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Pembina Pipeline Corporation announces fourth quarter and annual results

March 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
    ($ millions, except where           December 31         12 Months Ended
    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        0.28       0.27       0.87       0.99
    and 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          172.3       66.0      493.8      305.8
    operating activities(1)

    Adjusted cash flow from           0.59       0.39       1.91       1.83
    operating 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.
      o 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.
      o The Company is nearing completion of the Phase 1 NGL expansion,
        which is expected to cost $30million and add approximately 17
        thousand barrels per day ("mbpd") of additional NGL capacity to the
        Northern NGL System in the second quarter of 2013.
      o 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 $70million.
      o 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 $30million.
        --  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"):
      o 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):
      o 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:
      o 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;
      o 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;
      o 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;
      o Pembina successfully completed and commissioned an 8,000 bpd
        expansion at its Redwater fractionator on schedule and under budget
        in September 2012;
      o 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;
      o 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,
      o 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(TM)
                per day                            and Dividend
                                                   Reinvestment Plan

    mboe/d      thousands of barrels of     Frac   Fractionation
                oil equivalent per day

    MMcf/d      millions of cubic feet      IFRS   International Financial
                per day                            Reporting Standards

    bcf/d       billions of cubic feet      NGL    Natural gas liquids
                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         2012       2011       2012       2011
    noted)

    Average throughput -             480.2      422.8      456.3      413.9
    Conventional Pipelines
    (mbpd)

    Contracted capacity - Oil        870.0      870.0      870.0      870.0
    Sands & Heavy Oil (mbpd)

    Average processing volume -       46.0       45.3       45.9       42.3
    Gas Services (mboe/d)net to
    Pembina(1)

    NGL sales volume - NGL           115.8               97.7(3)
    Midstream (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,              968.6      308.0    2,475.0    1,072.3
    including 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                  47.8       19.6      173.6       68.0
    amortization 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                     27.3       21.0       97.5       62.2
      administrative expenses

      Acquisition-related and          0.5        0.8       24.7        1.4
      other 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                27.1      (0.2)       75.3       38.9
    (reduction)

    Earnings for the period           81.3       45.0      225.0      165.7

    Earnings per share - basic        0.28       0.27       0.87       0.99
    and diluted (dollars)

    Adjusted earnings(2)             115.8       43.7      283.7      208.9

    Adjusted earnings per share       0.40       0.26       1.10       1.25
    (2)

    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          172.3       66.0      493.8      305.8
    operating activities(2)

    Adjusted cash flow from           0.59       0.39       1.91       1.83
    operating 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
                   Revenue Margin(2)   Revenue Margin(2)   Revenue Margin(2)   Revenue Margin(2)
    ($ millions)       (1)                 (1)                 (1)                 (1)

    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       2012       2011       2012       2011
    noted)

    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                 0.8        1.3        0.1        4.4
    commodity-related
    derivative financial
    instruments

    Operating margin(1)             57.9       41.6      209.3      181.5

    Depreciation and                 7.8       11.1       44.0       41.6
    amortization 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.
      o 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.
      o 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.
      o 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.
      o 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"):
      o 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):
      o 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       2012       2011       2012       2011
    noted)

    Capacity under contract        870.0      870.0      870.0      870.0
    (mbpd)

    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                 5.0        4.9       19.8       12.8
    amortization 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         2012       2011       2012       2011
    noted)

    Average processing volume        276.0      271.5      275.2      253.8
    (MMcf/d) net to Pembina

    Average processing volume         46.0       45.3       45.9       42.3
    (mboe/d) (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                   3.7        2.6       14.5        9.9
    amortization 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         2012       2011       2012       2011
    noted)

    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,              975.0      308.0    2,494.5    1,072.4
    including product purchases

    Realized gain (loss) on           10.2      (0.4)      (4.7)        0.9
    commodity related
    derivative financial
    instruments

    Operating margin(3)              119.5       23.4      288.5       93.2

    Depreciation and                  31.3        0.9       95.3        3.6
    amortization 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:
      o 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.
      o 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 (Buy)/Sell Effective
                                                              Period

    2013 Natural Gas   CDN $3.29 per  (19,500) gjpd           April 1 -
                       gj(1)(6)                               October 31

         Crude Oil     US $89.32 per       675 bpd            April 1 -
                       bbl(2)(6)                              October 31

                       CDN $86.43 per   10,150 bpd            January 1 -
                       bbl(2)(8)                              January 31

         Propane       US $0.955 per       528 bpd            April 1 -
                       gallon(3)(6)                           December 31

         Normal Butane US $1.507 per       500 bpd            April 1 -
                       gallon(4)(6)                           October 31

         ISO Butane    US $1.636 per       250 bpd            April 1 -
                       gallon(5)(6)                           October 31

         Foreign       Sell US                                April 1 -
         Exchange      $8,400,000 @                           October 31
                       0.9956(7)

                       Sell US                                April 1 -
                       $20,850,000 @                          December 31
                       0.9979(7)

    2014 Propane       US $0.955 per       745 bpd            January 1 -
                       gallon(3)(6)                           March 31

         Foreign       Sell US                                January 1 -
         Exchange      $2,700,000 @                           March 31
                       0.9979(7)

    (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 % Change      2012        2011     % Change

    WTI crude     $88.18 $94.06      (6)    $94.21      $95.12          (1)
    oil (U.S.
    $ per bbl)

    Exchange       $0.99  $1.03        3     $1.00       $0.99
    rate (from                                                          (1)
    U.S.$ to
    Cdn$)

    WTI crude     $87.31 $96.68     (10)    $94.12      $94.21
    oil
    (expressed
    in Cdn$
    per bbl)

    AECO           $2.90  $3.29     (12)     $2.28       $3.48         (34)
    natural
    gas index
    (Cdn$ per
    GJ)

    Mont           $0.88  $1.44     (39)     $1.00       $1.47         (32)
    Belvieu
    Propane
    (U.S.$ per
    U.S.
    gallon)

    Mont             42%    64%     (34)       45%         65%         (31)
    Belvieu
    Propane
    expressed
    as a
    percentage
    of WTI

    Market        $38.61 $58.41     (34)    $44.70      $54.67         (18)
    Frac
    Spread in
    Cdn$ 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.
      o 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).
      o 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).
      o 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.
      o Butane and condensate sales prices were robust in the fourth
        quarter; however, price levels remained below those of 2011.
      o 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                        145.0             113.8
    outstanding (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             1,806.3           1,225.0
    (average of 4.90%)

    Convertible debentures(2)                       644.3             299.8

    Finance lease liability                           5.8               5.6

    Total debt and debentures                     2,601.4           1,644.2
    outstanding

    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

    Contractual                   Less than                           After
    Obligations             Total    1 year 1 - 3 years 3 - 5 years 5 years

    Operating and finance   293.0      25.4        55.5        58.8   153.6
    leases

    Loans and borrowings  2,446.7      80.6       368.9       637.2 1,360.0
    (1)

    Convertible             903.5      39.2        78.9       251.7   533.7
    debentures(1)

    Construction            362.8     324.2        38.6
    commitments

    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,        February 26, December 31, 2012 December 31, 2011
    except where             2013(2)
    noted)

    Trading volume and
    value

      Total volume       19,509,172        180,317,622        75,574,785
      (shares)

      Average daily         500,235            718,397           325,753
      volume (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             28.89              28.46             29.66
    price (dollars)

    Market value                                                        

      Shares                8,520.4            8,345.2           4,980.2

      5.75%                 334.0(3)          332.7(4)          326.8(5)
      convertible
      debentures
      (PPL.DB.C)

      5.75%                 205.3(6)          201.4(7)
      convertible
      debentures
      (PPL.DB.E)

      5.75%                 193.5(8)          191.0(9)
      convertible
      debentures
      (PPL.DB.F)

    Market                  9,253.2            9,070.3           5,306.9
    capitalization

    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(TM)”) equal to 102 percent
of the amount of reinvested dividends, pursuant to the “Premium
Dividend(TM) 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      480.2 443.9 433.9 466.9 422.8 430.4 411.4 390.3 375.0
    Throughput

    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       46.0  45.8  47.5  44.1  45.3  43.6  40.9  39.4  42.1
    Processing
    (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 margin        222.1       177.5  148.9 127.7 105.9 103.6 110.3  97.3  86.2
    (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 EBITDA         199.0       153.8  125.9 111.4  88.2  89.9 103.3  87.2  79.1
    (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 period         293.2       290.5  287.8 169.0 167.9 167.7 167.5 167.1 166.9

    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    1.61          1.56          1.56
    share)

         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           2012       2011       2012       2011
    share amounts)

    Results from operating           144.3       65.5      416.5      290.7
    activities

    Share of profit from equity        2.0        3.2        6.2       12.9
    accounted investees
        (before tax,
    depreciation and
    amortization)

    Depreciation and                  49.5       20.4      179.4       70.2
    amortization

    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                1.0                  24.1
    expenses

    Adjusted EBITDA                  199.0       88.2      590.1      368.6

    EBITDA per common share -         0.68       0.53       2.19       2.20
    basic (dollars)

    Adjusted EBITDA per common        0.68       0.53       2.28       2.20
    share - 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           2012       2011       2012       2011
    share amounts)

    Earnings before income tax       108.5       43.3      301.3      198.8
    and equity accounted
    investees

    Add (deduct):                                                          

    Unrealized (gains) losses          6.4      (1.6)     (40.2)        2.4
    on fair 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                1.0                  24.1
    expenses

    Adjusted earnings                115.8       43.7      283.7      208.9

    Adjusted earnings per             0.40       0.26       1.10       1.25
    common share - 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          2012       2011       2012       2011
    share amounts)

    Cash flow from operating        139.5       73.8      359.8      285.5
    activities

    Add (deduct):                                                         

    Change in non-cash working       31.8      (7.8)      109.9       20.3
    capital

    Acquisition-related               1.0                  24.1
    expenses

    Adjusted cash flow from         172.3       66.0      493.8      305.8
    operating activities

    Adjusted cash flow from          0.59       0.39       1.91       1.83
    operating 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,          968.6      308.0    2,475.0    1,072.3
      including 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                47.8       19.6      173.6       68.0
    amortization 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            27    31,529     10,471
    financial 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                301,347    198,769
    accounted investees

      Share of loss (profit) of investments in             1,056    (5,766)
      equity 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               (36,100)   (5,176)
      derivative financial instruments

      Net finance costs                              21   115,140    91,927

      Share of loss (profit) of investments in              1,056   (5,766)
      equity 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     15 (181,148) (261,102)
      the 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),         27,336     (676)
    end of 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,                                                200,726                      3,603,950
    2011               67,219     2,500,027        528,620          (1)          307,358           (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 as         Series C -     Series E -      Series F -
    noted)                 5.75%          5.75%           5.75%      Total

    Conversion
    price
    (dollars)             $28.55         $24.94          $29.53            

    Interest
    payable                             June 30
    semi-annually     May 31 and            and
    in arrears          November       December     June 30 and
    on:                       30             31     December 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          5,782          2,207
    and 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
                                           Sands &                           Corporate &
    Year Ended December     Conventional     Heavy        Gas   Midstream   Intersegment
    31, 2012($ thousands)   Pipelines(1)       Oil   Services         (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.

          NGL product and services, terminalling, storage and hub services
    (2)   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
    arising on plan
    liabilities                1,402             (14)                             211

    Experience
    adjustments
    arising on plan
    assets                   (7,417)                          17,702                 

The Company expects $12.6 million in contributions to be paid to its
defined benefit plans in 2013.

26. SHARE-BASED PAYMENTS

At December 31, 2012, the Company has the following share-based payment
arrangements:

Share option plan (equity settled)

The Company has a share option plan under which employees are eligible
to receive options to purchase shares in the Company.

Long-term share unit award incentive (cash-settled) plan

In 2005, the Company established a long-term share unit award incentive
plan. Under the share-based compensation plan, awards of restricted
(RSU) and performance (PSU) share units are made to officers,
non-officers and directors. The plan results in participants receiving
cash compensation based on the value of the underlying notional shares
granted under the plan. Payments are based on a trading value of the
Company’s common shares plus notional dividends and performance of the
Company.

Terms and conditions of share option plan and share unit award incentive
plan

The terms and conditions relating to the grants of the share option
program and the long-term share unit award incentive plans are listed
in the tables below:


    Grant date share options
    granted to employees
    (Number of units in            Number of options       Contractual life
    thousands)                          in thousands             of options

    August 3, 2011                             1,052                7 years

    October 1, 2011                               48                7 years

    January 3, 2012                               55                7 years

    April 2, 2012                                 19                7 years

    August 9, 2012                             1,372                7 years

    October 1, 2012                               49                7 years

One third vest on the first anniversary of the grant date, one third
vest on the second anniversary of the grant date, and one third vest on
the third anniversary of the grant date.

Long-term share unit award incentive plan((1))


    Grant date PSUs to Officers,
    Non-Officers(2) and Directors                    Contractual life
    (Number of units in thousands)       Units                 of PSU

    January 1, 2011                        284              3.0 years

    January 1, 2012                        188              3.0 years

    April 2, 2012 (on acquisition)         201              2.2 years

Vest on the third anniversary of the grant date. Actual PSUs awarded is
based on the trading value of the shares and performance of the
Company.


    Grant date RSUs to Officers,
    Non-Officers(2) and Directors                    Contractual life
    (Number of units in thousands)       Units                 of RSU

    January 1, 2011                        185              3.0 years

    January 1, 2012                        186              3.0 Years

    April 2, 2012 (on acquisition)         177              2.2 Years

One third vest on the first anniversary of the grant date, one third
vest on the second anniversary of the grant date, and one third vest on
the third anniversary of the grant date.


           Distribution Units are granted in addition to RSU and PSU grants
    (1)   based on notional accrued dividends from RSU and PSU granted but
          not paid.

    (2)   Non-Officers defined as senior selected positions within the
          Company.

Disclosure of share option plan

The number and weighted average exercise prices of share options as
follows:


                                                         Weighted Average
                                 Number of Options         Exercise Price

    Outstanding at
    December 31, 2010                    2,759,259                  16.43

    Granted                              1,100,800                  25.29

    Exercised                          (1,023,916)                  15.48

    Forfeited                            (161,763)                  19.75

    Outstanding at
    December 31, 2011                    2,674,380                  20.24

    Granted                              1,495,050                  26.70

    Exercised                            (427,934)                  16.96

    Forfeited or expired                 (209,858)                  24.73

    Outstanding as at
    December 31, 2012                    3,531,638                  23.11

As of December 31, 2012, the following options are outstanding:


                            Number                             Weighted
                          outstanding                           average
    Exercise Price      at December 31,       Options       remaining life
       (dollars)             2012           Exercisable         (years)

    $14.18 - $17.99           589,433          589,433               1.5

    $18.00 - 20.99            593,380          369,124               4.6

    $21.00 - $30.06         2,348,825          288,723               6.2

The weighted average share price at the date of exercise for share
options exercised in the year ended December 31, 2012 was $28.28
(December 31, 2011: $24.64).

Expected volatility estimated by considering historic average share
price volatility. The weighted average inputs used in the measurement
of the fair values at grant date of share options are the following:

Share options granted


    Year ended December 31                                          

    (dollars)                                      2012         2011

    Weighted average                                                

      Fair value at grant date                    $2.10        $2.72

      Share price at grant date                  $26.68       $25.72

      Exercise price                             $26.70       $25.29

      Expected volatility                         21.4%        24.7%

      Expected option life (years)                 3.67         3.67

    Expected annual dividends per option          $1.61        $1.56

    Expected forfeitures                           7.9%         7.0%

    Risk-free interest rate (based on
    government bonds)                              1.3%         1.6%

Disclosure of long-term share unit award incentive plan

The long-term share unit award incentive plan was valued using the
reporting date market price of the Company’s shares of $28.46 (December
31, 2011: $29.66). Actual payment may differ from amount valued based
on market price and company performance.

Long-term share unit award incentive units granted


    Year ended December 31                   2012            2011

    Number of share units granted         752,187         469,253

Employee expenses


    ($ thousands)                                        2012         2011

    Share option plan, equity settled                   1,828        1,097

    Long-term share unit award incentive plan          15,200       17,554

    Total expense recognized as employee costs         17,028       18,651

    Total carrying amount of liabilities for
    cash settled arrangements                          33,506       22,971

    Total intrinsic value of liability for
    vested benefits                                    16,267        8,911

27. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

Economic hedges

The Company has entered into derivative financial instruments to limit
the exposures to changes in commodity prices, interest rates, cost of
power and foreign currency exchange rates. Hedge accounting has not
been applied, however the Company still considers that there is an
economic hedge which limits the exposure to fluctuations in revenue and
expenses.

Financial risk

The Company has exposure to credit risk, liquidity risk and market risk.
The Company’s Board of Directors has the overall responsibility for the
oversight of these risks and reviews the Company’s policies on an
ongoing basis to ensure that these risks are appropriately managed. The
Company’s Audit Committee oversees how management monitors compliance
with the Company’s risk management policies and procedures and reviews
the adequacy of this risk framework in relation to the risks faced by
the Company. The Company’s Risk Management function assists in managing
these risks. The Company’s primary risk management objective is to
protect capital resources, earnings and cash flow.

Counterparty credit risk

Counterparty credit risk is the risk of financial loss to the Company if
a customer, partner or counterparty to a financial instrument failed to
meet its contractual obligations in accordance with the terms and
conditions of the financial instruments with the Company and which
arise primarily from the Company’s cash and cash equivalents, trade and
other receivables, and from counterparties to its derivative financial
instruments. The carrying amount of the financial assets represents the
maximum credit exposure to the Company. The maximum counterparty credit
exposure to counterparty credit risk at the reporting date was:


                                               Carrying Amount

    December 31
    ($ thousands)                             2012          2011

    Cash and cash equivalents               27,336              

    Trade and other receivables            334,772       159,081

    Derivative financial instruments         7,871         6,450

                                           369,979       165,531

The Company manages counterparty credit risk for its cash and cash
equivalents by maintaining bank accounts with Schedule 1 banks. The
Company has minimal counterparty credit risk related to its receivables
as a majority of these amounts are with large established
counterparties in the oil and gas industry and are subject to the terms
of the Company’s shipping rules and regulations or pursuant to
contracts. The rules and regulations permit the Company to receive and
hold financial assurances against a counterparty to cover current and
aged receivables when warranted. Balances are generally payable the
25th day of the following month. This date coincides with the date on
which oil and gas companies receive payment from industry partners and
counterparties. Typically, the Company has collected its receivables in
full and at December 31, 2012, approximately 93 percent were current.
The Company also maintains lien rights on the oil and NGL that are in
its custody during the transportation of such products on the pipeline
as well as the right to offset for single shipper operations.
Therefore, the risk of non-collection is considered to be low and no
impairment of receivables has been made.

Additionally, counterparty credit risk is mitigated through established
credit management techniques, including conducting comprehensive
financial and other assessments for all new counterparties and regular
reviews of existing counterparties to establish and monitor a
counterparty’s creditworthiness, setting exposure limits, monitoring
exposures against these limits, using contract netting arrangements and
obtaining financial assurances when warranted. In general, financial
assurances include guarantees, letters of credit and cash. The Company
monitors and manages its concentration of counterparty credit risk on
an ongoing basis. The Company believes these measures minimize its
counterparty credit risk but there is no certainty that they will
protect it against all material losses. Letters of credit mitigate the
counterparty credit risk on $44.6 million (December 31, 2011: $7.8
million) of the receivables balance. The Company’s assessment of a
counterparty’s creditworthiness includes external credit ratings, where
available, and in other cases, detailed financial and other assessments
which generate an internal credit rating based on financial ratios.
Counterparty exposure limits are established for each counterparty
representing the maximum unsecured dollar amount in conjunction with an
associated counterparty exposure limit approval authority matrix which
has been approved by the Risk Management Committee. The Company
continues to closely monitor and reassess its counterparty exposure
limits on an ongoing basis.

Liquidity risk

Liquidity risk is the risk the Company will not be able to meet its
financial obligations as they come due. The following are the
contractual maturities of financial liabilities, including estimated
interest payments and excluding the impact of netting agreements.


                                                    Outstanding balances due by
                                                                         period            

    December
    31, 2012                   Expected         6
    ($             Carrying        Cash    Months    6 - 12     1 - 2     2 - 5   More Than
    thousands)       Amount       Flows   or Less    Months     Years     Years     5 Years

    Trade
    payables
    and accrued
    liabilities     344,208     344,208   344,208                                          

    Loans and
    borrowings    1,938,626   2,446,733    44,927    35,637   312,765   693,389   1,360,015

    Finance
    lease
    liabilities       5,800       7,101     1,327     1,327     1,823     2,624            

    Convertible
    debentures      609,968     903,475    19,607    19,607    39,360   291,204     533,697

    Dividends
    payable          39,586      39,586    39,586                                          

    Derivative
    financial
    liabilities      67,691      67,691    11,532     4,400    16,774    25,115       9,870

                                                    Outstanding balances due by
                                                                         period            

    December
    31, 2011                   Expected         6
    ($             Carrying        Cash    Months    6 - 12     1 - 2     2 - 5   More Than
    thousands)       Amount       Flows   or Less    Months     Years     Years     5 Years

    Bank
    overdraft           676         676       676                                          

    Trade
    payables
    and accrued
    liabilities     155,926     155,926   155,926                                          

    Unsecured
    notes and
    credit
    facilities    1,272,838   1,663,644    27,120   340,285   350,445   117,494     828,300

    Senior
    secured
    notes            57,499      70,909     6,257     6,257    25,027    33,368            

    Finance
    lease
    liabilities       5,650       7,742     1,273     1,273     1,942     3,254            

    Convertible
    debentures      289,365     299,780                                             299,780

    Dividends
    payable          21,828      21,828    21,828                                          

    Derivative
    financial
    liabilities      17,539      18,460     2,385     2,385     3,670     6,438       3,582

The Company’s approach to managing liquidity risk is to ensure funds and
credit facilities are available to meet its short-term obligations.
Management monitors daily cash positions and performs cash forecasts
weekly to determine cash requirements. On a monthly basis, Management
typically forecasts cash flows for a period of 12 months to identify
financing requirements. These financing requirements are then addressed
through a combination of credit facilities and through access to
capital markets if required.

Market risk

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

a. Price risk

Commodity price volatility and market location differentials affect the
Midstream business. In addition, Midstream is exposed to possible price
declines between the time Pembina purchases NGL feedstock and sells NGL
products, and to narrowing frac spreads. Frac spreads are the
difference between the selling prices for propane-plus and the input
cost of the natural gas required to produce the respective NGL
products.

Pembina responds to these risks using a market risk management program
to protect margins on a portion of its natural gas based supply sales
contracts, and to manage physical contract exposure while retaining
some ability to participate in a widening margin environment. The
Company uses derivative financial instruments to manage exposure to
commodity prices and power costs. The Company does not trade financial
instruments for speculative purposes. The derivative instruments
include participating swaps and fixed price swap contracts that settle
against indexed reference pricing. Participating swaps are contracts
that provide a floor and ceiling for a certain percentage of the volume
of a contract. A swap contract is an agreement where a floating price
is exchanged for a fixed price over a specified period.

b. Currency risk

Pembina’s commodity sales are exposed to both positive and negative
effects of fluctuations in the Canadian/U.S. exchange rate. Pembina
manages this exposure by matching a significant portion of the cash
costs that it expects with revenues in the same currency. In addition,
Pembina uses derivative instruments to manage the U.S. cash
requirements of its business.

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

c. Interest rate risk

At the reporting date, the interest rate profile of the Company’s
interest-bearing financial instruments was:


    ($ thousands)                   Carrying Amounts of Financial Liability

    December 31                            2012                        2011

    Fixed rate instruments          (1,417,950)                 (1,324,758)

    Variable rate instruments         (520,675)                   (319,465)

The Company uses swap contracts to manage exposure to variable interest
rates.

Cash flow sensitivity analysis for variable rate instruments

A change of 100 basis points in interest rates at the reporting date
would have (increased) decreased profit or loss by the amounts shown
below. This analysis assumes that all other variables remain constant.


    December 31($ thousands)                      2012              2011

                                                 100 bp             100 bp

    Variable rate instruments                     5,250              3,149

    Interest rate swap                          (3,800)            (2,000)

    Profit or loss sensitivity (net)              1,450              1,149

Fair values

The fair values of financial assets and liabilities, together with the
carrying amounts shown in the statement of financial position, are as
follows:


    December 31                       2012                        2011

                         Carrying          Fair      Carrying          Fair
    ($ thousands)          Amount         Value        Amount         Value

    Financial
    assets carried
    at fair value                                                          

    Derivative
    financial
    instruments             7,871         7,871         6,450         6,450

    Financial
    assets carried
    at amortized
    cost                                                                   

    Cash and cash
    equivalents            27,336        27,336                            

    Trade and
    other
    receivables           334,772       334,772       159,081       159,081

                          362,108       362,108       159,081       159,081

    Financial
    liabilities
    carried at
    fair value                                                             

    Derivative
    financial
    instruments            67,691        67,691        17,538        17,538

    Financial
    liabilities
    carried at
    amortized cost                                                         

    Bank overdraft                                        676           676

    Trade payables
    and accrued
    liabilities           344,208       344,208       155,926       155,926

    Finance lease
    liabilities             5,800         6,170         5,650         5,948

    Dividends
    payable                39,586        39,586        21,828        21,828

    Loans and
    borrowings          1,938,626     2,083,505     1,272,838     1,391,895

    Senior secured
    notes                                              57,499        65,567

    Convertible
    debentures         609,968(1)       725,074       289,365       326,760

                        2,938,188     3,198,543     1,803,782     1,968,600

((1)) Carrying amount excludes conversion feature of convertible debentures.

The basis for determining fair values is disclosed in Note 4.

Interest rates used for determining fair value

The interest rates used to discount estimated cash flows, when
applicable, are based on the government yield curve at the reporting
date plus and adequate credit spread, and were as follows:


    December 31                         2012                2011

    Derivatives                  1.2% - 2.5%         1.1% - 1.8%

    Loans and borrowings         2.0% - 3.7%         2.2% - 4.2%

    Leases                              4.4%                4.8%

Fair value of power derivatives are based on market rates reflecting
forward curves.

Fair value hierarchy

The fair value of financial instruments carried at fair value is
classified according to the following hierarchy based on the amount of
observable inputs used to value the instruments.

Level 1: Unadjusted quoted prices are available in active markets for
identical assets or liabilities as the reporting date. Pembina does not
use Level 1 inputs for any of its fair value measurements.

Level 2: Inputs other than quoted prices included within Level 1 that
are observable for the asset or liability, either directly (i.e. as
prices) or indirectly (i.e. derived from prices). Level 2 valuations
are based on inputs, including quoted forward prices for commodities,
time value and volatility factors, which can be substantially observed
or corroborated in the marketplace. Instruments in this category
include non-exchange traded derivatives such as over-the-counter
physical forwards and options, including those that have prices similar
to quoted market prices. Pembina obtains quoted market prices for
commodities, future power contracts, interest rates and foreign
exchange rates from information sources including banks, Bloomberg
Terminals and Natural Gas Exchange (NGX). With the exception of one
item described under Level 3, all of Pembina’s financial instruments
carried at fair value are valued using Level 2 inputs.

Level 3: Valuations in this level require the most significant judgments
and consist primarily of unobservable or non-market based inputs. Level
3 inputs include longer-term transactions, transactions in less active
markets or transactions at locations for which pricing information is
not available. In these instances, internally developed methodologies
are used to determine fair value. The redemption liability related to
Three Star is classified as a Level 3 instrument, as the fair value is
determined by using inputs that are not based on observable market
data. The liability represents a put option, held by the
non-controlling interest of Three Star, to sell the remaining one-third
of the business to Pembina after the third anniversary of the original
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 Three Star’s earnings during the three year period prior to
exercise, adjusted for associated capital expenditures and debt based
on management estimates. These estimates are subject to measurement
uncertainty and the effect on the financial statements of future
periods could be material.

Financial instruments classified as Level 3


    ($ thousands)                                      2012         2011

    Redemption liability, beginning of year                             

    Assumed on acquisition                            6,183             

    Accretion of liability                               65             

    Gain on revaluation                               (962)             

    Redemption liability, end of year                 5,286             

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


    As at December 31 ($ thousands)                  2012             2011

    Frac spread related                           (3,068)                 

    Product margin                                (1,088)            2,267

    Corporate                                                             

      Power                                       (7,100)            4,183

      Interest rate                              (14,302)         (17,538)

      Foreign exchange                                653                 

    Other derivative financial
    instruments                                                           

      Conversion feature of convertible
      debentures (Note 13)                       (29,629)                 

      Redemption liability related to
      acquisition of subsidiary                   (5,286)                 

    Net derivative financial instruments
    liability                                    (59,820)         (11,088)

In conjunction with the Acquisition, the Company assumed all of the
rights and obligations of Provident relating to the Provident
Debentures which included a $29.7 million liability for the conversion
feature of the Provident Debentures. These convertible debentures
contain a cash conversion option which is measured at fair value
through profit and loss at each reporting date, with any unrealized
gains or losses arising from fair value changes reported in the
consolidated statement of comprehensive income. This resulted in the
Company recording a gain of $0.1 million on the revaluation on the
conversion feature of convertible debentures in profit and loss in net
finance costs for the year ended December 31, 2012.


    Commodity-Related Derivative Financial                  Year Ended
    Instruments                                            December 31

    ($ thousands)                                       2012          2011

    Realized (loss) gain on commodity-related
    derivative financial instruments                                      

    Frac spread related                              (4,497)              

    Product margin                                     (141)           882

    Power                                                 67         4,413

    Realized (loss) gain on commodity-related
    derivative financial instruments                 (4,571)         5,295

    Unrealized gain on commodity-related
    derivative financial instruments                  36,100         5,176

    Gain on commodity-related derivative
    financial instruments                             31,529        10,471

For non-commodity-related derivative financial instruments see Note 21,
Net Finance Costs.

Sensitivity analysis

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


    As at December 31,                                + Change     - Change
    2012 ($ thousands)

    Frac spread related                                                  

      Natural gas             (AECO +/- $1.00 per       6,724      (6,724)
                              GJ)

      NGL (includes           (Belvieu +/- U.S.       (3,991)        3,991
      propane, butane)        $0.10 per gal)

      Foreign exchange        (FX rate +/- $0.05)     (3,637)        3,637
      (U.S.$ vs. Cdn$)

    Product margin                                                       

      Crude oil               (WTI +/- $5.00 per      (6,387)        6,387
                              bbl)

      NGL (includes           (Belvieu +/- U.S.         6,112      (6,112)
      propane, butane         $0.10 per gal)
      and condensate)

    Corporate                                                            

      Interest rate           (Rate +/- 50 basis        3,857      (3,857)
                              points)

      Power                   (AESO +/- $5.00 per       3,631      (3,631)
                              MW/h)

    Conversion feature        (Pembina share          (2,761)        2,629
    of convertible            price +/- $0.50 per
    debentures                share)

28. OPERATING LEASES

Leases as lessee

Operating lease rentals are payable as follows:


    December 31 ($ thousands)            2012           2011

    Less than 1 year                   22,754          6,237

    Between 1 and 5 years             109,542         20,021

    More than 5 years                 153,574         40,494

                                      285,870         66,752

The Company leases a number of offices, warehouses, vehicles and rail
cars under operating leases. The leases run for a period of one to
fifteen years, with an option to renew the lease after that date. The
Company has sublet office space up to 2022 and has contracted sub-lease
payments of $51.4 million over the term.

During the year ended December 31, 2012, an amount of $7.1 million was
recognized as an expense in profit or loss in respect of operating
leases (December 31, 2011: $3.8 million).

29. CAPITAL MANAGEMENT

The Company’s objective when managing capital is to safeguard the
Company’s ability to provide a stable stream of dividends to
shareholders that is sustainable over the long-term. The Company
manages its capital structure and makes adjustments to it in light of
changes in economic conditions and risk characteristics of its
underlying asset base and based on requirements arising from
significant capital development activities. Pembina manages and
monitors its capital structure and short-term financing requirements
using Non-GAAP measures; the ratios of debt to EBITDA, debt to
Enterprise Value (market value of common shares and convertible
debentures), adjusted cash flow to debt and debt to equity. The metrics
are used to measure the Company’s overall debt position and measure the
strength of the Company’s balance sheet. The Company remains satisfied
that the leverage currently employed in the Company’s capital structure
is sufficient and appropriate given the characteristics and operations
of the underlying asset base. The Company, upon approval from its Board
of Directors, will balance its overall capital structure through new
equity or debt issuances as required.

The Company maintains a conservative capital structure that allows it to
finance its day-to-day cash requirements through its operations,
without requiring external sources of capital. The Company funds its
operating commitments, short-term capital spending as well as its
dividends to shareholders through this cash flow, while new borrowing
and equity issuances are reserved for the support of specific
significant development activities. The capital structure of the
Company consists of shareholder’s equity plus long-term liabilities.
Long-term debt is comprised of bank credit facilities, unsecured notes,
finance lease obligations and convertible debentures.

Pembina is subject to certain financial covenants in its credit facility
agreements and is in compliance with all financial covenants as of
December 31, 2012.

Note 15 of these financial statements demonstrates the change in Share
Capital for the year ended December 31, 2012.

30. GROUP ENTITIES

Significant subsidiaries


                                                  Ownership Interest

    December 31 (percentages)                        2012         2011

    Pembina Pipeline                                  100          100

    Pembina Gas Services Limited Partnership          100          100

    Pembina Oil Sands Pipeline LP                     100          100

    Pembina Midstream Limited Partnership             100          100

    Pembina North Limited Partnership                 100          100

    Pembina West Limited Partnership                  100          100

    Pembina NGL Corporation                           100             

    Pembina Facilities NGL LP                         100             

    Pembina Infrastructure and Logistics LP           100             

    Pembina Empress NGL Partnership                   100             

    Pembina Resource Services Canada                  100             

    Pembina Resource Services (U.S.A.)                100             

    Three Star Trucking Ltd.                           67             

31. RELATED PARTIES

All transactions with related parties were made on terms equivalent to
those that prevail in arm’s length transactions.

Investments in equity accounted investees

Officers of Pembina Pipeline Corporation, the ultimate controlling
party, are Directors of Fort Saskatchewan Ethylene Storage Corporation
(“FSESC”), the parent of Fort Saskatchewan Ethylene Storage Limited
Partnership (“FSESLP”). FSESLP and FSESC are both recognized as
investments in joint ventures under the equity method on Pembina’s
financial statements. Results from operating activities are recorded as
Share of Profit from Equity Accounted Investees on Pembina’s Statement
of Comprehensive Income, representing a 50 percent interest in the
joint ventures.


                                             Transaction          Balance
                                                Value           Outstanding
    ($                                       Year Ended       As At December
    thousands)                               December 31            31

                                            2012     2011     2012       2011

    Related        Transaction     Note
    Party

                   Interest                  262      876
    FSESLP         revenue

                   Loan                                                17,903
                   receivable

Key management personnel and director compensation

Key management consists of the Company’s directors and certain key
officers.

Compensation

In addition to short-term employee benefits – including salaries,
director fees and bonuses – the Company also provides key management
personnel with share-based compensation, contributes to post employment
pension plans and provides car allowances, parking and business club
memberships.

Key management personnel compensation comprised:


    Year Ended December 31 ($ thousands)            2012          2011

    Short term employee benefits                   2,743         2,802

    Post-employment benefits                         231           207

    Share-based compensation                       5,806         6,150

    Other compensation                               121           112

    Total compensation of key management           8,901         9,271

Transactions

Key management personnel and directors of the Company control 0.5
percent (2011: 0.8 percent) of the voting common shares of the Company.
Certain directors and key management personnel also hold Pembina
convertible debentures. Dividend and interest payments received for the
common shares and debentures held are commensurate with other
non-related holders of those instruments.

Certain officers are subject to employment agreements in the event of
termination without just cause or change of control.

Post employment benefit plans

Pembina has significant influence over the pension plans for the benefit
of their respective employees.

Transactions


                                            Transaction         Balance
                                               Value          Outstanding
                                             Year Ended      As At December
    ($ thousands)                           December 31            31

    Post-employment
    benefit plan          Transaction       2012    2011     2012      2011

    Defined benefit
    plan                  Funding         10,000   8,000                   


CORPORATE INFORMATION
_______________________________________________________________________________


HEAD OFFICE

Pembina Pipeline Corporation
Suite 3800, 525 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1

AUDITORS

KPMG LLP
Chartered Accountants
Calgary, Alberta

TRUSTEE, REGISTRAR & TRANSFER AGENT

Computershare Trust Company of Canada
Suite 600, 530 – 8th Avenue SW
Calgary, Alberta T2P 3S8
1-800-564-6253

STOCK EXCHANGE

Pembina Pipeline Corporation
TSX listing symbols for:
Common shares: PPL
Convertible debentures: PPL.DB.C, PPL,DB.E, PPL.DB.F

NYSE listing symbol for:
Common shares: PBA


INVESTOR INQUIRIES

Phone: (403) 231-3156
Fax: (403) 237-0254
Toll Free: 1-855-880-7404
Email: investor-relations@pembina.com
Website: www.pembina.com

SOURCE Pembina Pipeline Corporation


Source: PR Newswire