For equity settled share-based payment plans, the fair value of the
share-based payment at grant date is recognized as an expense, with a
corresponding increase in equity, over the period that the employees
unconditionally become entitled to the awards. The amount recognized as an
expense is adjusted to reflect the number of awards for which the related
service and non-market vesting conditions are expected to be met, such that
the amount ultimately recognized as an expense is based on the number of
awards that meet the related service conditions at the vesting date.

For cash settled share-based payment plans, the fair value of the amount
payable to employees is recognized as an expense with a corresponding increase
in liabilities, over the period that the employees unconditionally become
entitled to payment. The liability is remeasured at each reporting date and at
settlement date. Any changes in the fair value of the liability are recognized
as an expense in profit or loss.

j.Provisions

A provision is recognized if, as a result of a past event, the Company has a
present legal or constructive obligation that can be estimated reliably, and
it is probable that an outflow of economic benefits will be required to settle
the obligation. Provisions are determined by discounting the expected future
cash flows at a pre-tax rate that reflects current market assessments of the
time value of money and the risks specific to the liability. Provisions are
remeasured at each reporting date based on the best estimate of the settlement
amount. The unwinding of the discount rate (accretion) is recognized as a
finance cost.

Decommissioning obligation

The Company's activities give rise to dismantling, decommissioning and site
disturbance remediation activities. A provision is made for the estimated cost
of site restoration and capitalized in the relevant asset category.

Decommissioning obligations are measured at the present value, based on a risk
free rate, of management's best estimate of expenditure required to settle the
obligation at the balance sheet date. Subsequent to the initial measurement,
the obligation is adjusted at the end of each period to reflect the passage of
time, changes in the risk free rate and changes in the estimated future cash
flows underlying the obligation. The increase in the provision due to the
passage of time is recognized as finance costs whereas increases/decreases due
to changes in the estimated future cash flows or risk free rate are added to
or deducted from the cost of the related asset.

k.Revenue

Revenue in the course of ordinary activities is measured at the fair value of
the consideration received or receivable. Revenue is recognized when
persuasive evidence exists that the significant risks and rewards of ownership
have been transferred to the customer or the service has been provided,
recovery of the consideration is probable, the associated costs can be
estimated reliably, there is no continuing management involvement with the
goods, and the amount of revenue can be measured reliably.

The timing of the transfer of significant risks and rewards varies depending
on the individual terms of the sales or service agreement. For product sales,
usually transfer of significant risks and rewards occurs when the product is
delivered to a customer. For pipeline transportation revenues and storage
revenue, transfer of significant risks and rewards usually occurs when the
service is provided as per the contract with the customer. For rate or
contractually regulated pipeline operations, revenue is recognized in a manner
that is consistent with the underlying rate design as mandated by agreement or
regulatory authority.

Certain commodity buy/sell arrangements where the risks and rewards of
ownership have not transferred are recognized on a net basis in profit or
loss.

l.Finance income and finance costs

Finance income comprises interest income on funds deposited and invested,
gains on non-commodity-related derivatives measured at fair value through
profit or loss and foreign exchange gains. Interest income is recognized as it
accrues in profit or loss, using the effective interest method.

Finance costs comprise interest expense on loans and borrowings, unwinding of
discount rate on provisions, losses on disposal of available for sale
financial assets, losses on non-commodity-related derivatives, impairment
losses recognized on financial assets (other than trade and other receivables)
and foreign exchange losses.

Borrowing costs that are not directly attributable to the acquisition, or
construction of a qualifying asset are recognized in profit or loss using the
effective interest method.

m.Income tax

Income tax expense comprises current and deferred tax. Current and deferred
tax are recognized in profit or loss except to the extent that it relates to a
business combination, or items are recognized directly in equity or in other
comprehensive income.

Current tax is the expected tax payable or receivable on the taxable income or
loss for the period, using tax rates enacted or substantively enacted at the
reporting date, and any adjustment to tax payable in respect of previous
years.

Deferred tax is recognized in respect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes
and the amounts used for taxation purposes. Deferred tax is not recognized
for:

  *temporary differences on the initial recognition of assets or liabilities
    in a transaction that is not a business combination and that affects
    neither accounting nor taxable profit or loss;
  *temporary differences relating to investments in subsidiaries and jointly
    controlled entities to the extent that it is probable that they will not
    reverse in the foreseeable future; and
  *taxable temporary differences arising on the initial recognition of
    goodwill.

The measurement of deferred tax reflects the tax consequences that would
follow the manner in which the Company expects, at the end of the reporting
period, to recover or settle the carrying amount of its assets and
liabilities.

Deferred tax is measured at the tax rates that are expected to be applied to
temporary differences when they reverse, based on the laws that have been
enacted or substantively enacted by the reporting date.

Deferred tax assets and liabilities are offset if there is a legally
enforceable right to offset current tax liabilities and assets, and they
relate to income taxes levied by the same tax authority on the same taxable
entity, or on different tax entities, but they intend to settle current tax
liabilities and assets on a net basis or their tax assets and liabilities will
be realized simultaneously.

A deferred tax asset is recognized for unused tax losses, tax credits and
deductible temporary differences, to the extent that it is probable that
future taxable profits will be available against which they can be utilized.
Deferred tax assets are reviewed at each reporting date and are reduced to the
extent that it is no longer probable that the related tax benefit will be
realized.

In determining the amount of current and deferred tax, the Company takes into
account the impact of uncertain tax positions and whether additional taxes and
interest may be due. This assessment relies on estimates and assumptions and
may involve a series of judgments about future events. New information may
become available that causes the Company to change its judgment regarding the
adequacy of existing tax liabilities, such changes to tax liabilities will
impact tax expense in the period that such a determination is made.

n.Earnings per share

The Company presents basic and diluted earnings per share ("EPS") data for its
common shares. Basic EPS is calculated by dividing the profit or loss
attributable to common shareholders of the Company by the weighted average
number of common shares outstanding during the period. Diluted EPS is
determined by adjusting the profit or loss attributable to common shareholders
and the weighted average number of common shares outstanding, for the effects
of all potentially dilutive common shares, which comprise convertible
debentures and share options granted to employees ("Convertible Instruments").
Only outstanding and Convertible Instruments that will have a dilutive effect
are included in fully diluted calculations.

The dilutive effect of Convertible Instruments is determined whereby
outstanding Convertible Instruments at the end of the period are assumed to
have been converted at the beginning of the period or at the time issued if
issued during the year. Amounts charged to income or loss relating to the
outstanding Convertible Instruments are added back to net income for the
diluted calculations. The shares issued upon conversion are included in the
denominator of per share basic calculations for the date of issue.

o.Segment reporting

An operating segment is a component of the Company that engages in business
activities from which it may earn revenues and incur expenses, including
revenues and expenses that relate to transactions with any of the Company's
other components. All operating segments' operating results are reviewed
regularly by the Company's Chief Executive Officer ("CEO"), Chief Financial
Officer ("CFO") and Chief Operating Officer ("COO") to make decisions about
resources to be allocated to the segment and assess its performance, and for
which discrete financial information is available.

Segment results that are reported to the CEO, CFO and COO include items
directly attributable to a segment as well as those that can be allocated on a
reasonable basis. Unallocated items comprise mainly corporate assets, head
office expenses, finance income and costs and income tax assets and
liabilities.

Segment capital expenditure is the total cost incurred during the period to
acquire property, plant and equipment, and intangible assets other than
goodwill.

p.Cash flow statements

The cash flow statement is prepared using the indirect method. Changes in
balance sheet items that have not resulted in cash flows such as share-based
payment expense, unrealized gains and losses, depreciation and amortization,
employee future benefit expenses, deferred income tax expense, share of profit
from equity accounted investees, among others, have been eliminated for the
purpose of preparing this statement. Dividends paid to ordinary shareholders,
among other expenditures, are included in financing activities. Interest paid
is included in operating activities.

q.New standards and interpretations not yet adopted

Certain new standards, interpretations, amendments and improvements to
existing standards were issued by the IASB or International Financial
Reporting Interpretations Committee ("IFRIC") for accounting periods beginning
after January 1, 2013. The Company has reviewed these and determined the
following:

Amendments to IFRS 7 Financial Instruments: Disclosures are effective for
annual periods beginning on or after January 1, 2013. The adoption of these
amendments is not expected to have a material impact on the Company's
Financial Statements.

IFRS 9 (2010) Financial Instruments is effective for annual periods beginning
on or after January 1, 2015, with early adoption permitted. The Company
intends to adopt IFRS 9 (2010) in its financial statements for the annual
period beginning January 1, 2015. The extent of the impact of adoption of IFRS
9 (2010) has not yet been determined.

IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12
Disclosure of Interest in Other Entities and IFRS 13 Fair Value Measurement
are effective for annual periods beginning on or after January 1, 2013. The
adoption of these standards is not expected to have a material impact on the
Company's financial statements.

Amendments to IAS 19 Employee Future Benefits are effective for annual periods
beginning on or after January 1, 2013. The adoption of these amendments is not
expected to have a material impact on the Company's Financial Statements.

IAS 32 Financial Instruments: Presentation is effective for annual periods
beginning on or after January 1, 2014. The Company is currently evaluating the
impact that the standard will have on its results of operations and financial
position.

4. DETERMINATION OF FAIR VALUES

A number of the Company's accounting policies and disclosures require the
determination of fair value, for both financial and non-financial assets and
liabilities. Fair values have been determined for measurement and/or
disclosure purposes based on the following methods. When applicable, further
information about the assumptions made in determining fair values is disclosed
in the notes specific to that asset or liability.

i)Property, plant and equipment

The fair value of property, plant and equipment recognized as a result of a
business combination is based on market values when available and depreciated
replacement cost when appropriate. Depreciated replacement cost reflects
adjustments for physical deterioration as well as functional and economic
obsolescence.

ii)Intangible assets

The fair value of intangible assets acquired in a business combination is
determined using the multi-period excess earnings method, whereby the subject
asset is valued after deducting a fair return on all other assets that are
part of creating the related cash flows.

The fair value of other intangible assets is based on the discounted cash
flows expected to be derived from the use and eventual sale of the assets.

iii)Derivatives

Fair value of derivatives, with the exception of the redemption liability
which is related to the acquisition of the Company's subsidiary, are estimated
by reference to independent monthly forward settlement prices, interest rate
yield curves, currency rates, quoted market prices per share and volatility
rates at the period ends.

The redemption liability related to one of the Company's subsidiaries
represents a put option, held by the non-controlling interest, to sell the
remaining one-third of the business to the Company after the third anniversary
of the acquisition date (October 3, 2014). The put price to be paid by the
Company for the residual interest upon exercise is based on a multiple of the
subsidiary's earnings during the three year period prior to exercise, adjusted
for associated capital expenditures and debt based on management estimates
(see Note 27 "Financial Instruments and Financial Risk Management").

Fair values reflect the credit risk of the instrument and include adjustments
to take account of the credit risk of the Company entity and counterparty when
appropriate.

iv)Non-derivative financial assets and liabilities

Fair value, which is determined for disclosure purposes, is calculated based
on the present value of future principal and interest cash flows, discounted
at the market rate of interest at the reporting date. In respect of the
convertible debentures, the fair value is determined by the market price of
the convertible debenture on the reporting date. For finance leases the market
rate of interest is determined by reference to similar lease agreements.

v)Share-based payment transactions

The fair value of the employee share options is measured using the
Black-Scholes formula. Measurement inputs include share price on measurement
date, exercise price of the instrument, expected volatility (based on weighted
average historic volatility adjusted for changes expected due to publicly
available information), weighted average expected life of the instruments
(based on historical experience and general option holder behaviour), expected
dividends, expected forfeitures and the risk-free interest rate (based on
government bonds). Service and non-market performance conditions attached to
the transactions are not taken into account in determining fair value.

The fair value of the long-term share unit award incentive plan and associated
distribution units are measured based on the reporting date market price of
the Company's shares. Expected dividends are not taken into account in
determining fair value as they are issued as additional distribution share
units.

vi)Inventories

The net realizable value of inventories is determined based on the estimated
selling price in the ordinary course of business less estimated cost to sell.

5. ACQUISITION

On April 2, 2012, Pembina acquired all of the outstanding Provident Energy
Ltd. ("Provident") common shares (the "Provident Shares") in exchange for
Pembina common shares valued at approximately $3.3 billion (the
"Acquisition"). Provident shareholders received 0.425 of a Pembina common
share for each Provident Share held for a total of 116,535,750 Pembina common
shares. On closing, Pembina assumed all of the rights and obligations of
Provident relating to the 5.75 percent convertible unsecured subordinated
debentures of Provident maturing December 31, 2017, and the 5.75 percent
convertible unsecured subordinated debentures of Provident maturing December
31, 2018 (collectively, the "Provident Debentures"). The face value of the
outstanding Provident Debentures at April 2, 2012 was $345 million. The
debentures remain outstanding and continue with terms and maturity as
originally set out in their respective indentures. Pursuant to the
Acquisition, Provident amalgamated with a wholly-owned subsidiary of Pembina
and has continued under the name "Pembina NGL Corporation". The results of the
acquired business are included as part of the Midstream business.

The purchase price equation, subject to finalization of deferred tax
liabilities, is based on assessed fair values and is estimated as follows:

                                                                  
($ millions)                                                       
Cash                                                               9
Trade receivables and other                                      195
Inventory                                                         87
Property, plant and equipment                                  1,988
Intangible assets and goodwill (including $1,753 goodwill)     2,414
Trade payables and accrued liabilities                         (249)
Derivative financial instruments - current                      (53)
Derivative financial instruments - non-current                  (36)
Loans and borrowings                                           (215)
Convertible debentures                                         (317)
Provisions and other                                           (128)
Deferred tax liabilities                                       (406)
Non-controlling interest                                         (5)
                                                              3,284

The determination of fair values and the purchase price equation are based
upon an independent valuation. The primary drivers that generate goodwill are
synergies and business opportunities from the integration of Pembina and
Provident and the acquisition of a talented workforce. The recognized goodwill
is generally not expected to be deductible for tax purposes.

Upon closing of the Acquisition, Pembina repaid Provident's revolving term
credit facility of $205 million.

The Company has recognized $24.1 million in acquisition-related expenses.
These expenses are included in acquisition-related and other expenses in the
Financial Statements.

The Pembina Shares were listed and began trading on the NYSE under the symbol
"PBA" on April 2, 2012.

Revenue generated by the Provident business for the period from the
Acquisition date of April 2, 2012 to December 31, 2012, before intersegment
eliminations, was $1,151.4 million. Net earnings, before intersegment
eliminations, for the same period were $54.2 million.

Unaudited proforma consolidated revenue (prepared as if the Provident
Acquisition had occurred on January 1, 2012) for the year ended December 31,
2012 are $3,967.5 million and net earnings for the same period are $277
million.

6. TRADE AND OTHER RECEIVABLES

                                                                     
December 31 ($ thousands)                                2012       2011
Trade accounts receivable from customers              310,364    116,809
Trade accounts receivable and other receivables                 
from related parties                                      10,814        28,864
Prepayments                                            10,514      2,594
Total current trade and other receivables             331,692    148,267
Non-current holdbacks receivable                        3,080          
Receivable due from related parties                              10,814
                                                     334,772    159,081

On March 29, 2012 the Musreau Deep Cut experienced a gear box failure,
resulting in an interruption to business until Pembina brought the Deep Cut
compressor back into service on September 2, 2012. Business interruption and
capital insurance claims are currently being pursued. Pembina has recognized a
receivable based on information on the claim status as of the reporting date.

7. PROPERTY, PLANT AND EQUIPMENT

                                                                                       
                    Land                                                        
                      and                   Facilities        Linefill           Assets
                     Land                          and             and            Under
($ thousands)      Rights     Pipelines      Equipment           Other     Construction             Total
Cost                                                                                    
Balance at                                                                      
December 31,
2010               57,248     1,997,267        483,765         149,117          260,819         2,948,216
Additions         10,006     216,293       30,208        48,891        222,196         527,594
Change in                                                                       
decommissioning
provision                      117,491                                                        117,491
Capitalized                                                                     
interest                           207                                        10,015            10,222
Transfers            104     169,354       15,075         1,139      (185,672)               
Disposals and                                                                   
other               (139)         (585)          (428)           1,579                               427
Balance at                                                                      
December 31,
2011               67,219     2,500,027        528,620     200,726^(1)          307,358     3,603,950^(1)
Acquisition                                                                     
(Note 5)           18,093       276,225      1,319,286         287,319           87,273         1,988,196
Additions          5,900      20,315       38,533        31,021        488,545         584,314
Change in                                                                       
decommissioning
provision                    (139,468)       (31,441)                                        (170,909)
Capitalized                                                                     
interest                           570             98                          13,821            14,489
Transfers          1,793    (61,401)      217,928      (13,149)      (145,171)               
Disposals and                                                                   
other             (5,001)       (2,534)          (828)             626                           (7,737)
Balance at                                                                      
December 31,
2012               88,004     2,593,734      2,072,196         506,543          751,826         6,012,303
                                                                                       
Depreciation                                                                            
Balance at                                                                      
December 31,
2010                4,043       659,277         76,498          49,301                           789,119
Depreciation          45      48,334       16,768         4,374                        69,521
Disposals                     (516)        (268)       (1,436)                       (2,220)
Balance at                                                                      
December 31,
2011                4,088       707,095         92,998          52,239                           856,420
Depreciation         279      70,795       54,476        19,629                       145,179
Transfers                       917       24,628      (25,545)                             
Disposals and                                                                   
other                          (2,099)          (225)         (1,514)                           (3,838)
Balance at                                                                      
December 31,
2012                4,367       776,708        171,877          44,809                           997,761
                                                                                       
Carrying                                                                        
amounts                                                                                            
December 31,                                                                    
2011               63,131     1,792,932        435,622         148,487          307,358         2,747,530
December 31,                                                                    
2012               83,637     1,817,026      1,900,319         461,734          751,826         5,014,542

^(1)$1.5 million was reclassified from inventory to Linefill and Other at
December 31, 2011.

Property, plant and equipment under construction

Costs of assets under construction at December 31, 2012 totalled $751.8
million ($2011: $307.4 million). Such amounts include capitalized borrowing
costs.

For the year ended December 31, 2012, capitalized borrowing costs related to
the construction of the new pipelines or facilities amounted to $14.5 million
(2011: $10.2 million), with capitalization rates ranging from 4.29 percent to
4.77 percent (2011: 4.91 percent to 5.36 percent).

Commitments

At December 31, 2012, the Company has contractual commitments for the
acquisition and or construction of property, plant and equipment of $362.8
million (December 31, 2011: $364.3 million).

8. INTANGIBLE ASSETS AND GOODWILL

                                                                       
                             Other Intangible Assets                             
                                                                             Total
                            Purchase                                   Total     Goodwill
                                 and                                   Other            &
                                Sale        Customer   Purchase   Intangible   Intangible
                Goodwill   Contracts   Relationships    Options       Assets       Assets
Cost                                                                         
Balance at                                                              
December 31,
2010 and
2011             222,670      23,038                                23,038      245,708
Acquisition                                                             
(Note 5)       1,752,942     157,051         226,497    277,350      660,898    2,413,840
Additions                                                               
and other                     5,000                                 5,000        5,000
Balance at                                                              
December 31,
2012           1,975,612     185,089         226,497    277,350      688,936    2,664,548
                                                                            
Amortization                                                                 
Accumulated                                                             
amortization
at
December 31,
2010                          1,106                                 1,106        1,106
Amortization                  698                                698         698
Accumulated                                                             
amortization
at
December 31,
2011                          1,804                                 1,804        1,804
Amortization               24,778         15,289               40,067      40,067
Accumulated                                                             
amortization
at
December 31,
2012                         26,582          15,289                 41,871       41,871
                                                                            
Carrying                                                                
amounts                                                                            
December 31,                                                            
2011             222,670      21,234                                21,234      243,904
December 31,                                                            
2012           1,975,612     158,507         211,208    277,350      647,065    2,622,677

Other intangible assets consist of customer purchase and sale contracts with
several producers acquired through business combinations. In addition, Pembina
has a purchase option of $277.3 million to acquire property, plant and
equipment. The purchase option is not being amortized because it is not
exercisable until 2018.

The aggregate carrying amount of intangible assets and goodwill allocated to
each operating segment is as follows:

                                              
($ thousands)                    2012        2011
Conventional Pipelines        315,470     194,370
Oil Sands and Heavy Oil        33,300      28,300
Gas Services                  196,136      21,234
Midstream                   2,077,771           
                           2,622,677     243,904

Impairment testing

For the purpose of impairment testing, goodwill is allocated to the Company's
operating divisions which represent the lowest level within the Company at
which the goodwill is monitored for internal management purposes, which is not
higher than the Company's operating segments. Impairment testing for goodwill
was performed on December 31, 2012. The recoverable amounts were based on
their value in use and were determined to be higher than their carrying
amounts.

Value in use was determined by discounting the future cash flows generated
from the continuing use of each cash generating unit. The calculation of the
value in use was based on the following key assumptions:

Cash flows were projected based on past experience, actual operating results
and the first 5 years of the business plan approved by management. Cash flows
for periods up to 68 years (2011: 75 years) were extrapolated using a constant
growth rate of 2 percent (2011: 1.9 percent), which does not exceed the
long-term average growth rate for the industry. Pre-tax discount rates between
7.49 percent and 8.63 percent (2011: 7.51 percent and 8.84 percent) were
applied in determining the recoverable amount of the cash generating units.
The discount rates were estimated based on past experience, the Company's risk
free rate and average cost of debt in addition to estimates of the specific
cash generating unit's equity risk premium, size premium, small capitalization
premium, projection risk, betas, tax rate and industry targeted debt to equity
ratios.

9. INVESTMENTS IN EQUITY ACCOUNTED INVESTEES

The Company has a 50 percent interest in two jointly controlled, equity
accounted investees that are reported using the equity method of accounting.
The carrying value of the investment at December 31, 2012 is $161.2 million
(2011: $161 million).

                                                                                            
                                                                                              Payments
                                                                     Pembina's Proportionate        from
                                                                             Share of              Equity
                       Pembina's Proportionate Share of             Transaction Value For The     Accounted
                                 Balance As At                              Year Ended            Investees
                                                                                 Profit 
               Current   Non-Current       Current   Non-Current                            and
                Assets        Assets   Liabilities   Liabilities   Revenues   Expenses     Loss           
($                                                                                       
thousands)                                                                                         
Fort                                                                                     
Saskatchewan
Ethylene
Storage
Corporation
(FSESC)            316            11             1                      78          2       76           
Fort                                                                                     
Saskatchewan
Ethylene
Storage
Limited
Partnership
(FSESLP)         3,271        26,216        20,125        12,087     45,925      7,082   38,843      16,869
December 31,                                                                             
2011             3,587        26,227        20,126        12,087     46,003      7,084   38,919      16,869
FSESC             331            4            2                    12         4       8          
FSESLP          2,917       41,343       16,950       21,457    14,646     8,788   5,858     17,428
December 31,                                                                             
2012             3,248        41,347        16,952        21,457     14,658      8,792    5,866      17,428

On acquisition, Pembina recognized a fair value adjustment which is amortized
over the useful life of the assets. Pembina's share of profit of investments
in equity accounted investees includes amortization of the fair value
adjustment of $7.7 million (2011: $5.2 million), derecognition of fair value
adjustment of $nil (2011: $25.2 million), income tax benefit (expense) of $0.5
million (2011: $(1.9) million) and other $0.3 million (2011: $(0.7) million)
In 2012, Pembina made contributions for the construction of caverns of $8.2
million (2011: $nil).

Commitments

At December 31, 2012, the Company's share of investment in equity accounted
investees contractual commitments for the construction of property, plant and
equipment is $31.6 million (December 31, 2011: $42.7 million).

10. INCOME TAXES

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

                                                          
($ thousands)                                      2012        2011
Asset:                                                           
Intangible assets                                            2,512
Derivative financial instruments                 22,787       2,772
Employee benefits                                 7,156       4,238
Share-based payments                              7,971       3,515
Provisions                                      114,617     101,358
Benefit of loss carryforwards                    76,702      62,426
Other deductible temporary differences            2,783       4,240
Total deferred tax asset                        232,016     181,061
                                                                
Liability:                                                       
Property, plant and equipment                   589,909     203,178
Intangible assets                               127,467           
Investments in equity accounted investees        21,841      25,802
Taxable limited partnership income deferral      75,295      50,175
Other taxable temporary differences               1,993       8,821
Total deferred tax liability                    816,505     287,976
Total deferred tax liability                    584,489     106,915

The Company's consolidated effective tax rate for the year ended December 31,
2012 was 25 percent (2011: 19.6 percent).

Reconciliation of effective tax rate

                                                         
Year Ended December 31 ($ thousands)              2012            2011
Earnings before income tax                     301,347         198,769
                                                                   
Statutory tax rate                         25.0%     26.5%
                                                                   
Income tax at statutory rate                    75,337          52,674
                                                                   
Tax rate changes on deferred income                       
tax balances                                         1,948             (5,051)
Changes in estimate from prior year            (2,160)         (8,880)
Other                                              214             126
Income tax expense                              75,339          38,869

In 2007, the Canadian federal government enacted a change in the federal
income tax rate from 16.5 percent in 2011 to 15 percent in 2012.

Income tax expense

                                                                    
Year Ended December 31 ($ thousands)                    2012       2011
Current tax benefit                                                  
      Adjustment for prior period                     (463)          
      Total current tax benefit                       (463)          
Deferred tax expense                                                 
      Origination and reversal of temporary                   
       differences                                        58,005        23,826
      Tax rate changes on deferred tax balances       1,948    (5,075)
      Decrease in tax loss carry forward             15,849     20,118
      Total deferred tax expense                     75,802     38,869
Total income tax expense                              75,339     38,869
                                                                    
The movement of the deferred tax liability is as               
follows:                                                                    
($ thousands)                                           2012       2011
Opening balance, January 1                           106,915     69,686
Deferred income tax expense                           75,802     38,869
Tax benefit on share of (loss) profit of equity                
accounted investees                                        (458)         1,900
Income tax benefit in other comprehensive income     (3,641)    (3,540)
Acquisition (Note 5)                                 405,847          
Other                                                     24          
Deferred income taxes, December 31                   584,489    106,915

11. TRADE PAYABLES AND ACCRUED LIABILITIES

                                                           
December 31 ($ thousands)                           2012        2011
Trade payables                                   301,936     141,452
Non-trade payables & accrued liabilities^(1)      42,804      25,194
                                                344,740     166,646

^(1)Includes current portion of decommissioning provision of $532 (2011 -
$10,720).

U.S. dollar trade payables at December 31, 2012 are $0.3 million (December 31,
2011: Nil).

12. LOANS AND BORROWINGS

This note provides information about the contractual terms of the Company's
interest-bearing loans and borrowings, which are measured at amortized cost.

Carrying value terms and debt repayment schedule

Terms and conditions of outstanding loans were as follows:

                                                             
($                                                
thousands)                                                 Carrying amount^(3)
               Available                                      
               facilities
                       at
                 December        Nominal                   December      December
                      31,       interest      Year of           31,           31,
                    2012           rate     maturity          2012          2011
                              prime +                         
                                    0.50
Operating                      or BA^(2)
facility^(1)       30,000         + 1.50         2013                      3,139
Revolving                     prime +                         
unsecured                           0.50
credit                         or BA^(2)
facility        1,500,000         + 1.50         2017       520,676       309,981
Senior                                                        
secured
notes                        7.38                                 57,499
Senior                                                        
unsecured
notes -
Series A          175,000     5.99         2014       174,677       174,462
Senior                                                        
unsecured
notes -
Series C          200,000     5.58         2021       196,983       196,638
Senior                                                        
unsecured
notes -
Series D          267,000     5.91         2019       265,604       265,403
Senior                                                        
unsecured
term
facility           75,000     6.16         2014        74,800        74,658
Senior                                                        
unsecured
medium-term
notes 1           250,000     4.89         2021       248,714       248,558
Senior                                                        
unsecured
medium-term
notes 2           450,000     3.77         2022       447,825             
Subsidiary                                                    
debt                9,347     5.04         2014         9,347             
Finance                                                       
lease
liabilities                                                5,800         5,650
Total                                                         
interest
bearing
liabilities     2,956,347                         1,944,426     1,335,988
Less current                                                  
portion                                                 (11,652)     (323,927)
Total                                                         
non-current                                            1,932,774     1,012,061

^(1)  Operating facility expected to be renewed on an annual basis.
^(2)   Bankers' Acceptance.
^(3)  Deferred financing fees are all classified as non-current. Non-current
        carrying amount of facilities are net of deferred financing fees.

All facilities are governed by specific debt covenants which Pembina has been
in compliance with during the years ended December 31, 2012 and 2011.

For more information about the Company's exposure to interest rate, foreign
currency and liquidity risk, see financial instruments and financial risk
management Note 27.

13. CONVERTIBLE DEBENTURES

                                                                 
($ thousands, except    Series C -   Series E -   Series F -  
as noted)                      5.75%          5.75%          5.75%      Total
Conversion price                                              
(dollars)                     $28.55         $24.94         $29.53           
                                        June 30      June 30  
Interest payable                                and            and
semi-annually in          May 31 and       December       December
arrears on:              November 30             31             31           
                          November     December     December  
                                 30,            31,            31,
Maturity date                   2020           2017           2018           
Balance December 31,                                          
2010                         288,635                                 288,635
Conversions                  (220)                             (220)
Deferred financing                                            
fees (net of
amortization)                    950                                     950
Balance, December                                             
31, 2011                     289,365                                 289,365
Assumed on                                                    
acquisition^(1)
(Note 5)                                   158,471        158,343     316,814
Conversions and                                               
redemptions                     (54)          (351)           (55)       (460)
Accretion of                                                  
liability                                      841            688       1,529
Deferred financing                                            
fee (net
amortization)                  1,168            826            726       2,720
Balance, December                                             
31, 2012                     290,479        159,787        159,702     609,968

^(1)Excludes conversion feature of convertible debentures.

The Series C debentures may be converted at the option of the holder at a
conversion price of $28.55 per share at any time prior to maturity and may be
redeemed by the Company. The Company may, at its option after November 30,
2016, (or after November 30, 2014, provided that the volume weighted average
trading price of the common shares on the TSX during the 20 consecutive
trading days ending on the fifth trading day preceding the date on when the
notice of redemption is given is not less than 125 percent of the conversion
price of the debentures) elect to redeem the debentures by issuing shares. The
Company may also elect to pay interest on the debentures by issuing shares.

The Series E debentures may be converted at the option of the holder at a
conversion price of $24.94 per share at any time prior to maturity and may be
redeemed by the Company. The Company may, at its option on or after December
31, 2013 and prior to December 31, 2015, elect to redeem the Series E
debentures in whole or in part, provided that the volume weighted average
trading price of the common price of the shares on the TSX during the 20
consecutive trading days ending on the fifth trading day preceding the date on
which the notice of redemption is given is not less than 125 percent of the
conversion price of the Series E debentures. On or after December 31, 2015,
the Series E debentures may be redeemed in whole or in part at the option of
the Company at a price equal to their principal amount plus accrued and unpaid
interest. Any accrued unpaid interest will be paid in cash.

The Series F debentures may be converted at the option of the holder at a
conversion price of $29.53 per share at any time prior to maturity and may be
redeemed by the Company. The Company may, at its option on or after December
31, 2014 and prior to December 31, 2016, elect to redeem the Series F
debentures in whole or in part, provided that the volume weighted average
trading price of the common price of the shares on the TSX during the 20
consecutive trading days ending on the fifth trading day preceding the date on
which the notice of redemption is given is not less than 125 percent of the
conversion price of the Series F debentures. On or after December 31, 2016,
the Series F debentures may be redeemed in whole or in part at the option of
the Company at a price equal to their principal amount plus accrued and unpaid
interest. Any accrued unpaid interest will be paid in cash.

The Company retains a cash conversion option on the Series E and F convertible
debentures, allowing the Company to pay cash to the converting holder of the
debentures, at the option of the Company. For convertible debentures with a
cash conversion option, the conversion feature is recognized as an embedded
derivative and accounted for as a derivative financial instrument, measured at
fair value using an option pricing model.

14. PROVISIONS

The Company has estimated the net present value of its total decommissioning
obligations based on a total future liability of $361.7 million (2011: $416.2
million). The estimate has applied a medium-term inflation rate and current
discount rate and includes a revision in the decommissioning assumptions and
associated costs and timing of payments. The obligations are expected to be
paid over the next 75 years with majority being paid between 30 and 40 years.
The Company applied a 2 percent inflation rate per annum (2011: 2.4 percent)
and a risk free rate of 2.36 percent (2011: 2.49 percent) to calculate the
present value of the decommissioning provision. During the year ended December
31, 2012, the Company estimated a decrease of $54.5 million (2011: increase of
$134.5 million) in the total decommissioning obligation, including an increase
of $124.6 million assumed on the Acquisition, offset by a $144.8 million
decrease due to revised assumptions which the Company believes are more in
line with industry, a $46.7 million decrease (2011: increase of $106.8
million) based on a change in the discount and inflation rates used to
remeasure the obligation and $7 million (2011: $7.1 million) for unwinding of
the discount rate, net of any settlements and a $5.4 million increase (2011:
$20.6 million increase) representing the present value of additional
obligations. The remeasured decommissioning provision decreased property,
plant and equipment and decommissioning provision liability. $5.9 million of
the re-measurement reduction in the decommissioning provision was in excess of
the carrying amount of the related asset and is recognized as a credit to
depreciation expense (2011: nil).

The property, plant and equipment of the Company consist primarily of
underground pipelines, above ground equipment facilities and storage assets.
No amount has been recorded relating to the removal of the underground
pipelines or the storage assets as the potential obligations relating to these
assets cannot be reasonably estimated due to the indeterminate timing or scope
of the asset retirement. As the timing and scope of retirement become
determinable for these assets, the fair value of the liability and the cost of
retirement will be recorded.

                                                                   
($ thousands)                                         2012        2011
Balance at January 1                               416,153     281,694
Unwinding of discount rate                          11,956      10,141
Assumed on acquisition (Note 5)                    124,579           
Decommissioning liabilities settled during                    
the period                                             (4,944)         (3,123)
Change in rates                                   (46,654)     106,793
Change in estimates and other                    (139,352)      20,648
Total                                              361,738     416,153
Less current portion (included in accrued                     
liabilities)                                               532          10,720
Balance at December 31                             361,206     405,433

15. SHARE CAPITAL

Share capital

Pembina is authorized to issue an unlimited number of common shares and an
unlimited number of a class of preferred shares designated as Preferred
Shares, Series A. The holders of the common shares are entitled to receive
notice of, attend at and vote at any meeting of the shareholders of the
Company, receive dividends declared and share in the remaining property of the
Company upon distribution of the assets of the Company among its shareholders
for the purpose of winding-up its affairs.

Pembina has adopted a shareholder rights plan ("Plan") as a mechanism designed
to assist the board in ensuring the fair and equal treatment of all
shareholders in the face of an actual or contemplated unsolicited bid to take
control of the company. Take-over bids may be structured in such a way as to
be coercive or discriminatory in effect, or may be initiated at a time when it
will be difficult for the board to prepare an adequate response. Such offers
may result in shareholders receiving unequal or unfair treatment, or not
realizing the full or maximum value of their investment in Pembina. The Plan
discourages the making of any such offers by creating the potential of
significant dilution to any offeror who does so.

                                                                   
($ thousands, except share                 Number of    
amounts)                                   Common Shares         Share Capital
Balance December 31, 2010                166,876,651         1,794,536
Share-based payment transactions           1,023,916            16,978
Debenture conversions and other                7,704               220
Balance December 31, 2011                167,908,271         1,811,734
Issued on acquisition (Note 5)           116,535,750         3,283,976
Share-based payment transactions             427,934             9,221
Dividend reinvestment plan                 8,338,254           218,695
Debenture conversions and other               16,264               432
Balance December 31, 2012                293,226,473         5,324,058

Dividends

The following dividends were declared by the Company:

                                                             
Year Ended December 31 ($ thousands)                  2012        2011
$1.61 per qualifying common share (2011: $1.56                
)                                                      417,601         261,236

On January 8, 2013 and February 12, 2013, Pembina announced that the Board of
Directors declared a dividend for each of January and February of $0.135 per
qualifying common share ($1.62 annualized) in the total amount of $79.5
million.

16. REVENUES

                                                                     
Year Ended December 31 ($ thousands)                   2012         2011
Rendering of Services:                                                
Conventional pipeline transportation                338,772      296,190
Oil Sands and Heavy Oil pipeline                              
transportation                                         172,429         134,874
Midstream and marketing terminalling, storage                 
and hub services (net)                               2,847,403       1,173,480
Gas services gathering and processing services       88,285       71,506
Intersegment eliminations                          (19,487)            
                                                 3,427,402    1,676,050

17. COST OF SALES

                                                           
Year Ended December 31 ($ thousands)                2012          2011
Operating expense                                271,566       191,923
Cost of goods sold, including product                       
purchases                                          2,475,038         1,072,270
Depreciation and amortization - operating        173,604        68,012
                                              2,920,208     1,332,205

18. GENERAL AND ADMINISTRATIVE EXPENSE

                                                              
Year Ended December 31 ($ thousands)                   2012       2011
Other general & administrative expense               91,706     59,984
Depreciation and amortization - general and           5,782      2,207
administrative
                                                    97,488     62,191

19. DEPRECIATION AND AMORTIZATION

                                                        
Year Ended December 31 ($ thousands)        2012       2011
Cost of sales                            173,604     68,012
General and administrative                 5,782      2,207
                                        179,386     70,219

20. PERSONNEL EXPENSES

                                                     
Year Ended December 31 ($ thousands)          2012       2011
Salaries and wages                          82,350     57,564
Canada Pension Plan and EI remittances       2,436      1,717
Share-based payment transactions            17,028     18,651
Short-term incentive plan (bonus)           11,430      8,393
Defined contribution plan expense            1,685        878
Defined benefit pension plan expense         7,225      4,828
Health and dental benefit expense            3,459      2,232
Employee Savings plan expense                3,946      2,172
Other benefits                               1,573      1,064
                                          131,132     97,499

21. NET FINANCE COSTS

                                                                
Year Ended December 31 ($ thousands)                      2012      2011
Interest income from:                                                 
Related parties                                          (262)     (876)
Bank deposits                                          (1,200)     (414)
Interest expense on financial liabilities measured               
at amortized cost:                                                          
               Loans and borrowings                    72,956    56,722
               Convertible debentures                  36,348    18,415
               Finance leases                             426       404
               Unwinding of discount                   12,021    10,141
(Gain) loss in fair value of non-commodity-related               
derivative financial instruments                          (4,087)        7,619
Foreign exchange gains                                 (1,062)      (84)
Net finance costs                                      115,140    91,927

22. OPERATING SEGMENTS

The Company determines its reportable segments based on the nature of
operations and includes four operating segments: Conventional Pipelines, Oil
Sands & Heavy Oil, Gas Services and Midstream.

Conventional Pipelines consists of the tariff based operations of pipelines
and related facilities to deliver crude oil, condensate and NGL in Alberta and
B.C.

Oil Sands & Heavy Oil consists of the Syncrude, Horizon, Nipisi and Mitsue
Pipelines, and the Cheecham Lateral. These pipelines and related facilities
deliver synthetic crude oil produced from oil sands under long-term
cost-of-service arrangements.

Gas Services consists of natural gas gathering and processing facilities,
including three gas plants, twelve compressor stations and over 300 kilometres
of gathering systems.

Midstream consists of the Company's interests in extraction and fractionation
facilities, terminalling and storage hub services under a mixture of short,
medium and long-term contractual arrangements.

The financial results of the business segments is included below. Performance
is measured based on results from operating activities, net of depreciation
and amortization, as included in the internal management reports that are
reviewed by the Company's CEO, CFO and COO. The segments results from
operating activities, before depreciation and amortization, is used to measure
performance as management believes that such information is the most relevant
in evaluating results of certain segments relative to other entities that
operate within these industries. Intersegment transactions are recorded at
market value and eliminated under corporate and intersegment eliminations.

                                                                                        
                                          Oil                                        
Year Ended December                     Sands &                               Corporate &
31, 2012 ($              Conventional     Heavy        Gas                   Intersegment
thousands)              Pipelines^(1)       Oil   Services   Midstream^(2)   Eliminations       Total
Revenue:                                                                                 
  Pipeline                                                                           
 transportation              338,772   172,429                                (19,487)     491,714
  NGL product and                                                                    
  services,
  terminalling,
  storage and hub
 services                                                    2,847,403                 2,847,403
 Gas Services                                 88,285                                88,285
Total revenue                338,772  172,429    88,285      2,847,403      (19,487)  3,427,402
 Operations                 129,555   55,629    29,260         59,685       (2,563)    271,566
  Cost of goods sold,                                                                
  including product
 purchases                                                   2,494,525       (19,487)   2,475,038
  Realized gain                                                                      
  (loss) on
  commodity-related
  derivative
  financial
 instruments                     111                            (4,682)                   (4,571)
Operating margin             209,328  116,800    59,025        288,511         2,563    676,227
  Depreciation and                                                                   
  amortization
 (operational)                43,959    19,800     14,546          95,299                   173,604
  Unrealized gain                                                                    
  (loss) on
  commodity-related
  derivative
  financial
 instruments                 (9,043)                             45,143                    36,100
Gross profit                 156,326   97,000    44,479        238,355         2,563    538,723
  Depreciation                                                                       
  included in general
 and administrative                                                            5,782       5,782
  Other general and                                                                  
 administrative                6,692     3,771      4,130          15,478         61,635      91,706
  Acquisition-related                                                                
  and other expenses
 (income)                        957       297         11             434         23,049      24,748
Reportable segment                                                                   
results from
operating activities          148,677    92,932     40,338         222,443       (87,903)     416,487
Net finance costs                                                                    
(income)                        6,192     1,889        800           3,205        103,054     115,140
Reportable segment                                                                   
earnings (loss)
before tax and income
from equity accounted
investees                     142,485    91,043     39,538         219,238      (190,957)     301,347
Share of loss of                                                                     
investments in equity
accounted investees,
net of tax                                                        1,056                     1,056
Capital expenditures         187,264   30,432   162,838        203,969         (189)    584,314

^(1)  5.1 percent of Conventional Pipelines revenue is under regulated
       tolling arrangements.
^(2)  NGL product and services, terminalling, storage and hub services
       revenue includes $97.1 million associated with U.S. midstream sales.
     

                                                                            
                                          Oil                                    
Year Ended December                     Sands &                           Corporate &
31, 2011                 Conventional     Heavy        Gas               Intersegment
($ thousands)           Pipelines^(1)       Oil   Services   Midstream   Eliminations       Total
Revenue:                                                                             
  Pipeline                                                                       
 transportation              296,190   134,874                                        431,064
  Terminalling,                                                                  
  storage and hub
 services                                                1,173,480                 1,173,480
 Gas Services                                 71,506                            71,506
Total revenue                296,190  134,874    71,506  1,173,480               1,676,050
 Operations                 119,093   43,986    22,407      8,833       (2,396)    191,923
  Cost of goods sold,                                                            
  including product
 purchases                                               1,072,270                 1,072,270
  Realized gain                                                                  
  (loss) on
  commodity-related
  derivative
  financial
 instruments                   4,413                            882                     5,295
Operating margin             181,510   90,888    49,099     93,259         2,396    417,152
  Depreciation and                                                               
  amortization
 (operational)                41,595    12,786      9,921       3,710                    68,012
  Unrealized gain                                                                
  (loss) on
  commodity-related
  derivative
  financial
 instruments                   3,743                          1,433                     5,176
Gross profit                 143,658   78,102    39,178     90,982         2,396    354,316
  Depreciation                                                                   
  included in general
 and administrative                                                        2,207       2,207
  Other general and                                                              
 administrative                6,421     2,898      4,117       5,234         41,314      59,984
  Acquisition-related                                                            
  and other expenses
 (income)                      1,018     (127)          6           2            530       1,429
Reportable segment                                                               
results from
operating activities          136,219    75,331     35,055      85,746       (41,655)     290,696
Net finance costs              7,110    1,729       999        109        81,980     91,927
Reportable segment                                                               
earnings (loss)
before tax and income
from equity accounted
investees                     129,109    73,602     34,056      85,637      (123,635)     198,769
Share of loss                                                                    
(profit) of
investments in equity
accounted investees,
net of tax                                                  (5,766)                   (5,766)
Capital expenditures          72,034  191,723   136,505    111,480        15,852    527,594

^(1)  4.8 percent of Conventional Pipelines revenue is under regulated
       tolling arrangements.

23. EARNINGS PER SHARE

Basic earnings per share

The calculation of basic earnings per share at December 31, 2012 was based on
the earnings attributable to common shareholders of $224.8 million (2011:
$165.7 million) and a weighted average number of common shares outstanding of
258.9 million (2011: 167.4 million).

Diluted earnings per share

The calculation of diluted earnings per share at December 31, 2012 was based
on earnings attributable to common shareholders of $224.8 million (December
31, 2011: $165.7 million), and weighted average number of common shares
outstanding after adjustment for the effects of all dilutive potential common
shares of 259.5 million (2011: 168.2 million), calculated as follows:

Weighted average number of common shares

                                                                     
(In thousands of shares)                              2012          2011
Issued common shares at January 1                  167,908       166,877
Effect of shares issued on acquisition              87,243             
Effect of share options exercised                      185           556
Effect of conversion of convertible                          
debentures                                                  9                
Effect of shares issued under dividend                       
reinvestment plan                                       3,524                
Weighted average number of common shares at                  
December 31 (basic)                                   258,869          167,433
                                                                     
Dilutive effect of conversion of convertible                 
debentures                                                                  
Dilutive effect of share options on issue              614           742
Weighted average number of common shares at                  
December 31 (diluted)                                 259,483          168,175
                                                                     
Basic earnings per share ($)                    0.87    0.99
Diluted earnings per share ($)                  0.87    0.99

At December 31, 2012, the effect of the conversion of the convertible
debentures was excluded from the diluted earnings per share calculation as the
impact was anti-dilutive. If the convertible debentures were included, an
additional 23.3 million (2011: 10.5 million) common shares would be added to
the weighted average number of common shares and $27.3 million (2011: $13.8
million) would be added to earnings, representing after tax interest expense
of the convertible debentures.

The average market value of the Company's shares for purposes of calculating
the dilutive effect of share options was based on quoted market prices for the
period during which the options were outstanding.

24. CHANGES IN NON-CASH WORKING CAPITAL

                                                                   
Year Ended December 31 ($ thousands)                 2012         2011
Accounts receivable, inventory and other            6,043     (30,388)
Accounts payable and accrued liabilities        (115,924)       10,091
Change in non-cash operating working                         
capital                                             (109,881)         (20,297)

25. EMPLOYEE BENEFITS

                                                     
December 31 ($ thousands)                     2012       2011
Registered defined benefit obligation       21,394     10,755
Supplemental defined benefit obligation      6,180      5,092
Other accrued benefit obligations            1,049      1,104
Employee benefit obligations                28,623     16,951

The Company maintains a defined contribution plan and non-contributory defined
pension plans covering its employees. The defined benefit plans include a
funded registered plan for all employees and an unfunded supplemental
retirement plan for those employees affected by the Canada Revenue Agency
maximum pension limits. The Company also has other accrued benefit obligations
which include a non-contribution unfunded post employment extended health and
dental plan provided to a few remaining retired employees. Benefits under the
plans are based on the length of service and the annual average best three
years of earnings during last ten years of service of the employee. Benefits
paid out of the plans are not indexed. The Company measures its accrued
benefit obligations and the fair value of plan assets for accounting purposes
as at December 31 of each year. The most recent actuarial valuation was at
December 31, 2009.

Defined benefit obligations

                                                           
December 31                2012                          2011
                Registered   Supplemental   Registered   Supplemental
($ thousands)           Plan             Plan           Plan             Plan
Present value                                           
of unfunded
obligations                            6,180                          5,092
Present value                                           
of funded
obligations          121,783                        100,138                
Total present                                           
value of
obligations          121,783            6,180        100,138            5,092
Fair value of                                           
plan assets          100,389                         89,383                
Recognized                                              
liability for
defined
benefit
obligations         (21,394)          (6,180)       (10,755)          (5,092)

The Company funds the defined benefit obligation plans in accordance with
government regulations by contributing to trust funds administered by an
independent trustee. The funds are invested primarily in equities and bonds.
Defined benefit plan contributions totalled $10 million for the year ended
December 31, 2012 (2011: $8 million).

The Company has determined that, in accordance with the terms and conditions
of the defined benefit plans, and in accordance with statutory requirements of
the plans, the present value of refunds or reductions in future contributions
is not lower than the balance of the total fair value of the plan assets less
the total present value of obligations. As such, no decreases in the defined
benefit asset is necessary at December 31, 2012 and December 31, 2011.

Registered defined benefit pension plan assets comprise

                                           
December 31 (percentages)       2012      2011
Equity securities               65.1      64.1
Debt                            30.1      30.8
Other                            4.8       5.1
                              100.0     100.0

Movement in the present value of the pension obligation

                                             
Year Ended                                    
December 31                   2012                            2011
                 Registered   Supplemental   Registered   Supplemental
($ thousands)            Plan             Plan           Plan             Plan
Defined                                                  
benefits
obligations at
January 1             100,138            5,092         90,090            4,382
Benefits paid                                            
by the plan           (5,896)             (66)        (6,108)                
Current                                                  
service costs
and interest           12,009              504          9,944              402
Actuarial                                                
losses in
other
comprehensive
income                 15,532              650          6,212              308
Defined                                                  
benefit
obligations at
December 31           121,783            6,180        100,138            5,092

Movement in the present value of registered defined benefit pension plan
assets

                                                                   
Year Ended December 31 ($ thousands)                  2012        2011
Fair value of plan assets at January 1              89,383      89,609
Contributions paid into the plan                    10,000       8,000
Benefits paid by the plan                          (5,896)     (6,108)
Expected return on plan assets                       5,288       5,521
Actuarial (losses) gains in other                             
comprehensive income                                     1,614         (7,639)
Fair value of registered plan assets at                       
December 31                                            100,389          89,383

Expense recognition in profit or loss

                                                      
Year Ended                                    
December 31                   2012                            2011
                 Registered   Supplemental   Registered   Supplemental
($ thousands)            Plan             Plan           Plan             Plan
Current                                                  
service costs           6,655              232          4,780              149
Interest on                                              
obligation              5,354              272          5,164              253
Expected                                                 
return on plan
assets                (5,288)                        (5,521)                
                     6,721            504        4,423            402

The expense is recognized in the following line items in the statement of
comprehensive income:

                                                      
Year Ended                                    
December 31                   2012                            2011
                 Registered   Supplemental   Registered   Supplemental
($ thousands)            Plan             Plan           Plan             Plan
Operating                                                
expenses                3,734                          2,771                
General and                                              
administrative
expense                 2,987              504          1,652              402
                     6,721            504        4,423            402
                                                                 
Actual return                                            
on plan assets          6,902                        (2,118)                

Actuarial gains and losses recognized in other comprehensive income

                                                                        
                             2012                                     2011
($           Registered   Supplemental            Registered   Supplemental  
thousands)           Plan             Plan      Total           Plan             Plan      Total
Cumulative                                                                   
amount at
January 1          15,050              146     15,196          4,662             (85)      4,577
Recognized                                                                   
during the
period
after tax          10,439              488     10,927         10,388              231     10,619
Cumulative                                                                   
amount at
December
31                 25,489              634     26,123         15,050              146     15,196

Principal actuarial assumptions used as at December 31 (expressed as weighted
averages):

                                                             
                                                     2012     2011
Discount rate                                         4.4%     5.2%
Expected long-term rate of return on plan assets      5.8%     6.1%
Future pension earning increases                      4.0%     4.0%

Assumptions regarding future mortality are based on published statistics and
mortality tables. The current longevities underlying the values of the
liabilities in the defined plans are as follows:

                                                          
December 31 (years)                                2012     2011
Longevity at age 65 for current pensioners                    
Males                                              19.8     19.7
Females                                            22.1     22.1
                                                          
Longevity at age 65 for current member aged 45                
Males                                              21.3     21.2
Females                                            22.9     22.9

The calculation of the defined benefit obligation is sensitive to the discount
rate, compensation increases, retirements and termination rates as set out
above. An increase or decrease of the estimated discount rate of 4.4 percent
by 100 basis points at December 31, 2012 is considered reasonably possible in
the next financial year. A discount rate of 5.4 percent would decrease the
obligation by $18.2 million. A discount rate of 3.4 percent would increase the
obligation by $23.2 million.

The overall expected long-term rate of return on assets is 5.8 percent. The
expected long-term rate of return is based on the portfolio as a whole and not
the sum of the returns on individual asset categories. The return is based
exclusively on historical returns, without adjustments.

Historical information

                                                                  
December 31                    2011                               2010
                    Registered   Supplemental   Registered            Supplemental
($ thousands)               Plan             Plan           Plan                      Plan
Present value of                                            
the defined
benefit
obligation               100,138            5,092         90,090                     4,382
Fair value of                                               
plan assets               89,383                         89,609                         
(Deficit) in the                                            
plan                    (10,755)          (5,092)          (481)                   (4,382)
Experience                                                  
adjustments
arising on plan
liabilities                                                886                       356
Experience                                                  
adjustments
arising on plan
assets                     7,639                        (2,968)                         
                                                                             
December 31                    2009                               2008
                    Registered   Supplemental   Registered            Supplemental
($ thousands)               Plan             Plan           Plan                      Plan
Present value of                                            
the defined
benefit
obligation                76,873            4,110         58,359                     3,000
Fair value of                                               
plan assets               78,852                         60,682                         
(Deficit)/surplus                                           
in the plan                1,979          (4,110)          2,323                   (3,000)
Experience                                                  
adjustments                                                        </td*Story
arising on plan                                                    too large*
liabilities                1,402             (14)              

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