Pembina Pipeline Corporation announces third quarter 2012 results

PR Newswire

CALGARY, Nov. 6, 2012

Pembina continues to progress growth projects while maintaining steady
operating results

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 historic 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, Nov. 6, 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 nine month periods ending September
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 Arrangement, please refer to Note 3 of
the Interim Financial Statements for the period ended September 30,
2012.

Financial & Operating Overview
(unaudited)


($ millions, except where noted)	3 Months Ended September 30		9 Months Ended September 30
	2012	2011	2012	2011
Revenue	815.3	300.6	2,161.8	1,207.9
Operating margin⁽¹⁾	177.5	103.6	454.1	311.2
Gross profit	102.9	86.5	366.6	267.1
Earnings for the period	30.7	30.1	143.7	120.7
Earnings per share – basic and diluted (dollars)	0.11	0.18	0.58	0.72
Adjusted EBITDA⁽¹⁾	153.8	89.9	391.1	280.4
Cash flow from operating activities	130.9	87.7	220.3	211.7
Adjusted cash flow from operating activities⁽¹⁾	133.2	82.0	321.5	239.8
Adjusted cash flow from operating activities per share⁽¹⁾	0.46	0.49	1.30	1.43
Dividends declared	117.3	65.4	299.2	195.8
Dividends per common share (dollars)	0.405	0.390	1.200	1.170

⁽¹⁾	Refer to “Non-GAAP Measures.”

Third Quarter Highlights

Consolidated operating margin during the third quarter increased to
$177.5 million compared to $103.6 million during the same period of the
prior year. Year-to-date operating margin totalled $454.1 million
compared to $311.2 million during the first nine months 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 $49.4 million in operating margin from its
Conventional Pipelines business, $29.3 million from Oil Sands & Heavy
Oil and $16.6 million from Gas Services. The Midstream business saw a
significant increase to $81.6 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 continued soft propane pricing environment.
These softer prices are the result of high industry inventory levels
due to decreased propane demand, which was caused by the relatively
warm 2011/12 winter across North America and increasing supply.
The Company’s earnings were $30.7 million ($0.11 per share) during the
third quarter of 2012 compared to $30.1 million ($0.18 per share)
during the third quarter of 2011. Earnings were $143.7 million ($0.58
per share) during the first nine months of 2012 compared to $120.7
million ($0.72 per share) during the same period of the prior year.
Earnings for the three and nine month periods ended September 30, 2012
increased as a result of the Arrangement and were impacted by
unrealized gains (losses) on commodity-related derivative financial
instruments. However, earnings per share decreased primarily due to the
116.5 million shares issued as a result of the Arrangement (all per
share metrics discussed below were impacted by this factor).
Pembina generated adjusted EBITDA of $153.8 million during the third
quarter of 2012 compared to $89.9 million during the third quarter of
2011 (adjusted EBITDA is a non-GAAP measure; see “Non-GAAP Measures”).
Adjusted EBITDA for the nine month period ended September 30, 2012 was
$391.1 million compared to $280.4 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 completion of the
Arrangement.
Cash flow from operating activities was $130.9 million ($0.45 per share)
during the third quarter of 2012 compared to $87.7 million ($0.52 per
share) during the third quarter of 2011. For the nine months ended
September 30, 2012, cash flow from operating activities was $220.3
million ($0.89 per share) compared to $211.7 million ($1.27 per share)
during the same period last year. The increase is primarily due to
higher EBITDA, which was partially offset by acquisition-related
expenses, higher interest expenses and an increase in working capital
reflecting a seasonal inventory build of NGL products.
Adjusted cash flow from operating activities was $133.2 million ($0.46
per share) during the third quarter of 2012 compared to $82.0 million
($0.49 per share) during the third 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 $321.5
million ($1.30 per share) during the first nine months of 2012 compared
to $239.8 million ($1.43 per share) during the same period of last
year.

Growth and Operational Update

Pembina continues to make steady progress on its major growth projects,
as follows:

On October 22, 2012, Pembina closed the offering of $450 million of
senior unsecured medium-term notes. The notes have a fixed interest
rate of 3.77% per annum, paid semi-annually, and will mature on October
24, 2022. The net proceeds will be used to repay a portion of Pembina’s
existing credit facility, giving the Company increased flexibility to
pursue its capital plans;
Following an unplanned outage, the 205 MMcf/d Musreau deep cut was
placed back in service on September 2, 2012;
The 50 MMcf/d Musreau shallow cut expansion was placed into service on
September 13, 2012;
Construction has started on a joint venture full-service terminal in the
Judy Creek, Alberta area and has an estimated project completion date
of April 2013;
Pembina successfully completed and commissioned an 8,000 bpd expansion
at the Redwater fractionator, which required a 20-day turn-around of
the facility in September. The project was completed on schedule and
under budget;
Development of seven fee-for-service cavern storage facilities continued
at Pembina’s Redwater site, the first of which came into service
September 1, 2012;
Pembina received Board approval to proceed with two expansions of its
Conventional Pipeline systems (subject to reaching commercial
arrangements with its customers and receipt of regulatory approval) to
accommodate increased customer demand due to strong drilling results
and increased field liquids extraction by producers in areas of Alberta
including Dawson Creek, Grande Prairie, Kaybob and Fox Creek:

Pembina is pursuing the second phase of the Northern NGL System
expansion, which will increase capacity from 167,000 bpd to 220,000
bpd. Pembina expects this expansion to cost approximately $330 million
and to be complete in early to mid-2015;
Pembina is also pursuing an expansion of its Peace Pipeline crude oil
system, which will increase crude and condensate capacity from 195,000
bpd to 250,000 bpd. Pembina expects this expansion to cost
approximately $215 million and to be complete in mid- to late 2014; and
Pembina expects to spend an additional $125 million to tie-in area
producers to the expanded systems.

Pembina has received the required regulatory approvals and has awarded
construction contracts for the pipeline portions of the Resthaven and
Saturn projects. A significant portion of the major equipment for both
facilities has been ordered and Pembina has begun to receive major
equipment at each site. The Company expects to begin construction on
both projects during the fall and winter of 2012/2013;

Preliminary engineering work continued on the proposed new 70,000 bpd
ethane plus fractionator at Pembina’s Redwater facility and the Company
continues soliciting customer support for the project; and

Pembina is investigating offshore export opportunities for propane that
would allow it to leverage its existing assets and provide a solution
for Canadian producers.

“Pembina delivered steady operational and financial results this quarter
and we continued to make substantial progress on a number of capital
projects across our business,” said Bob Michaleski, Pembina’s Chief
Executive Officer. “Our integration with Provident is essentially
complete with only a few remaining items on the information systems
front, which we expect to wrap up by year-end. Moving forward, I’m
confident we have the financial resources, human capital, and strategic
focus to further our pursuit of fee-for-service opportunities, which we
expect will continue adding long-term shareholder value.”

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 on November 7, 2012 at 9 a.m. MT (11
a.m. ET) to discuss details related to the third 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=526791&s=1&k=34AC4F42C4AB2E0D2358DE14B1E8071E 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 November 6, 2012 and is
supplementary to, and should be read in conjunction with, Pembina’s
condensed consolidated unaudited interim financial statements for the
period ended September 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.”

On April 2, 2012 Pembina completed its acquisition of Provident Energy
Ltd. (“Provident”) (the “Arrangement”). The amounts disclosed herein
for the three and nine month periods ending September 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 of the Interim Financial Statements for the
period ended September 30, 2012.

About Pembina

Calgary-based Pembina Pipeline Corporation is a leading transportation
and midstream service provider that has been serving North America’s
energy industry for nearly 60 years. Pembina owns and operates:
pipelines that transport conventional and synthetic crude oil and
natural gas liquids produced in western Canada; oil sands 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 the
hydrocarbon value chain.

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

Strategy

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

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

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

Common Abbreviations

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

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

Financial & Operating Overview
(unaudited)


		3 Months Ended September 30		9 Months Ended September 30
($ millions, except where noted)		2012	2011	2012	2011
Average throughput – Conventional Pipelines (mbpd)		443.9	430.4	448.2	410.8
Contracted capacity – Oil Sands & Heavy Oil (mbpd)		870.0	775.0	870.0	775.0
Average processing volume – Gas Services (mboe/d) net to Pembina⁽¹⁾		45.8	41.3	45.8	39.7
NGL sales volume – NGL Midstream (mbpd)		86.7		88.6⁽³⁾
Revenue		815.3	300.6	2,161.7	1,207.9
Operations		69.5	54.4	185.6	136.8
Cost of goods sold, including product purchases		565.5	145.8	1,506.4	764.3
Realized gain (loss) on commodity-related derivative financial instruments		(2.8)	3.2	(15.6)	4.4
Operating margin⁽²⁾		177.5	103.6	454.1	311.2
Depreciation and amortization included in operations		51.6	17.8	125.8	48.4
Unrealized gain (loss) on commodity-related derivative financial instruments		(23.0)	0.7	38.3	4.3
Gross profit		102.9	86.5	366.6	267.1
Deduct/(add)
	General and administrative expenses	26.9	13.8	70.2	41.2
	Acquisition-related and other expense (income)	1.5	1.2	24.2	0.6
	Net finance costs	33.1	30.5	79.4	69.8
	Share of loss (profit) of investments in equity accounted investee, net of tax	0.6	0.6	0.9	(4.3)
Income tax expense		10.1	10.3	48.2	39.1
Earnings for the period		30.7	30.1	143.7	120.7
Earnings per share – basic and diluted (dollars)		0.11	0.18	0.58	0.72
Adjusted earnings⁽²⁾		65.4	47.0	167.9	165.2
Adjusted earnings per share⁽²⁾		0.23	0.28	0.68	0.99
Adjusted EBITDA⁽²⁾		153.8	89.9	391.1	280.4
Cash flow from operating activities		130.9	87.7	220.3	211.7
Cash flow from operating activities per share		0.45	0.52	0.89	1.27
Adjusted cash flow from operating activities⁽²⁾		133.2	82.0	321.5	239.8
Adjusted cash flow from operating activities per share⁽²⁾		0.46	0.49	1.30	1.43
Dividends declared		117.3	65.4	299.2	195.8
Dividends per common share (dollars)		0.405	0.390	1.200	1.170
Capital expenditures		143.4	77.2	329.7	378.7
Total enterprise value ($ billions) ⁽²⁾		10.6	5.9	10.6	5.9
Total assets ($ billions)		8.2	3.2	8.2	3.2

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

Revenue, net of cost of goods sold, increased to $249.8 million during
the third quarter of 2012 compared to $154.8 million in the third
quarter of 2011. Year-to-date revenue, net of cost of goods sold, in
2012 was $655.4 million compared to $443.6 million for 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 increased performance in each of
Pembina’s legacy businesses.

Operating expenses were $69.5 million during the third quarter of 2012
compared to $54.4 million in the third quarter of 2011. Operating
expenses for the nine months ended September 30, 2012 were $185.6
million compared to $136.8 million in the same period in 2011. The
increase in operating expenses for the third quarter and first nine
months 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 $177.5 million during the third quarter, up 71
percent from the same period last year (operating margin is a Non-GAAP
measure; see “Non-GAAP Measures”). For the nine months ended September
30, 2012 operating margin was $454.1 million compared to $311.2 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 loss on commodity-related derivative financial instruments
was $23.0 million for the three months ended September 30, 2012 and
$38.3 million for the first nine months of the year reflecting changes
in the future NGL and natural gas price indices between April 2, 2012
and September 30, 2012 (see “Business Environment”).

Depreciation and amortization (operational) increased to $51.6 million
during the third quarter of 2012 compared to $17.8 million during the
same period in 2011. For the nine months ended September 30, 2012,
depreciation and amortization (operational) increased to $125.8
million, up from $48.4 million for the same period last year. Both the
quarterly and year-to-date increases reflect depreciation on new
capital additions including those assets acquired through the
Arrangement.

The increases in revenue and operating margin contributed to gross
profit of $102.9 million during the third quarter and $366.6 million
for the first nine months of 2012 compared to $86.5 million and $267.1
million for the comparative periods of the prior year.

General and administrative expenses (“G&A”) of $26.9 million were
incurred during the third quarter of 2012 compared to $13.8 million
during the third quarter of 2011. G&A for the first nine months of 2012
was $70.2 million compared to $41.2 million for the same period of
2011. The increase in G&A for the three and nine month periods of 2012
compared to the prior year is mainly due to 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. In addition, every $1 change in share price is
expected to change Pembina’s annual share-based incentive expense by
$0.8 million.

Pembina generated adjusted EBITDA of $153.8 million during the third
quarter of 2012 compared to $89.9 million during the third quarter of
2011 (adjusted EBITDA is a Non-GAAP measure; see “Non-GAAP Measures”).
Adjusted EBITDA for the nine month period ended September 30, 2012 was
$391.1 million compared to $280.4 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 of Pembina’s
operations since completion of the Arrangement.

The Company’s earnings were $30.7 million ($0.11 per share) during the
third quarter of 2012 compared to $30.1 million ($0.18 per share)
during the third quarter of 2011. Earnings were $143.7 million ($0.58
per share) during the first nine months of 2012 compared to $120.7
million ($0.72 per share) during the same period of the prior year.
Earnings for the three and nine month periods ended September 30, 2012
increased as a result of the acquisition of Provident and were impacted
by the unrealized gain (loss) 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 (all per share
metrics discussed below were impacted by this factor).

Adjusted earnings were $65.4 million ($0.23 per share) during the third
quarter and $167.9 million ($0.68 per share) for the first nine months
of 2012 compared to $47.0 million ($0.28 per share) and $165.2 million
($0.99 per share) for the respective periods of 2011 (adjusted earnings
is a Non-GAAP measure; see “Non-GAAP Measures”). The quarterly and
year-to-date increase is primarily due to higher operating margin, as
discussed above, which was partially offset by increased depreciation
and amortization (operational).

Cash flow from operating activities was $130.9 million ($0.45 per share)
during the third quarter of 2012 compared to $87.7 million ($0.52 per
share) during the third quarter of 2011. For the nine months ended
September 30, 2012, cash flow from operating activities was $220.3
million ($0.89 per share) compared to $211.7 million ($1.27 per share)
during the same period last year. The increase in cash flow from
operating activities is primarily due to an increase in adjusted
EBITDA, which was partially offset by acquisition-related expenses,
higher interest expenses and an increase in working capital reflecting
a seasonal inventory build of NGL products.

Adjusted cash flow from operating activities was $133.2 million ($0.46
per share) during the third quarter of 2012 compared to $82.0 million
($0.49 per share) during the third 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 $321.5
million ($1.30 per share) during the first nine months of 2012 compared
to $239.8 million ($1.43 per share) during the same period of last
year.

Operating Results
(unaudited)


	3 Months Ended September 30				9 Months Ended September 30
	2012		2011		2012		2011
($ millions)	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾	Net Revenue⁽¹⁾	Operating Margin⁽²⁾
Conventional Pipelines	79.0	49.4	78.7	45.8	239.6	151.4	220.4	139.9
Oil Sands & Heavy Oil	44.1	29.3	37.0	24.3	126.6	87.2	95.2	63.6
Gas Services	23.7	16.6	18.8	12.4	65.0	44.6	52.4	36.1
Midstream	103.0	81.6	20.3	19.3	224.2⁽³⁾	169.0⁽³⁾	75.6	69.8
Corporate		0.6		1.8		1.9		1.8
Total	249.8	177.5	154.8	103.6	655.4	454.1	443.6	311.2

⁽¹⁾	Midstream revenue is net of $571.7 million in cost of goods sold, including product purchases, for the quarter ended September 30, 2012 (quarter ended September 30, 2011: $145.8 million) and $1,519.5 million cost of goods sold, including product purchases, for nine months ended September 30, 2012 (nine months ended September 30, 2011: $764.3 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 September 30		9 Months Ended September 30
($ millions, except where noted)	2012	2011	2012	2011
Average throughput (mbpd)	443.9	430.4	448.2	410.8
Revenue	79.0	78.7	239.6	220.4
Operations	30.1	34.6	87.5	83.6
Realized gain (loss) on commodity related derivative financial instruments	0.5	1.7	(0.7)	3.1
Operating margin⁽¹⁾	49.4	45.8	151.4	139.9
Depreciation and amortization included in operations	12.0	10.4	36.2	30.5
Unrealized gain (loss) on commodity-related derivative financial instruments	(7.1)		(9.8)	4.6
Gross profit	30.3	35.4	105.4	114.0
Capital expenditures	34.7	20.3	99.2	47.1

⁽¹⁾	Refer to “Non-GAAP Measures.”

Business Overview

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

Operational Performance: Throughput

During the third quarter of 2012, Conventional Pipelines’ throughput
averaged 443.9 mbpd, consisting of an average of 330.4 mbpd of crude
oil and condensate and 113.5 mbpd of NGL. This increase, which is
approximately three percent higher than the same period of 2011, when
average throughput was 430.4 mbpd, is primarily due to continued
production growth from regional resource plays in the Cardium (oil),
Deep Basin Cretaceous (NGL), Montney (oil/NGL) and Beaverhill Lake
(oil) formations. This producer production growth also contributed to a
nine percent increase in throughput for the first nine months of 2012
compared to the same period of 2011.

Financial Performance

During the third quarter of 2012, Conventional Pipelines generated
revenue of $79.0 million, virtually unchanged from the same quarter of
the previous year. For the first nine months of 2012, revenue was
$239.6 million compared to $220.4 million for the same period in 2011.
This nine percent increase is due to higher volumes generated by newly
connected facilities on Conventional Pipeline’s larger systems.

During the third quarter, operating expenses decreased to $30.1 million
compared to $34.6 million in the third quarter of 2011 due to the
timing of integrity related and geotechnical expenditures as well as
lower power costs. Operating expenses for the nine months ended
September 30, 2012 increased to $87.5 million from $83.6 million during
the same period of 2011. This five percent year-to-date increase
primarily resulted 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.

As a result of consistent revenue and lower operating expenses,
operating margin for the third quarter of 2012 was $49.4 million
compared to $45.8 million during the same period of 2011. On a
year-to-date basis, operating margin increased to $151.4 million due to
higher revenue, which was offset slightly by an increase in operating
expenses, as discussed above, compared with $139.9 million for the
first nine months of 2011.

Depreciation and amortization included in operations increased to $12.0
million during the third quarter of 2012 from $10.4 million during the
third quarter of 2011, reflecting capital additions in this business.
Depreciation and amortization included in operations for the nine
months ended September 30, 2012 was $36.2 million, up from $30.5
million in the first nine months of 2012.

For the three and nine months ended September 30, 2012, unrealized
losses on commodity-related derivative financial instruments were $7.1
million and $9.8 million compared to nil and a $4.6 million gain for
the same periods in 2011. The 2012 losses are largely a result of lower
power price indices over the term of the power purchase contracts.

For the three and nine months ended September 30, 2012, gross profit was
$30.3 million and $105.4 million, respectively, compared to gross
profit of $35.4 million and $114.0 million, respectively, during the
same periods in 2011. Higher operating margin was more than offset by
increased depreciation and amortization and unrealized losses on
commodity-related derivative financial instruments.

Capital expenditures for the third quarter of 2012 totalled $34.7
million compared to $20.3 million during the third quarter of 2011, and
were $99.2 million in the first nine months of the year compared to
$47.1 million 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 working to complete the first portion of its $100 million
Northern NGL expansion, which will add approximately 17 mbpd of
additional NGL capacity on Pembina’s Peace and Northern pipelines
(together the “Northern NGL System”). To complete this expansion,
Pembina plans to install a total of three pump stations, two of which
are expected to be in-service by the end of the year, and are expected
to provide about 10 mbpd of additional capacity. The third pump station
for the first portion of the expansion is expected to be in-service in
the first quarter of 2013. Pembina plans to bring an additional 35 mbpd
on stream by the fourth quarter of 2013, resulting in a total capacity
for the Northern NGL System of approximately 167 mbpd. Pembina has
reached long-term commercial agreements to underpin the Northern NGL
Expansion.

On November 6, 2012, Pembina received Board approval to proceed with two
new expansions of its Conventional Pipeline systems (subject to
reaching long-term commercial arrangements with its customers and
receipt of regulatory approval) to accommodate increased customer
demand due to strong drilling results and increased field liquids
extraction by area producers:

Pembina is pursuing the second phase of the Northern NGL System
expansion, which will increase capacity from 167 mbpd to 220 mbpd.
Pembina expects this expansion to cost approximately $330 million and
to be complete in early to mid-2015;
Pembina is also pursuing an expansion of its Peace Pipeline crude oil
system, which will increase crude and condensate capacity from 195 mbpd
to 250 mbpd. Pembina expects this expansion to cost approximately $215
million and to be complete in mid- to late 2014; and
Pembina expects to spend an additional $125 million to tie-in area
producers to the expanded systems.

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
Company’s Saturn and Resthaven gas plant projects. These two pipeline
projects will gather NGL from the gas plants for delivery to Pembina’s
Peace Pipeline system. Pembina has received the required regulatory
approvals, has awarded construction contracts and expects to begin
construction on both projects during the fall and winter of 2012/2013.

Oil Sands & Heavy Oil


	3 Months Ended September 30		9 Months Ended September 30
($ millions, except where noted)	2012	2011	2012	2011
Capacity under contract (mbpd)	870.0	775.0	870.0	775.0
Revenue	44.1	37.0	126.6	95.2
Operations	14.8	12.7	39.4	31.6
Operating margin⁽¹⁾	29.3	24.3	87.2	63.6
Depreciation and amortization included in operations	5.0	3.9	14.8	7.9
Gross profit	24.3	20.4	72.4	55.7
Capital expenditures	6.1	14.0	12.1	143.9

⁽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 has 870 mbpd of capacity under long-term, extendible
contracts which provide for the flow-through of operating expenses to
customers. As a result, operating margin from this business is
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 $44.1 million in
the third quarter of 2012 compared to $37.0 million in the third
quarter of 2011. This 19 percent increase is primarily due to
contributions from the Nipisi and Mitsue pipelines, which were placed
into service in June and July of 2011. For the same reason,
year-to-date revenue in 2012 was $126.6 million compared to $95.2
million for the same period in 2011.

Operating expenses in Pembina’s Oil Sands & Heavy Oil business were
$14.8 million during the third quarter of 2012 compared to $12.7
million during the third quarter of 2011. For the first nine months of
2012, operating expenses were $39.4 million compared to $31.6 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 nine months ended September 30, 2012, operating margin
increased to $29.3 million and $87.2 million compared to $24.3 million
and $63.6 million, respectively, during the same periods in 2011. This
is primarily due to the same factors that contributed to the increase
in revenue, as discussed above.

Depreciation and amortization included in operations for the third
quarter of 2012 totalled $5.0 million compared to $3.9 million during
the same period of the prior year, and $14.8 million for the first nine
months of 2012 compared to $7.9 million during the same period in 2011.
These increases primarily reflect the additional depreciation and
amortization included in operations related to the Nipisi and Mitsue
pipelines.

For the three and nine months ended September 30, 2012, gross profit was
$24.3 million and $72.4 million, primarily due to higher operating
margin as discussed above, compared to $20.4 million and $55.7 million,
respectively, during the same periods of 2011.

For the nine months ended September 30, 2012, capital expenditures
within the Oil Sands & Heavy Oil business totalled $12.1 million and
were primarily related to Nipisi and Mitsue post-construction clean-up
costs. This compares to $143.9 million spent during the same period in
2011, the majority of which related to completing the Nipisi and Mitsue
pipeline projects.

Gas Services


	3 Months Ended September 30		9 Months Ended September 30
($ millions, except where noted)	2012	2011	2012	2011
Average processing volume (MMcf/d) net to Pembina	275.0	247.6	275.0	237.9
Average processing volume (mboe/d) ⁽¹⁾ net to Pembina	45.8	41.3	45.8	39.7
Revenue	23.7	18.8	65.0	52.4
Operations	7.1	6.4	20.4	16.3
Operating margin⁽²⁾	16.6	12.4	44.6	36.1
Depreciation and amortization included in operations	3.3	2.5	10.8	7.3
Gross profit	13.3	9.9	33.8	28.8
Capital expenditures	29.8	29.0	85.6	70.1

⁽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 410 MMcf/d of processing capacity (355 MMcf/d net to
Pembina), a 205 MMcf/d ethane plus extraction facility, as well as
approximately 350 km of gathering pipelines. The Cutbank Complex is
connected to Pembina’s Peace Pipeline system and serves an active
exploration and production area in the WCSB. Pembina has initiated
construction on two projects in its Gas Services business, the Saturn
and Resthaven enhanced NGL extraction facilities, to meet the growing
needs of producers in west central Alberta.

Financial Performance

Gas Services recorded an increase in revenue of approximately 26 percent
during the third quarter of 2012, contributing $23.7 million compared
to $18.8 million in the third quarter of 2011. In the first nine months
of the year, revenue was $65.0 million compared to $52.4 million in the
same period of 2011. These increases primarily reflect higher
processing volumes at Pembina’s Cutbank Complex. Average processing
volumes, net to Pembina, were 275.0 MMcf/d during the third quarter of
2012, approximately 11 percent higher than the 247.6 MMcf/d processed
during the third quarter of the previous year.

During the third quarter of 2012, operating expenses were $7.1 million
compared to $6.4 million incurred in the third quarter of 2011.
Year-to-date operating expenses totalled $20.4 million, up from $16.3
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 strong operating margin of $16.6 million in the third
quarter and $44.6 million in the first nine months of 2012 compared to
$12.4 million and $36.1 million during the same periods of the prior
year.

Depreciation and amortization included in operations during the third
quarter of 2012 totalled $3.3 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 and shallow cut expansion). For the same
reason, year-to-date depreciation and amortization included in
operations totalled $10.8 million compared to $7.3 million during the
first nine months of 2011.

For the three months ended September 30, 2012, gross profit was $13.3
million compared to $9.9 million in the same period of 2011. On a
year-to-date basis, gross profit was $33.8 million compared to $28.8
million during the first nine months of 2011. These increases reflect
higher operating margin during the periods, as discussed above.

For the nine months ended September 30, 2012, capital expenditures
within Gas Services totalled $85.6 million compared to $70.1 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 expansions
detailed below to bring the Company’s gas processing capacity to 890
MMcf/d (net). This includes enhanced NGL extraction capacity of
approximately 535 MMcf/d (net), of which 205 MMcf/d is currently in
service. These volumes would be processed largely on a contracted,
fee-for-service basis and are expected to result in approximately 45
mbpd of incremental NGL to be transported for additional toll revenue
on Pembina’s conventional pipelines by early 2014.

Musreau Deep Cut Facility

The Musreau Deep Cut Facility experienced an unplanned outage in March
and was placed back in service on September 2, 2012. Pembina does not
recognize an increase in gas processing volumes resulting from the deep
cut being in service because those same volumes are first processed
through the shallow cut facilities of the Cutbank Complex.

Expansion at the Cutbank Complex: Musreau Shallow Cut Expansion

The 50 MMcf/d shallow cut gas processing expansion at Pembina’s Musreau
plant was completed in August 2012 and placed into service on September
13, 2012. The Cutbank Complex now has 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.

Saturn and Resthaven Facilities

Site construction on both the Saturn and Resthaven facilities is
underway and the anticipated in-service dates for the projects are the
fourth quarter of 2013 and first quarter of 2014, respectively. A
significant portion of the major equipment has been ordered and Pembina
has begun to receive major equipment on site. Once complete, these
facilities are expected to add an additional 330 MMcf/d (net) of
enhanced liquids extraction capability and approximately 25 mbpd of NGL
volumes to Pembina’s conventional pipeline systems.

Midstream⁽¹⁾


	3 Months Ended September 30		9 Months Ended September 30⁽²⁾
($ millions, except where noted)	2012	2011	2012	2011
Revenue	674.7	166.2	1,743.7	840.0
Operations	18.0	2.5	40.3	7.1
Cost of goods sold, including product purchases	571.7	145.9	1,519.5	764.4
Realized gain (loss) on commodity related derivative financial instruments	(3.4)	1.5	(14.9)	1.3
Operating margin⁽³⁾	81.6	19.3	169.0	69.8
Depreciation and amortization included in operations	31.3	0.9	64.0	2.7
Unrealized gains (losses) on commodity-related derivative financial instruments	(15.9)	0.7	48.1	(0.3)
Gross profit	34.4	19.1	153.1	66.8
Capital expenditures	70.7	5.0	126.6	106.9

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

Business Overview

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

Crude oil midstream, 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
NGL midstream, which Pembina acquired through the Arrangement, includes two operating
systems, Redwater West and Empress East:

The Redwater West NGL system includes the Younger extraction and
fractionation facility in B.C.; the recently expanded 73,000 bpd
Redwater NGL fractionator, 6.8 mmbbls of cavern storage and
terminalling facilities at Redwater, Alberta; and, third party
fractionation capacity in Fort Saskatchewan, Alberta.
The Empress East NGL system includes a 2.1 bcf/d interest in the
straddle plants at Empress, Alberta; 20,000 bpd of fractionation
capacity as well as 1.1 mmbbls of cavern storage in Sarnia, Ontario;
and, approximately 5.0 mmbbls of hydrocarbon storage at Corunna,
Ontario.

Financial Performance

In the Midstream business, revenue, net of cost of goods sold, grew to
$103.0 million during the third quarter of 2012 from $20.3 million
during the third quarter of 2011. Year-to-date revenue, net of cost of
goods sold, was $224.2 million in 2012 compared to $75.6 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 third quarter of 2012 were $18.0 million
compared to $2.5 million in the third quarter of 2011. Operating
expenses for the first nine months of the year were $40.3 million in
2012 and $7.1 million in the same period of 2011. Operating expenses
for the quarter and first nine months of the year were higher due to
the increase in Midstream’s asset base since the Arrangement.

Operating margin was $81.6 million during the third quarter of 2012
compared to $19.3 million during the third quarter of 2011. Operating
margin for the first nine months of 2012 was $169.0 million compared to
$69.8 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 third
quarter of 2012 totalled $31.3 million compared to $0.9 million during
the same period of the prior year. Year-to-date depreciation and
amortization included in operations totalled $64.0 million compared to
$2.7 million during the first nine months of 2011. Both increases
reflect the additional assets in Midstream since the closing of the
Arrangement.

For the three months ended September 30, 2012, unrealized losses on
commodity-related derivative financial instruments were $15.9 million.
Year-to-date was a gain of $48.1 million. These amounts reflect
fluctuations in the future NGL and natural gas prices indices during
the periods.

For the three and nine months ended September 30, 2012, gross profit in
this business increased to $34.4 million and $153.1 million from $19.1
million and $66.8 million during the same periods in 2011. This is due
to the addition of assets acquired through the Arrangement, higher
operating margin and the impact of unrealized gains (losses) on
commodity-related derivative financial instruments.

For the nine months ended September 30, 2012, capital expenditures
within the Midstream business totalled $126.6 million and were
primarily related to cavern development and related infrastructure as
well as fractionation capacity expansion at the Redwater Facility by
approximately 8,000 bpd. This compares to capital expenditures of
$106.9 million during the same period of 2011 which included the
acquisition of a terminalling and storage facility near Edmonton,
Alberta and the acquisition of linefill for the Peace Pipeline.

Operating Margin

Crude Oil Midstream

Operating margin for the Company’s crude oil midstream activities during
the third quarter of 2012 was $27.2 million compared to $19.3 million
during the third quarter of 2011. Year-to-date operating margin was
$87.4 million, representing an increase of 25 percent from $69.8
million in the same period last year. Strong third 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 the Pembina
Nexus Terminal (“PNT”) added in the first quarter of 2012.

NGL Midstream

Operating margin for Pembina’s NGL midstream activities was $54.4
million for the third quarter and $81.6 million year-to-date since
closing of the Arrangement, including a $15.0 million year-to-date
realized loss on commodity-related derivative financial instruments
(see “Market Risk Management Program”).

NGL sales volumes during the third quarter of 2012 were 86.7 mbpd and
88.6 mbpd since the closing of the Arrangement.

Redwater West

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

Operating margin during the third quarter of 2012, excluding realized
losses from commodity-related derivative financial instruments, was
$46.6 million. Year-to-date since closing of the Arrangement, operating
margin, excluding realized losses from commodity-related derivative
financial instruments, was $82.8 million. Realized propane margin
results were impacted by weak 2012 market prices and decreased gas
volumes at the Younger plant during the two periods. Conversely, third
quarter western butane and condensate market prices and resulting
margins were higher driven by strong Alberta demand. Overall, Redwater
West NGL sales volumes averaged 52.5 mbpd since closing of the
Arrangement.

Empress East

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

Operating margin during the third quarter of 2012, excluding realized
losses from commodity-related derivative financial instruments, was
$11.6 million. Year-to-date since closing of the Arrangement, operating
margin, excluding realized losses from commodity-related derivative
financial instruments, was $13.8 million. Results were impacted by low
sales volumes, soft 2012 propane prices and high extraction premiums,
but were offset by strong refinery demand for butane and low AECO
natural gas prices during the two periods. Overall, Empress East NGL
sales volumes averaged 36.1 mbpd since closing of the Arrangement.

New Developments: Midstream

The capital being deployed in the Midstream business is primarily
directed towards fee-for-service projects which will continue to
increase its stability and predictability.

During the third quarter, Pembina began construction on a joint venture
full-service terminal in the Judy Creek, Alberta, area which has an
estimated project completion date of April 2013. Full-service terminals
focus on emulsion treating (separating oil from impurities to meet
shipping quality requirements), produced water handling and water
disposal.

Also during the third quarter, Pembina successfully completed and
commissioned the approximately 8,000 bpd expansion at the Redwater
fractionator. The expansion required a 20-day turn-around of the
facility in September and the project was completed on schedule and
under budget.

Further, development of seven fee-for-service cavern storage facilities
continued at Pembina’s Redwater site, the first of which came into
service September 1, 2012.

Market Risk Management Program

Pembina is exposed to frac spread risk which is the difference between
the selling prices for propane-plus liquids and the input cost of
natural gas required to produce respective NGL products. Pembina has a
risk management program and uses derivative financial instruments to
mitigate frac spread risk when possible to safeguard a base level of
operating cash flow in order to cover the input cost of such natural
gas. Pembina has entered into derivative financial swap contracts 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
mitigate 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.

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

Activity in the third quarter⁽¹⁾


Year	Commodity	Description	Volume (Buy)/Sell		Effective Period
2012	Crude Oil	U.S. $90.39 per bbl⁽²⁾⁽⁴⁾	2,120	bpd	October 1 – December 31
2012	Condensate	U.S. $1.93 per gallon⁽³⁾⁽⁴⁾	(2,120)	bpd	October 1 – December 31
2013	Crude Oil	U.S. $91.28 per bbl⁽²⁾⁽⁴⁾	2,753	bpd	January 1 – December 31
2013	Condensate	U.S. $1.94 per gallon⁽³⁾⁽⁴⁾	(2,753)	bpd	January 1 – December 31
2014	Power	Cdn $50.75 per MW/h⁽⁵⁾	(5)	MW/h	January 1 – December 31
2015	Power	Cdn $49.00 per MW/h⁽⁵⁾	(5)	MW/h	January 1 – December 31
2016	Power	Cdn $50.00 per MW/h⁽⁵⁾	(10)	MW/h	January 1 – December 31

⁽¹⁾	This table represents the transactions entered into during the third quarter of 2012.
⁽²⁾	Crude oil contracts are settled against NYMEX WTI calendar average.
⁽³⁾	Condensate contracts are settled against Belvieu NON-TET natural gasoline.
⁽⁴⁾	Management of physical contract exposure – rail contracts.
⁽⁵⁾	Power contracts are settled against the hourly price of power as published by the AESO in $/MWh.

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


		3 Months Ended September 30		9 Months Ended September 30
($ thousands)		2012	2011	2012	2011
Realized (loss) gain on commodity-related derivative financial instruments
Frac spread related
	Crude oil	(173)		(2,170)
	Natural gas	(7,922)		(15,684)
	Propane	2,253		3,980
	Butane	1,448		2,217
	Condensate	1,205		1,477
	Sub-total frac spread related	(3,189)		(10,180)
Corporate
	Power	755	1,712	(1,009)	3,167
Management of exposure embedded in physical contracts and other		(425)	1,496	(4,366)	1,292
Realized (loss) gain on commodity-related derivative financial instruments		(2,859)	3,208	(15,555)	4,459

The realized loss on commodity-related derivative financial instruments
for the third quarter of 2012 was $2.9 million compared to a realized
gain of $3.2 million in the comparable period in 2011. The majority of
the realized loss in the third 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,
partially offset by NGL derivative sales contracts settling at a
contracted price higher than the current NGL market prices during the
settlement period.

Business Environment


	3 Months Ended September 30			9 Months Ended September 30
	2012	2011	% Change	2012	2011	% Change
WTI crude oil (U.S. $ per barrel)	92.22	89.76	3	96.21	95.48	1
Exchange rate (from U.S.$ to Cdn$)	1.00	0.98	2	1.00	0.98	2
WTI crude oil (expressed in Cdn$ per barrel)	91.69	87.99	4	96.35	93.37	3

AECO natural gas monthly index (Cdn$ per GJ)	2.08	3.53	(41)	2.07	3.55	(42)

Mont Belvieu Propane (U.S.$ per U.S. gallon)	0.89	1.54	(42)	1.04	1.48	(30)
Mont Belvieu Propane expressed as a percentage of WTI	41%	72%	(43)	45%	65%	(31)

Market Frac Spread in Cdn$ per barrel⁽¹⁾	39.51	56.09	(30)	46.75	53.42	(13)

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

The third quarter of 2012 saw a six percent increase in the S&P TSX
Composite Index from the previous quarter, with the value of the Index
also having increased six percent since the same time a year ago. The
Canadian dollar strengthened against the U.S. dollar during most of the
third quarter, averaging $0.995 per U.S. dollar, due in part to an
increase in commodity prices; however, it was weaker than an average
value of $0.979 per U.S. dollar over the same period in the previous
year.

The benchmark WTI oil price recovered through July and August after
setting year-to-date lows in late June and realized gains through the
latter half of September, averaging and exiting the third quarter at
U.S. $92.00/bbl. The Canadian heavy crude oil benchmark, Western
Canadian Select, continued to trade at relatively wide differentials to
WTI throughout the third quarter due to an ongoing tight supply-demand
balance. Natural gas prices remained range-bound through the third
quarter of 2012. The closing second quarter AECO price was $2.13 per
GJ, which decreased four percent during the third quarter to exit at
$2.05 per GJ (the average price during the period was $2.08 per GJ).
While low natural gas prices are generally favourable for NGL
extraction and fractionation economics, a sustained low gas price
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.

The NGL pricing environment in the third quarter of 2012 recovered from
lows set in June and July, but continued to be negatively impacted by a
warm 2011/2012 winter and increasing production which resulted in a
supply-demand imbalance in North America. In the U.S., industry
propane/propylene inventories were approximately 76 million barrels at
the end of the third quarter of 2012 (approximately 13 million barrels
or 22 percent above the five-year historical average for this period).
In Canada, industry propane inventories increased to 13.6 million
barrels at the end of the third quarter of 2012 (1.3 million barrels,
or 11 percent higher, than the historic five-year average). This
over-supply continues to generate reduced prices, where the Mont
Belvieu propane price averaged U.S. $0.89 per U.S. gallon (41 percent
of WTI) in the third quarter of 2012, significantly below its five-year
average of 60 percent of WTI. Butane and condensate sales prices
recovered from lows through the quarter but were generally lower in the
third quarter of 2012 compared to prior years. Market frac spreads
averaged $39.51 per barrel during the third quarter of 2012 compared to
$45.70 per barrel in the second quarter of 2012 and $56.09 per barrel
in the third quarter of 2011. Compared to the second quarter of 2012,
lower frac spreads resulted from lower NGL sales prices. The market
frac spread does not include extraction premiums,
operating/transportation/storage costs and regional sales prices.

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

Non-Operating Expenses

G&A

Pembina incurred G&A of $26.9 million during the third quarter of 2012
compared to $13.8 million during the third quarter of 2011. G&A for the
first nine months of 2012 was $70.2 million compared to $41.2 million
for the same period of 2011. The increase in G&A for the three and nine
month periods of 2012 compared to the prior year is mainly due to 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. In addition, every $1
change in share price is expected to change Pembina’s annual
share-based incentive expense by $0.8 million.

Depreciation & Amortization (Operational)

Depreciation and amortization (operational) increased to $51.6 million
during the third quarter of 2012 compared to $17.8 million during the
same period in 2011. For the nine months ended September 30, 2012,
depreciation and amortization (operational) was $125.8 million, up from
$48.4 million for the same period last year. Both 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 third quarter were
$1.5 million. For the nine months ended September 30, 2012,
acquisition-related and other expenses were $24.2 million which
includes acquisition expenses of $14.9 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 third quarter of 2012 were $33.1 million
compared to $30.5 million in the third quarter of 2011. Year-to-date
net finance costs in 2012 totalled $79.4 million compared to $69.8
million in the same period of 2011. The increases primarily relate to
an $11.9 million year-to-date increase in loans and borrowings interest
expense ($3.2 million for the third quarter of 2012) due to higher debt
balances and a quarterly and year-to-date increase in interest on
convertible debentures totalling $5.9 million and $11.9 million,
respectively, due to the Provident debentures assumed on closing of the
Arrangement. These factors were offset by a $12.4 million increase in
the change in the fair value of non-commodity-related derivative
financial instruments for the first nine months of the year when
compared to the same period in 2011 and a $4.2 million unrealized gain
in 2012 on the conversion feature of the convertible debentures ($6.7
million loss for the third quarter of 2012). See Notes 10 and 13 to the
Interim Financial Statements for the period ended September 30, 2012.
Beginning in the second quarter of 2012, the change in fair value of
commodity-related derivative financial instruments has been
reclassified from net finance costs to gain/loss 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 $10.2 million was recorded in the third quarter of 2012
compared to $10.3 million in the third quarter of 2011. Year-to-date
income tax expense in 2012 totalled $48.2 million compared to $39.1
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)		September 30, 2012	December 31, 2011
Working capital		101.7	(343.7)⁽¹⁾
Variable rate debt⁽²⁾
	Bank debt	865.0	313.8
	Variable rate debt swapped to fixed	(380.0)	(200.0)
Total variable rate debt outstanding (average rate of 2.85%)		485.0	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	9.2
	Variable rate debt swapped to fixed	380.0	200.0
Total fixed rate debt outstanding (average of 5.27%)		1,356.2	1,225.0
Convertible debentures⁽²⁾		644.3	299.8
Finance lease liability		5.6	5.6
Total debt and debentures outstanding		2,491.1	1,644.2
Cash and unutilized debt facilities		688.8	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 totalling $688.8 million as at September 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 dividend
record date to help fund its ongoing capital program (see “Trading
Activity and Total Enterprise Value” for further details). Management
remains satisfied that the leverage employed in Pembina’s capital
structure is sufficient and appropriate given the characteristics and
operations of the underlying asset base.

Management may make adjustments to Pembina’s capital structure as a
result of changes in economic conditions or the risk characteristics of
the underlying assets. To maintain or modify Pembina’s capital
structure in the future, Pembina may renegotiate new debt terms, repay
existing debt 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 renegotiated its operating facility
to $30 million from $50 million.

Pembina’s credit facilities at September 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
credit facilities are based on the credit rating of Pembina’s senior
unsecured debt. There are no repayments due over the term of these
facilities. As at September 30, 2012, Pembina had $865 million drawn on
bank debt, $1.6 million in letters of credit and $25.4 million in cash,
leaving $688.8 million of unutilized debt facilities on the $1,530
million of established bank facilities. In addition, as at September
30, 2012, Pembina had $14.1 million in letters of credit issued in a
separate demand letter of credit facility. Other debt includes $75
million in senior unsecured term debt due 2014; $175 million in senior
unsecured notes due 2014; $267 million in senior unsecured notes due
2019; $200 million in senior unsecured notes due 2021; 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 September 30, 2012, Pembina had loans and borrowing (excluding
amortization, letters of credit and finance lease liabilities) of
$1,841.2 million. Pembina’s senior debt to total capital at September
30, 2012 was 27 percent.

Offering of Medium-Term Notes

On October 22, 2012, Pembina closed the offering of $450 million
principal amount of senior unsecured medium-term notes (“Notes”). The
Notes have a fixed interest rate of 3.77% per annum, paid
semi-annually, and will mature on October 24, 2022. The net proceeds
from the offering of the Notes were used to repay a portion of
Pembina’s existing credit facility. Standard & Poor’s Rating Services
(“S&P”) and DBRS Limited (“DBRS”) have assigned credit ratings of BBB
to the Notes. The Notes were offered through a syndicate of agents
under Pembina’s short form base prospectus dated November 2, 2010, a
related prospectus supplement dated March 16, 2011 and a related
pricing supplement dated October 17, 2012.

Credit Ratings

Pembina considers the maintenance of an investment grade credit rating
important to its ongoing ability to access capital markets on
attractive terms. DBRS rates Pembina’s senior unsecured notes ‘BBB’.
S&P’s long-term corporate credit rating on Pembina is ‘BBB’. 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 judgement, 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 September 30, 2012, $344.6 million of the
debentures are still outstanding.

Capital Expenditures


		3 Months Ended September 30		9 Months Ended September 30
($ millions)		2012	2011	2012	2011
Development capital
	Conventional Pipelines	34.7	20.3	99.2	47.1
	Oil Sands & Heavy Oil	6.1	14.0	12.1	143.9
	Gas Services	29.8	29.0	85.6	70.1
	Midstream	70.7	5.0	126.6	106.9
Corporate/other projects		2.0	8.9	6.1	10.7
Total development capital		143.3	77.2	329.6	378.7

During the first nine months of 2012, capital expenditures were $329.6
million compared to $378.7 million during the same nine month period in
2011. In the comparable period in 2011, the Company’s capital
expenditures included the construction of the Nipisi and Mitsue
pipelines, the acquisition of midstream assets in the Edmonton, Alberta
area (related to PNT) and linefill for the Peace Pipeline system.

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

Contractual Obligations at September 30, 2012


($ thousands)	Payments Due By Period
Contractual Obligations	Total	Less than 1 year	1 – 3 years	4 – 5 years	After 5 years
Office and vehicle leases	294,058	23,291	52,800	57,550	160,417
Loans and borrowings⁽¹⁾	2,183,789	63,537	377,996	943,330	798,926
Convertible debentures⁽¹⁾	913,273	39,183	118,453	243,311	512,326
Construction commitments	496,960	425,973	70,987
Provisions⁽²⁾	485,857	2,445			483,412
Total contractual obligations	4,373,937	554,429	620,236	1,244,191	1,955,081

⁽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 Saturn Facility and the Resthaven
Facility, and to the remaining capital expenditures associated with the
Nipisi and Mitsue pipelines. See “Forward-Looking Statements &
Information.”

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

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.
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. Actual results may differ from these judgments, estimates and
underlying assumptions. The Interim Financial Statements were prepared
with the same critical accounting estimates as disclosed in Pembina’s
consolidated audited annual financial statements and MD&A for the year
ended December 31, 2011 in addition to the following:

Business Combinations

Business combinations are accounted for using the acquisition method of
accounting. The determination of fair value often requires Management
to make assumptions and estimates about future events. The assumptions
and estimates with respect to determining the fair value of property,
plant and equipment and intangible assets acquired generally require
the most judgment and include estimates of cash flows, forecast
benchmark commodity prices, and discount rates. Changes in any of the
assumptions or estimates used in determining the fair value of acquired
assets and liabilities could impact the amounts assigned to assets,
liabilities, intangibles and goodwill in the purchase price analysis.
Future net earnings can be affected as a result of changes in future
depreciation and amortization, asset or goodwill impairment.

Derivative Financial Instruments

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

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 third 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 Interim Financial Statements for the quarter ended September
30, 2012 was approximately 38 percent of consolidated net revenue and
approximately six percent of consolidated pre-tax earnings.

Additionally, Provident’s current assets and current liabilities were
approximately 64 percent and 53 percent of consolidated current assets
and liabilities, respectively, and its non-current assets and
non-current liabilities were approximately 58 percent and 34 percent of
consolidated non-current assets and non-current liabilities,
respectively.

The scope limitation is primarily based on the time required to assess
Provident’s 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 Note 3 in
the Notes to the Company’s Interim Financial Statements for the third
quarter of 2012.

Trading Activity and Total Enterprise Value⁽¹⁾


			As at and for the 3 months ended
($ millions, except where noted)		November 2, 2012⁽²⁾	September 30, 2012	September 30, 2011
Trading volume and value
	Total volume (shares)	10,113,704	32,503,841	14,789,753
	Average daily volume (shares)	421,404	524,256	234,758
	Value traded	280.4	876.4	371.8
Shares outstanding (shares)		290,430,401	290,506,020	167,661,608
Closing share price (dollars)		27.99	27.60	25.65
Market value
	Shares	8,157.1	8,018.0	4,300.5
	5.75% convertible debentures (PPL.DB.C)	333.3⁽³⁾	329.0⁽⁴⁾	308.9
	5.75% convertible debentures (PPL.DB.E)	198.0⁽⁵⁾	202.2⁽⁶⁾
	5.75% convertible debentures (PPL.DB.F)	189.4⁽⁷⁾	190.3⁽⁸⁾
Market capitalization		8,877.8	8,739.5	4,609.4
Senior debt		1,907.0	1,832.0	1,251.7
Total enterprise value⁽⁹⁾		10,784.8	10,571.5	5,861.1

⁽¹⁾	Trading information in this table reflects the activity of Pembina securities on the TSX.
⁽²⁾	Based on 24 trading days from October 1, 2012 to November 2, 2012, inclusive.
⁽³⁾	$299.7 million principal amount outstanding at a market price of $111.20 at November 2, 2012 and with a conversion price of $28.55 .
⁽⁴⁾	$299.7 million principal amount outstanding at a market price of $109.76 at September 30, 2012 and with a conversion price of $28.55.
⁽⁵⁾	$172.2 million principal amount outstanding at a market price of $115.01 at November 2, 2012 and with a conversion price of $24.94.
⁽⁶⁾	$172.2 million principal amount outstanding at a market price of $117.48 at September 30, 2012 and with a conversion price of $24.94.
⁽⁷⁾	$172.4 million principal amount outstanding at a market price of $109.81 at November 2, 2012 and with a conversion price of $29.53.
⁽⁸⁾	$172.4 million principal amount outstanding at a market price of $110.37 at September 30, 2012 and with a conversion price of $29.53.
⁽⁹⁾	Refer to “Non-GAAP Measures.”

As indicated in the previous table, Pembina’s total enterprise value was
$10.6 billion at September 30, 2012 and issued and outstanding shares
of Pembina rose to 290.5 million at the end of the third quarter 2012
primarily due to shares issued under the Arrangement, compared to 167.7
million at the end of the same period in 2011.

Dividends

On April 12, 2012, following closing of the Arrangement, Pembina
announced an increase in 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™”) equal to 102 percent of the
amount of reinvested dividends, pursuant to the “Premium Dividend™
Component” of the DRIP. Additional information about the terms and
conditions of the DRIP can be found at www.pembina.com.

Participation in the DRIP for the third quarter was 56 percent of common
shares outstanding for proceeds of approximately $66.3 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 (the successor to
Provident following the completion of the Arrangement) company profile
on www.sedar.com or on Provident’s profile at www.sec.gov.

Selected Quarterly Operating Information


	2012			2011				2010
	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Average volume (mbpd)
Conventional Throughput	443.9	433.9	466.9	422.8	430.4	411.4	390.3	375.0	361.4
Oil Sands & Heavy Oil⁽¹⁾	870.0	870.0	870.0	870.0	775.0	775.0	775.0	775.0	775.0
Gas Services Processing (mboe/d)⁽²⁾	45.8	47.5	44.1	45.3	41.3	40.9	39.4	42.1	38.9
NGL sales volume (mboe/d)	86.7	90.4

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

Selected Quarterly Financial Information


		2012			2011				2010
($ millions, except where noted)		Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Revenue		815.3	870.9	475.5	468.1	300.6	512.4	394.9	290.7	266.1
Operations		69.5	67.7	48.4	55.1	54.4	37.6	44.8	41.9	40.0
Cost of goods sold including product purchases		565.5	641.9	299.1	308.0	145.8	364.3	254.2	161.8	148.2
Realized gain (loss) on commodity related derivative financial instruments		(2.8)	(12.4)	(0.3)	0.8	3.2	(0.2)	1.4	(0.8)	0.3
Operating margin⁽¹⁾		177.5	148.9	127.7	105.8	103.6	110.3	97.3	86.2	78.2
Depreciation and amortization included in operations		51.6	52.5	21.7	19.5	17.8	15.8	14.8	15.6	15.3
Unrealized gain (loss) on commodity-related derivative financial instruments		(23.0)	64.8	(3.5)	0.9	0.7	3.3	0.3	1.8	(3.2)
Gross profit		102.9	161.2	102.5	87.2	86.5	97.8	82.8	72.4	59.7
Adjusted EBITDA⁽¹⁾		153.8	125.9	111.4	88.2	89.9	103.3	87.2	79.1	68.1
Cash flow from operating activities		130.9	24.1	65.3	74.3	87.7	49.5	74.5	54.6	66.6
Cash flow from operating activities per common share ($ per share)		0.45	0.08	0.39	0.44	0.52	0.30	0.45	0.33	0.41
Adjusted cash flow from operating activities⁽¹⁾		133.2	89.5	98.8	57.3	82.0	81.8	76.0	62.6	67.6
Adjusted cash flow from operating activities per common share⁽¹⁾($ per share)		0.46	0.31	0.59	0.34	0.49	0.49	0.45	0.39	0.41
Earnings for the period		30.7	80.4	32.6	45.1	30.1	48.0	42.5	55.2	28.6
Earnings per common share ($ per share)
	Basic	0.11	0.28	0.19	0.27	0.18	0.29	0.25	0.34	0.19
	Diluted	0.11	0.28	0.19	0.27	0.18	0.29	0.25	0.33	0.19
Common shares outstanding (millions):
	Weighted average (basic)	289.2	285.3	168.3	167.4	167.6	167.3	167.0	165.0	164.0
	Weighted average (diluted)	289.7	286.0	168.9	168.2	168.2	168.0	167.6	171.7	166.9
	End of period	290.5	287.8	169.0	167.9	167.7	167.5	167.1	166.9	164.5
Dividends declared		117.3	116.2	65.7	65.4	65.4	65.3	65.1	64.6	64.0
Dividends per common share ($ per share)		0.405	0.405	0.390	0.390	0.390	0.390	0.390	0.390	0.390

⁽¹⁾	Refer to “Non-GAAP measures.”

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

Increased oil production from customers operating in the Cardium and
Deep Basin Cretaceous formations of west central Alberta, which has
resulted in increased service offerings in these areas, as well as new
connections and capacity expansions;
Increased liquids-rich natural gas production from producers in the WCBS
(Deep Basin, Montney, Cardium and emerging Duvernay Shale plays), which
has resulted in increased gas gathering and processing at the Company’s
gas services assets and additional associated NGL transported on its
pipelines;
Revenue contribution from the Nipisi and Mitsue Pipelines, which were
completed in June and July of 2011; and
The acquisition of Provident, which closed on April 2, 2012 (for more
details please see Note 3 of the Interim Financial Statements for the
period ended September 30, 2012).

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 September 30		9 Months Ended September 30
($ millions, except per share amounts)	2012	2011	2012	2011
Results from operating activities	74.5	71.5	272.2	225.2
Share of profit from equity accounted investees (before tax, depreciation and amortization)	1.4	0.5	4.2	9.7
Depreciation and amortization	53.2	18.6	129.9	49.8
Unrealized loss (gain) on commodity-related derivative financial instruments	23.0	(0.7)	(38.3)	(4.3)
EBITDA	152.1	89.9	368.0	280.4
Add:
Acquisition-related expenses	1.7		23.1
Adjusted EBITDA	153.8	89.9	391.1	280.4
EBITDA per common share – basic (dollars)	0.53	0.54	1.49	1.68
Adjusted EBITDA per common share – basic (dollars)	0.53	0.54	1.58	1.68

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 September 30		9 Months Ended September 30
($ millions, except per share amounts)	2012	2011	2012	2011
Earnings before income tax and equity accounted investees	41.4	41.0	192.8	155.5
Add (deduct):
Unrealized change in fair value of derivative financial instruments	23.1	6.8	(46.6)	4.0
Share of (loss) profit of investments in equity accounted investees (after tax)	(0.6)	(0.6)	(1.0)	4.3
Tax on share of profit of investments in equity accounted investees	(0.2)	(0.2)	(0.4)	1.4
Acquisition-related expenses	1.7		23.1
Adjusted earnings	65.4	47.0	167.9	165.2
Adjusted earnings per common share – basic (dollars)	0.23	0.28	0.68	0.99

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 September 30		9 Months Ended September 30
($ millions, except per share amounts)	2012	2011	2012	2011
Cash flow from operating activities	130.9	87.7	220.3	211.7
Add:
Change in non-cash working capital	0.6	(5.7)	78.1	28.1
Acquisition-related expenses	1.7		23.1
Adjusted cash flow from operating activities	133.2	82.0	321.5	239.8
Adjusted cash flow from operating activities per common share – basic (dollars)	0.46	0.49	1.30	1.43

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 September 30		9 Months Ended September 30
($ millions)		2012	2011	2012	2011
Revenue		815.3	300.6	2,161.7	1,207.9
Cost of sales:
	Operations	69.5	54.4	185.6	136.8
	Cost of goods sold	565.5	145.8	1,506.4	764.3
	Realized gain (loss) on commodity-related derivative financial instruments	(2.8)	3.2	(15.6)	4.4
Operating margin		177.5	103.6	454.1	311.2
Depreciation and amortization included in operations		51.6	17.8	125.8	48.4
Unrealized gain (loss) on commodity-related derivative financial instruments		(23.0)	0.7	38.3	4.3
Gross profit		102.9	86.5	366.6	267.1

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

Total enterprise value

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

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

Forward-Looking Statements & Information

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

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

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

the future levels of cash dividends that Pembina intends to pay to its
shareholders;
capital expenditure-estimates, plans, schedules, rights and activities
and the planning, development, construction, operations and costs of
pipelines, gas service facilities, terminalling, storage and hub
facilities and other facilities or energy infrastructure, including,
but not limited to, in relation to the PNT, 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 and Peace crude 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,
the proposed development of a C2+ fractionator at Redwater, and the
potential offshore export opportunities for propane;
future expansion of Pembina’s pipelines and other infrastructure;
pipeline, processing and storage facility and system operations and
throughput levels;
oil and gas industry exploration and development activity levels;
Pembina’s strategy and the development of new business initiatives;
growth opportunities;
expectations regarding Pembina’s ability to raise capital and to carry
out acquisition, expansion and growth plans;
treatment under government regulatory regimes including environmental
regulations and related abandonment and reclamation obligations;
future G&A expenses at Pembina
increased throughput potential due to increased activity and new
connections and other initiatives on Pembina’s pipelines;
future cash flows, potential revenue and cash flow enhancements across
Pembina’s businesses and the maintenance of operating margins;
tolls and tariffs and transportation, storage and services commitments
and contracts;
cash dividends and the tax treatment thereof;
operating risks (including the amount of future liabilities related to
pipeline spills and other environmental incidents) and related
insurance coverage and inspection and integrity programs;
the expected capacity 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, the Northern NGL System
and the Peace crude 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 offshore export opportunities for propane;
the possibility of renegotiating debt terms, repayment of existing debt,
seeking new borrowing and/or issuing equity;
expectations regarding participation in Pembina’s DRIP;
the expected impact of changes in share price on annual share-based
incentive expense;
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 and the ability of
Pembina to maintain current credit ratings;
the availability of capital to fund future capital requirements relating
to existing assets and projects, including but not limited to future
capital expenditures relating to expansion, upgrades and maintenance
shutdowns;
future operating costs;
geotechnical and integrity costs associated with the Western System;
in respect of the proposed Saturn Facility and the 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 crude throughput capacity on the Peace crude system
and the estimated in-service dates with respect to the same; that
Pembina will receive regulatory approval; that counterparties will
comply with contracts in a timely manner; that there are no unforeseen
events preventing the performance of contracts by Pembina; that there
are no unforeseen construction costs related to the expansion; and that
there are no unforeseen material costs relating to the pipelines that
are not recoverable from customers;
in respect of the proposed 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 and crude volumes being transported on
the conventional pipelines, the proposed expansion plans to strengthen
Pembina’s transportation service options that it provides to producers
developing the Cardium oil formation located in central Alberta, the
installation of two remaining pump stations on the Nipisi and Mitsue
pipelines, the development of seven-fee-for-service storage facilities
at Redwater and the Redwater fractionator expansion that counterparties
will comply with contracts in a timely manner; that there are no
unforeseen events preventing the performance of contracts by Pembina;
that there are no unforeseen construction costs; and that there are no
unforeseen material costs relating to the developments, expansions and
capital expenditures which are not recoverable from customers;
the future exploration for and production of oil, NGL and natural gas in
the capture area around Pembina’s conventional and midstream assets,
including new production from the Cardium formation in western Alberta,
the demand for gathering and processing of hydrocarbons, and the
corresponding utilization of Pembina’s assets;
in respect of the stability of Pembina’s dividend; prevailing commodity
prices, margins and exchange rates; that Pembina’s future results of
operations will be consistent with past performance and management
expectations in relation thereto; the continued availability of capital
at attractive prices to fund future capital requirements relating to
existing assets and projects, including but not limited to future
capital expenditures relating to expansion, upgrades and maintenance
shutdowns; the success of growth projects; future operating costs; that
counterparties to material agreements will continue to perform in a
timely manner; that there are no unforeseen events preventing the
performance of contracts; and that there are no unforeseen material
construction or other costs related to current growth projects or
current operations; and
prevailing regulatory, tax and environmental laws and regulations.

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

the regulatory environment and decisions;
the impact of competitive entities and pricing;
labour and material shortages;
reliance on key alliances and agreements;
the strength and operations of the oil and natural gas production
industry and related commodity prices;
non-performance or default by counterparties to agreements which Pembina
or one or more of its affiliates has entered into in respect of its
business;
actions by governmental or regulatory authorities including changes in
tax laws and treatment, changes in royalty rates or increased
environmental regulation;
fluctuations in operating results;
adverse general economic and market conditions in Canada, North America
and elsewhere, including changes in interest rates, foreign currency
exchange rates and commodity prices;
the failure to realize the anticipated benefits of the Arrangement;
the failure to complete remaining integration of 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)


($ thousands)		Note	September 30, 2012	December 31, 2011
Assets Current assets
	Cash and cash equivalents		25,391
	Trade receivables and other		294,168	148,267
	Derivative financial instruments	13	21,885	4,643
	Inventory		140,719	21,235
			482,163	174,145
Non-current assets
	Property, plant and equipment	4	4,914,846	2,747,530
	Intangible assets and goodwill	5	2,644,145	243,904
	Investments in equity accounted investees		158,580	161,002
	Derivative financial instruments	13	110	1,807
	Other receivables		3,983	10,814
			7,721,664	3,165,057
Total Assets			8,203,827	3,339,202
Liabilities and Shareholders’ Equity Current liabilities
	Bank indebtedness			676
	Trade payables and accrued liabilities		308,182	166,646
	Dividends payable		39,218	21,828
	Loans and borrowings	6	11,319	323,927
	Derivative financial instruments	13	21,785	4,725
			380,504	517,802
Non-current liabilities
	Loans and borrowings	6	1,824,497	1,012,061
	Convertible debentures	7	608,668	289,365
	Derivative financial instruments	13	53,606	12,813
	Employee benefits		14,701	16,951
	Share-based payments		14,321	14,060
	Deferred revenue		2,943	2,185
	Provisions	8	483,412	405,433
	Deferred tax liabilities		568,656	106,915
			3,570,804	1,859,783
Total Liabilities			3,951,308	2,377,585
Shareholders’ Equity
Equity attributable to shareholders:
	Share capital	9	5,253,122	1,811,734
	Deficit		(990,658)	(834,921)
	Accumulated other comprehensive income		(15,196)	(15,196)
			4,247,268	961,617
Non-controlling interest			5,251
			4,252,519	961,617
Total Liabilities and Shareholders’ Equity			8,203,827	3,339,202

See accompanying notes to the Interim Financial Statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME
(unaudited)


			3 Months Ended September 30		9 Months Ended September 30
($ thousands, except per share amounts)		Note	2012	2011	2012	2011
Revenue			815,347	300,620	2,161,767	1,207,913
Cost of sales			686,578	218,050	1,817,887	949,601
(Loss) gain on commodity-related derivative financial instruments		13	(25,846)	3,895	22,731	8,744
Gross profit		11	102,923	86,465	366,611	267,056

	General and administrative		26,870	13,765	70,229	41,193
	Acquisition-related and other expense		1,509	1,224	24,178	642
			28,379	14,989	94,407	41,835

Results from operating activities			74,544	71,476	272,204	225,221
	Finance income		(6,862)	(268)	(9,236)	(1,179)
	Finance costs		39,973	30,733	88,601	70,932
	Net finance costs	10	33,111	30,465	79,365	69,753

Earnings before income tax and equity accounted investees			41,433	41,011	192,839	155,468

Share of loss (profit) of investments in equity accounted investees, net of tax			572	585	970	(4,257)

	Income tax expense		10,162	10,305	48,210	39,069

Earnings and total comprehensive income for the period			30,699	30,121	143,659	120,656

Earnings and comprehensive income attributable to:
	Shareholders		30,555	30,121	143,475	120,656
	Non-controlling interest		144		184
			30,699	30,121	143,659	120,656

Earnings per share attributable to the shareholders of the Company
Basic and diluted earnings per share (dollars)			0.11	0.18	0.58	0.72

See accompanying notes to the Interim Financial Statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY
(unaudited)


			9 Months Ended September 30
($ thousands)		Note	2012	2011
Share Capital
	Balance, beginning of period		1,811,734	1,794,536
	Common shares issued on acquisition	3	3,283,976
	Dividend reinvestment plan		151,131
	Share-based payment transactions		5,865	12,767
	Debenture conversions and other		416	22
	Balance, end of period	9	5,253,122	1,807,325

Deficit
	Balance, beginning of period		(834,921)	(739,351)
	Earnings for the period attributable to shareholders		143,475	120,656
	Dividends declared	9	(299,212)	(195,789)
	Balance, end of period		(990,658)	(814,484)

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

Non-controlling interest
	Balance, beginning of period
	Assumed on acquisition	3	5,067
	Earnings attributable to non-controlling interest		184
	Balance, end of period		5,251
Total Equity			4,252,519	988,264

	See accompanying notes to the Interim Financial Statements

CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
(unaudited)


			3 Months Ended September 30		9 Months Ended September 30
($ thousands)		Note	2012	2011	2012	2011
Cash provided by (used in):
Operating activities:
Earnings for the period			30,699	30,121	143,659	120,656
Adjustments for:
	Depreciation and amortization		53,210	18,671	129,887	49,846
	Unrealized loss (gain) on commodity-related derivative financial instruments	13	22,987	(687)	(38,286)	(4,285)
	Net finance costs	10	33,111	30,465	79,365	69,753
	Share of loss (profit) of investments in equity accounted investees, net of tax		572	585	970	(4,257)
	Deferred income tax expense		9,243	10,305	47,893	39,069
	Share-based payments		5,321	3,051	11,620	10,940
	Employee future benefits expense		1,921	1,188	5,250	3,589
	Increase in provisions			2,321		2,321
	Other		(350)	434	117	374
	Changes in non-cash working capital		(623)	5,688	(78,145)	(28,073)
	Distributions from investments in equity accounted investees		1,514	4,216	9,247	12,901
	Decommissioning liability expenditures		(570)	(114)	(2,937)	(1,889)
	Employee future benefit contributions		(2,500)	(2,000)	(7,500)	(6,000)
	Net interest paid		(23,635)	(16,563)	(80,833)	(53,281)
Cash flow from operating activities			130,900	87,683	220,307	211,664
Financing activities
	Bank borrowings		80,000	24,627	346,861	64,627
	Repayment of loans and borrowings		(805)	(2,764)	(60,841)	(87,864)
	Issuance of debt					250,000
	Financing fees			(18)	(5,066)	(1,774)
	Exercise of stock options		1,810	2,992	4,457	12,078
	Issue of shares under Dividend Reinvestment Plan		66,157		151,131
	Dividends paid		(116,922)	(65,349)	(281,822)	(195,688)
Cash flow from financing activities			30,240	(40,512)	154,720	41,379
Investing activities:
	Net capital expenditures		(138,730)	(82,245)	(357,834)	(378,917)
	Cash acquired on acquisition				8,874
Cash flow used in investing activities			(138,730)	(82,245)	(348,960)	(378,917)
Change in cash			22,410	(35,074)	26,067	(125,874)
Cash (bank indebtedness), beginning of period			2,981	34,597	(676)	125,397
Cash and cash equivalents, end of period			25,391	(477)	25,391	(477)

See accompanying notes to the Interim Financial Statements

NOTES TO THE 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 unaudited 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 nine months ending September 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 November 6, 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.

Certain of the prior period’s comparative figures have been reclassified
to conform to the current year’s presentation.

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 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 $1,761 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 an independent valuation. The primary drivers that
generate goodwill are synergies and business opportunities from the
integration of Pembina and Provident and the acquisition of a talented
workforce. 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 $23.1 million in acquisition-related
expenses. These expenses are included in acquisition-related and other
expenses in the Interim Financial Statements.

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

Revenue generated by the Provident business for the period from the
acquisition date of April 2, 2012 to September 30, 2012, before
intersegment eliminations, was $676.1 million. Net earnings, before
intersegment eliminations, for the same period were $45.2 million.

Unaudited proforma consolidated revenue (prepared as if the Provident
acquisition had occurred on January 1, 2012) for the nine months ended
September 30, 2012 are $2,701.9 million and net earnings for the same
period are $190.8 million.

4. PROPERTY, PLANT AND EQUIPMENT


($ thousands)	Land and Land Rights	Pipelines	Facilities and Equipment	Linefill and Other	Assets Under Construction	Total
Cost
Balance at December 31, 2011	67,219	2,500,027	528,620	200,726⁽¹⁾	307,358	3,603,950⁽¹⁾
Acquisition (Note 3)	18,093	280,435	1,281,073	321,277	87,318	1,988,196
Additions	5,885	5,081	120,395	25,689	172,604	329,654
Change in decommissioning provision		(35,335)	(17,688)			(53,023)
Capitalized interest		79	98		9,589	9,766
Transfers	22	(75,270)	116,226	(16,496)	(24,482)
Disposals and other	(5,001)	(917)	(533)	771		(5,680)
Balance at September 30, 2012	86,218	2,674,100	2,028,191	531,967	552,387	5,872,863

Depreciation
Balance at December 31, 2011	4,088	707,095	92,998	52,239		856,420
Depreciation	210	53,087	35,774	13,894		102,965
Transfers		3,091	22,454	(25,545)
Disposals and other		(567)	(89)	(712)		(1,368)
Balance at September 30, 2012	4,298	762,706	151,137	39,876		958,017

Carrying amounts
December 31, 2011	63,131	1,792,932	435,622	148,487	307,358	2,747,530
September 30, 2012	81,920	1,911,394	1,877,054	492,091	552,387	4,914,846

⁽¹⁾	$1.5 million was 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 35 years) or declining balance method at rates ranging from 3
percent to 37 percent (at an average rate of 12 percent per annum).
Other assets are depreciated using the straight line method over 2 to
45 years (an average of 23 years) or declining balance method at rates
ranging from 3 percent to 37 percent (at an average rate of 2 percent
per annum).

Commitments

At September 30, 2012, the Company has contractual commitments for the
acquisition and or construction of property, plant and equipment of
$497.0 million (December 31, 2011: $364.3 million).

5. INTANGIBLE ASSETS AND GOODWILL


	Goodwill	Other Intangibles	Total
($ thousands)
Cost
Balance at December 31, 2011	222,670	23,038	245,708
Acquisition (Note 3)	1,761,264	660,899	2,422,163
Additions and other		5,000	5,000
Balance at September 30, 2012	1,983,934	688,937	2,672,871
Amortization
Balance at December 31, 2011		1,804	1,804
Amortization		26,922	26,922
Balance at September 30, 2012		28,726	28,726
Carrying amounts
December 31, 2011	222,670	21,234	243,904
September 30, 2012	1,983,934	660,211	2,644,145

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 operating segment is as follows:


	September 30,	December 31,
($ thousands)	2012	2011
Conventional Pipelines	194,370	194,370
Oil Sands and Heavy Oil	33,300	28,300
Gas Services	20,710	21,234
Midstream	2,395,765
	2,644,145	243,904

The allocation is subject to change based on additional information
obtained subsequent to the valuation. 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 facilities	Nominal interest rate	Year of maturity	September 30, 2012	December 31, 2011
Operating facility⁽¹⁾	30,000	prime + 0.50 or BA⁽²⁾+ 1.50	2013		3,139
Revolving unsecured credit facility	1,500,000	prime + 0.50 or BA⁽²⁾ + 1.50	2017	860,481	309,981
Senior secured notes		7.38			57,499
Senior unsecured notes – Series A	175,000	5.99	2014	174,623	174,462
Senior unsecured notes – Series C	200,000	5.58	2021	196,897	196,638
Senior unsecured notes – Series D	267,000	5.91	2019	265,554	265,403
Senior unsecured term facility	75,000	6.16	2014	74,764	74,658
Senior unsecured medium term notes	250,000	4.89	2021	248,675	248,558
Subsidiary debt	9,169	4.99	2014	9,169
Finance lease liabilities				5,653	5,650
Total interest bearing liabilities	2,506,169			1,835,816	1,335,988
Less current portion				(11,319)	(323,927)
Total non-current				1,824,497	1,012,061

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

7. CONVERTIBLE DEBENTURES


($ thousands)	Series C – 5.75%	Series E – 5.75%	Series F – 5.75%	Total
Conversion price (dollars)	$28.55	$24.94	$29.53
Interest payable semi-annually in arrears on:	May 31 and November 30	June 30 and December 31	June 30 and December 31
Maturity date	November 30, 2020	December 31, 2017	December 31, 2018
Balance, December 31, 2011	289,365			289,365
Assumed on acquisition⁽¹⁾ (Note 3)		158,471	158,343	316,814
Conversions and redemptions	(54)	(332)	(55)	(441)
Unwinding of discount rate		561	460	1,021
Deferred financing fee (net amortization)	876	550	483	1,909
Balance, September 30, 2012	290,187	159,250	159,231	608,668

⁽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	9,072
Assumed on acquisition (Note 3)	124,579
Decommissioning liabilities settled during the period	(2,937)
Change in rates	(46,653)
Change in estimate and other	(14,357)
Total	485,857
Less current portion (included in accrued liabilities)	(2,445)
Balance at September 30, 2012	483,412

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

9. SHARE CAPITAL


($ thousands, except share amounts)	Number	Share Capital
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	272,936	5,865
Dividend reinvestment plan	5,773,600	151,131
Other	15,463	416
Balance September 30, 2012	290,506,020⁽¹⁾	5,253,122

⁽¹⁾

Weighted average number of common shares outstanding for the three
months ended September 30, 2012 is 289.2 million (September 30, 2011:
167.6 million). On a fully diluted basis, the weighted average number
of common shares outstanding for the three months ended September 30,
2012 is 289.7 million (September 30, 2011: 168.2 million). Weighted
average number of common shares outstanding for the nine months ended
September 30, 2012 is 247.8 million (September 30, 2011: 167.3
million). On a fully diluted basis, the weighted average number of
common shares outstanding for the nine months ended September 30, 2012
is 248.4 million (September 30, 2011: 168.0 million).

Dividends

The following dividends were declared by the Company:


	9 Months Ended September 30
($ thousands)	2012	2011
$1.20 per qualifying common share (2011: $1.17 )	299,212	195,789

On October 11, 2012, Pembina’s Board of Directors declared a dividend
for October of $39.3 million, representing $0.135 per qualifying common
share ($1.62 annualized).

10. NET FINANCE COSTS


		3 Months Ended September 30		9 Months Ended September 30
($ thousands)		2012	2011	2012	2011
Interest income from:
	Related parties		(226)	(263)	(636)
	Bank deposits	(365)	(23)	(666)	(412)
Interest expense on financial liabilities measured at amortized cost:
	Loans and borrowings	19,076	15,909	52,910	41,041
	Convertible debentures	10,583	4,657	25,767	13,825
	Finance leases	106	105	316	298
	Unwinding of discount	3,317	2,605	9,118	7,510
Loss (gain) in fair value of non-commodity-related derivative financial instruments		(6,497)	7,457	(4,100)	8,258
Loss (gain) in fair value of conversion feature of convertible debentures		6,670		(4,207)
Foreign exchange losses (gains)		221	(19)	490	(131)
Net finance costs		33,111	30,465	79,365	69,753

11. OPERATING SEGMENTS


3 Months Ended September 30, 2012 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream⁽³⁾	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	79,044	44,101			(6,219)	116,926
	NGL product and services, terminalling, storage and hub services				674,732		674,732
	Gas Services			23,689			23,689
Total revenue		79,044	44,101	23,689	674,732	(6,219)	815,347
	Operations	30,112	14,779	7,097	18,122	(633)	69,477
	Cost of goods sold, including product purchases				571,678	(6,219)	565,459
	Realized gain (loss) on commodity-related derivative financial instruments	496			(3,355)		(2,859)
Operating margin		49,428	29,322	16,592	81,577	633	177,552
	Depreciation and amortization (operational)	12,021	5,002	3,350	31,269		51,642
	Unrealized gain (loss) on commodity-related derivative financial instruments	(7,062)			(15,925)		(22,987)
Gross profit		30,345	24,320	13,242	34,383	633	102,923
	Depreciation included in general and administrative					1,568	1,568
	Other general and administrative	1,845	994	974	4,480	17,009	25,302
	Acquisition-related and other expenses (income)	10	(33)		69	1,463	1,509
Reportable segment results from operating activities		28,490	23,359	12,268	29,834	(19,407)	74,544
Net finance costs (income)		1,428	430	(10)	(2,786)	34,049	33,111
Reportable segment earnings (loss) before tax and income from equity accounted investees		27,062	22,929	12,278	32,620	(53,456)	41,433
Share of loss (profit) of investments in equity accounted investees, net of tax					572		572
Reportable segment assets		596,104	1,090,764	564,037	4,533,374⁽²⁾	1,419,548	8,203,827
Capital expenditures		34,748	6,093	29,824	70,668	2,034	143,367
Reportable segment liabilities		300,417	82,710	45,704	792,599	2,729,878	3,951,308

⁽¹⁾	6.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
⁽²⁾	Includes investments in equity accounted investees of $158.6 million.
⁽³⁾	NGL product and services, terminalling, storage and hub services revenue includes $21.8 million associated with U.S. midstream sales.



3 Months Ended September 30, 2011 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	78,689	36,983				115,672
	NGL product and services, terminalling, storage and hub services				166,171		166,171
	Gas Services			18,777			18,777
Total revenue		78,689	36,983	18,777	166,171		300,620
	Operations	34,619	12,642	6,403	2,570	(1,840)	54,394
	Cost of goods sold, including product purchases				145,832		145,832
	Realized gain (loss) on commodity-related derivative financial instruments	1,712			1,496		3,208
Operating margin		45,782	24,341	12,374	19,265	1,840	103,602
	Depreciation and amortization (operational)	10,423	3,907	2,522	972		17,824
	Unrealized gain (loss) on commodity-related derivative financial instruments	(21)			708		687
Gross profit		35,338	20,434	9,852	19,001	1,840	86,465
	Depreciation included in general and administrative					847	847
	Other general and administrative	1,510	870	892	1,267	8,379	12,918
	Acquisition-related and other expenses (income)	1,313	(11)	1	(2)	(77)	1,224
Reportable segment results from operating activities		32,515	19,575	8,959	17,736	(7,309)	71,476
Net finance costs		1,839	556	289	28	27,753	30,465
Reportable segment earnings (loss) before tax and income from equity accounted investees		30,676	19,019	8,670	17,708	(35,062)	41,011
Share of loss (profit) of investments in equity accounted investees, net of tax					585		585
Reportable segment assets		783,770	1,059,464	431,197	261,423⁽²⁾	636,638	3,172,492
Capital expenditures		20,297	13,954	28,990	5,041	8,905	77,187
Reportable segment liabilities		295,029	84,121	46,908	17,161	1,741,009	2,184,228

⁽¹⁾	11.6 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
⁽²⁾	Includes investments in equity accounted investees of $160.2 million.



9 Months Ended September 30, 2012 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream⁽²⁾	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	239,625	126,610			(13,094)	353,141
	NGL product and services, terminalling, storage and hub services				1,743,674		1,743,674
	Gas Services			64,952			64,952
Total revenue		239,625	126,610	64,952	1,743,674	(13,094)	2,161,767
	Operations	87,573	39,385	20,295	40,271	(1,893)	185,631
	Cost of goods sold, including product purchases				1,519,526	(13,094)	1,506,432
	Realized gain (loss) on commodity-related derivative financial instruments	(693)			(14,862)		(15,555)
Operating margin		151,359	87,225	44,657	169,015	1,893	454,149
	Depreciation and amortization (operational)	36,145	14,831	10,844	64,004		125,824
	Unrealized gain (loss) on commodity-related derivative financial instruments	(9,814)			48,100		38,286
Gross profit		105,400	72,394	33,813	153,111	1,893	366,611
	Depreciation included in general and administrative					4,063	4,063
	Other general and administrative	4,968	2,901	2,951	11,255	44,091	66,166
	Acquisition-related and others	933	355	11	168	22,711	24,178
Reportable segment results from operating activities		99,499	69,138	30,851	141,688	(68,972)	272,204
Net finance costs (income)		4,792	1,470	754	1,614	70,735	79,365
Reportable segment earnings (loss) before tax and income from equity accounted investees		94,707	67,668	30,097	140,074	(139,707)	192,839
Share of loss (profit) of investments in equity accounted investees, net of tax					970		970
Capital expenditures		99,220	12,134	85,586	126,597	6,117	329,654

⁽¹⁾	5.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
⁽²⁾	NGL product and services, terminalling, storage and hub services revenue includes $50.5 million associated with U.S. midstream sales.



9 Months Ended September 30, 2011 ($ thousands)		Conventional Pipelines⁽¹⁾	Oil Sands & Heavy Oil	Gas Services	Midstream	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	220,353	95,236				315,589
	NGL product and services, terminalling, storage and hub services				839,961		839,961
	Gas Services			52,363			52,363
Total revenue		220,353	95,236	52,363	839,961		1,207,913
	Operations	83,625	31,601	16,286	7,138	(1,841)	136,809
	Cost of goods sold, including product purchases				764,321		764,321
	Realized gain (loss) on commodity-related derivative financial instruments	3,167			1,292		4,459
Operating margin		139,895	63,635	36,077	69,794	1,841	311,242
	Depreciation and amortization (operational)	30,535	7,887	7,322	2,727		48,471
	Unrealized gain (loss) on commodity-related derivative financial instruments	4,630			(345)		4,285
Gross profit		113,990	55,748	28,755	66,722	1,841	267,056
	Depreciation included in general and administrative					1,375	1,375
	Other general and administrative	4,208	2,020	2,971	3,552	27,067	39,818
	Acquisition-related and other expense (income)	858	(118)	6	4	(108)	642
Reportable segment results from operating activities		108,924	53,846	25,778	63,166	(26,493)	225,221
Net finance costs		5,382	1,230	747	67	62,327	69,753
Reportable segment earnings (loss) before tax and income from equity accounted investees		103,542	52,616	25,031	63,099	(88,820)	155,468
Share of loss (profit) of investments in equity accounted investees, net of tax					(4,257)		(4,257)
Capital expenditures		47,083	143,852	70,083	106,950	10,697	378,665

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

12. SHARE BASED PAYMENTS

Long-term share unit award incentive plan⁽¹⁾


Grant date Performance Share Units (“PSU”)⁽⁴⁾ to Officers, Non-Officers⁽²⁾ and Directors (Number of units in thousands)	Units	Contractual life of options
January 1, 2012	188	3.0 Years
April 2, 2012 (on acquisition)	201	2.2 Years


Grant date Restricted Share Units (“RSU”)⁽³⁾ to Officers, Non-Officers⁽²⁾ and Directors (Number of units in thousands)	Units	Contractual life of options
January 1, 2012	187	3.0 Years
April 2, 2012 (on acquisition)	177	2.2 Years

⁽¹⁾	Distribution Units are granted in addition to RSU and PSU grants based on notional accrued dividends from RSU and PSU granted but not paid.
⁽²⁾	Non-Officers defined as senior selected positions within the Company.
⁽³⁾	One third vests on the first anniversary of the grant date, one third vests on the second anniversary of the grant date, and one third vests on the third anniversary of the grant date.
⁽⁴⁾	Vest on the third anniversary of the grant date. Actual PSUs awarded is based on the trading value of the shares and performance of the Company.

Disclosure of share option plan

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


	Number of Options	Weighted Average Exercise Price
Outstanding at December 31, 2011	2,674,380	20.24
Granted	1,446,100	26.67
Exercised	(272,936)	16.17
Forfeited	(132,163)	24.29
Outstanding as at September 30, 2012	3,715,381	22.90

13. FINANCIAL INSTRUMENTS

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


($ thousands)		As at September 30, 2012	As at December 31, 2011
Frac spread related
	Natural gas	(8,676)
	Propane	7,336
	Butane	4,467
	Condensate	2,878
	Foreign exchange	2,631
	Sub-total frac spread related	8,636
Management of exposure embedded in physical contracts and other		(6,632)	2,267
Corporate
	Power	(8,442)	4,183
	Interest rate	(15,937)	(17,538)
Other derivative financial instruments
	Conversion feature of convertible debentures	(25,500)
	Redemption liability related to acquisition of subsidiary	(5,521)
Net derivative financial instruments liability		(53,396)	(11,088)

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 is
subsequently fair valued at each reporting date with changes in the
value flowing through profit and loss. At September 30, 2012, the fair
value of the redemption liability was determined to be $5.5 million,
resulting in an unrealized gain of $0.9 million and $0.7 million
recorded in net finance costs for the three and nine months ended
September 30, 2012, respectively.

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 loss of $6.7 million and a gain of $4.2 million on
the revaluation on the conversion feature of convertible debentures in
profit and loss in net finance costs for the three and nine months
ended September 30, 2012, respectively.

The following table shows 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 September 30, 2012 ($ thousands)			+ Change	– Change
Frac spread related
	Natural gas	(AECO +/- $1.00 per GJ)	7,289	(7,289)
	NGL (includes propane, butane)	(Belvieu +/- U.S. $0.10 per gal)	(6,055)	6,055
	Foreign exchange (U.S.$ vs. Cdn$)	(FX rate +/- $0.05)	(4,902)	4,902
Management of exposure embedded in physical contracts
	Crude oil	(WTI +/- $5.00 per bbl)	(8,793)	8,793
	NGL (includes propane, butane and condensate)	(Belvieu +/- U.S. $0.10 per gal)	8,148	(8,148)
Corporate
	Interest rate	(Rate +/- 100 basis points)	973	(973)
	Power	(AESO +/- $5.00 per MW/h)	3,528	(3,528)
Conversion feature of convertible debentures		(Pembina share price +/- $0.50 per share)	(2,512)	2,381


Commodity-Related Derivative Financial Instruments		3 Months Ended September 30		9 Months Ended September 30
($ thousands)		2012	2011	2012	2011
Realized (loss) gain on commodity-related derivative financial instruments
Frac spread related
	Crude oil	(173)		(2,170)
	Natural gas	(7,922)		(15,684)
	Propane	2,253		3,980
	Butane	1,448		2,217
	Condensate	1,205		1,477
	Sub-total frac spread related	(3,189)		(10,180)
Corporate
	Power	755	1,712	(1,009)	3,167
Management of exposure embedded in physical contracts and other		(425)	1,496	(4,366)	1,292
Realized (loss) gain on commodity-related derivative financial instruments		(2,859)	3,208	(15,555)	4,459
Unrealized (loss) gain on commodity-related derivative financial instruments		(22,987)	687	38,286	4,285
(Loss) gain on commodity-related derivative financial instruments		(25,846)	3,895	22,731	8,744

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

14. SUBSEQUENT EVENT

On October 22, 2012, Pembina closed the offering of $450 million of
senior unsecured medium-term notes (“Notes”). The Notes have a fixed
interest rate of 3.77% per annum, paid semi-annually, and will mature
on October 24, 2022. The net proceeds from the offering of Notes were
used to repay a portion of Pembina’s existing credit facility.

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