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Press release from PR Newswire

Pembina Pipeline Corporation announces third quarter 2012 results

Tuesday, November 06, 2012

Pembina Pipeline Corporation announces third quarter 2012 results16:23 EST Tuesday, November 06, 2012 Pembina continues to progress growth projects while maintaining steady operating results All financial figures are in Canadian dollars unless noted otherwise. This report contains forward-looking statements and information that are based on Pembina Pipeline Corporation's current expectations, estimates, projections and assumptions in light of its experience and its perception of historic trends. Actual results may differ materially from those expressed or implied by these forward-looking statements. Please see "Forward-Looking Statements & Information" for more details. This report also refers to financial measures that are not defined by Canadian Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP Measures." CALGARY, Nov. 6, 2012 /PRNewswire/ - On April 2, 2012 Pembina Pipeline Corporation ("Pembina" or the "Company") completed its acquisition of Provident Energy Ltd. ("Provident") (the "Arrangement"). The amounts disclosed herein for the three and nine month periods ending September 30, 2012 reflect results of the post-Arrangement Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. The comparative figures reflect solely the 2011 results of legacy Pembina. For further information with respect to the Arrangement, please refer to Note 3 of the Interim Financial Statements for the period ended September 30, 2012. Financial & Operating Overview (unaudited)           ($ millions, except where noted)       3 Months Ended       September 30       9 Months Ended       September 30         2012       2011       2012       2011 Revenue 815.3 300.6 2,161.8 1,207.9 Operating margin(1) 177.5 103.6 454.1 311.2 Gross profit 102.9 86.5 366.6 267.1 Earnings for the period 30.7 30.1 143.7 120.7 Earnings per share - basic and diluted (dollars) 0.11       0.18 0.58       0.72 Adjusted EBITDA(1) 153.8 89.9 391.1 280.4 Cash flow from operating activities 130.9 87.7 220.3 211.7 Adjusted cash flow from operating activities(1) 133.2 82.0 321.5 239.8 Adjusted cash flow from operating activities per share(1) 0.46       0.49 1.30       1.43 Dividends declared 117.3 65.4 299.2 195.8 Dividends per common share (dollars)       0.405       0.390       1.200       1.170 (1)  Refer to "Non-GAAP Measures." Third Quarter Highlights Consolidated operating margin during the third quarter increased to $177.5 million compared to $103.6 million during the same period of the prior year. Year-to-date operating margin totalled $454.1 million compared to $311.2 million during the first nine months of 2011. Pembina's overall results for the quarter reflect Pembina's legacy businesses combined with those acquired through the Arrangement, which are reported as part of the Company's Midstream business. Operating margin is a non-GAAP measure; see "Non-GAAP Measures." Pembina generated $49.4 million in operating margin from its Conventional Pipelines business, $29.3 million from Oil Sands & Heavy Oil and $16.6 million from Gas Services. The Midstream business saw a significant increase to $81.6 million, which includes operating margin generated by the assets acquired through the Arrangement. Higher results from Pembina's legacy crude oil midstream business were somewhat tempered by a continued soft propane pricing environment. These softer prices are the result of high industry inventory levels due to decreased propane demand, which was caused by the relatively warm 2011/12 winter across North America and increasing supply. The Company's earnings were $30.7 million ($0.11 per share) during the third quarter of 2012 compared to $30.1 million ($0.18 per share) during the third quarter of 2011. Earnings were $143.7 million ($0.58 per share) during the first nine months of 2012 compared to $120.7 million ($0.72 per share) during the same period of the prior year. Earnings for the three and nine month periods ended September 30, 2012 increased as a result of the Arrangement and were impacted by unrealized gains (losses) on commodity-related derivative financial instruments. However, earnings per share decreased primarily due to the 116.5 million shares issued as a result of the Arrangement (all per share metrics discussed below were impacted by this factor). Pembina generated adjusted EBITDA of $153.8 million during the third quarter of 2012 compared to $89.9 million during the third quarter of 2011 (adjusted EBITDA is a non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the nine month period ended September 30, 2012 was $391.1 million compared to $280.4 million for the same period in 2011. The increase in quarterly and year-to-date adjusted EBITDA was due to strong results from each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the completion of the Arrangement. Cash flow from operating activities was $130.9 million ($0.45 per share) during the third quarter of 2012 compared to $87.7 million ($0.52 per share) during the third quarter of 2011. For the nine months ended September 30, 2012, cash flow from operating activities was $220.3 million ($0.89 per share) compared to $211.7 million ($1.27 per share) during the same period last year. The increase is primarily due to higher EBITDA, which was partially offset by acquisition-related expenses, higher interest expenses and an increase in working capital reflecting a seasonal inventory build of NGL products. Adjusted cash flow from operating activities was $133.2 million ($0.46 per share) during the third quarter of 2012 compared to $82.0 million ($0.49 per share) during the third quarter of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted cash flow from operating activities was $321.5 million ($1.30 per share) during the first nine months of 2012 compared to $239.8 million ($1.43 per share) during the same period of last year. Growth and Operational Update Pembina continues to make steady progress on its major growth projects, as follows: On October 22, 2012, Pembina closed the offering of $450 million of senior unsecured medium-term notes. The notes have a fixed interest rate of 3.77% per annum, paid semi-annually, and will mature on October 24, 2022. The net proceeds will be used to repay a portion of Pembina's existing credit facility, giving the Company increased flexibility to pursue its capital plans; Following an unplanned outage, the 205 MMcf/d Musreau deep cut was placed back in service on September 2, 2012; The 50 MMcf/d Musreau shallow cut expansion was placed into service on September 13, 2012; Construction has started on a joint venture full-service terminal in the Judy Creek, Alberta area and has an estimated project completion date of April 2013; Pembina successfully completed and commissioned an 8,000 bpd expansion at the Redwater fractionator, which required a 20-day turn-around of the facility in September. The project was completed on schedule and under budget; Development of seven fee-for-service cavern storage facilities continued at Pembina's Redwater site, the first of which came into service September 1, 2012; Pembina received Board approval to proceed with two expansions of its Conventional Pipeline systems (subject to reaching commercial arrangements with its customers and receipt of regulatory approval) to accommodate increased customer demand due to strong drilling results and increased field liquids extraction by producers in areas of Alberta including Dawson Creek, Grande Prairie, Kaybob and Fox Creek: Pembina is pursuing the second phase of the Northern NGL System expansion, which will increase capacity from 167,000 bpd to 220,000 bpd. Pembina expects this expansion to cost approximately $330 million and to be complete in early to mid-2015; Pembina is also pursuing an expansion of its Peace Pipeline crude oil system, which will increase crude and condensate capacity from 195,000 bpd to 250,000 bpd. Pembina expects this expansion to cost approximately $215 million and to be complete in mid- to late 2014; and Pembina expects to spend an additional $125 million to tie-in area producers to the expanded systems. Pembina has received the required regulatory approvals and has awarded construction contracts for the pipeline portions of the Resthaven and Saturn projects. A significant portion of the major equipment for both facilities has been ordered and Pembina has begun to receive major equipment at each site. The Company expects to begin construction on both projects during the fall and winter of 2012/2013; Preliminary engineering work continued on the proposed new 70,000 bpd ethane plus fractionator at Pembina's Redwater facility and the Company continues soliciting customer support for the project; and Pembina is investigating offshore export opportunities for propane that would allow it to leverage its existing assets and provide a solution for Canadian producers. "Pembina delivered steady operational and financial results this quarter and we continued to make substantial progress on a number of capital projects across our business," said Bob Michaleski, Pembina's Chief Executive Officer. "Our integration with Provident is essentially complete with only a few remaining items on the information systems front, which we expect to wrap up by year-end. Moving forward, I'm confident we have the financial resources, human capital, and strategic focus to further our pursuit of fee-for-service opportunities, which we expect will continue adding long-term shareholder value." Hedging Information Pembina has posted updated hedging information on its website, www.pembina.com, under "Investor Centre - Hedging". Conference call & Webcast Pembina will host a conference call on November 7, 2012 at 9 a.m. MT (11 a.m. ET) to discuss details related to the third quarter of 2012. The conference call dial in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A live webcast of the conference call can be accessed on Pembina's website under "Investor Centre - Presentation & Events," or by entering http://event.on24.com/r.htm?e=526791&s=1&k=34AC4F42C4AB2E0D2358DE14B1E8071E in your web browser. MANAGEMENT'S DISCUSSION AND ANALYSIS The following management's discussion and analysis ("MD&A") of the financial and operating results of Pembina Pipeline Corporation ("Pembina" or the "Company") is dated November 6, 2012 and is supplementary to, and should be read in conjunction with, Pembina's condensed consolidated unaudited interim financial statements for the period ended September 30, 2012 ("Interim Financial Statements") as well as Pembina's consolidated audited annual financial statements and MD&A for the year ended December 31, 2011 (the "Consolidated Financial Statements"). All dollar amounts contained in this MD&A are expressed in Canadian dollars unless otherwise noted. Management is responsible for preparing the MD&A. This MD&A has been reviewed and recommended by the Audit Committee of Pembina's Board of Directors and approved by its Board of Directors. This MD&A contains forward-looking statements (see "Forward-Looking Statements & Information") and refers to financial measures that are not defined by Canadian Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP Measures." On April 2, 2012 Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Arrangement"). The amounts disclosed herein for the three and nine month periods ending September 30, 2012 reflect results of the post-Arrangement Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. The comparative figures reflect solely the 2011 results of legacy Pembina. The results of the business acquired through the Arrangement are reported as part of the Company's Midstream business. For further information with respect to the Arrangement, please refer to Note 3 of the Interim Financial Statements for the period ended September 30, 2012. About Pembina Calgary-based Pembina Pipeline Corporation is a leading transportation and midstream service provider that has been serving North America's energy industry for nearly 60 years. Pembina owns and operates: pipelines that transport conventional and synthetic crude oil and natural gas liquids produced in western Canada; oil sands and heavy oil pipelines; gas gathering and processing facilities; and, an oil and natural gas liquids infrastructure and logistics business. With facilities strategically located in western Canada and in natural gas liquids markets in eastern Canada and the U.S., Pembina also offers a full spectrum of midstream and marketing services that span across its operations. Pembina's integrated assets and commercial operations enable it to offer services needed by the energy sector along the hydrocarbon value chain. Pembina is a trusted member of the communities in which it operates and is committed to generating value for its investors by running its businesses in a safe, environmentally responsible manner that is respectful of community stakeholders. Strategy Pembina's goal is to provide highly competitive and reliable returns to investors through monthly dividends while enhancing the long-term value of its shares. To achieve this, Pembina's strategy is to: Preserve value by providing safe, responsible, cost-effective and reliable services. Diversify Pembina's asset base along the hydrocarbon value chain by providing integrated service offerings which enhance profitability. Pursue projects or assets that are expected to generate increased cash flow per share and capture long-life, economic hydrocarbon reserves. Maintain a strong balance sheet through the application of prudent financial management to all business decisions. Pembina is structured into four businesses: Conventional Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream, which are described in their respective sections of this MD&A. Common Abbreviations The following is a list of abbreviations that may be used in this MD&A: Measurement     Other   bbl  barrel   AECO  Alberta gas trading price mmbbls  millions of barrels   AESO  Alberta Electric Systems Operator bpd  barrels per day   B.C.  British Columbia mbpd  thousands of barrels per day   DRIP  Premium Dividend? and Dividend Reinvestment Plan mboe/d  thousands of barrels of oil equivalent per day   Frac  Fractionation MMcf/d  millions of cubic feet per day   IFRS  International Financial Reporting Standards bcf/d  billions of cubic feet per day   NGL  Natural gas liquids MW/h  megawatts per hour   NYMEX  New York Mercantile Exchange GJ  gigajoule   NYSE  New York Stock Exchange km  kilometre   TET  Indicates product in the Texas Eastern Products Pipeline at Mont Belvieu, Texas (Non-TET refers to product in a location at Mont Belvieu other than in the Texas Eastern Products pipeline)       TSX  Toronto Stock Exchange       U.S.  United States       WCSB  Western Canadian Sedimentary Basin        WTI  West Texas Intermediate (crude oil benchmark price) Financial & Operating Overview (unaudited)                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except where noted)       2012       2011       2012       2011 Average throughput - Conventional Pipelines (mbpd) 443.9 430.4 448.2 410.8 Contracted capacity - Oil Sands & Heavy Oil (mbpd) 870.0 775.0 870.0 775.0 Average processing volume - Gas Services (mboe/d) net to Pembina(1) 45.8 41.3 45.8 39.7 NGL sales volume - NGL Midstream (mbpd) 86.7   88.6(3)   Revenue 815.3 300.6 2,161.7 1,207.9 Operations 69.5 54.4 185.6 136.8 Cost of goods sold, including product purchases 565.5 145.8 1,506.4 764.3 Realized gain (loss) on commodity-related derivative financial instruments (2.8) 3.2 (15.6) 4.4 Operating margin(2) 177.5 103.6 454.1 311.2 Depreciation and amortization included in operations 51.6 17.8 125.8 48.4 Unrealized gain (loss) on commodity-related derivative financial instruments (23.0) 0.7 38.3 4.3 Gross profit 102.9 86.5 366.6 267.1 Deduct/(add)           General and administrative expenses 26.9 13.8 70.2 41.2   Acquisition-related and other expense (income) 1.5 1.2 24.2 0.6   Net finance costs 33.1 30.5 79.4 69.8   Share of loss (profit) of investments in equity accounted investee, net of tax 0.6 0.6 0.9 (4.3) Income tax expense 10.1 10.3 48.2 39.1 Earnings for the period 30.7 30.1 143.7 120.7 Earnings per share - basic and diluted (dollars) 0.11 0.18 0.58 0.72 Adjusted earnings(2) 65.4 47.0 167.9 165.2 Adjusted earnings per share(2) 0.23 0.28 0.68 0.99 Adjusted EBITDA(2) 153.8 89.9 391.1 280.4 Cash flow from operating activities 130.9 87.7 220.3 211.7 Cash flow from operating activities per share 0.45 0.52 0.89 1.27 Adjusted cash flow from operating activities(2) 133.2 82.0 321.5 239.8 Adjusted cash flow from operating activities per share(2) 0.46 0.49 1.30 1.43 Dividends declared 117.3 65.4 299.2 195.8 Dividends per common share (dollars) 0.405 0.390 1.200 1.170 Capital expenditures 143.4 77.2 329.7 378.7 Total enterprise value ($ billions) (2) 10.6 5.9 10.6 5.9 Total assets ($ billions) 8.2 3.2 8.2 3.2 (1)  Gas Services processing volumes converted to mboe/d from MMcf/d at 6:1 ratio. (2)  Refer to "Non-GAAP Measures." (3)  Represents per day volumes since the closing of the Arrangement.     Revenue, net of cost of goods sold, increased to $249.8 million during the third quarter of 2012 compared to $154.8 million in the third quarter of 2011. Year-to-date revenue, net of cost of goods sold, in 2012 was $655.4 million compared to $443.6 million for the same period last year. Revenue was higher in 2012 than the comparative periods in 2011 primarily due to the addition of results generated by the assets acquired through the Arrangement, which are reported in the Company's Midstream business, as well as increased performance in each of Pembina's legacy businesses. Operating expenses were $69.5 million during the third quarter of 2012 compared to $54.4 million in the third quarter of 2011. Operating expenses for the nine months ended September 30, 2012 were $185.6 million compared to $136.8 million in the same period in 2011. The increase in operating expenses for the third quarter and first nine months of 2012 was primarily due to added costs associated with the growth in Pembina's asset base since the Arrangement and higher variable costs in each of the Company's businesses due to increased volumes. Operating margin was $177.5 million during the third quarter, up 71 percent from the same period last year (operating margin is a Non-GAAP measure; see "Non-GAAP Measures"). For the nine months ended September 30, 2012 operating margin was $454.1 million compared to $311.2 million for the same period of 2011. These increases were primarily due to higher revenue, as discussed above. Realized and unrealized gains (losses) on commodity-related derivative financial instruments are the result of Pembina's market risk management program and are primarily related to outstanding positions acquired on the closing of the Arrangement (see "Market Risk Management Program" and Note 13 to the Interim Financial Statements). The unrealized loss on commodity-related derivative financial instruments was $23.0 million for the three months ended September 30, 2012 and $38.3 million for the first nine months of the year reflecting changes in the future NGL and natural gas price indices between April 2, 2012 and September 30, 2012 (see "Business Environment"). Depreciation and amortization (operational) increased to $51.6 million during the third quarter of 2012 compared to $17.8 million during the same period in 2011. For the nine months ended September 30, 2012, depreciation and amortization (operational) increased to $125.8 million, up from $48.4 million for the same period last year. Both the quarterly and year-to-date increases reflect depreciation on new capital additions including those assets acquired through the Arrangement. The increases in revenue and operating margin contributed to gross profit of $102.9 million during the third quarter and $366.6 million for the first nine months of 2012 compared to $86.5 million and $267.1 million for the comparative periods of the prior year. General and administrative expenses ("G&A") of $26.9 million were incurred during the third quarter of 2012 compared to $13.8 million during the third quarter of 2011. G&A for the first nine months of 2012 was $70.2 million compared to $41.2 million for the same period of 2011. The increase in G&A for the three and nine month periods of 2012 compared to the prior year is mainly due to the addition of employees who joined Pembina through the Arrangement, an increase in salaries and benefits for existing and new employees, and increased rent for new and expanded office space. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by $0.8 million. Pembina generated adjusted EBITDA of $153.8 million during the third quarter of 2012 compared to $89.9 million during the third quarter of 2011 (adjusted EBITDA is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the nine month period ended September 30, 2012 was $391.1 million compared to $280.4 million for the same period in 2011. The increase in quarterly and year-to-date adjusted EBITDA was due to strong results from each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the growth of Pembina's operations since completion of the Arrangement. The Company's earnings were $30.7 million ($0.11 per share) during the third quarter of 2012 compared to $30.1 million ($0.18 per share) during the third quarter of 2011. Earnings were $143.7 million ($0.58 per share) during the first nine months of 2012 compared to $120.7 million ($0.72 per share) during the same period of the prior year. Earnings for the three and nine month periods ended September 30, 2012 increased as a result of the acquisition of Provident and were impacted by the unrealized gain (loss) on commodity-related derivative financial instruments. Earnings per share decreased primarily due to the 116.5 million shares issued as a result of the Arrangement (all per share metrics discussed below were impacted by this factor). Adjusted earnings were $65.4 million ($0.23 per share) during the third quarter and $167.9 million ($0.68 per share) for the first nine months of 2012 compared to $47.0 million ($0.28 per share) and $165.2 million ($0.99 per share) for the respective periods of 2011 (adjusted earnings is a Non-GAAP measure; see "Non-GAAP Measures"). The quarterly and year-to-date increase is primarily due to higher operating margin, as discussed above, which was partially offset by increased depreciation and amortization (operational). Cash flow from operating activities was $130.9 million ($0.45 per share) during the third quarter of 2012 compared to $87.7 million ($0.52 per share) during the third quarter of 2011. For the nine months ended September 30, 2012, cash flow from operating activities was $220.3 million ($0.89 per share) compared to $211.7 million ($1.27 per share) during the same period last year. The increase in cash flow from operating activities is primarily due to an increase in adjusted EBITDA, which was partially offset by acquisition-related expenses, higher interest expenses and an increase in working capital reflecting a seasonal inventory build of NGL products. Adjusted cash flow from operating activities was $133.2 million ($0.46 per share) during the third quarter of 2012 compared to $82.0 million ($0.49 per share) during the third quarter of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted cash flow from operating activities was $321.5 million ($1.30 per share) during the first nine months of 2012 compared to $239.8 million ($1.43 per share) during the same period of last year. Operating Results (unaudited)                           3 Months Ended       September 30       9 Months Ended       September 30         2012       2011       2012       2011 ($ millions)       Net Revenue(1) Operating Margin(2)       Net Revenue(1) Operating Margin(2)       Net Revenue(1) Operating Margin(2)       Net Revenue(1) Operating Margin(2) Conventional Pipelines 79.0 49.4 78.7 45.8 239.6 151.4 220.4 139.9 Oil Sands & Heavy Oil 44.1 29.3 37.0 24.3 126.6 87.2 95.2 63.6 Gas Services 23.7 16.6 18.8 12.4 65.0 44.6 52.4 36.1 Midstream 103.0 81.6 20.3 19.3 224.2(3) 169.0(3) 75.6 69.8 Corporate   0.6   1.8   1.9   1.8 Total 249.8 177.5 154.8 103.6 655.4 454.1 443.6 311.2 (1)  Midstream revenue is net of $571.7 million in cost of goods sold, including product purchases, for the quarter ended September 30, 2012 (quarter ended September 30, 2011: $145.8 million) and $1,519.5 million cost of goods sold, including product purchases, for nine months ended September 30, 2012 (nine months ended September 30, 2011: $764.3 million). (2)  Refer to "Non-GAAP Measures." (3) Includes results from operations generated by the acquired assets from Provident since closing of the Arrangement. Conventional Pipelines                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except where noted)       2012       2011       2012       2011 Average throughput (mbpd) 443.9 430.4 448.2 410.8 Revenue 79.0 78.7 239.6 220.4 Operations 30.1 34.6 87.5 83.6 Realized gain (loss) on commodity related derivative financial instruments 0.5 1.7 (0.7) 3.1 Operating margin(1) 49.4 45.8 151.4 139.9 Depreciation and amortization included in operations 12.0 10.4 36.2 30.5 Unrealized gain (loss) on commodity-related derivative financial instruments (7.1)   (9.8) 4.6 Gross profit 30.3 35.4 105.4 114.0 Capital expenditures 34.7 20.3 99.2 47.1 (1)  Refer to "Non-GAAP Measures." Business Overview Pembina's Conventional Pipelines business comprises a well-maintained and strategically located 7,850 km pipeline network that extends across much of Alberta and B.C. It transports approximately half of Alberta's conventional crude oil production, about thirty percent of the NGL produced in western Canada, and virtually all of the conventional oil and condensate produced in B.C. This business' primary objective is to generate sustainable operating margin while pursuing opportunities for increased throughput and revenue. Conventional Pipelines endeavours to maintain and/or improve operating margin by capturing incremental volumes, expanding its pipeline systems, managing revenue and adopting strong discipline relative to operating expenses. Operational Performance: Throughput During the third quarter of 2012, Conventional Pipelines' throughput averaged 443.9 mbpd, consisting of an average of 330.4 mbpd of crude oil and condensate and 113.5 mbpd of NGL. This increase, which is approximately three percent higher than the same period of 2011, when average throughput was 430.4 mbpd, is primarily due to continued production growth from regional resource plays in the Cardium (oil), Deep Basin Cretaceous (NGL), Montney (oil/NGL) and Beaverhill Lake (oil) formations. This producer production growth also contributed to a nine percent increase in throughput for the first nine months of 2012 compared to the same period of 2011. Financial Performance During the third quarter of 2012, Conventional Pipelines generated revenue of $79.0 million, virtually unchanged from the same quarter of the previous year. For the first nine months of 2012, revenue was $239.6 million compared to $220.4 million for the same period in 2011. This nine percent increase is due to higher volumes generated by newly connected facilities on Conventional Pipeline's larger systems. During the third quarter, operating expenses decreased to $30.1 million compared to $34.6 million in the third quarter of 2011 due to the timing of integrity related and geotechnical expenditures as well as lower power costs. Operating expenses for the nine months ended September 30, 2012 increased to $87.5 million from $83.6 million during the same period of 2011. This five percent year-to-date increase primarily resulted from increased variable and power costs associated with higher volumes and new assets that are now in-service, as well as increased spending related to pipeline integrity and geotechnical work. As a result of consistent revenue and lower operating expenses, operating margin for the third quarter of 2012 was $49.4 million compared to $45.8 million during the same period of 2011. On a year-to-date basis, operating margin increased to $151.4 million due to higher revenue, which was offset slightly by an increase in operating expenses, as discussed above, compared with $139.9 million for the first nine months of 2011. Depreciation and amortization included in operations increased to $12.0 million during the third quarter of 2012 from $10.4 million during the third quarter of 2011, reflecting capital additions in this business. Depreciation and amortization included in operations for the nine months ended September 30, 2012 was $36.2 million, up from $30.5 million in the first nine months of 2012. For the three and nine months ended September 30, 2012, unrealized losses on commodity-related derivative financial instruments were $7.1 million and $9.8 million compared to nil and a $4.6 million gain for the same periods in 2011. The 2012 losses are largely a result of lower power price indices over the term of the power purchase contracts. For the three and nine months ended September 30, 2012, gross profit was $30.3 million and $105.4 million, respectively, compared to gross profit of $35.4 million and $114.0 million, respectively, during the same periods in 2011. Higher operating margin was more than offset by increased depreciation and amortization and unrealized losses on commodity-related derivative financial instruments. Capital expenditures for the third quarter of 2012 totalled $34.7 million compared to $20.3 million during the third quarter of 2011, and were $99.2 million in the first nine months of the year compared to $47.1 million for the same period of 2011. The majority of this spending relates to the expansion of certain pipeline assets as described below. New Developments: Conventional Pipelines Liquids-Rich Natural Gas: Expansion of Peace and Northern NGL Pipelines Pembina is working to complete the first portion of its $100 million Northern NGL expansion, which will add approximately 17 mbpd of additional NGL capacity on Pembina's Peace and Northern pipelines (together the "Northern NGL System"). To complete this expansion, Pembina plans to install a total of three pump stations, two of which are expected to be in-service by the end of the year, and are expected to provide about 10 mbpd of additional capacity. The third pump station for the first portion of the expansion is expected to be in-service in the first quarter of 2013. Pembina plans to bring an additional 35 mbpd on stream by the fourth quarter of 2013, resulting in a total capacity for the Northern NGL System of approximately 167 mbpd. Pembina has reached long-term commercial agreements to underpin the Northern NGL Expansion. On November 6, 2012, Pembina received Board approval to proceed with two new expansions of its Conventional Pipeline systems (subject to reaching long-term commercial arrangements with its customers and receipt of regulatory approval) to accommodate increased customer demand due to strong drilling results and increased field liquids extraction by area producers: Pembina is pursuing the second phase of the Northern NGL System expansion, which will increase capacity from 167 mbpd to 220 mbpd. Pembina expects this expansion to cost approximately $330 million and to be complete in early to mid-2015; Pembina is also pursuing an expansion of its Peace Pipeline crude oil system, which will increase crude and condensate capacity from 195 mbpd to 250 mbpd. Pembina expects this expansion to cost approximately $215 million and to be complete in mid- to late 2014; and Pembina expects to spend an additional $125 million to tie-in area producers to the expanded systems. Supporting Gas Services' Saturn and Resthaven Projects Pembina's Conventional Pipelines business is working closely with its Gas Services business to construct the pipeline components of the Company's Saturn and Resthaven gas plant projects. These two pipeline projects will gather NGL from the gas plants for delivery to Pembina's Peace Pipeline system. Pembina has received the required regulatory approvals, has awarded construction contracts and expects to begin construction on both projects during the fall and winter of 2012/2013. Oil Sands & Heavy Oil                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except where noted)       2012       2011       2012       2011 Capacity under contract (mbpd) 870.0 775.0 870.0 775.0 Revenue 44.1 37.0 126.6 95.2 Operations 14.8 12.7 39.4 31.6 Operating margin(1) 29.3 24.3 87.2 63.6 Depreciation and amortization included in operations 5.0 3.9 14.8 7.9 Gross profit 24.3 20.4 72.4 55.7 Capital expenditures 6.1 14.0 12.1 143.9 (1)  Refer to "Non-GAAP Measures." Business Overview Pembina plays an important role in supporting Alberta's oil sands and heavy oil industry. Pembina is the sole transporter of crude oil for Syncrude Canada Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources Ltd.'s Horizon Oil Sands operation (via the Horizon Pipeline) to delivery points near Edmonton, Alberta. Pembina also owns and operates the Nipisi and Mitsue Pipelines, which provide transportation for producers operating in the Pelican Lake and Peace River heavy oil regions of Alberta, and the Cheecham Lateral which transports product to oil sands producers operating southeast of Fort McMurray, Alberta. The Oil Sands & Heavy Oil business operates approximately 1,650 km of pipeline and has 870 mbpd of capacity under long-term, extendible contracts which provide for the flow-through of operating expenses to customers. As a result, operating margin from this business is primarily related to invested capital and is not sensitive to fluctuations in operating expenses or actual throughput. Financial Performance The Oil Sands & Heavy Oil business realized revenue of $44.1 million in the third quarter of 2012 compared to $37.0 million in the third quarter of 2011. This 19 percent increase is primarily due to contributions from the Nipisi and Mitsue pipelines, which were placed into service in June and July of 2011. For the same reason, year-to-date revenue in 2012 was $126.6 million compared to $95.2 million for the same period in 2011. Operating expenses in Pembina's Oil Sands & Heavy Oil business were $14.8 million during the third quarter of 2012 compared to $12.7 million during the third quarter of 2011. For the first nine months of 2012, operating expenses were $39.4 million compared to $31.6 million for the same period in 2011. These increases primarily reflect the additional operating expenses related to the Nipisi and Mitsue pipelines. For the three and nine months ended September 30, 2012, operating margin increased to $29.3 million and $87.2 million compared to $24.3 million and $63.6 million, respectively, during the same periods in 2011. This is primarily due to the same factors that contributed to the increase in revenue, as discussed above. Depreciation and amortization included in operations for the third quarter of 2012 totalled $5.0 million compared to $3.9 million during the same period of the prior year, and $14.8 million for the first nine months of 2012 compared to $7.9 million during the same period in 2011. These increases primarily reflect the additional depreciation and amortization included in operations related to the Nipisi and Mitsue pipelines. For the three and nine months ended September 30, 2012, gross profit was $24.3 million and $72.4 million, primarily due to higher operating margin as discussed above, compared to $20.4 million and $55.7 million, respectively, during the same periods of 2011. For the nine months ended September 30, 2012, capital expenditures within the Oil Sands & Heavy Oil business totalled $12.1 million and were primarily related to Nipisi and Mitsue post-construction clean-up costs. This compares to $143.9 million spent during the same period in 2011, the majority of which related to completing the Nipisi and Mitsue pipeline projects. Gas Services                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except where noted)       2012       2011       2012       2011 Average processing volume (MMcf/d) net to Pembina 275.0 247.6 275.0 237.9 Average processing volume (mboe/d) (1) net to Pembina 45.8 41.3 45.8 39.7 Revenue 23.7 18.8 65.0 52.4 Operations 7.1 6.4 20.4 16.3 Operating margin(2) 16.6 12.4 44.6 36.1 Depreciation and amortization included in operations 3.3 2.5 10.8 7.3 Gross profit 13.3 9.9 33.8 28.8 Capital expenditures 29.8 29.0 85.6 70.1 (1)  Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio. (2)  Refer to "Non-GAAP Measures." Business Overview Pembina's operations include a growing natural gas gathering and processing business. Located approximately 100 km south of Grande Prairie, Alberta, Pembina's key revenue-generating Gas Services assets form the Cutbank Complex which comprises three sweet gas processing plants with 410 MMcf/d of processing capacity (355 MMcf/d net to Pembina), a 205 MMcf/d ethane plus extraction facility, as well as approximately 350 km of gathering pipelines. The Cutbank Complex is connected to Pembina's Peace Pipeline system and serves an active exploration and production area in the WCSB. Pembina has initiated construction on two projects in its Gas Services business, the Saturn and Resthaven enhanced NGL extraction facilities, to meet the growing needs of producers in west central Alberta. Financial Performance Gas Services recorded an increase in revenue of approximately 26 percent during the third quarter of 2012, contributing $23.7 million compared to $18.8 million in the third quarter of 2011. In the first nine months of the year, revenue was $65.0 million compared to $52.4 million in the same period of 2011. These increases primarily reflect higher processing volumes at Pembina's Cutbank Complex. Average processing volumes, net to Pembina, were 275.0 MMcf/d during the third quarter of 2012, approximately 11 percent higher than the 247.6 MMcf/d processed during the third quarter of the previous year. During the third quarter of 2012, operating expenses were $7.1 million compared to $6.4 million incurred in the third quarter of 2011. Year-to-date operating expenses totalled $20.4 million, up from $16.3 million during the same period of the prior year. The quarterly and year-to-date increases were mainly due to variable costs incurred to process higher volumes at the Cutbank Complex. As a result of processing higher volumes at the Cutbank Complex, Gas Services realized strong operating margin of $16.6 million in the third quarter and $44.6 million in the first nine months of 2012 compared to $12.4 million and $36.1 million during the same periods of the prior year. Depreciation and amortization included in operations during the third quarter of 2012 totalled $3.3 million, up from $2.5 million during the same period of the prior year, primarily due to higher in-service capital balances from additions to the Cutbank Complex (including the Musreau Deep Cut Facility and shallow cut expansion). For the same reason, year-to-date depreciation and amortization included in operations totalled $10.8 million compared to $7.3 million during the first nine months of 2011. For the three months ended September 30, 2012, gross profit was $13.3 million compared to $9.9 million in the same period of 2011. On a year-to-date basis, gross profit was $33.8 million compared to $28.8 million during the first nine months of 2011. These increases reflect higher operating margin during the periods, as discussed above. For the nine months ended September 30, 2012, capital expenditures within Gas Services totalled $85.6 million compared to $70.1 million during the same period of 2011. This increase was due to the spending required to complete the Musreau Deep Cut Facility, the expansion of the shallow cut facility at the Cutbank Complex as well as capital expenditures incurred to progress the Saturn and Resthaven enhanced NGL extraction facilities. New Developments: Gas Services Pembina continues to see significant growth opportunities resulting from the trend towards liquids-rich gas drilling and the extraction of valuable NGL from gas in the WCSB. Pembina expects the expansions detailed below to bring the Company's gas processing capacity to 890 MMcf/d (net). This includes enhanced NGL extraction capacity of approximately 535 MMcf/d (net), of which 205 MMcf/d is currently in service. These volumes would be processed largely on a contracted, fee-for-service basis and are expected to result in approximately 45 mbpd of incremental NGL to be transported for additional toll revenue on Pembina's conventional pipelines by early 2014. Musreau Deep Cut Facility The Musreau Deep Cut Facility experienced an unplanned outage in March and was placed back in service on September 2, 2012. Pembina does not recognize an increase in gas processing volumes resulting from the deep cut being in service because those same volumes are first processed through the shallow cut facilities of the Cutbank Complex. Expansion at the Cutbank Complex: Musreau Shallow Cut Expansion The 50 MMcf/d shallow cut gas processing expansion at Pembina's Musreau plant was completed in August 2012 and placed into service on September 13, 2012. The Cutbank Complex now has an aggregate raw shallow gas processing capacity of 410 MMcf/d (355 MMcf/d net to Pembina), an increase of 16 percent net to Pembina. Saturn and Resthaven Facilities Site construction on both the Saturn and Resthaven facilities is underway and the anticipated in-service dates for the projects are the fourth quarter of 2013 and first quarter of 2014, respectively. A significant portion of the major equipment has been ordered and Pembina has begun to receive major equipment on site. Once complete, these facilities are expected to add an additional 330 MMcf/d (net) of enhanced liquids extraction capability and approximately 25 mbpd of NGL volumes to Pembina's conventional pipeline systems. Midstream(1)                   3 Months Ended       September 30  9 Months Ended  September 30(2) ($ millions, except where noted)       2012       2011       2012       2011 Revenue 674.7 166.2 1,743.7 840.0 Operations 18.0 2.5 40.3 7.1 Cost of goods sold, including product purchases 571.7 145.9 1,519.5 764.4 Realized gain (loss) on commodity related derivative financial instruments (3.4) 1.5 (14.9) 1.3 Operating margin(3) 81.6 19.3 169.0 69.8 Depreciation and amortization included in operations 31.3 0.9 64.0 2.7 Unrealized gains (losses) on commodity-related derivative financial instruments (15.9) 0.7 48.1 (0.3) Gross profit 34.4 19.1 153.1 66.8 Capital expenditures 70.7 5.0 126.6 106.9 (1)  Share of profit from equity accounted investees not included in these results. (2)  Includes results from NGL midstream since the closing of the Arrangement. (3)  Refer to "Non-GAAP Measures." Business Overview Pembina provides a comprehensive suite of midstream products and services through its Midstream business as follows: Crude oil midstream, which represents the Company's legacy midstream operations, is situated at key sites across Pembina's operations and comprises a network of liquids truck terminals, terminalling at downstream hub locations, including storage and pipeline connectivity; and NGL midstream, which Pembina acquired through the Arrangement, includes two operating systems, Redwater West and Empress East: The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; the recently expanded 73,000 bpd Redwater NGL fractionator, 6.8 mmbbls of cavern storage and terminalling facilities at Redwater, Alberta; and, third party fractionation capacity in Fort Saskatchewan, Alberta. The Empress East NGL system includes a 2.1 bcf/d interest in the straddle plants at Empress, Alberta; 20,000 bpd of fractionation capacity as well as 1.1 mmbbls of cavern storage in Sarnia, Ontario; and, approximately 5.0 mmbbls of hydrocarbon storage at Corunna, Ontario. Financial Performance In the Midstream business, revenue, net of cost of goods sold, grew to $103.0 million during the third quarter of 2012 from $20.3 million during the third quarter of 2011. Year-to-date revenue, net of cost of goods sold, was $224.2 million in 2012 compared to $75.6 million in 2011. These increases were primarily due to the addition of the NGL midstream business acquired through the Arrangement and increased activity on Pembina's pipeline systems. Operating expenses during the third quarter of 2012 were $18.0 million compared to $2.5 million in the third quarter of 2011. Operating expenses for the first nine months of the year were $40.3 million in 2012 and $7.1 million in the same period of 2011. Operating expenses for the quarter and first nine months of the year were higher due to the increase in Midstream's asset base since the Arrangement. Operating margin was $81.6 million during the third quarter of 2012 compared to $19.3 million during the third quarter of 2011. Operating margin for the first nine months of 2012 was $169.0 million compared to $69.8 million in the same period of 2011. This increase was largely due to the same factors that contributed to the increase in revenue, net of cost of goods sold, as discussed above. Depreciation and amortization included in operations during the third quarter of 2012 totalled $31.3 million compared to $0.9 million during the same period of the prior year. Year-to-date depreciation and amortization included in operations totalled $64.0 million compared to $2.7 million during the first nine months of 2011. Both increases reflect the additional assets in Midstream since the closing of the Arrangement. For the three months ended September 30, 2012, unrealized losses on commodity-related derivative financial instruments were $15.9 million. Year-to-date was a gain of $48.1 million. These amounts reflect fluctuations in the future NGL and natural gas prices indices during the periods. For the three and nine months ended September 30, 2012, gross profit in this business increased to $34.4 million and $153.1 million from $19.1 million and $66.8 million during the same periods in 2011. This is due to the addition of assets acquired through the Arrangement, higher operating margin and the impact of unrealized gains (losses) on commodity-related derivative financial instruments. For the nine months ended September 30, 2012, capital expenditures within the Midstream business totalled $126.6 million and were primarily related to cavern development and related infrastructure as well as fractionation capacity expansion at the Redwater Facility by approximately 8,000 bpd. This compares to capital expenditures of $106.9 million during the same period of 2011 which included the acquisition of a terminalling and storage facility near Edmonton, Alberta and the acquisition of linefill for the Peace Pipeline. Operating Margin Crude Oil Midstream Operating margin for the Company's crude oil midstream activities during the third quarter of 2012 was $27.2 million compared to $19.3 million during the third quarter of 2011. Year-to-date operating margin was $87.4 million, representing an increase of 25 percent from $69.8 million in the same period last year. Strong third quarter and year-to-date 2012 results were primarily due to higher volumes and activity on Pembina's pipeline systems and wider margins, as well as opportunities associated with enhanced connectivity at the Pembina Nexus Terminal ("PNT") added in the first quarter of 2012. NGL Midstream Operating margin for Pembina's NGL midstream activities was $54.4 million for the third quarter and $81.6 million year-to-date since closing of the Arrangement, including a $15.0 million year-to-date realized loss on commodity-related derivative financial instruments (see "Market Risk Management Program"). NGL sales volumes during the third quarter of 2012 were 86.7 mbpd and 88.6 mbpd since the closing of the Arrangement. Redwater West Redwater West purchases NGL mix from various natural gas and natural gas liquids producers and fractionates it into finished products at fractionation facilities near Fort Saskatchewan, Alberta. Redwater West also includes NGL production from the Younger NGL extraction and fractionation plant (Taylor, B.C.) that provides specification NGL to B.C. markets. Also located at the Redwater facility are Pembina's industry-leading rail-based condensate terminal and more than 6.8 mmbbls of underground hydrocarbon cavern storage both of which service Pembina's proprietary and customer needs. Pembina's condensate terminal is the largest of its kind in western Canada. Operating margin during the third quarter of 2012, excluding realized losses from commodity-related derivative financial instruments, was $46.6 million. Year-to-date since closing of the Arrangement, operating margin, excluding realized losses from commodity-related derivative financial instruments, was $82.8 million. Realized propane margin results were impacted by weak 2012 market prices and decreased gas volumes at the Younger plant during the two periods. Conversely, third quarter western butane and condensate market prices and resulting margins were higher driven by strong Alberta demand. Overall, Redwater West NGL sales volumes averaged 52.5 mbpd since closing of the Arrangement. Empress East Empress East extracts NGL mix from natural gas at the Empress straddle plants and purchases NGL mix from other producers/suppliers. Ethane and condensate are generally fractionated out of the NGL mix at Empress and sold into Alberta markets. The remaining NGL mix is transported by pipelines to Sarnia, Ontario for fractionation and storage of specification products. Propane and butane are sold into central Canadian and eastern U.S. markets. Demand for propane is seasonal; inventory generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year during the winter heating season. Operating margin during the third quarter of 2012, excluding realized losses from commodity-related derivative financial instruments, was $11.6 million. Year-to-date since closing of the Arrangement, operating margin, excluding realized losses from commodity-related derivative financial instruments, was $13.8 million. Results were impacted by low sales volumes, soft 2012 propane prices and high extraction premiums, but were offset by strong refinery demand for butane and low AECO natural gas prices during the two periods. Overall, Empress East NGL sales volumes averaged 36.1 mbpd since closing of the Arrangement. New Developments: Midstream The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects which will continue to increase its stability and predictability. During the third quarter, Pembina began construction on a joint venture full-service terminal in the Judy Creek, Alberta, area which has an estimated project completion date of April 2013. Full-service terminals focus on emulsion treating (separating oil from impurities to meet shipping quality requirements), produced water handling and water disposal. Also during the third quarter, Pembina successfully completed and commissioned the approximately 8,000 bpd expansion at the Redwater fractionator. The expansion required a 20-day turn-around of the facility in September and the project was completed on schedule and under budget. Further, development of seven fee-for-service cavern storage facilities continued at Pembina's Redwater site, the first of which came into service September 1, 2012. Market Risk Management Program Pembina is exposed to frac spread risk which is the difference between the selling prices for propane-plus liquids and the input cost of natural gas required to produce respective NGL products. Pembina has a risk management program and uses derivative financial instruments to mitigate frac spread risk when possible to safeguard a base level of operating cash flow in order to cover the input cost of such natural gas. Pembina has entered into derivative financial swap contracts to protect the frac spread and to manage exposure to power costs, interest rates and foreign exchange rates. Pembina's credit policy mitigates risk of non-performance by counterparties of its derivative financial instruments. Activities undertaken to reduce risk include: regularly monitoring counterparty exposure to approved credit limits; financial reviews of all active counterparties; entering into International Swap Dealers Association ("ISDA") agreements; and, obtaining financial assurances where warranted. In addition, Pembina has a diversified base of available counterparties. Management continues to actively monitor commodity price risk and mitigate its impact through financial risk management activities. Subject to market conditions and at Management's discretion, Pembina may hedge a portion of its natural gas and NGL volumes. A summary of Pembina's current financial derivative positions is available on Pembina's website at www.pembina.com. A summary of Pembina's risk management contracts executed during the third quarter of 2012 is contained in the following table: Activity in the third quarter(1)             Year Commodity Description       Volume (Buy)/Sell Effective Period 2012 Crude Oil U.S. $90.39 per bbl(2)(4) 2,120 bpd October 1 - December 31 Condensate U.S. $1.93 per gallon(3)(4) (2,120) bpd October 1 - December 31 2013 Crude Oil U.S. $91.28 per bbl(2)(4) 2,753 bpd January 1 - December 31 Condensate U.S. $1.94 per gallon(3)(4) (2,753) bpd January 1 - December 31 2014 Power Cdn $50.75 per MW/h(5) (5) MW/h January 1 - December 31 2015 Power Cdn $49.00 per MW/h(5) (5) MW/h January 1 - December 31 2016 Power Cdn $50.00 per MW/h(5) (10) MW/h January 1 - December 31 (1)  This table represents the transactions entered into during the third quarter of 2012. (2)  Crude oil contracts are settled against NYMEX WTI calendar average. (3)  Condensate contracts are settled against Belvieu NON-TET natural gasoline. (4)  Management of physical contract exposure - rail contracts. (5)  Power contracts are settled against the hourly price of power as published by the AESO in $/MWh. The following table summarizes the impact of commodity-related derivative financial contracts settled during the first three quarters of 2012 and 2011 that were included in the realized (loss) gain on commodity-related derivative financial instruments:                   3 Months Ended       September 30       9 Months Ended       September 30 ($ thousands)       2012       2011       2012       2011 Realized (loss) gain on commodity-related derivative financial instruments         Frac spread related           Crude oil (173)   (2,170)     Natural gas (7,922)   (15,684)     Propane 2,253   3,980     Butane 1,448   2,217     Condensate 1,205   1,477     Sub-total frac spread related (3,189)   (10,180)   Corporate           Power 755 1,712 (1,009) 3,167 Management of exposure embedded in physical contracts and other (425) 1,496 (4,366) 1,292 Realized (loss) gain on commodity-related derivative financial instruments (2,859) 3,208 (15,555) 4,459 The realized loss on commodity-related derivative financial instruments for the third quarter of 2012 was $2.9 million compared to a realized gain of $3.2 million in the comparable period in 2011. The majority of the realized loss in the third quarter of 2012 was driven by natural gas purchase derivative contracts settling at a contracted price higher than the market natural gas prices during the settlement period, partially offset by NGL derivative sales contracts settling at a contracted price higher than the current NGL market prices during the settlement period. Business Environment                       3 Months Ended       September 30       9 Months Ended       September 30   2012 2011 % Change 2012 2011 % Change WTI crude oil (U.S. $ per barrel) 92.22 89.76 3 96.21 95.48 1 Exchange rate (from U.S.$ to Cdn$) 1.00 0.98 2 1.00 0.98 2 WTI crude oil (expressed in Cdn$ per barrel) 91.69 87.99 4 96.35 93.37 3               AECO natural gas monthly index (Cdn$ per GJ) 2.08 3.53 (41) 2.07 3.55 (42)               Mont Belvieu Propane (U.S.$ per U.S. gallon) 0.89 1.54 (42) 1.04 1.48 (30) Mont Belvieu Propane expressed as a percentage of WTI       41% 72% (43)       45% 65% (31)               Market Frac Spread in Cdn$ per barrel(1) 39.51 56.09 (30) 46.75 53.42 (13) (1)  Market frac spread is determined using average spot prices at Mont Belvieu, weighted based on 65 percent propane, 25 percent butane and 10 percent condensate, and the AECO monthly index price for natural gas. The third quarter of 2012 saw a six percent increase in the S&P TSX Composite Index from the previous quarter, with the value of the Index also having increased six percent since the same time a year ago. The Canadian dollar strengthened against the U.S. dollar during most of the third quarter, averaging $0.995 per U.S. dollar, due in part to an increase in commodity prices; however, it was weaker than an average value of $0.979 per U.S. dollar over the same period in the previous year. The benchmark WTI oil price recovered through July and August after setting year-to-date lows in late June and realized gains through the latter half of September, averaging and exiting the third quarter at U.S. $92.00/bbl. The Canadian heavy crude oil benchmark, Western Canadian Select, continued to trade at relatively wide differentials to WTI throughout the third quarter due to an ongoing tight supply-demand balance. Natural gas prices remained range-bound through the third quarter of 2012. The closing second quarter AECO price was $2.13 per GJ, which decreased four percent during the third quarter to exit at $2.05 per GJ (the average price during the period was $2.08 per GJ). While low natural gas prices are generally favourable for NGL extraction and fractionation economics, a sustained low gas price environment could impact the availability and overall cost of natural gas and NGL mix supply in western Canada as natural gas producers may elect to shut-in production or reduce drilling activities. The NGL pricing environment in the third quarter of 2012 recovered from lows set in June and July, but continued to be negatively impacted by a warm 2011/2012 winter and increasing production which resulted in a supply-demand imbalance in North America. In the U.S., industry propane/propylene inventories were approximately 76 million barrels at the end of the third quarter of 2012 (approximately 13 million barrels or 22 percent above the five-year historical average for this period). In Canada, industry propane inventories increased to 13.6 million barrels at the end of the third quarter of 2012 (1.3 million barrels, or 11 percent higher, than the historic five-year average). This over-supply continues to generate reduced prices, where the Mont Belvieu propane price averaged U.S. $0.89 per U.S. gallon (41 percent of WTI) in the third quarter of 2012, significantly below its five-year average of 60 percent of WTI. Butane and condensate sales prices recovered from lows through the quarter but were generally lower in the third quarter of 2012 compared to prior years. Market frac spreads averaged $39.51 per barrel during the third quarter of 2012 compared to $45.70 per barrel in the second quarter of 2012 and $56.09 per barrel in the third quarter of 2011. Compared to the second quarter of 2012, lower frac spreads resulted from lower NGL sales prices. The market frac spread does not include extraction premiums, operating/transportation/storage costs and regional sales prices. The outlook for the energy infrastructure sector in the WCSB remains positive for all of Pembina's businesses. Strong activity levels within the oil sands region represent opportunities for the Company to leverage existing assets to capitalize on additional growth opportunities. Pembina also continues to benefit from the combination of relatively high oil prices and low natural gas prices which has resulted in oil and gas producers continuing to extract the liquids value from their natural gas production and favouring liquids-rich natural gas plays over dry natural gas. Pembina's Conventional Pipelines, Gas Services and Midstream businesses are well-positioned to capitalize on the increased activity levels in key NGL-rich producing basins. Crude oil and NGL plays being developed in the vicinity of Pembina's pipelines include the Cardium, Montney, Cretaceous, Duvernay and Swan Hills. While recent weakness in liquids prices and an inflationary cost environment have resulted in some producers scaling back activity in the WCSB, the Company expects that the growth profile will continue to be positive for energy infrastructure. Non-Operating Expenses G&A Pembina incurred G&A of $26.9 million during the third quarter of 2012 compared to $13.8 million during the third quarter of 2011. G&A for the first nine months of 2012 was $70.2 million compared to $41.2 million for the same period of 2011. The increase in G&A for the three and nine month periods of 2012 compared to the prior year is mainly due to the addition of employees who joined Pembina through the Arrangement, an increase in salaries and benefits for existing and new employees, and increased rent for new and expanded office space. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by $0.8 million. Depreciation & Amortization (Operational) Depreciation and amortization (operational) increased to $51.6 million during the third quarter of 2012 compared to $17.8 million during the same period in 2011. For the nine months ended September 30, 2012, depreciation and amortization (operational) was $125.8 million, up from $48.4 million for the same period last year. Both increases reflect depreciation on new property, plant and equipment and depreciable intangibles including those assets acquired through the Arrangement. Acquisition-Related and Other Acquisition-related and other expenses during the third quarter were $1.5 million. For the nine months ended September 30, 2012, acquisition-related and other expenses were $24.2 million which includes acquisition expenses of $14.9 million as well as $8.2 million due to the required make whole payment for the redemption of the senior secured notes from the first quarter of the year. See "Liquidity and Capital Resources". Net Finance Costs Net finance costs in the third quarter of 2012 were $33.1 million compared to $30.5 million in the third quarter of 2011. Year-to-date net finance costs in 2012 totalled $79.4 million compared to $69.8 million in the same period of 2011. The increases primarily relate to an $11.9 million year-to-date increase in loans and borrowings interest expense ($3.2 million for the third quarter of 2012) due to higher debt balances and a quarterly and year-to-date increase in interest on convertible debentures totalling $5.9 million and $11.9 million, respectively, due to the Provident debentures assumed on closing of the Arrangement. These factors were offset by a $12.4 million increase in the change in the fair value of non-commodity-related derivative financial instruments for the first nine months of the year when compared to the same period in 2011 and a $4.2 million unrealized gain in 2012 on the conversion feature of the convertible debentures ($6.7 million loss for the third quarter of 2012). See Notes 10 and 13 to the Interim Financial Statements for the period ended September 30, 2012. Beginning in the second quarter of 2012, the change in fair value of commodity-related derivative financial instruments has been reclassified from net finance costs to gain/loss on commodity-related derivative financial instruments to be included in operational results. Income Tax Expense Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities. An income tax expense of $10.2 million was recorded in the third quarter of 2012 compared to $10.3 million in the third quarter of 2011. Year-to-date income tax expense in 2012 totalled $48.2 million compared to $39.1 million in the same period of 2011. The change in income tax expense is consistent with the change in earnings before income tax and equity accounted investees. Liquidity & Capital Resources       ($ millions) September 30, 2012 December 31, 2011 Working capital 101.7 (343.7)(1) Variable rate debt(2)       Bank debt 865.0 313.8   Variable rate debt swapped to fixed (380.0) (200.0) Total variable rate debt outstanding (average rate of 2.85%) 485.0 113.8 Fixed rate debt(2)       Senior secured notes   58.0   Senior unsecured notes 642.0 642.0   Senior unsecured term debt 75.0 75.0   Senior unsecured medium term note 250.0 250.0   Subsidiary debt 9.2     Variable rate debt swapped to fixed 380.0 200.0 Total fixed rate debt outstanding (average of 5.27%) 1,356.2 1,225.0 Convertible debentures(2) 644.3 299.8 Finance lease liability 5.6 5.6 Total debt and debentures outstanding 2,491.1 1,644.2 Cash and unutilized debt facilities 688.8 235.1 (1) As at December 31, 2011, working capital includes $310 million of current, non-revolving unsecured credit facilities. (2)  Face value. Pembina anticipates cash flow from operating activities will be more than sufficient to meet its short-term operating obligations and fund its targeted dividend level. In the medium-term, Pembina expects to source funds required for capital projects from cash and unutilized debt facilities totalling $688.8 million as at September 30, 2012. Based on its successful access to financing in the debt and equity markets during the past several years, Pembina believes it would likely continue to have access to funds at attractive rates. Additionally, Pembina has reinstated its DRIP as of the January 25, 2012 dividend record date to help fund its ongoing capital program (see "Trading Activity and Total Enterprise Value" for further details). Management remains satisfied that the leverage employed in Pembina's capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base. Management may make adjustments to Pembina's capital structure as a result of changes in economic conditions or the risk characteristics of the underlying assets. To maintain or modify Pembina's capital structure in the future, Pembina may renegotiate new debt terms, repay existing debt and seek new borrowing and/or issue equity. In connection with the closing of the Arrangement on April 2, 2012, Pembina increased its $800 million facility to $1.5 billion for a term of five years. Upon closing of the Arrangement, Pembina used the facility, in part, to repay Provident's revolving term credit facility of $205 million. Further, Pembina renegotiated its operating facility to $30 million from $50 million. Pembina's credit facilities at September 30, 2012 consisted of an unsecured $1.5 billion revolving credit facility due March 2017 and an operating facility of $30 million due July 2013. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil percent to 1.25 percent or Bankers' Acceptances rates plus 1.00 percent to 2.25 percent. Margins on the credit facilities are based on the credit rating of Pembina's senior unsecured debt. There are no repayments due over the term of these facilities. As at September 30, 2012, Pembina had $865 million drawn on bank debt, $1.6 million in letters of credit and $25.4 million in cash, leaving $688.8 million of unutilized debt facilities on the $1,530 million of established bank facilities. In addition, as at September 30, 2012, Pembina had $14.1 million in letters of credit issued in a separate demand letter of credit facility. Other debt includes $75 million in senior unsecured term debt due 2014; $175 million in senior unsecured notes due 2014; $267 million in senior unsecured notes due 2019; $200 million in senior unsecured notes due 2021; and $250 million in senior unsecured medium term notes due 2021. On April 30, 2012, the senior secured notes were redeemed. Pembina has recognized $8.2 million due to the associated make whole payment, which has been included in acquisition-related and other expenses in the first quarter of the year. At September 30, 2012, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,841.2 million. Pembina's senior debt to total capital at September 30, 2012 was 27 percent. Offering of Medium-Term Notes On October 22, 2012, Pembina closed the offering of $450 million principal amount of senior unsecured medium-term notes ("Notes"). The Notes have a fixed interest rate of 3.77% per annum, paid semi-annually, and will mature on October 24, 2022. The net proceeds from the offering of the Notes were used to repay a portion of Pembina's existing credit facility. Standard & Poor's Rating Services ("S&P") and DBRS Limited ("DBRS") have assigned credit ratings of BBB to the Notes. The Notes were offered through a syndicate of agents under Pembina's short form base prospectus dated November 2, 2010, a related prospectus supplement dated March 16, 2011 and a related pricing supplement dated October 17, 2012. Credit Ratings Pembina considers the maintenance of an investment grade credit rating important to its ongoing ability to access capital markets on attractive terms. DBRS rates Pembina's senior unsecured notes 'BBB'. S&P's long-term corporate credit rating on Pembina is 'BBB'. These ratings are not recommendations to purchase, hold or sell the securities in as much as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgement, circumstances so warrant. Assumption of rights related to the Provident Debentures On closing of the Arrangement on April 2, 2012, Pembina assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2017 (TSX: PPL.DB.E), and the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2018 (TSX: PPL.DB.F). Outstanding Provident debentures at April 2, 2012 were $345 million. As of September 30, 2012, $344.6 million of the debentures are still outstanding. Capital Expenditures                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions)       2012       2011       2012       2011 Development capital           Conventional Pipelines 34.7 20.3 99.2 47.1   Oil Sands & Heavy Oil 6.1 14.0 12.1 143.9   Gas Services 29.8 29.0 85.6 70.1   Midstream 70.7 5.0 126.6 106.9 Corporate/other projects 2.0 8.9 6.1 10.7 Total development capital 143.3 77.2 329.6 378.7 During the first nine months of 2012, capital expenditures were $329.6 million compared to $378.7 million during the same nine month period in 2011. In the comparable period in 2011, the Company's capital expenditures included the construction of the Nipisi and Mitsue pipelines, the acquisition of midstream assets in the Edmonton, Alberta area (related to PNT) and linefill for the Peace Pipeline system. The majority of the capital expenditures in the third quarter and first nine months of 2012 were in Pembina's Conventional Pipelines, Gas Services and Midstream businesses. Conventional Pipelines capital was incurred to progress the Northern NGL Expansion and on various new connections. Gas Services capital was deployed to complete the Musreau Deep Cut Facility and the expansion of the shallow cut facility at the Cutbank Complex as well as to progress the Saturn and Resthaven enhanced NGL extraction facilities. Midstream's capital expenditures were primarily directed towards cavern development and related infrastructure as well as the 8,000 bpd expansion at the Redwater Facility. Contractual Obligations at September 30, 2012             ($ thousands)       Payments Due By Period Contractual Obligations Total Less than 1 year 1 - 3 years 4 - 5 years After 5 years Office and vehicle leases 294,058 23,291 52,800 57,550 160,417 Loans and borrowings(1) 2,183,789 63,537 377,996 943,330 798,926 Convertible debentures(1) 913,273 39,183 118,453 243,311 512,326 Construction commitments 496,960 425,973 70,987     Provisions(2) 485,857 2,445     483,412 Total contractual obligations 4,373,937 554,429 620,236 1,244,191 1,955,081 (1) Excluding deferred financing costs. Finance leases included under "office and vehicle leases." (2)  Includes discounted constructive and legal obligations included in the decommissioning provision. Pembina is, subject to certain conditions, contractually committed to the construction and operation of the Saturn Facility and the Resthaven Facility, and to the remaining capital expenditures associated with the Nipisi and Mitsue pipelines. See "Forward-Looking Statements & Information." The contractual obligations noted above have changed significantly since December 31, 2011, due primarily to the assumption of the contractual obligations of Provident as a result of the Arrangement. Critical Accounting Estimates Preparing the Interim Financial Statements in conformity with IFRS requires Management to make judgments, estimates and assumptions based on the circumstances and estimates at the date of the financial statements and affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses.  Judgments, estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Actual results may differ from these judgments, estimates and underlying assumptions.  The Interim Financial Statements were prepared with the same critical accounting estimates as disclosed in Pembina's consolidated audited annual financial statements and MD&A for the year ended December 31, 2011 in addition to the following: Business Combinations Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires Management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant and equipment and intangible assets acquired generally require the most judgment and include estimates of cash flows, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities, intangibles and goodwill in the purchase price analysis. Future net earnings can be affected as a result of changes in future depreciation and amortization, asset or goodwill impairment. Derivative Financial Instruments The Company's derivative financial instruments are recognized on the statement of financial position at fair value based on Management's estimate of commodity prices, share price and associated volatility, foreign exchange rates, interest rates, and the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors. Changes in Accounting Principles and Practices For a discussion of future changes to Pembina's IFRS accounting policies, see Pembina's MD&A for the year ended December 31, 2011. Subsequent to the Arrangement, Pembina reviewed and compared legacy Provident's accounting policies with the Company's existing policies and determined that there were no significant differences. Controls and Procedures Changes in internal control over financial reporting During the third quarter of 2012, there have been no changes in the Company's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting, except as noted below. In accordance with the provisions of National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, Management, including the CEO and CFO, have limited the scope of their design of the Company's disclosure controls and procedures and internal control over financial reporting to exclude controls, policies and procedures of Provident. Pembina acquired the assets of Provident and its subsidiaries on April 2, 2012. Provident's contribution to the Company's Interim Financial Statements for the quarter ended September 30, 2012 was approximately 38 percent of consolidated net revenue and approximately six percent of consolidated pre-tax earnings. Additionally, Provident's current assets and current liabilities were approximately 64 percent and 53 percent of consolidated current assets and liabilities, respectively, and its non-current assets and non-current liabilities were approximately 58 percent and 34 percent of consolidated non-current assets and non-current liabilities, respectively. The scope limitation is primarily based on the time required to assess Provident's disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICFR") in a manner consistent with the Company's other operations. Further details related to the Arrangement are disclosed in Note 3 in the Notes to the Company's Interim Financial Statements for the third quarter of 2012. Trading Activity and Total Enterprise Value(1)                   As at and for the 3       months ended ($ millions, except where noted) November 2, 2012(2) September 30, 2012 September 30, 2011 Trading volume and value         Total volume (shares) 10,113,704  32,503,841 14,789,753   Average daily volume (shares) 421,404  524,256 234,758   Value traded 280.4        876.4       371.8 Shares outstanding (shares) 290,430,401  290,506,020 167,661,608 Closing share price (dollars) 27.99        27.60       25.65 Market value         Shares 8,157.1        8,018.0       4,300.5   5.75% convertible debentures (PPL.DB.C) 333.3(3) 329.0(4)       308.9   5.75% convertible debentures (PPL.DB.E) 198.0(5) 202.2(6)     5.75% convertible debentures (PPL.DB.F) 189.4(7) 190.3(8)   Market capitalization 8,877.8        8,739.5       4,609.4 Senior debt 1,907.0        1,832.0       1,251.7 Total enterprise value(9) 10,784.8        10,571.5       5,861.1 (1)  Trading information in this table reflects the activity of Pembina securities on the TSX. (2)  Based on 24 trading days from October 1, 2012 to November 2, 2012, inclusive. (3)  $299.7 million principal amount outstanding at a market price of $111.20 at November 2, 2012 and with a conversion price of $28.55 . (4)  $299.7 million principal amount outstanding at a market price of $109.76 at September 30, 2012 and with a conversion price of $28.55. (5)  $172.2 million principal amount outstanding at a market price of $115.01 at November 2, 2012 and with a conversion price of $24.94. (6)  $172.2 million principal amount outstanding at a market price of $117.48 at September 30, 2012 and with a conversion price of $24.94. (7)  $172.4 million principal amount outstanding at a market price of $109.81 at November 2, 2012 and with a conversion price of $29.53. (8)  $172.4 million principal amount outstanding at a market price of $110.37 at September 30, 2012 and with a conversion price of $29.53. (9)  Refer to "Non-GAAP Measures." As indicated in the previous table, Pembina's total enterprise value was $10.6 billion at September 30, 2012 and issued and outstanding shares of Pembina rose to 290.5 million at the end of the third quarter 2012 primarily due to shares issued under the Arrangement, compared to 167.7 million at the end of the same period in 2011. Dividends On April 12, 2012, following closing of the Arrangement, Pembina announced an increase in its monthly dividend rate 3.8 percent from $0.13 per share per month (or $1.56 annualized) to $0.135 per share per month (or $1.62 annualized). Pembina is committed to providing increased shareholder returns over time by providing stable dividends and, where appropriate, further increases in Pembina's dividend, subject to compliance with applicable laws and the approval of Pembina's Board of Directors. Pembina has a history of delivering dividend increases once supportable over the long-term by the underlying fundamentals of Pembina's businesses as a result of, among other things, accretive growth projects or acquisitions (see "Forward-Looking Statements & Information"). Dividends are payable if, as, and when declared by Pembina's Board of Directors. The amount and frequency of dividends declared and payable is at the discretion of the Board of Directors, which will consider earnings, capital requirements, the financial condition of Pembina and other relevant factors. Eligible Canadian investors may benefit from an enhanced dividend tax credit afforded to the receipt of dividends, depending on individual circumstances. Dividends paid to eligible U.S. investors should qualify for the reduced rate of tax applicable to long-term capital gains but investors are encouraged to seek independent tax advice in this regard. DRIP Pembina has reinstated its DRIP as of January 25, 2012. Eligible Pembina shareholders have the opportunity to receive, by reinvesting the cash dividends declared payable by Pembina on their shares, either (i) additional common shares at a discounted subscription price equal to 95 percent of the Average Market Price (as defined in the DRIP), pursuant to the "Dividend Reinvestment Component" of the DRIP, or (ii) a premium cash payment (the "Premium Dividend?") equal to 102 percent of the amount of reinvested dividends, pursuant to the "Premium Dividend? Component" of the DRIP. Additional information about the terms and conditions of the DRIP can be found at www.pembina.com. Participation in the DRIP for the third quarter was 56 percent of common shares outstanding for proceeds of approximately $66.3 million. Listing on the NYSE On April 2, 2012, Pembina listed its common shares, including those issued under the Arrangement, on the NYSE under the symbol "PBA". Risk Factors Management has identified the primary risk factors that could potentially have a material impact on the financial results and operations of Pembina. Such risk factors are presented in Pembina's MD&A and Provident's MD&A for the year ended December 31, 2011, in Pembina's Annual Information Form ("AIF") for the year ended December 31, 2011 and in Provident's AIF for the year ended December 31, 2011. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com. Provident's MD&A is available at www.pembina.com and its AIF can be found on Pembina NGL Corporation's (the successor to Provident following the completion of the Arrangement) company profile on www.sedar.com or on Provident's profile at www.sec.gov. Selected Quarterly Operating Information                             2012       2011       2010   Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Average volume (mbpd)                   Conventional Throughput 443.9 433.9 466.9 422.8 430.4 411.4 390.3 375.0 361.4 Oil Sands & Heavy Oil(1) 870.0 870.0 870.0 870.0 775.0 775.0 775.0 775.0 775.0 Gas Services Processing (mboe/d)(2) 45.8 47.5 44.1 45.3 41.3 40.9 39.4 42.1 38.9 NGL sales volume (mboe/d) 86.7 90.4               (1)    Oil Sands & Heavy Oil throughput refers to contracted capacity. (2)   Converted to mboe/d from MMcf/d at a 6:1 ratio. Selected Quarterly Financial Information                             2012       2011       2010 ($ millions, except where noted) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Revenue 815.3 870.9 475.5 468.1 300.6 512.4 394.9 290.7 266.1 Operations 69.5 67.7 48.4 55.1 54.4 37.6 44.8 41.9 40.0 Cost of goods sold including product purchases 565.5 641.9 299.1 308.0 145.8 364.3 254.2 161.8 148.2 Realized gain (loss) on commodity related derivative financial instruments (2.8) (12.4) (0.3) 0.8 3.2 (0.2) 1.4 (0.8) 0.3 Operating margin(1) 177.5 148.9 127.7 105.8 103.6 110.3 97.3 86.2 78.2 Depreciation and amortization included in operations 51.6 52.5 21.7 19.5 17.8 15.8 14.8 15.6 15.3 Unrealized gain (loss) on commodity-related derivative financial instruments (23.0) 64.8 (3.5) 0.9 0.7 3.3 0.3 1.8 (3.2) Gross profit 102.9 161.2 102.5 87.2 86.5 97.8 82.8 72.4 59.7 Adjusted EBITDA(1) 153.8 125.9 111.4 88.2 89.9 103.3 87.2 79.1 68.1 Cash flow from operating activities 130.9 24.1 65.3 74.3 87.7 49.5 74.5 54.6 66.6 Cash flow from operating activities per common share ($ per share) 0.45 0.08 0.39 0.44 0.52 0.30 0.45 0.33 0.41 Adjusted cash flow from operating activities(1) 133.2 89.5 98.8 57.3 82.0 81.8 76.0 62.6 67.6 Adjusted cash flow from operating activities per common share(1) ($ per share) 0.46 0.31 0.59 0.34 0.49 0.49 0.45 0.39 0.41 Earnings for the period 30.7 80.4 32.6 45.1 30.1 48.0 42.5 55.2 28.6 Earnings per common share ($ per share)                     Basic 0.11 0.28 0.19 0.27 0.18 0.29 0.25 0.34 0.19   Diluted 0.11 0.28 0.19 0.27 0.18 0.29 0.25 0.33 0.19 Common shares outstanding (millions):                     Weighted average (basic) 289.2 285.3 168.3 167.4 167.6 167.3 167.0 165.0 164.0   Weighted average (diluted) 289.7 286.0 168.9 168.2 168.2 168.0 167.6 171.7 166.9   End of period 290.5 287.8 169.0 167.9 167.7 167.5 167.1 166.9 164.5 Dividends declared 117.3 116.2 65.7 65.4 65.4 65.3 65.1 64.6 64.0 Dividends per common share ($ per share)       0.405 0.405 0.390 0.390 0.390 0.390 0.390 0.390 0.390 (1)  Refer to "Non-GAAP measures." During the above periods, Pembina's results were influenced by the following factors and trends: Increased oil production from customers operating in the Cardium and Deep Basin Cretaceous formations of west central Alberta, which has resulted in increased service offerings in these areas, as well as new connections and capacity expansions; Increased liquids-rich natural gas production from producers in the WCBS (Deep Basin, Montney, Cardium and emerging Duvernay Shale plays), which has resulted in increased gas gathering and processing at the Company's gas services assets and additional associated NGL transported on its pipelines; Revenue contribution from the Nipisi and Mitsue Pipelines, which were completed in June and July of 2011; and The acquisition of Provident, which closed on April 2, 2012 (for more details please see Note 3 of the Interim Financial Statements for the period ended September 30, 2012). Additional Information Additional information about Pembina and legacy Provident filed with Canadian securities commissions and the United States Securities Commission ("SEC"), including quarterly and annual reports, Annual Information Forms (filed with the SEC under Form 40-F), Management Information Circulars and financial statements can be found online at www.sedar.com, www.sec.gov and Pembina's website at www.pembina.com. Non-GAAP Measures Throughout this MD&A, Pembina has used the following terms that are not defined by GAAP but are used by Management to evaluate performance of Pembina and its business. Since certain Non-GAAP financial measures may not have a standardized meaning, securities regulations require that Non-GAAP financial measures are clearly defined, qualified and reconciled to their nearest GAAP measure. Concurrent with the acquisition of Provident, certain Non-GAAP Measures definitions have changed from those previously used to better reflect the changes in aspects of Pembina's business activities. Earnings before interest, taxes, depreciation and amortization ("EBITDA") EBITDA is commonly used by Management, investors and creditors in the calculation of ratios for assessing leverage and financial performance and is calculated as results from operating activities plus share of profit from equity accounted investees (before tax) plus depreciation and amortization (included in operations and general and administrative expense) and unrealized gains or losses on commodity-related derivative financial instruments. Adjusted EBITDA is EBITDA excluding acquisition-related expenses in connection with the Arrangement.                   3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except per share amounts)       2012       2011       2012       2011 Results from operating activities 74.5 71.5 272.2 225.2 Share of profit from equity accounted investees (before tax, depreciation and amortization) 1.4 0.5 4.2 9.7 Depreciation and amortization 53.2 18.6 129.9 49.8 Unrealized loss (gain) on commodity-related derivative financial instruments 23.0 (0.7) (38.3) (4.3) EBITDA 152.1 89.9 368.0 280.4 Add:         Acquisition-related expenses 1.7   23.1   Adjusted EBITDA 153.8 89.9 391.1 280.4 EBITDA per common share - basic (dollars) 0.53 0.54 1.49 1.68 Adjusted EBITDA per common share - basic (dollars) 0.53 0.54 1.58 1.68 Adjusted earnings Adjusted earnings is commonly used by Management for assessing and comparing financial performance each reporting period and is calculated as earnings before tax excluding unrealized gains or losses on derivative financial instruments and acquisition-related expenses in connection with the Arrangement plus share of profit from equity accounted investees (before tax).                     3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except per share amounts)       2012       2011       2012       2011 Earnings before income tax and equity accounted investees 41.4 41.0 192.8 155.5 Add (deduct):         Unrealized change in fair value of derivative financial instruments 23.1 6.8 (46.6) 4.0 Share of (loss) profit of investments in equity accounted investees (after tax) (0.6) (0.6) (1.0) 4.3 Tax on share of profit of investments in equity accounted investees (0.2) (0.2) (0.4) 1.4 Acquisition-related expenses 1.7   23.1   Adjusted earnings 65.4 47.0 167.9 165.2 Adjusted earnings per common share - basic (dollars) 0.23 0.28 0.68 0.99 Adjusted cash flow from operating activities Adjusted cash flow from operating activities is commonly used by Management for assessing financial performance each reporting period and is calculated as cash flow from operating activities plus the change in non-cash working capital and excluding acquisition-related expenses.                     3 Months Ended       September 30       9 Months Ended       September 30 ($ millions, except per share amounts)       2012       2011       2012       2011 Cash flow from operating activities 130.9 87.7 220.3 211.7 Add:         Change in non-cash working capital 0.6 (5.7) 78.1 28.1 Acquisition-related expenses 1.7   23.1   Adjusted cash flow from operating activities 133.2 82.0 321.5 239.8 Adjusted cash flow from operating activities per common share - basic (dollars) 0.46 0.49 1.30 1.43 Operating margin Operating margin is commonly used by Management for assessing financial performance and is calculated as gross profit before depreciation and amortization included in operations and unrealized gain (loss) on commodity-related derivative financial instruments. Reconciliation of operating margin to gross profit:                   3 Months Ended       September 30  9 Months Ended   September 30 ($ millions)       2012       2011       2012       2011 Revenue 815.3 300.6 2,161.7 1,207.9 Cost of sales:           Operations 69.5 54.4 185.6 136.8   Cost of goods sold 565.5 145.8 1,506.4 764.3   Realized gain (loss) on commodity-related derivative financial instruments (2.8) 3.2 (15.6) 4.4 Operating margin 177.5 103.6 454.1 311.2 Depreciation and amortization included in operations 51.6 17.8 125.8 48.4 Unrealized gain (loss) on commodity-related derivative financial instruments (23.0) 0.7 38.3 4.3 Gross profit 102.9 86.5 366.6 267.1 Beginning in the second quarter of 2012, unrealized gain (loss) on commodity-related derivative financial instruments has been reclassified from net finance costs to be included in gross profit. Total enterprise value Total enterprise value, in combination with other measures, is used by Management and the investment community to assess the overall market value of the business. Total enterprise value is calculated based on the market value of common shares and convertible debentures at a specific date plus senior debt. Management believes these supplemental Non-GAAP measures facilitate the understanding of Pembina's results from operations, leverage, liquidity and financial positions. Investors should be cautioned that EBITDA, adjusted EBITDA, adjusted earnings, adjusted cash flow from operating activities, operating margin and total enterprise value should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial results determined in accordance with GAAP as an indicator of Pembina's performance. Furthermore, these Non-GAAP measures may not be comparable to similar measures presented by other issuers. Forward-Looking Statements & Information In the interest of providing our securityholders and potential investors with information regarding Pembina, including Management's assessment of our future plans and operations, certain statements contained in this MD&A constitute forward-looking statements or information (collectively, "forward-looking statements") within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "could", "believe", "plan", "intend", "design", "target", "undertake", "view", "indicate", "maintain", "explore", "entail", "schedule", "objective", "strategy", "likely", "potential", "envision", "aim", "outlook", "propose", "goal", "would", and similar expressions suggesting future events or future performance. By their nature, such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Pembina believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of the MD&A. In particular, this MD&A contains forward-looking statements, including certain financial outlook, pertaining to the following: the future levels of cash dividends that Pembina intends to pay to its shareholders; capital expenditure-estimates, plans, schedules, rights and activities and the planning, development, construction, operations and costs of pipelines, gas service facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, including, but not limited to, in relation to the PNT, the proposed Resthaven Facility and the proposed Saturn Facility, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in Central Alberta, the expansion of throughput capacity on the Northern NGL System and Peace crude system, the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven fee-for-service storage facilities at Redwater, the Redwater fractionator expansion, the proposed development of a C2+ fractionator at Redwater, and the potential offshore export opportunities for propane; future expansion of Pembina's pipelines and other infrastructure; pipeline, processing and storage facility and system operations and throughput levels; oil and gas industry exploration and development activity levels; Pembina's strategy and the development of new business initiatives; growth opportunities; expectations regarding Pembina's ability to raise capital and to carry out acquisition, expansion and growth plans; treatment under government regulatory regimes including environmental regulations and related abandonment and reclamation obligations; future G&A expenses at Pembina increased throughput potential due to increased activity and new connections and other initiatives on Pembina's pipelines; future cash flows, potential revenue and cash flow enhancements across Pembina's businesses and the maintenance of operating margins; tolls and tariffs and transportation, storage and services commitments and contracts; cash dividends and the tax treatment thereof; operating risks (including the amount of future liabilities related to pipeline spills and other environmental incidents) and related insurance coverage and inspection and integrity programs; the expected capacity of the proposed Resthaven Facility and the proposed Saturn Facility; expectations regarding in-service dates for new developments, including the Resthaven Facility, the Saturn Facility, the Northern NGL System and the Peace crude system; expectations regarding incremental NGL volumes to be transported on Pembina's conventional pipelines by the end of 2013 as a result of new developments in Pembina's Gas Services business; expectations regarding in-service dates for the seven fee-for-service storage facilities at Redwater, the Redwater fractionator expansion project and the proposed C2+ fractionator at Redwater; the possibility of offshore export opportunities for propane; the possibility of renegotiating debt terms, repayment of existing debt, seeking new borrowing and/or issuing equity; expectations regarding participation in Pembina's DRIP; the expected impact of changes in share price on annual share-based incentive expense; expectations regarding the potential construction, expansion and conversion of downstream infrastructure in the U.S. Midwest and Gulf Coast; the impact of approval from the British Columbia Utilities Commission of Pembina's application on the Western System; inventory and pricing levels in the North American liquids market; Pembina's discretion to hedge natural gas and NGL volumes; and competitive conditions. Various factors or assumptions are typically applied by Pembina in drawing conclusions or making the forecasts, projections, predictions or estimations set out in forward-looking statements based on information currently available to Pembina. These factors and assumptions include, but are not limited to: the success of Pembina's operations; prevailing commodity prices and exchange rates and the ability of Pembina to maintain current credit ratings; the availability of capital to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns; future operating costs; geotechnical and integrity costs associated with the Western System; in respect of the proposed Saturn Facility and the proposed Resthaven Facility and their estimated in-service dates of fourth quarter of 2013 and the first quarter of 2014, respectively; that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner, that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of such facilities; that such facilities will be fully supported by long-term firm service agreements accounting for the entire designed throughput at such facilities at the time of such facilities' completion; that there are no unforeseen construction costs related to the facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers; in respect of the expansion of NGL throughput capacity on the Northern NGL System and the crude throughput capacity on the Peace crude system and the estimated in-service dates with respect to the same; that Pembina will receive regulatory approval; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs related to the expansion; and that there are no unforeseen material costs relating to the pipelines that are not recoverable from customers; in respect of the proposed C2+ fractionator at Redwater; that Pembina will receive regulatory approval; that Pembina will reach satisfactory long-term arrangements with customers; that counterparties will comply with such contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the proposed fractionators that are not recoverable from customers; in respect of other developments, expansions and capital expenditures planned, including the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the expectation of additional NGL and crude volumes being transported on the conventional pipelines, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in central Alberta, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven-fee-for-service storage facilities at Redwater and the Redwater fractionator expansion that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the developments, expansions and capital expenditures which are not recoverable from customers; the future exploration for and production of oil, NGL and natural gas in the capture area around Pembina's conventional and midstream assets, including new production from the Cardium formation in western Alberta, the demand for gathering and processing of hydrocarbons, and the corresponding utilization of Pembina's assets; in respect of the stability of Pembina's dividend; prevailing commodity prices, margins and exchange rates; that Pembina's future results of operations will be consistent with past performance and management expectations in relation thereto; the continued availability of capital at attractive prices to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns; the success of growth projects; future operating costs; that counterparties to material agreements will continue to perform in a timely manner; that there are no unforeseen events preventing the performance of contracts; and that there are no unforeseen material construction or other costs related to current growth projects or current operations; and prevailing regulatory, tax and environmental laws and regulations. The actual results of Pembina could differ materially from those anticipated in these forward-looking statements as a result of the material risk factors set forth below: the regulatory environment and decisions; the impact of competitive entities and pricing; labour and material shortages; reliance on key alliances and agreements; the strength and operations of the oil and natural gas production industry and related commodity prices; non-performance or default by counterparties to agreements which Pembina or one or more of its affiliates has entered into in respect of its business; actions by governmental or regulatory authorities including changes in tax laws and treatment, changes in royalty rates or increased environmental regulation; fluctuations in operating results; adverse general economic and market conditions in Canada, North America and elsewhere, including changes in interest rates, foreign currency exchange rates and commodity prices; the failure to realize the anticipated benefits of the Arrangement; the failure to complete remaining integration of the businesses of Pembina and Provident; and the other factors discussed under "Risk Factors" in Pembina's MD&A and Provident's MD&A for the year ended December 31, 2011, in Pembina's Annual Information Form ("AIF") for the year ended December 31, 2011 and in Provident's AIF for the year ended December 31, 2011. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com. Provident's MD&A is available at www.pembina.com and its AIF can be found on Pembina NGL Corporation's company profile on www.sedar.com or on Provident's profile at www.sec.gov. These factors should not be construed as exhaustive. Unless required by law, Pembina does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Any forward-looking statements contained herein are expressly qualified by this cautionary statement. CONDENSED CONSOLIDATED INTERIM STATEMENT OF FINANCIAL POSITION (unaudited)           ($ thousands) Note September 30, 2012 December 31, 2011 Assets Current assets         Cash and cash equivalents   25,391     Trade receivables and other   294,168 148,267   Derivative financial instruments 13 21,885 4,643   Inventory   140,719 21,235     482,163 174,145 Non-current assets         Property, plant and equipment 4 4,914,846 2,747,530   Intangible assets and goodwill 5 2,644,145 243,904   Investments in equity accounted investees   158,580 161,002   Derivative financial instruments 13 110 1,807   Other receivables   3,983 10,814     7,721,664 3,165,057 Total Assets   8,203,827 3,339,202 Liabilities and Shareholders' Equity Current liabilities         Bank indebtedness     676   Trade payables and accrued liabilities   308,182 166,646   Dividends payable   39,218 21,828   Loans and borrowings 6 11,319 323,927   Derivative financial instruments 13 21,785 4,725     380,504 517,802 Non-current liabilities         Loans and borrowings 6 1,824,497 1,012,061   Convertible debentures 7 608,668 289,365   Derivative financial instruments 13 53,606 12,813   Employee benefits   14,701 16,951   Share-based payments   14,321 14,060   Deferred revenue   2,943 2,185   Provisions 8 483,412 405,433   Deferred tax liabilities   568,656 106,915     3,570,804 1,859,783 Total Liabilities   3,951,308 2,377,585 Shareholders' Equity       Equity attributable to shareholders:         Share capital 9 5,253,122 1,811,734   Deficit   (990,658) (834,921)   Accumulated other comprehensive income   (15,196) (15,196)     4,247,268 961,617 Non-controlling interest   5,251       4,252,519 961,617 Total Liabilities and Shareholders' Equity   8,203,827 3,339,202         See accompanying notes to the Interim Financial Statements CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME (unaudited)                  3 Months Ended  September 30 9 Months Ended  September 30 ($ thousands, except per share amounts) Note 2012 2011 2012 2011 Revenue   815,347 300,620 2,161,767 1,207,913 Cost of sales   686,578 218,050 1,817,887 949,601 (Loss) gain on commodity-related derivative financial instruments 13 (25,846) 3,895 22,731 8,744 Gross profit 11 102,923 86,465 366,611 267,056               General and administrative   26,870 13,765 70,229 41,193   Acquisition-related and other expense   1,509 1,224 24,178 642     28,379 14,989 94,407 41,835             Results from operating activities   74,544 71,476 272,204 225,221   Finance income   (6,862) (268) (9,236) (1,179)   Finance costs   39,973 30,733 88,601 70,932   Net finance costs 10 33,111 30,465 79,365 69,753             Earnings before income tax and equity accounted investees   41,433 41,011 192,839 155,468             Share of loss (profit) of investments in equity accounted investees, net of tax   572 585 970 (4,257)               Income tax expense   10,162 10,305 48,210 39,069             Earnings and total comprehensive income for the period   30,699 30,121 143,659 120,656             Earnings and comprehensive income attributable to:             Shareholders   30,555 30,121 143,475 120,656   Non-controlling interest   144   184       30,699 30,121 143,659 120,656             Earnings per share attributable to the shareholders of the Company                                   Basic and diluted earnings per share (dollars)         0.11       0.18       0.58       0.72             See accompanying notes to the Interim Financial Statements CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY (unaudited)                   9 Months Ended September 30 ($ thousands) Note 2012 2011 Share Capital         Balance, beginning of period   1,811,734 1,794,536   Common shares issued on acquisition 3 3,283,976     Dividend reinvestment plan   151,131     Share-based payment transactions   5,865 12,767   Debenture conversions and other   416 22   Balance, end of period 9 5,253,122 1,807,325         Deficit         Balance, beginning of period   (834,921) (739,351)   Earnings for the period attributable to shareholders   143,475 120,656   Dividends declared 9 (299,212) (195,789)   Balance, end of period   (990,658) (814,484)         Other Comprehensive Loss         Balance, beginning and end of period   (15,196) (4,577)         Non-controlling interest         Balance, beginning of period         Assumed on acquisition 3 5,067     Earnings attributable to non-controlling interest   184     Balance, end of period   5,251   Total Equity   4,252,519 988,264           See accompanying notes to the Interim Financial Statements CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS (unaudited)                       3 Months Ended       September 30       9 Months Ended       September 30 ($ thousands) Note 2012 2011 2012 2011 Cash provided by (used in):           Operating activities:           Earnings for the period   30,699 30,121 143,659 120,656 Adjustments for:             Depreciation and amortization   53,210 18,671 129,887 49,846   Unrealized loss (gain) on commodity-related derivative financial instruments 13 22,987 (687) (38,286) (4,285)   Net finance costs 10 33,111 30,465 79,365 69,753   Share of loss (profit) of investments in equity accounted investees, net of tax   572 585 970 (4,257)   Deferred income tax expense   9,243 10,305 47,893 39,069   Share-based payments   5,321 3,051 11,620 10,940   Employee future benefits expense   1,921 1,188 5,250 3,589   Increase in provisions     2,321   2,321   Other   (350) 434 117 374   Changes in non-cash working capital   (623) 5,688 (78,145) (28,073)   Distributions from investments in equity accounted investees   1,514 4,216 9,247 12,901   Decommissioning liability expenditures   (570) (114) (2,937) (1,889)   Employee future benefit contributions   (2,500) (2,000) (7,500) (6,000)   Net interest paid   (23,635) (16,563) (80,833) (53,281) Cash flow from operating activities   130,900 87,683 220,307 211,664 Financing activities             Bank borrowings   80,000 24,627 346,861 64,627   Repayment of loans and borrowings   (805) (2,764) (60,841) (87,864)   Issuance of debt         250,000   Financing fees     (18) (5,066) (1,774)   Exercise of stock options   1,810 2,992 4,457 12,078   Issue of shares under Dividend Reinvestment Plan   66,157   151,131     Dividends paid   (116,922) (65,349) (281,822) (195,688) Cash flow from financing activities   30,240 (40,512) 154,720 41,379 Investing activities:             Net capital expenditures   (138,730) (82,245) (357,834) (378,917)   Cash acquired on acquisition       8,874   Cash flow used in investing activities   (138,730) (82,245) (348,960) (378,917) Change in cash   22,410 (35,074) 26,067 (125,874) Cash (bank indebtedness), beginning of period   2,981 34,597 (676) 125,397 Cash and cash equivalents, end of period   25,391 (477) 25,391 (477)             See accompanying notes to the Interim Financial Statements NOTES TO THE INTERIM FINANCIAL STATEMENTS (unaudited) 1. REPORTING ENTITY Pembina Pipeline Corporation ("Pembina" or the "Company") is an energy transportation and service provider domiciled in Canada. The condensed consolidated unaudited interim financial statements ("Interim Financial Statements") include the accounts of the Company, its subsidiary companies, partnerships and any interests in associates and jointly controlled entities as at and for the nine months ending September 30, 2012. These Interim Financial Statements and the notes thereto have been prepared in accordance with IAS 34 - Interim Financial Reporting. They do not include all of the information required for full annual financial statements and should be read in conjunction with the consolidated financial statements of the Company as at and for the year ended December 31, 2011. The Interim Financial Statements were authorized for issue by the Board of Directors on November 6, 2012. Pembina owns or has interests in pipelines that transport conventional crude oil and natural gas liquids, oil sands and heavy oil pipelines, gas gathering and processing facilities, and a natural gas liquids infrastructure and logistics business. Facilities are located in Canada and in the U.S. Pembina also offers midstream services that span across its operations. 2. SIGNIFICANT ACCOUNTING POLICIES The accounting policies are set out in the December 31, 2011 financial statements. Those policies have been applied consistently to all periods presented in these Interim Financial Statements except for an addition to an accounting policy as a result of the acquisition of Provident Energy Ltd. which is provided below. Inventories Inventories are measured at the lower of cost and net realizable value and consist primarily of crude oil and natural gas liquids. The cost of inventories is determined using the weighted average costing method and includes direct purchase costs and when applicable, costs of production, extraction, fractionation costs, and transportation costs. Net realizable value is the estimated selling price in the ordinary course of business less the estimated selling costs. All changes in the value of the inventories are reflected in inventories and cost of sales. Certain of the prior period's comparative figures have been reclassified to conform to the current year's presentation. 3. ACQUISITION On April 2, 2012, Pembina acquired all of the outstanding Provident Energy Ltd. ("Provident") common shares (the "Provident Shares") in exchange for Pembina common shares valued at approximately $3.3 billion (the "Arrangement"). Provident shareholders received 0.425 of a Pembina common share for each Provident Share held for a total of 116,535,750 Pembina common shares. On closing, Pembina assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2017, and the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2018 (collectively, the "Provident Debentures"). The face value of the outstanding Provident Debentures at April 2, 2012 was $345 million. The debentures remain outstanding and continue with terms and maturity as originally set out in their respective indentures. Pursuant to the Arrangement, Provident amalgamated with a wholly-owned subsidiary of Pembina and has continued under the name "Pembina NGL Corporation". The results of the acquired business are included as part of the Midstream business. The purchase price allocation based on assessed fair values is estimated as follows:     ($ millions)   Cash 9 Trade receivables and other 195 Inventory 87 Property, plant and equipment 1,988 Intangible assets and goodwill (including $1,761 goodwill) 2,422 Trade payables and accrued liabilities (249) Derivative financial instruments - current (53) Derivative financial instruments - non-current (36) Loans and borrowings (215) Convertible debentures (317) Provisions and other (128) Deferred tax liabilities (414) Non-controlling interest (5)   3,284     The determination of fair values and the allocation of the purchase price is based upon an independent valuation. The primary drivers that generate goodwill are synergies and business opportunities from the integration of Pembina and Provident and the acquisition of a talented workforce. None of the goodwill recognized is expected to be deductible for income tax purposes. Upon closing of the Arrangement, Pembina repaid Provident's revolving term credit facility of $205 million. The Company has recognized $23.1 million in acquisition-related expenses. These expenses are included in acquisition-related and other expenses in the Interim Financial Statements. The Pembina Shares were listed and began trading on the NYSE under the symbol "PBA" on April 2, 2012. Revenue generated by the Provident business for the period from the acquisition date of April 2, 2012 to September 30, 2012, before intersegment eliminations, was $676.1 million. Net earnings, before intersegment eliminations, for the same period were $45.2 million. Unaudited proforma consolidated revenue (prepared as if the Provident acquisition had occurred on January 1, 2012) for the nine months ended September 30, 2012 are $2,701.9 million and net earnings for the same period are $190.8 million. 4. PROPERTY, PLANT AND EQUIPMENT               ($ thousands) Land and Land Rights Pipelines Facilities and Equipment Linefill and Other Assets Under Construction Total Cost             Balance at December 31, 2011 67,219 2,500,027 528,620 200,726(1) 307,358 3,603,950(1) Acquisition (Note 3) 18,093 280,435 1,281,073 321,277 87,318 1,988,196 Additions 5,885 5,081 120,395 25,689 172,604 329,654 Change in decommissioning provision   (35,335) (17,688)     (53,023) Capitalized interest   79 98   9,589 9,766 Transfers 22 (75,270) 116,226 (16,496) (24,482)   Disposals and other (5,001) (917) (533) 771   (5,680) Balance at September 30, 2012 86,218 2,674,100 2,028,191 531,967 552,387 5,872,863               Depreciation             Balance at December 31, 2011 4,088 707,095 92,998 52,239   856,420 Depreciation 210 53,087 35,774 13,894   102,965 Transfers   3,091 22,454 (25,545)     Disposals and other   (567) (89) (712)   (1,368) Balance at September 30, 2012 4,298 762,706 151,137 39,876   958,017               Carrying amounts             December 31, 2011 63,131 1,792,932 435,622 148,487 307,358 2,747,530 September 30, 2012 81,920 1,911,394 1,877,054 492,091 552,387 4,914,846 (1)  $1.5 million was reclassified from inventory to Linefill and Other at December 31, 2011.     Pipeline assets are generally depreciated using the straight line method over 5 to 75 years (an average of 49 years) or declining balance method at rates ranging from 3 percent to 48 percent per annum (an average rate of 15 percent per annum). Facilities and equipment are depreciated using the straight line method over 3 to 75 years (at an average rate of 35 years) or declining balance method at rates ranging from 3 percent to 37 percent (at an average rate of 12 percent per annum). Other assets are depreciated using the straight line method over 2 to 45 years (an average of 23 years) or declining balance method at rates ranging from 3 percent to 37 percent (at an average rate of 2 percent per annum). Commitments At September 30, 2012, the Company has contractual commitments for the acquisition and or construction of property, plant and equipment of $497.0 million (December 31, 2011: $364.3 million). 5. INTANGIBLE ASSETS AND GOODWILL           Goodwill Other Intangibles Total ($ thousands)       Cost       Balance at December 31, 2011 222,670 23,038 245,708 Acquisition (Note 3) 1,761,264 660,899 2,422,163 Additions and other   5,000 5,000 Balance at September 30, 2012 1,983,934 688,937 2,672,871 Amortization       Balance at December 31, 2011   1,804 1,804 Amortization   26,922 26,922 Balance at September 30, 2012   28,726 28,726 Carrying amounts       December 31, 2011 222,670 21,234 243,904 September 30, 2012 1,983,934 660,211 2,644,145         Amortization is recognized in profit or loss on a straight-line or declining balance basis over the estimated useful lives of depreciable intangible assets from the date that they are available for use. The estimated useful lives of other intangible assets with finite useful lives range from 3 to 33 years (an average of 9 years). The preliminary allocation of the aggregate carrying amount of intangible assets to each operating segment is as follows:         September 30, December 31, ($ thousands) 2012 2011 Conventional Pipelines 194,370 194,370 Oil Sands and Heavy Oil 33,300 28,300 Gas Services 20,710 21,234 Midstream 2,395,765     2,644,145 243,904       The allocation is subject to change based on additional information obtained subsequent to the valuation. See Note 3. 6. LOANS AND BORROWINGS Carrying value terms and debt repayment schedule Terms and conditions of outstanding loans were as follows:             ($ thousands)       Carrying amount(3)   Available facilities Nominal interest rate Year of maturity September 30, 2012 December 31, 2011 Operating facility(1) 30,000 prime + 0.50 or BA(2) + 1.50 2013   3,139 Revolving unsecured credit facility 1,500,000 prime + 0.50 or BA(2) + 1.50 2017 860,481 309,981 Senior secured notes         7.38     57,499 Senior unsecured notes - Series A 175,000       5.99 2014 174,623 174,462 Senior unsecured notes - Series C 200,000       5.58 2021 196,897 196,638 Senior unsecured notes - Series D 267,000       5.91 2019 265,554 265,403 Senior unsecured term facility 75,000       6.16 2014 74,764 74,658 Senior unsecured medium term notes 250,000       4.89 2021 248,675 248,558 Subsidiary debt 9,169       4.99 2014 9,169   Finance lease liabilities       5,653 5,650 Total interest bearing liabilities 2,506,169           1,835,816 1,335,988 Less current portion       (11,319) (323,927) Total non-current       1,824,497 1,012,061 (1)  Operating facility expected to be renewed on an annual basis. (2)  Bankers' Acceptance. (3)  Deferred financing fees are all classified as non-current. Non-current carrying amount of facilities are net of deferred financing fees. 7. CONVERTIBLE DEBENTURES           ($ thousands) Series C - 5.75% Series E - 5.75% Series F - 5.75% Total Conversion price (dollars) $28.55 $24.94 $29.53   Interest payable semi-annually in arrears on: May 31 and November 30 June 30 and December 31 June 30 and December 31   Maturity date November 30, 2020 December 31, 2017 December 31, 2018   Balance, December 31, 2011 289,365     289,365 Assumed on acquisition(1) (Note 3)   158,471 158,343 316,814 Conversions and redemptions (54) (332) (55) (441) Unwinding of discount rate   561 460 1,021 Deferred financing fee (net amortization) 876 550 483 1,909 Balance, September 30, 2012 290,187 159,250 159,231 608,668 (1)  Excludes conversion feature of convertible debentures. The Company may, at its option on or after December 31, 2013 and prior to December 31, 2015, elect to redeem the Series E debentures in whole or in part, provided that the volume weighted average trading price of the common price of the shares on the TSX during the 20 consecutive trading days ending on the fifth trading day preceding the date on which the notice of redemption is given is not less than 125 percent of the conversion price of the Series E debentures. On or after December 31, 2015, the Series E debentures may be redeemed in whole or in part at the option of the Company at a price equal to their principal amount plus accrued and unpaid interest. Any accrued unpaid interest will be paid in cash. The Company may, at its option on or after December 31, 2014 and prior to December 31, 2016, elect to redeem the Series F debentures in whole or in part, provided that the volume weighted average trading price of the common price of the shares on the TSX during the 20 consecutive trading days ending on the fifth trading day preceding the date on which the notice of redemption is given is not less than 125 percent of the conversion price of the Series F debentures. On or after December 31, 2016, the Series F debentures may be redeemed in whole or in part at the option of the Company at a price equal to their principal amount plus accrued and unpaid interest. Any accrued unpaid interest will be paid in cash. The Company retains a cash conversion option on the Series E and F convertible debentures, allowing the Company to pay cash to the converting holder of the debentures, at the option of the Company. For convertible debentures with a cash conversion option, the equity conversion option is recognized as an embedded derivative and accounted for as a stand-alone derivative financial instrument, measured at fair value using an option pricing model. 8. PROVISIONS     ($ thousands) Total Balance at December 31, 2011(1) 416,153 Unwinding of discount rate 9,072 Assumed on acquisition (Note 3) 124,579 Decommissioning liabilities settled during the period (2,937) Change in rates (46,653) Change in estimate and other (14,357) Total 485,857 Less current portion (included in accrued liabilities) (2,445) Balance at September 30, 2012 483,412 (1)  Includes current provision of $10,720 at December 31, 2011 (included in accrued liabilities). 9. SHARE CAPITAL       ($ thousands, except share amounts) Number Share Capital Balance December 31, 2011 167,908,271 1,811,734 Issued on acquisition (Note 3) 116,535,750 3,283,976 Share based payment transactions 272,936 5,865 Dividend reinvestment plan 5,773,600 151,131 Other 15,463 416 Balance September 30, 2012 290,506,020(1) 5,253,122 (1)  Weighted average number of common shares outstanding for the three months ended September 30, 2012 is 289.2 million (September 30, 2011: 167.6 million). On a fully diluted basis, the weighted average number of common shares outstanding for the three months ended September 30, 2012 is 289.7 million (September 30, 2011: 168.2 million). Weighted average number of common shares outstanding for the nine months ended September 30, 2012 is 247.8 million (September 30, 2011: 167.3 million). On a fully diluted basis, the weighted average number of common shares outstanding for the nine months ended September 30, 2012 is 248.4 million (September 30, 2011: 168.0 million). Dividends The following dividends were declared by the Company:               9 Months Ended       September 30 ($ thousands) 2012 2011 $1.20 per qualifying common share (2011: $1.17 ) 299,212 195,789 On October 11, 2012, Pembina's Board of Directors declared a dividend for October of $39.3 million, representing $0.135 per qualifying common share ($1.62 annualized). 10. NET FINANCE COSTS                   3 Months Ended       September 30       9 Months Ended       September 30 ($ thousands) 2012 2011 2012 2011 Interest income from:           Related parties   (226) (263) (636)   Bank deposits (365) (23) (666) (412) Interest expense on financial liabilities measured at amortized cost:           Loans and borrowings 19,076 15,909 52,910 41,041   Convertible debentures 10,583 4,657 25,767 13,825   Finance leases 106 105 316 298   Unwinding of discount 3,317 2,605 9,118 7,510 Loss (gain) in fair value of non-commodity-related derivative financial instruments (6,497) 7,457 (4,100) 8,258 Loss (gain) in fair value of conversion feature of convertible debentures 6,670   (4,207)   Foreign exchange losses (gains) 221 (19) 490 (131) Net finance costs 33,111 30,465 79,365 69,753 11. OPERATING SEGMENTS                 3 Months Ended September 30, 2012 ($ thousands) Conventional Pipelines(1) Oil Sands & Heavy Oil Gas Services Midstream(3) Corporate & Intersegment Eliminations Total Revenue:               Pipeline transportation 79,044 44,101     (6,219) 116,926   NGL product and services, terminalling, storage and hub services       674,732   674,732   Gas Services     23,689     23,689 Total revenue 79,044 44,101 23,689 674,732 (6,219) 815,347   Operations 30,112 14,779 7,097 18,122 (633) 69,477   Cost of goods sold, including product purchases       571,678 (6,219) 565,459   Realized gain (loss) on commodity-related derivative financial instruments 496     (3,355)   (2,859) Operating margin 49,428 29,322 16,592 81,577 633 177,552   Depreciation and amortization (operational) 12,021 5,002 3,350 31,269   51,642   Unrealized gain (loss) on commodity-related derivative financial instruments (7,062)     (15,925)   (22,987) Gross profit 30,345 24,320 13,242 34,383 633 102,923   Depreciation included in general and administrative         1,568 1,568   Other general and administrative 1,845 994 974 4,480 17,009 25,302   Acquisition-related and other expenses (income) 10 (33)   69 1,463 1,509 Reportable segment results from operating activities 28,490 23,359 12,268 29,834 (19,407) 74,544 Net finance costs (income) 1,428 430 (10) (2,786) 34,049 33,111 Reportable segment earnings (loss) before tax and income from equity accounted investees 27,062 22,929 12,278 32,620 (53,456) 41,433 Share of loss (profit) of investments in equity accounted investees, net of tax       572   572 Reportable segment assets 596,104 1,090,764 564,037 4,533,374(2) 1,419,548 8,203,827 Capital expenditures 34,748 6,093 29,824 70,668 2,034 143,367 Reportable segment liabilities 300,417 82,710 45,704 792,599 2,729,878 3,951,308 (1) 6.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements. (2)  Includes investments in equity accounted investees of $158.6 million. (3) NGL product and services, terminalling, storage and hub services revenue includes $21.8 million associated with U.S. midstream sales.                             3 Months Ended September 30, 2011 ($ thousands) Conventional Pipelines(1) Oil Sands & Heavy Oil Gas Services Midstream Corporate & Intersegment Eliminations Total Revenue:               Pipeline transportation 78,689 36,983       115,672   NGL product and services, terminalling, storage and hub services       166,171   166,171   Gas Services     18,777     18,777 Total revenue 78,689 36,983 18,777 166,171   300,620   Operations 34,619 12,642 6,403 2,570 (1,840) 54,394   Cost of goods sold, including product purchases       145,832   145,832   Realized gain (loss) on commodity-related derivative financial instruments 1,712     1,496   3,208 Operating margin 45,782 24,341 12,374 19,265 1,840 103,602   Depreciation and amortization (operational) 10,423 3,907 2,522 972   17,824   Unrealized gain (loss) on commodity-related derivative financial instruments (21)     708   687 Gross profit 35,338 20,434 9,852 19,001 1,840 86,465   Depreciation included in general and administrative         847 847   Other general and administrative 1,510 870 892 1,267 8,379 12,918   Acquisition-related and other expenses (income) 1,313 (11) 1 (2) (77) 1,224 Reportable segment results from operating activities 32,515 19,575 8,959 17,736 (7,309) 71,476 Net finance costs 1,839 556 289 28 27,753 30,465 Reportable segment earnings (loss) before tax and income from equity accounted investees 30,676 19,019 8,670 17,708 (35,062) 41,011 Share of loss (profit) of investments in equity accounted investees, net of tax       585   585 Reportable segment assets 783,770 1,059,464 431,197 261,423(2) 636,638 3,172,492 Capital expenditures 20,297 13,954 28,990 5,041 8,905 77,187 Reportable segment liabilities 295,029 84,121 46,908 17,161 1,741,009 2,184,228 (1) 11.6 percent of Conventional Pipelines revenue is under regulated tolling arrangements. (2) Includes investments in equity accounted investees of $160.2 million.                             9 Months Ended September 30, 2012 ($ thousands) Conventional Pipelines(1) Oil Sands & Heavy Oil Gas Services Midstream(2) Corporate & Intersegment Eliminations Total Revenue:               Pipeline transportation 239,625 126,610     (13,094) 353,141   NGL product and services, terminalling, storage and hub services       1,743,674   1,743,674   Gas Services     64,952     64,952 Total revenue 239,625 126,610 64,952 1,743,674 (13,094) 2,161,767   Operations 87,573 39,385 20,295 40,271 (1,893) 185,631   Cost of goods sold, including product purchases       1,519,526 (13,094) 1,506,432   Realized gain (loss) on commodity-related derivative financial instruments (693)     (14,862)   (15,555) Operating margin 151,359 87,225 44,657 169,015 1,893 454,149   Depreciation and amortization (operational) 36,145 14,831 10,844 64,004   125,824   Unrealized gain (loss) on commodity-related derivative financial instruments (9,814)     48,100   38,286 Gross profit 105,400 72,394 33,813 153,111 1,893 366,611   Depreciation included in general and administrative         4,063 4,063   Other general and administrative 4,968 2,901 2,951 11,255 44,091 66,166   Acquisition-related and others 933 355 11 168 22,711 24,178 Reportable segment results from operating activities 99,499 69,138 30,851 141,688 (68,972) 272,204 Net finance costs (income) 4,792 1,470 754 1,614 70,735 79,365 Reportable segment earnings (loss) before tax and income from equity accounted investees 94,707 67,668 30,097 140,074 (139,707) 192,839 Share of loss (profit) of investments in equity accounted investees, net of tax       970   970 Capital expenditures 99,220 12,134 85,586 126,597 6,117 329,654 (1) 5.1 percent of Conventional Pipelines revenue is under regulated tolling arrangements. (2) NGL product and services, terminalling, storage and hub services revenue includes $50.5 million associated with U.S. midstream sales.                             9 Months Ended September 30, 2011 ($ thousands) Conventional Pipelines(1) Oil Sands & Heavy Oil Gas Services Midstream Corporate & Intersegment Eliminations Total Revenue:               Pipeline transportation 220,353 95,236       315,589   NGL product and services, terminalling, storage and hub services       839,961   839,961   Gas Services     52,363     52,363 Total revenue 220,353 95,236 52,363 839,961   1,207,913   Operations 83,625 31,601 16,286 7,138 (1,841) 136,809   Cost of goods sold, including product purchases       764,321   764,321   Realized gain (loss) on commodity-related derivative financial instruments 3,167     1,292   4,459 Operating margin 139,895 63,635 36,077 69,794 1,841 311,242   Depreciation and amortization (operational) 30,535 7,887 7,322 2,727   48,471   Unrealized gain (loss) on commodity-related derivative financial instruments 4,630     (345)   4,285 Gross profit 113,990 55,748 28,755 66,722 1,841 267,056   Depreciation included in general and administrative         1,375 1,375   Other general and administrative 4,208 2,020 2,971 3,552 27,067 39,818   Acquisition-related and other expense  (income) 858 (118) 6 4 (108) 642 Reportable segment results from operating activities 108,924 53,846 25,778 63,166 (26,493) 225,221 Net finance costs 5,382 1,230 747 67 62,327 69,753 Reportable segment earnings (loss) before tax and income from equity accounted investees 103,542 52,616 25,031 63,099 (88,820) 155,468 Share of loss (profit) of investments in equity accounted investees, net of tax       (4,257)   (4,257) Capital expenditures 47,083 143,852 70,083 106,950 10,697 378,665 (1)  11.6 percent of Conventional Pipelines revenue is under regulated tolling arrangements. 12. SHARE BASED PAYMENTS Long-term share unit award incentive plan(1)       Grant date Performance Share Units ("PSU")(4) to Officers, Non-Officers(2) and Directors (Number of units in thousands) Units Contractual life of options January 1, 2012 188 3.0 Years April 2, 2012 (on acquisition) 201 2.2 Years             Grant date Restricted Share Units ("RSU")(3) to Officers, Non-Officers(2) and Directors (Number of units in thousands) Units Contractual life of options January 1, 2012 187 3.0 Years April 2, 2012 (on acquisition) 177 2.2 Years (1)  Distribution Units are granted in addition to RSU and PSU grants based on notional accrued dividends from RSU and PSU granted but not paid. (2)  Non-Officers defined as senior selected positions within the Company. (3)  One third vests on the first anniversary of the grant date, one third vests on the second anniversary of the grant date, and one third vests on the third anniversary of the grant date. (4)  Vest on the third anniversary of the grant date. Actual PSUs awarded is based on the trading value of the shares and performance of the Company. Disclosure of share option plan The number and weighted average exercise prices of share options as follows:         Number of Options Weighted Average Exercise Price Outstanding at December 31, 2011 2,674,380 20.24 Granted 1,446,100 26.67 Exercised (272,936) 16.17 Forfeited (132,163) 24.29 Outstanding as at September 30, 2012 3,715,381 22.90 13. FINANCIAL INSTRUMENTS The following table is a summary of the net derivative financial instrument liability:       ($ thousands) As at September 30, 2012 As at December 31, 2011 Frac spread related       Natural gas (8,676)     Propane 7,336     Butane 4,467     Condensate 2,878     Foreign exchange 2,631     Sub-total frac spread related 8,636   Management of exposure embedded in physical contracts and other (6,632) 2,267 Corporate       Power (8,442) 4,183   Interest rate (15,937) (17,538) Other derivative financial instruments       Conversion feature of convertible debentures (25,500)     Redemption liability related to acquisition of subsidiary (5,521)   Net derivative financial instruments liability (53,396) (11,088) In conjunction with the Arrangement, the Company acquired a two-thirds ownership interest in Provident's subsidiary, Three Star Trucking Ltd. ("Three Star"), which included a redemption liability that represents a put option, held by the non-controlling interest of Three Star, to sell the remaining one-third interest of the business to the Company after the third anniversary of the original acquisition date by Provident (October 3, 2014). The put price to be paid by the Company for the residual interest upon exercise is based on a multiple of Three Star's earnings during the period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates. On acquisition, the Company recorded a $6.2 million redemption liability associated with this put option. The redemption liability is subsequently fair valued at each reporting date with changes in the value flowing through profit and loss. At September 30, 2012, the fair value of the redemption liability was determined to be $5.5 million, resulting in an unrealized gain of $0.9 million and $0.7 million recorded in net finance costs for the three and nine months ended September 30, 2012, respectively. Also in conjunction with the Arrangement, the Company assumed all of the rights and obligations of Provident relating to the Provident Debentures which included a $29.7 million liability for the conversion feature of the Provident Debentures. These convertible debentures contain a cash conversion option which is measured at fair value through profit and loss at each reporting date, with any unrealized gains or losses arising from fair value changes reported in the consolidated statement of comprehensive income. This resulted in the Company recording a loss of $6.7 million and a gain of $4.2 million on the revaluation on the conversion feature of convertible debentures in profit and loss in net finance costs for the three and nine months ended September 30, 2012, respectively. The following table shows the impact on gain (loss) on derivative financial instruments if the underlying risk variables of the derivative financial instruments changed by a specified amount, with other variables held constant.         As at September 30, 2012 ($ thousands)   + Change - Change Frac spread related         Natural gas (AECO +/- $1.00 per GJ) 7,289 (7,289)   NGL (includes propane, butane) (Belvieu +/- U.S. $0.10 per gal) (6,055) 6,055   Foreign exchange (U.S.$ vs. Cdn$) (FX rate +/- $0.05) (4,902) 4,902 Management of exposure embedded in physical contracts         Crude oil (WTI +/- $5.00 per bbl) (8,793) 8,793   NGL (includes propane, butane and condensate) (Belvieu +/- U.S. $0.10 per gal) 8,148 (8,148) Corporate         Interest rate (Rate +/- 100 basis points) 973 (973)   Power (AESO +/- $5.00 per MW/h) 3,528 (3,528) Conversion feature of convertible debentures (Pembina share price +/- $0.50 per share) (2,512) 2,381                   Commodity-Related Derivative Financial Instruments       3 Months Ended       September 30       9 Months Ended       September 30 ($ thousands)       2012       2011       2012       2011 Realized (loss) gain on commodity-related derivative financial instruments         Frac spread related           Crude oil (173)   (2,170)     Natural gas (7,922)   (15,684)     Propane 2,253   3,980     Butane 1,448   2,217     Condensate 1,205   1,477     Sub-total frac spread related (3,189)   (10,180)   Corporate           Power 755 1,712 (1,009) 3,167 Management of exposure embedded in physical contracts and other (425) 1,496 (4,366) 1,292 Realized (loss) gain on commodity-related derivative financial instruments (2,859) 3,208 (15,555) 4,459 Unrealized (loss) gain on commodity-related derivative financial instruments (22,987) 687 38,286 4,285 (Loss) gain on commodity-related derivative financial instruments (25,846) 3,895 22,731 8,744 For non-commodity-related derivative financial instruments see Note 10, Net Finance Costs 14. SUBSEQUENT EVENT On October 22, 2012, Pembina closed the offering of $450 million of senior unsecured medium-term notes ("Notes"). The Notes have a fixed interest rate of 3.77% per annum, paid semi-annually, and will mature on October 24, 2022. The net proceeds from the offering of Notes were used to repay a portion of Pembina's existing credit facility. CORPORATE INFORMATION HEAD OFFICE Pembina Pipeline Corporation Suite 3800, 525 - 8th Avenue S.W. Calgary, Alberta  T2P 1G1 AUDITORS KPMG LLP Chartered Accountants Calgary, Alberta TRUSTEE, REGISTRAR & TRANSFER AGENT Computershare Trust Company of Canada Suite 600, 530 - 8th Avenue SW Calgary, Alberta  T2P 3S8 1-800-564-6253 STOCK EXCHANGE Pembina Pipeline Corporation TSX listing symbols for: Common shares: PPL Convertible debentures: PPL.DB.C, PPL,DB.E, PPL.DB.F NYSE listing symbol for: Common shares: PBA                 SOURCE Pembina Pipeline CorporationFor further information: <p> </p> <p> <b>INVESTOR INQUIRIES </b> </p> <p> Phone: (403) 231-3156<br/> Fax: (403) 237-0254<br/> Toll Free: 1-855-880-7404<br/> Email: <a href="mailto:investor-relations@pembina.com">investor-relations@pembina.com</a><br/> Website: <a href="http://www.pembina.com">www.pembina.com</a> </p>