Pembina Pipeline 40F 2012 Annual report | PBA Filing

Pembina Pipeline Corporation

MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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

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

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

About Pembina

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

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

Strategy

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

Preserve value by providing safe, responsible, cost-effective and reliable services;

Diversify Pembina's asset base along the hydrocarbon value chain by providing integrated service offerings which enhance profitability;

Pursue projects or assets that are expected to generate increased cash flow per share and capture long-life, economic hydrocarbon reserves; and

Maintain a strong balance sheet through the application of prudent financial management to all business decisions.

Pembina Pipeline Corporation

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)

Pembina Pipeline Corporation

Financial & Operating Overview

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

⁽¹⁾

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

⁽²⁾

Refer to "Non-GAAP Measures."

⁽³⁾

Represents per day volumes since the closing of the Acquisition.

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

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

Pembina Pipeline Corporation

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

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

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

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

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

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

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

Pembina Pipeline Corporation

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

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

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

Operating Results

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

⁽¹⁾

Midstream revenue is net of $975 million in cost of goods sold, including product purchases, for the quarter ended December 31, 2012 (quarter ended December 31, 2011: $308 million) and $2,494.5 million in cost of goods sold, including product purchases, for the twelve months ended December 31, 2012 (twelve months ended December 31, 2011: $1,072.3 million).

⁽²⁾

Refer to "Non-GAAP Measures."

⁽³⁾

Includes results from operations generated by the acquired assets from Provident since closing of the Acquisition on April 2, 2012.

Pembina Pipeline Corporation

Conventional Pipelines

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

⁽¹⁾

Refer to "Non-GAAP Measures."

Business Overview

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

Operational Performance: Throughput

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

Financial Performance

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

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

Pembina Pipeline Corporation

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

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

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

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

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

New Developments: Conventional Pipelines

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

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

The expansion has been split into two phases. During the first phase, the Company completed a re-contracting initiative in 2012 on existing and new volumes on the Northern NGL System (the Peace and Northern pipelines) to underpin the system’s Phase 1 NGL expansion.

Pembina Pipeline Corporation

The Company is nearing completion of the Phase 1 NGL expansion, which is expected to cost $30 million and add approximately 17 mbpd of additional NGL capacity to the Northern NGL System in the second quarter of 2013.

The Phase 1 Peace high vapour pressure ("HVP") expansion, which requires seven new or upgraded pump stations and associated pipeline reinforcement work from west of Fox Creek to Fort Saskatchewan, will add NGL capacity of approximately 35 mbpd. Pembina expects to commission three of the pump stations by August 2013, and the remaining four stations by October 2013 at an estimated cost of $70 million.

The Phase 1 Peace low vapour pressure ("LVP") expansion requires three upgraded pump stations and associated pipeline reinforcement work between Fox Creek and Edmonton, Alberta, and will provide an additional 40 mbpd of crude oil and condensate capacity on this segment. Pembina expects to commission one of the three pump stations by June 2013, and the remaining two stations by October 2013 at an estimated cost of $30 million.

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

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

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

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

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

Pembina Pipeline Corporation

Oil Sands & Heavy Oil

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

⁽¹⁾

Refer to "Non-GAAP Measures."

Business Overview

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

Financial Performance

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

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

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

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

Pembina Pipeline Corporation

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

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

New Developments: Oil Sands & Heavy Oil

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

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

Gas Services

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

⁽¹⁾

Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio.

⁽²⁾

Refer to "Non-GAAP Measures."

Business Overview

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

Pembina Pipeline Corporation

Financial Performance

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

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

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

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

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

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

New Developments: Gas Services

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

Pembina Pipeline Corporation

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

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

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

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

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

Midstream⁽¹⁾

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

⁽¹⁾

Share of profit from equity accounted investees not included in these results.

⁽²⁾

Includes results from NGL midstream since the closing of the Acquisition.

⁽³⁾

Refer to "Non-GAAP Measures."

Business Overview

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

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

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

Pembina Pipeline Corporation

The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; the recently expanded 73,000 bpd Redwater NGL fractionator, 6.8 mmbbls of cavern storage and terminalling facilities at Redwater, Alberta; and, third-party fractionation capacity in Fort Saskatchewan, Alberta.

The Empress East NGL system includes a 2.1 bcf/d interest in the straddle plants at Empress, Alberta; 20,000 bpd of fractionation capacity as well as 1.1 mmbbls of cavern storage in Sarnia, Ontario; and, approximately 5 mmbbls of hydrocarbon storage at Corunna, Ontario.

Financial Performance

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

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

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

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

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

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

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

Pembina Pipeline Corporation

Crude Oil Midstream

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

NGL Midstream

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

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

Redwater West

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

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

Empress East

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

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

Pembina Pipeline Corporation

New Developments: Midstream

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

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

As part of its full service terminal ("FST") development program, Pembina will be putting two new facilities into service in 2013. This includes a joint venture FST in the Judy Creek area of Alberta to serve the production from Beaverhill Lake and Swan Hills and a second FST that serves producers in the Cynthia area west of Drayton Valley. Pembina continues to advance other prospects for approval in 2013 and development in 2014.

During 2013, Pembina will enhance the connectivity of PNT, both to third-party infrastructure and to the Company’s own facilities between Edmonton and Fort Saskatchewan. Pembina will be adding a truck terminal and constructing storage which will come on stream in 2015. Pembina will also commission the first phase of a crude oil rail loading facility. This latter project will capitalize on synergies between capabilities and expertise acquired with Provident and the crude oil midstream business.

During 2012, Pembina successfully completed and commissioned an 8,000 bpd expansion at the Redwater fractionator, which required a 20-day turn-around of the facility in September. The project was completed on schedule and under budget. Also at Redwater, Pembina is currently in discussions with customers and completing preliminary engineering work to advance its proposed new 73,000 bpd ethane plus fractionator at its site. This fractionator would essentially duplicate the existing fractionator, and is being pursued by the Company to help ease anticipated fractionation capacity constraints in the Fort Saskatchewan, Alberta area.

In September of 2012, Pembina brought the first of seven fee-for-service caverns into service at its Redwater site. Three additional caverns are completed and Pembina is in the process of preparing them for service. Pembina expects to be able to bring two caverns into service in March 2013, and the third cavern into service in June 2013.

During the second quarter, Pembina entered into an agreement with a joint venture partner and a third-party producer to tie in its production of up to 60 MMcf/d and backstop a $12 million natural gas lateral connection to the Younger plant by the first quarter of 2013. Pembina’s share of NGL extracted from this expanded gathering footprint will be incremental supply to Pembina’s marketing portfolio in both Taylor, B.C. and Fort Saskatchewan, Alberta.

Given the oversupply of propane in western Canada and North America at large, and the associated pricing imbalance, Pembina is investigating opportunities for offshore propane export which would leverage its existing assets and help provide a solution for Canadian producers.

Market Risk Management Program

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

Pembina Pipeline Corporation

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

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

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

Transactions entered into during the fourth quarter

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

⁽¹⁾

Natural gas contracts are settled against Canadian Gas Price Reporter AECO's monthly index.

⁽²⁾

Crude oil contracts are settled against NYMEX WTI calendar average in U.S. or CDN dollars.

⁽³⁾

Propane contracts are settled against OPIS Mont Belvieu C3 TET.

⁽⁴⁾

Normal butane contracts are settled against OPIS Mont Belvieu NC4 NON TET.

⁽⁵⁾

ISO butane contracts are settled against OPIS Mont Belvieu IC4 NON TET.

⁽⁶⁾

Frac spread contracts entered into to manage revenue and costs associated with natural gas based supply arrangements.

⁽⁷⁾

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

⁽⁸⁾

Product margin contracts entered into to protect margins on commodity contracts.

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

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

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

Pembina Pipeline Corporation

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

Business Environment

	3 Months Ended December 31									12 Months Ended December 31
	2012			2011			% Change			2012			2011			% Change
WTI crude oil(U.S. $ per bbl)	$	88.18		$	94.06			(6	)	$	94.21		$	95.12			(1	)
Exchange rate(from U.S.$ to Cdn$)	$	0.99		$	1.03			3		$	1.00		$	0.99			(1	)
WTI crude oil(expressed in Cdn$ per bbl)	$	87.31		$	96.68			(10	)	$	94.12		$	94.21

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

Mont Belvieu Propane(U.S.$ per U.S. gallon)	$	0.88		$	1.44			(39	)	$	1.00		$	1.47			(32	)
Mont Belvieu Propane expressed as a percentage of WTI		42	%		64	%		(34	)		45	%		65	%		(31	)

Market Frac Spread in Cdn$ per bbl⁽¹⁾	$	38.61		$	58.41			(34	)	$	44.70		$	54.67			(18	)

⁽¹⁾

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

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

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

With respect to commodity prices:

The benchmark WTI oil price exited 2012 at U.S. $91.82/bbl, with prices remaining range-bound after recovering from lows set earlier in the year. The Canadian heavy crude oil benchmark differential, Western Canadian Select, compared to WTI widened significantly in the fourth quarter as infrastructure constraints were aggravated by continued production growth from the WCSB. Compared to $17.17 per barrel differential in 2011, the Western Canadian Select differential averaged $25.23 in 2012.

Natural gas prices posted strong gains in the fourth quarter as more seasonal temperatures returned to North America. An abnormally warm 2011/2012 winter depressed pricing through the first half of 2012 resulting in a full year average of $2.28 compared to $3.48 in 2011. While low natural gas prices are generally favourable for NGL extraction and fractionation economics, a sustained low gas price could impact the availability and overall cost of natural gas and NGL mix supply in western Canada with the potential for natural gas producers to elect to shut-in production or reduce drilling activities.

NGL prices in the fourth quarter of 2012 were mixed across products and continued to be negatively impacted by a warm 2011/2012 winter and increasing production. This resulted in a North American supply-demand imbalance.

Pembina Pipeline Corporation

In the U.S., industry propane/propylene inventories were approximately 66.7 million barrels at the end of 2012 (approximately 15.9 million barrels or 31 percent above the five-year historical average for this period).

In Canada, industry propane inventories increased to 8.7 million barrels at the end of 2012 (2.5 million barrels, or 40 percent higher, than the historic five-year average).

This over-supply continues to exert pressure on prices, where the Mont Belvieu propane price averaged U.S. $0.88 per U.S. gallon (42 percent of WTI) in the fourth quarter of 2012 and U.S. $1.00 per U.S. gallon (44 percent of WTI) for the full year, significantly below its five-year average of 58 percent of WTI.

Butane and condensate sales prices were robust in the fourth quarter; however, price levels remained below those of 2011.

Market frac spreads averaged $38.61 per barrel and $44.70 per barrel during the fourth quarter and full year of 2012, respectively, compared to $58.41 per barrel and $54.67 per barrel during the same periods of the prior year. The market frac spread does not include extraction premiums, operating/transportation/storage costs and regional sales prices.

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

Non-Operating Expenses

G&A

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

Depreciation & Amortization (operational)

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

Pembina Pipeline Corporation

Acquisition-Related and Other

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

Net Finance Costs

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

Income Tax Expense

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

Pension Liability

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

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

Pembina Pipeline Corporation

Liquidity & Capital Resources

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

⁽¹⁾

As at December 31, 2011, working capital includes $310 million of current, non-revolving, unsecured credit facilities.

⁽²⁾

Face value.

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

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

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

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

Pembina Pipeline Corporation

Offering of Medium-Term Notes

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

Credit Ratings

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

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

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

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

Pembina Pipeline Corporation

Capital Expenditures

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

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

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

Contractual Obligations at December 31, 2012

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

⁽¹⁾

Excluding deferred financing costs.

⁽²⁾

Includes discounted constructive and legal obligations included in the decommissioning provision.

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

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

Critical Accounting Estimates

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

Pembina Pipeline Corporation

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

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

Judgments

(i) Business combinations

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

(ii) Componentization

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

(iii) Depreciation and amortization

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

Estimates

(i) Inventory

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

(ii) Financial derivative instruments

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

(iii) Business Combinations

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

Pembina Pipeline Corporation

(iv) Defined benefit obligations

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

(v) Provisions and contingencies

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

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

(vi) Share-based payments

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

(vii) Deferred taxes

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

(viii) Depreciation and amortization

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

Changes in Accounting Principles and Practices

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

New standards and interpretations not yet adopted

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

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

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

Pembina Pipeline Corporation

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

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

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

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

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

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

Controls and Procedures

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

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

Pembina Pipeline Corporation

Changes in internal control over financial reporting

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

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

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

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

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

Trading Activity and Total Enterprise Value⁽¹⁾

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

⁽¹⁾

Trading information in this table reflects the activity of Pembina securities on the TSX only.

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

⁽⁵⁾

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

⁽⁶⁾

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

⁽⁷⁾

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

⁽⁸⁾

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

⁽⁹⁾

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

⁽¹⁰⁾

Refer to "Non-GAAP Measures."

Pembina Pipeline Corporation

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

Dividends

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

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

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

DRIP

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

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

Listing on the NYSE

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

Risk Factors

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

Pembina Pipeline Corporation

RISKS INHERENT IN PEMBINA'S BUSINESS

Operational Risks

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

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

Midstream Business

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

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

Pembina Pipeline Corporation

Reputation

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

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

Environmental Costs & Liabilities

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

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

Pembina Pipeline Corporation

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

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

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

Abandonment Costs

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

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

Pembina Pipeline Corporation

Reserve Replacement, Throughput and Product Demand

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

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

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

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

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

Operating and Capital Costs

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

Pembina Pipeline Corporation

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

Completion of the Resthaven Facility and Saturn Facility

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

Expansion of the Peace/Northern NGL System

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

Possible Failure to Realize Anticipated Benefits of Acquisitions

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

Pembina Pipeline Corporation

Competition

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

Execution Risk

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

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

Shipper and Processing Contracts

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

Pembina Pipeline Corporation

GENERAL RISK FACTORS

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

Dilution of Shareholders

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

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

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

•

the level of Pembina's indebtedness from time to time could impair Pembina's ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise;

•

the uncertainty of future dividend payments by Pembina and the level thereof as Pembina's dividend policy and the funds available for the payment of dividends from time to time will be dependent upon, among other things, operating cash flow generated by Pembina and its subsidiaries, financial requirements for Pembina's operations and the execution of its growth strategy and the satisfaction of solvency tests imposed by the Alberta Business Corporations Act for the declaration and payment of dividends;

•

Pembina may make future acquisitions or may enter into financings or other transactions involving the issuance of securities of Pembina which may be dilutive; and

•

the risk that the market value of the common shares may materially deteriorate if Pembina is unable to meet its cash dividend targets or make cash dividends in the future.

Market Value of Common Shares and Other Securities

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

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

Pembina Pipeline Corporation

Regulation

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

Additional Financing and Capital Resources

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

Counterparty credit risk

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

Pembina Pipeline Corporation

Debt Service

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

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

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

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

Credit Ratings

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

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

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

Pembina Pipeline Corporation

Changes in Legislation

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

Reliance on Management

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

Potential Conflicts of Interest

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

Litigation

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

Variations in Interest Rates and Foreign Exchange Rates

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

Selected Quarterly Operating Information

2012

2011

2010

Average volume
(mbpd unless stated otherwise)

Conventional Throughput

480.2

443.9

433.9

466.9

422.8

430.4

411.4

390.3

375.0

Oil Sands & Heavy Oil⁽¹⁾

870.0

870.0

775.0

Gas Services Processing(mboe/d)⁽²⁾

46.0

45.8

47.5

44.1

45.3

43.6

40.9

39.4

42.1

NGL sales volume(mboe/d)

115.8

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.

Pembina Pipeline Corporation

Selected Quarterly Financial Information

	2012												2011									2010
($ millions, except where noted)	Q4			Q3			Q2			Q1			Q4		Q3		Q2			Q1		Q4
Revenue		1,265.7			815.3			870.9			475.5			468.1		300.6		512.4			394.9		290.7
Operations		86.0			69.5			67.7			48.4			55.1		54.4		37.6			44.8		41.9
Cost of goods sold including product purchases		968.6			565.5			641.9			299.1			308.0		145.8		364.3			254.2		161.8
Realized gain (loss) on commodity-related derivative financial instruments		11.0			(2.8	)		(12.4	)		(0.3	)		0.9		3.2		(0.2	)		1.4		(0.8	)
Operating margin⁽¹⁾		222.1			177.5			148.9			127.7			105.9		103.6		110.3			97.3		86.2
Depreciation and amortization included in operations		47.8			51.6			52.5			21.7			19.6		17.8		15.8			14.8		15.6
Unrealized gain (loss) on commodity-related derivative financial instruments		(2.2	)		(23.0	)		64.8			(3.5	)		0.9		0.7		3.3			0.3		1.8
Gross profit		172.1			102.9			161.2			102.5			87.2		86.5		97.8			82.8		72.4
Adjusted EBITDA⁽¹⁾		199.0			153.8			125.9			111.4			88.2		89.9		103.3			87.2		79.1
Cash flow from operating activities		139.5			130.9			24.1			65.3			73.8		87.7		49.5			74.5		54.6
Cash flow from operating activities per common share($ per share)		0.48			0.45			0.08			0.39			0.44		0.52		0.30			0.45		0.33
Adjusted cash flow from operating activities⁽¹⁾		172.3			133.2			89.5			98.8			66.0		82.0		81.8			76.0		62.6
Adjusted cash flow from operating activities per common share⁽¹⁾($ per share)		0.59			0.46			0.31			0.59			0.39		0.49		0.49			0.45		0.39
Earnings for the period		81.3			30.7			80.4			32.6			45.0		30.1		48.0			42.5		55.2
Earnings per common share($ per share)
Basic		0.28			0.11			0.28			0.19			0.27		0.18		0.29			0.25		0.34
Diluted		0.28			0.11			0.28			0.19			0.27		0.18		0.29			0.25		0.33
Common shares outstanding(millions):
Weighted average (basic)		291.9			289.2			285.3			168.3			167.4		167.6		167.3			167.0		165.0
Weighted average (diluted)		292.5			289.7			286.0			168.9			168.2		168.2		168.0			167.6		171.7
End of period		293.2			290.5			287.8			169.0			167.9		167.7		167.5			167.1		166.9
Dividends declared		118.4			117.3			116.2			65.7			65.4		65.4		65.3			65.1		64.6
Dividends per common share($ per share)		0.405			0.405			0.405			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 5 of the Consolidated Financial Statements for the year ended December 31, 2012).

Pembina Pipeline Corporation

Selected Annual Financial Information

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

⁽¹⁾

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

Additional Information

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

Non-GAAP Measures

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

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

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

Pembina Pipeline Corporation

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

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

Adjusted earnings

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

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

Adjusted cash flow from operating activities

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

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

Pembina Pipeline Corporation

Operating margin

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

Reconciliation of operating margin to gross profit:

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

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

Total enterprise value

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

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

Pembina Pipeline Corporation

Forward-Looking Statements & Information

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

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

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

the future levels of cash dividends that Pembina intends to pay to its shareholders;

capital expenditure-estimates, plans, schedules, rights and activities and the planning, development, construction, operations and costs of pipelines, gas service facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, including, but not limited to, the Northern NGL System, the Peace HVP expansion between Fox Creed and Fort Saskatchewan, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion, the Phase 2 NGL Expansion, the joint venture full-service terminal in the Judy Creek area of Alberta area, the development program in the Cynthia area west of Drayton Valley, offshore export opportunities for propane, the Nipisi and Mitsue pipelines expansions, the Saturn facility and associated pipelines, the Resthaven facility and associated pipelines, the Nexus expansion, the Redwater expansion;

future expansion of Pembina's pipelines and other infrastructure;

pipeline, processing and storage facility and system operations and throughput levels;

oil and gas industry exploration and development activity levels;

Pembina's strategy and the development of new business initiatives;

growth opportunities;

expectations regarding Pembina's ability to raise capital and to carry out acquisition, expansion and growth plans;

treatment under government regulatory regimes including environmental regulations and related abandonment and reclamation obligations;

future G&A expenses at Pembina

increased throughput potential due to increased activity and new connections and other initiatives on Pembina's pipelines;

future cash flows, potential revenue and cash flow enhancements across Pembina's businesses and the maintenance of operating margins;

tolls and tariffs and transportation, storage and services commitments and contracts;

cash dividends and the tax treatment thereof;

operating risks (including the amount of future liabilities related to pipeline spills and other environmental incidents) and related insurance coverage and inspection and integrity programs;

the expected capacity, incremental volumes and in-services dates of proposed expansions and new developments, including the Northern NGL System, the Peace HVP expansion between Fox Creek and Fort Saskatchewan, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion, the Phase 2 NGL Expansion, the Nipisi and Mitsue pipelines, the Saturn facility, the Resthaven facility and Nexus;

the possibility of offshore export opportunities for propane;

the possibility of renegotiating debt terms, repayment of existing debt, seeking new borrowing and/or issuing equity;

expectations regarding participation in Pembina's DRIP;

the expected impact of changes in share price on annual share-based incentive expense;

inventory and pricing levels in the North American liquids market;

Pembina's discretion to hedge natural gas and NGL volumes; and

competitive conditions.

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

the success of Pembina's operations;

prevailing commodity prices and exchange rates and the ability of Pembina to maintain current credit ratings;

the availability of capital to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns;

future operating costs;

geotechnical and integrity costs associated with the Western System;

in respect of the proposed Saturn facility and the Resthaven facility and their estimated in-service dates; that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner, that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of such facilities; that such facilities will be fully supported by long-term firm service agreements accounting for the entire designed throughput at such facilities at the time of such facilities' completion; that there are no unforeseen construction costs related to the facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;

in respect of the expansion of NGL throughput capacity on the Northern NGL System and the crude throughput capacity on the Peace crude system and the estimated in-service dates with respect to the same; that Pembina will receive regulatory approval; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs related to the expansion; and that there are no unforeseen material costs relating to the pipelines that are not recoverable from customers;

Pembina Pipeline Corporation

in respect of the proposed expansion of Redwater; that Pembina will receive regulatory approval; that Pembina will reach satisfactory long-term arrangements with customers; that counterparties will comply with such contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the proposed fractionators that are not recoverable from customers;

in respect of other developments, expansions and capital expenditures planned, including the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the expectation of additional NGL and crude volumes being transported on the conventional pipelines, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in central Alberta, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven-fee-for-service storage facilities at Redwater and the Redwater fractionator expansion that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the developments, expansions and capital expenditures which are not recoverable from customers;

the future exploration for and production of oil, NGL and natural gas in the capture area around Pembina's conventional and midstream assets, including new production from the Cardium formation in western Alberta, the demand for gathering and processing of hydrocarbons, and the corresponding utilization of Pembina's assets;

in respect of the stability of Pembina's dividend; prevailing commodity prices, margins and exchange rates; that Pembina's future results of operations will be consistent with past performance and management expectations in relation thereto; the continued availability of capital at attractive prices to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns; the success of growth projects; future operating costs; that counterparties to material agreements will continue to perform in a timely manner; that there are no unforeseen events preventing the performance of contracts; and that there are no unforeseen material construction or other costs related to current growth projects or current operations; and

prevailing regulatory, tax and environmental laws and regulations.

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

the regulatory environment and decisions;

the impact of competitive entities and pricing;

labour and material shortages;

reliance on key alliances and agreements;

the strength and operations of the oil and natural gas production industry and related commodity prices;

non-performance or default by counterparties to agreements which Pembina or one or more of its affiliates has entered into in respect of its business;

actions by governmental or regulatory authorities including changes in tax laws and treatment, changes in royalty rates or increased environmental regulation;

fluctuations in operating results;

adverse general economic and market conditions in Canada, North America and elsewhere, including changes in interest rates, foreign currency exchange rates and commodity prices;

the failure to realize the anticipated benefits of the Acquisition;

the failure to complete remaining integration of the businesses of Pembina and Provident; and

the other factors discussed under "Risk Factors" in Pembina's Annual Information Form ("AIF") for the year ended December 31, 2012. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com and in the U.S. on the Company's profile at www.sec.gov.

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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	7th grade Bad

Pembina Pipeline (PBA) 40-F2012 FY Annual report (Canada)

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