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Pembina Pipeline Corporation 2012 second quarter results

August 9, 2012

Pembina releases first consolidated results following acquisition of
Provident Energy Ltd.; continues building its fee-for-service business

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 current expectations,
estimates, projections and assumptions in light of its experience and
its perception of historical trends. Actual results may differ
materially from those expressed or implied by these forward-looking
statements. Please see” Forward-Looking Statements & Information” for
more details. This report also refers to financial measures that are
not defined by Canadian Generally Accepted Accounting Principles
(“GAAP”). For more information about the measures which are not defined
by GAAP, see “Non-GAAP Measures.”

CALGARY, Aug. 9, 2012 /PRNewswire/ – On April 2, 2012 Pembina Pipeline
Corporation (“Pembina” or the “Company”) completed its acquisition of
Provident Energy Ltd. (“Provident”) (the “Arrangement”). The amounts
disclosed herein for the three and six month periods ending June 30,
2012 reflect results of the post-Arrangement Pembina from April 2, 2012
together with results of legacy Pembina alone, excluding Provident,
from January 1 through April 1, 2012. The comparative figures reflect
solely the 2011 results of legacy Pembina. For further information with
respect to the acquisition transaction, please refer to Note 3 of the
unaudited interim condensed consolidated financial statements for the
period ended June 30, 2012.

Financial & Operating Overview
(unaudited)


    ($ millions, except        3 Months Ended            6 Months Ended
    where noted)                   June 30                   June 30

                                2012        2011          2012        2011

    Revenue                    870.9       512.4       1,346.4       907.3

    Operating margin(1)        148.9       110.3         276.6       207.6

    Gross profit               161.2        97.8         263.7       180.6

    Earnings for the
    period                      80.4        48.0         113.0        90.5

    Earnings per share -
    basic and diluted
    (dollars)                   0.28        0.29          0.50        0.54

    Adjusted EBITDA(1)         125.9       103.3         237.3       190.5

    Cash flow from
    operating activities        24.1        49.5          89.4       124.0

    Adjusted cash flow
    from operating
    activities(1)               89.5        81.8         188.3       157.8

    Adjusted cash flow
    from operating
    activities per share
    (1)                         0.31        0.49          0.83        0.94

    Dividends declared         116.2        65.3         181.9       130.4

    Dividends per common
    share (dollars)             0.41        0.39          0.80        0.78

((1) )Refer to “Non-GAAP Measures.”

Second Quarter Highlights

        --  Consolidated operating margin during the second quarter
            increased to $148.9 million compared to $110.3 million during
            the same period of the prior year. Year-to-date, operating
            margin totaled $276.6 million compared to $207.6 million in the
            first half of 2011. Pembina's overall results for the quarter
            reflect Pembina's legacy businesses combined with those
            acquired through the Arrangement, which are reported as part of
            the Company's Midstream business. Operating margin is a
            non-GAAP measure; see "Non-GAAP Measures".
        --  Pembina generated $47.5 million in operating margin from
            Conventional Pipelines, $27.8 million from Oil Sands & Heavy
            Oil and $15.0 million from Gas Services. The Midstream business
            saw a significant increase to $58.0 million which includes
            operating margin generated by the assets acquired through the
            Arrangement. Higher results from Pembina's legacy crude oil
            midstream business were somewhat tempered by a weak propane
            pricing environment which impacted the newly acquired NGL
            midstream business. Industry propane inventory levels remain
            high due to decreased demand for the commodity as a result of
            the relatively warm winter across North America.
        --  The Company's earnings were $80.4 million ($0.28 per share)
            during the second quarter of 2012 compared to $48.0 million
            ($0.29 per share) during the second quarter of 2011. Earnings
            were $113.0 million ($0.50 per share) during the first half of
            2012 compared to $90.5 million ($0.54 per share) during the
            same period of the prior year. Earnings for the three and six
            month periods ended June 30, 2012 increased as a result of the
            Arrangement and unrealized gains on commodity-related
            derivative financial instruments. Earnings per share decreased
            primarily due to the 116.5 million shares issued to complete
            the Arrangement.
        --  Pembina generated adjusted EBITDA of $125.9 million during the
            second quarter of 2012 compared to $103.3 million during the
            second quarter of 2011 (adjusted EBITDA is a Non-GAAP measure;
            see "Non-GAAP Measures"). Adjusted EBITDA for the six month
            period ended June 30, 2012 was $237.3 million compared to
            $190.5 million for the same period in 2011. The increase in
            quarterly and year-to-date 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 in
            Pembina's operations since completion of the Arrangement.
        --  Cash flow from operating activities was $24.1 million ($0.08
            per share) during the second quarter of 2012 compared to $49.5
            million ($0.30 per share) during the second quarter of 2011.
            For the six months ended June 30, 2012, cash flow from
            operating activities was $89.4 million ($0.39 per share)
            compared to $124.0 million ($0.74 per share) during the same
            period last year. The decrease in cash flow from operating
            activities during the 2012 periods is primarily due to
            acquisition-related expenses, higher interest expenses and an
            increase in working capital reflecting a seasonal inventory
            build.
        --  Adjusted cash flow from operating activities was $89.5 million
            ($0.31 per share) during the second quarter of 2012 compared to
            $81.8 million ($0.49 share) during the second 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 $188.3 million ($0.83 per share)
            during the first half of 2012 compared to $157.8 million ($0.94
            share) during the same period of last year. Adjusted cash flow
            from operating activities per share decreased primarily due to
            the 116.5 million shares issued to complete the Arrangement.

Growth and Operational Update

Following the acquisition of Provident, Pembina is now one of Canada’s
largest integrated energy infrastructure companies. The Company is
focused on integrating the acquired assets to realize efficiencies and
revenue synergies in the future. Pembina is also pursuing the largest
capital spending program in its history. Progress on Pembina’s major
projects includes:

Conventional Pipelines:

        --  Work to refurbish the Calmar booster station was completed,
            which has expanded the capacity of Pembina's Drayton Valley
            mainline (which serves the Cardium play) from 145 mbpd to 195
            mbpd;
        --  A re-contracting initiative on the Northern NGL pipeline is
            complete, and considerable progress on this project was made.
            The first portion of the expansion is expected to be in-service
            in the fourth quarter of 2012 and is expected to add
            approximately 17 mbpd of additional NGL capacity, with an
            additional 35 mbpd expected to be on stream by the fourth
            quarter of 2013;
        --  The British Columbia Utilities Commission approved an
            application on Pembina's Western System, which will allow
            Pembina to fully recover anticipated geotechnical and integrity
            costs associated with that pipeline, and extend customer
            arrangements and the useful life of the asset.

Gas Services:

        --  Site construction on both the Saturn and Resthaven facilities
            is underway with anticipated in-service dates of fourth quarter
            2013 and first quarter 2014, respectively. Once complete, the
            facilities will add an additional 330 MMcf/d of enhanced
            liquids extraction capability;
        --  A long-term arrangement was completed for the remaining 50
            MMcf/d of spare capacity at Saturn, bringing the total
            contracted capacity to 100 percent;
        --  The 50 MMcf/d Musreau shallow cut expansion is being
            commissioned with start-up expected in August 2012.

Midstream:

        --  A joint venture agreement was entered into with a third party
            to develop a new full-service terminal (50 percent interest net
            to Pembina) at Judy Creek to serve the production expansion in
            the Beaverhill Lake and Swan Hills formations with an
            anticipated in-service date of the first quarter of 2013;
        --  Development of seven fee-for-service cavern storage facilities
            continued at Pembina's Redwater site, the first of which is
            expected to come into service in the fourth quarter of 2012;
        --  An expansion to the Redwater fractionator by approximately
            8,000 bpd was progressed, which is expected to be in-service in
            the fourth quarter of 2012;
        --  Preliminary engineering work for a new 70,000 bpd C2+
            fractionator at Pembina's Redwater facility was advanced and
            the Company is currently soliciting customer support for the
            project;
        --  An agreement with a third party producer was signed to tie in
            its production of up to 60 MMcf/d to the Younger plant by the
            first quarter of 2013.

“This was a very productive quarter for Pembina; we made significant
progress to bring our two teams together following our acquisition of
Provident while maintaining steady performance across our operations,”
said Bob Michaleski, Pembina’s Chief Executive Officer. “As well, we
listed our shares on the New York Stock Exchange and have made
substantial strides to integrate our newly acquired operations with
those in our existing businesses. Pembina will continue to focus on
integration-related activities and enhancing the value from the newly
acquired assets, including growing the ‘fee-for-service’ component
across our businesses. While we did have to deal with a lower propane
price environment, we’re confident that the depth and breadth of
service we are now able to offer to our customers is a key
differentiator that positions Pembina for significant growth in the
years to come.”

Hedging Information

Pembina has posted updated hedging information on its website, www.pembina.com, under “Investor Centre – Hedging”.

Conference Call & Webcast

Pembina will host a conference call Friday, August 10, at 9:00 a.m. MT
(11:00 a.m. ET) to discuss details related to the second quarter of
2012. 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=489792&s=1&k=8609836C574E1C73A84090F0CE92BB87 in your web browser.

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 August 9, 2012 and is
supplementary to, and should be read in conjunction with, Pembina’s
condensed consolidated unaudited interim financial statements for the
period ended June 30, 2012 (“Interim Financial Statements”) as well as
Pembina’s consolidated audited annual financial statements and MD&A for
the year ended December 31, 2011 (the “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 Canadian Generally Accepted Accounting Principles
(“GAAP”). For more information about the measures which are not defined
by GAAP, see “Non-GAAP Measures.”

Acquisition of Provident Energy Ltd. (“Provident”)

On April 2, 2012, Pembina completed its acquisition of Provident by way
of a plan of arrangement pursuant to Section 193 of the Business
Corporations Act (Alberta) (the “Arrangement”). Provident shareholders
received 0.425 of a Pembina share for each Provident share held. In
addition, Pembina has 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
(“Series E Debentures”) (TSX Trading Symbol: PPL.DB.E), and the 5.75
percent convertible unsecured subordinated debentures of Provident
maturing December 31, 2018 (“Series F Debentures”) (TSX Trading Symbol:
PPL.DB.F). On closing of the Arrangement, Pembina listed its common
shares, including those issued under the Arrangement, on the NYSE under
the symbol “PBA”. Pursuant to the Arrangement, Provident amalgamated
with a wholly-owned subsidiary of Pembina and was continued under the
name “Pembina NGL Corporation”.

The consolidated financial statements contained in this MD&A and the
Interim Financial Statements include Pembina’s post-Arrangement results
from April 2, 2012. As such, the amounts disclosed herein for the three
and six month periods ending June 30, 2012 reflect results of the
post-Arrangement Pembina from April 2, 2012 together with results of
legacy Pembina alone, excluding Provident, from January 1 through April
1, 2012. The comparative figures reflect solely the 2011 results of
legacy Pembina. The results of the business acquired through the
Arrangement are reported as part of the Company’s Midstream business.
For further information with respect to the Arrangement, please refer
to Note 3 to the Interim Financial Statements.

About Pembina

Calgary-based Pembina Pipeline Corporation is a leading transportation
and midstream service provider with nearly 60 years serving North
America’s energy industry. Pembina owns and operates: pipelines that
transport conventional crude oil and natural gas liquids produced in
western Canada; oil sands and heavy oil 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 span across its operations. Pembina’s
integrated assets and commercial operations enable it to offer services
needed by the energy sector along each step of 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 through operational
excellence: 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 common shares. To achieve this, Pembina’s strategy is to:

        --  Generate value by providing customers with safe,
            cost-effective, reliable services.
        --  Diversify Pembina's asset base to enhance profitability. A
            diverse portfolio provides Pembina with the ability to respond
            to market conditions, reduce risk and increase opportunities to
            leverage existing businesses. A priority is placed on
            developing businesses that support Pembina's core competency -
            operating crude oil and NGL transportation systems, and gas
            gathering, processing and fractionation infrastructure - which
            allow for expansion, vertical integration and accretive growth.
        --  Implement growth projects and conduct existing operations in a
            safe and environmentally responsible manner. Growth is expected
            to occur through expansion of existing businesses, additional
            acquisitions and the development of new services. Pembina's
            investment criteria include pursuing projects or assets that
            are expected to generate increased cash flow per share and
            capture long-life, economic hydrocarbon reserves.
        --  Maintain a strong balance sheet through the application of
            prudent financial management to all business decisions.

Pembina is structured in 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

    kbbls    thousands of              AESO               Alberta Electric
             barrels                                      Systems Operator

    mmbbls   millions of               BC                 British Columbia
             barrels

    bpd      barrels per day           DRIP               Premium
                                                          Dividend(TM)
                                                          and Dividend
                                                             Reinvestment
                                                          Plan

    mbpd     thousands of              Frac               Fractionation
             barrels per day

    boe      barrels of oil            IFRS               International
             equivalent                                   Financial
                                                          Reporting
                                                          Standards

    boe/d    barrels of oil            NGL                Natural gas
             equivalent per                               liquids
             day

    mboe     thousands of              NYMEX              New York
             barrels of oil                               Mercantile
             equivalent                                   Exchange

    mboe/d   thousands of              NYSE               New York Stock
             barrels of oil                               Exchange
             equivalent per
             day

    MMcf     millions of cubic         TET                indicates product
             feet                                         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)

    MMcf/d   millions of cubic         TSX                Toronto Stock
             feet per day                                 Exchange

    bcf/d    billions of cubic         U.S.               United States
             feet per day

    MW/h     megawatts per             USD                United States
             hour                                         dollars

    GJ       gigajoule                 WCSB               Western Canadian
                                                          Sedimentary Basin

    km       kilometre                 WTI                West Texas
                                                          Intermediate
                                                          (crude oil
                                                           benchmark price)

Financial & Operating Overview
(unaudited)


                                  3 Months Ended           6 Months Ended
                                      June 30                  June 30

    ($ millions, except
    where noted)                 2012        2011          2012        2011

    Average throughput -
    conventional (mbpd)         433.9       411.4         450.4       400.9

    Contracted capacity -
    oil sands (mbpd)            870.0       775.0         870.0       775.0

    Average processing
    volume - gas services
    (mboe/dnet to
    Pembina)
    (1)                          47.5        40.9          45.8        40.1

    Total NGL sales
    volume (mbpd)                90.4                   90.4(3)            

    Revenue                     870.9       512.4       1,346.4       907.3

    Operations                   67.7        37.6         116.1        82.4

    Cost of goods sold,
    including product
    purchases                   641.9       364.3         941.0       618.5

    Realized gain (loss)
    on commodity-related
    derivative financial
    instruments                (12.4)       (0.2)        (12.7)         1.2

    Operating margin(2)         148.9       110.3         276.6       207.6

    Depreciation and
    amortization included
    in operations                52.5        15.8          74.2        30.6

    Unrealized gain on
    commodity-related
    derivative financial
    instruments                  64.8         3.3          61.3         3.6

    Gross profit                161.2        97.8         263.7       180.6

    Deduct/(add)                                                           

      General and
      administrative
      expenses                   25.8        12.8          43.3        27.4

      Acquisition-related
      and other expenses
      (income)                    0.5       (0.6)          22.7       (0.6)

      Net finance costs          26.7        25.0          46.3        39.3

      Share of loss
      (profit) of
      investments in
      equity accounted
      investee,
         net of tax               0.6       (2.6)           0.4       (4.8)

      Income tax expense         27.2        15.2          38.0        28.8

    Earnings for the
    period                       80.4        48.0         113.0        90.5

    Earnings per share -
    basic and diluted
    (dollars)                    0.28        0.29          0.50        0.54

    Adjusted earnings(2)         37.4        65.4         102.7       118.1

    Adjusted earnings per
    share(2)                     0.13        0.39          0.45        0.71

    Adjusted EBITDA(2)          125.9       103.3         237.3       190.5

    Cash flow from
    operating activities         24.1        49.5          89.4       124.0

    Cash flow from
    operating activities
    per share                    0.08        0.30          0.39        0.74

    Adjusted cash flow
    from operating
    activities(2)                89.5        81.8         188.3       157.8

    Adjusted cash flow
    from operating
    activities per share
    (2)                          0.31        0.49          0.83        0.94

    Dividends declared          116.2        65.3         181.9       130.4

    Dividends per common
    share (dollars)              0.41        0.39          0.80        0.78

    Capital expenditures        136.6        78.2         186.3       301.5

    Total enterprise
    value ($ billions)(2)         9.9         5.8           9.9         5.8

    Total assets ($
    billions)                     8.1         3.1           8.1         3.1

    (1)  Gas Services processing volumes converted to mboe/d from MMcf/d at
         a 6:1 ratio.

    (2)  Refer to "Non-GAAP Measures."

    (3)  Represents per day volumes since the closing of the Arrangement.

Revenue, net of cost of goods sold, increased approximately 55 percent
during the second quarter of 2012 to $229.0 million compared to $148.1
million in the second quarter of 2011. Year-to-date revenue, net of
cost of goods sold, in 2012 was $405.4 million, up 40 percent from the
same period last year. 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 Arrangement, which are reported in the
Company’s Midstream business, as well as continued strong performance
in each of Pembina’s businesses.

Operating expenses were $67.7 million during the second quarter of 2012
compared to $37.6 million in the second quarter of 2011. Operating
expenses for the six months ended June 30, 2012 were $116.1 million
compared to $82.4 million in the same period in 2011. The increase in
operating expenses for the second quarter and first half of 2012 was
primarily due to added costs associated with the growth in Pembina’s
asset base since the Arrangement and higher variable costs in each of
the Company’s businesses due to increased volumes.

Operating margin was $148.9 million during the second quarter, up 35
percent from the same period last year (operating margin is a Non-GAAP
measure; see “Non-GAAP Measures”). For the six months ended June 30,
2012 operating margin was $276.6 million compared to $207.6 million for
the same period of 2011. These increases were primarily due to higher
revenue, as discussed above.

Realized and unrealized gains (losses) on commodity-related derivative
financial instruments are the result of Pembina’s market risk
management program and are primarily related to outstanding positions
acquired on the closing of the Arrangement (see “Market Risk Management
Program” and Note 13 to the Interim Financial Statements). The
unrealized gains on commodity-related derivative financial instruments
of $64.8 million and $61.3 million recognized in the three and six
months ended June 30, 2012, respectively, reflect the reduction in the
future NGL price indices between April 2, 2012 and June 30, 2012 (see
“Business Environment”).

Depreciation and amortization (operational) increased to $52.5 million
during the second quarter of 2012 compared to $15.8 million during the
same period in 2011. For the six months ended June 30, 2012,
depreciation and amortization (operational) increased to $74.2 million,
up from $30.6 million for the same period last year. Both the quarterly
and year-to-date increases reflect depreciation on new capital
additions including the assets acquired through the Arrangement.

The increases in revenue and operating margin combined with an
unrealized gain on commodity-related derivative financial instruments
contributed to gross profit of $161.2 million during the second quarter
and $263.7 million during the first six months of 2012 compared to
$97.8 million and $180.6 million during the comparative periods of the
prior year.

General and administrative expenses (“G&A”) of $25.8 million were
incurred during the second quarter of 2012 compared to $12.8 million
during the second quarter of 2011. G&A for the first half of 2012 was
$43.3 million compared to $27.4 million for the same period of 2011.
The increase in G&A for the three and six month periods in 2012
compared to the prior year is mainly due the addition of employees who
joined Pembina through the Arrangement, an increase in salaries and
benefits for existing and new employees, and increased rent for new and
expanded office space. Every $1 change in share price is expected to
change Pembina’s annual share-based incentive expense by $0.7 million.

Pembina generated adjusted EBITDA of $125.9 million during the second
quarter of 2012 compared to $103.3 million during the second quarter of
2011 (adjusted EBITDA is a Non-GAAP measure; see “Non-GAAP Measures”).
Adjusted EBITDA for the six month period ended June 30, 2012 was $237.3
million compared to $190.5 million for the same period in 2011. The
increase in quarterly and year-to-date 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 in Pembina’s
operations since completion of the Arrangement.

The Company’s earnings were $80.4 million ($0.28 per share) during the
second quarter of 2012 compared to $48.0 million ($0.29 per share)
during the second quarter of 2011. Earnings were $113.0 million ($0.50
per share) during the first half of 2012 compared to $90.5 million
($0.54 per share) during the same period of the prior year. Earnings
for the three and six month periods ended June 30, 2012 increased as a
result of the acquisition of Provident and unrealized gains on
commodity-related derivative financial instruments. Earnings per share
decreased primarily due to the 116.5 million shares issued as a result
of the Arrangement.

Adjusted earnings were $37.4 million ($0.13 per share) during the second
quarter and $102.7 million ($0.45 per share) for the first half of
2012, down from $65.4 million ($0.39 per share) and $118.1 million
($0.71 per share) for the comparative periods of 2011 (adjusted
earnings is a Non-GAAP measure; see “Non-GAAP Measures”). The quarterly
and year-to-date decrease is primarily due to increased depreciation
and amortization (operational) and higher finance costs, which were
partially offset by an increase in operating margin.

Cash flow from operating activities was $24.1 million ($0.08 per share)
during the second quarter of 2012 compared to $49.5 million ($0.30 per
share) during the second quarter of 2011. For the six months ended June
30, 2012, cash flow from operating activities was $89.4 million ($0.39
per share) compared to $124.0 million ($0.74 per share) during the same
period last year. The decrease in cash flow from operating activities
during the 2012 periods is primarily due to acquisition-related
expenses, higher interest expenses and an increase in working capital
reflecting a seasonal inventory build.

Adjusted cash flow from operating activities was $89.5 million ($0.31
per share) during the second quarter of 2012 compared to $81.8 million
($0.49 share) during the second 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 $188.3
million ($0.83 per share) during the first half of 2012 compared to
$157.8 million ($0.94 share) during the same period of last year.
Adjusted cash flow from operating activities per share decreased
primarily due to the 116.5 million shares issued as a result of the
Arrangement.

Operating Results
(unaudited)


                                        3 Months Ended                           6 Months Ended
                                            June 30                                  June 30

                            2012                    2011                  2012                2011

                       Net                 Net                       Net                 Net
                   Revenue Operating   Revenue       Operating   Revenue Operating   Revenue Operating
    ($ millions)       (1) Margin(2)       (1)       Margin(2)       (1) Margin(2)       (1) Margin(2)

    Conventional
    Pipelines         78.4      47.5      72.4            50.1     160.6     101.9     141.7      94.1

    Oil Sands &
    Heavy Oil         39.4      27.8      27.7            20.0      82.5      57.9      58.2      39.3

    Gas Services      22.2      15.0      18.6            13.4      41.3      28.1      33.6      23.7

    Midstream         89.0      58.0      29.3            26.8  121.0(3)   87.4(3)      55.3      50.5

    Corporate                    0.6                                           1.3                    

    Total            229.0     148.9     148.0           110.3     405.4     276.6     288.8     207.6

    (1)  Midstream revenue is net of $648.8 million in cost of goods sold
         for the quarter ended June 30, 2012 (quarter ended June 30, 2011:
         $364.4 million) and $947.9 million in cost of goods sold for six
         months ended June 30, 2012 (six months ended June 30, 2011: $618.5
         million).

    (2)  Refer to "Non-GAAP Measures."

    (3)   Includes results from operations generated by the acquired assets
         from Provident since closing of the Arrangement.

Conventional Pipelines


                                              3 Months Ended 6 Months Ended
                                                 June 30        June 30

    ($ millions, except where noted)           2012     2011  2012     2011

    Average throughput (mbpd)                 433.9    411.4 450.4    400.9

    Revenue                                    78.4     72.4 160.6    141.7

    Operations                                 29.9     22.2  57.5     49.0

    Realized gain (loss) on commodity-related
    derivative financial instruments          (1.0)    (0.1) (1.2)      1.4

    Operating margin(1)                        47.5     50.1 101.9     94.1

    Depreciation and amortization included in
    operations                                 12.2     10.4  24.1     20.1

    Unrealized gain (loss) on
    commodity-related derivative financial
    instruments                                 0.2      0.1 (2.8)      4.7

    Gross profit                               35.5     39.8  75.0     78.7

    Capital expenditures                       55.6     10.1  64.5     26.8

((1) )Refer to “Non-GAAP Measures.”

Business Overview

Pembina’s Conventional Pipelines business is comprised of 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 endeavors to maintain and/or improve
operating margin by capturing incremental volumes, expanding its
pipeline systems, managing revenue and adopting strong discipline
relative to operating expenses.

Operational Performance: Throughput

During the second quarter of 2012, Conventional Pipelines’ throughput
averaged 433.9 mbpd, consisting of an average of 332.5 mbpd of crude
oil and condensate and 101.4 mbpd of NGL. This is approximately five
percent higher than the same period of 2011 when average throughput was
411.4 mbpd, with the increase being primarily due to continued
production growth from regional resource play development in the
Cardium (oil), Deep Basin Cretaceous (NGL), Montney (oil/NGL) and
Beaverhill Lake (oil) formations. Pipeline receipts during the second
quarter of 2012 increased on several of Conventional Pipelines’ systems
including the Peace, Swan Hills and Northern systems. However, NGL
volumes were impacted during the second quarter due to a turnaround at
a third party delivery facility as well as several extended third party
gas plant maintenance outages that were scheduled to coincide with the
previously mentioned delivery point outage. The producer growth in
production discussed above also contributed to a 12 percent increase in
throughput for the first six months of 2012 compared to the same period
of the prior year.

Financial Performance

During the second quarter of 2012, Conventional Pipelines generated
revenue of $78.4 million, up eight percent from the same quarter of
2011. This is due to higher volumes generated by newly connected
facilities on Pembina’s larger pipeline systems. For the first six
months of 2012, revenue was $160.6 million compared to $141.7 million
for the same period in 2011.

During the second quarter, operating expenses were higher at $29.9
million compared to $22.2 million in the second quarter of 2011.
Similarly, operating expenses for the six months ended June 30, 2012
increased to $57.5 million from $49.0 million during the same period of
2011. These quarterly and year-to-date increases resulted primarily
from increased variable and power costs associated with higher volumes
and new assets that are now in-service, as well as increased spending
related to pipeline integrity and geotechnical work.

Operating margin for the second quarter of 2012 was $47.5 million
compared to $50.1 million during the same period of 2011. This decrease
was primarily due to increased operating expenses which were partially
offset by higher revenue, as discussed above. On a year-to-date basis,
operating margin increased to $101.9 million from $94.1 million for the
first six months of 2011.

Depreciation and amortization included in operations increased to $12.2
million during the second quarter of 2012 from $10.4 million during the
second quarter of 2011, reflecting capital additions in this business.
Depreciation and amortization included in operations for the six months
ended June 30, 2012 was $24.1 million, up from $20.1 million in the
first half of 2011.

For the three and six months ended June 30, 2012, gross profit was $35.5
million and $75.0 million, respectively, compared to $39.8 million and
$78.7 million for the same periods of the prior year. These decreases
are due to higher revenues being offset by increased operating expenses
and depreciation and amortization included in operations during the
2012 periods for the reasons discussed above.

Capital expenditures for the second quarter of 2012 totaled $55.6
million compared to $10.1 million during the second quarter of 2011 and
capital expenditures for the first half of 2012 were $64.5 million
compared to $26.8 for the same period of 2011. The majority of this
spending relates to the expansion of certain pipeline assets as
described below.

New Developments: Conventional Pipelines

Liquids-Rich Natural Gas: Expansion of Peace and Northern NGL Pipelines

Pembina is progressing plans to expand the NGL throughput capacity on
its Peace and Northern pipelines (together the “Northern NGL System”)
by 52 mbpd (the “NGL Expansion”) to accommodate increased customer
demand following strong drilling results and increased field liquids
extraction by area producers.

As of August, Pembina has reached long-term commercial agreements with
its customers to underpin the $100 million NGL Expansion. Assuming
regulatory approvals are obtained in a timely manner, Pembina expects
to bring 17 mbpd of the NGL Expansion into service by the end of 2012
and the remaining 35 mbpd by the end of 2013.

During the second quarter of 2012, Pembina received regulatory approval
for and began construction on two of the three pump stations as part of
the first phase of the NGL Expansion.

Pembina’s Northern NGL System is strategically located across
liquids-rich natural gas production areas in the WCSB and serves
producers in the Deep Basin, Montney, Cardium and emerging Duvernay
Shale plays. Currently, the Northern NGL System’s capacity is 115 mbpd.
As at the beginning of August, average daily throughput on the Northern
NGL System was approximately 100 mbpd. Once complete, the proposed NGL
Expansion will increase capacity on the Northern NGL System by 45
percent to 167 mbpd.

Drayton Valley Area

In the area of the Cardium formation of west central Alberta, Pembina
continues to actively work with producers on numerous connection and
expansion opportunities.

Pembina completed the refurbishment of its Calmar booster station in
May, 2012, adding 50 mbpd of capacity on the Drayton Valley mainline
and bringing the total capacity of the system to approximately 190
mbpd.

Supporting Gas Services’ Saturn and Resthaven Projects

Pembina’s Conventional Pipelines business is working closely with its
Gas Services business to construct the pipeline components of the
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. During the second quarter of 2012, Pembina continued
its consultation activities related to the right-of-way and pipeline
routing for both of these projects with First Nations, community
stakeholders and the appropriate regulators, and has continued to order
long-lead equipment for the pipeline and pump stations.

Western System

Subsequent to the quarter end, the British Columbia Utilities Commission
approved an application on Pembina’s Western System, which will allow
Pembina to fully recover anticipated geotechnical and integrity costs
associated with that pipeline, and extend customer arrangements and the
useful life of the asset.

Oil Sands & Heavy Oil


                                        3 Months Ended       6 Months Ended
                                           June 30              June 30

    ($ millions, except where
    noted)                         2012           2011  2012           2011

    Capacity under contract
    (mbpd)                        870.0          775.0 870.0          775.0

    Revenue                        39.4           27.7  82.5           58.2

    Operations                     11.6            7.7  24.6           18.9

    Operating margin(1)            27.8           20.0  57.9           39.3

    Depreciation and amortization
    included in operations          4.9            2.1   9.8            4.0

    Gross profit                   22.9           17.9  48.1           35.3

    Capital expenditures                          30.1   6.0          129.9

((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 product
to oil sands producers operating southeast of Fort McMurray, Alberta.
The Oil Sands & Heavy Oil business operates approximately 1,650 km of
pipeline and accounts for about one-third of the total take-away
capacity from the Athabasca oil sands region. These assets operate
under long-term, extendible contracts that provide for the flow-through
of operating expenses to customers. As a result, operating margin from
this business is primarily related to invested capital and is not
sensitive to fluctuations in operating expenses or actual throughput.

Financial Performance

The Oil Sands & Heavy Oil business realized revenue of $39.4 million in
the second quarter of 2012 compared to $27.7 million in the second
quarter of 2011. This 42 percent increase is primarily due to
contributions from the Nipisi and Mitsue pipelines, which commenced
operations in the third quarter of 2011. For the same reason,
year-to-date revenue in 2012 was $82.5 million compared to $58.2
million for the same period in 2011.

Operating expenses in Pembina’s Oil Sands & Heavy Oil business were
$11.6 million during the second quarter of 2012 compared to $7.7
million during the second quarter of 2011. For the first six months of
2012, operating expenses were $24.6 million compared to $18.9 million
for the same period in 2011. These increases primarily reflect the
additional operating expenses related to the Nipisi and Mitsue
pipelines.

For the three and six months ended June 30, 2012, operating margin was
$27.8 million and $57.9 million, higher than the operating margin of
$20.0 million and $39.3 million, respectively, during the same periods
in 2011, primarily due to the same factors that contributed to the
increase in revenue, as discussed above.

Depreciation and amortization included in operations for the second
quarter of 2012 totaled $4.9 million compared to $2.1 million during
the same period of the prior year. For the first half of 2012,
depreciation and amortization included in operations was $9.8 million
compared to $4.0 million in the first half of 2011. These increases
primarily reflect the additional depreciation and amortization included
in operations related to the Nipisi and Mitsue pipelines.

For the three and six months ended June 30, 2012, gross profit was $22.9
million and $48.1 million, higher than gross profit of $17.9 million
and $35.3 million, respectively, during the same periods in 2011,
primarily due to higher operating margin as discussed above.

For the six months ended June 30, 2012, capital expenditures within the
Oil Sands & Heavy Oil business totaled $6.0 million compared to $129.9
million during the same period in 2011. The majority of Pembina’s 2011
investment in this business related to completing the Nipisi and Mitsue
pipeline projects.

Segmented Operating Margin

Syncrude Pipeline

The Syncrude Pipeline has a capacity of 389 mbpd and is fully contracted
to the owners of Syncrude Canada Ltd. under an extendible agreement
that expires in 2035. Operating margin generated by the Syncrude
Pipeline during the second quarter and first half of 2012 was $6.4
million and $13.1 million, respectively, virtually unchanged from $6.3
million and $12.8 million during the same period in 2011.

Cheecham Lateral

Pembina’s Cheecham Lateral has a capacity of 136 mbpd and is fully
contracted to shippers under an extendible agreement that expires in
2032. Operating margin generated by the Cheecham Lateral during the
second quarter and first half of 2012 was $1.1 million and $2.2
million, respectively, compared to $1.2 million and $2.3 million during
the same periods in 2011.

Horizon Pipeline

The Horizon Pipeline has an ultimate capacity of 250 mbpd (with the
addition of pump stations) and is fully contracted to Canadian Natural
Resources Ltd. under an extendible agreement that expires in 2033.
Operating margin generated by the Horizon Pipeline during the second
quarter and first half of 2012 was $11.6 million and $22.8 million,
respectively, compared to $12.1 million and $23.5 million during the
same period in 2011.

Nipisi & Mitsue Pipelines

In June and July of 2011, Pembina completed construction of its Nipisi
and Mitsue pipelines. Pembina is in the process of installing two
remaining pump stations and expects it will bring the combined capacity
of the pipelines to approximately 122 mbpd in the second quarter of
2013. Operating margin generated by these assets in the second quarter
of 2012 was $8.0 million and $18.5 million for the first half of the
year.

New Developments: Oil Sands & Heavy Oil

Pembina continues to actively explore other oil sands and heavy oil
pipeline opportunities and believes the Company’s strong foothold and
recent construction and community relations experience in the oil sands
region position it well to attract new business.

Gas Services


                                            3 Months Ended   6 Months Ended
                                               June 30         June 30

    ($ millions, except where noted)       2012       2011  2012       2011

    Average processing volume (MMcf/d)    285.0      245.5 275.0      240.8

    Average processing volume (mboe/d)(1)  47.5       40.9  45.8       40.1

    Revenue                                22.2       18.6  41.3       33.6

    Operations                              7.2        5.2  13.2        9.9

    Operating margin(2)                    15.0       13.4  28.1       23.7

    Depreciation and amortization
    included in operations                  4.3        2.5   7.5        4.8

    Gross profit                           10.7       10.9  20.6       18.9

    Capital expenditures                   23.5       25.5  55.8       41.1

    (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 360 MMcf/d of processing capacity (305 MMcf/d net to
Pembina), a new 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 plans to expand
its Gas Services business by constructing 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 approximately 19 percent
during the second quarter of 2012, contributing $22.2 million compared
to $18.6 million in the second quarter of 2011. In the first half of
the year, revenue was $41.3 million compared to $33.6 million in the
same period of 2011. These increases primarily reflect higher
processing volumes at Pembina’s Cutbank Complex. Average processing
volume, net to Pembina, was 285.0 MMcf/d during the second quarter of
2012, 16 percent higher than the 245.5 MMcf/d processed during the
second quarter of 2011.

During the second quarter of 2012, operating expenses were $7.2 million,
an increase from the $5.2 million incurred in the second quarter of
2011. Year-to-date operating expenses totaled $13.2 million, up from
$9.9 million during the same period of the prior year. The quarterly
and year-to-date increases were mainly due to variable costs incurred
to process higher volumes at the Cutbank Complex.

As a result of processing higher volumes at the Cutbank Complex, Gas
Services realized operating margin of $15.0 million in the second
quarter and $28.1 million in the first half of 2012 compared to $13.4
million and $23.7 million during the same periods of the prior year.

Depreciation and amortization included in operations during the second
quarter of 2012 totaled $4.3 million, up from $2.5 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 Deep Cut Facility). For the same reason, year-to-date
depreciation and amortization included in operations totaled $7.5
million, up from $4.8 million during the first half of 2011.

For the three months ended June 30, 2012, gross profit was $10.7
million, consistent with the same period of 2011. On a year-to-date
basis, gross profit was $20.6 million compared to $18.9 million during
the first half of 2011.

For the six months ended June 30, 2012, capital expenditures within Gas
Services totaled $55.8 million compared to $41.1 million during the
same period of 2011. This increase was due to 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 gas drilling and the extraction of
valuable NGL from gas in the WCSB. Pembina expects the three expansions
detailed below to bring the Company’s gas processing capacity to 890
MMcf/d (net), including enhanced NGL extraction capacity of
approximately 535 MMcf/d (net) which would be processed largely on a
contracted, fee-for-service basis and result in approximately 45 mbpd
of incremental NGL to be transported for additional toll revenue on
Pembina’s conventional pipelines by early 2014.

Musreau Deep Cut Facility

Pembina completed construction and began operations at its Musreau Deep
Cut Facility, a 205 MMcf/d ethane extraction facility, mid-February
2012. The Musreau Deep Cut Facility experienced an unplanned outage in
March of 2012 and repairs are ongoing.

Expansion at the Cutbank Complex: Musreau Shallow Cut Expansion

Pembina is expanding Musreau’s shallow cut gas processing capability by
50 MMcf/d at an estimated cost of $17 million. With commissioning
activities near completion, Pembina expects the expansion to be
in-service in August 2012. Once in-service, the Cutbank Complex will
have an aggregate raw shallow gas processing capacity of 410 MMcf/d
(355 MMcf/d net to Pembina), an increase of 16 percent net to Pembina.
Related to this expansion, Pembina has entered into contracts with a
minimum term of five years with area producers for the entire capacity
of the expansion on a fee-for-service basis.

Saturn Facility

Pembina is developing a $200 million 200 MMcf/d enhanced NGL extraction
facility (the “Saturn Facility”) and associated NGL and gas gathering
pipelines in the Berland area of west central Alberta. Once
operational, Pembina expects the Saturn Facility will have the capacity
to extract up to 13.5 mbpd of NGL. Subject to regulatory and
environmental approval, Pembina expects the Saturn Facility and
associated pipelines to be in-service in the fourth quarter of 2013. In
June, Pembina executed a long-term arrangement for the remaining 50
MMcf/d of capacity at Saturn, bringing the total contracted capacity to
100 percent.

As of the beginning of August 2012, Pembina has ordered 90 percent of
the major long-lead equipment for the project and is progressing plant
site construction. Pipeline environmental field assessments have been
completed and stakeholder consultation is ongoing.

Resthaven Facility

Pembina is developing a combined shallow cut and deep cut NGL extraction
facility (the “Resthaven Facility”) by modifying and expanding an
existing gas plant, and is constructing a pipeline to transport the
extracted NGL from the Resthaven Facility to Pembina’s Peace Pipeline
system for a total estimated cost of $230 million. Once complete,
Pembina will own approximately 65 percent of the Resthaven Facility and
100 percent of the NGL pipeline. Pembina expects the initial phase of
the Resthaven Facility will have a gross capacity of 200 MMcf/d (130
MMcf/d net) and 13 mbpd of liquids extraction capability, with ultimate
processing capacity of 300 MMcf/d (195 MMcf/d net) and 18 mbpd of
liquids extraction capability. Subject to regulatory and environmental
approvals, Pembina expects these new assets to be in-service in the
first quarter of 2014.

As of the beginning of August 2012, Pembina has ordered 65 percent of
the major long-lead equipment for the project and is progressing plant
site construction. Other activities related to the project include
pipeline stakeholder consultation, environmental planning, route
selection, engineering, and right-of-way surveying.

Midstream((1))


                                           3 Months Ended   6 Months Ended
                                              June 30          June 30

    ($ millions, except where noted)            2012  2011       2012  2011

    Total NGL sales volume (mbpd)               90.4          90.4(3)      

    Revenue                                    737.8 393.7    1,068.9 673.8

    Operations                                  19.6   2.5       22.1   4.6

    Cost of goods sold, including product
    purchases                                  648.8 364.4      947.9 618.5

    Realized loss on commodity-related
    derivative financial instruments          (11.4)           (11.5) (0.2)

    Operating margin(2)                         58.0  26.8       87.4  50.5

    Depreciation and amortization
    included in operations                      31.1   0.9       32.7   1.8

    Unrealized gains (losses) on
    commodity-related derivative
    financial  instruments                      64.6   3.2       64.0 (1.0)

    Gross profit                                91.5  29.1      118.7  47.7

    Capital expenditures                        55.2  11.6       55.9 101.9

    (1)  Share of profit from equity accounted investees not included in
         results above.

    (2)  Refer to "Non-GAAP Measures."

    (3)  Represents per day volumes since the closing of the Arrangement.

Business Overview

Pembina’s Midstream business is organized into two components:

        --  a crude oil midstream business, which represents the Company's
            legacy midstream operations is situated at key sites across
            Pembina's operations and comprises a network of liquids truck
            terminals, terminalling at downstream hub locations, including
            storage and pipeline connectivity; and
        --  an NGL midstream business, which Pembina acquired through the
            Arrangement, which includes two operating systems: Redwater
            West and Empress East.
      o The Redwater West NGL system includes the Younger extraction and
        fractionation facility in B.C.; a 65,000 bpd fractionator, 6.3
        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 plant at Empress, Alberta, and 20,000 bpd of fractionation
        capacity as well as 6.4 mmbbls of cavern storage in Sarnia,
        Ontario.

By providing integrated services along the crude oil and NGL value
chains, this business has increased the range of services Pembina is
able to provide its customers. This business also contributes
throughput to the Company’s Conventional Pipelines business, and
provides essential downstream services that support its Gas Services
business.

Financial Performance

In the Midstream business, revenue, net of cost of goods sold, grew by
204 percent to $89.0 million during the second quarter of 2012 from
$29.3 million during the second quarter of 2011. Year-to-date revenue,
net of cost of goods sold, was $121.0 million in 2012 compared to $55.3
million in 2011. These increases were primarily due to the addition of
the NGL midstream business acquired through the Arrangement and
increased activity on Pembina’s pipeline systems.

Operating expenses during the second quarter of 2012 were $19.6 million,
up from the $2.5 million in the second quarter of 2011. Operating
expenses for the first half of the year were $22.1 million in 2012 and
$4.6 million in 2011. Operating expenses for the quarter and
year-to-date were higher due to the increase in Midstream’s asset base
since the Arrangement.

Operating margin was $58.0 million during the second quarter of 2012
compared to $26.8 million during the second quarter of 2011. Operating
margin for the first six months of 2012 was $87.4 million compared to
$50.5 million in the same period of 2011. This increase was 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 second
quarter of 2012 totaled $31.1 million, up from $0.9 million during the
same period of the prior year. Year-to-date depreciation and
amortization included in operations totaled $32.7 million, up from $1.8
million during the first half of 2011. The quarterly and year-to-date
increases reflect the additional assets in Midstream since the closing
of the Arrangement.

For the three and six months ended June 30, 2012, gross profit in this
business increased to $91.5 million and $118.7 million from $29.1
million and $47.7 million during the same periods in 2011 as a result
of the addition of assets acquired through the Arrangement, higher
operating margin and unrealized gains on commodity-related derivative
financial instruments.

For the six months ended June 30, 2012, capital expenditures within the
Midstream business were primarily related to cavern development and
related infrastructure as well as the expansion at the Redwater
Facility by approximately 8,000 bpd and totaled $55.9 million compared
to $101.9 million during the same period of 2011. Capital spending in
the first half of 2011 had included the acquisition of a terminalling
and storage facility near Edmonton, Alberta and the acquisition of
linefill for the Peace Pipeline.

Operating Margin by Activity

Crude Oil Midstream

Pembina’s crude oil midstream activity consists of a network of
terminals, pipeline-connected storage and hub locations situated at key
sites across the Company’s conventional pipeline system. This includes
the development of the Pembina Nexus Terminal (“PNT”) as well as a 50
percent non-operated interest in both the Fort Saskatchewan Ethylene
Storage Facility and the LaGlace Full-Service Terminal.

Operating margin for this activity during the second quarter of 2012 was
$30.8 million compared to $26.8 million during the second quarter of
2011. Year-to-date operating margin was $60.2 million, up 19 percent
from $50.5 million in the same period last year. Strong second quarter
and year-to-date 2012 results were primarily due to higher volumes and
activity on Pembina’s pipeline systems and wider margins, as well as
opportunities associated with enhanced connectivity at PNT added in the
first quarter of 2012.

NGL Midstream

Operating margin for the NGL midstream business, which was acquired by
Pembina on April 2, 2012, was $27.2 million for the second quarter and
year-to-date, including an $11.2 million realized loss on
commodity-related derivative financial instruments (see “Market Risk
Management Program”). The second quarter of 2012 was a period of weak
demand for propane and lower NGL prices (see “Business Environment”)
which impacted operating margin for the period and resulted in an $8.4
million impairment of the inventory balance at June 30, 2012.

Redwater West

Redwater West purchases NGL mix from various natural gas and natural gas
liquids producers and fractionates it into finished products at the
Redwater fractionation facility near Fort Saskatchewan, Alberta.
Redwater West also includes NGL production from the Younger NGL
extraction and fractionation plant located at Taylor in northeastern
BC. The Younger plant supplies specification NGL to local BC markets as
well as NGL mix into the Fort Saskatchewan area for fractionation and
sale. Also located at the Redwater facility is Pembina’s
industry-leading rail-based condensate terminal, which serves the heavy
oil industry’s need for diluent. Pembina’s condensate terminal is the
largest of its size in western Canada.

Operating margin during the second quarter of 2012, excluding realized
losses from commodity-related derivative financial instruments, was
$36.2 million. Second quarter results were impacted by weak propane
prices and decreased gas throughput volumes at the Younger plant.
Propane margins were low in the second quarter of 2012 due to inventory
builds resulting from a significantly warmer 2011-12 winter.
Conversely, butane margins were high, primarily due to strong refinery
demand and increases in market prices in the second quarter of 2012.
Condensate sales also contributed to the Redwater West gross operating
margin in the second quarter of 2012 as increased market prices offset
slightly lower condensate sales volumes. Overall, Redwater West NGL
sales volumes averaged 51.9 mbpd.

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, consisting of
primarily propane and butane, is shipped on Pembina’s 50 percent owned
Kerrobert Pipeline to a third party pipeline for transport to Sarnia,
Ontario where it is then fractionated into specification products.
Specification propane and butanes are sold into central Canadian and
eastern U.S. markets. Demand for propane is seasonal and results in
inventory that generally builds over the second and third quarters of
the year and is sold in the fourth quarter and the first quarter of the
following year during the winter heating season.

Operating margin during the second quarter of 2012, excluding realized
losses from commodity-related derivative financial instruments, was
$2.2 million. Second quarter results were impacted by low sales volumes
associated with weak demand for propane but was offset by strong
refinery demand for butane. Weak demand and lower NGL sales prices were
partially offset by lower AECO natural gas prices. Overall, Empress
East NGL sales volumes averaged 38.5 mbpd.

The lower market frac spreads in the second quarter of 2012 (see
“Business Environment”) were further impacted at Empress by the
continued high cost of natural gas supply in the form of extraction
premiums, reflecting a higher long-term relative frac spread. Empress
extraction premiums were also higher as a result of decreased volumes
of natural gas flowing past the Empress straddle plants and thus
increased competition for NGL. Natural gas throughput directly impacts
production at the Empress facilities which, in turn, reduces the supply
of propane-plus available for sale in Sarnia and in surrounding eastern
markets.

Pembina has partially mitigated the impact of lower natural gas-based
NGL supply at Empress by purchasing NGL mix supply in western Canada.
The mix is then transported to the Sarnia market for fractionation and
sale. Pembina also purchases NGL mix supply from other Empress plant
owners and in the Edmonton market.

New Developments: Midstream

The capital being deployed in the Midstream business is primarily being
directed towards fee-for-service projects which will continue to
increase its stability and predictability. The Company continues to
develop the PNT, which connects key infrastructure in the Edmonton -
Fort Saskatchewan – Namao, Alberta area via pipelines to other Pembina
infrastructure as well as refineries and downstream terminals. PNT will
enable Pembina to create tailored products and services for customers
while facilitating growth opportunities for the Company’s other
businesses.

Pembina is also moving forward on its plans to expand the services
offered at a number of existing truck terminals and construct new
full-service terminals that focus on emulsion treating (separating oil
from impurities to meet shipping quality requirements), produced water
handling and water disposal. In addition to earning fees for these
services, Pembina’s truck terminals will secure volumes for its
pipeline systems to generate additional pipeline toll revenue.  The Company has entered into a joint venture agreement with a third
party to develop a new full-service terminal (50 percent interest net
to Pembina) at Judy Creek to serve the production expansion in the
Beaverhill Lake and Swan Hills formations with an anticipated
in-service date of the first quarter of 2013. Pembina continues to advance its other full-service terminal initiatives
and is presently involved with assessing disposal well candidates prior
to making binding commitments.

Pembina is continuing to develop seven fee-for-service storage caverns at its
Redwater site, the first of which is expected to come into service in
the fourth quarter of 2012. As well, the Company is progressing an
expansion to the Redwater fractionator by approximately 8,000 bpd,
which is expected to be in-service in the fourth quarter of 2012.

During the second quarter, Pembina also signed an agreement with a third
party producer to tie in its production of up to 60 MMcf/d to the
Younger plant by the first quarter of 2013.

Market Risk Management Program

Pembina is exposed to frac spread risk which is the difference between
the selling prices for propane-plus 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. Pembina has entered into derivative financial swap
contracts through March 2013 to protect the frac spread 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
(“ISDA”) 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
mitigage its impact through financial risk management activities.
Subject to market conditions and at management’s discretion, Pembina
may hedge a portion of its natural gas and NGL volumes. A summary of
Pembina’s current financial derivative positions is available on
Pembina’s website at www.pembina.com.

In the second quarter of 2012, Pembina bought out the remaining portion
of Provident’s legacy participating crude oil hedges for $1.2 million
as Pembina believed these did not represent effective hedges for NGL
prices. As a result, the Company no longer has any propane or butane
hedges linked to crude oil prices.

A summary of Pembina’s risk management contracts executed during the
second quarter of 2012 is contained in the following table.

Activity in the second quarter


              Commodity                                     Effective
    Year                 Description      Volume (Buy)/Sell Period

              Crude Oil  U.S. $95.94 per                    July 1 -
                         bbl(2)(6)(7)            1,299 bpd  December 31

                         U.S. $1.226 per                    July 1 -
              Propane    gallon(3)(6)          (1,630) bpd  December 31

    2012                 U.S. $1.725 per                    July 1 -
              Condensate gallon(4)(7)            (565) bpd  December 31

                         Sell U.S.
                         $1,400,000 per
                         month at 0.994                     July 1 -
              F/X        (5)(9)                             December 31

              Crude Oil  U.S. $104.22
                         per bbl(2)(6)                      January 1 -
                         (7)                       750 bpd  April 30

                         U.S. $1.226 per                    January 1 -
    2013      Propane    gallon(3)(6)          (1,667) bpd  April 30

                         Sell U.S.
                         $1,400,000 per
                         month at 0.994                     January 1 -
              F/X        (5)(9)                             March 31

              Power                                         July 1 -
                         Cdn $65.86 per                     December 31,
                         MW/h(8)                  (15) MW/h 2013

                         Cdn $67.95 per                     January 1 -
                         MW/h(8)                            December 31,
                                                  (10) MW/h 2014
    Corporate
                         Cdn $67.95 per                     January 1 -
                         MW/h(8)                            December 31,
                                                  (10) MW/h 2015

                         Cdn $68.00 per                     January 1 -
                         MW/h(8)                            December 31,
                                                   (5) MW/h 2016

    (1) The above table represents a number of transactions entered into
        over the second quarter of 2012.

    (2) Crude oil contracts are settled against NYMEX WTI calendar average.

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

    (4) Condensate contracts are settled against Belvieu Non-TET natural
        gasoline.

    (5) Frac spread contracts.

    (6) Management of physical contract exposure - NGL product contracts.

    (7) Management of physical contract exposure - rail contracts.

    (8) Power contracts are settled against the hourly price of power as
        published by the AESO in $/MWh.

    (9) U.S. dollar forward contracts are settled against the Bank of
        Canada noon rate average. Selling notional U.S. dollars for
        Canadian dollar fixed exchange rate results in a fixed Canadian
        dollar price for the underlying commodity.

The following table summarizes the impact of commodity-related
derivative financial contracts settled during the first two quarters of
2012 and 2011 that were included in the realized (loss) gain on
commodity-related derivative financial instruments.


                                      3 Months Ended                          6 Months Ended
                                         June 30                                 June 30

    ($ thousands,
    except volumes)            2012               2011                 2012                2011

                               Volume                                                      Volume
                             $    (1)     $       Volume        $       Volume     $

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

    Frac spread
    related                                                                         

      Crude oil        (1,997)    0.1                     (1,997)          0.1                   

      Natural gas      (7,762)    4.6                     (7,762)          4.6                   

      Propane            1,727    0.2                       1,727          0.2                   

      Butane               769    0.3                         769          0.3                   

      Condensate           272    0.2                         272          0.2                   

      Sub-total frac
      spread related   (6,991)                            (6,991)                   

    Corporate                                                                                    

      Power            (1,608)        (159)               (1,764)              1,455             

    Management of
    exposure embedded
    in physical
    contracts and
    other              (3,870)    0.3                     (3,941)          0.5 (204)

    Realized (loss)
    gain on
    commodity-related
    derivative
    financial
    instruments       (12,469)        (159)              (12,696)              1,251

    (1) The above table represents aggregate net volumes that were
        bought/sold over the periods. Crude oil and NGL volumes are listed
        in millions of barrels and natural gas is listed in millions of
        gigajoules.

The realized loss on commodity-related derivative financial instruments
for the second quarter of 2012 was $12.5 million compared to $0.2
million in the comparable period in 2011. The majority of the realized
loss in the second quarter of 2012 was driven by natural gas purchase
derivative contracts settling at a contracted price higher than the
market natural gas prices during the settlement period, crude oil
derivative sales contracts settling at contracted crude oil prices
lower than the crude oil market prices during the settlement period,
and power purchase derivative contracts settling at a contracted price
higher than the market prices during the settlement period.

Business Environment


                                    3 Months ended                              6 Months ended
                                        June 30                                    June 30

                                                         %                                          %
                            2012               2011 Change              2012              2011 Change

    WTI crude
    oil (U.S.$
    per
    barrel)                93.49             102.56    (9)             98.21             98.33       

    Exchange
    rate (from
    U.S.$ to
    Cdn$)                   1.01               0.97      4              1.01              0.98      3

    WTI crude
    oil
    (expressed
    in Cdn$
    per
    barrel)                94.44              99.25    (5)             98.77             96.05      3

    AECO
    natural
    gas
    monthly
    index
    (Cdn$ per
    gj)                     1.74               3.54   (51)              2.06              3.56   (42)

    Frac
    Spread
    Ratio(1)               54.3x              28.0x     94             47.9x             27.0x     77

    Mont
    Belvieu
    Propane
    (U.S.$ per
    U.S.
    gallon)                 0.98               1.50   (35)              1.12              1.45   (23)

    Mont
    Belvieu
    Propane
    expressed
    as a
    percentage
    of WTI                   44%                61%   (28)               48%               62%   (23)

    Market
    Frac
    Spread in
    Cdn$ per
    barrel(2)              45.70              53.84   (15)             50.43             52.09    (3)

    (1) Frac spread ratio is the ratio of WTI expressed in Canadian dollars
        per barrel to the AECO monthly index (Cdn$ per gj).

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

The second quarter of 2012 saw a 6.4 percent decrease in the S&P TSX
Composite from the previous quarter, with the value of the Index being
down 11.5 percent since the same time a year ago. From early May
through to the end of the second quarter, the Canadian dollar weakened
against the U.S. dollar, due in part to a decline in commodity prices,
averaging $1.01 per U.S. dollar for the quarter from a value of $0.97 per U.S. dollar
over the same period in the previous year.

The benchmark WTI oil price also trended downward in May and June after
a period of stability in April, averaging U.S. $93 for the quarter and
exiting the quarter at U.S. $85. The Canadian light crude oil
benchmark, Edmonton Par, recovered from a higher-than-average price
differential to WTI in the second quarter of 2012 following
historically high differentials and volatility in the first quarter
which had been caused by increasing crude supply, refinery downtime and
export infrastructure constraints. The Canadian heavy crude oil
benchmark, Western Canadian Select, continued to trade at relatively
wide differentials to WTI throughout the second quarter due primarily
to downstream infrastructure constraints which resulted in a tight
supply-demand balance following the return to service of certain
Canadian heavy oil assets. The weakened crude oil price environment
coupled with increasing cost inflation in Alberta has caused some
smaller producers in the WCSB to reduce their budgets. However, oil
drilling in the WCSB remained robust in the second quarter of 2012
compared to longer-term historic levels, which has continued to benefit
Pembina’s oil gathering infrastructure. The opening and potential
construction, expansion and conversion of downstream infrastructure in
the U.S. Midwest and Gulf Coast is expected to provide narrower
differentials in the future as Canadian producers gain access to
premium markets with adequate transportation and refining capacity.

Despite historically high storage levels in both Canada and the U.S.,
natural gas prices recovered slightly through the second quarter
because of the larger-than-anticipated decline in Alberta production to
below multi-year averages. The closing first quarter AECO price was
$1.61 per GJ, which increased 32 percent during the second quarter to
exit at $2.13 per GJ with an average of $1.74 per GJ over the quarter.
While low natural gas prices are generally favourable for NGL
extraction and fractionation economics, a sustained low-priced gas
environment could impact the availability and overall cost of natural
gas and NGL mix supply in western Canada as natural gas producers may
elect to shut-in production or reduce drilling activities. While this
has occurred to some extent through the second quarter of 2012, many
producers have mitigated the low price environment through non-core
asset sales, partnerships and targeted development, all of which have
served Pembina in developing long-term opportunities.

The NGL pricing environment in the second quarter of 2012 was weakened
by a supply-demand imbalance in North America which was caused by
sustained exploitation of liquids-rich and associated gas in shale
plays in the U.S. coupled with historically high opening inventories
during the inventory build season due to the relatively warm winter. In
the U.S., industry propane inventories were approximately 62 million
barrels at the end of the second quarter of 2012, approximately 14
million barrels or 29 percent above the five-year historical average;
in Canada, industry propane inventories increased to 2.1 million
barrels higher than the historic five-year average, or approximately
8.1 million barrels at the end of the second quarter of 2012. The U.S.
and Canadian inventory builds for propane were primarily due to the
relatively warm 2011-12 winter and associated decreased demand. This
over-supply led to weak prices, where the Mont Belvieu propane price
averaged U.S. $0.98 per U.S. gallon (44 percent of WTI) in the second quarter of 2012, significantly below its
five-year average of 61 percent of WTI. Butane and condensate sales
prices were also lower in the second quarter of 2012.

Pembina believes that the liquids market should balance out in North
America in the coming months and years. The Company expects to see
increased demand for heavier NGL due to unconventional oil development
and expanded processing, and greater export capacity for lighter NGL as
a result of increased infrastructure capacity at the two primary U.S.
NGL hubs in Conway, Kansas and Mont Belvieu, Texas. However, downward
price pressure is expected to continue in the near-term while
inventories are cleared and supply remains robust.

Market frac spreads averaged $45.70 per barrel during the second quarter
of 2012 compared to $55.17 per barrel in the first quarter of 2012 and
$53.84 per barrel in the second quarter of 2011. Compared to the first
quarter of 2012, lower frac spreads resulted from lower NGL sales
prices combined with a higher AECO natural gas price.

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 its
pipelines include Cardium, Montney, Cretaceous, Duvernay and Swan
Hills. While recent weakness in liquids prices and an inflationary cost
environment have resulted in some producers scaling back activity in
the WCSB, it is expected that the growth profile will continue to be
positive for energy infrastructure as the liquids price environment
remains at historic highs.

Non-Operating Expenses

G&A

Pembina incurred G&A of $25.8 million during the second quarter of 2012
compared to $12.8 million during the second quarter of 2011. G&A for
the first half of 2012 was $43.3 million compared to $27.4 million for
the same period of 2011. The increase in G&A for the three and six
month periods in 2012 compared to the prior year is mainly due the
addition of employees who joined Pembina through the Arrangement, an
increase in salaries and benefits for existing and new employees, and
increased rent for new and expanded office space. Every $1 change in
share price is expected to change Pembina’s annual share-based
incentive expense by $0.7 million.

Depreciation & Amortization (Operational)

Depreciation and amortization (operational) increased to $52.5 million
during the second quarter of 2012 compared to $15.8 million during the
same period in 2011. For the six months ended June 30, 2012,
depreciation and amortization (operational) was $74.2 million, up from
$30.6 million for the same period last year. Both the quarterly and
year-to-date increases reflect depreciation on new property, plant and
equipment and depreciable intangibles including those assets acquired
through the Arrangement.

Acquisition-Related and Other

Acquisition-related and other expenses during the second quarter were
$0.5 million which includes acquisition expenses of $0.3 million and
$0.2 million in other expenses. For the six months ended June 30, 2012,
acquisition-related and other expenses were $22.7 million which
includes acquisition expenses of $13.2 million as well as $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 second quarter of 2012 were $26.7 million
compared to $25.0 million in the second quarter of 2011. Year-to-date
net finance costs in 2012 totaled $46.3 million, up from $39.3 million
in the same period of 2011. The increases relate primarily to: an $8.4
million year-to-date increase in loans and borrowings interest expense
($4.2 million for the second quarter of 2012) due to higher debt
balances; a $1.9 million change in the fair value of
non-commodity-related derivative financial instruments for the first
half of the year; and quarterly and year-to-date increased interest on
convertible debentures totaling $6.0 million due to the Provident
debentures assumed on closing of the Arrangement. These factors were
offset by a $10.9 million unrealized gain in the second quarter of 2012
on the conversion feature of the convertible debentures. See Notes 10
and 13 to the Interim Financial Statements for the period ended June
30, 2012. The change in fair value of commodity-related derivative
financial instruments has been reclassified from net finance costs to
gain on commodity-related derivative financial instruments to be
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 $27.2 million was recorded in the second quarter of 2012
compared to $15.2 million in the second quarter of 2011. Year-to-date
income tax expense in 2012 totaled $38.0 million, up from $28.8 million
in the same period of 2011. The change in income tax expense is
consistent with the change in earnings before income tax and equity
accounted investees.

Liquidity & Capital Resources


    ($ millions)                                            December 31,
                                        June 30, 2012               2011

    Working Capital                             102.0         (343.7)(1)

    Variable rate debt(2)                                               

           Bank debt                            785.0              313.8

           Variable rate debt
           swapped to fixed                   (380.0)            (200.0)

    Total variable rate debt
    outstanding (average rate of
    2.71%)                                      405.0              113.8

    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

           Subsidiary debt                        9.3                   

           Variable rate debt
           swapped to fixed                     380.0              200.0

    Total fixed rate debt
    outstanding (average rate of
    5.27%)                                    1,356.3            1,225.0

    Convertible debentures(2)                   644.4              299.8

    Finance lease liability                       5.8                5.6

    Total debt and debentures
    outstanding                               2,411.5            1,644.2

    Cash and unutilized debt
    facilities                                  728.8              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 medium-term, Pembina expects to
source funds required for capital projects from cash and unutilized
debt facilities totaling $728.8 million as at June 30, 2012. 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. Additionally,
Pembina has reinstated its DRIP as of the January 25, 2012 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 and seek new borrowing and/or issue equity.

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

Pembina’s credit facilities at June 30, 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 Bankers’
Acceptances rate 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 June 30, 2012, Pembina had $785.0 million drawn on
bank debt, $19.2 million in letters of credit and $3.0 million in cash,
leaving $728.8 million of unutilized debt facilities on the $1,530
million of established bank facilities. 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; and $250 million
in senior unsecured medium term notes due 2021. 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 June 30, 2012, Pembina had loans and borrowing (excluding
amortization, letters of credit and finance lease liabilities) of
$1,761.3 million. Pembina’s senior debt to total capital at June 30,
2012 was 26 percent.

Pembina considers the maintenance of an investment grade credit rating
as important to its ongoing ability to access capital markets on
attractive terms. On March 30, 2012, DBRS lowered the BBB (high)
ratings of the senior unsecured notes of Pembina to ‘BBB’. On April 3,
2012, Standard & Poor’s lowered its ratings, including its ‘BBB+’
long-term corporate credit rating on Pembina to ‘BBB’ following closing
of the Arrangement (see “Acquisition of Provident Energy Ltd.”). These
ratings are not recommendations to purchase, hold or sell the
securities in as much as such ratings do not comment as to market price
or suitability for a particular investor. There is no assurance any
rating will remain in effect for any given period of time or that any
rating will not be revised or withdrawn entirely by a rating agency in
the future if, in its judgment, circumstances so warrant.

Assumption of rights related to the Provident Debentures

On closing of the Arrangement on April 2, 2012, 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 (TSX: PPL.DB.E), and the 5.75 percent convertible
unsecured subordinated debentures of Provident maturing December 31,
2018 (TSX: PPL.DB.F). Outstanding Provident debentures at April 2, 2012
were $345 million. As of June 30, 2012, $344.7 million of the
debentures are still outstanding.

Capital Expenditures


                                3 Months Ended          6 Months Ended
                                    June 30                 June 30

    ($ millions)                  2012       2011        2012        2011

    Development capital                                                  

      Conventional                55.6       10.1        64.5        26.8
      Pipelines

      Oil Sands & Heavy                      30.1         6.0       129.9
      Oil

      Gas Services                23.5       25.5        55.8        41.1

      Midstream                   55.2       11.6        55.9       101.9

    Corporate/other                2.3        0.9         4.1         1.8
    projects

    Total development            136.6       78.2       186.3       301.5
    capital

For the three months ended June 30, 2012, capital expenditures were
$136.6 million compared to the $78.2 million expended in the same three
months of 2011.

During the first half of 2012, capital expenditures were $186.3 million
compared to $301.5 million during the same six month period in 2011.
Capital expenditures for the same period of 2011 were significantly
higher than in 2012 due to construction of the Nipisi and Mitsue
pipelines and the acquisition of midstream assets in the Edmonton,
Alberta area (related to PNT) and linefill for the Peace Pipeline
system.

The majority of the capital expenditures in the second quarter and first
half 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 to progress the expansion of the shallow cut facility at the
Cutbank Complex and 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
expansion at the Redwater Facility.

Contractual Obligations at June 30, 2012


    ($
    thousands)                                          Payments Due By Period

    Contractual                      Less than                                         After
    Obligations            Total        1 year   1 - 3 years     4 - 5 years         5 years

    Office and
    vehicle
    leases               305,274        25,801        52,404          56,878         170,191

    Loans and
    borrowings
    (1)                2,117,526        62,238       383,242         863,329         808,717

    Convertible
    debentures
    (1)                  923,169        39,156       118,351         246,170         519,492

    Construction
    commitments          462,428       336,483       125,945                                

    Provisions
    (2)                  507,707         2,358         2,664             447         502,238

    Total
    contractual
    obligations        4,316,104       466,036       682,606       1,166,824       2,000,638

    (1)  Excluding deferred financing costs; finance leases included under
         "office and vehicle leases".

    (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 Musreau Deep Cut Facility at its
Cutbank Complex, the Musreau Shallow Cut Expansion, the Saturn Facility
and the Resthaven Facility, and to the remaining capital expenditures
associated with the Nipisi and Mitsue pipelines. See “Forward-Looking Statements & Information.”

Critical Accounting Estimates

Preparing the Interim Financial Statements in conformity with IFRS
requires management to make judgments, estimates and assumptions 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.

Please refer to the “Critical Accounting Estimates” section of Pembina’s
MD&A for the year ended December 31, 2011 for more information.

Changes in Accounting Principles and Practices

For a discussion of future changes to Pembina’s IFRS accounting
policies, see Pembina’s MD&A for the year ended December 31, 2011.
Subsequent to the Arrangement, Pembina reviewed and compared legacy
Provident’s accounting policies with the Company’s existing policies
and determined that there were no significant differences.

Controls and Procedures

Changes in internal control over financial reporting

During the second quarter of 2012, there have been no changes in 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 National Instrument 52-109 -
Certification of Disclosure in Issuers’ Annual and Interim Filings,
management, including the CEO and CFO, have limited the scope of their
design of the Company’s disclosure controls and procedures and internal
control over financial reporting 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 unaudited condensed consolidated financial statements for the
quarter ended June 30, 2012 was approximately 38 percent of
consolidated net revenues and approximately 49 percent of consolidated
pre-tax earnings.

Additionally, Provident’s current assets and current liabilities were
approximately 70 percent and 56 percent of consolidated current assets
and liabilities, respectively, and its non-current assets and
non-current liabilities were approximately 58 percent and 35 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 disclosure controls and procedures (“DC&P”) and internal
controls over financial reporting (“ICFR”) in a manner consistent with
the Company’s other operations.

Further details related to the Arrangement are disclosed in “Acquisition
of Provident Energy Ltd.” of this MD&A and in Note 3 in the Notes to
the Company’s Interim Financial Statements for the second quarter of
2012.

Trading Activity and Total Enterprise Value( (1))


                                                     As at and for the 3
                                                        months ended

    ($ thousands, except
    where noted)             August 7, 2012(2) June 30, 2012 June 30, 2011

    Trading volume and value                                              

           Total volume
           (shares)                  9,851,046    56,667,601    10,543,451

           Average daily
           volume (shares)             394,042       899,486       167,356

           Value traded                263,725     1,620,184       390,673

    Shares outstanding
    (shares)                       288,697,725   287,785,195   167,470,150

    Closing share price
    (dollars)                            26.40         26.02         25.39

    Market value                                                          

           Shares                    7,621,627     7,488,171     4,252,067

           5.75% convertible
           debentures
           (PPL.DB.C)               326,252(3)    325,922(4)    310,500(5)

           5.75% convertible
           debentures
           (PPL.DB.E)(6)            195,399(7)    192,948(8)              

           5.75% convertible
           debentures
           (PPL.DB.F)(6)            187,964(9)   186,205(10)              

    Market capitalization            8,331,242     8,193,246     4,562,567

    Senior debt                      1,782,000     1,752,000     1,229,041

    Total enterprise value
    (11)                            10,113,242     9,945,246     5,791,608

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

    (2)   Based on 25 trading days from June 30, 2012 to August 7, 2012
          inclusive.

    (3)   $299.7 million principal amount outstanding at a market price of
          $108.85 at August 7, 2012 and with a conversion price of $28.55.

    (4)   $299.7 million principal amount outstanding at a market price of
          $108.47 at June 29, 2012 and with a conversion price of $28.55.

    (5)   $300 million principal amount outstanding at a market price of
          $103.50 at June 30, 2011 and with a conversion price of $28.55.

    (6)   Pursuant to the Arrangement, Pembina assumed the rights and
          obligations of Provident debentures, which are listed on the TSX
          under PPL.DB.E and PPL.DB.F.

    (7)   $172.2 million principal amount outstanding at a market price of
          $113.50 at August 7, 2012 and with a conversion price of $24.94.

    (8)   $172.2 million principal amount outstanding at a market price of
          $112.06 at June 29, 2012 and with a conversion price of $24.94.

    (9)   $172.4 million principal amount outstanding at a market price of
          $109.00 at August 7, 2012 and with a conversion price of $29.53.

    (10)  $172.4 million principal amount outstanding at a market price of
          $107.98 at June 29, 2012 and with a conversion price of $29.53.

    (11)  Refer to "Non-GAAP Measures."

As indicated in the previous table, Pembina’s total enterprise value was
$9.9 billion at June 30, 2012 and issued and outstanding shares of
Pembina rose to 287.8 million by the end of the second quarter 2012
primarily due to shares issued under the Arrangement, compared to 167.5
million in the same period of 2011.

Dividends

Pembina announced on April 12, 2012 that following closing of the
Arrangement it increased its monthly dividend rate 3.8 percent from
$0.13 per share per month (or $1.56 annualized) to $0.135 per share per
month (or $1.62 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 has reinstated its DRIP 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 second quarter was 58 percent of
common shares outstanding for proceeds of approximately $57.0 million.

Listing on the NYSE

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

Risk Factors

Management has identified the primary risk factors that could
potentially have a material impact on the financial results and
operations of Pembina. Such risk factors are presented in Pembina’s
MD&A and Provident’s MD&A for the year ended December 31, 2011, in
Pembina’s Annual Information Form (“AIF”) for the year ended December
31, 2011 and in Provident’s AIF for the year ended December 31, 2011.
Pembina’s MD&A and AIF are available at www.pembina.com and in Canada under Pembina’s company profile on www.sedar.com. Provident’s MD&A is available at www.pembina.com and its AIF can be found on Pembina NGL Corporation’s company profile
on www.sedar.com or on Provident’s profile at www.sec.gov.

Selected Quarterly Operating Information


                             2012                            2011                         2010

                          Q2       Q1       Q4       Q3       Q2       Q1       Q4       Q3       Q2

    Average
    throughput
    (mbpd)                                                                                          

    Total
    Conventional
    Throughput         433.9    466.9    422.8    430.4    411.4    390.3    375.0    361.4    370.4

    Oil Sands &
    Heavy Oil(1)       870.0    870.0    870.0    775.0    775.0    775.0    775.0    775.0    775.0

    Gas Services
    Processing
    (mboe/d)(2)         47.5     44.1     45.3     43.6     40.9     39.4     42.1     38.9     38.9

    NGL sales
    volume              90.4
    (mboe/d)             (3)                                                                        

    (1)  Oil Sands & Heavy Oil throughput refers to contracted capacity.

    (2)  Converted to mboe/d from MMcf/d at a 6:1 ratio.

    (3)  Represents per day volumes since the closing of the Arrangement.

Selected Quarterly Financial Information


                                        2012                                    2011                                  2010

    ($ millions, except
    where noted)                   Q2          Q1       Q4          Q3          Q2          Q1          Q4          Q3          Q2

    Revenue                     870.9       475.5    468.1       300.6       512.4       394.9       290.7       266.1       386.5

    Operations                   67.7        48.4     56.3        54.4        37.6        44.8        41.9        40.0        38.2

    Cost of goods sold          641.9       299.1    307.9       145.8       364.3       254.2       161.8       148.2       262.2

    Realized gains
    (losses) on
    commodity-related
    derivative
    financial instruments      (12.4)       (0.3)      0.8                   (0.2)         1.4       (0.8)         0.3         1.2

    Operating margin(1)         148.9       127.7    104.7       100.4       110.3        97.3        86.2        78.2        87.3

    Depreciation and
    amortization included
    in operations                52.5        21.7     19.5        17.8        15.8        14.8        15.6        15.3        15.3

    Unrealized gains
    (losses) on
    commodity-related
    derivative financial
    instruments                  64.8       (3.5)      0.9         0.7         3.3         0.3         1.8       (3.2)         2.4

    Gross profit                161.2       102.5     86.1        83.3        97.8        82.8        72.4        59.7        74.4

    Adjusted EBITDA(1)          125.9       111.4     87.0        86.8       103.3        87.2        79.1        68.1        78.0

    Cash flow from
    operating
    activities                   24.1        65.3     74.3        88.0        49.5        74.5        54.6        66.6        69.6

    Cash flow from
    operating activities
    per common share ($
    per share)                   0.08        0.39     0.44        0.53        0.30        0.45        0.33        0.41        0.43

    Adjusted cash flow
    from operating
    activities(1)                89.5        98.8     57.3        90.8        81.8        76.0        62.6        67.6        63.0

    Adjusted cash flow
    from operating
    activities per common
    share(1)
        ($ per share)            0.31        0.59     0.34        0.54        0.49        0.45        0.39        0.41        0.38

    Earnings for the
    period                       80.4        32.6     45.1        30.1        48.0        42.5        55.2        28.6        37.7

    Earnings per common
    share
          ($ per share):                                                                                                          

           Basic                 0.28        0.19     0.27        0.18        0.29        0.25        0.34        0.19        0.23

           Diluted               0.28        0.19     0.27        0.18        0.29        0.25        0.33        0.19        0.23

    Common shares
    outstanding
    (millions):                                                                                                                   

           Weighted
           average
           (basic)              285.3       168.3    167.4       167.6       167.3       167.0       165.0       164.0       163.2

           Weighted
           average
           (diluted)            286.0       168.9    168.2       168.2       168.0       167.6       171.7       166.9       166.2

           End of period        287.8       169.0    167.9       167.7       167.5       167.1       166.9       164.5       163.6

    Dividendsdeclared           116.2        65.7     65.4        65.4        65.3        65.1        64.6        64.0        63.8

    Dividends per common
    share
          ($ per share):         0.41        0.39     0.39        0.39        0.39        0.39        0.39        0.39        0.39

((1) )Refer to “Non-GAAP measures.”

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.

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 Arrangement.


                                 3 Months Ended           6 Months Ended
                                    June 30                  June 30

    ($ millions, except
    per share amounts)            2012        2011         2012        2011

    Results from
    operating activities         134.9        85.6        197.7       153.7

    Share of profit from
    equity accounted
    investees
        (before tax,
    depreciation and
    amortization)                  1.3         4.9          2.8         9.2

    Depreciation and
    amortization                  54.2        16.1         76.7        31.2

    Unrealized gain on
    commodity-related
    derivative financial
    instruments                 (64.8)       (3.3)       (61.3)       (3.6)

    EBITDA                       125.6       103.3        215.9       190.5

    Add:                                                                   

    Acquisition-related
    expenses                       0.3                     21.4            

    Adjusted EBITDA              125.9       103.3        237.3       190.5

    EBITDA per common
    share - basic
    (dollars)                     0.44        0.62         0.95        1.14

    Adjusted EBITDA per
    common share - basic
    (dollars)                     0.44        0.62         1.05        1.14

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 Arrangement plus share of profit from equity
accounted investees (before tax).


                                 3 Months Ended           6 Months Ended
                                     June 30                 June 30

    ($ millions, except
    per share amounts)             2012       2011         2012        2011

    Earnings before income
    tax and equity
    accounted investees           108.2       60.6        151.4       114.5

    Add (deduct):                                                          

    Unrealized change in
    fair value of
    derivative financial
    instruments                  (70.2)        1.2       (69.5)       (2.8)

    Share of (loss) profit
    of investments in
    equity accounted
    investees (after tax)         (0.6)        2.7        (0.4)         4.8

    Tax on share of profit
    of investments in
    equity accounted
    investees                     (0.3)        0.9        (0.2)         1.6

    Acquisition-related
    expenses                        0.3                    21.4            

    Adjusted earnings              37.4       65.4        102.7       118.1

    Adjusted earnings per
    common share - basic
    (dollars)                      0.13       0.39         0.45        0.71

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         6 Months Ended
                                      June 30                June 30

    ($ millions, except per        2012       2011        2012        2011
    share amounts)

    Cash flow from operating       24.1       49.5        89.4       124.0
    activities

    Add:                                                                  

    Change in non-cash             65.1       32.3        77.5        33.8
    working capital

    Acquisition-related             0.3                   21.4
    expenses

    Adjusted cash flow from        89.5       81.8       188.3       157.8
    operating activities

    Adjusted cash flow from        0.31       0.49        0.83        0.94
    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            6 Months Ended
                                   June 30                    June 30

    ($ millions)                 2012        2011          2012        2011

    Revenue                     870.9       512.4       1,346.4       907.3

    Cost of sales:                                                         

      Operations                 67.7        37.6         116.1        82.4

      Cost of goods sold        641.9       364.3         941.0       618.5

      Realized gain            (12.4)       (0.2)        (12.7)         1.2
    (loss) on
    commodity-related
    derivative financial
    instruments

    Operating margin            148.9       110.3         276.6       207.6

    Depreciation and             52.5        15.8          74.2        30.6
    amortization
    included in
    operations

    Unrealized gain on           64.8         3.3          61.3         3.6
    commodity-related
    derivative financial
    instruments

    Gross profit                161.2        97.8         263.7       180.6

Unrealized gain 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”, “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, in
            relation to the PNT, the expansions at the Cutbank Complex's
            Musreau Gas Plant, the proposed Resthaven Facility and the
            proposed Saturn Facility, 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 expansion of throughput
            capacity on the Northern NGL System, the proposed expansion of
            a number of existing truck terminals and construction of new
            full-service terminals, the installation of two remaining pump
            stations on the Nipisi and Mitsue pipelines, the development of
            seven fee-for-service storage facilities at Redwater, the
            Redwater fractionator expansion, and the proposed development
            of a C2+ fractionators at Redwater;
        --  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 governmental 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 of the proposed Resthaven Facility and
            the proposed Saturn Facility;
        --  expectations regarding in-service dates for new developments,
            including the Resthaven Facility, the Saturn Facility and the
            Northern NGL System;
        --  expectations regarding incremental NGL volumes to be
            transported on Pembina's conventional pipelines by the end of
            2013 as a result of new developments in Pembina's Gas Services
            business;
        --  expectations regarding in-service dates for the seven
            fee-for-service storage facilities at Redwater, the Redwater
            fractionator expansion project and the proposed C2+
            fractionator at Redwater;
        --  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;
        --  expectations regarding the potential construction, expansion
            and conversion of downstream infrastructure in the U.S. Midwest
            and Gulf Coast;
        --  the impact of approval from the British Columbia Utilities
            Commission of Pembina's application on the Western System;
        --  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;
        --  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 proposed
            Resthaven Facility and their estimated in-service dates of
            fourth quarter of 2013 and the first quarter of 2014,
            respectively; 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 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 C2+ fractionator at 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
            volumes being transported on the conventional pipelines, the
            proposed expansion of the Musreau Gas Plant's shallow cut gas
            processing capability, 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
            Arrangement;
        --  the failure to integrate the businesses of Pembina and
            Provident; and
        --  the other factors discussed under "Risk Factors" in Pembina's
            MD&A and Provident's MD&A for the year ended December 31, 2011,
            in Pembina's Annual Information Form ("AIF") for the year ended
            December 31, 2011 and in Provident's AIF for the year ended
            December 31, 2011. Pembina's MD&A and AIF are available at
            www.pembina.com and in Canada under Pembina's company profile
            on www.sedar.com. Provident's MD&A is available at
            www.pembina.com and its AIF can be found on Pembina NGL
            Corporation's company profile on www.sedar.com or on
            Provident'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.

CONDENSED CONSOLIDATED INTERIM STATEMENT OF FINANCIAL POSITION
(unaudited)


                                                    June 30,      December
    ($ thousands)                        Note           2012      31, 2011

    Assets
    Current assets

      Cash and cash equivalents                        2,981              

      Trade receivables and other                    289,204       148,267

      Derivative financial instruments     13         37,770         4,643

      Inventory                                      102,227        21,235

                                                     432,182       174,145

    Non-current assets                                                    

      Property, plant and equipment         4      4,827,773     2,747,530

      Intangible assets and goodwill        5      2,657,479       243,904

      Investments in equity accounted                158,116       161,002
    investees

      Derivative financial instruments     13            724         1,807

     Other receivables                                 5,579        10,814

                                                   7,649,671     3,165,057

    Total Assets                                   8,081,853     3,339,202

    Liabilities and Shareholders' Equity
    Current liabilities

      Bank indebtedness                                                676

      Trade payables and accrued                     251,640       166,646
    liabilities

      Dividends payable                               38,850        21,828

      Loans and borrowings                  6          9,963       323,927

      Derivative financial instruments     13         29,768         4,725

                                                     330,221       517,802

    Non-current liabilities                                               

      Loans and borrowings                  6      1,745,554     1,012,061

      Convertible debentures                7        607,458       289,365

      Derivative financial instruments     13         38,945        12,813

      Employee benefits                               15,281        16,951

      Share-based payments                            10,837        14,060

      Deferred revenue                                 2,411         2,185

      Provisions                            8        501,192       405,433

      Deferred tax liabilities                       559,401       106,915

                                                   3,481,079     1,859,783

    Total Liabilities                              3,811,300     2,377,585

    Shareholders' Equity                                                  

    Equity attributable to shareholders:                                  

      Share capital                         9      5,184,564     1,811,734

      Deficit                                      (903,922)     (834,921)

      Accumulated other comprehensive               (15,196)      (15,196)
    income

                                                   4,265,446       961,617

    Non-controlling interest                           5,107              

                                                   4,270,553       961,617

    Total Liabilities and Shareholders'            8,081,853     3,339,202
    Equity

       See accompanying notes to condensed consolidated interim
financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME
(unaudited)


                                     3 Months Ended        6 Months Ended
                                         June 30               June 30

    ($ thousands, except   Note       2012       2011       2012       2011
    per share amounts)

    Revenues                       870,929    512,406  1,346,420    907,294

    Cost of sales                  762,099    417,746  1,131,309    731,552

    Gain on                  13     52,351      3,142     48,577      4,849
    commodity-related
    derivative financial
    instruments

    Gross profit             11    161,181     97,802    263,688    180,591

      General and                   25,782     12,781     43,359     27,428
    administrative

      Acquisition-related              538      (662)     22,669      (582)
    and other expense
    (income)

                                    26,320     12,119     66,028     26,846

    Results from operating         134,861     85,683    197,660    153,745
    activities

      Finance income              (11,175)      (536)   (11,441)      (911)

      Finance costs                 37,880     25,583     57,695     40,199

      Net finance costs      10     26,705     25,047     46,254     39,288

    Earnings before income
    tax and equity
    accounted
       investees                   108,156     60,636    151,406    114,457

      Share of loss
    (profit) of
    investments in equity
    accounted
        investees, net of
    tax                                570    (2,652)        398    (4,842)

      Income tax expense            27,178     15,245     38,048     28,764

    Earnings and total              80,408     48,043    112,960     90,535
    comprehensive income
    for the period

    Earnings and
    comprehensive income
    attributable to:

      Shareholders                  80,368     48,043    112,920     90,535

      Non-controlling                   40                    40
    interest

                                    80,408     48,043    112,960     90,535

    Earnings per share
    attributable to the
    shareholders of the
      Company

      Basic and diluted               0.28       0.29       0.50       0.54
    earnings per share
    (dollars)

       See accompanying notes to condensed consolidated interim
financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY
(unaudited)


                                                  6 Months Ended June 30

    ($ thousands)                      Note            2012            2011

    Share Capital                                                          

      Balance, beginning of period                1,811,734       1,794,536

      Common shares issued on                     3,283,976
    acquisition

      Dividend reinvestment plan                     84,974                

      Share-based payment transactions                3,516           9,417

      Debenture conversion                              366                

      Other                                             (2)            (10)

      Balance, end of period           9          5,184,564       1,803,943

    Deficit                                                                

      Balance, beginning of period                (834,921)       (739,351)

      Earnings for the period                       112,920          90,535
    attributable to shareholders

      Dividends declared                          (181,921)       (130,416)

      Balance, end of period                      (903,922)       (779,232)

    Other Comprehensive Income (Loss)                                      

      Balance, beginning and end of                (15,196)         (4,577)
    period

    Non-controlling interest                                               

      Balance, beginning of period                                         

      Assumed on acquisition                          5,067                

      Earnings attributable to                           40
    non-controlling interest

      Balance, end of period                          5,107                

    Total Equity                                  4,270,553       1,020,134

       See accompanying notes to condensed consolidated interim
financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
(unaudited)


                                        3 Months Ended       6 Months Ended
                                           June 30              June 30

    ($ thousands)            Note      2012       2011      2012       2011

    Cash provided by (used
    in):

    Operating activities:                                                  

    Earnings for the period          80,408     48,043   112,960     90,535

    Adjustments for:                                                       

      Depreciation and               54,165     16,071    76,677     31,175
    amortization

      Unrealized gain on
    commodity-related
         derivative
    financial instruments      13  (64,820)    (3,301)  (61,273)    (3,598)

      Net finance costs        10    26,705     25,047    46,254     39,288

      Share of loss (profit)
    of investments in equity
       accounted investees
    (net of tax)                        570    (2,652)       398    (4,842)

      Deferred income tax            27,780     15,245    38,650     28,764
    expense

      Share-based payments            2,689      3,911     6,299      7,889

      Employee future                 1,898      1,203     3,329      2,401
    benefits expense

      Other                             (3)      (146)       467       (62)

      Changes in non-cash          (65,093)   (32,310)  (77,522)   (33,761)
    working capital

      Distributions from
    investments in equity
    accounted
        investees                     3,588      7,237     7,733      8,685

      Decommissioning               (1,310)      (739)   (2,367)    (1,775)
    liability expenditures

      Employer future               (2,500)    (2,000)   (5,000)    (4,000)
    benefit contributions

      Net interest paid            (40,004)   (26,106)  (57,198)   (36,718)

    Cash flow from operating         24,073     49,503    89,407    123,981
    activities

    Financing activities:                                                  

      Bank borrowings               200,000              266,861     40,000

      Repayment of loans and       (57,315)   (82,588)  (60,037)   (85,100)
    borrowings

      Issuance of debt                                              250,000

      Financing fees                (2,275)       (54)   (5,066)    (1,756)

      Exercise of stock               1,611      5,266     2,647      9,086
    options

      Issue of shares under          56,973               84,974
    Dividend Reinvestment
    Plan

      Dividends paid               (99,338)   (65,223) (164,900)  (130,339)

    Cash flow from financing         99,656  (142,599)   124,479     81,891
    activities

    Investing activities:                                                  

      Net capital                 (131,869)   (89,094) (219,103)  (296,672)
    expenditures

      Cash acquired on                8,874                8,874
    acquisition

    Cash flow used in             (122,995)   (89,094) (210,229)  (296,672)
    investing activities

    Change in cash                      734  (182,190)     3,657   (90,800)

    Cash (bank                        2,247    216,787     (676)    125,397
    indebtedness), beginning
    of period

    Cash and cash                     2,981     34,597     2,981     34,597
    equivalents, end of
    period

       See accompanying notes to condensed consolidated interim
financial statements

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(unaudited)

1. REPORTING ENTITY

Pembina Pipeline Corporation (“Pembina” or the “Company”) is an energy
transportation and service provider domiciled in Canada. The condensed
consolidated interim financial statements (“Interim 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 six months ending June 30, 2012.
These Interim Financial Statements and the notes thereto have been
prepared in accordance with IAS 34 – Interim Financial Reporting. They
do not include all of the information required for full annual
financial statements and should be read in conjunction with the
consolidated financial statements of the Company as at and for the year
ended December 31, 2011. The Interim Financial Statements were
authorized for issue by the Board of Directors on August 9, 2012.

Pembina owns or has interests in pipelines that transport conventional
crude oil and natural gas liquids, oil sands and heavy oil pipelines,
gas gathering and processing facilities, and a natural gas liquids
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. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies are set out in the December 31, 2011 financial
statements. Those policies have been applied consistently to all
periods presented in these Interim Financial Statements except for an
addition to an accounting policy as a result of the acquisition of
Provident Energy Ltd. which is provided below.

Inventories

Inventories are measured at the lower of cost and net realizable value
and consist primarily of crude oil and natural gas liquids. 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.


3. 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 “Arrangement”). 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 Arrangement, 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 preliminary purchase price allocation based on assessed fair values
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 $1,759 goodwill) 2,422

    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                                   (414)

    Non-controlling interest                                     (5)

                                                               3,284

The determination of fair values and the allocation of the purchase
price is based upon a preliminary independent valuation which is
pending finalization. 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. None of the
goodwill recognized is expected to be deductible for income tax
purposes.

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

The Company has recognized $21.4 million in acquisition-related
expenses. These expenses are included in acquisition-related and other
expenses in the Condensed Consolidated Interim Statement of
Comprehensive Income.

The Pembina Shares were listed and began trading on the NSYE under the
symbol “PBA” on April 2, 2012.

Revenues of the Provident business for the period from the acquisition
date of April 2, 2012 to June 30, 2012, net of intersegment
eliminations, were $328.8 million. Net earnings, net of intersegment
eliminations, for the same period were $35.9 million.

Unaudited proforma consolidated revenues (prepared as if the Provident
acquisition had occurred on January 1, 2012) for the six months ended
June 30, 2012 are $1,886.5 million and net earnings for the same period
are $159.9 million.

On closing of the Arrangement, the following significant subsidiaries
were acquired:


    (percentages)                           Ownership Interest

    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

4.  PROPERTY, PLANT AND EQUIPMENT


                         Land               Facilities   Linefill         Assets
                          and                      and        and          Under
                         Land                Equipment      Other   Construction
    ($ thousands)      Rights   Pipelines                                              Total

    Cost                                                                                    

    Balance at
    December 31,                                         200,726                   3,603,950
    2011               67,219   2,500,027      528,620   (1)             307,358   (1)

    Acquisition        18,093     280,481    1,281,091    321,287         87,319   1,988,271
    (Note 3)

    Additions               2        (99)      104,051      5,422         76,912     186,288

    Change in                    (28,811)      (3,156)                              (31,967)
    decommissioning
    provision

    Capitalized                     3,173          696                     1,977       5,846
    interest

    Transfers              22    (67,116)      106,866   (18,126)       (21,646)            

    Disposals and     (5,000)       (917)        (621)        349                    (6,189)
    other

    Balance at June    80,336   2,686,738    2,017,547    509,658        451,920   5,746,199
    30, 2012

    Depreciation                                                                            

    Balance at          4,088     707,095       92,998     52,239                    856,420
    December 31,
    2011

    Depreciation          140      35,017       20,604      7,516                     63,277

    Transfers                       1,217       24,328   (25,545)                           

    Disposals and                   (567)         (76)      (628)                    (1,271)
    other

    Balance at June     4,228     742,762      137,854     33,582                    918,426
    30, 2012

    Carrying
    amounts

    December 31,       63,131   1,792,932      435,622    148,487        307,358   2,747,530
    2011

    June 30, 2012      76,108   1,943,976    1,879,693    476,076        451,920   4,827,773

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

Pipeline assets are generally depreciated using the straight line method
over 5 to 75 years (an average of 49 years) or declining balance method
at rates ranging from 3 percent to 48 percent per annum (an average
rate of 15 percent per annum). Facilities and equipment are depreciated
using the straight line method over 3 to 75 years (at an average rate
of 34 years) or declining balance method at rates ranging from 3
percent to 37 percent (at an average rate of 13 percent per annum).
Other assets are depreciated using the straight line method over 2 to
45 years (an average of 10 years) or declining balance method at rates
ranging from 3 percent to 37 percent (at an average rate of 8 percent
per annum).

Commitments

At June 30, 2012, the Company has contractual commitments for the
acquisition and or construction of property, plant and equipment of
$462.4 million (December 31, 2011: $364.3 million).

5.  INTANGIBLE ASSETS AND GOODWILL


                                                 Other
                                  Goodwill Intangibles     Total

    ($ thousands)                                               

    Cost                                                        

    Balance at December 31, 2011   222,670      23,038   245,708

    Acquisition (Note 3)         1,759,356     662,732 2,422,088

    Additions and other                          5,000     5,000

    Balance at June 30, 2012     1,982,026     690,770 2,672,796

    Amortization                                                

    Balance at December 31, 2011                 1,804     1,804

    Amortization                                13,513    13,513

    Balance at June 30, 2012                    15,317    15,317

    Carrying amounts                                            

    December 31, 2011              222,670      21,234   243,904

    June 30, 2012                1,982,026     675,453 2,657,479

Amortization is recognized in profit or loss on a straight-line or
declining balance basis over the estimated useful lives of depreciable
intangible assets 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 33 years (an average of 9 years).

The preliminary allocation of the aggregate carrying amount of
intangible assets to each cash generating unit is as follows:


                                       June 30, December 31,
    ($ thousands)                          2012         2011

    Conventional Pipelines              194,370      194,370

    Oil Sands and Heavy Oil              33,300       28,300

    Gas Services                         20,885       21,234

    Midstream                         2,408,924             

                                      2,657,479      243,904

The allocation is subject to change upon finalization of purchase price
analysis of the acquisition. See Note 3.

6.  LOANS AND BORROWINGS

Carrying value terms and debt repayment schedule

Terms and conditions of outstanding loans were as follows:


    ($ thousands)                                               Carrying amount
                                                                            (3)

                      Available      Nominal    Year of    June 30,    Dec. 31,
                     facilities     interest   maturity        2012        2011
                                        rate

                                     prime +
                                        0.50
    Operating                     or BA(2) +
    facility(1)          30,000         1.50       2013                   3,139

                                     prime +
    Revolving                           0.50
    unsecured credit              or BA(2) +
    facility         1,500,000          1.50       2017     780,230     309,981

    Senior secured                      7.38                             57,499
    notes

    Senior unsecured    175,000         5.99       2014     174,570     174,462
    notes - Series A

    Senior unsecured    200,000         5.58       2021     196,810     196,638
    notes - Series C

    Senior unsecured    267,000         5.91       2019     265,504     265,403
    notes - Series D

    Senior unsecured     75,000         6.16       2014      74,729      74,658
    term facility

    Senior unsecured    250,000         4.89       2021     248,636     248,558
    medium term
    notes

    Subsidiary debt       9,279         4.98       2014       9,279            

    Finance lease                                             5,759       5,650
    liabilities

    Total             2,506,279                           1,755,517   1,335,988
    interest-bearing
    liabilities

    Less current                                            (9,963)   (323,927)
    portion

    Total                                                 1,745,554   1,012,061
    non-current

((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.

7.  CONVERTIBLE DEBENTURES


    ($ thousands)        Series C       Series E       Series F       Total
                          - 5.75%        - 5.75%        - 5.75%

    Conversion             $28.55         $24.94         $29.53
    price
    (dollars)

    Interest           May 31 and    June 30 and    June 30 and
    payable           November 30    December 31    December 31
    semi-annually
    in arrears on:

                     November 30,   December 31,   December 31,
    Maturity date            2020           2017           2018

    Balance,              289,365                                   289,365
    December 31,
    2011

    Assumed on                           158,471        158,343     316,814
    acquisition
    (1) (Note 3)

    Conversions              (54)          (264)           (14)       (332)
    and
    redemptions

    Accretion                                280            229         509

    Deferred                  584            275            243       1,102
    financing fee
    (net
    amortization)

    Balance, June         289,895        158,762        158,801     607,458
    30, 2012

((1))  Excludes conversion feature of convertible debentures

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 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 equity
conversion option is recognized as an embedded derivative and accounted
for as a stand-alone derivative financial instrument, measured at fair
value using an option pricing model.

8.  PROVISIONS


    ($ thousands)                                             Total

    Balance at December 31, 2011(1)                         416,153

    Unwinding of discount rate                                5,777

    Incurred during the period                                1,766

    Assumed on acquisition (Note 3)                         124,579

    Decommissioning liabilities settled during the period   (2,367)

    Change in rates                                        (30,299)

    Change in estimate and other                            (7,902)

    Total                                                   507,707

    Less current portion (included in accrued liabilities)    6,515

                                                            501,192

((1))  Includes current provision of $10,720 at December 31, 2011 (included
in accrued liabilities).

9.  SHARE CAPITAL


    ($ thousands, except share                     Number   Share Capital
    amounts)

    Balance December 31, 2011                 167,908,271       1,811,734

    Issued on acquisition (Note 3)            116,535,750       3,283,976

    Share based payment transactions              175,203           3,516

    Dividend reinvestment plan                  3,151,670          84,974

    Other                                          14,301             364

    Balance June 30, 2012                  287,785,195(1)       5,184,564

    (1)  Weighted average number of common shares outstanding for the three
         months ended June 30, 2012 is 285.3 million (June 30, 2011: 167.3
         million). On a fully diluted basis, the weighted average number of
         common shares outstanding for the three months ended June 30, 2012
         is 286.0 million (June 30, 2011: 168.0 million).Weighted average
         number of common shares outstanding for the six months ended June
         30, 2012 is 226.8 million (June 30, 2011: 167.2 million). On a
         fully diluted basis, the weighted average number of common shares
         outstanding for the six months ended June 30, 2012 is 250.7
         million (June 30, 2011: 167.8 million).

Dividends 

The following dividends were declared and paid by the Company:


                                                    6 Months Ended
                                                        June 30

    ($ thousands)                                      2012    2011

    $0.80 per qualifying common share (2011: $0.78) 181,921 130,416

On July 9 , 2012, Pembina’s Board of Directors declared a dividend for
July of $39.0 million, representing $0.135 per qualifying common share
($1.62 annualized).


10. NET FINANCE COSTS


                                              3 Months Ended 6 Months Ended
                                                 June 30        June 30

    ($ thousands)                               2012    2011   2012    2011

    Interest income from:                                                  

      Related parties                                    220    263     410

      Bank deposits                              298     284    301     389

    Foreign exchange gains                                32            112

    Change in fair value of conversion        10,877         10,877
    feature of convertible debentures

    Finance income                            11,175     536 11,441     911

    Interest expense on financial liabilities
    measured at amortized cost:

      Loans and borrowings                    18,120  13,967 33,536  25,132

      Convertible debentures                  10,579   4,601 15,184   9,168

      Finance leases                             105      97    210     193

      Unwinding of discount                    3,327   2,393  5,801   4,905

    Change in fair value of
    non-commodity-related derivative
    financial
     instruments                               5,475   4,525  2,659     801

    Foreign exchange losses                      274            305        

    Finance costs                             37,880  25,583 57,695  40,199

    Net finance costs                         26,705  25,047 46,254  39,288

11. OPERATING SEGMENTS


    3 Months Ended June                            Oil Sands                                       Corporate &
    30, 2012                    Conventional               &            Gas       Midstream       Intersegment
    ($ thousands)               Pipelines(1)       Heavy Oil       Services             (3)       Eliminations       Total

    Revenue:                                                                                                              

      Pipeline                        78,410          39,412                                           (6,875)     110,947
    transportation

      NGL product and
       services,
    terminalling,
       storage and hub
    services                                                                        737,770                        737,770

      Gas Services                                                   22,212                                         22,212

    Total revenue                     78,410          39,412         22,212         737,770            (6,875)     870,929

      Operations                      29,886          11,604          7,172          19,640              (624)      67,678

      Cost of goods sold,
    including
       product purchases                                                            648,794            (6,875)     641,919

      Realized gain
    (loss) on
       commodity-related
    derivative
       financial
    instruments                      (1,033)                                       (11,436)                       (12,469)

    Operating margin                  47,491          27,808         15,040          57,900                624     148,863

      Depreciation and
       amortization
    (operational)                     12,179           4,938          4,332          31,053                         52,502

      Unrealized gain
    (loss) on
        commodity-related
        derivative
    financial instruments                233                                         64,587                         64,820

    Gross profit                      35,545          22,870         10,708          91,434                624     161,181

      Depreciation                                                                                       1,664       1,664
    included in
       general and
    administrative

      Other general and                2,225             968          1,456           5,488             13,981      24,118
    administrative

      Acquisition-related              (311)             519                            100                230         538
    and other

    Reportable segment
    results from
    operating activities              33,631          21,383          9,252          85,846           (15,251)     134,861

      Net finance costs                1,760             563          1,964           4,128             18,290      26,705

    Reportable segment
    earnings before tax
    and income from
    equity accounted
    investees                         31,871          20,820          7,288          81,718           (33,541)     108,156

    Share of loss
    (profit) of
    investments in equity
     accounted investees,
    net of tax                                                                          570                            570

    Reportable segment               616,803       1,097,240        539,565    4,493,465(2)          1,334,780   8,081,853
    assets

    Capital expenditures              55,632                         23,459          55,240              2,277     136,608

    Reportable segment               293,529          83,397         43,816         771,086          2,619,472   3,811,300
    liabilities

    (1)   4.5 percent of Conventional Pipelines revenue is under regulated
         tolling arrangements.

    (2)   Includes investments in equity accounted investees of $158.1
         million.

         NGL product and services, terminalling, storage and hub services
    (3)  revenue includes $28.7 million associated with U.S. midstream
         sales.

                                                     Oil                                  Corporate &
    3 Months Ended June                          Sands &                                 Intersegment
    30, 2011                    Conventional       Heavy       Gas                       Eliminations
    ($ thousands)               Pipelines(1)         Oil  Services       Midstream                          Total

    Revenue:                                                                                                     

      Pipeline
       transportation                 72,407      27,707                                                  100,114

      NGL product and
    services,
        terminalling,
    storage
        and hub services                                                   393,679                        393,679

      Gas Services                                          18,613                                         18,613

    Total revenue                     72,407      27,707    18,613         393,679                        512,406

      Operations                      22,177       7,753     5,193           2,474                         37,597

       Cost of goods
    sold, including
        product purchases                                                  364,356                        364,356

      Realized gain
    (loss) on
       commodity-related
       derivative
    financial instruments              (159)                                                                (159)

    Operating margin                  50,071      19,954    13,420          26,849                        110,294

      Depreciation and                10,356       2,037     2,512             888                         15,793
    amortization
    (operational)

      Unrealized gain
    (loss) on
       commodity-related
       derivative
    financial instruments                117                                 3,184                          3,301

    Gross profit                      39,832      17,917    10,908          29,145                         97,802

      Depreciation
    included in
       general and
    administrative                                                                                279         279

      Other general and                1,412         553       938           1,098              8,501      12,502
    administrative

      Acquisition-related              (497)       (107)       (1)             (9)               (48)       (662)
    and other

    Reportable segment
    results
     from operating
    activities                        38,917      17,471     9,971          28,056            (8,732)      85,683

    Net finance costs                  1,743         358       145              38             22,763      25,047

    Reportable segment
    earnings
     before tax and
    income from
     equity accounted
    investees                         37,174      17,113     9,826          28,018           (31,495)      60,636

    Share of loss
    (profit) of
    investments in equity
     accounted investees,
    net of tax                                                             (2,652)                        (2,652)

    Reportable segment               850,314     947,780   392,609      243,296(2)            621,671   3,055,670
    assets

    Capital expenditures              10,088      30,135    25,467          11,564                942      78,196

    Reportable segment               231,460      75,750    39,684           5,651          1,682,991   2,035,536
    liabilities

    (1)  10.3 percent of Conventional Pipelines revenue is under regulated
         tolling arrangements.

    (2)   Includes investments in equity accounted investees of $162,753.

                                                      Oil
    6 Months Ended June                           Sands &                                       Corporate &
    30, 2012                    Conventional        Heavy            Gas       Midstream       Intersegment
    ($ thousands)               Pipelines(1)          Oil       Services             (2)       Eliminations       Total

    Revenue:                                                                                                           

      Pipeline                       160,581       82,509                                           (6,875)     236,215
    transportation

      NGL product and
    services,
    terminalling, storage
       and hub services                                                        1,068,942                      1,068,942

      Gas Services                                                41,263                                         41,263

    Total revenue                    160,581       82,509         41,263       1,068,942            (6,875)   1,346,420

      Operations                      57,461       24,606         13,198          22,149            (1,260)     116,154

      Cost of goods sold,                                                        947,848            (6,875)     940,973
    including product
    purchases

      Realized gain
    (loss) on
    commodity-related
       derivative
    financial instruments            (1,189)                                    (11,507)                       (12,696)

    Operating margin                 101,931       57,903         28,065          87,438              1,260     276,597

      Depreciation and                24,124        9,829          7,494          32,735                         74,182
    amortization
    (operational)

      Unrealized gain
    (loss) on
    commodity-related
        derivative
    financial instruments            (2,752)                                      64,025                         61,273

    Gross profit                      75,055       48,074         20,571         118,728              1,260     263,688

      Depreciation
    included in
       general and
    administrative                                                                                    2,495       2,495

       Other general and               3,123        1,907          1,977           6,775             27,082      40,864
    administrative

      Acquisition-related                923          388             11              99             21,248      22,669
    and other

    Reportable segment
    results from
    operating
       activities                     71,009       45,779         18,583         111,854           (49,565)     197,660

      Net finance costs                3,364        1,040          2,134           4,170             35,546      46,254

    Reportable segment
    earnings before tax
     and income from
    equity
     accounted investees              67,645       44,739         16,449         107,684           (85,111)     151,406

    Share of loss
    (profit) of
    investments in equity
       accounted
    investees, net of tax                                                            398                            398

    Capital expenditures              64,472        6,041         55,762          55,930              4,083     186,288

    (1)  4.5 percent of Conventional Pipelines revenue is under regulated
         tolling arrangements.

         NGL product and services, terminalling, storage and hub services
    (2)  revenue includes $28.7 million associated with U.S. midstream
         sales.

                                                     Oil
    6 Months Ended June                          Sands &                                  Corporate &
    30, 2011                    Conventional       Heavy       Gas                       Intersegment
    ($ thousands)               Pipelines(1)         Oil Services        Midstream       Eliminations       Total

    Revenue:                                                                                                     

      Pipeline                       141,664      58,253                                                  199,917
    transportation

      NGL product and
    services,
    terminalling, storage
       and hub services                                                    673,790                        673,790

      Gas Services                                          33,587                                         33,587

    Total revenue                    141,664      58,253    33,587         673,790                        907,294

      Operations                      49,006      18,959     9,883           4,568                         82,416

       Cost of goods                                                       618,489                        618,489
    sold, including
    product purchases

      Realized gain
    (loss) on
    commodity-related
       derivative
    financial instruments              1,455                                 (204)                          1,251

    Operating margin                  94,113      39,294    23,704          50,529                        207,640

      Depreciation and                20,112       3,980     4,800           1,755                         30,647
    amortization
    (operational)

      Unrealized gain
    (loss) on
    commodity-related
       derivative
    financial instruments              4,652                               (1,054)                          3,598

    Gross profit                      78,653      35,314    18,904          47,720                        180,591

      Depreciation
    included in
       general and
    administrative                                                                                528         528

      Other general and                2,698       1,150     2,079           2,285             18,688      26,900
    administrative

      Acquisition-related              (455)       (107)         5               6               (31)       (582)
    and other

    Reportable segment
    results from
    operating
       activities                     76,410      34,271    16,820          45,429           (19,185)     153,745

    Net finance costs                  3,544         674       458              39             34,573      39,288

    Reportable segment
    earnings before tax
    and
       income from equity
    accounted investees               72,866      33,597    16,362          45,390           (53,758)     114,457

    Share of loss
    (profit) of
    investments in equity
       accounted
    investees, net of tax                                                  (4,842)                        (4,842)

    Capital expenditures              26,786     129,898    41,093         101,909              1,792     301,478

    (1)  11.5 percent of Conventional Pipelines revenue is under regulated
        tolling arrangements.

12. SHARE BASED PAYMENTS

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


    Grant date Restricted Share Units ("RSU")(3)           Contractual life
    to Officers,Non-Officers(2) and Directors                    of options

    (Number of units in thousands)                   Units

    January 1, 2012                                    188        3.0 Years

    April 2, 2012 (on acquisition)                     201        2.2 Years

    Grant date Performance Share Units ("PSU")(4)         Contractual life
    to Officers, Non-Officers(2) and Directors                  of options
    (Number of units in thousands)                  Units

    January 1, 2012                                   187        3.0 Years

    April 2, 2012 (on acquisition)                    177        2.2 Years

         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.

         One third vests on the first anniversary of the grant date, one
    (3)  third vests on the second anniversary of the grant date, and one
         third vests on the third anniversary of the grant date.

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

Disclosure of share option plan

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


                              Number of Options     Weighted Average
                                                      Exercise Price

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

    Granted                              74,100                29.52

    Exercised                         (175,203)                15.69

    Forfeited                          (80,493)                24.34

    Outstanding as at June            2,492,784                20.71
    30, 2012

13. FINANCIAL INSTRUMENTS

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


                                                  As at              As at
                                               June 30,       December 31,
    ($ thousands)                                  2012               2011

    Frac spread related                                                   

      Natural gas                              (17,235)                   

      Propane                                    11,482                   

      Butane                                      9,681                   

      Condensate                                  8,001                   

      Foreign exchange                          (1,149)                   

      Sub-total frac spread related              10,780                   

    Management of exposure embedded in              397              2,267
    physical contracts and other

    Corporate                                                             

      Power                                       1,593              4,183

      Interest rate                            (17,747)           (17,538)

    Other derivative financial
    instruments

      Conversion feature of convertible        (18,835)
    debentures

      Redemption liability related to           (6,407)
    acquisition of subsidiary

    Net derivative financial instruments       (30,219)           (11,088)
    liability

In conjunction with the Arrangement, the Company acquired a two-thirds
ownership interest in Provident’s subsidiary, Three Star Trucking Ltd.
(“Three Star”), which included a redemption liability that represents a
put option, held by the non-controlling interest of Three Star, to sell
the remaining one-third interest of the business to the Company after
the third anniversary of the original acquisition date by Provident
(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 period prior to exercise, adjusted for associated
capital expenditures and debt based on management estimates. On
acquisition, the Company recorded a $6.2 million redemption liability
associated with this put option. The redemption liability will be
accreted and subsequently fair valued at each reporting date with
changes in the value flowing through profit and loss. At June 30, 2012
the fair value of the redemption liability was determined to be $6.4
million, resulting in an unrealized loss of $0.2 million in the second
quarter of 2012 recorded in net finance costs.

Also in conjunction with the Arrangement, 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 $10.9 million on the revaluation on the
conversion feature of convertible debentures in profit and loss in the
second quarter of 2012 in net finance costs.

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


    As at June 30, 2012 ($                                + Change - Change
    thousands)

    Frac spread related                                                    

      Natural gas             (AECO +/- $1.00 per gj)       12,336 (12,336)

      NGLs (includes propane, (Belvieu +/- U.S. $0.10 per  (8,377)    8,377
    butane)                   gal)

      Foreign exchange (U.S.$ (FX rate +/- $0.05)          (6,868)    6,868
    vs. Cdn$)

    Management of exposure
    embedded in
    physical contracts

      Crude oil               (WTI +/- $5.00 per bbl)      (5,601)    5,601

      NGLs (includes propane, (Belvieu +/- U.S. $0.10 per    4,920  (4,920)
    butane and condensate)    gal)

    Corporate                                                              

      Interest rate           (Rate +/- 100 basis points)      946    (946)

      Power                   (AESO +/- $5.00 per MW/h)      3,217  (3,217)

    Conversion feature of     (Pembina share price +/-       2,101  (1,971)
    convertible debentures    $0.50 per share)

    Commodity-Related                  3 Months Ended                      6 Months Ended
    Derivative                            June 30                              June 30
    Financial
    Instruments

                                  2012               2011             2012               2011

    ($ thousands,               Volume
    except volumes)           $    (1)     $       Volume        $ Volume      $       Volume

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

    Frac spread
    related

      Crude oil         (1,997)    0.1                     (1,997)     0.1                   

      Natural gas       (7,762)    4.6                     (7,762)     4.6                   

      Propane             1,727    0.2                       1,727     0.2                   

      Butane                769    0.3                         769     0.3                   

      Condensate            272    0.2                         272     0.2                   

      Sub-total frac    (6,991)                            (6,991)
    spread related

    Corporate                                                                                

      Power             (1,608)        (159)               (1,764)         1,455             

    Management of
    exposure
     embedded in
    physical contracts
     and other          (3,870)    0.3                     (3,941)     0.5 (204)             

    Realized (loss)    (12,469)        (159)              (12,696)         1,251
    gain on derivative
    financial
    instruments

    Unrealized gain on
     commodity-related
    derivative
     financial
    instruments          64,820        3,301                61,273         3,598             

    Gain on
    commodity-related
     derivative
    financial
    instruments          52,351        3,142                48,577         4,849             

         The above table represents aggregate volumes that were bought/sold
    (1)  over the periods. Crude oil and NGL volumes are listed in millions
         of barrels and natural gas is listed in millions of gigajoules.

For non-commodity-related derivative financial instruments see Note 10,
Net Finance Costs.

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

 

 

 

 

 

 

 

 

 

SOURCE Pembina Pipeline Corporation


Source: PR Newswire