Pembina reports record year-end 2013 results

New facilities and expansions drive strong results and future growth

CALGARY, Feb. 26, 2014 /CNW/ - All financial figures are in Canadian dollars unless noted otherwise. This report contains forward-looking statements and information that are based on Pembina Pipeline Corporation's ("Pembina" or the "Company") current expectations, estimates, projections and assumptions in light of its experience and its perception of historic trends. Actual results may differ materially from those expressed or implied by these forward-looking statements. Please see "Forward-Looking Statements & Information" in the accompanying Management's Discussion & Analysis ("MD&A") for more details. This report also refers to financial measures that are not defined by Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP and Additional GAAP Measures" of the accompanying MD&A.

On April 2, 2012 Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the twelve month period ended December 31, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012, together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. For further information about the Acquisition, please refer to Note 27 of the Consolidated Financial Statements.

Financial & Operating Overview

($ millions, except where noted)	3 Months Ended       December 31       (unaudited)						12 Months Ended       December 31
		2013			2012			2013			2012
Revenue		1,301			1,265			5,025			3,427
Operating margin^(1)		275			222			949			676
Gross profit		235			172			793			538
Earnings for the period		95			81			351			225
Earnings per common share - basic and diluted (dollars)		0.29			0.28			1.12			0.87
Adjusted EBITDA^(1)		235			199			831			590
Cash flow from operating activities		194			139			651			360
Cash flow from operating activities per common share (dollars)		0.62			0.48			2.12			1.39
Adjusted cash flow from operating activities^(1)		180			172			720			494
Adjusted cash flow from operating activities per common share (dollars)^(1)		0.57			0.59			2.34			1.91
Common share dividends declared		132			118			507			418
Dividends per common share (dollars)		0.42			0.41			1.65			1.61

⁽¹⁾ Refer to "Non-GAAP and Additional GAAP Measures."

Fourth Quarter and Year-End 2013 Highlights

• Pembina reported strong operating and financial results in 2013 and announced the largest pipeline expansion plan in its history.
  
  
• Consolidated operating margin was $275 million for the fourth quarter of 2013, an increase of 24 percent compared to $222 million during the same period of the prior year. Operating margin was positively impacted by several factors, including increased volumes resulting from higher producer activity levels in the majority of Pembina's operating areas, new expansions being brought into service and stronger propane prices. Operating margin in the fourth quarter of 2013 compared to the fourth quarter of 2012 by business was as follows:
• Midstream: $162 million compared to $119 million;
• Conventional Pipelines: $59 million compared to $58 million;
• Oil Sands & Heavy Oil: $33 million compared to $30 million; and
• Gas Services: $21 million compared to $14 million.
  
  
• For the full-year of 2013, operating margin totalled $949 million compared to $676 million during the prior year, representing an increase of approximately 40 percent. Operating margin was positively impacted by the factors mentioned above as well as by the Acquisition and was partially offset by increased operating expenses. By business, full-year operating margin generated in 2013 compared to 2012 was as follows:
• Midstream: $486 million compared to $288 million;
• Conventional Pipelines: $251 million compared to $209 million;
• Oil Sands & Heavy Oil: $131 million compared to $117 million; and
• Gas Services: $78 million compared to $59 million.
  
  
• Pembina realized increased volumes in all of its businesses. In Midstream, stronger propane market fundamentals contributed to an increase in natural gas liquids ("NGL") sales volumes during the fourth quarter of 2013 compared to the same period of the prior year. Conventional Pipelines transported an average of 500 thousand barrels per day ("mbpd") in the fourth quarter of 2013 and 492 mbpd for the full-year, four and eight percent higher, respectively, than the same periods of 2012, which was driven by continued producer activity, new connections and expansions being placed into service. In Oil Sands & Heavy Oil, volumes exceeded contracted capacity on the Company's Nipisi pipeline during the fourth quarter mainly due to the addition of a new pump station on the system. Gas Services also saw an increase in volumes of 44 and 16 percent due to new assets being placed into service, processing an average of 397 million cubic feet per day ("MMcf/d") during the fourth quarter of 2013 and 319 MMcf/d during 2013 compared to 276 MMcf/d and 275 MMcf/d in the comparable periods of the previous year.
  
  
• The Company's earnings increased to $95 million ($0.29 per common share) during the fourth quarter of 2013 compared to $81 million ($0.28 per common share) during the fourth quarter of 2012 and $351 million ($1.12 per common share) for the full-year of 2013 compared to $225 million ($0.87 per common share) in 2012. These increases were primarily due to improved operating margin which was offset by a $68 million increase in income tax expense and a $71 million unrealized loss relating to the conversion feature of Pembina's outstanding convertible debentures (2012: nil) because of the increase in Pembina's common share price in 2013. The full-year variance was also impacted by the timing of the Acquisition.
  
  
• Pembina generated adjusted EBITDA of $235 million during the fourth quarter of 2013 compared to $199 million during the fourth quarter of 2012. This increase was largely due to improved results from operating activities in each of Pembina's businesses and returns on new assets, expansions and services. Adjusted EBITDA for the full-year of 2013 was $831 million compared to $590 million in 2012 with the increase caused by strong results in each of Pembina's businesses including new assets, expansions and services having been brought on-stream, an improved propane market and the impact of the Acquisition.
  
  
• Cash flow from operating activities was $194 million ($0.62 per common share) during the fourth quarter of 2013 compared to $139 million ($0.48 per common share) for the same period in 2012. For the year ended December 31, 2013, cash flow from operating activities was $651 million ($2.12 per common share) compared to $360 million ($1.39 per common share) during 2012. The quarterly and full-year increases were primarily due to improved results from operating activities and decreased changes in non-cash working capital. The timing of the Acquisition also impacted the full-year variances.
  
  
• Adjusted cash flow from operating activities was $180 million ($0.57 per common share) during the fourth quarter of 2013 compared to $172 million ($0.59 per common share) during the fourth quarter of 2012. This decrease on a per share basis was due to higher interest paid and current taxes, preferred share dividends, as well as an increase in the number of common shares outstanding. Adjusted cash flow from operating activities was $720 million ($2.34 per common share) during 2013 compared to $494 million ($1.91 per common share) during 2012, with the increase primarily due to stronger operating results, returns on new investments and expansions as well as the impact of the Acquisition.

Growth and Operational Update

2013 was the most growth-oriented year in Pembina's history. The Company successfully leveraged its existing assets, including those it obtained through the Acquisition in 2012, to secure and progress growth projects in each of its businesses with the goal of providing customers highly integrated service offerings along the hydrocarbon value chain. The suite of growth projects Pembina secured during 2013 total an estimated capital expenditure of $3.5 billion, a portion of which is subject to regulatory approval, over the next several years. Highlights include:

• On February 13, 2013, Pembina announced having 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 by 55 mbpd (the "Phase II LVP Expansion");
  
  
• On March 5, 2013, Pembina announced plans to proceed with a $1 billion expansion of its NGL infrastructure, including Saturn II, a 200 MMcf/d deep cut facility, and RFS II, a second 73,000 bpd ethane-plus fractionator at Pembina's Redwater site, as well as the 53 mbpd Phase II NGL Expansion on its Peace and Northern NGL systems;
  
  
• On June 27, 2013, the Company announced having entered into an engineering support agreement to progress work related to a new diluent and blended bitumen pipeline system (the "Cornerstone Pipeline") associated with a third-party's enhanced oil recovery developments in northeast Alberta;
  
  
• On July 31, 2013, Pembina announced having secured long-term cost-of-service agreements with a third-party for the use of an underground storage cavern at Pembina's Redwater site and also announced that it plans to upsize certain facilities associated with RFS II to accommodate the future development of a third fractionator at Redwater;
  
  
• On August 9, 2013, Pembina announced plans to construct, own, and operate a new, fully-contracted 100 MMcf/d shallow cut gas plant ("Musreau II") and associated NGL and gas gathering pipelines near its existing Musreau facility (part of the Company's Cutbank Complex) in west central Alberta;
  
  
• On September 3, 2013, Pembina announced having acquired the $20 million "Heartland Hub", a site in the Alberta Industrial Heartland featuring an existing rail system and utility infrastructure to support the future development of rail, terminalling and storage facilities and other complementary midstream services;
  
  
• On September 3, 2013, Pembina announced having entered into a multi-year, fee-for-service agreement with a major North American refiner under which Pembina will provide rail loading services for up to 40 mbpd of various crude oil grades at the Company's Redwater facility;
  
  
• On September 16, 2013, the Company announced a $115 million expansion of its Peace Pipeline System between Simonette and Fox Creek, Alberta;
  
  
• On November 28, 2013, Pembina announced having converted a segment of its existing rail infrastructure to offer crude oil unit train service, the first of which left the site at the end of October; and
  
  
• On December 16, 2013, the Company announced having reached binding commercial agreements with 30 customers in Pembina's operating areas to proceed with constructing approximately $2 billion in pipeline expansions (the "Phase III Expansion") which will follow and expand upon certain segments of the Company's existing pipeline systems from Taylor, British Columbia southeast to Edmonton, Alberta.

In addition to the growth projects detailed above, which have expected in-service dates ranging from 2014 through 2017, Pembina brought numerous projects on-stream during 2013. These include:

• three long-term fee-for-service hydrocarbon storage caverns, which were placed into service at Pembina's Redwater site in the second quarter;
  
  
• an additional pump station on the Nipisi Pipeline, which increased capacity to 105 mbpd and was completed in the second quarter;
  
  
• an additional pump station on the Mitsue Pipeline, which increased capacity to 22 mbpd and was completed in the third quarter;
  
  
• the Company's Saturn I Facility (a 200 MMcf/d deep cut processing plant) and associated pipelines and infrastructure, which was placed into service in the fourth quarter;
  
  
• the Phase I Low Vapour Pressure Expansion, which provides an additional 40 mbpd of crude oil and condensate capacity on Pembina's Peace Pipeline between Fox Creek and Edmonton, Alberta and was placed into service late in the fourth quarter;
  
  
• the Phase I NGL Expansion, which expanded NGL capacity by 52 mbpd on the Peace and Northern Pipelines and was placed into service late in the fourth quarter; and
  
  
• eight clean crude oil and condensate truck unloading risers at the Company's Fox Creek Terminal, which were placed into service in the fourth quarter and allow producers to access Edmonton area markets through the previously announced Peace Pipeline mainline expansions.

Pembina is also actively constructing several other projects, including its previously announced Resthaven Facility, a 200 MMcf/d (130 MMcf/d net to Pembina) combined shallow cut and deep cut NGL extraction facility in the Resthaven, Alberta area. Further, the Company continues to progress its full-service terminal build-out program and cavern development at its Redwater site.

Financing Activity

The Company successfully executed numerous financings throughout 2013 to fund its growth plans.

On March 21, 2013, Pembina announced having closed its bought deal offering of 11,206,750 common shares at a price of $30.80 per share through a syndicate of underwriters, for gross proceeds of approximately $345 million.

On April 30, 2013, Pembina closed the offering of $200 million 30-year senior unsecured medium-term notes ("Notes"). The Notes have a fixed interest rate of 4.75 percent per annum paid semi-annually and will mature on April 30, 2043.

On July 26, 2013, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the "Series 1 Preferred Shares") at a price of $25.00 per share and on October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset class A preferred shares, series 3 (the "Series 3 Preferred Shares") at a price of $25.00 per share. The Series 1 Preferred Shares and Series 3 Preferred Shares trade on the Toronto Stock Exchange under the symbols PPL.PR.A and PPL.PR.C, respectively.

Subsequent to year-end, on January 16, 2014, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 5 (the "Series 5 Preferred Shares") at a price of $25.00 per share. The Series 5 Preferred Shares began trading on the Toronto Stock Exchange on January 16, 2014 under the symbol PPL.PR.E.

The Company used the proceeds from these offerings to partially fund capital projects, repay amounts outstanding on Pembina's credit facility, and for other general corporate purposes.

Transition of CEO and Chairman of the Board

As announced on September 4, 2013, Michael (Mick) Dilger, previously the Company's President and Chief Operating Officer, succeeded Bob Michaleski as Pembina's Chief Executive Officer ("CEO") upon Mr. Michaleski's retirement effective January 1, 2014. At that time, Mr. Dilger was also appointed to the Company's Board of Directors. Mr. Michaleski continues to serve as a member of Pembina's Board of Directors following his retirement as CEO.

Further, Pembina announced today that the Company's Chairman of the Board, Lorne Gordon, plans to step down effective April 1, 2014. Randall Findlay, a director of Pembina since 2007 and previous director of Provident from 2001 to 2012, will be taking over the role of Chairman of the Board that same day. Mr. Gordon will continue to serve as a member of Pembina's Board of Directors.

Summary

"2013 was the most successful and exciting year in Pembina's 60 year history," said Mr. Dilger, Pembina's President and CEO. "We began to realize the benefits of all of the effort that went into acquiring and then combining the strengths and realizing the synergies of the assets, people and processes of Provident. Our teams were able to bring in record results and secure more growth projects than ever, all while running our existing businesses safely and responsibly."

Mr. Dilger added: "I'm very excited for what 2014 has to bring. As always, we'll be focused on pursuing responsible and safe growth and delivering on the projects we have announced to continue generating long-term and sustainable returns for our shareholders. I trust we'll be able to succeed once again in following through on our commitments; we have highly motivated people, some of the most ideally-located assets and the most integrated services offering in western Canada's energy infrastructure space."

Fourth Quarter and Full-Year 2013 Conference Call & Webcast

Pembina will host a conference call on February 27, 2014 at 7:30 a.m. MT (9:30 a.m. ET) for interested investors, analysts, brokers and media representatives to discuss details related to the 2013 fourth quarter and full-year. The conference call dial-in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A recording of the conference call will be available for replay until March 6, 2014 at 11:59 p.m. ET. To access the replay, please dial either 416-849-0833 or 855-859-2056 and enter the password 41585575.

A live webcast of the conference call can be accessed on Pembina's website at www.pembina.com under Investor Centre, Presentation & Events, or by entering:
http://event.on24.com/r.htm?e=742950&s=1&k=B2FF195F78BC8020705B69E912D51242 in your web browser. Shortly after the call, an audio archive will be posted on the website for a minimum of 90 days.

2013 Online Annual Report

Pembina has published an online annual report on its website at www.pembina.com under "Investor Centre, Financial Reports" which is supplementary to its annual management's discussion and analysis, financial statements and notes.

While the online annual report will not be printed, investors and other stakeholders may obtain a hard copy of Pembina's annual management's discussion and analysis, financial statements and notes by mail by contacting Investor Relations at [email protected].

2014 Investor Day

Pembina will hold an Investor Day on Wednesday, March 5, 2014 at the Trump Hotel in Toronto, Ontario where members of the executive team will provide updates on strategy, operations, capital projects and Pembina's integrity management program.

Parties interested in attending the event are asked to email [email protected] to request an invitation. A live webcast will begin at 8:30 a.m. ET. To register for the webcast please click the following link or enter the URL into your web browser:
http://event.on24.com/r.htm?e=743572&s=1&k=4F6C55E3C58A34CA62F22DA512432CC1

The webcast and presentation will be accessible and available for replay through Pembina's website under Investor Centre, Presentations & Events.

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 February 26, 2014 and is supplementary to, and should be read in conjunction with, Pembina's audited consolidated annual financial statements for the years ended December 31, 2013 and 2012 ("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 and Additional GAAP Measures."

On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the comparative twelve month period ended December 31, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. The results of the business acquired through the Acquisition are reported as part of the Company's Midstream business. For further information about the Acquisition, please refer to Note 27 of the Consolidated Financial Statements.

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 60 years. Pembina owns and operates an integrated system of pipelines that transport various hydrocarbon liquids including conventional and synthetic crude oil, heavy oil and oil sands products, condensate (diluent) and natural gas liquids produced in western Canada. The Company also owns and operates 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 on its shares while enhancing the long-term value of its securities. To achieve this, Pembina's strategy is to:

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

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

Common Abbreviations

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

Measurement							Other
bpd			barrels per day				AECO			Alberta gas trading price
mbpd			thousands of barrels per day				AESO			Alberta Electric Systems Operator
mmbbls			millions of barrels				B.C.			British Columbia
mboe/d			thousands of barrels of oil equivalent per day				DRIP			Premium Dividend™ and Dividend Reinvestment Plan
MMcf/d			millions of cubic feet per day				Frac			Fractionation
bcf/d			billions of cubic feet per day				IFRS			International Financial Reporting Standards
MW/h			megawatts per hour				NGL			Natural gas liquids
GJ			gigajoule				NYSE			New York Stock Exchange
km			kilometre				TSX			Toronto Stock Exchange
							U.S.			United States
							WCSB			Western Canadian Sedimentary Basin
							WTI			West Texas Intermediate (crude oil benchmark price)

Financial & Operating Overview

		3 Months Ended       December 31       (unaudited)						12 Months Ended       December 31
($ millions, except where noted)		2013			2012			2013			2012
Conventional Pipelines throughput (mbpd)			500			480			492			456
Oil Sands & Heavy Oil contracted capacity, end of period (mbpd)			880			870			880			870
Gas Services average volume processed (mboe/d) net to Pembina^(1)			66			46			53			46
NGL sales volume (mbpd)			122			116			109			98
Total volume (mbpd)			1,568			1,512			1,534			1,470
Revenue			1,301			1,265			5,025			3,427
Cost of goods sold, including product purchases			922			968			3,719			2,475
Net revenue^(2)			379			297			1,306			952
Operating expenses			101			86			356			271
Realized (loss) gain on commodity-related derivative financial instruments			(3)			11			(1)			(5)
Operating margin^(2)			275			222			949			676
Depreciation and amortization included in operations			42			48			163			174
Unrealized gain (loss) on commodity-related derivative financial instruments			2			(2)			7			36
Gross profit			235			172			793			538
Deduct
	General and administrative expenses		43			27			132			97
	Acquisition-related and other expenses		1			1			1			26
	Net finance costs		55			36			166			115
	Current tax expense		19						38
	Deferred tax expense		22			27			105			75
Earnings			95			81			351			225
Earnings per common share - basic and diluted (dollars)			0.29			0.28			1.12			0.87
Adjusted EBITDA^(2)			235			199			831			590
Cash flow from operating activities			194			139			651			360
Cash flow from operating activities per common share (dollars)			0.62			0.48			2.12			1.39
Adjusted cash flow from operating activities^(2)			180			172			720			494
Adjusted cash flow from operating activities per common share (dollars)^(2)			0.57			0.59			2.34			1.91
Common share dividends declared			132			118			507			418
Dividends per common share (dollars)			0.42			0.41			1.65			1.61
Preferred share dividends declared			5						5
Capital expenditures			275			254			880			584
Total enterprise value ($ billions)^(2)			15			11			15			11
Total assets ($ billions)			9			8			9			8

^(1)	Gas Services average volume processed converted to mboe/d from MMcf/d at 6:1 ratio.
^(2)	Refer to "Non-GAAP and Additional GAAP Measures."

Net revenue increased 28 percent to $379 million during the fourth quarter of 2013 from $297 million during the same period of 2012. This increase was due to strong performance in each of Pembina's businesses, particularly in Midstream and Gas Services, as well as returns on new capital investments. Full-year net revenue in 2013 was $1,306 million compared to $952 million in 2012, up 37 percent from the same period last year. This increase was primarily due to improved performance in each of Pembina's businesses, including returns on new capital investments, as well as the impact of the Acquisition.

Operating expenses were $101 million during the fourth quarter and $356 million for the full-year in 2013 compared to $86 million and $271 million during the same periods in 2012. The increase in operating expenses for the fourth quarter and full-year of 2013 was largely the result of higher variable costs, such as power, labour and pipeline and facility integrity expenses, due to increased volumes that were driven by higher oil and NGL industry activity, as well as additional costs associated with the growth in Pembina's asset base primarily related to the Acquisition and Pembina's completed growth projects.

Operating margin was $275 million during the fourth quarter of 2013, up 24 percent from the same period last year when operating margin totalled $222 million. These increases were primarily the result of a strong NGL market in Midstream and the Saturn I Facility being placed into service in Gas Services. For the year ended December 31, 2013, operating margin was $949 million compared to $676 million for the full-year of 2012. These increases were primarily due to strong performance and growth across Pembina's operations, particularly from Midstream and Gas Services. The full-year increase was also attributable to the timing and impact of the Acquisition.

Gains/losses on commodity-related derivative financial instruments resulting from Pembina's market risk management program are primarily related to power, frac spread, and product margin derivative financial instruments (see "Market Risk Management Program" and Note 22 to the Consolidated Financial Statements). Pembina realized losses of $3 million and $1 million and recognized unrealized gains of $2 million and $7 million on commodity-related derivative financial instruments for the fourth quarter and year ended December 31, 2013, respectively, reflecting changes in the future NGL, natural gas and power price indices. For the comparative periods in 2012, the Company realized gains of $11 million and losses of $5 million and recognized unrealized losses of $2 million and gains of $36 million on commodity-related derivative financial instruments which were largely attributable to the reduction in the future NGL price indices between April 2, 2012, the date of the Acquisition, and December 31, 2012.

Depreciation and amortization included in operations decreased to $42 million during the fourth quarter of 2013 compared to $48 million during the same period in 2012 and to $163 million for the year ended December 31, 2013 compared to $174 million in 2012. Both the quarterly and full-year decreases reflect a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset which was recognized as a credit to depreciation expense in Conventional Pipelines.

Increases in revenue and operating margin and a decrease in depreciation and amortization included in operations contributed to gross profit of $235 million during the fourth quarter and $793 million for the full-year of 2013 compared to $172 million and $538 million for the same periods of 2012.

General and administrative expenses ("G&A") of $43 million were incurred during the fourth quarter of 2013, up from $27 million during the fourth quarter of 2012. This increase was primarily due to the addition of new employees as a result of Pembina's growth since the prior period as well as increased short-term and share-based incentive expenses as a result of a 10 percent increase in the Company's share price ($3.28 per share) during the fourth quarter. Full-year 2013 G&A totaled $132 million compared to $97 million in 2012. The increase for the full-year was mainly due to higher salary and incentive expenses as a result of additional employees (approximately 20 percent) due to the Company's growth and the Acquisition and a 31 percent increase in Pembina's share price ($8.96 per share) at December 31, 2013 compared to December 31, 2012. Every $1 change in share price is expected to change Pembina's annual share-based incentive expense by approximately $1 million.

Pembina generated adjusted EBITDA of $235 million during the fourth quarter of 2013 compared to $199 million during the fourth quarter of 2012. This increase was largely due to improved results from operating activities in each of Pembina's businesses and returns on new assets, expansions and services. Adjusted EBITDA for the full-year of 2013 was $831 million compared to $590 million in 2012 with the increase caused by strong results in each of Pembina's businesses including new assets, expansions and services having been brought on-stream, an improved propane market and the timing of the Acquisition.

The Company's earnings increased to $95 million ($0.29 per common share) during the fourth quarter of 2013 compared to $81 million ($0.28 per common share) during the fourth quarter of 2012 and $351 million ($1.12 per common share) for the full-year of 2013 compared to $225 million ($0.87 per common share) in 2012. These increases were primarily due to improved operating margin which was offset by a $68 million increase in income tax expense and a $71 million unrealized loss relating to the conversion feature of Pembina's outstanding convertible debentures (2012: nil) due to the increase in Pembina's common share price in 2013. The year-to-date results were also impacted by the timing of the Acquisition.

Cash flow from operating activities was $194 million ($0.62 per common share) during the fourth quarter of 2013 compared to $139 million ($0.48 per common share) for the same period in 2012. For the year ended December 31, 2013, cash flow from operating activities was $651 million ($2.12 per common share) compared to $360 million ($1.39 per common share) during 2012. The quarterly and full-year increases were primarily due to improved results from operating activities and decreased changes in non-cash working capital. The timing of the Acquisition also impacted the full-year variances.

Adjusted cash flow from operating activities was $180 million ($0.57 per common share) during the fourth quarter of 2013 compared to $172 million ($0.59 per common share) during the fourth quarter of 2012. This decrease on a per share basis was due to higher interest paid and current taxes, preferred share dividends as well as an increase in the number of common shares outstanding. Adjusted cash flow from operating activities was $720 million ($2.34 per common share) during 2013 compared to $494 million ($1.91 per common share) during 2012, with the increase primarily due to stronger operating results, returns on new investments and expansions as well as the impact of the Acquisition.

Operating Results

	3 Months Ended       December 31       (unaudited)											12 Months Ended       December 31
	2013					2012						2013						2012
($ millions)	Net Revenue^(1)			Operating Margin^(1)			Net Revenue^(1)			Operating Margin^(1)			Net Revenue^(1)			Operating Margin^(1)			Net Revenue^(1)			Operating Margin^(1)
Conventional Pipelines		111			59			99			58			411			251			339			209
Oil Sands & Heavy Oil		52			33			46			30			195			131			172			117
Gas Services		33			21			23			14			121			78			88			59
Midstream		184			162			129			119			580			486			353			288
Corporate		(1)									1			(1)			3						3
Total		379			275			297			222			1,306			949			952			676

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

Conventional Pipelines

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions, except where noted)	2013			2012			2013			2012
Average throughput (mbpd)		500			480			492			456
Revenue		111			99			411			339
Operating expenses		52			42			162			130
Realized gain on commodity-related derivative financial instruments					1			2
Operating margin^(1)		59			58			251			209
Depreciation and amortization included in operations		6			8			12			44
Unrealized (loss) gain on commodity-related derivative financial instruments		(1)			1			1			(9)
Gross profit		52			51			240			156
Capital expenditures		126			88			325			187

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

Business Overview

Pembina's Conventional Pipelines business comprises a well-maintained and strategically located 8,200 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 objectives are to provide safe and reliable transportation services for customers, pursue opportunities for increased throughput and maintain and/or grow sustainable operating margin on invested capital by capturing incremental volumes, expanding its pipeline systems, managing revenue and following a disciplined approach to its operating expenses.

Operational Performance

During the fourth quarter of 2013, Conventional Pipelines' throughput averaged 500 mbpd, consisting of an average of 369 mbpd of crude oil and condensate and 131 mbpd of NGL. This represents an increase of approximately four percent compared to the same period of 2012, when average throughput was 480 mbpd. On a full-year basis, 2013 throughput averaged 492 mbpd compared to 456 mbpd for 2012. The cause of the increased throughput was greater oil and gas producer activity in Conventional Pipelines' service areas, which led to a number of newly connected facilities and higher volumes at existing connections and truck terminals. Pembina's Phase I crude oil, condensate and NGL pipeline capacity expansions, which were placed into service in December 2013, also contributed to the fourth quarter and full-year 2013 results, with December 2013 volumes averaging 538 mbpd compared to 492 mbpd in the prior year.

Financial Performance

During the fourth quarter of 2013, Conventional Pipelines generated revenue of $111 million, 12 percent higher than the $99 million generated in the same quarter of the previous year. This increase was primarily due to stronger volumes, new connections and higher tolls, as well as the Phase I expansions noted above which increased capacity on certain of Pembina's systems beginning in December 2013. For 2013, revenue was $411 million compared to $339 million during 2012. This 21 percent year-over-year increase was due to the same factors impacting the fourth quarter, combined with toll increases on certain of Pembina's pipelines which were implemented in early 2013. Further, a Pembina-owned and operated pipeline system previously captured within the Midstream business is now managed and reported in Conventional Pipelines, positively impacting revenue by $7 million and $26 million for the fourth quarter and year ended December 31, 2013, respectively. This had no impact on average throughput as the assets are interconnected to existing Conventional Pipelines systems.

Operating expenses in the fourth quarter of 2013 were $52 million compared to $42 million in the fourth quarter of 2012 and $162 million in 2013 compared to $130 million in 2012. The 24 and 25 percent increases were mainly due to work undertaken to continue to ensure safe and reliable operations at historically high throughput levels. This includes increased pipeline integrity and geotechnical activities, as well as seasonal, winter-access pipeline work, higher power costs related to volume growth (particularly in December 2013) and higher labour costs contributed to the increase.

Operating margin for the fourth quarter of 2013 was $59 million compared to $58 million during the same period of 2012. Operating margin was virtually unchanged due to a commensurate increase in operating expenses relative to revenue. Full-year operating margin in 2013 grew to $251 million compared to $209 million for 2012 due to higher revenue driven by growth in volumes as discussed above.

For depreciation and amortization included in operations during the fourth quarter of 2013, Conventional Pipelines incurred a $6 million expense compared to an expense of $8 million during the same period of the prior year. The decrease in the comparable period is due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset which resulted in a credit to depreciation expense. An expense of $12 million was recognized for the year ended December 31, 2013 compared to an expense of $44 million in 2012 with the difference between the periods being due to the same factor noted above.

For the three months ended December 31, 2013, Pembina recognized an unrealized loss on commodity-related derivative financial instruments of $1 million compared to an unrealized gain of $1 million in the fourth quarter of 2012. For the full-year of 2013, Pembina recognized an unrealized gain on commodity-related derivative financial instruments of $1 million compared to an unrealized loss of $9 million for 2012. The 2013 unrealized gain 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, 2013, gross profit was $52 million and $240 million, respectively, compared to $51 million and $156 million, respectively, during the same periods in 2012. For the fourth quarter, gross profit was impacted by higher revenue which was offset by increased operating expenses. The full-year increase was primarily due to higher operating margin and decreased depreciation and amortization included in operations.

Capital expenditures for the fourth quarter and full-year of 2013 totalled $126 million and $325 million, respectively, compared to $88 million and $187 million for the same periods of 2012. The majority of this spending relates to the expansion of certain pipeline assets as described below, as well as the completion of several new connections to bring additional producer volumes on-line.

New Developments

Pembina is pursuing numerous crude oil, condensate and NGL expansions on its Conventional Pipelines systems to accommodate increased customer demand and address constrained pipeline capacity in several areas of the WCSB.

Late in the fourth quarter of 2013, Pembina completed construction of its Phase I NGL Expansion, which expanded NGL capacity by 52 mbpd on the Peace and Northern pipelines (the "Peace/Northern NGL System"), bringing total capacity on these systems to 167 mbpd as of December 2013. The Company also completed its Phase I crude oil and condensate expansion on its Peace Pipeline between Fox Creek and Edmonton, Alberta providing an additional 40 mbpd of crude oil and condensate capacity on this segment in December 2013.

Pembina is also progressing its previously announced Phase II expansions. The Phase II NGL Expansion of its Peace/Northern NGL System is expected to increase capacity of the system from 167 mbpd to 220 mbpd. Subject to obtaining regulatory and environmental approvals, Pembina expects the Phase II NGL Expansion to be complete in mid-2015. The Phase II crude oil and condensate expansion on its Peace Pipeline (the "Phase II LVP Expansion") is expected to increase capacity of the system from 195 mbpd to 250 mbpd. Subject to obtaining regulatory and environmental approvals, Pembina expects the Phase II LVP Expansion to be complete in late-2014.

On September 16, 2013, in response to requests from area producers for firm service between Simonette and Fox Creek, Alberta, Pembina announced plans to proceed with a $115 million expansion of its Peace Pipeline System (the "Simonette Pipeline Expansion"). This expansion is expected to initially deliver approximately 40 mbpd of additional liquids to Pembina's Fox Creek Terminal from which it will access the Company's previously announced Phase I and II Peace Pipeline mainline expansions to reach Edmonton-area markets. The new pipeline will have a capacity of approximately 150 mbpd and is expected to be in service in the third quarter of 2014.

The Simonette Pipeline Expansion will include approximately 60 km of 16-inch pipeline along the Company's existing right-of-way, providing service to producers developing the regional Montney and Duvernay resource plays. Once complete, Pembina will have three pipelines in the corridor capable of segregating and shipping various grades of crude oil, condensate and NGL. Pembina believes the addition of this 16-inch pipeline will provide suitable capacity in the area for projected volume growth.

On December 16, 2013, the Company announced having reached binding commercial agreements to proceed with constructing approximately $2 billion in pipeline expansions (the "Phase III Expansion"). The Phase III Expansion is underpinned by long-term take-or-pay transportation services agreements with 30 customers in Pembina's operating areas and is expected to be in-service between late-2016 and mid-2017, subject to environmental and regulatory approvals. The 540 km Phase III Expansion will follow and expand upon certain segments of the Company's existing pipeline systems from Taylor, British Columbia southeast to Edmonton, Alberta to fulfill capacity needs for Pembina's customers, with priority being placed on areas where debottlenecking is essential.

The core of the Phase III Expansion will entail constructing a new 270 km 24 inch diameter pipeline from Fox Creek, Alberta to the Edmonton area, which is expected to have an initial capacity of 320 mbpd and an ultimate capacity of over 500 mbpd with the addition of midpoint pump stations. Once complete, Pembina will have three distinct pipelines in the Fox Creek to Edmonton, Alberta corridor. With the Company's existing pipelines and current expansions, these three pipelines (which will be part of the Peace and Northern systems) are expected to have the designed capacity to transport up to approximately 1,000 mbpd if fully expanded. The Phase III Expansion also contemplates increasing pipeline interconnectivity between Edmonton and Fort Saskatchewan, including Pembina's Redwater and Heartland Hub sites as well as third-party delivery points in these areas. This interconnectivity is expected to provide the option for customers to access a broad variety of delivery points including fractionators, refineries and storage hubs, as well as increased access to pipeline and rail take-away capacity.

The contracts underpinning the Phase III Expansion are generally ten-year transportation services agreements for volumes that average over 230 mbpd, or approximately 75 percent of the initial planned capacity, and that are expected to provide a steady, long-term EBITDA stream. The Company anticipates securing further pipeline transportation commitments over the next four to six months while it refines the project scope. Any additional commitments made before the Company begins to order long-lead equipment would support increasing the design capacity of the Phase III Expansion.

Oil Sands & Heavy Oil

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions, except where noted)	2013			2012			2013			2012
Contracted capacity, end of period (mbpd)		880			870			880			870
Revenue		52			46			195			172
Operating expenses		19			16			64			55
Operating margin^(1)		33			30			131			117
Depreciation and amortization included in operations		2			5			17			20
Gross profit		31			25			114			97
Capital expenditures		5			18			38			30

^(1)	Refer to "Non-GAAP and Additional 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 approximately 880 mbpd of capacity under long-term, extendible contracts, which provide for the flow-through of eligible operating expenses to customers. As a result, operating margin from this business is primarily driven by 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 $52 million in the fourth quarter of 2013 compared to $46 million in the fourth quarter of 2012. Full-year revenue in 2013 was $195 million compared to $172 million for 2012. Revenue for the fourth quarter and year ended December 31, 2013 was higher than the comparable periods of the prior year largely because of increased contribution from the Nipisi Pipeline which resulted from a new pump station being placed into service and enabled the transportation of volumes above contracted levels since being brought on-stream in the second quarter of 2013.

Operating expenses were $19 million during the fourth quarter of 2013 compared to $16 million during the fourth quarter of 2012. For the year ended December 31, 2013, operating expenses were $64 million compared to $55 million for the full-year of 2012. Additional power and maintenance costs were the main reasons for the increase in operating expenses for both the fourth quarter and full-year of 2013.

For the three and twelve months ended December 31, 2013, operating margin grew to $33 million and $131 million from $30 million and $117 million, respectively, generated during the same periods in 2012. These increases were primarily due to the new pump station on the Nipisi Pipeline which enabled throughput above contracted volumes since being brought on-stream in the second quarter of 2013.

For the three and twelve months ended December 31, 2013, gross profit was $31 million and $114 million, respectively, compared to $25 million and $97 million, respectively, during the same periods of 2012. These increases were primarily due to higher operating margin in the quarter and full-year, as discussed above.

For the year ended December 31, 2013, capital expenditures within the Oil Sands & Heavy Oil business totalled $38 million and were primarily related to the construction of additional pump stations in the Slave Lake, Alberta, area on the Nipisi and Mitsue pipelines. This compares to $30 million spent during 2012, which also related to the Nipisi and Mitsue pipelines.

New Developments

Pembina continues to move forward with work related to its previously announced $35 million engineering support agreement ("ESA") to progress a potential new oil sands pipeline project (the "Cornerstone Pipeline System"). Provided that satisfactory commercial agreements can be reached and that regulatory and environmental approvals can be obtained thereafter, Pembina expects the Cornerstone Pipeline System could be in-service in the third quarter of 2017 at an estimated cost of approximately $1 billion. The capital expenditure estimate for the potential Cornerstone Pipeline System has been increased from its original estimate of $850 million due to the project scope being refined as the Company has advanced project development and preliminary engineering. Pembina anticipates that the Cornerstone Pipeline System would also provide integration opportunities and synergies for Pembina's Midstream business, which is expected to be a 50-percent shipper on the diluent pipeline.

During 2013, Pembina completed an additional pump station on the Nipisi Pipeline, which increased capacity to 105 mbpd, and an additional pump station on the Mitsue Pipeline, which increased capacity to 22 mbpd.

Gas Services

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions, except where noted)	2013			2012			2013			2012
Average volume processed (MMcf/d) net to Pembina^(1)		397			276			319			275
Average volume processed (mboe/d)^(2) net to Pembina		66			46			53			46
Revenue		33			23			121			88
Operating expenses		12			9			43			29
Operating margin^(3)		21			14			78			59
Depreciation and amortization included in operations		7			4			20			15
Gross profit		14			10			58			44
Capital expenditures		56			77			258			163

^(1)	Volumes at Musreau exclude deep cut processing as those volumes are counted when they are processed through the shallow cut portion of the plant.
^(2)	Average volume processed converted to mboe/d from MMcf/d at a 6:1 ratio.
^(3)	Refer to "Non-GAAP and Additional GAAP Measures."

Business Overview

Pembina's operations include a growing natural gas gathering and processing business, which is strategically positioned in active and emerging NGL-rich plays in the WCSB and integrated with Pembina's other businesses. Gas Services provides gas gathering, compression, and both shallow and deep cut processing services for its customers, primarily on a fee-for-service basis under long-term contracts. The NGL extracted through these processes are transported on Pembina's Conventional Pipelines. Operating assets in this business include:

• Pembina's Cutbank Complex - located near Grand Prairie, Alberta, this facility includes three shallow cut sweet gas processing plants (the Cutbank Gas Plant, the Musreau Gas Plant and the Kakwa Gas Plant) and one deep cut gas processing plant (the Musreau Deep Cut Facility). In total, the Cutbank Complex has 425 MMcf/d of processing capacity (368 MMcf/d net to Pembina) and 205 MMcf/d of ethane-plus extraction capacity. This facility also includes approximately 350 km of gathering pipelines.
• Pembina's Saturn I Facility - located near Hinton, Alberta, this facility includes 200 MMcf/d of ethane-plus extraction capacity as well as approximately 25 km of gathering pipelines.

The Cutbank Complex and Saturn I Facility are connected to Pembina's Peace Pipeline system. The Company continues to progress construction and development of numerous other facilities in its Gas Services business to meet the growing needs of producers in west central Alberta, as discussed in more detail below.

Operational Performance

Average volume processed, net to Pembina, was 397 MMcf/d during the fourth quarter of 2013, approximately 44 percent higher than the 276 MMcf/d processed during the fourth quarter of the previous year. On a full-year basis, volumes increased 16 percent to 319 MMcf/d compared to 275 MMcf/d in 2012. This growth was caused by new volumes from the Saturn I Facility being placed into service along with sustained activity by producers in the surrounding areas and their focus on liquids-rich natural gas due to its higher price relative to dry gas.

Financial Performance

Gas Services contributed $33 million in revenue during the fourth quarter of 2013, approximately 43 percent higher than the $23 million generated in the fourth quarter of 2012. For the full-year of 2013, revenue was $121 million compared to $88 million in 2012. These increases primarily reflect the Saturn I Facility being placed into service in the fourth quarter of 2013, as well as higher processing fees and operating recoveries at the Company's Musreau shallow and deep cut facilities. Revenue was also greater as a result of the Company investing additional capital in these facilities to meet producer demand. Further, at the Cutbank Complex, the Musreau deep cut facility and shallow cut expansion were brought on-stream early in September of 2012 and have operated throughout 2013.

During the fourth quarter of 2013, operating expenses were $12 million compared to $9 million incurred in the fourth quarter of 2012. Full-year operating expenses in 2013 totalled $43 million, up from $29 million during the prior year. The quarterly and full-year increases were mainly due to additional power, labour and maintenance costs associated with new assets being in-service as well as higher volumes and increased activity at the expanded Cutbank Complex.

Gas Services realized an operating margin of $21 million in the fourth quarter and $78 million in the full-year of 2013, respectively, compared to $14 million and $59 million, respectively, during the same periods of the prior year. These increases are the result of new assets being placed into service and the associated new volumes, higher throughput at the Cutbank Complex and the collection of additional fees for capital invested.

Depreciation and amortization included in operations during the fourth quarter of 2013 totalled $7 million, up from $4 million during the same period of the prior year, primarily due to higher in-service assets from capital additions to the Cutbank Complex (including the Musreau deep cut facility and shallow cut expansion) and the new Saturn I Facility. For the same reason, depreciation and amortization included in operations totalled $20 million in 2013 compared to $15 million in 2012.

For the three months ended December 31, 2013, gross profit was $14 million compared to $10 million in the same period of 2012, and was $58 million for the full-year of 2013 compared to $44 million in 2012. These increases reflect higher operating margin during the 2013 periods.

For the year ended December 31, 2013, capital expenditures within Gas Services totalled $258 million compared to $163 million during the same period of 2012. This increase in spending was primarily to complete the Saturn I Facility and to progress the multi-year construction projects at Resthaven, Saturn II, and Musreau II which are discussed below.

New Developments

During 2013, Pembina completed and commissioned its Saturn I Facility (a 200 MMcf/d deep cut processing plant) and its associated pipelines and infrastructure. The facility, which has the capability of extracting up to 13.5 mbpd of NGL, was fully operational as of late-October 2013.

In 2014, Pembina's Gas Services business plans to spend approximately $260 million to progress new facilities and associated infrastructure. Pembina expects the expansions detailed below to bring the Company's Gas Services processing capacity to approximately 1.2 bcf/d (net) by the end of 2015 which includes ethane-plus extraction capacity of approximately 735 MMcf/d (net). The volumes from Pembina's existing assets and those under development would be processed largely on a contracted, fee-for-service basis and could result in an addition of approximately 55 mbpd of NGL, subject to gas compositions, to be transported for toll revenue on Pembina's Conventional Pipelines once the projects are complete.

• Resthaven Facility - a 200 MMcf/d (134 MMcf/d net to Pembina) combined shallow cut and deep cut NGL extraction facility, which is expected to cost approximately $240 million (net to Pembina);
• Saturn II Facility - a 200 MMcf/d 'twin' of the Saturn I Facility, which is expected to cost approximately $170 million; and,
• Musreau II Facility - a 100 MMcf/d shallow cut gas plant and associated infrastructure, which is expected to cost approximately $110 million.

Pembina is progressing construction of the Resthaven Facility with 100 percent of major equipment ordered and expects to bring the facility and associated pipelines into service in the third quarter of 2014. Once operational, the Company expects the Resthaven Facility will have the capability to extract up to 13 mbpd of NGL.

The Saturn II Facility will leverage the engineering work completed for the Saturn I Facility and is expected to be in-service by late-2015. Pembina has received the required regulatory and environmental approvals and is progressing construction of the facility with over 65 percent of the major equipment ordered. The Company expects the Saturn II Facility will have the capability to extract up to 13.5 mbpd of NGL which will be transported, using excess capacity, on the same liquids pipeline lateral Pembina constructed for the Saturn I Facility.

On August 9, 2013, Pembina announced that it is pursuing the Musreau II Facility, a new 100 MMcf/d shallow cut gas plant with associated NGL and gas gathering pipelines near its existing Musreau Gas Plant (part of the greater Cutbank Complex). The Musreau II Facility is underpinned by long-term take-or-pay agreements with area producers. The facility is designed to extract propane-plus (C₃+) and could deliver up to approximately 4.2 mbpd of NGL for transportation on Pembina's Conventional Pipelines. Pembina has received the required regulatory and environmental approvals, construction is underway with 100 percent of the major equipment ordered and Pembina expects the Musreau II Facility to be in-service in the first quarter of 2015.

Midstream

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31^(1)
($ millions, except where noted)	2013			2012			2013			2012
NGL sales volume (mbpd)		122			116			109			98
Revenue		1,117			1,103			4,347			2,847
Cost of goods sold, including product purchases		933			974			3,767			2,494
Net revenue^(2)		184			129			580			353
Operating expenses		19			20			91			60
Realized gain (loss) on commodity-related derivative financial instruments		(3)			10			(3)			(5)
Operating margin^(2)		162			119			486			288
Depreciation and amortization included in operations		27			31			114			95
Unrealized gain (loss) on commodity-related derivative financial instruments		3			(3)			6			45
Gross profit		138			85			378			238
Capital expenditures		87			77			254			204

^(1)	Share of profit from equity accounted investees not included in these results.
^(2)	Refer to "Non-GAAP and Additional 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 development opportunities at key sites across Pembina's network and comprises 16 truck terminals (including two capable of emulsion treatment and water disposal), terminalling at downstream hub locations, storage, crude oil by rail services and the Pembina Nexus Terminal ("PNT"). PNT includes: 21 inbound pipeline connections; 13 outbound pipeline connections; in excess of 1.2 million bpd of crude oil and condensate supply connected to the terminal; and 310,000 barrels of surface storage in and around the Edmonton, Alberta area.
  
  
• NGL midstream includes two NGL operating systems - Redwater West and Empress East.
• The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; a 73 mbpd NGL fractionator and 7.8 mmbbls of finished product cavern storage at Redwater, Alberta; and third-party fractionation capacity in Fort Saskatchewan, Alberta. Redwater West purchases NGL mix from various natural gas and NGL producers and fractionates it into finished products for further distribution and sale. Also located at the Redwater site is Pembina's rail-based terminal which services Pembina's proprietary and customer needs for importing and exporting specification NGL and crude oil.
  
  
• The Empress East NGL system includes a 2.1 bcf/d capacity in the straddle plants at Empress, Alberta; 20 mbpd of fractionation capacity and 1.1 mmbbls of cavern storage in Sarnia, Ontario; and ownership of 5.1 mmbbls of hydrocarbon storage at Corunna, Ontario. 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 pipeline to Sarnia, Ontario for fractionation, distribution and sale. Propane and butane are sold into central Canadian and eastern U.S. markets.
  
  The financial performance of NGL midstream can be affected by the seasonal demand for propane. Propane 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. Condensate and butane are generally sold consistently throughout the year.

Financial Performance

In the Midstream business net revenue grew to $184 million during the fourth quarter of 2013 from $129 million during the fourth quarter of 2012. For the most part, the increase is due to higher propane prices which resulted from lower inventories in North America in the 2013 period compared to 2012. Full-year net revenue in 2013 was $580 million compared to $353 million in 2012. This increase was primarily due to a full-year of results generated by the NGL assets in 2013 compared to 2012, which only captured nine months of results due to the timing of the Acquisition, along with improved propane pricing. Stronger margins and increased storage opportunities for crude oil and condensate in the first quarter of 2013 also contributed to the full-year increase.

Operating expenses during the fourth quarter and full-year of 2013 were $19 million and $91 million, respectively, compared to $20 million and $60 million in the comparable periods of 2012. Full-year operating expenses were higher primarily due to the increase in Midstream's asset base since the Acquisition.

Operating margin was $162 million during the fourth quarter of 2013 and $486 million during the full-year compared to $119 million and $288 million in the respective periods of 2012. These increases primarily related to growth in revenue and were partially offset by higher operating expenses, as discussed above.

The Company's crude oil midstream operating margin grew to $48 million compared to $45 million in the same period of 2012 (both periods included a $1 million realized gain on commodity-related derivative financial instruments. This increase was largely due to stronger margins and new services such as crude oil unit train loading, as well as improved volumes at Pembina's truck and full-service terminals during the quarter. For the year ended December 31, 2013, crude oil midstream's operating margin totalled $147 million including a $2 million realized loss on commodity-related derivative financial instruments compared to $132 million including a $1 million gain on commodity-related derivative financial instruments during the prior year. The full-year increase was primarily driven by both higher volumes and activity on Pembina's pipeline systems, robust demand for midstream services and wider margins (particularly in the first quarter of the year), the Company's crude oil unit train service offering and increased throughput at the crude oil midstream truck terminals.

Operating margin for Pembina's NGL midstream activities was $114 million for the fourth quarter of 2013, including a $4 million realized loss on commodity-related derivative financial instruments (see "Market Risk Management Program") compared to $74 million for the fourth quarter of 2012, including a $9 million realized gain on commodity-related derivative financial instruments. For the year ended December 31, 2013, operating margin for NGL midstream was $339 million, including a $1 million realized loss on commodity-related derivative financial instruments compared to $156 million, which included a realized loss on commodity-related derivative financial instruments of $6 million, for the same period of 2012.

At 122 mbpd, fourth quarter 2013 NGL sales volumes were five percent higher than the same period in 2012, with the increase largely attributable to ethane and butane product sales.

Operating margin from Redwater West during the fourth quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $71 million compared to $48 million in the fourth quarter of 2012. The increase was primarily driven by a stronger year-over-year market for propane. Overall, Redwater West NGL sales volumes averaged 69 mbpd in the fourth quarter of 2013 compared to 72 mbpd in the fourth quarter of 2012. The decrease in sales volumes primarily related to an operational issue with one of the feedstock caverns for the fractionator. While this issue had restricted production rates, it did not impact any of Pembina's NGL sales commitments. The feedstock cavern issue was resolved subsequent to year-end in early January 2014.

Operating margin from Empress East during the fourth quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $47 million compared to $17 million in the same quarter in 2012. These improved results were largely attributable to the strong year-over-year 2013 propane market and lower inventory acquisition costs at Empress. Overall, Empress East NGL sales volumes averaged 53 mbpd in the fourth quarter of 2013 compared to 44 mbpd in the fourth quarter of 2012.

Depreciation and amortization included in operations during the fourth quarter of 2013 totalled $27 million compared to $31 million during the same period of the prior year. The decrease primarily reflects assets previously in the Midstream business which are now accounted for in Conventional Pipelines, as previously discussed. Full-year depreciation and amortization included in operations totalled $114 million, up from $95 million for 2012. The full-year increase reflects the additional assets in this business since the closing of the Acquisition.

In the fourth quarter of 2013, unrealized gains on commodity-related derivative financial instruments relating to the Midstream business were $3 million compared to an unrealized loss of $3 million for the three months ended December 31, 2012. Full-year unrealized gains on commodity-related derivative financial instruments were $6 million in 2013 compared to $45 million in the prior year. The significant changes in unrealized losses and gains on commodity-related derivative financial instruments which were recognized in the three and twelve month periods ended December 31, 2013, respectively, reflect the reduction in the future NGL price indices between April 2, 2012 (the date of the Acquisition) and December 31, 2012.

For the three and twelve months ended December 31, 2013, gross profit in this business was $138 million and $378 million compared to $85 million and $238 million, respectively, during the same periods in 2012 due to the factors impacting revenue, operating expenses, depreciation and amortization included in operations and unrealized gains (losses) on commodity-related derivative financial instruments noted above.

For the twelve months ended December 31, 2013, capital expenditures within the Midstream business totalled $254 million compared to $204 million during 2012. Capital spending in this business was primarily directed towards the development of Pembina's second fractionator, storage caverns and associated infrastructure and unit train capability at Redwater, the build-out of Pembina's full-service terminal network, the acquisition of the Heartland Hub (as defined below) and increased interconnectivity and optionality at PNT.

New Developments

Market demand for products and services in the Midstream space is strong for both crude oil and NGL. The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects.

On September 3, 2013, Pembina announced the acquisition of a $20 million site in the Alberta Industrial Heartland featuring existing rail access and utility infrastructure to support the future development of rail, terminalling and storage facilities (the "Heartland Hub"). The Heartland Hub is a further build-out of PNT, servicing crude oil and diluent customers for terminalling, storage and rail.

At the same time, Pembina announced entering into a multi-year, fee-for-service agreement with a major North American refiner under which Pembina will provide rail loading services for up to 40 mbpd of pipeline-connected crude oil grades at the Company's Redwater facility. The Company has been moving unit train outbound deliveries since the end of October, 2013.

Regarding Pembina's previously announced $415 million RFS II project (a second 73 mbpd fractionator at Pembina's Redwater site), the Company continued to progress with facility construction and associated feed cavern development during the fourth quarter. To-date, the site has been stripped and graded, the facility roadways and parking lots have been laid out, the storm water pond has be dug and lined, and the construction facilities are substantially complete. Pembina expects to have contractors mobilized and on site to begin construction in April, 2014 and to be able to bring RFS II into service in the fourth quarter of 2015.

Market Risk Management Program

Pembina's results are subject to movements in commodity prices, foreign exchange and interest rates. A formal Risk Management Program including policies and procedures has been designed to mitigate these risks.

Commodity price risk

Pembina's Midstream business is exposed to changes in commodity prices as a result of frac spread risk or the relative price differential between the input cost of the natural gas required to produce NGL products and the price at which they are sold. Pembina responds to commodity price risk by using an active Risk Management Program to fix revenues on a minimum of 50 percent of the committed term natural gas supply costs. Pembina's Midstream business is also exposed to variability in quality, time and location differentials. The Company utilizes financial derivative instruments as part of its overall risk management strategy to assist in managing the exposure to commodity price risk as a result of these activities. The Company does not trade financial instruments for speculative purposes.

Foreign exchange risk

Pembina's commodity-related cash flows are subject to currency risk, primarily arising from the denomination of specific earnings and cash flows in U.S. dollars. Pembina responds to this risk using an active Risk Management Program to exchange foreign currency for domestic currency at a fixed rate.

Interest rate risk

Pembina has floating interest rate debt which subjects the Company to interest rate risk. Pembina responds to this risk under the active Risk Management Program by entering into financial derivative contracts to fix interest rates.

(For more information on financial instruments and financial risk management, see Note 22 to the Consolidated Financial Statements.)

Non-Operating Expenses

G&A

Pembina incurred G&A (including corporate depreciation and amortization) of $43 million during the fourth quarter of 2013, up from $27 million during the fourth quarter of 2012. This increase was primarily due to the addition of new employees as a result of Pembina's growth since the prior period as well as increased short-term and share-based incentive expenses as a result of a 10 percent increase in the Company's share price ($3.28 per share) during the fourth quarter. Full-year 2013 G&A totaled $132 million compared to $97 million in 2012. The increase for the full-year was mainly due to higher salary and incentive expenses as a result of additional employees (approximately 20 percent) due to the Company's growth and the Acquisition and a 31 percent increase in Pembina's share price ($8.96 per share) at December 31, 2013 compared to December 31, 2012. Every $1 change in share price is expected to change Pembina's annual share-based incentive expense by approximately $1 million.

Depreciation & Amortization Included in Operations

Depreciation and amortization included in operations decreased to $42 million during the fourth quarter of 2013 compared to $48 million during the same period in 2012. For the year ended December 31, 2013, depreciation and amortization included in operations was $163 million, down from $174 million last year. The variances during the quarter and full-year compared to the same periods of 2012 are primarily due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset, which was recognized as a $33 million credit to depreciation expense (in Conventional Pipelines) for 2013 (2012: $6 million) and was offset by depreciation from new assets.

Net Finance Costs

Net finance costs in the fourth quarter of 2013 were $55 million compared to $36 million in the fourth quarter of 2012. The increase is primarily attributed to an unrealized loss relating to the conversion feature of Pembina's outstanding convertible debentures due to the Company's higher common share price in 2013, which was offset by lower interest expense on loans and borrowings. Full-year net finance costs in 2013 totalled $166 million in 2013, up from $115 million in 2012. The increase is due to a loss on the conversion feature of convertible debentures of $71 million, which was partially offset by a reduction in interest on loans and borrowings of $18 million. Interest expense on loans and borrowings totalled $55 million in 2013, down from $73 million in 2012, reflecting reduced borrowing levels.

Income Tax Expense

Income tax expense was $41 million for the fourth quarter of 2013, including current taxes of $19 million and deferred taxes of $22 million, compared to deferred taxes of $27 million in the same period of 2012. Full-year income tax expense totalled $143 million including current taxes of $38 million and deferred taxes of $105 million, up from $75 million of deferred taxes in the same period of 2012. The current taxes increased during the year primarily because taxable income exceeded available deductions. Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities.

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 qualified employees and an unfunded supplemental retirement plan for those employees affected by the Canada Revenue Agency maximum pension limits. At the end of 2013, the pension plans carried an obligation of $2 million compared to an obligation of $28 million at the end of 2012. At December 31, 2013, plan obligations amounted to $126 million (2012: $128 million) compared to plan assets of $124 million (2012: $100 million). In 2013, the pension plans' expense was $10 million (2012: $7 million). Contributions to the pension plans totaled $13 million in 2013 and $10 million in 2012.

In 2014, contributions to the pension plans are expected to be $10 million and the pension plans' net expenses are anticipated to be $9 million. Management anticipates an annual increase in compensation of 4 percent, which is consistent with current industry standards.

Liquidity & Capital Resources

($ millions)		December 31, 2013			December 31, 2012
Working capital		(170)^(3)			66
Variable rate debt^(1)(2)
	Bank debt	50			525
Total variable rate debt outstanding (average rate of 2.67%)		50			525
Fixed rate debt^(1)
	Senior unsecured notes	642			642
	Senior unsecured term debt	75			75
	Senior unsecured medium-term notes	900			700
	Subsidiary debt	8			9
Total fixed rate debt outstanding (average of 4.99%)		1,625			1,426
Convertible debentures^(1)		633			644
Finance lease liability		9			6
Total debt and debentures outstanding		2,317			2,601
Cash and unutilized debt facilities		1,531			1,032

^(1)	Face value.
^(2)	Pembina maintains derivative financial instruments to manage exposure to variable interest rates. See "Market Risk Management Program."
^(3)	As at December 31, 2013, working capital includes $262 million (December 31, 2012: $12 million) associated with the current portion of loans and borrowings.

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 $1,531 million as at December 31, 2013. In addition, based on its successful access to financing in the debt and equity markets over the past several years, Pembina believes it would continue to have access to funds at attractive rates, if and when required. 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 additional equity. See "Risk Factors - Additional Financing and Capital Resources" and "Risk Factors - Debt Service."

Pembina's credit facilities at December 31, 2013 consisted of an unsecured $1.5 billion revolving credit facility due March 2018 and an operating facility of $30 million due July 2014 which is expected to be renewed on an annual basis. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil 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, 2013, Pembina had $50 million drawn on bank debt, leaving $1,480 million of unutilized debt facilities on the $1,530 million of established bank facilities. Pembina also had an additional $8 million in letters of credit issued in a separate demand letter of credit facility. At December 31, 2013, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,675 million. Pembina's senior debt to total capital at December 31, 2013 was 22 percent. Pembina is required to meet certain specific financial covenants under its senior unsecured notes, medium-term notes and revolving credit and operating facilities 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. All notes and facilities are governed by specific and customary affirmative and negative financial covenants and require the Company to maintain certain financial ratios, all of which Pembina has been in compliance with during the years ended December 31, 2013 and 2012.

On March 21, 2013, Pembina announced that it had closed its bought deal offering of 11,206,750 common shares at a price of $30.80 per share through a syndicate of underwriters, which includes 1,461,750 common shares issued at the same price on the exercise in full of the over-allotment option granted to the underwriters. The aggregate gross proceeds from the offering was approximately $345 million. The net proceeds from the offering were used to reduce the Company's debt.

On April 30, 2013, Pembina closed the offering of $200 million 30-year senior unsecured medium-term notes ("Notes"). The Notes have a fixed interest rate of 4.75 percent per annum paid semi-annually, and will mature on April 30, 2043.

On July 26, 2013, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the "Series 1 Preferred Shares") at a price of $25.00 per share. The Series 1 Preferred Shares began trading on the Toronto Stock Exchange the same day under the symbol PPL.PR.A.

On October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset class A preferred shares, series 3 (the "Series 3 Preferred Shares") at a price of $25.00 per share. The Series 3 Preferred Shares began trading on the Toronto Stock Exchange the same day under the symbol PPL.PR.C.

The Company used the proceeds from the offerings to partially fund capital projects, repay amounts outstanding on Pembina's credit facility, and for other general corporate purposes.

Subsequent to year-end, on January 16, 2014, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 5 (the "Series 5 Preferred Shares") at a price of $25.00 per share. Proceeds from the Series 5 Preferred Shares will be used to partially fund Pembina's 2014 capital expenditure program, including capital expenditures relating to Pembina's current expansions and growth projects, to reduce indebtedness under the Company's credit facilities, and for general corporate purposes. The Series 5 Preferred Shares began trading on the Toronto Stock Exchange on January 16, 2014 under the symbol PPL.PR.E.

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, and the associated costs, to enter 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 judgment, circumstances so warrant.

DBRS rates Pembina's senior unsecured notes 'BBB' and Series 1, Series 3 and Series 5 Preferred Shares Pfd-3. S&P's long-term corporate credit rating on Pembina is 'BBB' and its rating of the Series 1, Series 3 and Series 5 Preferred Shares is P-3.

Capital Expenditures

		3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions)		2013			2012			2013			2012
Development capital
	Conventional Pipelines		126			88			325			187
	Oil Sands & Heavy Oil		5			18			38			30
	Gas Services		56			77			258			163
	Midstream		87			77			254			204
Corporate/other projects			1			(6)			5
Total development capital			275			254			880			584

During the fourth quarter and full-year 2013, capital expenditures were $275 million and $880 million, respectively, compared to $254 million and $584 million spent in the same periods of 2012.

The majority of the capital expenditures in the fourth quarter and full-year of 2013 were in Pembina's Conventional Pipelines, Midstream and Gas Services businesses. Conventional Pipelines' capital was incurred to complete its Phase I expansion program, progress its numerous other expansions and on various new connections. Gas Services' capital was deployed to complete the Saturn I Facility and progress the Resthaven, Saturn II and Musreau II facilities. Midstream's capital expenditures were primarily directed towards RFS II, as well as cavern development and related infrastructure at the Redwater facility.

With respect to Pembina's planned capital expenditures for 2014, refer to "Conventional Pipelines - New Developments", "Oil Sands & Heavy Oil - New Developments", "Gas Services - New Developments" and "Midstream - New Developments." Also refer to "Risk Factors - Completion and Timing of Expansion Projects" and "Possible Failure to Realize Anticipated Benefits of Corporate Strategy."

Contractual Obligations at December 31, 2013

($ 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		548			30			109			103			306
Loans and borrowings^(1)		2,379			331			131			181			1,736
Convertible debentures^(1)		850			39			78			402			331
Construction commitments^(2)(3)		1,346			1,176			170
Provisions		309						7			27			275
Total contractual obligations^(2)		5,432			1,576			495			713			2,648

^(1)	Excluding deferred financing costs.
^(2)	Excluding significant projects that are awaiting regulatory approval.
^(3)	Including investment commitments to equity accounted investees of $24 million (2012: nil).

Pembina is, subject to certain conditions, contractually committed to the construction and operation of the Saturn II Facility, the Resthaven Facility, the Musreau II Facility, RFS II, as well as its Phase II and III pipeline expansions and certain caverns at its Redwater site. See "Forward-Looking Statements & Information."

Critical Accounting Estimates

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

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

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

Judgments

(i) Business combinations

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

(ii) 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) 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. 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 earnings can be affected as a result of changes in future depreciation and amortization, asset or goodwill impairment.

(ii) 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 most significant 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.

(iii) Income 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.

(iv) 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.

(v) Impairment tests

Annual goodwill impairment tests include management's estimates of future cash flows and discount rates.

Changes in Accounting Principles and Practices

The Company has adopted the following new standards and amendments to standards, including any consequential amendments to other standards, as of January 1, 2013. The nature and effects of the changes are explained below.

a) IFRS 7 Financial Instruments: Disclosures

As a result of the amendments to IFRS 7, the Company has expanded its disclosures about the offsetting of financial assets and financial liabilities (see Note 22).

b) IFRS 13 Fair Value Measurement

IFRS establishes a single framework for measuring fair value and making disclosures about fair value measurements when such measurements are required or permitted by other IFRSs. The change had no significant impact on the measurements of the Company's assets and liabilities.

c) IAS 19 Employment Benefits (2011)

As a result of IAS 19 (2011), the Company has changed its accounting policy with respect to the basis for determining the income or expense related to its post-employment defined benefit plan.

Under IAS 19 (2011), the Company determines net interest expense on the net defined benefit liability for the period by applying the discount rate used to measure the defined benefit obligation at the beginning of the annual period to the then-net defined benefit liability, taking into account any changes in the net defined benefit liability during the period as a result of contributions and benefit payments. Consequently, the net interest on the net defined benefit liability now comprises: interest cost on the defined benefit obligation and interest income on plan assets. Previously, the Company determined interest income on plan assets based on their long-term expected rate of return.

The quantitative impact is not material to the financial statements.

New Standards and Interpretations Not Yet Adopted

Certain new standards, interpretations, amendments and improvements to existing standards were issued by the International Accounting Standards Board or IFRS Interpretations Committee ("IFRIC") and are effective for accounting periods beginning on or after January 1, 2014. These standards have not been applied in preparing these consolidated financial statements nor does the Company expect to adopt them early. Those which may be relevant to Pembina are described below.

IFRS 9 (2010) Financial Instruments does not have a mandatory effective date but is available for adoption. The Company is currently evaluating the impact that the standard will have on its results of operations and financial position and is assessing when adoption will occur.

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

IFRIC 21 Levies interpretation is effective for annual periods beginning on or after January 1, 2014. The Company is currently evaluating the impact that the standard will have on its results of operations and financial position.

Controls and Procedures

Internal Control over Financial Reporting

Pembina maintains internal control over financial reporting which is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a - 15(f) and 15d - 15(f) under the United States Securities Exchange Act of 1934, as amended (the "Exchange Act") and under National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings ("NI 52-109").

Management, including the Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO"), has conducted an evaluation of Pembina's internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on management's assessment as at December 31, 2013, management has concluded that Pembina's internal control over financial reporting is effective.

The effectiveness of internal control over financial reporting as of December 31, 2013 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm, which is included in this 2013 Annual Report to Shareholders.

Due to its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of Pembina's financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

Changes in Internal Control over Financial Reporting

During the year, the Company completed the transition of internal controls of the entities acquired in the Acquisition. No additional changes were made in Pembina's internal control over financial reporting during the fiscal year ended December 31, 2013 that have materially affected or are reasonably likely to materially affect Pembina's internal control over financial reporting.

Disclosure Controls and Procedures

Pembina maintains disclosure controls and procedures designed to provide reasonable assurance that information required to be disclosed in Pembina's interim and annual filings is reviewed, recognized and disclosed accurately and in the appropriate time period.

An evaluation, as of December 31, 2013, of the effectiveness of the design and operation of Pembina's disclosure controls and procedures, as defined in Rule 13a - 15(e) and 15d - 15(e) under the Exchange Act and NI 52-109, was carried out by management, including the CEO and the CFO. Based on that evaluation, the CEO and CFO have concluded that the design and operation of Pembina's disclosure controls and procedures were effective to ensure that information required to be disclosed in the reports that Pembina files or submits under the Exchange Act or Canadian securities legislation is recorded, processed, summarized and reported within the time periods specified in the rules and forms therein.

It should be noted that while the CEO and CFO believe that Pembina's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that Pembina's disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Trading Activity and Total Enterprise Value⁽¹⁾

				As at and for the 12 months ended
($ millions, except where noted)		February 24, 2014^(2)			December 31, 2013			December 31, 2012
Trading volume and value
	Total volume (millions of shares)	18			142			180
	Average daily volume (shares)	490,773			565,821			718,397
	Value traded	695			4,580			5,022
Shares outstanding (millions of shares)		320			315			293
Closing share price (dollars)		40.07			37.42			28.46
Market value
	Common shares	12,805			11,793			8,345
	Series 1 Preferred Shares (PPL.PR.A)	239	^(3)		242	^(4)
	Series 3 Preferred Shares (PPL.PR.C)	149	^(5)		151	^(6)
	Series 5 Preferred Shares (PPL.PR.E)	259	^(7)
	5.75% convertible debentures (PPL.DB.C)	419	^(8)		396	^(9)		333	^(10)
	5.75% convertible debentures (PPL.DB.E)	148	^(11)		244	^(12)		201	^(13)
	5.75% convertible debentures (PPL.DB.F)	235	^(14)		219	^(15)		191	^(16)
Market capitalization		14,254			13,045			9,070
Senior debt		1,617			1,617			1,942
Total enterprise value^(17)		15,871			14,662			11,012

^(1)	Trading information in this table reflects the activity of Pembina securities on the TSX only.
^(2)	Based on 37 trading days from January 2, 2014 to February 24, 2014, inclusive.
^(3)	10 million preferred shares outstanding at a market price of $23.90 at February 24, 2014.
^(4)	10 million preferred shares outstanding at a market price of $24.26 at December 31, 2013.
^(5)	6 million preferred shares outstanding at a market price of $24.85 at February 24, 2014.
^(6)	6 million preferred shares outstanding at a market price of $25.15 at December 31, 2013.
^(7)	10 million preferred shares outstanding at a market price of $25.90 at February 24, 2014.
^(8)	$297 million principal amount outstanding at a market price of $141.25 at February 24, 2014 and with a conversion price of $28.55.
^(9)	$298.6 million principal amount outstanding at a market price of $132.63 at December 31, 2013 and with a conversion price of $28.55.
^(10)	$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.
^(11)	$92.3 million principal amount outstanding at a market price of $160.00 at February 24, 2014 and with a conversion price of $24.94.
^(12)	$162.5 million principal amount outstanding at a market price of $149.95 at December 31, 2013 and with a conversion price of $24.94.
^(13)	$172.2 million principal outstanding at a market price of $117.00 at December 31, 2012 and with a conversion price of $24.94.
^(14)	$171.6 million principal amount outstanding at a market price of $136.73 at February 24, 2014 and with a conversion price of $29.53.
^(15)	$172 million principal amount outstanding at a market price of $127.50 at December 31, 2013 and with a conversion price of $29.53.
^(16)	$172.4 million principal outstanding at a market price of $110.75 at December 31, 2012 with a conversion price of $29.53.
^(17)	Refer to "Non-GAAP and Additional GAAP Measures."

As indicated in the previous table, Pembina's total enterprise value was approximately $14.7 billion at December 31, 2013. The increase from 2012 was primarily due to more common shares outstanding, an increase in the price of Pembina's common shares and additional securities issued during 2013. The number of issued and outstanding shares rose to approximately 315 million at the end of 2013 compared to approximately 293 million at the end of 2012 primarily due to shares issued pursuant to the bought deal financing in the first quarter of 2013 and shares issued under the DRIP.

Common Share Dividends

Pembina announced on August 9, 2013, that it increased its monthly dividend rate by 3.7 percent from $0.135 per common share per month (or $1.62 annualized) to $0.14 per common share per month (or $1.68 annualized) effective as of the August 25, 2013 record date. 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 common share 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").

Common share 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.

Preferred Share Dividends

The holders of Series 1 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly on the 1st day of March, June, September and December, if, as and when declared by the Board of Directors of Pembina, for the initial fixed rate period to but excluding December 1, 2018. The dividend rate will reset on December 1, 2018 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.47 per cent.

The holders of Series 3 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.1750 per share, payable quarterly on the 1st day of March, June, September and December, if, as and when declared by the Board of Directors of Pembina, for the initial fixed rate period to but excluding March 1, 2019. The dividend rate will reset on March 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.60 per cent.

The holders of Series 5 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.25 per share, payable quarterly on the 1st day of March, June, September and December, as and when declared by the Board of Directors of Pembina, for the initial fixed rate period to but excluding June 1, 2019. The first quarterly dividend payment date is scheduled for March 1, 2014. The dividend rate will reset on June 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 3.00 per cent.

DRIP

Eligible Pembina shareholders have the opportunity to receive, by reinvesting the cash dividends declared payable by Pembina on their common 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 fourth quarter of 2013 was approximately 57 percent of common shares outstanding for proceeds of approximately $75 million. For the full-year of 2013, participation was also approximately 57 percent of common shares outstanding for proceeds of approximately $286 million.

Risk Factors

Pembina's value proposition is based on maintaining a low risk profile. In addition to contractually eliminating the majority of its business risk, Pembina has a formal Risk Management Program including policies, procedures and systems designed to mitigate any residual risks, such as market risk, counterparty credit risk and operational risk. For a full discussion of the risk factors affecting the business and operation of Pembina and its operating subsidiaries, readers are referred to Pembina's Annual Information Form ("AIF"), an electronic copy of which is available at www.pembina.com or on Pembina's SEDAR profile at www.sedar.com. Additional discussion about market risk, counterparty risk, liquidity risk and additional information on financial risk management can be found in Note 22 to the Consolidated Financial Statements.

Shareholders and prospective investors should carefully consider these risk factors before investing in Pembina's securities, as each of these risks may negatively affect the trading price of Pembina's securities, the amount of dividends paid to shareholders and the ability of Pembina to fund its debt obligations, including debt obligations under its outstanding convertible debentures and any other debt securities that Pembina may issue from time to time.

RISKS INHERENT IN PEMBINA'S BUSINESS

Operational Risks

Operational risks include: pipeline leaks; the breakdown or failure of equipment, information systems or processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); spills at truck terminals and hubs; spills associated with the loading and unloading of harmful substances onto rail cars and trucks; 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 Pembina's pipelines; and catastrophic events such as natural disasters, fires, explosions, fractures, acts of terrorists and saboteurs, and other similar events, many of which are beyond the control of Pembina. The occurrence or continuance of any of these events could increase the cost of operating Pembina's assets or reduce revenue, thereby impacting earnings.

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 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. Pembina's reputation could also be impacted by the actions and activities of other companies operating in the energy industry, especially other pipeline companies, over which it has no control. In particular, Pembina's reputation could be impacted by negative publicity related to pipeline incidents, unpopular expansion plans, and due to opposition from organizations opposed to oil sands development and shipment of production from oil sands regions. 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.

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. The 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 significant 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 the Company's operations, and the discovery of pre-existing environmental liabilities in relation to any of the Company's existing or future properties or operations, could result in significant costs and liabilities to the Company. In addition, the costs of environmental liabilities in relation to spill sites of which the Company is currently aware could be greater than the Company currently anticipates, and any such differences could be substantial. If the Company is 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 the Convertible Debentures and the Company's other debt obligations could be adversely affected.

While the Company 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 thereof in respect of certain occurrences unless they are discovered within fixed time periods, which typically range from 72 hours to 30 days. Although the Company believes it has adequate leak detection systems in place to monitor a significant spill of product, if the Company 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.

Abandonment Costs

The Company 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, including, in respect of certain pipeline systems, line fill, may be available to offset abandonment costs. However, it is not possible to predict abandonment costs since they will be a function of regulatory requirements at the time and the value of the Company's assets, including line fill, may then be more or less than abandonment costs. The Company 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 the Convertible Debentures and the Company's other debt obligations.

Pembina continues to work with the NEB and other shippers towards a pipeline abandonment fund collection plan and set aside mechanism as per the Land Matters Consultation Initiative for Pembina's rate regulated pipelines. Pembina's rate regulated pipelines account for less than 260 km, or three percent, of the total infrastructure in Conventional Pipelines.

Reserve Replacement, Throughput and Product Demand

The Company'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 the Company'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 or seek out lower cost alternatives for transportation. If the level of tariffs collected by the Company decreases as a result, cash flow available for dividends to shareholders and to service obligations under the Convertible Debentures and the Company's other debt obligations could be adversely affected.

Over the long term, the Company's business will depend, in part, on the level of demand for crude oil, condensate, NGL and natural gas in the markets served by the crude oil and NGL pipelines and gas processing and gathering infrastructure in which the Company has an interest. 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 economic, political and other conditions in other oil and natural gas regions, all of which are beyond the Company'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.

Completion and Timing of Expansion Projects

Many of Pembina's current growth projects are under development by the Company and the successful completion of these facilities and expansions is dependent on a number of factors outside of the Company's control, including availability of capital, receipt of regulatory approval and reaching long-term commercial arrangements with customers in respect of certain portions of the expansions, construction schedules and costs that may change depending on supply, demand and/or inflation, labour, materials and equipment availability, contractor non-performance, weather conditions, and cost of engineering services. 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, or that third parties will comply with contractual obligations in a timely manner. Factors such as special interest group opposition, changes in shipper support over time, and changes to the legislative or regulatory framework could all impact on contractual and regulatory milestones being accomplished. As a result, the cost estimates and completion dates for Pembina's major projects can change at different stages of the project. Early stage projects face additional challenges including right-of-way procurement and Aboriginal consultation requirements. Accordingly, actual costs can vary from initial estimates and these differences can be significant. Further, there is a risk that maintenance will be required more often than currently planned or that significant maintenance capital projects could arise that were not previously anticipated.

Under most of Pembina's construction and operation agreements, the Company is obligated to construct the facilities regardless of delays and cost increases and the Company bears the risk for any cost overruns, and future agreements with customers entered into with respect to expansions may contain similar conditions. While the Company is not currently aware of any undisclosed significant cost overruns at the date hereof, any such cost overruns in the future may adversely affect the economics of particular projects, as well as Pembina's business operations and financial results, and could reduce the Company's expected return which, in turn, could reduce the level of cash available for dividends to Shareholders.

Pembina's growth plans may strain its resources and may be subject to high cost pressures in the North American energy sector. 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. Pembina will attempt to mitigate capital constraints and cost escalation risks through structuring of commercial agreements 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.

Possible Failure to Realize Anticipated Benefits of Corporate Strategy

Pembina evaluates the value proposition for expansion projects, new acquisitions or divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility in the economy, change in cost estimates, project scoping and risk assessment could result in a loss in profits for the Company.

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 Simonette pipeline expansion, the Resthaven facility, the Saturn II facility, the Musreau II facility, and the RFS II project 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.

Debt Service

At the end of 2013, Pembina had exposure to floating interest rates on $46 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 less than $1 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 and dividends paid by Pembina.

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 common share dividends to shareholders. Variations in interest rates and scheduled principal repayments for which Pembina may not be able to 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 common share dividends to shareholders. Pembina, on a consolidated basis, is also required to meet certain financial covenants under the credit facilities 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.

The lenders under Pembina's unsecured credit facilities have also been provided with 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.

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.

Selected Quarterly Operating Information

		2013												2012												2011
	Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Average volume (mbpd unless stated otherwise)
Conventional Pipelines throughput		500			489			484			494			480			444			434			467			423
Oil Sands & Heavy Oil contracted capacity, end of period		880			880			870			870			870			870			870			870			870
Gas Services processing (mboe/d)^(1)		66			48			48			50			46			46			48			44			45
NGL sales volume		122			99			94			123			116			87			90
Total		1,568			1,516			1,496			1,537			1,512			1,447			1,442			1,381			1,338

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

Selected Quarterly Financial Information

		2013												2012												2011
($ millions, except where noted)		Q4			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Revenue			1,301			1,300			1,175			1,249			1,265			816			871			475			468
Operating expenses			101			87			91			77			86			69			68			48			55
Cost of goods sold, including product purchases			922			983			880			934			968			566			642			299			308
Realized (loss) gain on commodity-related derivative financial instruments			(3)			(4)			4			2			11			(3)			(13)						1
Operating margin^(1)			275			226			208			240			222			178			148			128			106
Depreciation and amortization included in operations			42			47			32			42			48			52			52			22			20
Unrealized gain (loss) on commodity-related derivative financial instruments			2			(2)			1			6			(2)			(23)			65			(4)			1
Gross profit			235			177			177			204			172			103			161			102			87
Adjusted EBITDA^(1)			235			201			185			210			199			154			126			111			88
Cash flow from operating activities			194			88			140			229			139			131			24			66			74
Cash flow from operating activities per common share ($ per share)			0.62			0.28			0.45			0.77			0.48			0.45			0.08			0.39			0.44
Adjusted cash flow from operating activities^(1)			180			189			144			207			172			133			90			99			66
Adjusted cash flow from operating activities per common share^(1)($ per share)			0.57			0.61			0.47			0.70			0.59			0.46			0.31			0.59			0.39
Earnings for the period			95			72			94			90			81			31			80			33			45
Basic and diluted earnings per common share ($ per share)			0.29			0.22			0.30			0.30			0.28			0.11			0.28			0.19			0.27
Common shares outstanding (millions):
	Weighted average (basic)		314			311			308			296			292			289			285			168			167
	Weighted average (diluted)		315			312			309			297			293			290			286			169			168
	End of period		315			312			310			307			293			291			288			169			168
Common share dividends declared			132			129			125			121			118			117			116			66			65
Common dividends per share ($ per share)			0.420			0.415			0.405			0.405			0.405			0.405			0.405			0.390			0.390
Preferred share dividends			5

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

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

• Increased oil production from customers operating in the Montney, Cardium and Deep Basin Cretaceous formations of west central Alberta, which resulted in increased service offerings, new connections and capacity expansions in these areas;
• Increased liquids-rich natural gas production from producers in the WCBS (Deep Basin, Montney and emerging Duvernay Shale plays), which resulted in increased gas gathering and processing at the Company's Gas Services assets, additional associated NGL transported on its pipelines and expansion of its fractionation capacity;
• New assets being placed into service;
• Improved propane industry fundamentals in Canada and North America;
• The Acquisition, which closed on April 2, 2012; and
• Increased shares outstanding due to: the Acquisition; the DRIP; and the bought deal equity financing in the first quarter of 2013.

Selected Annual Financial Information

($ millions, except where noted)				2013			2012			2011
Revenue				5,025			3,427			1,676
Earnings				351			225			166
	Per common share - basic and diluted			1.12			0.87			0.99
Total assets				9,142			8,284			3,339
Long-term financial liabilities^(1)				2,454			3,005			1,753
Declared dividends per common share ($ per share)				1.65			1.61			1.56

^(1)	Includes loans and borrowings, convertible debentures, long-term derivative financial instruments, provisions and employee benefits, share based payments and other.

Additional Information

Additional information about Pembina filed with Canadian and U.S. securities commissions, including quarterly and annual reports, AIFs (filed with the U.S. Securities and Exchange Commission under Form 40-F), Management Information Circulars and financial statements can be found online at www.sedar.com, www.sec.gov and at Pembina's website at www.pembina.com.

Non-GAAP and Additional 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 Non-GAAP and Additional GAAP financial measures do not have a standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies, securities regulations require that Non-GAAP and Additional GAAP financial measures are clearly defined, qualified and reconciled to their nearest GAAP measure. Except as otherwise indicated, these Non-GAAP and Additional GAAP measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

The intent of Non-GAAP and Additional GAAP measures is to provide additional useful information to investors and analysts and the measures do not have any standardized meaning under IFRS. The measures should not, therefore, be considered in isolation or used in substitute for measures of performance prepared in accordance with IFRS. Other issuers may calculate the Non-GAAP and Additional GAAP measures differently.

Investors should be cautioned that net revenue, 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.

Net revenue

Net revenue is a Non-GAAP financial measure which is defined as total revenue less cost of goods sold including product purchases. Management believes that net revenue provides investors with a single measure to indicate the margin on sales before non-product operating expenses that is comparable between periods. Management utilizes net revenue to compare consecutive results including the Midstream business, aggregate revenue results of each of the Company's businesses and set comparable objectives.

	3 Months Ended       December 31       (unaudited)						12 Months Ended       December 31
($ millions)		2013			2012			2013			2012
Total revenue		1,301			1,265			5,025			3,427
Cost of goods sold		922			968			3,719			2,475
Net revenue		379			297			1,306			952

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

EBITDA and adjusted EBITDA are Non-GAAP financial measures. EBITDA 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. The exclusion of unrealized gains or losses on commodity-related derivative financial instruments eliminates the non-cash impact. Adjusted EBITDA is EBITDA excluding acquisition-related expenses. Adjusted EBITDA excludes items of a non-recurring basis that do not reflect normal operations.

Management believes that EBITDA and adjusted EBITDA provide useful information to investors as they are an important indicator of the issuer's ability to generate liquidity through cash flow from operating activities and assist investors and creditors in the calculation of ratios for assessing leverage and financial performance. EBITDA and adjusted EBITDA are also used by investors and analysts for the purpose of valuing an issuer, including financial and leverage ratios. Management utilizes EBITDA and adjusted EBITDA to set objectives and as key performance indicators of the Company's success.

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions, except per share amounts)	2013			2012			2013			2012
Results from operating activities		191			144			660			415
Share of profit from equity accounted investees     (before tax, depreciation and amortization)		2			2			8			7
Depreciation and amortization		44			50			171			180
Unrealized loss (gain) on commodity-related derivative financial instruments		(2)			2			(7)			(36)
EBITDA		235			198			832			566
Add:
Acquisition-related expenses					1			(1)			24
Adjusted EBITDA		235			199			831			590
EBITDA per common share - basic (dollars)		0.75			0.68			2.71			2.19
Adjusted EBITDA per common share - basic (dollars)		0.75			0.68			2.71			2.28

Adjusted earnings

Adjusted earnings is a Non-GAAP financial measure which is calculated as earnings before tax excluding unrealized gains or losses on derivative financial instruments and acquisition-related expenses less preferred share dividends declared. Adjusted earnings excludes items of a non-recurring basis that do not reflect normal operations and preferred dividends as they are not attributable to common shareholders. Management believes that adjusted earnings provides useful information to investors by increasing the ability to predict and compare the financial performance of consecutive reporting periods. Management utilizes adjusted earnings to assess the performance of the Company.

	3 Months Ended       December 31       (unaudited)					12 Months Ended       December 31
($ millions, except per share amounts)	2013			2012			2013				2012
Earnings before income tax		136			108			494				300
Add (deduct):
Unrealized (gains) losses on fair value of derivative financial instruments		28			7			58				(40)
Preferred dividends declared		(5)						(5)
Acquisition-related expenses (recovery)					1			(1)				24
Adjusted earnings		159			116			546				284
Adjusted earnings per common share - basic (dollars)		0.51			0.40			1.78				1.10

Adjusted cash flow from operating activities

Adjusted cash flow from operating activities is a Non-GAAP financial measure which is defined as cash flow from operating activities plus the change in non-cash working capital and excluding preferred share dividends declared and acquisition-related expenses. Adjusted cash flow from operating activities excludes items of a non-recurring basis that do not reflect normal operations and preferred dividends because they are not attributable to common shareholders. Management believes that adjusted cash flow from operating activities provides comparable information to investors for assessing financial performance each reporting period. Management utilizes adjusted cash flow from operating activities to set objectives and as a key performance indicator of the Company's ability to meet interest obligations, dividend payments and other commitments.

	3 Months Ended       December 31       (unaudited)						12 Months Ended       December 31
($ millions, except per share amounts)		2013			2012			2013			2012
Cash flow from operating activities		194			139			651			360
Add (deduct):
Change in non-cash working capital		(9)			32			75			110
Preferred dividends declared		(5)						(5)
Acquisition-related expenses (recovery)					1			(1)			24
Adjusted cash flow from operating activities		180			172			720			494
Cash flow from operating activities per common share (dollars)		0.62			0.48			2.12			1.39
Adjusted cash flow from operating activities per common share - basic (dollars)		0.57			0.59			2.34			1.91

Operating margin

Operating margin is an Additional GAAP financial measure which is defined as gross profit before depreciation and amortization included in operations and unrealized gain/loss on commodity-related derivative financial instruments. Management believes that operating margin provides useful information to investors for assessing financial performance of the Company's operations. Management utilizes operating margin in setting objectives and a key performance indicator of the Company's success.

Reconciliation of operating margin to gross profit:

		3 Months Ended       December 31       (unaudited)						12 Months Ended       December 31
($ millions)		2013			2012			2013			2012
Revenue			1,301			1,265			5,025			3,427
Cost of sales
	Operations		101			86			356			271
	Cost of goods sold, including product purchases		922			968			3,719			2,475
	Realized (loss) gain on commodity-related derivative financial instruments		(3)			11			(1)			(5)
Operating margin			275			222			949			676
Depreciation and amortization included in operations			42			48			163			174
Unrealized (loss) gain on commodity-related derivative financial instruments			2			(2)			7			36
Gross profit			235			172			793			538

Total enterprise value

Total enterprise value is a Non-GAAP financial measure which is calculated by aggregating the market value of common shares, preferred shares and convertible debentures at a specific date plus senior debt. Management believes that total enterprise value provides useful information to investors to assess the overall market value of the business and as an input to calculate financial ratios. Management utilizes total enterprise value to assess Pembina's growth.

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", "projection", "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 and the tax treatment thereof;
• planning, construction, capital expenditure estimates, schedules, expected capacity, incremental volumes, in-service dates, rights, activities and operations with respect to new construction of, or expansions on existing, pipelines, gas services facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure;
• pipeline, processing and storage facility and system operations and throughput levels;
• Pembina's strategy and the development and expected timing of new business initiatives growth opportunities, and succession planning;
• increased throughput potential due to increased oil and gas industry activity and new connections and other initiatives on Pembina's pipelines;
• expected future cash flows and future financing options;
• tolls and tariffs and transportation, storage and services commitments and contracts;
• 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; and
• expectations around increases to employee compensation and contributions to pension plans (including the impact of share price on annual share-based incentive expense).

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:

• oil and gas industry exploration and development activity levels;
• 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;
• expectations regarding participation in Pembina's DRIP;
• future operating costs;
• geotechnical and integrity costs;
• in respect of current developments, expansions, planned capital expenditures, completion dates and capacity expectations: that third parties will provide any necessary support; that any thirdparty projects relating to Pembina's growth projects will be sanctioned and completed as expected; that any required commercial agreements can be reached; 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 the relevant facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;
• in respect of the stability of Pembina's dividends: 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;
• interest and tax rates; 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 relationships 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; and
• the other factors discussed under "Risk Factors" in Pembina's AIF for the year ended December 31, 2013. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com and in the U.S. on the Company's profile at www.sec.gov.

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

MANAGEMENT'S REPORT

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

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

Management's Assessment of Internal Controls over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a - 15(f) and 15d - 15(f) under the United States Securities Exchange Act of 1934, as amended (the "Exchange Act") and under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109").

Management, including the Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO"), has conducted an evaluation of Pembina's internal control over financial reporting based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

Based on management's assessment as at December 31, 2013, management has concluded that Pembina's internal control over financial reporting is effective.

Due to its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of Pembina's financial statements would be prevented or detected. Further, the evaluation of the effectiveness of internal control over financial reporting was made as of a specific date, and continued effectiveness in future periods is subject to the risks that controls may become inadequate.

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

KPMG LLP, the independent auditors, have audited the Company's financial statements in accordance with Canadian generally accepted auditing standards and Public Company Accounting Oversight Board (United States) , and have also audited the effectiveness of Pembina's internal control over financial reporting as of December 31, 2013 and has included an attestation report on management's assessment in their reports which follow. The independent auditors have full and unrestricted access to the Audit Committee to discuss their audit and their related findings.

Michael H. Dilger		Peter D. Robertson
President and Chief Executive Officer		Senior Vice President, Chief Financial Officer
Pembina Pipeline Corporation		Pembina Pipeline Corporation
February 26, 2014

INDEPENDENT AUDITORS' REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Pembina Pipeline Corporation

We have audited the accompanying consolidated financial statements of Pembina Pipeline Corporation (the "Corporation"), which comprise the consolidated statements of financial position as at December 31, 2013 and December 31, 2012, the consolidated statements of earnings and comprehensive income, changes in equity and cash flow for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

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

Auditors' Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

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

Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Corporation as at December 31, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation's internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992), and our report dated February 26, 2014 expressed an unmodified (unqualified) opinion on the effectiveness of the Corporation's internal control over financial reporting.

KPMG LLP

Chartered Accountants
Calgary, Canada

February 26, 2014

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Pembina Pipeline Corporation

We have audited Pembina Pipeline Corporation (the "Corporation") internal control over financial reporting as at December 31, 2013, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992). The Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report to the Shareholders. Our responsibility is to express an opinion on the Corporation's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

An entity's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992).

We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated statements of financial position of the Corporation as of December 31, 2013 and December 31, 2012, and the related consolidated statements of earnings and comprehensive income, changes in equity and cash flow for the years then ended, and our report dated February 26, 2014 expressed an unmodified (unqualified) opinion on those consolidated financial statements.

KPMG LLP

Chartered Accountants
Calgary, Canada

February 26, 2014

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
As at December 31 ($ millions)			Note			2013			2012
Assets Current assets
	Cash and cash equivalents					51			27
	Trade receivables and other		6			434			335
	Derivative financial instruments		22			4			8
	Inventory					159			108
						648			478
Non-current assets
	Property, plant and equipment		7			5,750			5,014
	Intangible assets and goodwill		8			2,564			2,623
	Investments in equity accounted investees		9			165			161
	Deferred tax assets		10			15			8
						8,494			7,806
Total Assets						9,142			8,284
Liabilities and Shareholders' Equity Current liabilities
	Trade payables and accrued liabilities		11			461			345
	Taxes payable					38
	Dividends payable					44			39
	Loans and borrowings		12			262			12
	Derivative financial instruments		22			13			16
						818			412
Non-current liabilities
	Loans and borrowings		12			1,409			1,933
	Convertible debentures		13			604			610
	Derivative financial instruments		22			107			52
	Employee benefits, share-based payments and other					25			49
	Provisions		14			309			361
	Deferred tax liabilities		10			699			592
						3,153			3,597
Total Liabilities						3,971			4,009
Equity
	Equity attributable to shareholders of the Company
	Common share capital		15			5,972			5,324
	Preferred share capital		15			391
	Deficit					(1,189)			(1,028)
	Accumulated other comprehensive income					(8)			(26)
						5,166			4,270
Non-controlling interest			27			5			5
Total Equity						5,171			4,275
Total Liabilities and Equity						9,142			8,284
See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF EARNINGS AND COMPREHENSIVE INCOME
Year Ended December 31 ($ millions, except per share amounts)			Note			2013			2012
Revenue			18			5,025			3,427
Cost of sales						4,238			2,920
Gain on commodity-related derivative financial instruments						6			31
Gross profit			18			793			538
	General and administrative					132			97
	Acquisition-related and other expense					1			26
						133			123
Results from operating activities						660			415
	Net finance costs		17			166			115
Earnings before income tax						494			300
	Current tax expense		10			38
	Deferred tax expense		10			105			75
	Income tax expense					143			75
Earnings for the year attributable to shareholders						351			225
Other comprehensive income (loss) that will never be reclassified to earnings
	Remeasurements of defined benefit liability					24			(15)
	Related tax					(6)			4
	Other comprehensive income (loss), net of tax		20			18			(11)
Total comprehensive income attributable to shareholders						369			214
Earnings per common share
	Basic and diluted earnings per common share (dollars)		19			1.12			0.87
See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
				Attributable to Shareholders of the Company
($ millions)		Note			Common Shares			Preferred Shares			Deficit			Accumulated Other Comprehensive Income			Total			Non- controlling Interest			Total Equity
December 31, 2011						1,812						(835)			(15)			962						962
Total comprehensive income
	Earnings											225						225						225
Other comprehensive income
	Defined benefit plan actuarial losses, net of tax		20												(11)			(11)						(11)
Total comprehensive income												225			(11)			214						214
Transactions with shareholders of the Company
	Dividend reinvestment plan		15			219												219						219
	Share-based payment transactions, debenture conversions and other		15			9												9						9
	Dividends declared - common		15									(418)						(418)						(418)
	Common shares issued on Acquisition		15			3,284												3,284						3,284
Total transactions with shareholders of the Company						3,512						(418)						3,094						3,094
Non-controlling interest assumed on Acquisition			27																		5			5
December 31, 2012						5,324						(1,028)			(26)			4,270			5			4,275
Total comprehensive income
	Earnings											351						351						351
Other comprehensive income
	Defined benefit plan actuarial gains, net of tax		20												18			18						18
Total comprehensive income												351			18			369						369
Transactions with shareholders of the Company
	Common shares issued, net of issue costs		15			335												335						335
	Preferred shares issued, net of issue costs		15						391									391						391
	Dividend reinvestment plan		15			286												286						286
	Share-based payment transactions, debenture conversions and other		15			27												27						27
	Dividends declared - common		15									(507)						(507)						(507)
	Dividends declared - preferred		15									(5)						(5)						(5)
Total transactions with shareholders of the Company						648			391			(512)						527						527
December 31, 2013						5,972			391			(1,189)			(8)			5,166			5			5,171

See accompanying notes to the consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31 ($ millions)			Note			2013			2012
Cash provided by (used in)
Operating activities
Earnings for the year						351			225
Adjustments for
	Depreciation and amortization					171			180
	Unrealized gain on commodity-related derivative financial instruments					(7)			(36)
	Net finance costs		17			166			115
	Deferred income tax expense		10			105			75
	Share-based payments expense		21			34			17
	Other					2			(5)
	Changes in non-cash working capital					(75)			(110)
	Payments from equity accounted investees					19			17
	Net interest paid		17			(115)			(118)
Cash flow from operating activities						651			360
Financing activities
	Bank borrowings					170			6
	Repayment of loans and borrowings					(649)			(61)
	Issuance of debt					200			450
	Issuance of common shares					345
	Issuance of preferred shares					400
	Financing fees					(29)			(7)
	Exercise of stock options					17			7
	Dividends paid (net of shares issued under the dividend reinvestment plan)					(221)			(181)
Cash flow from financing activities						233			214
Investing activities
	Capital expenditures					(880)			(584)
	Changes in non-cash investing working capital and other					33			37
	Contributions to equity accounted investees					(13)			(8)
	Cash acquired on Acquisition		27						9
Cash flow used in investing activities						(860)			(546)
Change in cash						24			28
Cash (bank indebtedness), beginning of year						27			(1)
Cash and cash equivalents end of year						51			27
See accompanying notes to the consolidated financial statements

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. REPORTING ENTITY

Pembina Pipeline Corporation ("Pembina" or the "Company") is an energy transportation and service provider domiciled in Canada. The consolidated financial statements ("Financial Statements") include the accounts of the Company, its subsidiary companies, partnerships and any interests in associates and jointly controlled entities as at and for the year ended December 31, 2013. These Financial Statements present fairly the financial position, financial performance and cash flows of the Company.

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

2. BASIS OF PREPARATION

a. Statement of compliance

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

Certain insignificant comparative amounts have been reclassified to conform with the presentation adopted in the current year.

The Financial Statements were authorized for issue by the Board of Directors on February 26, 2014.

b. Basis of measurement

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

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

c. Functional and presentation currency

The Financial Statements are presented in Canadian dollars, which is the functional currency of the Company and its subsidiaries. All financial information presented in Canadian dollars has been disclosed in millions except where noted.

d. Use of estimates and judgments

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

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

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

Judgments

(i) Business combinations

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

(ii) 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) 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. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities, intangible assets and goodwill in the purchase price analysis. Future earnings can be affected as a result of changes in future depreciation and amortization, asset or goodwill impairment.

(ii) 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 most significant uncertainties in estimating the provision are the discount rates used, the costs that will be incurred and the timing of when these costs will occur. In addition, in determining the provision it is assumed that the Company will utilize technology and materials that are currently available.

(iii) 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.

(iv) 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.

(v) Impairment tests

Annual goodwill impairment tests include management's estimates of future cash flows and discount rates.

3. CHANGES IN ACCOUNTING POLICIES

Except for the changes below, accounting policies as disclosed in Note 4 have been applied to all periods consistently.

The Company has adopted the following new standards and amendments to standards, including any consequential amendments to other standards, as of January 1, 2013. The nature and effects of the changes are explained below:

a) IFRS 7 Financial Instruments: Disclosures

As a result of the amendments to IFRS 7, the Company has reviewed and, when required, expanded its disclosures about the offsetting of financial assets and financial liabilities. The amendment has had no significant impact to the Company's disclosure in the financial statements.

b) IFRS 13 Fair Value Measurement

IFRS establishes a single framework for measuring fair value and making disclosures about fair value measurements when such measurements are required or permitted by other IFRSs. The change had no significant impact on the measurements of the Company's assets and liabilities.

c) IAS 19 Employee Benefits (2011)

As a result of IAS 19 (2011), the Company has changed its accounting policy with respect to the basis for determining the income or expense related to its post-employment defined benefit plan.

Under IAS 19 (2011), the Company determines net interest expense on the net defined benefit liability for the period by applying the discount rate used to measure the defined benefit obligation at the beginning of the annual period to the then-net defined benefit liability, taking into account any changes in the net defined benefit liability during the period as a result of contributions and benefit payments. Consequently, the net interest on the net defined benefit liability now comprises: interest cost on the defined benefit obligation and interest income on plan assets. Previously, the Company determined interest income on plan assets based on their long-term expected rate of return.

The quantitative impact is not material to the financial statements.

4. SIGNIFICANT ACCOUNTING POLICIES

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

a. Basis of consolidation

i) Business combinations

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

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

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

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

ii) Subsidiaries

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

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

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

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

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

iv) Jointly controlled operations

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

v) Transactions eliminated on consolidation

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

vi) Foreign currency

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

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

Foreign currency differences arising on retranslation are recognized in earnings.

b. Inventories

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

c. Financial instruments

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

i) Non-derivative financial assets

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

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

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

Cash and cash equivalents

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

Trade and other receivables

Trade and other receivables are financial assets with fixed or determinable payments that are not quoted in an active market.

Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, loans and receivables are measured at amortized cost using the effective interest method less any impairment losses.

ii) Non-derivative financial liabilities

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

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

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

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

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

iii) Common share capital

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

iv) Preferred share capital

Preferred shares are classified as equity because they bear discretionary dividends and do not contain any obligations to deliver cash or other financial assets. Discretionary dividends are recognized as equity distributions on approval by the Company's Board of Directors. Incremental costs directly attributable to the issue of preferred shares are recognized as a deduction from equity, net of any tax effects.

v) Compound financial instruments

The Company's convertible debentures are compound financial instruments consisting of a financial liability and an embedded conversion feature. In accordance with IAS 39, the embedded derivatives are required to be separated from the host contracts and accounted for as stand-alone instruments.

Debentures containing a cash conversion option allow Pembina to pay cash to the converting holder of the debentures, at the option of the Company. As such, the conversion feature is presented as a financial derivative liability within long-term derivative financial instruments. Debentures without a cash conversion option are settled in shares on conversion, and therefore the conversion feature is presented within equity, in accordance with its contractual substance.

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

vi) Derivative financial instruments

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

d. Property, plant and equipment

i) Recognition and measurement

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

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

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

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

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

ii) Subsequent costs

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

iii) Depreciation

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

Depreciation is recognized in earnings on a straight line or declining balance basis, which most closely reflects the expected pattern of consumption of the future economic benefits embodied in the asset. Pipeline assets and facilities are generally depreciated using the straight line method over 27 to 75 years (an average of 51 years) or declining balance method at rates ranging from 3 percent to 37 percent per annum (an average rate of 17 percent per annum). Facilities and equipment are depreciated using straight line method over 27 to 75 years (at an average rate of 38 years) or declining balance method at rates ranging from 8 to 37 percent (at an average rate of 19 percent per annum). Other assets are depreciated using the straight line method over 3 to 60 years (an average of 39 years) or declining balance method at rates ranging from 6 percent to 21 percent (at an average rate of 7 percent per annum). These rates are established to depreciate remaining net book value over the shorter of their useful lives, economic lives or contractual duration of the related assets.

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

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

e. Intangible assets

i) Goodwill

Goodwill that arises upon acquisitions is included in intangible assets. See Note 4(a)(i) for the policy on measurement of goodwill at initial recognition.

Subsequent measurement

Goodwill is measured at cost less accumulated impairment losses.

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

ii) Other intangible assets

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

iii) Subsequent expenditures

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

iv) Amortization

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

Amortization is recognized in earnings on a straight-line basis over the estimated useful lives of intangible assets, other than goodwill, from the date that they are available for use. The estimated useful lives of other intangible assets with finite useful lives range from 2 to 33 years (at an average of 19 years).

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

f. Leased assets

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

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

g. Lease payments

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

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

i) Determining whether an arrangement contains a lease

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

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

h. Impairment

i) Non-derivative financial assets

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

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

Trade receivables ("Receivables")

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

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

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

ii) Non-financial assets

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

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

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

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

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

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

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

i. Employee benefits

i) Defined contribution plans

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

ii) Defined benefit pension plans

A defined benefit pension plan is a post-employment benefit plan other than a defined contribution plan. The Company's net obligation in respect of Defined Benefit Pension Plans ("Plans") is calculated separately for each plan by estimating the amount of future benefit that employees have earned in return for their service in the current and prior periods, discounted to determine its present value, less the fair value of any plan assets. The discount rate used to determine the present value is established by referencing market yields on high-quality corporate bonds on the measurement date with cash flows that match the timing and amount of expected benefits.

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

When the benefits of a plan are improved, the portion of the increased benefit relating to past service by employees is recognized in earnings immediately.

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

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

iii) Short-term employee benefits

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

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

iv) Share-based payment transactions

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

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

j. Provisions

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

Decommissioning obligation

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

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

k. Revenue

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

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

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

l. Finance income and finance costs

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

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

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

m. Income tax

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

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

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

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

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

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

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

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

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

n. Earnings per common share

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

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

o. Segment reporting

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

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

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

p. Cash flow statements

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

q. New standards and interpretations not yet adopted

Certain new standards, interpretations, amendments and improvements to existing standards were issued by the IASB or International Financial Reporting Interpretations Committee ("IFRIC") for accounting periods beginning on or after January 1, 2014. The Company has reviewed these and determined the following:

IFRS 9 (2010) Financial Instruments: Does not have a mandatory effective date but is available for adoption. The Company is currently evaluating the impact that the standard will have on its results of operations and financial position and is assessing when adoption will occur.

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

IFRIC 21 Levies: Interpretation is effective for annual periods beginning on or after January 1, 2014. The Company is currently evaluating the impact that the standard will have on its results of operations and financial position.

5. DETERMINATION OF FAIR VALUES

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

i) Property, plant and equipment

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

ii) Intangible assets

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

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

iii) Derivatives

Fair value of derivatives are estimated by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, quoted market prices per share and volatility rates at the period ends.

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

iv) Non-derivative financial assets and liabilities

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

v) Share-based payment transactions

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

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

vi) Inventories

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

6. TRADE RECEIVABLES AND OTHER

December 31 ($ millions)			2013			2012
Trade accounts receivable from customers			419			313
Trade accounts receivable and other receivables from related parties						11
Prepayments			15			11
Total current trade and other receivables			434			335

7. PROPERTY, PLANT AND EQUIPMENT

($ millions)		Land and Land Rights			Pipelines			Facilities and Equipment			Linefill and Other			Assets Under Construction			Total
Cost
Balance at December 31, 2011		67			2,500			529			201			307			3,604
Acquisition (Note 27)		18			276			1,319			288			87			1,988
Additions		6			20			38			31			489			584
Change in decommissioning provision					(140)			(31)									(171)
Capitalized interest														14			14
Transfers		2			(61)			218			(14)			(145)
Disposals and other		(5)			(1)			(1)									(7)
Balance at December 31, 2012		88			2,594			2,072			506			752			6,012
Additions		7			104			285			56			425			877
Change in decommissioning provision					(19)			(8)									(27)
Capitalized interest					5			5						25			35
Transfers		11			105			320			130			(566)
Disposals and other					(6)			(4)			5						(5)
Balance at December 31, 2013		106			2,783			2,670			697			636			6,892
Depreciation
Balance at December 31, 2011		4			707			93			52						856
Depreciation					71			54			20						145
Transfers					1			25			(26)
Disposals					(2)						(1)						(3)
Balance at December 31, 2012		4			777			172			45						998
Depreciation		1			52			73			27						153
Transfers
Disposals and other					(5)			(4)									(9)
Balance at December 31, 2013		5			824			241			72						1,142
Carrying amounts
December 31, 2012		84			1,817			1,900			461			752			5,014
December 31, 2013		101			1,959			2,429			625			636			5,750

Property, plant and equipment under construction

Costs of assets under construction at December 31, 2013 totalled $636 million ($2012: $752 million) including capitalized borrowing costs.

For the year ended December 31, 2013, capitalized borrowing costs related to the construction of the new pipelines or facilities amounted to $35 million (2012: $14 million), with capitalization rates ranging from 4.4 percent to 5.0 percent (2012: 4.3 percent to 4.8 percent).

Commitments

At December 31, 2013, the Company has contractual commitments for the acquisition and or construction of property, plant and equipment of $1,322 million (December 31, 2012: $363 million).

8. INTANGIBLE ASSETS AND GOODWILL

		Intangible Assets
($ millions)	Goodwill	Purchase and Sale Contracts	Customer Relationships	Purchase Option	Total	Total Goodwill & Intangible Assets
Cost
Balance at December 31, 2011	223	23			23	246
Acquisition (Note 27)	1,753	157	227	277	661	2,414
Additions and other		5			5	5
Balance at December 31, 2012	1,976	185	227	277	689	2,665
Additions and other	(10)	3			3	(7)
Balance at December 31, 2013	1,966	188	227	277	692	2,658
Amortization
Accumulated amortization at    December 31, 2011		2			2	2
Amortization		25	15		40	40
Balance at December 31, 2012		27	15		42	42
Amortization		33	19		52	52
Balance at December 31, 2013		60	34		94	94
Carrying amounts
December 31, 2012	1,976	158	212	277	647	2,623
December 31, 2013	1,966	128	193	277	598	2,564

The purchase option of $277 million to acquire property, plant and equipment is not being amortized because it is not exercisable until 2018.

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

($ millions) December 31			2013			2012
Conventional Pipelines			316			316
Oil Sands and Heavy Oil			33			33
Gas Services			195			196
Midstream			2,020			2,078
			2,564			2,623

Impairment testing

For the purpose of impairment testing, goodwill is allocated to the Company's operating segments which represent the lowest level within the Company at which the goodwill is monitored for internal management purposes. Impairment testing for goodwill was performed at December 31, 2013. The recoverable amounts were based on their value in use and were determined to be higher than their carrying amounts.

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

Cash flows were projected based on past experience, actual operating results and the first 5 years of the business plan approved by management. Cash flows for periods up to 75 years were extrapolated using a constant medium-term inflation rate of 2 percent. Pre-tax discount rates between 8.6 percent and 9.4 percent were applied in determining the recoverable amount of the CGUs. The discount rates were estimated based on past experience, the Company's risk free rate and average cost of debt in addition to estimates of the specific CGU's equity risk premium, size premium, small capitalization premium, projection risk, betas, tax rate and industry targeted debt to equity ratios.

9. INVESTMENTS IN EQUITY ACCOUNTED INVESTEES

The Company has a 50 percent interest in two jointly controlled, equity accounted investees (Fort Saskatchewan Ethylene Storage Corporation and Fort Saskatchewan Ethylene Storage Limited Partnership) that are reported using the equity method of accounting. The carrying value of the investment at December 31, 2013 is $165 million (2012: $161 million).

At December 31, 2013, the Company has contractual commitments for additional investment in its equity accounted investees of $24 million (December 31, 2012: NIL).

10. INCOME TAXES

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

($ millions) December 31			2013			2012
Deferred income tax assets
Derivative financial instruments			6			23
Provisions			78			115
Benefit of loss carryforwards			14			77
Other deductible temporary differences			22			17
Deferred income tax liabilities
Property, plant and equipment			(588)			(590)
Intangible assets			(124)			(127)
Investments in equity accounted investees			(17)			(22)
Taxable limited partnership income deferral			(64)			(75)
Other taxable temporary differences			(11)			(2)
Net deferred tax liabilities^(1)			(684)			(584)

^(1)	The Company has recognized a net deferred tax asset of $15 million (December 31, 2012: $8 million) relating to its U.S. subsidiaries. The Company has determined that it is probable that future taxable profits will be sufficient to utilize the deferred tax asset.

The Company's consolidated effective tax rate for the year ended December 31, 2013 was 25 percent (2012: 25 percent).

Reconciliation of effective tax rate
	Year Ended December 31 ($ millions, except as noted)			2013			2012
	Earnings before income tax			494			300
	Statutory tax rate (percent)			25%			25%
	Income tax at statutory rate			124			75
	Tax rate changes on deferred income tax balances			1			2
	Changes in estimate and other			(2)			(2)
	Permanent items			13
	Other			7
	Income tax expense			143			75
Income tax expense
	Year Ended December 31 ($ millions)			2013			2012
	Current tax expense			38
	Deferred tax expense
	Origination and reversal of temporary differences			51			58
	Tax rate changes on deferred tax balances			1			2
	Decrease in tax loss carry forward			53			15
	Total deferred tax expense			105			75
	Total income tax expense			143			75
The movement of the net deferred tax liability is as follows:
	($ millions)			2013			2012
	Balance at January 1			584			107
	Deferred income tax expense			105			75
	Income tax expense (benefit) in other comprehensive income			6			(4)
	Acquisition (Note 27)			(3)			406
	Preferred share issue costs			(7)
	Other			(1)
	Balance at December 31			684			584
Deferred tax items recovered directly in equity
	Year Ended December 31 ($ millions)			2013			2012
	Preferred share issue costs			7
	Other comprehensive (income) loss			(6)			4
	Deferred tax items recovered directly in equity			1			4

Cash taxes received during the year were $2 million (2012: nil)

The Company has temporary differences associated with its investments in foreign subsidiaries, branches, and interests in joint ventures. At December 31, 2013, the Company has not recorded a deferred tax asset or liability for these temporary differences (December 31, 2012: nil) as the Company controls the timing of the reversal and it is not probable that the temporary differences will reverse in the foreseeable future.

At December 31, 2013, the Company had $37 million (December 31, 2012: $35 million) of U.S. tax losses that will expire after 2030. The Company has recorded deferred tax assets in respect of these losses, as it has been determined that it is probable that future taxable profits will be sufficient to utilize these losses.

11. TRADE PAYABLES AND ACCRUED LIABILITIES

December 31 ($ millions)		2013			2012
Trade payables		359			301
Non-trade payables & accrued liabilities		102			44
		461			345

12. LOANS AND BORROWINGS

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

Carrying value, terms and conditions, and debt maturity schedule

Terms and conditions of outstanding loans were as follows:

December 31 ($ millions)										Carrying amount
		Available facilities at December 31, 2013		Nominal interest rate			Year of maturity			2013			2012
Operating facility^(3)		30			prime + 0.45 or BA^(2)+ 1.45			2014^(1)
Revolving unsecured credit facility^(3)		1,500			prime + 0.45 or BA^(2) + 1.45			2018			46			521
Senior unsecured notes - Series A		175			5.99			2014			175			175
Senior unsecured notes - Series C		200			5.58			2021			197			197
Senior unsecured notes - Series D		267			5.91			2019			266			265
Senior unsecured term facility		75			6.16			2014			75			75
Senior unsecured medium-term notes 1		250			4.89			2021			249			249
Senior unsecured medium-term notes 2		450			3.77			2022			448			448
Senior unsecured medium-term notes 3		200			4.75			2043			198
Subsidiary debt		8			5.04			2014			8			9
Finance lease liabilities											9			6
Total interest bearing liabilities		3,155									1,671			1,945
Less current portion											(262)			(12)
Total non-current											1,409			1,933

^(1)	Operating facility expected to be renewed on an annual basis.
^(2)	Bankers' Acceptance.
^(3)	The nominal interest rate is based on the Company's credit rating at December 31, 2013.

All facilities are governed by specific debt covenants which Pembina has been in compliance with during the years ended December 31, 2013 and 2012.

For more information about the Company's exposure to interest rate, foreign currency and liquidity risk, see financial instruments and financial risk management Note 22.

13. CONVERTIBLE DEBENTURES

($ millions, except as noted)		Series C - 5.75%			Series E - 5.75%			Series F - 5.75%				Total
Conversion price (dollars)		$28.55			$24.94			$29.53
Interest payable semi-annually in arrears on:		May 31 and November 30			June 30 and December 31			June 30 and December 31
Maturity date		November 30, 2020			December 31, 2017			December 31, 2018
Balance at December 31, 2011		289										289
Assumed on Acquisition^(1) (Note 27)					159			158				317
Conversions and redemptions					(1)							(1)
Accretion of liability					1			1				2
Deferred financing fees (net of amortization)		1			1			1				3
Balance at December 31, 2012		290			160			160				610
Conversions and redemptions		(1)			(9)			(1)				(11)
Accretion of liability					1			1				2
Deferred financing fee (net of amortization)		1			1			1				3
Balance at December 31, 2013		290			153			161				604

^(1)	Excludes conversion feature of convertible debentures which is recognized in derivative financial instruments.

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

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

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

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

14. PROVISIONS

The Company has estimated the net present value of its total decommissioning obligations based on a total future liability of $309 million. The estimate has applied a medium-term inflation rate and current discount rate and includes a revision in the decommissioning assumptions and associated costs and timing of payments. The obligations are expected to be paid over the next 75 years with majority being paid between 30 and 40 years. The Company applied a 2 percent inflation rate per annum and a risk free rate of 3.2 percent (2012: 2.4 percent) to calculate the present value of the decommissioning provision. The remeasured decommissioning provision decreased property, plant and equipment and decommissioning provision liability. Of the re-measurement reduction of the decommissioning provision, $33 million (2012: $6 million) was in excess of the carrying amount of the related asset and was credited to depreciation expense.

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

($ millions)			2013			2012
Balance at January 1			361			416
Unwinding of discount rate			9			12
Decommissioning liabilities settled during the period			(1)			(5)
Change in rates			(88)			(47)
Change in estimates and other			28			(139)
Assumed on Acquisition (Note 27)						125
Total			309			362
Less current portion (included in accrued liabilities)						(1)
Balance at December 31			309			361

15. SHARE CAPITAL

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

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

Common Share Capital

($ millions, except as noted)		Number of Common Shares (thousands)			Common Share Capital
Balance at December 31, 2011		167,908			1,812
Dividend reinvestment plan		8,338			219
Share-based payment transactions, debenture conversions and other		444			9
Issued on Acquisition (Note 27)		116,536			3,284
Balance at December 31, 2012		293,226			5,324
Issued, net of issue costs		11,207			335
Dividend reinvestment plan		9,384			286
Share-based payment transactions, debenture conversions and other		1,327			27
Balance at December 31, 2013		315,144			5,972
Preferred Share Capital
($ millions, except as noted)		Number of Preferred Shares (thousands)			Preferred Share Capital
Balance at December 31, 2012 and 2011
Class A, Series 1 Preferred shares issued, net of issue costs		10,000			244
Class A, Series 3 Preferred shares issued, net of issue costs		6,000			147
Balance at December 31, 2013		16,000			391

On July 26, 2013, Pembina issued 10,000,000 cumulative redeemable 5-year rate reset Class A Preferred shares, Series 1 ("Series 1 Preferred Shares") at a price of $25.00 per Series 1 Preferred Share for aggregate proceeds of $250 million. The holders of Series 1 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share when declared by the Board of Directors. The dividend rate will reset on December 1, 2018 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.47 percent. The Series 1 Preferred Shares are redeemable by the Company at the Company's option on December 1, 2018 and on December 1 of every fifth year thereafter.

Holders of the Series 1 Preferred Shares have the right to convert all or any part of their shares into cumulative redeemable floating rate Class A Preferred shares, Series 2 ("Series 2 Preferred Shares"), subject to certain conditions, on December 1, 2018 and on December 1 of every fifth year thereafter. Holders of Series 2 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 2.47 percent, if, as and when declared by the Board of Directors of Pembina.

On October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset Class A Preferred shares, Series 3 (the "Series 3 Preferred Shares") at a price of $25.00 per share for aggregate proceeds of $150 million. The holders of Series 3 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.1750 per share, if, as and when declared by the Board of Directors. The dividend rate will reset on March 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.60 percent. The Series 3 Preferred Shares are redeemable by the Company at its option on March 1, 2019 and on March 1 of every fifth year thereafter.

Holders of the Series 3 Preferred Shares have the right to convert their shares into cumulative redeemable floating rate Class A Preferred shares, Series 4 ("Series 4 Preferred Shares"), subject to certain conditions, on March 1, 2019 and on March 1 of every fifth year thereafter. Holders of Series 4 Preferred Shares will be entitled to receive a cumulative quarterly floating dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 2.60 percent, if, as and when declared by the Board of Directors of Pembina.

Dividends

The Company has a Premium Dividend™ and Dividend Reinvestment Plan. Eligible common shareholders have the opportunity to receive additional common shares by reinvesting the cash dividends declared payable by the Company on its common shares.

The following dividends were declared by the Company:

Year Ended December 31 ($ millions)				2013			2012
Common shares
	$1.65 per qualifying share (2012: $1.61)			507			418
Preferred shares
	$.3726 per qualifying Series 1 share (2012: nil)			4
	$.1932 per qualifying Series 3 share (2012: nil)			1
				5

On January 7, 2014 and February 10, 2014, Pembina announced that the Board of Directors declared a dividend for each of January and February of $0.14 per qualifying common share ($1.68 annualized) in the total amount of approximately $90 million.

On January 7, 2014, Pembina announced that the Board of Directors had declared a quarterly dividend of $0.265625 per Series 1 Class A Preferred Share to be paid to holders of Series 1 Class A Preferred Shares of record on February 1, 2014, and a dividend of $0.29375 per Series 3 Class A Preferred Share to holders of Series 3 Class A Preferred Shares of record on February 1, 2014 in the amount of $4 million.

On January 16, 2014, Pembina announced the initial dividend on the Series 5 Class A Preferred Shares, to be paid on March 1, 2014 to holders of Series 5 Class A Preferred Shares of record on February 1, 2014 for the period commencing on the date of issuance (January 16, 2014) up to but excluding February 28, 2014 in the amount of $0.1507 per share in the total amount of $2 million.

16. PERSONNEL EXPENSES

Year Ended December 31 ($ millions)			2013			2012
Salaries and wages			118			85
Share-based payment transactions			34			17
Short-term incentive plan			26			11
Pension plan expense			12			9
Health, savings plan and other benefits			10			9
Personnel expenses			200			131

17. NET FINANCE COSTS

Year Ended December 31 ($ millions)			2013			2012
Interest income from:
	Bank deposits and other		(5)			(1)
Interest expense on financial liabilities measured at amortized cost:
	Loans and borrowings		55			73
	Convertible debentures		42			36
	Unwinding of discount		9			12
Gain in fair value of non-commodity-related derivative financial instruments			(6)			(4)
Loss on revaluation of conversion feature of convertible debentures			71
Foreign exchange gains and other						(1)
Net finance costs			166			115

Net interest paid of $115 million (2012: $118 million) includes capitalized borrowing costs of $35 million (2012: $14 million).

18. OPERATING SEGMENTS

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

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

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

Gas Services consists of natural gas gathering and processing facilities, including four gas plants, twelve compressor stations and over 350 kilometres of gathering systems.

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

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

Year Ended December 31, 2013 ($ millions)			Conventional Pipelines^(1)			Oil Sands & Heavy Oil			Gas Services			Midstream^(2)			Corporate & Intersegment Eliminations			Total
Revenue:
	Pipeline transportation		411			195									(49)			557
	Terminalling, storage and hub services											4,347						4,347
	Gas Services								121									121
Total revenue			411			195			121			4,347			(49)			5,025
	Operating expenses		162			64			43			91			(4)			356
	Cost of goods sold, including product purchases											3,767			(48)			3,719
	Realized gain (loss) on commodity-related   derivative financial instruments		2									(3)						(1)
Operating margin			251			131			78			486			3			949
	Depreciation and amortization included   in operations		12			17			20			114						163
	Unrealized gain on commodity-related   derivative financial instruments		1									6						7
Gross profit			240			114			58			378			3			793
	Depreciation included in general and administrative														8			8
	Other general and administrative		9			3			6			25			81			124
	Acquisition-related and other expenses (income)		2									1			(2)			1
Reportable segment results from operating activities			229			111			52			352			(84)			660
Net finance costs (income)			5			1			1			(4)			163			166
Reportable segment earnings (loss) before tax			224			110			51			356			(247)			494
Capital expenditures			325			38			258			254			5			880

^(1)	5.2 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
^(2)	NGL product and services, terminalling, storage and hub services revenue includes $158 million associated with U.S. midstream sales.

Year Ended December 31, 2012 ($ millions)			Conventional Pipelines^(1)			Oil Sands & Heavy Oil			Gas Services			Midstream^(2)			Corporate & Intersegment Eliminations			Total
Revenue:
	Pipeline transportation		339			172									(19)			492
	NGL product and services, terminalling, storage and hub services											2,847						2,847
	Gas Services								88									88
Total revenue			339			172			88			2,847			(19)			3,427
	Operating expense		130			55			29			60			(3)			271
	Cost of goods sold, including product purchases											2,494			(19)			2,475
	Realized loss on commodity-related derivative financial instruments											(5)						(5)
Operating margin			209			117			59			288			3			676
	Depreciation and amortization included in operations		44			20			15			95						174
	Unrealized gain (loss) on commodity-related derivative financial instruments		(9)									45						36
Gross profit			156			97			44			238			3			538
	Depreciation included in general and administrative														6			6
	Other general and administrative		7			2			4			15			63			91
	Acquisition-related and other expenses		1									2			23			26
Reportable segment results from operating activities			148			95			40			221			(89)			415
Net finance costs			6			2						3			104			115
Reportable segment earnings (loss) before tax			142			93			40			218			(193)			300
Capital expenditures			187			30			163			204						584

^(1)	5.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
^(2)	NGL product and services, terminalling, storage and hub services revenue includes $97 million associated with U.S. midstream sales.

19. EARNINGS PER COMMON SHARE

Basic earnings per common share

The calculation of basic earnings per common share at December 31, 2013 was based on the earnings attributable to common shareholders of $344 million (2012: $225 million) and a weighted average number of common shares outstanding of 307 million (2012: 259 million).

Diluted earnings per common share

The calculation of diluted earnings per common share at December 31, 2013 was based on earnings attributable to common shareholders of $344 million (December 31, 2012: $225 million), and weighted average number of common shares outstanding after adjustment for the effects of all dilutive potential common shares of 308 million (2012: 259 million).

Earnings attributable to common shareholders
	Year Ended December 31 ($ millions)			2013			2012
	Earnings			351			225
	Dividends on preferred shares			(5)
	Cumulative dividends on preferred shares, not yet declared			(2)
	Earnings contributable to common shareholders (basic and diluted)			344			225
Weighted average number of common shares
	(In thousands of shares, except as noted)			2013			2012
	Issued common shares at January 1			293,226			167,908
	Effect of shares issued			8,781			87,243
	Effect of share options exercised			350			185
	Effect of conversion of convertible debentures			83			9
	Effect of shares issued under dividend reinvestment plan			4,771			3,524
	Weighted average number of common shares at December 31 (basic)			307,211			258,869
	Dilutive effect of share options on issue			870			614
	Weighted average number of common shares at December 31 (diluted)			308,081			259,483
	Basic and diluted earnings per common share (dollars)			$1.12			$0.87

At December 31, 2013, the effect of the conversion of the convertible debentures was excluded from the diluted earnings per common share calculation as the impact was anti-dilutive. If the convertible debentures were included, an additional 23 million (2012: 23 million) common shares would be added to the weighted average number of common shares and $32 million (2012: $27 million) would be added to earnings, representing after tax interest expense of the convertible debentures.

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

20. PENSION PLAN

December 31 ($ millions)			2013			2012
Registered defined benefit (asset) obligation			(5)			22
Supplemental defined benefit obligation			7			6
Other accrued benefit obligations			1			1
Net employee benefit obligations			3			29

The Company maintains a defined contribution plan and non-contributory defined pension plans covering its employees. The Company contributes 5 to 10 percent of an employee's earnings to the defined contribution plan until the employee's age plus years of service equals 50, at which time they become eligible for the defined benefit plans. The defined benefit plans include a funded registered plan for all employees and an unfunded supplemental retirement plan for those employees affected by the Canada Revenue Agency maximum pension limits. The Company also has other accrued benefit obligations which include a non-contribution unfunded post employment extended health and dental plan provided to a few remaining retired employees. The defined benefit plans are administered by a single pension fund that is legally separated from the Company. Benefits under the plans are based on the length of service and the annual average best three years of earnings during the last ten years of service of the employee. Benefits paid out of the plans are not indexed. The Company measures its accrued benefit obligations and the fair value of plan assets for accounting purposes as at December 31 of each year. The most recent actuarial valuation was at December 31, 2012.

The defined benefit plans expose the Company to actuarial risks such as longevity risk, interest rate risk, and market (investment) risk.

Defined benefit obligations

December 31	2013						2012
($ millions)	Registered Plan			Supplemental Plan			Registered Plan			Supplemental Plan
Present value of unfunded obligations					7						6
Present value of funded obligations		119						122
Total present value of obligations		119			7			122			6
Fair value of plan assets		124						100
Recognized asset (liability) for defined benefit obligations		5			(7)			(22)			(6)

The Company funds the defined benefit obligation plans in accordance with government regulations by contributing to trust funds administered by an independent trustee. The funds are invested primarily in equities and bonds. Defined benefit plan contributions totalled $13 million for the year ended December 31, 2013 (2012: $10 million).

The Company has determined that, in accordance with the terms and conditions of the defined benefit plans, and in accordance with statutory requirements of the plans, the present value of refunds or reductions in future contributions is not lower than the balance of the total fair value of the plan assets less the total present value of obligations. As such, no decrease in the defined benefit asset is necessary at December 31, 2013 and December 31, 2012.

Registered defined benefit pension plan assets comprise
December 31 (percentages)								2013			2012
Equity securities								64			65
Debt								35			30
Other								1			5
								100			100
Movement in the present value of the defined benefit pension obligation
Year Ended December 31	2013						2012
($ millions)	Registered Plan			Supplemental Plan			Registered Plan			Supplemental Plan
Defined benefits obligations at January 1		122			6			100			5
Benefits paid by the plan		(6)						(6)
Current service costs		9			1			7
Interest expense		5						5
Actuarial (gains) losses in other comprehensive income		(11)						16			1
Defined benefit obligations at December 31		119			7			122			6
Movement in the present value of registered defined benefit pension plan assets
Year Ended December 31 ($ millions)								2013			2012
Fair value of plan assets at January 1								100			89
Contributions paid into the plan								13			10
Benefits paid by the plan								(6)			(6)
Return on plan assets								12			2
Interest income								5			5
Fair value of registered plan assets at December 31								124			100
Expense recognition in earnings
Registered Plan								2013			2012
Year Ended December 31 ($ millions)
Current service costs								9			7
Interest on obligation								5			5
Expected return on plan assets								(4)			(5)
								10			7
The expense is recognized in the following line items in the statement of comprehensive income:
Registered Plan								2013			2012
Year Ended December 31($ millions)
Operating expenses								5			4
General and administrative expense								5			3
								10			7

Expense recognized for the Supplemental Plan was less than $1 million for each of the years ended December 31, 2013 and 2012.

Actuarial gains and losses recognized in other comprehensive income

		2013						2012
($ millions)		Registered Plan		Supplemental Plan		Total		Registered Plan		Supplemental Plan		Total
Balance at January 1		(25)		(1)		(26)		(15)				(15)
Remeasurements gain:
	Actuarial gain (loss) arising from
	Demographic assumptions	(2)				(2)				(5)		(5)
	Financial assumptions	7				7		(12)				(12)
	Experience adjustments	4				4				4		4
Return on plan assets excluding interest income		9				9		2				2
Recognized during the period after tax		18				18		(10)		(1)		(11)
Balance at December 31		(7)		(1)		(8)		(25)		(1)		(26)
Principal actuarial assumptions used:
December 31 (weighted average percent)										2013		2012
Discount rate										4.9%		4.4%
Future pension earning increases										4.0%		4.0%

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

December 31 (years)							2013						2012
Longevity at age 65 for current pensioners
Males							21.3						19.8
Females							23.5						22.1
Longevity at age 65 for current member aged 45
Males							22.4						21.3
Females							24.2						22.9

The calculation of the defined benefit obligation is sensitive to the discount rate, compensation increases, retirements and termination rates as set out above. An increase or decrease of the estimated discount rate of 4.9 percent by 100 basis points at December 31, 2013 is considered reasonably possible in the next financial year but would not have a material impact on the obligation.

The Company expects to contribute $10 million to the defined benefit plans in 2014.

21. SHARE-BASED PAYMENTS

At December 31, 2013, the Company has the following share-based payment arrangements:

Share option plan (equity settled)

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

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

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

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

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

Grant date share options granted to employees (thousands of options, except as noted)			Number of options			Contractual life of options
January 3, 2012			55			7 years
April 2, 2012			19			7 years
August 9, 2012			1,372			7 years
October 1, 2012			49			7 years
January 2, 2013			61			7 years
April 1, 2013			52			7 years
August 9, 2013			1,605			7 years
October 1, 2013			70			7 years

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

Long-term share unit award incentive plan⁽¹⁾

Grant date PSUs to Officers, Non-Officers^(2) and Directors (thousands of units, except as noted)				Units				Contractual life of PSU
January 1, 2012				188				3.0 years
April 2, 2012 (on Acquisition)				201				2.2 years
January 1, 2013				292				3.0 years

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

Grant date RSUs to Officers, Non-Officers^(2) and Directors (thousands of units, except as noted)				Units				Contractual life of RSU
January 1, 2012				186				3.0 years
April 2, 2012 (on Acquisition)				177				2.2 years
January 1, 2013				285				3.0 years

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

^(1)	Distribution Units are granted in addition to RSU and PSU grants based on notional accrued dividends from RSU and PSU granted but not paid.
^(2)	Non-Officers defined as senior selected positions within the Company.

Disclosure of share option plan

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

(thousands of options, except as noted)			Number of Options			Weighted Average Exercise Price (dollars)
Outstanding at December 31, 2011			2,674			$20.24
Granted			1,495			$26.70
Exercised			(428)			$16.96
Forfeited			(209)			$24.73
Outstanding at December 31, 2012			3,532			$23.11
Granted			1,787			$32.17
Exercised			(887)			$19.08
Forfeited or expired			(233)			$26.14
Outstanding as at December 31, 2013			4,199			$27.65

As of December 31, 2013, the following options are outstanding:

(thousands of options, except as noted) Exercise Price (dollars)			Number outstanding at December 31, 2013			Options Exercisable			Weighted average remaining life
$14.18 - $17.99			117			117			1.92 years
$18.00 - $20.99			419			417			3.65 years
$21.00 - $29.99			1,957			752			5.25 years
$30.00 - $33.93			1,706			12			6.56 years
Total			4,199			1,298

The weighted average share price at the date of exercise for share options exercised in the year ended December 31, 2013 was $33.12 (December 31, 2012: $28.28).

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

Share options granted

Year Ended December 31 (dollars, except as noted)							2013						2012
Weighted average
	Fair value at grant date						2.59						2.10
	Share price at grant date						31.60						26.68
	Exercise price						32.17						26.70
	Expected volatility (percent)						20.6						21.4
	Expected option life (years)						3.67						3.67
Expected annual dividends per option							1.65						1.61
Expected forfeitures (percent)							7.9						7.9
Risk-free interest rate (based on government bonds)(percent)							1.4						1.3

Disclosure of long-term share unit award incentive plan

The long-term share unit award incentive plan was valued using the reporting date market price of the Company's shares of $37.42 (December 31, 2012: $28.46). Actual payment may differ from amount valued based on market price and company performance.

Long-term share unit award incentive units granted

Year Ended December 31 (thousands of share units)																														2013						2012
Number of share units granted																														577						752

Employee expenses

Year Ended December 31 ($ millions)				2013						2012
Share option plan, equity settled				3						2
Long-term share unit award incentive plan				31						15
Share based payment expense				34						17
Total carrying amount of liabilities for cash settled arrangements				48						34
Total intrinsic value of liability for vested benefits				30						16

22. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

Risk Management

Pembina has exposure to counterparty credit risk, liquidity risk and market risk. Pembina recognizes that effective management of these risks is a critical success factor in managing organization and shareholder value.

Risk management strategies, policies and limits ensure risks and exposures are aligned to Pembina's business strategy and risk tolerance. The Company's Board of Directors is responsible for providing risk management oversight at Pembina. The Company's Audit Committee oversees how management monitors compliance with the Company's risk management policies and procedures and reviews the adequacy of this risk framework in relation to the risks faced by the Company. Internal audit personnel assist the Audit Committee in its oversight role by monitoring and evaluating the effectiveness of the organization's risk management system.

Counterparty credit risk

Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its contractual obligations in accordance with the terms and conditions of the financial instruments with the Company. Counterparty credit risk arises primarily from the Company's cash and cash equivalents, trade and other receivables, and from counterparties to its derivative financial instruments. The carrying amount of the Company's cash and cash equivalents, trade and other receivables and derivative financial instruments represents the maximum counterparty credit exposure, without taking into account security held.

The Company manages counterparty credit risk through established credit management techniques, including conducting comprehensive financial and other assessments for all new counterparties and regular reviews of existing counterparties to establish and monitor a counterparty's creditworthiness, setting exposure limits, monitoring exposures against these limits and obtaining financial assurances where warranted. The Company utilizes various sources of financial, credit and business information in assessing the creditworthiness of a counterparty including external credit ratings, where available, and in other cases, detailed financial statement analysis in order to generate an internal credit rating based on quantitative and qualitative factors. The establishment of counterparty exposure limits is governed by a Board of Directors designated counterparty exposure limit matrix which represents the maximum dollar amounts of counterparty exposure by debt rating that can be approved for a counterparty. The Company continues to closely monitor and reassess the creditworthiness of its counterparties, which has resulted in the Company reducing or mitigating its exposure to certain counterparties where it was deemed warranted and permitted under contractual terms.

Financial assurances may include guarantees, letters of credit and cash. Letters of credit are held on $51 million (December 31, 2012: $45 million) of the receivables balance.

Typically, the Company has collected its receivables in full and at December 31, 2013, approximately 86 percent were current. The Company has a general lien and a continuing and first priority security interest in, and a secured charge on, all of a shipper's petroleum in its custody. The risk of non-collection is considered to be low and no impairment of trade and other receivables has been made.

The Company monitors and manages its concentration of counterparty credit risk on an ongoing basis. The Company believes these measures minimize its counterparty credit risk but there is no certainty that they will protect it against all material losses. As part of its ongoing operations, the Company must balance its market and counterparty credit risks when making business decisions.

Liquidity risk

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

									Outstanding balances due by period
December 31, 2013 ($ millions)			Carrying Amount			Expected Cash Flows			Less Than 1 Year		1 - 2 Years		2 - 5 Years		More Than 5 Years
Trade payables and accrued liabilities			461			461			461
Taxes payable			38			38			38
Loans and borrowings			1,671			2,387			334		68		250		1,735
Convertible debentures			604			850			39		39		441		331
Dividends payable			44			44			44
Derivative financial liabilities			120			120			13		5		102
Operating and finance leases						548			30		54		158		306
Construction commitments						1,346			1,176		170

The Company manages its liquidity risk by forecasting cash flows over a 12 month rolling time period to identify financing requirements. These financing requirements are then addressed through a combination of credit facilities and through access to capital markets, if required.

Market risk

Pembina's results are subject to movements in commodity prices, foreign exchange and interest rates. A formal Risk Management Program including policies and procedures has been designed to mitigate these risks.

a. Commodity price risk

Pembina's Midstream business is exposed to changes in commodity prices as a result of frac spread risk or the relative price differential between the input cost of the natural gas required to produce NGL products and the price in which they are sold. Pembina responds to commodity price risk by using an active Risk Management Program to fix revenues on a minimum of 50 percent of the committed term natural gas supply costs. Pembina's Midstream business is also exposed to variability in quality, time and location differentials. The Company utilizes financial derivative instruments as part of its overall risk management strategy to assist in managing the exposure to commodity price risk as a result of these activities. The Company does not trade financial instruments for speculative purposes.

b. Foreign exchange risk

Pembina's commodity-related cash flows are subject to currency risk, primarily arising from the denomination of specific cash flows in US dollars. Pembina responds to this risk using an active Risk Management Program to exchange foreign currency for domestic currency at a fixed rate.

c. Interest rate risk

Pembina has floating interest rate debt which subjects the Company to interest rate risk. Pembina responds to this risk under the active Risk Management Program to enter into financial derivative contracts to fix interest rates.

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

		Carrying Amounts of Financial Liability
December 31 ($ millions)		2013		2012
Fixed rate instruments		(1,625)		(1,424)
Variable rate instruments		(46)		(521)
		(1,671)		(1,945)

Cash flow sensitivity analysis for variable rate instruments

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

December 31 ($ millions)				2013				2012
				± 100 bp				± 100 bp
Variable rate instruments				± 1				± 5
Interest rate swap								± (4)
Earnings sensitivity (net)				± 1				± 1

Fair values

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

December 31		2013				2012
($ millions)		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets carried at fair value
Derivative financial instruments		4		4		8		8
Financial assets carried at amortized cost
Cash and cash equivalents		51		51		27		27
Trade and other receivables		434		434		335		335
		485		485		362		362
Financial liabilities carried at fair value
Derivative financial instruments		120		120		68		68
Financial liabilities carried at amortized cost
Trade payables and accrued liabilities		461		461		345		345
Taxes payable		38		38
Dividends payable		44		44		39		39
Loans and borrowings		1,671		1,764		1,945		2,090
Convertible debentures		604^(1)		633		610^(1)		725
		2,818		2,940		2,939		3,199

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

The basis for determining fair values is disclosed in Note 5.

Interest rates used for determining fair value

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

December 31 (percents)												2013				2012
Derivatives												1.2% - 2.4%				1.2% - 2.5%
Loans and borrowings												1.7% - 5.0%				2.0% - 4.4%

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

Fair value hierarchy

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

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

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

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

December 31 ($ millions)						2013							2012
Commodity						5							11
Interest rate						8							14
Foreign exchange						1
Conversion feature of convertible debentures (Note 13)						99							30
Redemption liability related to acquisition of subsidiary						3							5
Net derivative financial instruments liability						116							60

Sensitivity analysis

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

December 31, 2013 ($ millions)							+ Change			- Change
Frac spread related
	Natural gas			(AECO +/- $0.25 per GJ)			1			(1)
	NGL (includes propane, butane and condensate)			(Belvieu +/- U.S. $0.10 per gal)			(3)			3
	Foreign exchange (U.S.$ vs. Cdn$)			(FX rate +/- $0.05)			(2)			2
Product margin
	Crude oil			(WTI +/- $2.50 per bbl)			(2)			2
	NGL (includes condensate)			(Belvieu +/- U.S. $0.10 per gal)			3			(3)
Corporate
	Interest rate			(Rate +/- 50 basis points)			2			(2)
	Power			(AESO +/- $5.00 per MW/h)			4			(4)
Conversion feature of convertible debentures				(Pembina share price +/- $0.50 per common share)			(4)			4

23. OPERATING LEASES

Leases as lessee

Operating lease rentals are payable as follows:

December 31 ($ millions)					2013					2012
Less than 1 year					26					23
Between 1 and 5 years					206					110
More than 5 years					306					153
					538					286

The Company leases a number of offices, warehouses, vehicles and rail cars under operating leases. The leases run for a period of one to fifteen years, with an option to renew the lease after that date. The Company has sublet office space up to 2022 and has contracted sub-lease payments of $44 million over the term.

24. CAPITAL MANAGEMENT

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

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

Pembina is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants as of December 31, 2013.

Note 15 of these financial statements shows the change in Share Capital for the year ended December 31, 2013.

25. GROUP ENTITIES

Significant subsidiaries

						Ownership Interest
December 31 (percentages)						2013								2012
Pembina Pipeline						100								100
Pembina Gas Services Limited Partnership						100								100
Pembina Oil Sands Pipeline LP						100								100
Pembina Midstream Limited Partnership						100								100
Pembina North Limited Partnership						100								100
Pembina West Limited Partnership						100								100
Pembina NGL Corporation						100								100
Pembina Facilities NGL LP						100								100
Pembina Infrastructure and Logistics LP						100								100
Pembina Empress NGL Partnership						100								100
Pembina Resource Services Canada						100								100
Pembina Resource Services (U.S.A.)						100								100

26. RELATED PARTIES

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

Key management personnel and director compensation

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

Compensation

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

Key management personnel compensation comprised:

Year Ended December 31 ($ millions)						2013				2012
Short-term employee benefits						4				3
Share-based compensation and other						7				6
Total compensation of key management						11				9

Transactions

Key management personnel and directors of the Company control less than one percent of the voting common shares of the Company (consistent with the prior year). Certain directors and key management personnel also hold Pembina convertible debentures and preferred shares. Dividend and interest payments received for the common shares and debentures held are commensurate with other non-related holders of those instruments.

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

Post-employment benefit plans

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

Transactions

($ millions)								Transaction Value Year Ended December 31									Balance Outstanding  As At December 31
Post-employment benefit plan				Transaction				2013				2012					2013	2012
Defined benefit plan				Funding				13				10

27. ACQUISITION

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

The purchase price equation is based on assessed fair values and is as follows:

($ millions)
Cash						9
Trade receivables and other						195
Inventory						87
Property, plant and equipment						1,988
Intangible assets and goodwill (including $1,744 goodwill)						2,405
Trade payables and accrued liabilities						(249)
Derivative financial instruments - current						(53)
Derivative financial instruments - non-current						(36)
Loans and borrowings						(215)
Convertible debentures						(317)
Provisions and other						(128)
Deferred tax liabilities						(403)
Other equity						6
Non-controlling interest						(5)
						3,284

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

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

Pembina's common shares were listed and began trading on the NYSE under the symbol "PBA" on April 2, 2012.

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

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

28. SUBSEQUENT EVENTS

On January 16, 2014, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset Class A Preferred shares, Series 5 (the "Series 5 Preferred Shares") at a price of $25.00 per share for aggregate proceeds of $250 million. The holders of Series 5 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.25 per share, if, as and when declared by the Board of Directors. The dividend rate will reset on June 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 3.00 percent. The Series 5 Preferred Shares are redeemable by the Company at its option on June 1, 2019 and on June 1 of every fifth year thereafter.

Holders of the Series 5 Preferred Shares have the right to convert their shares into cumulative redeemable floating rate Class A Preferred shares, Series 6 ("Series 6 Preferred Shares"), subject to certain conditions, on June 1, 2019 and on June 1 of every fifth year thereafter. Holders of Series 5 Preferred Shares will be entitled to receive a cumulative quarterly floating dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 3.00 percent, if, as and when declared by the Board of Directors of Pembina.

Proceeds from the offering were used to partially fund capital projects, to reduce indebtedness under the Company's credit facilities, and for other general corporate purposes of the Company. The Series 5 Preferred Shares began trading on the Toronto Stock Exchange on January 16, 2014 under the symbol PPL.PR.E.

The Company's Board of Directors declared an initial dividend of $0.1507 per Series 5 Preferred Share for the period from January 16, 2014 to February 28, 2014 which is payable on March 1, 2014 to shareholders of record at the close of business on February 1, 2014.

CORPORATE INFORMATION

---

HEAD OFFICE

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

AUDITORS

KPMG LLP
Chartered Accountants
Calgary, Alberta

TRUSTEE, REGISTRAR & TRANSFER AGENT

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

STOCK EXCHANGE

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

NYSE listing symbol for:
Common shares: PBA

 

 

 

 

 

SOURCE: Pembina Pipeline Corporation

INVESTOR INQUIRIES 

Phone: [phone]
Fax: [phone]
Toll Free: 1-855-880-7404
Email: [email protected]
Website: www.pembina.com