2014

Pembina Pipeline Corporation 2012 second quarter results

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

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

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

Financial & Operating Overview
(unaudited)

         
($ millions, except where noted) 3 Months Ended
June 30
6 Months Ended
June 30
        2012       2011       2012       2011
Revenue       870.9       512.4       1,346.4       907.3
Operating margin(1)       148.9       110.3       276.6       207.6
Gross profit       161.2       97.8       263.7       180.6
Earnings for the period       80.4       48.0       113.0       90.5
Earnings per share - basic and diluted (dollars)       0.28       0.29       0.50       0.54
Adjusted EBITDA(1)       125.9       103.3       237.3       190.5
Cash flow from operating activities       24.1       49.5       89.4       124.0
Adjusted cash flow from operating activities(1)       89.5       81.8       188.3       157.8
Adjusted cash flow from operating activities per share(1)       0.31       0.49       0.83       0.94
Dividends declared       116.2       65.3       181.9       130.4
Dividends per common share (dollars)       0.41       0.39       0.80       0.78

(1) Refer to "Non-GAAP Measures."

Second Quarter Highlights

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

Growth and Operational Update

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

Conventional Pipelines:

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

Gas Services:

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

Midstream:

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

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

Hedging Information

Pembina has posted updated hedging information on its website, www.pembina.com, under "Investor Centre - Hedging".

Conference Call & Webcast

Pembina will host a conference call Friday, August 10, at 9:00 a.m. MT (11:00 a.m. ET) to discuss details related to the second quarter of 2012. The conference call dial-in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A live webcast of the conference call can be accessed on Pembina's website under "Investor Centre - Presentation & Events," or by entering http://event.on24.com/r.htm?e=489792&s=1&k=8609836C574E1C73A84090F0CE92BB87 in your web browser.



MANAGEMENT'S DISCUSSION AND ANALYSIS

The following management's discussion and analysis ("MD&A") of the financial and operating results of Pembina Pipeline Corporation ("Pembina" or the "Company") is dated August 9, 2012 and is supplementary to, and should be read in conjunction with, Pembina's condensed consolidated unaudited interim financial statements for the period ended June 30, 2012 ("Interim Financial Statements") as well as Pembina's consolidated audited annual financial statements and MD&A for the year ended December 31, 2011 (the "Consolidated Financial Statements"). All dollar amounts contained in this MD&A are expressed in Canadian dollars unless otherwise noted.

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

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

Acquisition of Provident Energy Ltd. ("Provident")

On April 2, 2012, Pembina completed its acquisition of Provident by way of a plan of arrangement pursuant to Section 193 of the Business Corporations Act (Alberta) (the "Arrangement"). Provident shareholders received 0.425 of a Pembina share for each Provident share held. In addition, Pembina has assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2017 ("Series E Debentures") (TSX Trading Symbol: PPL.DB.E), and the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2018 ("Series F Debentures") (TSX Trading Symbol: PPL.DB.F). On closing of the Arrangement, Pembina listed its common shares, including those issued under the Arrangement, on the NYSE under the symbol "PBA". Pursuant to the Arrangement, Provident amalgamated with a wholly-owned subsidiary of Pembina and was continued under the name "Pembina NGL Corporation".

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

About Pembina

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

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

Strategy

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

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

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

Common Abbreviations

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

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

Financial & Operating Overview
(unaudited)

     
        3 Months Ended
      June 30
      6 Months Ended
      June 30
($ millions, except where noted)       2012       2011       2012       2011
Average throughput - conventional (mbpd)       433.9       411.4       450.4       400.9
Contracted capacity - oil sands (mbpd)       870.0       775.0       870.0       775.0
Average processing volume - gas services (mboe/d net to Pembina)(1)       47.5       40.9       45.8       40.1
Total NGL sales volume (mbpd) 90.4   90.4(3)  
Revenue       870.9       512.4       1,346.4       907.3
Operations       67.7       37.6       116.1       82.4
Cost of goods sold, including product purchases       641.9       364.3       941.0       618.5
Realized gain (loss) on commodity-related derivative financial instruments       (12.4)       (0.2)       (12.7)       1.2
Operating margin(2)       148.9       110.3       276.6       207.6
Depreciation and amortization included in operations       52.5       15.8       74.2       30.6
Unrealized gain on commodity-related derivative financial instruments       64.8       3.3       61.3       3.6
Gross profit       161.2       97.8       263.7       180.6
Deduct/(add)        
  General and administrative expenses       25.8       12.8       43.3       27.4
  Acquisition-related and other expenses (income)       0.5       (0.6)       22.7       (0.6)
  Net finance costs       26.7       25.0       46.3       39.3
  Share of loss (profit) of investments in equity accounted investee,
   net of tax
      0.6       (2.6)       0.4       (4.8)
  Income tax expense       27.2       15.2       38.0       28.8
Earnings for the period       80.4       48.0       113.0       90.5
Earnings per share - basic and diluted (dollars)       0.28       0.29       0.50       0.54
Adjusted earnings(2)       37.4       65.4       102.7       118.1
Adjusted earnings per share(2)       0.13       0.39       0.45       0.71
Adjusted EBITDA(2)       125.9       103.3       237.3       190.5
Cash flow from operating activities       24.1       49.5       89.4       124.0
Cash flow from operating activities per share       0.08       0.30       0.39       0.74
Adjusted cash flow from operating activities(2)       89.5       81.8       188.3       157.8
Adjusted cash flow from operating activities per share (2)       0.31       0.49       0.83       0.94
Dividends declared       116.2       65.3       181.9       130.4
Dividends per common share (dollars)       0.41       0.39       0.80       0.78
Capital expenditures       136.6       78.2       186.3       301.5
Total enterprise value ($ billions) (2)       9.9       5.8       9.9       5.8
Total assets ($ billions)       8.1       3.1       8.1       3.1

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

Revenue, net of cost of goods sold, increased approximately 55 percent during the second quarter of 2012 to $229.0 million compared to $148.1 million in the second quarter of 2011. Year-to-date revenue, net of cost of goods sold, in 2012 was $405.4 million, up 40 percent from the same period last year. Revenue was higher in 2012 than the comparative periods in 2011 primarily due to the addition of results generated by the assets acquired through the Arrangement, which are reported in the Company's Midstream business, as well as continued strong performance in each of Pembina's businesses.

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

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

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

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

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

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

Pembina generated adjusted EBITDA of $125.9 million during the second quarter of 2012 compared to $103.3 million during the second quarter of 2011 (adjusted EBITDA is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the six month period ended June 30, 2012 was $237.3 million compared to $190.5 million for the same period in 2011. The increase in quarterly and year-to-date adjusted EBITDA was due to strong results from each of Pembina's legacy businesses, new assets and services having been brought on-stream and the growth in Pembina's operations since completion of the Arrangement.

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

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

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

Adjusted cash flow from operating activities was $89.5 million ($0.31 per share) during the second quarter of 2012 compared to $81.8 million ($0.49 share) during the second quarter of 2011 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). Adjusted cash flow from operating activities was $188.3 million ($0.83 per share) during the first half of 2012 compared to $157.8 million ($0.94 share) during the same period of last year. Adjusted cash flow from operating activities per share decreased primarily due to the 116.5 million shares issued as a result of the Arrangement.

Operating Results
(unaudited)

     
  3 Months Ended
June 30
6 Months Ended
June 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 78.4 47.5 72.4 50.1 160.6 101.9 141.7 94.1
Oil Sands & Heavy Oil 39.4 27.8 27.7 20.0 82.5 57.9 58.2 39.3
Gas Services 22.2 15.0 18.6 13.4 41.3 28.1 33.6 23.7
Midstream 89.0 58.0 29.3 26.8 121.0(3) 87.4(3) 55.3 50.5
Corporate   0.6       1.3    
Total 229.0 148.9 148.0 110.3 405.4 276.6 288.8 207.6

(1)  Midstream revenue is net of $648.8 million in cost of goods sold for the quarter ended June 30, 2012 (quarter ended June 30, 2011: $364.4 million) and $947.9 million in cost of goods sold for six months ended June 30, 2012 (six months ended June 30, 2011: $618.5 million).
(2)  Refer to "Non-GAAP Measures."
(3)  Includes results from operations generated by the acquired assets from Provident since closing of the Arrangement.
   

Conventional Pipelines

     
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions, except where noted) 2012 2011 2012 2011
Average throughput (mbpd) 433.9 411.4 450.4 400.9
Revenue 78.4 72.4 160.6 141.7
Operations 29.9 22.2 57.5 49.0
Realized gain (loss) on commodity-related derivative financial instruments (1.0) (0.1) (1.2) 1.4
Operating margin(1) 47.5 50.1 101.9 94.1
Depreciation and amortization included in operations 12.2 10.4 24.1 20.1
Unrealized gain (loss) on commodity-related derivative financial instruments 0.2 0.1 (2.8) 4.7
Gross profit 35.5 39.8 75.0 78.7
Capital expenditures 55.6 10.1 64.5 26.8

(1) Refer to "Non-GAAP Measures."

Business Overview

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

Operational Performance: Throughput

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

Financial Performance

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

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

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

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

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

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

New Developments: Conventional Pipelines

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

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

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

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

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

Drayton Valley Area

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

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

Supporting Gas Services' Saturn and Resthaven Projects

Pembina's Conventional Pipelines business is working closely with its Gas Services business to construct the pipeline components of the Saturn and Resthaven gas plant projects. These two pipeline projects will gather NGL from the gas plants for delivery to Pembina's Peace Pipeline system. During the second quarter of 2012, Pembina continued its consultation activities related to the right-of-way and pipeline routing for both of these projects with First Nations, community stakeholders and the appropriate regulators, and has continued to order long-lead equipment for the pipeline and pump stations.

Western System

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

Oil Sands & Heavy Oil

     
        3 Months Ended
      June 30
      6 Months Ended
      June 30
($ millions, except where noted) 2012 2011 2012 2011
Capacity under contract (mbpd) 870.0 775.0 870.0 775.0
Revenue 39.4 27.7 82.5 58.2
Operations 11.6 7.7 24.6 18.9
Operating margin(1) 27.8 20.0 57.9 39.3
Depreciation and amortization included in operations 4.9 2.1 9.8 4.0
Gross profit 22.9 17.9 48.1 35.3
Capital expenditures   30.1 6.0 129.9

(1) Refer to "Non-GAAP Measures."

Business Overview

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

Financial Performance

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

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

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

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

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

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

Segmented Operating Margin

Syncrude Pipeline

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

Cheecham Lateral

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

Horizon Pipeline

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

Nipisi & Mitsue Pipelines

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

New Developments: Oil Sands & Heavy Oil

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

Gas Services

     
    3 Months Ended
 June 30
  6 Months Ended
June 30
($ millions, except where noted) 2012 2011 2012 2011
Average processing volume (MMcf/d) 285.0 245.5 275.0 240.8
Average processing volume (mboe/d)(1) 47.5 40.9 45.8 40.1
Revenue 22.2 18.6 41.3 33.6
Operations 7.2 5.2 13.2 9.9
Operating margin(2) 15.0 13.4 28.1 23.7
Depreciation and amortization included in operations 4.3 2.5 7.5 4.8
Gross profit 10.7 10.9 20.6 18.9
Capital expenditures 23.5 25.5 55.8 41.1

(1)  Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio.
(2)  Refer to "Non-GAAP Measures."
   

Business Overview

Pembina's operations include a growing natural gas gathering and processing business. Located approximately 100 km south of Grande Prairie, Alberta, Pembina's key revenue-generating Gas Services assets form the Cutbank Complex which comprises three sweet gas processing plants with 360 MMcf/d of processing capacity (305 MMcf/d net to Pembina), a new 205 MMcf/d ethane plus extraction facility, as well as approximately 350 km of gathering pipelines. The Cutbank Complex is connected to Pembina's Peace Pipeline system and serves an active exploration and production area in the WCSB. Pembina plans to expand its Gas Services business by constructing the Saturn and Resthaven enhanced NGL extraction facilities to meet the growing needs of producers in west central Alberta.

Financial Performance

Gas Services recorded an increase in revenue of approximately 19 percent during the second quarter of 2012, contributing $22.2 million compared to $18.6 million in the second quarter of 2011. In the first half of the year, revenue was $41.3 million compared to $33.6 million in the same period of 2011. These increases primarily reflect higher processing volumes at Pembina's Cutbank Complex. Average processing volume, net to Pembina, was 285.0 MMcf/d during the second quarter of 2012, 16 percent higher than the 245.5 MMcf/d processed during the second quarter of 2011.

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

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

Depreciation and amortization included in operations during the second quarter of 2012 totaled $4.3 million, up from $2.5 million during the same period of the prior year, primarily due to higher in-service capital balances from additions to the Cutbank Complex (including the Musreau Deep Cut Facility). For the same reason, year-to-date depreciation and amortization included in operations totaled $7.5 million, up from $4.8 million during the first half of 2011.

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

For the six months ended June 30, 2012, capital expenditures within Gas Services totaled $55.8 million compared to $41.1 million during the same period of 2011. This increase was due to the spending required to complete the Musreau Deep Cut Facility, the expansion of the shallow cut facility at the Cutbank Complex as well as capital expenditures incurred to progress the Saturn and Resthaven enhanced NGL extraction facilities.

New Developments: Gas Services

Pembina continues to see significant growth opportunities resulting from the trend towards liquids-rich gas drilling and the extraction of valuable NGL from gas in the WCSB. Pembina expects the three expansions detailed below to bring the Company's gas processing capacity to 890 MMcf/d (net), including enhanced NGL extraction capacity of approximately 535 MMcf/d (net) which would be processed largely on a contracted, fee-for-service basis and result in approximately 45 mbpd of incremental NGL to be transported for additional toll revenue on Pembina's conventional pipelines by early 2014.

Musreau Deep Cut Facility

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

Expansion at the Cutbank Complex: Musreau Shallow Cut Expansion

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

Saturn Facility

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

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

Resthaven Facility

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

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

Midstream(1)

 
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions, except where noted)       2012 2011       2012 2011
Total NGL sales volume (mbpd) 90.4   90.4(3)  
Revenue 737.8 393.7 1,068.9 673.8
Operations 19.6 2.5 22.1 4.6
Cost of goods sold, including product purchases 648.8 364.4 947.9 618.5
Realized loss on commodity-related derivative financial instruments (11.4)   (11.5) (0.2)
Operating margin(2) 58.0 26.8 87.4 50.5
Depreciation and amortization included in operations 31.1 0.9 32.7 1.8
Unrealized gains (losses) on commodity-related derivative financial  instruments 64.6 3.2 64.0 (1.0)
Gross profit 91.5 29.1 118.7 47.7
Capital expenditures 55.2 11.6 55.9 101.9

(1)  Share of profit from equity accounted investees not included in results above.
(2)  Refer to "Non-GAAP Measures."
(3)  Represents per day volumes since the closing of the Arrangement.
   

Business Overview

Pembina's Midstream business is organized into two components:

  • a crude oil midstream business, which represents the Company's legacy midstream operations is situated at key sites across Pembina's operations and comprises a network of liquids truck terminals, terminalling at downstream hub locations, including storage and pipeline connectivity; and
  • an NGL midstream business, which Pembina acquired through the Arrangement, which includes two operating systems: Redwater West and Empress East.
    • The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; a 65,000 bpd fractionator, 6.3 mmbbls of cavern storage and terminalling facilities at Redwater, Alberta; and, third party fractionation capacity in Fort Saskatchewan, Alberta.
    • The Empress East NGL system includes a 2.1 bcf/d interest in the straddle plant at Empress, Alberta, and 20,000 bpd of fractionation capacity as well as 6.4 mmbbls of cavern storage in Sarnia, Ontario.

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

Financial Performance

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

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

Operating margin was $58.0 million during the second quarter of 2012 compared to $26.8 million during the second quarter of 2011. Operating margin for the first six months of 2012 was $87.4 million compared to $50.5 million in the same period of 2011. This increase was largely due to the same factors that contributed to the increase in revenue, net of cost of goods sold, as discussed above.

Depreciation and amortization included in operations during the second quarter of 2012 totaled $31.1 million, up from $0.9 million during the same period of the prior year. Year-to-date depreciation and amortization included in operations totaled $32.7 million, up from $1.8 million during the first half of 2011. The quarterly and year-to-date increases reflect the additional assets in Midstream since the closing of the Arrangement.

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

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

Operating Margin by Activity

Crude Oil Midstream

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

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

NGL Midstream

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

Redwater West

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

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

Empress East

Empress East extracts NGL mix from natural gas at the Empress straddle plants and purchases NGL mix from other producers/suppliers. Ethane and condensate are generally fractionated out of the NGL mix at Empress and sold into Alberta markets. The remaining NGL mix, consisting of primarily propane and butane, is shipped on Pembina's 50 percent owned Kerrobert Pipeline to a third party pipeline for transport to Sarnia, Ontario where it is then fractionated into specification products. Specification propane and butanes are sold into central Canadian and eastern U.S. markets. Demand for propane is seasonal and results in inventory that generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year during the winter heating season.

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

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

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

New Developments: Midstream

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

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

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

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

Market Risk Management Program

Pembina is exposed to frac spread risk which is the difference between the selling prices for propane-plus and the input cost of natural gas required to produce respective NGL products.  Pembina has a risk management program and uses derivative financial instruments to mitigate frac spread risk when possible to safeguard a base level of operating cash flow. Pembina has entered into derivative financial swap contracts through March 2013 to protect the frac spread and to manage exposure to power costs, interest rates and foreign exchange rates.

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

Management continues to actively monitor commodity price risk and mitigage its impact through financial risk management activities. Subject to market conditions and at management's discretion, Pembina may hedge a portion of its natural gas and NGL volumes. A summary of Pembina's current financial derivative positions is available on Pembina's website at www.pembina.com.

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

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

Activity in the second quarter

           
Year Commodity Description Volume (Buy)/Sell Effective Period
2012 Crude Oil U.S. $95.94 per bbl(2)(6)(7)       1,299 bpd July 1 - December 31
Propane U.S. $1.226 per gallon(3)(6)       (1,630) bpd July 1 - December 31
Condensate U.S. $1.725 per gallon(4)(7)       (565) bpd July 1 - December 31
F/X Sell U.S. $1,400,000 per month at 0.994(5)(9)           July 1 - December 31
2013 Crude Oil U.S. $104.22 per bbl(2)(6)(7)       750 bpd January 1 - April 30
Propane U.S. $1.226 per gallon(3)(6)       (1,667) bpd January 1 - April 30
F/X Sell U.S. $1,400,000 per month at 0.994(5)(9)     January 1 - March 31
Corporate Power Cdn $65.86 per MW/h(8)       (15) MW/h July 1 - December 31, 2013
  Cdn $67.95 per MW/h(8)       (10) MW/h January 1 - December 31, 2014
  Cdn $67.95 per MW/h(8)       (10) MW/h January 1 - December 31, 2015
  Cdn $68.00 per MW/h(8)       (5) MW/h January 1 - December 31, 2016

(1) The above table represents a number of transactions entered into over the second quarter of 2012.
(2) Crude oil contracts are settled against NYMEX WTI calendar average.
(3) Propane contracts are settled against Belvieu C3 TET.
(4) Condensate contracts are settled against Belvieu Non-TET natural gasoline.
(5) Frac spread contracts.
(6) Management of physical contract exposure - NGL product contracts.
(7) Management of physical contract exposure - rail contracts.
(8) Power contracts are settled against the hourly price of power as published by the AESO in $/MWh.
(9) U.S. dollar forward contracts are settled against the Bank of Canada noon rate average. Selling notional U.S. dollars for Canadian dollar fixed exchange rate results in a fixed Canadian dollar price for the underlying commodity.
   

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

     
        3 Months Ended
      June 30
      6 Months Ended
      June 30
($ thousands, except volumes)       2012       2011       2012       2011
    $ Volume(1)   $       Volume    $       Volume $       Volume
Realized (loss) gain on commodity-related derivative financial instruments                
Frac spread related                
  Crude oil (1,997) 0.1     (1,997) 0.1    
  Natural gas (7,762) 4.6     (7,762) 4.6    
  Propane 1,727 0.2     1,727 0.2    
  Butane 769 0.3     769 0.3    
  Condensate 272 0.2     272 0.2    
  Sub-total frac spread related (6,991)       (6,991)      
Corporate                
  Power (1,608)   (159)   (1,764)   1,455  
Management of exposure embedded in physical contracts and other (3,870) 0.3     (3,941) 0.5 (204)  
Realized (loss) gain on commodity-related derivative financial instruments (12,469)   (159)   (12,696)   1,251  

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

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

Business Environment

     
  3 Months ended
June 30
6 Months ended
June 30
        2012       2011 % Change 2012 2011 % Change
WTI crude oil (U.S.$ per barrel)             93.49             102.56 (9)             98.21             98.33  
Exchange rate (from U.S.$ to Cdn$)             1.01             0.97 4             1.01             0.98 3
WTI crude oil (expressed in Cdn$ per barrel)             94.44             99.25 (5)             98.77             96.05 3
                                
AECO natural gas monthly index (Cdn$ per gj)             1.74             3.54 (51)             2.06             3.56 (42)
             
Frac Spread Ratio(1)             54.3x             28.0x 94             47.9x             27.0x 77
                                       
Mont Belvieu Propane (U.S.$ per U.S. gallon)             0.98             1.50 (35)             1.12             1.45 (23)
Mont Belvieu Propane expressed as a percentage of WTI       44%       61% (28)       48%       62% (23)
             
Market Frac Spread in Cdn$ per barrel(2)             45.70             53.84 (15)             50.43             52.09 (3)

(1) Frac spread ratio is the ratio of WTI expressed in Canadian dollars per barrel to the AECO monthly index (Cdn$ per gj).
(2) Market frac spread is determined using average spot prices at Mont Belvieu, weighted based on 65 percent propane, 25 percent butane and 10 percent condensate, and the AECO monthly index price for natural gas.
   

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

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

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

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

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

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

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

Non-Operating Expenses

G&A

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

Depreciation & Amortization (Operational)

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

Acquisition-Related and Other

Acquisition-related and other expenses during the second quarter were $0.5 million which includes acquisition expenses of $0.3 million and $0.2 million in other expenses. For the six months ended June 30, 2012, acquisition-related and other expenses were $22.7 million which includes acquisition expenses of $13.2 million as well as $8.2 million due to the required make whole payment for the redemption of the senior secured notes from the first quarter of the year. See "Liquidity and Capital Resources."

Net Finance Costs

Net finance costs in the second quarter of 2012 were $26.7 million compared to $25.0 million in the second quarter of 2011. Year-to-date net finance costs in 2012 totaled $46.3 million, up from $39.3 million in the same period of 2011. The increases relate primarily to: an $8.4 million year-to-date increase in loans and borrowings interest expense ($4.2 million for the second quarter of 2012) due to higher debt balances; a $1.9 million change in the fair value of non-commodity-related derivative financial instruments for the first half of the year; and quarterly and year-to-date increased interest on convertible debentures totaling $6.0 million due to the Provident debentures assumed on closing of the Arrangement. These factors were offset by a $10.9 million unrealized gain in the second quarter of 2012 on the conversion feature of the convertible debentures. See Notes 10 and 13 to the Interim Financial Statements for the period ended June 30, 2012. The change in fair value of commodity-related derivative financial instruments has been reclassified from net finance costs to gain on commodity-related derivative financial instruments to be included in operational results.

Income Tax Expense

Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities. An income tax expense of $27.2 million was recorded in the second quarter of 2012 compared to $15.2 million in the second quarter of 2011. Year-to-date income tax expense in 2012 totaled $38.0 million, up from $28.8 million in the same period of 2011. The change in income tax expense is consistent with the change in earnings before income tax and equity accounted investees.

Liquidity & Capital Resources

     
($ millions)       June 30, 2012       December 31, 2011
Working Capital       102.0       (343.7)(1)
Variable rate debt(2)          
       Bank debt       785.0       313.8
       Variable rate debt swapped to fixed       (380.0)       (200.0)
Total variable rate debt outstanding (average rate of 2.71%)       405.0       113.8
Fixed rate debt(2)    
       Senior secured notes         58.0
       Senior unsecured notes       642.0       642.0
       Senior unsecured term debt       75.0       75.0
       Senior unsecured medium term note       250.0       250.0
       Subsidiary debt       9.3  
       Variable rate debt swapped to fixed       380.0       200.0
Total fixed rate debt outstanding (average rate of 5.27%)       1,356.3       1,225.0
Convertible debentures(2)       644.4       299.8
Finance lease liability       5.8       5.6
Total debt and debentures outstanding       2,411.5       1,644.2
Cash and unutilized debt facilities       728.8       235.1

(1) As at December 31, 2011, working capital includes $310 million of current, non-revolving unsecured credit facilities.
(2) Face value.
   

Pembina anticipates cash flow from operating activities will be more than sufficient to meet its short-term operating obligations and fund its targeted dividend level. In the medium-term, Pembina expects to source funds required for capital projects from cash and unutilized debt facilities totaling $728.8 million as at June 30, 2012. Based on its successful access to financing in the debt and equity markets during the past several years, Pembina believes it would likely continue to have access to funds at attractive rates. Additionally, Pembina has reinstated its DRIP as of the January 25, 2012 record date to help fund its ongoing capital program (see "Trading Activity and Total Enterprise Value" for further details). Management remains satisfied that the leverage employed in Pembina's capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base.

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

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

Pembina's credit facilities at June 30, 2012 consisted of an unsecured $1.5 billion revolving credit facility due March 2017 and an operating facility of $30 million due July 2013. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil percent to 1.25 percent or Bankers' Acceptances rates plus 1.00 percent to 2.25 percent. Margins on the Bankers' Acceptances rate are based on the credit rating of Pembina's senior unsecured debt. There are no repayments due over the term of these facilities. As at June 30, 2012, Pembina had $785.0 million drawn on bank debt, $19.2 million in letters of credit and $3.0 million in cash, leaving $728.8 million of unutilized debt facilities on the $1,530 million of established bank facilities. Other debt includes $75 million in senior unsecured term debt due 2014; $175 million in senior unsecured notes due 2014; $267 million in senior unsecured notes due 2019; $200 million in senior unsecured notes due 2021; and $250 million in senior unsecured medium term notes due 2021. On April 30, 2012, the senior secured notes were redeemed. Pembina has recognized $8.2 million due to the associated make whole payment, which has been included in acquisition-related and other expenses in the first quarter of the year. At June 30, 2012, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,761.3 million. Pembina's senior debt to total capital at June 30, 2012 was 26 percent.

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

Assumption of rights related to the Provident Debentures

On closing of the Arrangement on April 2, 2012, Pembina assumed all of the rights and obligations of Provident relating to the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2017 (TSX: PPL.DB.E), and the 5.75 percent convertible unsecured subordinated debentures of Provident maturing December 31, 2018 (TSX: PPL.DB.F). Outstanding Provident debentures at April 2, 2012 were $345 million. As of June 30, 2012, $344.7 million of the debentures are still outstanding.

Capital Expenditures

     
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions)       2012       2011       2012       2011
Development capital        
  Conventional Pipelines       55.6       10.1       64.5       26.8
  Oil Sands & Heavy Oil                      30.1       6.0       129.9
  Gas Services       23.5       25.5       55.8       41.1
  Midstream       55.2       11.6       55.9       101.9
Corporate/other projects       2.3       0.9       4.1       1.8
Total development capital       136.6       78.2       186.3       301.5
         

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

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

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

Contractual Obligations at June 30, 2012

           
($ thousands) Payments Due By Period
Contractual Obligations Total Less than
1 year
1 - 3 years 4 - 5 years After
5 years
Office and vehicle leases       305,274       25,801       52,404       56,878       170,191
Loans and borrowings(1)       2,117,526       62,238       383,242       863,329       808,717
Convertible debentures(1)       923,169       39,156       118,351       246,170       519,492
Construction commitments       462,428       336,483       125,945    
Provisions(2)       507,707       2,358       2,664       447       502,238
Total contractual obligations       4,316,104       466,036       682,606       1,166,824       2,000,638

(1)  Excluding deferred financing costs; finance leases included under "office and vehicle leases".
(2)  Includes discounted constructive and legal obligations included in the decommissioning provision.
   

Pembina is, subject to certain conditions, contractually committed to the construction and operation of the Musreau Deep Cut Facility at its Cutbank Complex, the Musreau Shallow Cut Expansion, the Saturn Facility and the Resthaven Facility, and to the remaining capital expenditures associated with the Nipisi and Mitsue pipelines. See "Forward-Looking Statements & Information."

Critical Accounting Estimates

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

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

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

Changes in Accounting Principles and Practices

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

Controls and Procedures

Changes in internal control over financial reporting

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

In accordance with the provisions of National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, management, including the CEO and CFO, have limited the scope of their design of the Company's disclosure controls and procedures and internal control over financial reporting to exclude controls, policies and procedures of Provident. Pembina acquired the assets of Provident and its subsidiaries on April 2, 2012. Provident's contribution to the Company's unaudited condensed consolidated financial statements for the quarter ended June 30, 2012 was approximately 38 percent of consolidated net revenues and approximately 49 percent of consolidated pre-tax earnings.

Additionally, Provident's current assets and current liabilities were approximately 70 percent and 56 percent of consolidated current assets and liabilities, respectively, and its non-current assets and non-current liabilities were approximately 58 percent and 35 percent of consolidated non-current assets and non-current liabilities, respectively.

The scope limitation is primarily based on the time required to assess Provident's disclosure controls and procedures ("DC&P") and internal controls over financial reporting ("ICFR") in a manner consistent with the Company's other operations.

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

Trading Activity and Total Enterprise Value (1)

     
    As at and for the 3
months ended
($ thousands, except where noted) August 7, 2012(2) June 30, 2012 June 30, 2011
Trading volume and value            
       Total volume (shares) 9,851,046 56,667,601 10,543,451
       Average daily volume (shares) 394,042 899,486 167,356
       Value traded 263,725 1,620,184 390,673
Shares outstanding (shares) 288,697,725 287,785,195 167,470,150
Closing share price (dollars)       26.40       26.02       25.39
Market value      
       Shares 7,621,627 7,488,171 4,252,067
       5.75% convertible debentures (PPL.DB.C) 326,252(3) 325,922(4) 310,500(5)
       5.75% convertible debentures (PPL.DB.E)(6) 195,399(7) 192,948(8)  
       5.75% convertible debentures (PPL.DB.F)(6) 187,964(9) 186,205(10)  
Market capitalization 8,331,242 8,193,246 4,562,567
Senior debt 1,782,000 1,752,000 1,229,041
Total enterprise value(11) 10,113,242 9,945,246 5,791,608

(1)  Trading information in this table reflects the activity of Pembina securities on the TSX.
(2)  Based on 25 trading days from June 30, 2012 to August 7, 2012 inclusive.
(3)  $299.7 million principal amount outstanding at a market price of $108.85 at August 7, 2012 and with a conversion price of $28.55.
(4)  $299.7 million principal amount outstanding at a market price of $108.47 at June 29, 2012 and with a conversion price of $28.55.
(5)  $300 million principal amount outstanding at a market price of $103.50 at June 30, 2011 and with a conversion price of $28.55.
(6)  Pursuant to the Arrangement, Pembina assumed the rights and obligations of Provident debentures, which are listed on the TSX under PPL.DB.E and PPL.DB.F.
(7)   $172.2 million principal amount outstanding at a market price of $113.50 at August 7, 2012 and with a conversion price of $24.94.
(8)  $172.2 million principal amount outstanding at a market price of $112.06 at June 29, 2012 and with a conversion price of $24.94.
(9)  $172.4 million principal amount outstanding at a market price of $109.00 at August 7, 2012 and with a conversion price of $29.53.
(10)  $172.4 million principal amount outstanding at a market price of $107.98 at June 29, 2012 and with a conversion price of $29.53.
(11)  Refer to "Non-GAAP Measures."
   

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

Dividends

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

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

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

DRIP

Pembina has reinstated its DRIP as of January 25, 2012. Eligible Pembina shareholders have the opportunity to receive, by reinvesting the cash dividends declared payable by Pembina on their shares, either: (i) additional common shares at a discounted subscription price equal to 95 percent of the Average Market Price (as defined in the DRIP), pursuant to the "Dividend Reinvestment Component" of the DRIP, or (ii) a premium cash payment (the "Premium Dividend™") 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 second quarter was 58 percent of common shares outstanding for proceeds of approximately $57.0 million.

Listing on the NYSE

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

Risk Factors

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

Selected Quarterly Operating Information

       
  2012 2011 2010
        Q2       Q1       Q4       Q3       Q2       Q1       Q4       Q3       Q2
Average throughput (mbpd)                  
Total Conventional Throughput       433.9 466.9 422.8 430.4 411.4 390.3 375.0 361.4 370.4
Oil Sands & Heavy Oil(1)       870.0 870.0 870.0 775.0 775.0 775.0 775.0 775.0 775.0
Gas Services Processing (mboe/d)(2)       47.5 44.1 45.3 43.6 40.9 39.4 42.1 38.9 38.9
NGL sales volume (mboe/d)       90.4(3)                

(1) Oil Sands & Heavy Oil throughput refers to contracted capacity.
(2)  Converted to mboe/d from MMcf/d at a 6:1 ratio.
(3)  Represents per day volumes since the closing of the Arrangement.
   

Selected Quarterly Financial Information

       
  2012 2011 2010
($ millions, except where noted)       Q2       Q1       Q4       Q3       Q2       Q1       Q4       Q3       Q2
Revenue       870.9       475.5 468.1       300.6       512.4       394.9       290.7       266.1       386.5
Operations       67.7       48.4 56.3       54.4       37.6       44.8       41.9       40.0       38.2
Cost of goods sold       641.9       299.1 307.9       145.8       364.3       254.2       161.8       148.2       262.2
Realized gains (losses) on commodity-related derivative financial instruments       (12.4)       (0.3) 0.8         (0.2)       1.4       (0.8)       0.3       1.2
Operating margin(1)       148.9       127.7 104.7       100.4       110.3       97.3       86.2       78.2       87.3
Depreciation and amortization included in operations       52.5       21.7 19.5       17.8       15.8       14.8       15.6       15.3       15.3
Unrealized gains (losses) on commodity-related derivative financial instruments       64.8       (3.5) 0.9       0.7       3.3       0.3       1.8       (3.2)       2.4
Gross profit       161.2       102.5 86.1       83.3       97.8       82.8       72.4       59.7       74.4
Adjusted EBITDA(1)       125.9       111.4 87.0       86.8       103.3       87.2       79.1       68.1       78.0
Cash flow from operating
activities
      24.1       65.3 74.3       88.0       49.5       74.5       54.6       66.6       69.6
Cash flow from operating activities per common share ($ per share)       0.08       0.39 0.44       0.53       0.30       0.45       0.33       0.41       0.43
Adjusted cash flow from operating activities(1)       89.5       98.8 57.3       90.8       81.8       76.0       62.6       67.6       63.0
Adjusted cash flow from operating activities per common share(1)
    ($ per share)
      0.31       0.59 0.34       0.54       0.49       0.45       0.39       0.41       0.38
Earnings for the period       80.4       32.6 45.1       30.1       48.0       42.5       55.2       28.6       37.7
Earnings per common share
      ($ per share):
                 
       Basic       0.28       0.19 0.27       0.18       0.29       0.25       0.34       0.19       0.23
       Diluted       0.28       0.19 0.27       0.18       0.29       0.25       0.33       0.19       0.23
Common shares outstanding (millions):                  
       Weighted average (basic)       285.3       168.3 167.4       167.6       167.3       167.0       165.0       164.0       163.2
       Weighted average (diluted)       286.0       168.9 168.2       168.2       168.0       167.6       171.7       166.9       166.2
       End of period       287.8       169.0 167.9       167.7       167.5       167.1       166.9       164.5       163.6
Dividends declared       116.2       65.7 65.4       65.4       65.3       65.1       64.6       64.0       63.8
Dividends per common share
      ($ per share):
      0.41       0.39 0.39       0.39       0.39       0.39       0.39       0.39       0.39

(1) Refer to "Non-GAAP measures."

Additional Information

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

Non-GAAP Measures

Throughout this MD&A, Pembina has used the following terms that are not defined by GAAP but are used by management to evaluate performance of Pembina and its business. Since certain Non-GAAP financial measures may not have a standardized meaning, securities regulations require that Non-GAAP financial measures are clearly defined, qualified and reconciled to their nearest GAAP measure. Concurrent with the acquisition of Provident, certain Non-GAAP Measures definitions have changed from those previously used to better reflect the changes in aspects of Pembina's business activities.

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

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

     
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions, except per share amounts) 2012       2011 2012 2011
Results from operating activities       134.9       85.6       197.7       153.7
Share of profit from equity accounted investees
    (before tax, depreciation and amortization)
      1.3       4.9       2.8       9.2
Depreciation and amortization       54.2       16.1       76.7       31.2
Unrealized gain on commodity-related derivative financial instruments       (64.8)       (3.3)       (61.3)       (3.6)
EBITDA       125.6       103.3       215.9       190.5
Add:              
Acquisition-related expenses       0.3         21.4  
Adjusted EBITDA       125.9       103.3       237.3       190.5
EBITDA per common share - basic (dollars)       0.44       0.62       0.95       1.14
Adjusted EBITDA per common share - basic (dollars)       0.44       0.62       1.05       1.14
         

Adjusted earnings

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

               
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions, except per share amounts) 2012 2011 2012 2011
Earnings before income tax and equity accounted investees       108.2       60.6       151.4       114.5
Add (deduct):                                
Unrealized change in fair value of derivative financial instruments       (70.2)       1.2       (69.5)       (2.8)
Share of (loss) profit of investments in equity accounted investees (after tax)       (0.6)       2.7       (0.4)       4.8
Tax on share of profit of investments in equity accounted investees       (0.3)       0.9       (0.2)       1.6
Acquisition-related expenses       0.3               21.4        
Adjusted earnings       37.4       65.4       102.7       118.1
Adjusted earnings per common share - basic (dollars)       0.13       0.39       0.45       0.71
         

Adjusted cash flow from operating activities

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

             
  3 Months Ended
June 30
6 Months Ended
June 30
($ millions, except per share amounts) 2012 2011 2012 2011
Cash flow from operating activities       24.1       49.5       89.4       124.0
Add:                                
Change in non-cash working capital       65.1       32.3       77.5       33.8
Acquisition-related expenses       0.3         21.4        
Adjusted cash flow from operating activities       89.5       81.8       188.3       157.8
Adjusted cash flow from operating activities per common share  - basic (dollars)       0.31       0.49       0.83       0.94
     

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
June 30
6 Months Ended
June 30
($ millions) 2012 2011 2012 2011
Revenue       870.9       512.4       1,346.4       907.3
Cost of sales:              
  Operations       67.7       37.6       116.1       82.4
  Cost of goods sold       641.9       364.3       941.0       618.5
  Realized gain (loss) on commodity-related derivative financial instruments       (12.4)       (0.2)       (12.7)       1.2
Operating margin       148.9       110.3       276.6       207.6
Depreciation and amortization included in operations       52.5       15.8       74.2       30.6
Unrealized gain on commodity-related derivative financial instruments       64.8       3.3       61.3       3.6
Gross profit       161.2       97.8       263.7       180.6
         

Unrealized gain on commodity-related derivative financial instruments has been reclassified from net finance costs to be included in gross profit.

Total enterprise value

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

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

Forward-Looking Statements & Information

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

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

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

  • the future levels of cash dividends that Pembina intends to pay to its shareholders;
  • capital expenditure estimates, plans, schedules, rights and activities and the planning, development, construction, operations and costs of pipelines, gas service facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, including, but not limited to, in relation to the PNT, the expansions at the Cutbank Complex's Musreau Gas Plant, the proposed Resthaven Facility and the proposed Saturn Facility, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in Central Alberta, the expansion of throughput capacity on the Northern NGL System, the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven fee-for-service storage facilities at Redwater, the Redwater fractionator expansion, and the proposed development of a C2+ fractionators at Redwater;
  • future expansion of Pembina's pipelines and other infrastructure;
  • pipeline, processing and storage facility and system operations and throughput levels;
  • oil and gas industry exploration and development activity levels;
  • Pembina's strategy and the development of new business initiatives;
  • growth opportunities;
  • expectations regarding Pembina's ability to raise capital and to carry out acquisition, expansion and growth plans;
  • treatment under governmental regulatory regimes including environmental regulations and related abandonment and reclamation obligations;
  • future G&A expenses at Pembina;
  • increased throughput potential due to increased activity and new connections and other initiatives on Pembina's pipelines;
  • future cash flows, potential revenue and cash flow enhancements across Pembina's businesses and the maintenance of operating margins;
  • tolls and tariffs and transportation, storage and services commitments and contracts;
  • cash dividends and the tax treatment thereof;
  • operating risks (including the amount of future liabilities related to pipeline spills and other environmental incidents) and related insurance coverage and inspection and integrity programs;
  • the expected capacity of the proposed Resthaven Facility and the proposed Saturn Facility;
  • expectations regarding in-service dates for new developments, including the Resthaven Facility, the Saturn Facility and the Northern NGL System;
  • expectations regarding incremental NGL volumes to be transported on Pembina's conventional pipelines by the end of 2013 as a result of new developments in Pembina's Gas Services business;
  • expectations regarding in-service dates for the seven fee-for-service storage facilities at Redwater, the Redwater fractionator expansion project and the proposed C2+ fractionator at Redwater;
  • the possibility of renegotiating debt terms, repayment of existing debt, seeking new borrowing and/or issuing equity;
  • expectations regarding participation in Pembina's DRIP;
  • the expected impact of changes in share price on annual share-based incentive expense;
  • expectations regarding the potential construction, expansion and conversion of downstream infrastructure in the U.S. Midwest and Gulf Coast;
  • the impact of approval from the British Columbia Utilities Commission of Pembina's application on the Western System;
  • inventory and pricing levels in the North American liquids market;
  • Pembina's discretion to hedge natural gas and NGL volumes; and
  • competitive conditions.

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

  • the success of Pembina's operations;
  • prevailing commodity prices and exchange rates;
  • the availability of capital to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns;
  • future operating costs;
  • geotechnical and integrity costs associated with the Western System;
  • in respect of the proposed Saturn Facility and the proposed Resthaven Facility and their estimated in-service dates of fourth quarter of 2013 and the first quarter of 2014, respectively; that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner, that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of such facilities; that such facilities will be fully supported by long-term firm service agreements accounting for the entire designed throughput at such facilities at the time of such facilities' completion; that there are no unforeseen construction costs related to the facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;
  • in respect of the expansion of NGL throughput capacity on the Northern NGL System and the estimated in-service dates with respect to the same; that Pembina will receive regulatory approval; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs related to the expansion; and that there are no unforeseen material costs relating to the pipelines that are not recoverable from customers;
  • in respect of the proposed C2+ fractionator at Redwater; that Pembina will receive regulatory approval; that Pembina will reach satisfactory long-term arrangements with customers; that counterparties will comply with such contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the proposed fractionators that are not recoverable from customers;
  • in respect of other developments, expansions and capital expenditures planned, including the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the expectation of additional NGL volumes being transported on the conventional pipelines, the proposed expansion of the Musreau Gas Plant's shallow cut gas processing capability, the proposed expansion plans to strengthen Pembina's transportation service options that it provides to producers developing the Cardium oil formation located in central Alberta, the installation of two remaining pump stations on the Nipisi and Mitsue pipelines, the development of seven fee-for-service storage facilities at Redwater, and the Redwater fractionator expansion that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the developments, expansions and capital expenditures which are not recoverable from customers;
  • the future exploration for and production of oil, NGL and natural gas in the capture area around Pembina's conventional and midstream assets, including new production from the Cardium formation in western Alberta, the demand for gathering and processing of hydrocarbons, and the corresponding utilization of Pembina's assets;
  • in respect of the stability of Pembina's dividend; prevailing commodity prices, margins and exchange rates; that Pembina's future results of operations will be consistent with past performance and management expectations in relation thereto; the continued availability of capital at attractive prices to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns; the success of growth projects; future operating costs; that counterparties to material agreements will continue to perform in a timely manner; that there are no unforeseen events preventing the performance of contracts; and that there are no unforeseen material construction or other costs related to current growth projects or current operations; and
  • prevailing regulatory, tax and environmental laws and regulations.

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

  • the regulatory environment and decisions;
  • the impact of competitive entities and pricing;
  • labour and material shortages;
  • reliance on key alliances and agreements;
  • the strength and operations of the oil and natural gas production industry and related commodity prices;
  • non-performance or default by counterparties to agreements which Pembina or one or more of its affiliates has entered into in respect of its business;
  • actions by governmental or regulatory authorities including changes in tax laws and treatment, changes in royalty rates or increased environmental regulation;
  • fluctuations in operating results;
  • adverse general economic and market conditions in Canada, North America and elsewhere, including changes in interest rates, foreign currency exchange rates and commodity prices;
  • the failure to realize the anticipated benefits of the Arrangement;
  • the failure to integrate the businesses of Pembina and Provident; and
  • the other factors discussed under "Risk Factors" in Pembina's MD&A and Provident's MD&A for the year ended December 31, 2011, in Pembina's Annual Information Form ("AIF") for the year ended December 31, 2011 and in Provident's AIF for the year ended December 31, 2011. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com. Provident's MD&A is available at www.pembina.com and its AIF can be found on Pembina NGL Corporation's company profile on www.sedar.com or on Provident's profile at www.sec.gov.

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

CONDENSED CONSOLIDATED INTERIM STATEMENT OF FINANCIAL POSITION
(unaudited)

       
($ thousands) Note       June 30,
      2012
     December
31, 2011
Assets
Current assets
     
  Cash and cash equivalents   2,981  
  Trade receivables and other   289,204 148,267
  Derivative financial instruments 13 37,770 4,643
  Inventory   102,227 21,235
    432,182 174,145
Non-current assets      
  Property, plant and equipment 4 4,827,773 2,747,530
  Intangible assets and goodwill 5 2,657,479 243,904
  Investments in equity accounted investees   158,116 161,002
  Derivative financial instruments 13 724 1,807
 Other receivables   5,579 10,814
    7,649,671 3,165,057
Total Assets   8,081,853 3,339,202
Liabilities and Shareholders' Equity
Current liabilities
     
  Bank indebtedness     676
  Trade payables and accrued liabilities   251,640 166,646
  Dividends payable   38,850 21,828
  Loans and borrowings 6 9,963 323,927
  Derivative financial instruments 13 29,768 4,725
    330,221 517,802
Non-current liabilities      
  Loans and borrowings 6 1,745,554 1,012,061
  Convertible debentures 7 607,458 289,365
  Derivative financial instruments 13 38,945 12,813
  Employee benefits   15,281 16,951
  Share-based payments   10,837 14,060
  Deferred revenue   2,411 2,185
  Provisions 8 501,192 405,433
  Deferred tax liabilities   559,401 106,915
    3,481,079 1,859,783
Total Liabilities   3,811,300 2,377,585
Shareholders' Equity      
Equity attributable to shareholders:      
  Share capital 9 5,184,564 1,811,734
  Deficit   (903,922) (834,921)
  Accumulated other comprehensive income   (15,196) (15,196)
    4,265,446 961,617
Non-controlling interest   5,107  
    4,270,553 961,617
Total Liabilities and Shareholders' Equity   8,081,853 3,339,202

       See accompanying notes to condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME
(unaudited)

           
    3 Months Ended
June 30
6 Months Ended
June 30
($ thousands, except per share amounts) Note       2012       2011       2012       2011
Revenues   870,929 512,406 1,346,420 907,294
Cost of sales   762,099 417,746 1,131,309 731,552
Gain on commodity-related derivative financial instruments 13 52,351 3,142 48,577 4,849
Gross profit 11 161,181 97,802 263,688 180,591
           
  General and administrative   25,782 12,781 43,359 27,428
  Acquisition-related and other expense (income)   538 (662) 22,669 (582)
    26,320 12,119 66,028 26,846
           
Results from operating activities   134,861 85,683 197,660 153,745
  Finance income   (11,175) (536) (11,441) (911)
  Finance costs   37,880 25,583 57,695 40,199
  Net finance costs 10 26,705 25,047 46,254 39,288
           
Earnings before income tax and equity accounted
   investees
  108,156 60,636 151,406 114,457
           
  Share of loss (profit) of investments in equity accounted
    investees, net of tax
  570 (2,652) 398 (4,842)
           
  Income tax expense   27,178 15,245 38,048 28,764
           
Earnings and total comprehensive income for the period   80,408 48,043 112,960 90,535
           
Earnings and comprehensive income attributable to:          
  Shareholders   80,368 48,043 112,920 90,535
  Non-controlling interest   40   40  
    80,408 48,043 112,960 90,535
           
Earnings per share attributable to the shareholders of the
  Company
         
  Basic and diluted earnings per share (dollars)         0.28       0.29       0.50       0.54

       See accompanying notes to condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY
(unaudited)

       
    6 Months Ended June 30
($ thousands)  Note       2012       2011
Share Capital       
  Balance, beginning of period         1,811,734       1,794,536
  Common shares issued on acquisition         3,283,976  
  Dividend reinvestment plan         84,974  
  Share-based payment transactions         3,516       9,417
  Debenture conversion         366  
  Other         (2)       (10)
  Balance, end of period  9       5,184,564       1,803,943
       
Deficit      
  Balance, beginning of period         (834,921)       (739,351)
  Earnings for the period attributable to shareholders         112,920       90,535
  Dividends declared         (181,921)       (130,416)
  Balance, end of period         (903,922)       (779,232)
       
Other Comprehensive Income (Loss)      
  Balance, beginning and end of period         (15,196)       (4,577)
       
Non-controlling interest      
  Balance, beginning of period      
  Assumed on acquisition         5,067  
  Earnings attributable to non-controlling interest         40  
  Balance, end of period         5,107  
       
Total Equity         4,270,553       1,020,134

       See accompanying notes to condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
(unaudited)

           
          3 Months Ended
      June 30
      6 Months Ended
      June 30
($ thousands) Note 2012 2011 2012 2011
Cash provided by (used in):          
Operating activities:          
Earnings for the period   80,408 48,043 112,960 90,535
Adjustments for:          
  Depreciation and amortization   54,165 16,071 76,677 31,175
  Unrealized gain on commodity-related
     derivative financial instruments
13 (64,820) (3,301) (61,273) (3,598)
  Net finance costs 10 26,705 25,047 46,254 39,288
  Share of loss (profit) of investments in equity
   accounted investees (net of tax)
  570 (2,652) 398 (4,842)
  Deferred income tax expense   27,780 15,245 38,650 28,764
  Share-based payments   2,689 3,911 6,299 7,889
  Employee future benefits expense   1,898 1,203 3,329 2,401
  Other   (3) (146) 467 (62)
  Changes in non-cash working capital   (65,093) (32,310) (77,522) (33,761)
  Distributions from investments in equity accounted
    investees
  3,588 7,237 7,733 8,685
  Decommissioning liability expenditures   (1,310) (739) (2,367) (1,775)
  Employer future benefit contributions   (2,500) (2,000) (5,000) (4,000)
  Net interest paid   (40,004) (26,106) (57,198) (36,718)
Cash flow from operating activities   24,073 49,503 89,407 123,981
           
Financing activities:          
  Bank borrowings   200,000   266,861 40,000
  Repayment of loans and borrowings   (57,315) (82,588) (60,037) (85,100)
  Issuance of debt         250,000
  Financing fees   (2,275) (54) (5,066) (1,756)
  Exercise of stock options   1,611 5,266 2,647 9,086
  Issue of shares under Dividend Reinvestment Plan   56,973   84,974  
  Dividends paid   (99,338) (65,223) (164,900) (130,339)
Cash flow from financing activities   99,656 (142,599) 124,479 81,891
           
Investing activities:          
  Net capital expenditures   (131,869) (89,094) (219,103) (296,672)
  Cash acquired on acquisition   8,874   8,874  
Cash flow used in investing activities   (122,995) (89,094) (210,229) (296,672)
Change in cash   734 (182,190) 3,657 (90,800)
Cash (bank indebtedness), beginning of period   2,247 216,787 (676) 125,397
Cash and cash equivalents, end of period   2,981 34,597 2,981 34,597

       See accompanying notes to condensed consolidated interim financial statements

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(unaudited)

1. REPORTING ENTITY

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

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

2. SIGNIFICANT ACCOUNTING POLICIES

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

Inventories

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


3. ACQUISITION

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

The preliminary purchase price allocation based on assessed fair values is estimated as follows:

   
($ millions)  
Cash  9
Trade receivables and other 195
Inventory 87
Property, plant and equipment 1,988
Intangible assets and goodwill (including $1,759 goodwill) 2,422
Trade payables and accrued liabilities (249)
Derivative financial instruments - current (53)
Derivative financial instruments - non-current (36)
Loans and borrowings (215)
Convertible debentures (317)
Provisions and other (128)
Deferred tax liabilities (414)
Non-controlling interest (5)
  3,284
   

The determination of fair values and the allocation of the purchase price is based upon a preliminary independent valuation which is pending finalization. The primary drivers that generate goodwill are synergies and business opportunities from the integration of Pembina and Provident and the acquisition of a talented workforce. None of the goodwill recognized is expected to be deductible for income tax purposes.

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

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

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

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

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

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

   
(percentages) Ownership Interest
Pembina NGL Corporation 100
Pembina Facilities (NGL ) LP 100
Pembina Infrastructure and Logistics LP 100
Pembina Empress NGL Partnership 100
Pembina Resource Services Canada 100
Pembina Resource Services (U.S.A.) 100
Three Star Trucking Ltd. 67
 

4.  PROPERTY, PLANT AND EQUIPMENT

                         
($ 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   280,481   1,281,091   321,287   87,319   1,988,271
Additions   2   (99)   104,051   5,422   76,912   186,288
Change in decommissioning provision       (28,811)   (3,156)           (31,967)
Capitalized interest       3,173   696       1,977   5,846
Transfers   22   (67,116)   106,866   (18,126)   (21,646)    
Disposals and other   (5,000)   (917)   (621)   349       (6,189)
Balance at June 30, 2012   80,336   2,686,738   2,017,547   509,658   451,920   5,746,199
                         
Depreciation                        
Balance at December 31, 2011   4,088   707,095   92,998   52,239       856,420
Depreciation   140   35,017   20,604   7,516       63,277
Transfers       1,217   24,328   (25,545)        
Disposals and other       (567)   (76)   (628)       (1,271)
Balance at June 30, 2012   4,228   742,762   137,854   33,582       918,426
                         
Carrying amounts                        
December 31, 2011   63,131   1,792,932   435,622   148,487   307,358   2,747,530
June 30, 2012   76,108   1,943,976   1,879,693   476,076   451,920   4,827,773

(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 34 years) or declining balance method at rates ranging from 3 percent to 37 percent (at an average rate of 13 percent per annum). Other assets are depreciated using the straight line method over 2 to 45 years (an average of 10 years) or declining balance method at rates ranging from 3 percent to 37 percent (at an average rate of 8 percent per annum).

Commitments

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

5.  INTANGIBLE ASSETS AND GOODWILL

       
  Goodwill Other
Intangibles
Total
($ thousands)      
Cost      
Balance at December 31, 2011 222,670 23,038 245,708
Acquisition (Note 3) 1,759,356 662,732 2,422,088
Additions and other   5,000 5,000
Balance at June 30, 2012 1,982,026 690,770 2,672,796
       
Amortization      
Balance at December 31, 2011   1,804 1,804
Amortization   13,513 13,513
Balance at June 30, 2012   15,317 15,317
       
Carrying amounts      
December 31, 2011 222,670 21,234 243,904
June 30, 2012 1,982,026 675,453 2,657,479
       

Amortization is recognized in profit or loss on a straight-line or declining balance basis over the estimated useful lives of depreciable intangible assets from the date that they are available for use. The estimated useful lives of other intangible assets with finite useful lives range from 3 to 33 years (an average of 9 years).

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

         
 
($ thousands)
 
 
 
 
June 30,
2012
December 31,
2011
Conventional Pipelines           194,370 194,370
Oil Sands and Heavy Oil           33,300 28,300
Gas Services           20,885 21,234
Midstream           2,408,924  
            2,657,479 243,904
         

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

6.  LOANS AND BORROWINGS

Carrying value terms and debt repayment schedule

Terms and conditions of outstanding loans were as follows:

                   
($ thousands)                   Carrying amount(3)
  Available
facilities
  Nominal interest
rate
  Year of
maturity
  June 30,
2012
  Dec. 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   780,230   309,981
Senior secured notes           7.38           57,499
Senior unsecured notes - Series A 175,000         5.99   2014   174,570   174,462
Senior unsecured notes - Series C 200,000         5.58   2021   196,810   196,638
Senior unsecured notes - Series D 267,000         5.91   2019   265,504   265,403
Senior unsecured term facility 75,000         6.16   2014   74,729   74,658
Senior unsecured medium term notes 250,000         4.89   2021   248,636   248,558
Subsidiary debt 9,279         4.98   2014   9,279    
Finance lease liabilities                   5,759   5,650
Total interest-bearing liabilities 2,506,279           1,755,517   1,335,988
Less current portion             (9,963)   (323,927)
Total non-current             1,745,554   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) (264) (14) (332)
Accretion   280 229 509
Deferred financing fee (net amortization) 584 275 243 1,102
Balance, June 30, 2012 289,895 158,762 158,801 607,458

(1)  Excludes conversion feature of convertible debentures

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

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

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

8.  PROVISIONS

   
($ thousands) Total
Balance at December 31, 2011(1) 416,153
Unwinding of discount rate 5,777
Incurred during the period 1,766
Assumed on acquisition (Note 3) 124,579
Decommissioning liabilities settled during the period (2,367)
Change in rates (30,299)
Change in estimate and other (7,902)
Total 507,707
Less current portion (included in accrued liabilities) 6,515
  501,192

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

9.  SHARE CAPITAL

     
($ thousands, except share 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       175,203       3,516
Dividend reinvestment plan       3,151,670       84,974
Other       14,301       364
Balance June 30, 2012       287,785,195(1)       5,184,564

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

Dividends 

The following dividends were declared and paid by the Company:

     
  6 Months Ended
June 30
($ thousands) 2012 2011
$0.80 per qualifying common share (2011: $0.78) 181,921 130,416
     

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


10. NET FINANCE COSTS

           
  3 Months Ended
June 30
6 Months Ended
June 30
($ thousands) 2012 2011 2012 2011
Interest income from:         
  Related parties   220 263 410
  Bank deposits 298 284 301 389
Foreign exchange gains   32   112
Change in fair value of conversion feature of convertible debentures 10,877   10,877  
Finance income 11,175 536 11,441 911
         
Interest expense on financial liabilities measured at amortized cost:        
  Loans and borrowings 18,120 13,967 33,536 25,132
  Convertible debentures 10,579 4,601 15,184 9,168
  Finance leases 105 97 210 193
  Unwinding of discount 3,327 2,393 5,801 4,905
Change in fair value of non-commodity-related derivative financial
 instruments
5,475 4,525 2,659 801
Foreign exchange losses 274   305  
Finance costs 37,880 25,583 57,695 40,199
Net finance costs 26,705 25,047 46,254 39,288
         
     

11. OPERATING SEGMENTS

             
3 Months Ended June 30, 2012
($ thousands)
      Conventional
      Pipelines(1)
      Oil Sands &
      Heavy Oil
      Gas
      Services
      Midstream(3)       Corporate &
      Intersegment
Eliminations
      Total
Revenue:                  
  Pipeline transportation       78,410       39,412     (6,875) 110,947
  NGL product and
   services, terminalling,
   storage and hub services
      737,770   737,770
  Gas Services     22,212     22,212
Total revenue       78,410       39,412 22,212 737,770 (6,875) 870,929
  Operations       29,886       11,604 7,172 19,640 (624) 67,678
  Cost of goods sold, including
   product purchases
      648,794 (6,875) 641,919
  Realized gain (loss) on
   commodity-related derivative
   financial instruments
      (1,033)     (11,436)   (12,469)
Operating margin       47,491       27,808 15,040 57,900 624 148,863
  Depreciation and
   amortization (operational)
      12,179       4,938 4,332 31,053   52,502
  Unrealized gain (loss) on
    commodity-related
    derivative financial instruments
      233           64,587   64,820
Gross profit       35,545       22,870 10,708 91,434 624 161,181
  Depreciation included in
   general and administrative
        1,664 1,664
  Other general and administrative       2,225       968 1,456 5,488 13,981 24,118
  Acquisition-related and other       (311)       519   100 230 538
Reportable segment results from operating activities       33,631       21,383 9,252 85,846 (15,251) 134,861
  Net finance costs       1,760       563 1,964 4,128 18,290 26,705
Reportable segment earnings before tax and income from equity accounted investees       31,871       20,820 7,288 81,718 (33,541) 108,156
Share of loss (profit) of investments in equity
 accounted investees, net of tax
      570   570
Reportable segment assets       616,803       1,097,240 539,565 4,493,465(2) 1,334,780 8,081,853
Capital expenditures       55,632   23,459 55,240 2,277 136,608
Reportable segment liabilities       293,529       83,397 43,816 771,086 2,619,472 3,811,300

(1)  4.5 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
(2)  Includes investments in equity accounted investees of $158.1 million.
(3)  NGL product and services, terminalling, storage and hub services revenue includes $28.7 million associated with U.S. midstream sales.
   

             
3 Months Ended June 30, 2011
($ thousands)
      Conventional
      Pipelines(1)
      Oil Sands &
      Heavy Oil
      Gas Services       Midstream       Corporate &
      Intersegment
Eliminations
      Total
Revenue:            
  Pipeline
   transportation
72,407 27,707       100,114
  NGL product and services,
    terminalling, storage
    and hub services
      393,679   393,679
  Gas Services     18,613     18,613
Total revenue 72,407 27,707 18,613 393,679   512,406
  Operations 22,177 7,753 5,193 2,474   37,597
   Cost of goods sold, including
    product purchases
      364,356   364,356
  Realized gain (loss) on
   commodity-related
   derivative financial instruments
(159)         (159)
Operating margin 50,071 19,954 13,420 26,849   110,294
  Depreciation and amortization (operational) 10,356 2,037 2,512 888   15,793
  Unrealized gain (loss) on
   commodity-related
   derivative financial instruments
117     3,184   3,301
Gross profit 39,832 17,917 10,908 29,145   97,802
  Depreciation included in
   general and administrative
        279 279
  Other general and administrative 1,412 553 938 1,098 8,501 12,502
  Acquisition-related and other (497) (107) (1) (9) (48) (662)
Reportable segment results
 from operating activities
38,917 17,471 9,971 28,056 (8,732) 85,683
Net finance costs 1,743 358 145 38 22,763 25,047
Reportable segment earnings
 before tax and income from
 equity accounted investees
37,174 17,113 9,826 28,018 (31,495) 60,636
Share of loss (profit) of investments in equity
 accounted investees, net of tax
      (2,652)   (2,652)
Reportable segment assets 850,314 947,780 392,609 243,296(2) 621,671 3,055,670
Capital expenditures 10,088 30,135 25,467 11,564 942 78,196
Reportable segment liabilities 231,460 75,750 39,684 5,651 1,682,991 2,035,536

(1)  10.3 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
(2)  Includes investments in equity accounted investees of $162,753.
   

             
6 Months Ended June 30, 2012
($ thousands)
      Conventional
      Pipelines(1)
      Oil Sands &
      Heavy Oil
      Gas
      Services
      Midstream(2)       Corporate &
      Intersegment
Eliminations
      Total
Revenue:                  
  Pipeline transportation       160,581       82,509     (6,875) 236,215
  NGL product and services, terminalling, storage
   and hub services
      1,068,942         1,068,942
  Gas Services     41,263     41,263
Total revenue       160,581       82,509 41,263 1,068,942 (6,875) 1,346,420
  Operations       57,461       24,606 13,198 22,149 (1,260) 116,154
  Cost of goods sold, including product purchases             947,848 (6,875) 940,973
  Realized gain (loss) on commodity-related
   derivative financial instruments
      (1,189)           (11,507)   (12,696)
Operating margin       101,931       57,903 28,065 87,438 1,260 276,597
  Depreciation and amortization (operational)       24,124       9,829 7,494 32,735   74,182
  Unrealized gain (loss) on commodity-related
    derivative financial instruments
      (2,752)           64,025   61,273
Gross profit       75,055       48,074 20,571 118,728 1,260 263,688
  Depreciation included in
   general and administrative
        2,495 2,495
   Other general and administrative       3,123       1,907 1,977 6,775 27,082 40,864
  Acquisition-related and other       923       388 11 99 21,248 22,669
Reportable segment results from operating
   activities
      71,009       45,779 18,583 111,854 (49,565) 197,660
  Net finance costs       3,364       1,040 2,134 4,170 35,546 46,254
Reportable segment earnings before tax
 and income from equity
 accounted investees
      67,645       44,739 16,449 107,684 (85,111) 151,406
Share of loss (profit) of investments in equity
   accounted investees, net of tax
            398   398
Capital expenditures       64,472       6,041 55,762 55,930 4,083 186,288

(1)  4.5 percent of Conventional Pipelines revenue is under regulated tolling arrangements.
(2)  NGL product and services, terminalling, storage and hub services revenue includes $28.7 million associated with U.S. midstream sales.
   

             
6 Months Ended June 30, 2011
($ thousands)
      Conventional
      Pipelines(1)
      Oil Sands &
      Heavy Oil
      Gas
Services
      Midstream       Corporate &
      Intersegment
Eliminations
      Total
Revenue:            
  Pipeline transportation 141,664 58,253       199,917
  NGL product and services, terminalling, storage
   and hub services
      673,790   673,790
  Gas Services     33,587     33,587
Total revenue 141,664 58,253 33,587 673,790   907,294
  Operations 49,006 18,959 9,883 4,568   82,416
   Cost of goods sold, including product purchases       618,489   618,489
  Realized gain (loss) on commodity-related
   derivative financial instruments
1,455     (204)   1,251
Operating margin 94,113 39,294 23,704 50,529   207,640
  Depreciation and amortization (operational) 20,112 3,980 4,800 1,755   30,647
  Unrealized gain (loss) on commodity-related
   derivative financial instruments
4,652     (1,054)   3,598
Gross profit 78,653 35,314 18,904 47,720   180,591
  Depreciation included in
   general and administrative
        528 528
  Other general and administrative 2,698 1,150 2,079 2,285 18,688 26,900
  Acquisition-related and other (455) (107) 5 6 (31) (582)
Reportable segment results from operating
   activities
76,410 34,271 16,820 45,429 (19,185) 153,745
Net finance costs 3,544 674 458 39 34,573 39,288
Reportable segment earnings before tax and
   income from equity accounted investees
72,866 33,597 16,362 45,390 (53,758) 114,457
Share of loss (profit) of investments in equity
   accounted investees, net of tax
      (4,842)   (4,842)
Capital expenditures 26,786 129,898 41,093 101,909 1,792 301,478

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


12. SHARE BASED PAYMENTS

Long-term share unit award incentive plan(1)

         
Grant date Restricted Share Units ("RSU")(3) 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 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   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 are as follows:

           
    Number of Options     Weighted Average Exercise Price
Outstanding at December 31, 2011   2,674,380     20.24
Granted   74,100     29.52
Exercised   (175,203)     15.69
Forfeited   (80,493)     24.34
Outstanding as at June 30, 2012   2,492,784     20.71
           
           

13. FINANCIAL INSTRUMENTS

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

         
($ thousands As at
June 30,
      2012
          As at
December 31,
      2011
Frac spread related        
  Natural gas       (17,235)      
  Propane       11,482      
  Butane       9,681      
  Condensate       8,001      
  Foreign exchange       (1,149)      
  Sub-total frac spread related       10,780            
Management of exposure embedded in physical contracts and other       397           2,267
Corporate        
  Power       1,593           4,183
  Interest rate       (17,747)           (17,538)
Other derivative financial instruments        
  Conversion feature of convertible debentures       (18,835)      
  Redemption liability related to acquisition of subsidiary       (6,407)      
Net derivative financial instruments liability       (30,219)           (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 will be accreted and subsequently fair valued at each reporting date with changes in the value flowing through profit and loss. At June 30, 2012 the fair value of the redemption liability was determined to be $6.4 million, resulting in an unrealized loss of $0.2 million in the second quarter of 2012 recorded in net finance costs.

Also in conjunction with the Arrangement, the Company assumed all of the rights and obligations of Provident relating to the Provident Debentures which included a $29.7 million liability for the conversion feature of the Provident Debentures. These convertible debentures contain a cash conversion option which is measured at fair value through profit and loss at each reporting date, with any unrealized gains or losses arising from fair value changes reported in the consolidated statement of comprehensive income. This resulted in the Company recording a gain of $10.9 million on the revaluation on the conversion feature of convertible debentures in profit and loss in the second quarter of 2012 in net finance costs.

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

       
As at June 30, 2012 ($ thousands)   + Change - Change
Frac spread related      
  Natural gas (AECO +/- $1.00 per gj) 12,336 (12,336)
  NGLs (includes propane, butane) (Belvieu +/- U.S. $0.10 per gal) (8,377) 8,377
  Foreign exchange (U.S.$ vs. Cdn$) (FX rate +/- $0.05) (6,868) 6,868
Management of exposure embedded in
physical contracts
     
  Crude oil (WTI +/- $5.00 per bbl) (5,601) 5,601
  NGLs (includes propane, butane and condensate) (Belvieu +/- U.S. $0.10 per gal) 4,920 (4,920)
Corporate      
  Interest rate (Rate +/- 100 basis points) 946 (946)
  Power (AESO +/- $5.00 per MW/h) 3,217 (3,217)
Conversion feature of convertible debentures (Pembina share price +/- $0.50 per share) 2,101 (1,971)
       

                 
Commodity-Related Derivative
Financial Instruments
      3 Months Ended
      June 30
      6 Months Ended
      June 30
        2012       2011       2012       2011
($ thousands, except volumes)   $ Volume(1)    $       Volume   $ Volume  $       Volume
Realized (loss) gain on commodity-related derivative financial instruments                
Frac spread related                
  Crude oil (1,997) 0.1     (1,997) 0.1    
  Natural gas (7,762) 4.6     (7,762) 4.6    
  Propane 1,727 0.2     1,727 0.2    
  Butane 769 0.3     769 0.3    
  Condensate 272 0.2     272 0.2    
  Sub-total frac spread related (6,991)       (6,991)      
Corporate                
  Power (1,608)   (159)   (1,764)   1,455  
Management of exposure
 embedded in physical contracts
 and other
(3,870) 0.3     (3,941) 0.5 (204)  
Realized (loss) gain on derivative financial instruments (12,469)   (159)   (12,696)   1,251  
Unrealized gain on
 commodity-related derivative
 financial instruments
64,820   3,301   61,273   3,598  
Gain on commodity-related
 derivative financial instruments
52,351   3,142   48,577   4,849  

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

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

CORPORATE INFORMATION
............................................................................................................................................................................................................................................

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

AUDITORS
KPMG LLP
Chartered Accountants
Calgary, Alberta

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

STOCK EXCHANGE

Pembina Pipeline Corporation

TSX listing symbols for:
Common shares: PPL
Convertible debentures: PPL.DB.C, PPL.DB.E, PPL.DB.F

NYSE listing symbol for:
Common shares: PBA

 

 

 

 

 

 

 

 

 

SOURCE Pembina Pipeline Corporation




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