Pembina reports solid results for the second quarter and first half of 2013

Strong operating performance and continued expansion opportunities in all of Pembina's businesses support 3.7 percent dividend increase

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

CALGARY, Aug. 9, 2013 /CNW/ - On April 2, 2012 Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the comparative six month period ending June 30, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. For further information with respect to the Acquisition, please refer to Note 4 of the Condensed Consolidated Interim Financial Statements for the period ended June 30, 2013.

Financial & Operating Overview

($ millions, except where noted)	3 Months Ended       June 30		6 Months Ended       June 30
	2013	2012	2013	2012
Revenue	1,175.0	870.9	2,423.5	1,346.4
Operating margin(1)	207.8	148.9	447.6	276.6
Gross profit	176.8	161.2	380.6	263.7
Earnings for the period	93.8	80.4	184.3	113.0
Earnings per share - basic and diluted (dollars)	0.30	0.28	0.61	0.50
Adjusted EBITDA(1)	185.1	125.9	395.3	237.3
Cash flow from operating activities	140.2	24.1	369.2	89.4
Adjusted cash flow from operating activities(1)	144.0	89.5	351.4	188.3
Adjusted cash flow from operating activities per share (dollars) (1)	0.47	0.31	1.16	0.83
Dividends declared	125.0	116.2	246.0	181.9
Dividends per common share (dollars)	0.41	0.41	0.81	0.80

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

Second Quarter Highlights

• On August 9, 2013, subsequent to the end of the quarter, Pembina announced a 3.7 percent increase of its monthly dividend rate from $0.135 per share per month to $0.14 per share per month, effective on the August 25, 2013 record date and payable on September 13, 2013. This increase reflects Management's ongoing confidence in the Company's solid fundamentals, growing and sustainable cash flows from existing businesses, and fee-for-service focused growth profile.
  
  
• Consolidated operating margin was $207.8 million for the second quarter of 2013, an increase of 40 percent compared to $148.9 million during the same period of the prior year. Year-to-date, operating margin totaled $447.6 million compared to $276.6 million in the first half of 2012, representing an increase of approximately 62 percent. Operating margin is a non-GAAP measure; see "Non-GAAP Measures."
  
  
• Operating margin generated by Pembina's businesses during the second quarter of 2013 was positively impacted by several factors, including: strong results driven by a more balanced propane market in Midstream; increased volumes resulting from higher activity levels in the majority of Pembina's operating areas on the Company's Conventional Pipelines and in Gas Services; and, throughput above contracted levels on one of Pembina's Oil Sands & Heavy Oil pipelines. Operating margin generated in the second quarter of 2013 compared to the second quarter of 2012 by business are as follows:
• $91.4 million compared to $57.8 million from Midstream;
  
• $65.6 million compared to $47.5 million from Conventional Pipelines;
• $32.6 million compared to $27.8 million from Oil Sands & Heavy Oil; and
• $17.5 million compared to $15.1 million from Gas Services.
• Operating margin generated during the first half of the year was positively impacted by the factors mentioned above, as well as by the Acquisition in the Midstream business. Operating margin generated in the first six months of 2013 compared to the same period of 2012 by business are as follows:
• $219.9 million compared to $87.4 million from Midstream;
• $126.1 million compared to $101.9 million from Conventional Pipelines;
• $64.1 million compared to $57.9 million from Oil Sands & Heavy Oil; and
• $36.1 million compared to $28.1 million from Gas Services.
• Conventional Pipelines transported an average of 483.7 thousand barrels per day ("mbpd") in the second quarter of 2013 and 488.6 mbpd in the first half of the year, eleven and eight percent higher, respectively, than the same periods of 2012. Gas Services also saw an increase in volumes of two and seven percent, with the Cutbank Complex processing an average of 290.4 million cubic feet per day ("MMcf/d") during the second quarter and 294.8 MMcf/d in first half of 2013 compared to 285 MMcf/d and 275 MMcf/d in the comparable periods of the previous year.
  
  
• The Company's earnings increased to $93.8 million ($0.30 per share) during the second quarter of 2013 due to stronger operating results from each of Pembina's businesses compared to $80.4 million ($0.28 per share) during the second quarter of 2012, which included significant unrealized gains on commodity-related derivative financial instruments. Earnings were $184.3 million ($0.61 per share) during the first half of 2013 compared to $113 million ($0.50 per share) during the same period of the prior year as a result of both improved operating results and the impact of the Acquisition.
  
  
• Pembina generated adjusted EBITDA of $185.1 million during the second quarter of 2013 compared to $125.9 million during the second quarter of 2012 (adjusted EBITDA is a non-GAAP measure; see "Non-GAAP Measures"). This increase was largely due to improved results from operating activities in each of Pembina's businesses. Adjusted EBITDA for the six month period ended June 30, 2013 was $395.3 million compared to $237.3 million for the same period in 2012 due to strong results in each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the completion of the Acquisition.
  
  
• Cash flow from operating activities was $140.2 million ($0.45 per share) for the second quarter of 2013 compared to $24.1 million ($0.08 per share) for the same period in 2012. This increase was primarily due to improved results from operations and the impact of changes in non-cash working capital. For the six months ended June 30, 2013, cash flow from operating activities was $369.2 million ($1.22 per share) compared to $89.4 million ($0.39 per share) during the same period last year. The year-to-date increase was primarily due to higher adjusted EBITDA combined with changes in working capital and lower acquisition-related costs in the period.
  
  
• Adjusted cash flow from operating activities was $144 million ($0.47 per share) for the second quarter of 2013 compared to $89.5 million ($0.31 per share) during the second quarter of 2012 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). This increase was due to improved results from operations. Adjusted cash flow from operating activities was $351.4 million ($1.16 per share) during the first half of 2013 compared to $188.3 million ($0.83 share) during the same period of last year, primarily due to stronger operating results and the impact of the Acquisition.

Growth and Operational Update

During the first half of 2013, Pembina secured approximately $1.5 billion in capital projects (not including the proposed Cornerstone Pipeline), which the Company expects will provide long-term, sustainable returns once complete.

Oil Sands & Heavy Oil Developments

On June 27, 2013, Pembina announced that it had executed a $35 million engineering support agreement ("ESA") with KKD Oil Sands Partnership ("KOSP" - a partnership between Statoil Canada Ltd. ("Statoil"), as managing partner, and PTTEP Canada Ltd.) to progress work on a potential new oil sands pipeline project (the "Cornerstone Pipeline System"). Concurrent with the work under the ESA, Pembina and Statoil will proceed with negotiations to conclude long-term agreements for the construction of and transportation service on this proposed pipeline system, which will involve moving diluent and blended bitumen between KOSP's enhanced oil recovery developments in northeast Alberta and the Edmonton, Alberta area. The ESA will allow Pembina and KOSP to conduct preliminary engineering work and begin associated stakeholder consultation. At the conclusion of the work contemplated under the ESA, Pembina expects to be in a position to file the applications necessary to proceed with constructing the Cornerstone Pipeline System, subject to reaching commercial agreements. Provided that satisfactory commercial agreements can be reached and that regulatory and environmental approvals can be obtained thereafter, Pembina expects the Cornerstone Pipeline System could be in-service in mid-2017 at an estimated cost of $850 million based on the preliminary design. The Cornerstone Pipeline System is expected to also provide integration opportunities and synergies for Pembina's Midstream business, which is expected to be a 50-percent shipper on the diluent pipeline alongside KOSP.

Midstream Developments

On July 31, 2013, Pembina announced plans to spend approximately $25 million to upsize certain facilities associated with its second fractionator ("RFS II"), which is currently under development, to accommodate further expansion and the development of a third fractionator ("RFS III") at a later date at its Redwater site. Pembina has not yet entered into commercial agreements for RFS III, but believes there is strong market demand for additional fractionation capacity beyond what will be available after the completion of RFS II. Pembina's existing Redwater fractionator features 73,000 bpd of ethane-plus fractionation capacity. With the addition of RFS II, which is expected to come into service in the fourth quarter of 2015, the Company's ethane-plus fractionation capacity will double to 146,000 bpd. Should RFS III proceed, the facility would leverage engineering and design work completed for the original fractionator at Redwater and RFS II.

With respect to Pembina's ongoing cavern development program, the Company brought three new long-term fee-for-service caverns on stream at its Redwater site during the second quarter. Pembina also announced, on July 31, 2013, that it entered into long-term cost-of-service agreements with NOVA Chemicals Corporation for the use of an additional underground storage cavern and associated facilities at Redwater. The cavern will provide approximately 500,000 barrels of storage, with an expected on-stream date in mid to late 2015. Pembina expects the total capital cost of the cavern and associated infrastructure to be approximately $40 million. Pembina's cavern development program at Redwater is indicative of the Company's ongoing plans to meet the strong market demand for underground hydrocarbon storage in the greater Fort Saskatchewan area.

Gas Services' Developments

On August 9, 2013, Pembina announced that it is pursuing a new 100 MMcf/d shallow gas plant and associated natural gas liquids ("NGL") and gas gathering pipelines, Musreau II, near its existing Musreau facility. Musreau II, which is expected to cost approximately $110 million, is underpinned by long-term agreements with area producers for 100 percent of the facility's capacity. The facility will be designed to handle propane-plus (C₃+) and is expected to yield approximately 4,200 barrels per day ("bpd") of NGL for transportation on Pembina's Conventional Pipelines. Subject to regulatory and environmental approvals, Pembina expects Musreau II to be in-service early to mid-2015.

Conventional Pipelines Developments

Pembina is progressing its Phase I NGL Expansion, which is expected to add 52,000 bpd of additional NGL capacity to the Peace and Northern Pipelines (the "Peace/Northern NGL System"). In June, Pembina brought three pump stations into service which provide an additional 17,000 bpd of NGL capacity. On its Peace Pipeline, the Company expects to commission three new pump stations and upgrade four existing stations by the end of October 2013 to provide an additional 35,000 bpd of NGL capacity at an estimated cost of $70 million.

The Company is also completing the tie-in of a major third-party gas plant for a customer in the Deep Basin region, which is expected to come into service in early 2014 and cost approximately $20 million. The project includes the construction of two 11 km pipelines and significant tube storage at one of Pembina's existing pump stations.

The Phase I low vapour pressure expansion ("LVP") is also underway on Pembina's Peace Pipeline and will include three upgraded pump stations and associated pipeline work between Fox Creek and Edmonton, Alberta. This expansion will provide an additional 40,000 bpd of crude oil and condensate capacity on this segment. Pembina commissioned and brought into service the first of the three pump stations in July 2013, and expects to bring the remaining two stations into service by October 2013 at an estimated cost of $30 million.

Pembina's previously announced northwest Alberta pipeline expansion non-binding open season concluded on April 30, 2013. Nominations were sufficient to formally proceed to the next stage of the project. As such, Pembina has initiated stakeholder consultation activities, advanced third-party engineering design analysis and commenced negotiation of binding transportation agreements with area producers.

In addition, Pembina is installing eight additional crude oil and condensate truck unloading risers at its Fox Creek Terminal to facilitate producer access to the 95,000 bpd of incremental Phase I & II LVP Expansion capacity. The Fox Creek Terminal project is expected to be operational by November 2013.

Financing Activity

On July 26, 2013, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the "Series 1 Preferred Shares") at a price of $25.00 per share. Proceeds from the offering will be used to partially fund capital projects, repay amounts outstanding on the credit facility, and for other general corporate purposes of the Company. For more details on the Series 1 Preferred Shares, please refer to Pembina's website at www.pembina.com.

Also during the second quarter, on April 30, 2013, Pembina closed its offering of $200 million of 30-year senior unsecured medium-term notes. The notes have a fixed interest rate of 4.75% per annum, paid semi-annually, and will mature on April 30, 2043. The net proceeds of the offering were used to repay outstanding amounts on the Company's credit facilities.

Summary

"Pembina's operating performance this quarter demonstrates, yet again, the continued strength of our uniquely integrated asset base and service offering, both of which support the dividend increase we were proud to announce today" said Bob Michaleski, Pembina's Chief Executive Officer. "Further, our two successful financings suggest that our investors are pleased with the Company's direction and the ability of our growth projects to add future value. With solid performance in the first half of the year, our strengthened balance sheet, and the 3.7 percent increase in our monthly dividend, Pembina is on track to continue delivering consistent and improving financial results and long-term returns to investors."

Mick Dilger, Pembina's President and Chief Operating Officer added: "Pembina has a strong track record of identifying and completing projects that enhance our financial and operating results and drive sustainable and growing shareholder value, as evidenced by the dividend increase we announced today. With more projects on the books now than ever before, we believe we are well-positioned to capitalize on the tremendous growth opportunities we have in front of us as we offer additional capacity and enhanced services to our customers in key producing areas of the Western Canadian Sedimentary Basin. Our focus going forward will be on project execution as we bring our portfolio of announced growth projects into service over the next several years."

Second Quarter 2013 Conference Call & Webcast

Pembina will host a conference call on August 12, 2013 at 8 a.m. MT (10 a.m. ET) to discuss details related to the second quarter. The conference call dial-in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A recording of the conference call will be available for replay until August 19, 2013 at 11:59 p.m. ET. To access the replay, please dial either 416-849-0833 or 855-859-2056 and enter the password 17968415.

A live webcast of the conference call can be accessed on Pembina's website at www.pembina.com under Investor Centre, Presentation & Events, or by entering: https://event.on24.com/eventRegistration/EventLobbyServlet?target=registration.jsp&eventid=656734&sessionid=1&key=F5C8000D74F4B53A3949D9A26D3E5E09&sourcepage=register in your web browser. Shortly after the call, an audio archive will be posted on the website for a minimum of 90 days.

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, 2013 and is supplementary to, and should be read in conjunction with, Pembina's unaudited condensed consolidated interim financial statements for the period ended June 30, 2013 ("Interim Financial Statements") as well as Pembina's consolidated audited annual financial statements and MD&A for the year ending December 31, 2012 (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 Generally Accepted Accounting Principles ("GAAP"). For more information about the measures which are not defined by GAAP, see "Non-GAAP Measures."

On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd. ("Provident") (the "Acquisition"). The amounts disclosed herein for the comparative six month period ending June 30, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. The results of the business acquired through the Acquisition are reported as part of the Company's Midstream business. For further information with respect to the Acquisition, please refer to Note 4 of the Interim Financial Statements.

About Pembina

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

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

Strategy

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

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

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

Common Abbreviations

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

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

Financial & Operating Overview

		3 Months Ended June 30		6 Months Ended June 30
($ millions, except where noted)		2013	2012	2013	2012
Conventional Pipelines throughput (mbpd)		483.7	433.9	488.6	450.4
Oil Sands & Heavy Oil contracted capacity (mbpd)		870.0	870.0	870.0	870.0
Gas Services average processed volume (mboe/d) net to Pembina(1)		48.4	47.5	49.1	45.8
NGL sales volume (mbpd)		93.8	90.4	108.3	90.4(3)
Total volume (mbpd)		1,495.9	1,441.8	1,516.0	1,456.6
Revenue		1,175.0	870.9	2,423.5	1,346.4
Operations		91.1	67.7	168.3	116.1
Cost of goods sold, including product purchases		880.2	641.9	1,813.8	941.0
Realized gain (loss) on commodity-related derivative financial instruments		4.1	(12.4)	6.2	(12.7)
Operating margin(2)		207.8	148.9	447.6	276.6
Depreciation and amortization included in operations		32.4	52.5	74.2	74.2
Unrealized gain (loss) on commodity-related derivative financial instruments		1.4	64.8	7.2	61.3
Gross profit		176.8	161.2	380.6	263.7
Deduct/(add)
	General and administrative expenses	26.2	25.8	58.8	43.4
	Acquisition-related and other expense	0.6	0.5		22.6
	Net finance costs	24.4	26.8	75.2	46.3
	Share of loss of investments in equity accounted investee, net of tax	0.4	0.6	0.7	0.4
	Income tax expense	31.4	27.1	61.6	38.0
Earnings for the period		93.8	80.4	184.3	113.0
Earnings per share - basic and diluted (dollars)		0.30	0.28	0.61	0.50
Adjusted EBITDA(2)		185.1	125.9	395.3	237.3
Cash flow from operating activities		140.2	24.1	369.2	89.4
Cash flow from operating activities per share (dollars)		0.45	0.08	1.22	0.39
Adjusted cash flow from operating activities(2)		144.0	89.5	351.4	188.3
Adjusted cash flow from operating activities per share (dollars)(2)		0.47	0.31	1.16	0.83
Dividends declared		125.0	116.2	246.0	181.9
Dividends per common share (dollars)		0.41	0.41	0.81	0.80
Capital expenditures		222.7	136.6	359.8	186.3
Total enterprise value ($ billions) (2)		12.5	9.9	12.5	9.9
Total assets ($ billions)		8.5	8.1	8.5	8.1

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

Revenue, net of cost of goods sold, increased 29 percent to $294.8 million during the second quarter of 2013 compared to $229 million during the second quarter of 2012, primarily due to strong operational performance in each of Pembina's businesses. Year-to-date revenue, net of cost of goods sold, in 2013 was $609.7 million, up 50 percent from the same period last year. This increase was primarily due to improved performance in each of Pembina's legacy businesses as well as the impact of the Acquisition.

Operating expenses were $91.1 million during the second quarter of 2013 compared to $67.7 million in the second quarter of 2012 and $168.3 million for the six months ended June 30, 2013 compared to $116.1 million in the same period in 2012. The increase in operating expenses for the second quarter and first half of 2013 was largely due to higher variable costs in each of the Company's legacy businesses because of increased volumes and activity as well as additional costs associated with the growth in Pembina's asset base primarily resulting from the Acquisition.

Operating margin totalled $207.8 million during the second quarter of 2013, up 40 percent from the same period last year when operating margin totalled $148.9 million (Operating margin is a Non-GAAP measure; see "Non-GAAP Measures"). For the six months ended June 30, 2013 operating margin was $447.6 million compared to $276.6 million for the same period of 2012. These increases were primarily due to strong performance and growth throughout Pembina's operations, but more particularly from Midstream and Conventional Pipelines.

Realized and unrealized gains/losses on commodity-related derivative financial instruments resulting from Pembina's market risk management program are primarily related to power, frac spread, and product margin derivative financial instruments (see "Market Risk Management Program" and Note 11 to the Interim Financial Statements). The unrealized gain on commodity-related derivative financial instruments was $1.4 million and $7.2 million in the three and six months ended June 30, 2013, respectively, reflecting changes in the future NGL, natural gas and power price indices. During the comparative 2012 periods, the significant unrealized gains on commodity-related derivative financial instruments were largely attributable to the reduction in the future NGL price indices between April 2, 2012 and June 30, 2012.

Depreciation and amortization (operational) decreased to $32.4 million during the second quarter of 2013 compared to $52.5 million during the same period in 2012. The decrease is primarily due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset (see Note 7 to the Interim Financial Statements). For the six months ended June 30, 2013, depreciation and amortization (operational) was $74.2 million, unchanged from the same period last year.

The increases in revenue and operating margin contributed to gross profit of $176.8 million during the second quarter and $380.6 million during the first six months of 2013 compared to $161.2 million and $263.7 million during the relative periods of the prior year.

General and administrative expenses ("G&A") of $26.2 million were incurred during the second quarter of 2013, virtually unchanged from $25.8 million during the second quarter of 2012. G&A for the first half of 2013 was $58.8 million compared to $43.4 million for the same period of 2012. The increase for the six month period was mainly due to the addition of new employees who joined the Company both as a result of the Company's growth as well as through the Acquisition. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by approximately $1 million.

The Company's earnings increased to $93.8 million ($0.30 per share) during the second quarter of 2013 due to stronger operating results from each of Pembina's businesses compared to $80.4 million ($0.28 per share) during the second quarter of 2012, which included significant unrealized gains on commodity-related derivative financial instruments. Earnings were $184.3 million ($0.61 per share) during the first half of 2013 compared to $113 million ($0.50 per share) during the same period of the prior year as a result of both improved operating results and the impact of the Acquisition.

Pembina generated adjusted EBITDA of $185.1 million during the second quarter of 2013 compared to $125.9 million during the second quarter of 2012 (adjusted EBITDA is a non-GAAP measure; see "Non-GAAP Measures"). This increase was largely due to improved results from operating activities in each of Pembina's businesses. Adjusted EBITDA for the six month period ended June 30, 2013 was $395.3 million compared to $237.3 million for the same period in 2012 due to strong results in each of Pembina's legacy businesses, new assets and services having been brought on-stream, and the completion of the Acquisition.

Cash flow from operating activities was $140.2 million ($0.45 per share) for the second quarter of 2013 compared to $24.1 million ($0.08 per share) for the same period in 2012. This increase was primarily due to improved results from operations and the impact of changes in non-cash working capital. For the six months ended June 30, 2013, cash flow from operating activities was $369.2 million ($1.22 per share) compared to $89.4 million ($0.39 per share) during the same period last year. The year-to-date increase was primarily due to higher adjusted EBITDA combined with changes in working capital and lower acquisition-related costs in the period.

Adjusted cash flow from operating activities was $144 million ($0.47 per share) for the second quarter of 2013 compared to $89.5 million ($0.31 per share) during the second quarter of 2012 (adjusted cash flow from operating activities is a Non-GAAP measure; see "Non-GAAP Measures"). This increase was due to improved results from operations. Adjusted cash flow from operating activities was $351.4 million ($1.16 per share) during the first half of 2013 compared to $188.3 million ($0.83 share) during the same period of last year, primarily due to stronger operating results and the impact of the Acquisition.

Operating Results

	3 Months Ended June 30				6 Months Ended June 30
	2013		2012		2013		2012
($ millions)	Net Revenue(1)	Operating Margin(1)	Net Revenue(1)	Operating Margin(1)	Net Revenue(1)	Operating Margin(1)	Net Revenue(1)	Operating Margin(1)
Conventional Pipelines	101.5	65.6	78.4	47.5	197.3	126.1	160.6	101.9
Oil Sands & Heavy Oil	50.9	32.6	39.4	27.8	94.3	64.1	82.5	57.9
Gas Services	28.6	17.5	22.2	15.1	56.1	36.1	41.3	28.1
Midstream	113.8	91.4	89.0	57.8	262.0	219.9	121.0(2)	87.4(2)
Corporate		0.7		0.7		1.4		1.3
Total	294.8	207.8	229.0	148.9	609.7	447.6	405.4	276.6

(1)	Refer to "Non-GAAP Measures."
(2)	Includes results from operations generated by the assets acquired from Provident since closing of the acquisition on April 2, 2012.

Conventional Pipelines

	3 Months Ended  June 30		6 Months Ended June 30
($ millions, except where noted)	2013	2012	2013	2012
Average throughput (mbpd)	483.7	433.9	488.6	450.4
Revenue	101.5	78.4	197.3	160.6
Operations	37.7	30.0	73.0	57.5
Realized gain (loss) on commodity related derivative financial instruments	1.8	(0.9)	1.8	(1.2)
Operating margin(1)	65.6	47.5	126.1	101.9
Depreciation and amortization (recovery) included in operations	(2.1)	12.2	(0.5)	24.1
Unrealized gain (loss) on commodity-related derivative financial instruments	1.4	0.3	2.3	(2.7)
Gross profit	69.1	35.6	128.9	75.1
Capital expenditures	58.9	55.6	120.3	64.5

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

Business Overview

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

Operational Performance: Throughput

During the second quarter of 2013, Conventional Pipelines' throughput averaged 483.7 mbpd, consisting of an average of 363 mbpd of crude oil and condensate and 120.7 mbpd of NGL. This represents an increase of approximately 11 percent compared to the same period of 2012, when average throughput was 433.9 mbpd. On a year-to-date basis in 2013, throughput averaged 488.6 mbpd compared to 450.4 mbpd in the first half of 2012. The higher throughputs resulted from increased oil and gas producer activity in the areas serviced by Conventional Pipelines, which led to a number of newly connected facilities and increased volumes at existing connections and at truck terminals.

Financial Performance

During the second quarter of 2013, Conventional Pipelines generated revenue of $101.5 million compared to $78.4 million in the same quarter of the previous year. For the first six months of 2013, revenue was $197.3 million compared to $160.6 million for the same period in 2012. The 29 and 23 percent increases during the respective periods were primarily due to stronger volumes, as noted above, and modest tariff increases on certain pipeline systems. Further, a pipeline system previously in the Midstream business was reassigned to Conventional Pipelines, resulting in increased revenue of $7.1 million and $13.1 million for the second quarter and first six months of 2013, respectively. This had no impact on volume (discussed above) as the assets are interconnected to existing Conventional Pipelines systems.

During the second quarter of 2013, operating expenses increased to $37.7 million compared to $30 million in the second quarter of 2012. Operating expenses for the six months ended June 30, 2013 increased to $73 million from $57.5 million during the same period of 2012. The quarterly and year-to-date increases were mainly associated with work to ensure safe and reliable operations at higher throughput levels, such as increased pipeline integrity and geotechnical initiatives, as well as power and labour costs, compared to the same periods of the prior year.

As a result of higher revenue, which was partially offset by an increase in operating expenses, operating margin for the second quarter of 2013 was $65.6 million compared to $47.5 million during the second quarter of 2012 and $126.1 million for the first half of 2013 compared to $101.9 million for the first six months of 2012.

For depreciation and amortization included in operations during the second quarter, Conventional Pipelines recovered $2.1 million due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset. This compares to an expense of $12.2 million during the second quarter of 2012. Depreciation and amortization included in operations for the six months ended June 30, 2013 was also a recovery of $0.5 million, due to the same factor noted above. This compares to an expense of $24.1 million in the first half of 2012.

For the three and six months ended June 30, 2013, gross profit was $69.1 million and $128.9 million, respectively, compared to $35.6 million and $75.1 million for the same periods of the prior year. These increases are due to higher revenue generated during the quarter and first half of the year, for the reasons discussed above, as well as the recovery in depreciation and amortization included in operations.

Capital expenditures for the second quarter and first half of 2013 totalled $58.9 million and $120.3 million, respectively, compared to $55.6 million and $64.5 for the same periods of 2012. The majority of this spending relates to the expansion of certain pipeline assets as described below, as well as several new connections.

New Developments

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

NGL Pipeline Capacity Expansions

Pembina is progressing its Phase I NGL Expansion, which is expected to add 52,000 bpd of additional NGL capacity to the Peace and Northern Pipelines (the "Peace/Northern NGL System"). In June, Pembina brought three pump stations into service which provide an additional 17,000 bpd of NGL capacity. On its Peace Pipeline, the Company expects to commission three new pump stations and upgrade four existing stations by the end of October 2013 to provide an additional 35,000 bpd of NGL capacity at an estimated cost of $70 million. Once complete, the Phase I NGL Expansion will increase NGL capacity on the Peace/Northern NGL System by 45 percent to 167,000 bpd.

As part of the Company's approximately $1 billion expansion of its existing NGL infrastructure, Pembina is also proceeding with the proposed Phase II NGL Expansion of its Peace/Northern NGL System which will increase capacity from 167,000 bpd to 220,000 bpd. In total, the Phase I and II expansions are expected to increase NGL transportation capacity by 90 percent. Subject to obtaining regulatory and environmental approvals, Pembina expects the Phase II NGL Expansion to cost approximately $415 million (including mainline and tie-in capital) and to be complete in early to mid-2015.

The Company is also completing the tie-in of a major third-party gas plant for a customer in the Deep Basin region, which is expected to come into service in early 2014 and cost approximately $20 million. The project includes the construction of two 11 km pipelines and significant tube storage at one of Pembina's existing pump stations.

Crude Oil and Condensate Pipeline Capacity Expansions

The Phase I low vapour pressure expansion ("LVP") is also underway on Pembina's Peace Pipeline and will include three upgraded pump stations and associated pipeline work between Fox Creek and Edmonton, Alberta. This expansion will provide an additional 40,000 bpd of crude oil and condensate capacity on this segment. Pembina commissioned and brought into service the first of the three pump stations in July 2013, and expects to bring the remaining two stations into service by October 2013 at an estimated cost of $30 million.

On February 13, 2013, Pembina announced that it had reached its contractual threshold to proceed with its previously announced plans to significantly expand its crude oil and condensate throughput capacity on its Peace Pipeline system by 55,000 bpd ("Phase II LVP Expansion"). Pembina expects the total cost of the Phase II LVP Expansion to be approximately $250 million (including the mainline expansion and tie-ins). Subject to regulatory and environmental approvals, Pembina anticipates being able to bring the expansion into service by late 2014. Once complete, this expansion will increase LVP capacity on Pembina's Peace Pipeline to 250,000 bpd. The Phase II LVP Expansion is underpinned by long-term fee-for-service agreements with area producers. The combined LVP expansions will increase capacity by 61 percent from current levels.

Open Season Update

Pembina's previously announced northwest Alberta pipeline expansion non-binding open season concluded on April 30, 2013. Nominations were sufficient to formally proceed to the next stage of the project. As such, Pembina has initiated stakeholder consultation activities, advanced third-party engineering design analysis and commenced negotiation of binding transportation agreements with area producers.

In addition, Pembina is installing eight additional crude oil and condensate truck unloading risers at its Fox Creek Terminal to facilitate producer access to the 95,000 bpd of incremental Phase I & II LVP Expansion capacity. The Fox Creek Terminal project is expected to be operational by November 2013.

Supporting Gas Services

Conventional Pipelines is also constructing the pipeline components of the Company's Saturn I, Saturn II and Resthaven gas plant projects. These pipeline projects will gather NGL from the gas plants for delivery to Pembina's Peace Pipeline system. Both Saturn I and Saturn II will use the same pipeline lateral, which is complete and ready for service when the Saturn I facility comes on-stream. Some additional equipment will be required when Saturn II is complete to tie the facility into the lateral. Pembina is also continuing to progress the pipeline component of the Resthaven project and is on schedule to meet the targeted in-service date.

Oil Sands & Heavy Oil 

	3 Months Ended June 30		6 Months Ended June 30
($ millions, except where noted)	2013	2012	2013	2012
Contracted capacity (mbpd)	870.0	870.0	870.0	870.0
Revenue	50.9	39.4	94.3	82.5
Operations	18.3	11.6	30.2	24.6
Operating margin(1)	32.6	27.8	64.1	57.9
Depreciation and amortization included in operations	4.9	4.9	9.8	9.8
Gross profit	27.7	22.9	54.3	48.1
Capital expenditures	12.5		24.6	6.0

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

Business Overview

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

Financial Performance

The Oil Sands & Heavy Oil business realized revenue of $50.9 million in the second quarter of 2013 compared to $39.4 million in the second quarter of 2012. Year-to-date revenue in 2013 was $94.3 million compared to $82.5 million for the same period in 2012. Revenue for the second quarter and first half of the year was higher than the comparable periods of the prior year mostly due to higher recoverable operating costs across the systems as well as increased contribution from the Nipisi system due to a new pump station being placed in-service, which allowed for additional volumes above contracted levels in the 2013 periods.

Operating expenses were $18.3 million during the second quarter of 2013 compared to $11.6 million during the second quarter of 2012. For the first six months of 2013, operating expenses were $30.2 million compared to $24.6 million for the same period in 2012. Additional power costs were the main reason for the increase in operating expenses for both the second quarter and first half of 2013.

For the three and six months ended June 30, 2013, operating margin increased to $32.6 million and $64.1 million compared to $27.8 million and $57.9 million, respectively, during the same periods in 2012. These increases were primarily due to a new pump station being placed in-service which allowed for additional throughput above contracted volumes on the Nipisi pipeline in the 2013 periods.

Depreciation and amortization included in operations for the second quarter and first half of 2013 totalled $4.9 million and $9.8 million respectively, unchanged from the same periods of the prior year.

For the three and six months ended June 30, 2013, gross profit was $27.7 million and $54.3 million, higher than gross profit of $22.9 million and $48.1 million, respectively, during the same periods of 2012.

During the first half of the year, capital expenditures within the Oil Sands & Heavy Oil business totalled $24.6 million and were primarily related to the construction of additional pump stations in the Slave Lake, Alberta, area on the Nipisi and Mitsue pipelines. This compares to $6 million spent during the same period in 2012, the majority of which related to completing the two pipeline construction projects.

New Developments

On June 27, 2013, Pembina announced that it had secured a $35 million engineering support agreement ("ESA") with KKD Oil Sands Partnership ("KOSP" - a partnership between Statoil Canada Ltd. ("Statoil"), as managing partner, and PTTEP Canada Ltd.) to progress work on a potential new oil sands pipeline project (the "Cornerstone Pipeline System"). Concurrent with the work under the ESA, Pembina and Statoil will proceed with negotiations to conclude long-term agreements for the construction of and transportation service on the Cornerstone Pipeline System. The Cornerstone Pipeline System, a diluent and blended bitumen pipeline system, would provide transportation services between KOSP's enhanced oil recovery developments in northeast Alberta and the Edmonton, Alberta area. The ESA will allow for Pembina and KOSP to conduct preliminary engineering work and begin associated stakeholder consultation. At the conclusion of the work contemplated under the ESA, Pembina expects to be in a position to file the applications necessary to proceed with constructing the Cornerstone Pipeline System, subject to reaching commercial agreements. Provided that satisfactory commercial agreements can be reached and that regulatory and environmental approvals can be obtained thereafter, Pembina expects the Cornerstone Pipeline System could be in-service in mid-2017 at an estimated cost of $850 million based on the preliminary design. The Cornerstone Pipeline System is expected to also provide integration opportunities and synergies for Pembina's Midstream business, which is expected to be a 50-percent shipper on the diluent pipeline alongside KOSP.

On the Nipisi Pipeline, Pembina commissioned a new pump station in April 2013, which increased its capacity to 105,000 bpd. Work is continuing on the corresponding pump station for the Mitsue condensate pipeline, which is anticipated to be in-service in the third quarter of 2013 and will bring Mitsue's capacity from 18,000 bpd to 22,000 bpd.

Gas Services

	3 Months Ended June 30		6 Months Ended June 30
($ millions, except where noted)	2013	2012	2013	2012
Average processed volume (MMcf/d) net to Pembina	290.4	285.0	294.8	275.0
Average processed volume (mboe/d)(1) net to Pembina	48.4	47.5	49.1	45.8
Revenue	28.6	22.2	56.1	41.3
Operations	11.1	7.1	20.0	13.2
Operating margin(2)	17.5	15.1	36.1	28.1
Depreciation and amortization included in operations	3.6	4.3	7.2	7.5
Gross profit	13.9	10.8	28.9	20.6
Capital expenditures	83.8	23.5	122.3	55.8

(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 near Grande Prairie, Alberta, Pembina's key revenue-generating Gas Services' asset is the Cutbank Complex, which includes three sweet gas processing plants with 425 MMcf/d of processing capacity (368 MMcf/d net to Pembina), a 205 MMcf/d ethane plus extraction facility, as well as approximately 350 km of gathering pipelines. The Cutbank Complex is connected to Pembina's Peace Pipeline system and serves an active exploration and production area in the WCSB. Pembina has initiated construction on and development of numerous projects in its Gas Services business to meet the growing needs of producers in west central Alberta.

Operational Performance

Average processing volumes, net to Pembina, were 290.4 MMcf/d during the second quarter of 2013, slightly higher than the 285 MMcf/d processed during the second quarter of the previous year. On a year-to-date basis, volumes have increased just over seven percent compared to the first half of last year. This increase is attributed to sustained interest of producers in the surrounding areas and their focus on liquids-rich natural gas, which continues to attract higher commodity pricing relative to dry gas.

Financial Performance

Gas Services recorded a 29 percent increase in revenue during the second quarter of 2013, contributing $28.6 million compared to $22.2 million in the second quarter of 2012. For the first half of the year, revenue was $56.1 million compared to $41.3 million in the same period of 2012. These increases primarily reflect higher fees for additional capital invested at the Company's Cutbank Complex and greater volumes, coupled with increased recovery of operating expenses of $4 million and $6.8 million, respectively.

During the second quarter of 2013, operating expenses were $11.1 million compared to $7.1 million in the second quarter of 2012. Year-to-date operating expenses totalled $20 million, up from $13.2 million during the same period of the prior year. The quarterly and year-to-date increases were mainly due to labour and power costs associated with higher volumes and increased activity at the Cutbank Complex as well as additional expenses related to running the Musreau shallow cut expansion and deep cut facility.

As a result of processing higher volumes at the Cutbank Complex, an increase in fees for capital invested and additional processing associated with the Musreau deep cut facility, Gas Services realized operating margin of $17.5 million in the second quarter and $36.1 million in the first half of 2013 compared to $15.1 million and $28.1 million during the same periods of the prior year.

For the three months ended June 30, 2013, gross profit was $13.9 million compared to $10.8 million in the same period of 2012. On a year-to-date basis, gross profit was $28.9 million compared to $20.6 million during the first half of 2012. These increases reflect higher operating margin during the period.

For the first six months of 2013, capital expenditures within Gas Services totalled $122.3 million compared to $55.8 million during the same period of 2012. This increase was because of spending to progress the Saturn I, Saturn II and Resthaven facilities, discussed below.

New Developments

Pembina's Gas Services business is progressing four new facilities and associated infrastructure:

• Saturn I facility - a 200 MMcf/d enhanced NGL extraction facility in the Berland area of west central Alberta, which is expected to cost $165 million;
• Resthaven facility - a 200 MMcf/d (130 MMcf/d net to Pembina) combined shallow cut and deep cut NGL extraction facility in the Resthaven, Alberta area, which is now expected to cost $240 million (net to Pembina);
• Saturn II facility - a 200 MMcf/d 'twin' of the Saturn I facility, which is expected to cost $170 million; and,
• Musreau II - a 100 MMcf/d shallow cut gas plant and associated infrastructure, which is expected to cost $110 million.

Saturn I

Pembina has completed construction of and is in the process of dry commissioning the Saturn I facility. The Company is on schedule to have Saturn I and its associated pipelines in-service in the third quarter of 2013. Once operational, Pembina expects Saturn I will have the capacity to extract up to 13.5 mbpd of NGL.

Resthaven

Pembina is progressing construction of the Resthaven facility and expects to bring the facility and associated pipelines into service in the third quarter of 2014. Capital costs on this project have increased due to design redevelopment and scope changes. Once operational, the Company expects the Resthaven facility will have the capacity to extract up to 13 mbpd of NGL.

In the second quarter, Pembina took over operatorship of the existing 100 MMcf/d shallow cut plant at the Resthaven site from Encana in order to streamline operation of the plant while the Resthaven facility is under construction.

Saturn II

Saturn II will leverage the engineering work completed for the Saturn I facility and is underpinned by a firm-service contract with a third-party for 130 MMcf/d (approximately 65 percent of the facility's total capacity) for a term of 10 years. Pembina expects the project could be in-service by late 2015, subject to regulatory and environmental approvals. Based on 100 percent capacity, Saturn II is expected to extract approximately 13.5 mbpd of NGL which will be transported on the same pipeline lateral Pembina is currently constructing for Saturn I.

Musreau II

On August 9, 2013, Pembina announced that it is pursuing a new 100 MMcf/d shallow gas plant and associated NGL and gas gathering pipelines, Musreau II, near its existing Musreau facility. Musreau II is underpinned by long-term agreements with area producers. The facility will be designed to handle propane-plus (C₃+) and is expected to yield approximately 4.2 mbpd of NGL for transportation on Pembina's Conventional Pipelines. Subject to regulatory and environmental approvals, Pembina expects Musreau II to be in-service in early to mid-2015.

Summary

Pembina expects the expansions detailed above to bring the Company's Gas Services processing capacity to approximately 1.2 billion cubic feet per day (net) by the end of 2015. This includes enhanced NGL extraction capacity of approximately 735 MMcf/d (net). The volumes from Pembina's existing assets and those under development would be processed largely on a contracted, fee-for-service basis and are expected to result in approximately 55 mbpd of NGL to be transported for additional toll revenue on Pembina's Conventional Pipelines once the projects are complete.

Midstream

	3 Months Ended June 30		6 Months Ended June 30(1)
($ millions, except where noted)	2013	2012	2013	2012
Revenue	1,006.0	737.8	2,100.9	1,068.9
Operations	24.7	19.7	46.5	22.1
Cost of goods sold, including product purchases	892.2	648.8	1,838.9	947.9
Realized gain (loss) on commodity related derivative financial instruments	2.3	(11.5)	4.4	(11.5)
Operating margin(2)	91.4	57.8	219.9	87.4
Depreciation and amortization included in operations	26.0	31.1	57.7	32.8
Unrealized gain on commodity-related derivative financial instruments		64.5	4.9	64.0
Gross profit	65.4	91.2	167.1	118.6
Capital expenditures	65.9	55.2	89.8	55.9

(1)	Share of profit from equity accounted investees not included in these results.
(2)	Refer to "Non-GAAP Measures."

Business Overview

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

• Crude oil midstream targets oil and diluent-related development opportunities from key sites across Pembina's network, which is comprised of 15 truck terminals (including one capable of emulsion treating and water disposal), terminalling at downstream hub locations, storage, and the Pembina Nexus Terminal ("PNT"). PNT includes: 21 inbound pipeline connections; 13 outbound pipeline connections; in excess of 1.2 million bpd of crude oil and condensate connected to the terminal; and, 310,000 barrels of surface storage in and around the Edmonton, Alberta area.
  
  
• NGL midstream includes two NGL operating systems - Redwater West and Empress East. The financial performance of NGL midstream can be affected by the seasonal demand for propane. Inventory generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year during the winter heating season.
• The Redwater West NGL system includes the Younger extraction and fractionation facility in B.C.; a 73 mbpd NGL fractionator and 7.8 mmbbls of finished product cavern storage at Redwater, Alberta; and, third-party fractionation capacity in Fort Saskatchewan, Alberta. Redwater West purchases NGL mix from various natural gas and NGL producers and fractionates it into finished products for further distribution and sale. Also located at the Redwater site is Pembina's industry-leading rail-based terminal which services Pembina's proprietary and customer needs for importing and exporting LPG and crude oil
  
  
• The Empress East NGL system includes a 2.1 bcf/d interest in the straddle plants at Empress, Alberta; 20 mbpd of fractionation capacity and 1.1 mmbbls of cavern storage in Sarnia, Ontario; and, ownership of 5.1 mmbbls of hydrocarbon storage at Corunna, Ontario. Empress East extracts NGL mix from natural gas at the Empress straddle plants and purchases NGL mix from other producers/suppliers. Ethane and condensate are generally fractionated out of the NGL mix at Empress and sold into Alberta markets. The remaining NGL mix is transported by pipeline to Sarnia, Ontario for fractionation, distribution and sale. Propane and butane are sold into central Canadian and eastern U.S. markets.

Financial Performance

In the Midstream business, revenue, net of cost of goods sold, grew to $113.8 million during the second quarter of 2013 from $89 million during the second quarter of 2012. For the most part, the increase is due to a more balanced propane market and lower inventories in North America in the 2013 period compared to the 2012 period. Year-to-date revenue, net of cost of goods sold, was $262 million in 2013 compared to $121 million in 2012. This increase was primarily due to a full six months of results generated by the NGL assets in 2013 compared to the 2012 period, which only captured three months of results due to the timing of the Acquisition, along with strong margins and increased storage opportunities for crude oil Midstream in the first quarter of 2013.

Operating expenses during the second quarter and first half of 2013 were $24.7 million and $46.5 million, respectively, compared to $19.7 million and $22.1 million in the comparable periods of 2012. Operating expenses were higher due to the increase in Midstream's asset base since the Acquisition.

Operating margin was $91.4 million during the second quarter of 2013 and $219.9 million during the first half of the year compared to $57.8 million and $87.4 million in the respective periods of 2012. These increases primarily relate to growth in revenue, as discussed above, but were partially offset by higher operating expenses.

The Company's crude oil midstream operating margin decreased to $28.1 million in the second quarter of 2013 compared to $30.7 million during the second quarter of 2012. This decrease was largely due to narrower price differentials resulting in fewer storage opportunities and lower overall margins in the second quarter. For the first half of the year, crude oil midstream operating margin totalled $70.8 million compared to $60.3 million during the same period of the prior year. The year-to-date increase was due to strong first quarter 2013 results driven by higher volumes and increased activity on Pembina's pipeline systems, robust demand for diluent services, wider margins, as well as increased throughput at the crude oil Midstream truck terminals.

Operating margin for Pembina's NGL midstream activities was $63.3 million for the second quarter, including a $2.9 million realized gain on commodity-related derivative financial instruments (see "Market Risk Management Program") compared to $27.1 million for the second quarter of 2012 including an $11.2 million realized loss on commodity related derivative financial instruments. For the six months ended June 30, 2013, operating margin for NGL midstream was $149.1 million, including a $6.7 million realized gain on commodity-related derivative financial instruments compared to $27.1 million, which included a realized loss on commodity-related derivative financial instruments of $11.2 million, for the same period of 2012.

NGL sales volumes during the second quarter of 2013 were 93.8 mbpd, a four percent increase overall from the second quarter of 2012, driven by higher sales in propane, butane and condensate.

Operating margin from Redwater West during the second quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $44.6 million compared to $36.2 million in the second quarter of 2012. The increase is primarily driven by a stronger year-over-year market for propane. Increased sales volumes for condensate also contributed to a higher operating margin in the second quarter of 2013. The increases in propane and condensate margins were somewhat offset by softer butane markets, as 2013 western Canadian butane inventories are at the high end of the five-year average.  Overall, Redwater West NGL sales volumes averaged 58.8 mbpd in the second quarter of 2013 compared to 51.9 mbpd in the second quarter of 2012.

Operating margin from Empress East during the second quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $15.9 million compared to $2.2 million in the same quarter in 2012. Similar to Redwater West, the increase in second quarter results in Empress East is primarily driven by a stronger year-over-year market for propane. The operating margin for condensate was slightly higher in the second quarter of 2013 compared to the same quarter of the prior year while operating margins for butane and ethane were slightly lower. Overall, Empress East NGL sales volumes averaged 35.1 mbpd in the second quarter of 2013 compared to 38.5 mbpd in the second quarter of 2012.

Depreciation and amortization included in operations during the second quarter of 2013 totalled $26 million compared to $31.1 million during the same period of the prior year. The decrease reflects a reassignment of assets previously in the Midstream business to Conventional Pipelines, as previously discussed. Year-to-date depreciation and amortization included in operations totaled $57.7 million, up from $32.8 million during the first half of 2012. The year-to-date increases reflect the additional Midstream assets in this business since the closing of the Acquisition.

In the second quarter of 2013, unrealized gains on commodity-related derivative financial instruments were nil compared to $64.5 million for the three months ended June 30, 2012. For the first half of the year, unrealized gains on commodity-related derivative financial instruments were $4.9 million compared to $64 million in the same period of the prior year. The significant unrealized gains on commodity-related derivative financial instruments which were recognized in the three and six month periods ended June 30, 2012, respectively, reflected the reduction in the future NGL price indices between April 2, 2012 and June 30, 2012.

For the three and six months ended June 30, 2013, gross profit in this business was $65.4 million and $167.1 million compared to $91.2 million and $118.6 million during the same periods in 2012 due to the factors impacting revenue, operating expenses and depreciation and amortization (operational) and unrealized gain (loss) on commodity-related derivative financial instruments noted above.

For the six months ended June 30, 2013, capital expenditures within the Midstream business totalled $89.8 million compared to $55.9 million during the same period of 2012 and were primarily related to cavern development and associated infrastructure.

New Developments

Market demand for assets and services in the Midstream space is strong across all commodities. The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects which are expected to continue to increase this businesses' stability and predictability.

The most substantial project in this business is the twinning of Pembina's existing Redwater fractionator in Redwater, Alberta ("RFS II"), which was announced on March 5, 2013 and is part of the Company's $1 billion NGL infrastructure expansion. Subject to regulatory and environmental approvals, Pembina expects RFS II to be in-service late in the fourth quarter of 2015.

Under the agreements signed with producers, Pembina will receive committed take-or-pay operating margin for an initial 10-year term from the in-service date. Contracts for 97 percent of the facility's operating capacity have been secured. Ethane produced at RFS II will be sold under a long-term fixed-fee arrangement.

The Company also announced, on July 31, 2013, that it plans to spend approximately $25 million to upsize certain facilities associated with RFS II to accommodate further expansion and the development of a third fractionator ("RFS III") at a later date at its Redwater site. Pembina has not yet entered into commercial agreements for RFS III, but believes there is strong market demand for additional fractionation capacity beyond what will be available after the completion of RFS II. With the addition of RFS II, which is expected to come into service in the fourth quarter of 2015, the Company's ethane-plus fractionation capacity at Redwater will double to 146,000 bpd. Should RFS III proceed, the facility would leverage engineering and design work completed for the original fractionator at Redwater and RFS II.

With respect to Pembina's ongoing cavern development program, the Company brought three new long-term fee-for-service caverns on stream at its Redwater site during the second quarter. Pembina also announced, on July 31, 2013, that it entered into long-term cost-of-service agreements with NOVA Chemicals Corporation for the use of an additional underground storage cavern and associated facilities at Redwater. The cavern will provide approximately 500,000 barrels of storage, with an expected on-stream date in mid to late 2015. Pembina expects the total capital cost of the cavern and associated infrastructure to be approximately $40 million. Pembina's cavern development program at Redwater is indicative of the Company's ongoing plans to meet the strong market demand for underground hydrocarbon storage in the greater Fort Saskatchewan area.

Pembina also continues to advance numerous other projects in Midstream as follows:

• In July 2013, Pembina brought a new full-service terminal ("FST") on stream. This FST is a joint venture in the Judy Creek area of Alberta and will serve the production from Beaverhill Lake and Swan Hills. The Company plans to bring a second FST that serves producers in the Cynthia area west of Drayton Valley on stream in the first quarter of 2014, a quarter behind its original schedule.
  
  
• In September 2013, Pembina expects to begin commercial operations of its 40,000 bpd crude oil rail loading facility.
  
  
• Pembina's Midstream business is working with Oil Sands & Heavy Oil to leverage the potential Cornerstone Pipeline project and offer additional midstream related services and is expected to be a 50-percent shipper on the diluent pipeline alongside KOSP.
  
  
• Pembina is also continuing to investigate offshore propane export opportunities that would allow it to leverage its existing assets and provide a substantial incremental market for Canadian producers impacted by weak western Canadian pricing.

Market Risk Management Program

Pembina is exposed to frac spread risk, which is the difference between the selling price for propane-plus liquids and the input cost of natural gas required to produce respective NGL products. Pembina has a risk management program and uses derivative financial instruments to mitigate frac spread risk, when possible, to safeguard a base level of operating cash flow that covers the input cost of natural gas. Pembina has entered into derivative financial swap contracts to partially protect the frac spread and product margin, 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 agreements; and, obtaining financial assurances where warranted. In addition, Pembina has a diversified base of available counterparties.

Management continues to actively monitor commodity price risk and mitigate its impact through financial risk management activities. For more information on financial instruments and financial risk management, see Note 11 to the Interim Financial Statements.

Non-Operating Expenses

G&A

Pembina incurred G&A (including corporate depreciation and amortization) of $26.2 million during the second quarter of 2013, virtually unchanged from $25.8 million during the second quarter of 2012. G&A for the first half of 2013 was $58.8 million compared to $43.4 million for the same period of 2012. The increase for the six month period was mainly due to the addition of new employees who joined the Company both as a result of the Company's growth as well as through the Acquisition. In addition, every $1 change in share price is expected to change Pembina's annual share-based incentive expense by approximately $1 million.

Depreciation & Amortization (operational)

Depreciation and amortization (operational) decreased to $32.4 million during the second quarter of 2013 compared to $52.5 million during the same period in 2012. For the six months ended June 30, 2013, depreciation and amortization (operational) was $74.2 million, unchanged from the same period last year. The variance during the quarter compared to the same period of last year is primarily due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset.

Net Finance Costs

Net finance costs in the second quarter of 2013 were $24.4 million compared to $26.8 million in the second quarter of 2012. This slight decrease is primarily due to gains on non-commodity-related derivative financial instruments driven by higher forward interest rates, as well as higher interest income and lower interest expense on loans and borrowings, offset by a loss on revaluation of the conversion feature of the convertible debentures. Year-to-date net finance costs in 2013 totaled $75.2 million, up from $46.3 million in the same period of 2012. The increase primarily relates to a $28.1 million loss on revaluation of the conversion feature on convertible debentures as a result of an increase in the market price of Pembina shares.

Income Tax Expense

Income tax expense was $31.4 million for the second quarter of 2013, including current taxes of $8.3 million and deferred taxes of $23.1 million compared to current tax benefits of $0.6 million and deferred taxes of $27.7 million in the same period of 2012. Year-to-date income tax expense in 2013 totaled $61.6 million, up from $38 million in the same period of 2012. The current taxes arose during the quarter primarily as a result of certain Pembina subsidiary corporation's taxable income exceeding their losses available for carry-over. Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities.

Liquidity & Capital Resources

($ millions)		June 30, 2013			December 31, 2012
Working capital		(224.2)(3)			62.8
Variable rate debt(1)(2)
	Bank debt	105.0			525.0
Total variable rate debt outstanding (average rate of 2.67%)		105.0			525.0
Fixed rate debt(1)
	Senior unsecured notes	642.0			642.0
	Senior unsecured term debt	75.0			75.0
	Senior unsecured medium-term notes	900.0			700.0
	Subsidiary debt	8.8			9.3
Total fixed rate debt outstanding (average of 4.99%)		1,625.8			1,426.3
Convertible debentures(1)		642.9			644.3
Finance lease liability		7.3			5.8
Total debt and debentures outstanding		2,381.0			2,601.4
Cash and unutilized debt facilities		1,434.8			1,032.3

(1)	Face value.
(2)	Pembina maintains derivative financial instruments to manage exposure to variable interest rates. See Market Risk Management Program.
(3)	As at June 30, 2013, working capital includes $261.4 million (December 31, 2012: $11.7 million) associated with the current portion of loans and borrowings.

Pembina anticipates cash flow from operating activities will be more than sufficient to meet its short-term operating obligations and fund its targeted dividend level. In the short-term, Pembina expects to source funds required for capital projects from cash and cash equivalents and unutilized debt facilities totalling $1,434.8 million as at June 30, 2013. In addition, based on its successful access to financing in the debt and equity markets during the past several years, Pembina believes it would likely continue to have access to funds at attractive rates. Management remains satisfied that the leverage employed in Pembina's capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base.

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

Pembina's credit facilities at June 30, 2013 consisted of an unsecured $1.5 billion revolving credit facility due March 2018 and an operating facility of $30 million due July 2014. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil percent to 1.25 percent or Bankers' Acceptances rates plus 1.00 percent to 2.25 percent. Margins on the credit facilities are based on the credit rating of Pembina's senior unsecured debt. There are no repayments due over the term of these facilities. As at June 30, 2013, Pembina had $105 million drawn on bank debt, $0.1 million in letters of credit and $9.8 million in cash, leaving $1,434.8 million of unutilized debt facilities on the $1,530 million of established bank facilities. Pembina also had an additional $17 million in letters of credit issued in a separate demand letter of credit facility. At June 30, 2013, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,730.8 million. Pembina's senior debt to total capital at June 30, 2013 was 25 percent.

On July 26, 2013, Pembina announced that it closed its previously announced public offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the "Series 1 Preferred Shares") at a price of $25.00 per Series 1 Preferred Share for aggregate gross proceeds of $250 million. This includes shares issued in respect of the previously announced underwriters' option to purchase an additional 2,000,000 Series 1 Preferred Shares at a price of $25.00 per share, which was exercised in full. Proceeds from the offering will be used to partially fund capital projects, repay amounts outstanding on the credit facility, and for other general corporate purposes of the Company. The Series 1 Preferred Shares began trading on the Toronto Stock Exchange on July 26, 2013 under the symbol PPL.PR.A.

Also during the second quarter, on April 30, 2013, Pembina closed its offering of $200 million of 30-year senior unsecured medium-term notes. The notes have a fixed interest rate of 4.75% per annum, paid semi-annually, and will mature on April 30, 2043. The net proceeds of the offering were used to repay outstanding amounts on the Company's credit facilities.

Credit Ratings

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

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

Capital Expenditures

		3 Months Ended June 30		6 Months Ended June 30
($ millions)		2013	2012	2013	2012
Development capital
	Conventional Pipelines	58.9	55.6	120.3	64.5
	Oil Sands & Heavy Oil	12.5		24.6	6.0
	Gas Services	83.8	23.5	122.3	55.8
	Midstream	65.9	55.2	89.8	55.9
Corporate/other projects		1.6	2.3	2.8	4.1
Total development capital		222.7	136.6	359.8	186.3

For the three months ended June 30, 2013, capital expenditures were $222.7 million compared to $136.6 million spent in the same three months of 2012.

During the first half of 2013, capital expenditures were $359.8 million compared to $186.3 million during the same six month period in 2012.

The majority of the capital expenditures in the first half of 2013 were in Pembina's Conventional Pipelines, Gas Services and Midstream businesses. Conventional Pipelines' capital was incurred to progress its phase I and phase II crude oil, condensate and NGL expansions and on various new connections. Gas Services' capital was deployed to progress the Saturn I and Resthaven enhanced NGL extraction facilities. Midstream's capital expenditures were primarily directed towards cavern development and related infrastructure as well as RFS II.

Contractual Obligations at June 30, 2013

($ millions)	Payments Due By Period
Contractual Obligations	Total	Less than 1 year	1 - 3 years	3 - 5 years	After 5 years
Operating and finance leases	307.8	26.6	61.7	63.4	156.1
Loans and borrowings(1)	2,474.2	338.8	131.3	236.2	1,767.9
Convertible debentures(1)	882.0	39.2	78.9	245.4	518.5
Construction commitments	817.8	456.4	361.4
Provisions(2)	307.8	0.2	5.6	25.6	276.4
Total contractual obligations(3)	4,789.6	861.2	638.9	570.6	2,718.9

(1)	Excluding deferred financing costs.
(2)	Includes discounted constructive and legal obligations included in the decommissioning provision.
(3)	Excluding expansion rights and obligations associated with existing contracts and which have not yet been triggered.

Pembina is, subject to certain conditions, contractually committed to the construction and operation of: the Saturn I, Saturn II and Resthaven facilities; RFS II; and the previously mentioned crude oil and NGL Conventional Pipeline expansions. See "Forward-Looking Statements & Information."

Changes in Accounting Principles and Practices

The following new standards, interpretations, amendments and improvements to existing standards issued by the International Accounting Standard Board or International Financial Reporting Interpretations Committee were adopted as of January 1, 2013 without any material impact to Pembina's Financial Statements: IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interests in Other Entities, IFRS 13 Fair Value Measurement, and IAS 19 Employee Future Benefits.

Controls and Procedures

Changes in internal control over financial reporting

Pembina's management is responsible for establishing and maintaining disclosure controls and procedures ("DC&P") and internal control over financial reporting ("ICFR"), as those terms are defined in National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or submitted under securities legislation.

The CEO and the CFO have designed, with the assistance of Pembina employees, DC&P and ICFR to provide reasonable assurance that material information relating to Pembina's business is made known to them, is reported on a timely basis, financial reporting is reliable, and financial statements prepared for external purposes are in accordance with GAAP.

During the second quarter 2013, there were no changes made to Pembina's ICFR that materially affected, or are reasonably likely to materially affect, its ICFR.

Trading Activity and Total Enterprise Value⁽¹⁾

			As at and for the 3 months ended
($ millions, except where noted)		August 7, 2013(2)	June 30, 2013	June 30, 2012
Trading volume and value
	Total volume (shares)	12,692,292	37,511,884	56,667,601
	Average daily volume (shares)	488,165	586,123	899,486
	Value traded	414.4	1,227.1	1,620.2
Shares outstanding (shares)		310,263,731	309,450,062	287,785,195
Closing share price (dollars)		32.08	32.18	26.02
Market value
	Common shares	9,953.3	9,958.1	7,488.2
	Series 1 preferred shares (PPL.PR.A)	245.0(3)
	5.75% convertible debentures (PPL.DB.C)	350.7(4)	354.6(5)	325.9(6)
	5.75% convertible debentures (PPL.DB.E)	223.1(7)	224.5(8)	192.9(9)
	5.75% convertible debentures (PPL.DB.F)	200.6(10)	191.2(11)	186.2(12)
Market capitalization		10,972.6	10,728.4	8,193.2
Senior debt		1,617.0	1,722.0	1,752.0
Total enterprise value(13)		12,589.6	12,450.4	9,945.2

(1)	Trading information in this table reflects the activity of Pembina securities on the TSX only.
(2)	Based on 26 trading days from July 1, 2013 to August 7, 2013, inclusive.
(3)	10 million preferred shares outstanding at a market price of $24.50 at August 7, 2013.
(4)	$299 million principal amount outstanding at a market price of $117.29 at August 7, 2013 and with a conversion price of $28.55.
(5)	$299.1 million principal amount outstanding at a market price of $118.55 at June 30, 2013 and with a conversion price of $28.55.
(6)	$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.
(7)	$171.6 million principal amount outstanding at a market price of $130.00 at August 7, 2013 and with a conversion price of $24.94.
(8)	$171.6 million principal amount outstanding at a market price of $130.79 at June 30, 2013 and with a conversion price of $24.94.
(9)	$172.4 million principal outstanding at a market price of $112.06 at June 29, 2012 and with a conversion price of $24.94.
(10)	$172.2 million principal amount outstanding at a market price of $116.50 at August 7, 2013 and with a conversion price of $29.53.
(11)	$172.2 million principal amount outstanding at a market price of $111.02 at June 30, 2013 and with a conversion price of $29.53.
(12)	$172.4 million principal outstanding at a market price of $107.98 at June 29, 2012 with a conversion price of $29.53.
(13)	Refer to "Non-GAAP Measures."

As indicated in the previous table, Pembina's total enterprise value was $12.5 billion at June 30, 2013 compared to $9.9 billion at June 30, 2012. The Company's issued and outstanding shares rose to 309.5 million by the end of the second quarter 2013, compared to 287.8 million in the same period of 2012, primarily due to shares issued on the closing of the bought deal financing which closed in the first quarter of 2013 and shares issued under the DRIP.

Dividends

Pembina announced on August 9, 2013, that it increased its monthly dividend rate by 3.7 percent from $0.135 per common share per month (or $1.62 annualized) to $0.14 per common share per month (or $1.68 annualized) effective as of the August 25, 2013 record date, payable September 13, 2013. Pembina is committed to providing increased shareholder returns over time by providing stable dividends and, where appropriate, further increases in Pembina's dividend, subject to compliance with applicable laws and the approval of Pembina's Board of Directors. Pembina has a history of delivering common share dividend increases once supportable over the long-term by the underlying fundamentals of Pembina's businesses as a result of, among other things, accretive growth projects or acquisitions (see "Forward-Looking Statements & Information").

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

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

Participation in the DRIP for the second quarter of 2013 was approximately 57 percent of common shares outstanding for proceeds of approximately $70.5 million.

As of the April 25, 2013 record date, Pembina has made its DRIP available to its U.S. shareholders. U.S. shareholders are only permitted to participate in the Dividend Reinvestment Component of Pembina's DRIP. Only Canadian resident shareholders are currently permitted to participate in the Premium Dividend™ Component of the DRIP. Shareholders who elect to enroll in the full Dividend Reinvestment Component are notified that the sale of the common shares issued on reinvestment is being made pursuant to a registration statement on Form F-3 filed by Pembina with the U.S. Securities and Exchange Commission ("SEC").

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

Selected Quarterly Operating Information

	2013		2012				2011
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Average volume (mbpd unless stated otherwise)
Conventional Pipelines throughput	483.7	493.7	480.2	443.9	433.9	466.9	422.8	430.4	411.4
Oil Sands & Heavy Oil contracted capacity	870.0	870.0	870.0	870.0	870.0	870.0	870.0	775.0	775.0
Gas Services processing (mboe/d)(1)	48.4	49.9	46.0	45.8	47.5	44.1	45.3	43.6	40.9
NGL sales volume (mboe/d)	93.8	122.9	115.8	86.7	90.4

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

Selected Quarterly Financial Information

		2013		2012				2011
($ millions, except where noted)		Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Revenue		1,175.0	1,248.5	1,265.7	815.3	870.9	475.5	468.1	300.6	512.4
Operations		91.1	77.2	86.0	69.5	67.7	48.4	55.1	54.4	37.6
Cost of goods sold, including   product purchases		880.2	933.6	968.6	565.5	641.9	299.1	308.0	145.8	364.3
Realized gain (loss) on commodity-   related derivative financial   instruments		4.1	2.1	11.0	(2.8)	(12.4)	(0.3)	0.9	3.2	(0.2)
Operating margin(1)		207.8	239.8	222.1	177.5	148.9	127.7	105.9	103.6	110.3
Depreciation and amortization   included in operations		32.4	41.8	47.8	51.6	52.5	21.7	19.6	17.8	15.8
Unrealized gain (loss) on   commodity-related derivative   financial instruments		1.4	5.8	(2.2)	(23.0)	64.8	(3.5)	0.9	0.7	3.3
Gross profit		176.8	203.8	172.1	102.9	161.2	102.5	87.2	86.5	97.8
Adjusted EBITDA(1)		185.1	210.2	199.0	153.8	125.9	111.4	88.2	89.9	103.3
Cash flow from operating activities		140.2	229.0	139.5	130.9	24.1	65.3	73.8	87.7	49.5
Cash flow from operating activities   per common share ($ per share)		0.45	0.77	0.48	0.45	0.08	0.39	0.44	0.52	0.30
Adjusted cash flow from operating   activities(1)		144.0	207.4	172.3	133.2	89.5	98.8	66.0	82.0	81.8
Adjusted cash flow from operating activities per common share(1)   ($ per share)		0.47	0.70	0.59	0.46	0.31	0.59	0.39	0.49	0.49
Earnings for the period		93.8	90.5	81.3	30.7	80.4	32.6	45.0	30.1	48.0
Basic and diluted earnings per   common share ($ per share)		0.30	0.30	0.28	0.11	0.28	0.19	0.27	0.18	0.29
Common shares outstanding   (millions):
	Weighted average (basic)	308.3	295.9	291.9	289.2	285.3	168.3	167.4	167.6	167.3
	Weighted average (diluted)	309.2	296.7	292.5	289.7	286.0	168.9	168.2	168.2	168.0
	End of period	309.5	307.0	293.2	290.5	287.8	169.0	167.9	167.7	167.5
Dividends declared		125.0	121.0	118.4	117.3	116.2	65.7	65.4	65.4	65.3
Dividends per common share   ($ per share)		0.405	0.405	0.405	0.405	0.405	0.390	0.390	0.390	0.390

(1)	Refer to "Non-GAAP measures."

During the periods in the previous table, Pembina's results were influenced by the following factors and trends:

• Increased oil production from customers operating in the Cardium and Deep Basin Cretaceous formations of west central Alberta, which has resulted in increased service offerings in these areas, as well as new connections and capacity expansions;
• Increased liquids-rich natural gas production from producers in the WCBS (Deep Basin, Montney and emerging Duvernay Shale plays), which has resulted in increased gas gathering and processing at the Company's Gas Services assets and additional associated NGL transported on its pipelines;
• Improved propane industry fundamentals in Canada and North America;
• The Acquisition, which closed on April 2, 2012 (see Note 4 of the Interim Financial Statements).
• Increased shares outstanding due to: the Acquisition; the DRIP; and, the bought deal equity financing in the first quarter of 2013.

Additional Information

Additional information about Pembina and legacy Provident filed with Canadian securities commissions and the SEC, including quarterly and annual reports, AIFs (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. Except as otherwise indicated, these Non-GAAP measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.

Net revenue

Net revenue is total revenue less cost of goods sold including product purchases.

					3 Months Ended       June 30		6 Months Ended       June 30
($ millions)					2013	2012	2013	2012
Total revenue					1,175.0	870.9	2,423.5	1,346.4
Cost of goods sold					880.2	641.9	1,813.8	941.0
Net revenue					294.8	229.0	609.7	405.4

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 Acquisition.

	3 Months Ended June 30		6 Months Ended June 30
($ millions, except per share amounts)	2013	2012	2013	2012
Results from operating activities	150.0	134.9	321.8	197.7
Share of profit from equity accounted investees (before tax,   depreciation and amortization)	1.6	1.3	3.4	2.8
Depreciation and amortization	34.8	54.2	77.9	76.7
Unrealized (gain) loss on commodity-related derivative financial   instruments	(1.4)	(64.8)	(7.2)	(61.3)
EBITDA	185.0	125.6	395.9	215.9
Add:
Acquisition-related expenses	0.1	0.3	(0.6)	21.4
Adjusted EBITDA	185.1	125.9	395.3	237.3
EBITDA per common share - basic (dollars)	0.60	0.44	1.31	0.95
Adjusted EBITDA per common share - basic (dollars)	0.60	0.44	1.31	1.05

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)	2013	2012	2013	2012
Cash flow from operating activities	140.2	24.1	369.2	89.4
Add (deduct):
Change in non-cash operating working capital	3.7	65.1	(17.2)	77.5
Acquisition-related expenses	0.1	0.3	(0.6)	21.4
Adjusted cash flow from operating activities	144.0	89.5	351.4	188.3
Cash flow from operating activities per common share - basic (dollars)	0.45	0.08	1.22	0.39
Adjusted cash flow from operating activities per common share - basic (dollars)	0.47	0.31	1.16	0.83

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)		2013	2012	2013	2012
Revenue		1,175.0	870.9	2,423.5	1,346.4
Cost of sales:
	Operations	91.1	67.7	168.3	116.1
	Cost of goods sold, including product purchases	880.2	641.9	1,813.8	941.0
	Realized gain (loss) on commodity-related derivative financial instruments	4.1	(12.4)	6.2	(12.7)
Operating margin		207.8	148.9	447.6	276.6
Depreciation and amortization included in operations		32.4	52.5	74.2	74.2
Unrealized gain (loss) on commodity-related derivative financial instruments		1.4	64.8	7.2	61.3
Gross profit		176.8	161.2	380.6	263.7

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, preferred 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 net revenue, EBITDA, adjusted EBITDA, adjusted cash flow from operating activities, operating margin and total enterprise value should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial results determined in accordance with GAAP as an indicator of Pembina's performance. Furthermore, these Non-GAAP measures may not be comparable to similar measures presented by other issuers.

Forward-Looking Statements & Information

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

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

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

• the future levels of cash dividends that Pembina intends to pay to its shareholders;
• capital expenditure-estimates, plans, schedules, rights and activities and the planning, development, construction, operations and costs of pipelines, gas services facilities, terminalling, storage and hub facilities and other facilities or energy infrastructure, including, but not limited to: the Cornerstone Pipeline system, the Peace/Northern NGL System, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase II LVP Expansion, the Phase II NGL Expansion, the joint venture full-service terminal in the Judy Creek area of Alberta area, the development program in the Cynthia area west of Drayton Valley, offshore export opportunities for propane, the Nipisi and Mitsue pipeline expansions, the Saturn I and II facilities and associated pipelines, the Musreau II facility, the Resthaven facility and associated pipelines, and the Redwater fractionator (RFS II) expansion and potential RFS III expansion;
• future expansion of Pembina's pipelines and other infrastructure;
• pipeline, processing and storage facility and system operations and throughput levels;
• oil and gas industry exploration and development activity levels;
• Pembina's strategy and the development of new business initiatives;
• growth opportunities;
• expectations regarding Pembina's ability to raise capital and to carry out acquisition, expansion and growth plans;
• treatment under government regulatory regimes including environmental regulations and related abandonment and reclamation obligations;
• future G&A expenses at Pembina;
• increased throughput potential due to increased activity and new connections and other initiatives on Pembina's pipelines;
• future cash flows, potential revenue and cash flow enhancements across Pembina's businesses and the maintenance of operating margins;
• tolls and tariffs and transportation, storage and services commitments and contracts;
• cash dividends and the tax treatment thereof;
• operating risks (including the amount of future liabilities related to pipeline spills and other environmental incidents) and related insurance coverage and inspection and integrity programs;
• the expected capacity, incremental volumes and in-services dates, as applicable, of proposed expansions and new developments, including the Cornerstone Pipeline system, Northern NGL System,  the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase II LVP Expansion, the Phase II NGL Expansion, the Nipisi and Mitsue pipeline expansions, the Saturn I and II facilities, the Musreau II facility, the Resthaven facility, and the Redwater fractionator (RFS II) expansion;
• the possibility of offshore export opportunities for propane;
• the possibility of renegotiating debt terms, repayment of existing debt, seeking new borrowing and/or issuing equity;
• expectations regarding participation in Pembina's DRIP;
• the expected impact of changes in share price on annual share-based incentive expense;
• inventory and pricing levels in the North American liquids market;
• Pembina's discretion to hedge natural gas and NGL volumes and power; and
• competitive conditions.

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

• the success of Pembina's operations;
• prevailing commodity prices and exchange rates and the ability of Pembina to maintain current credit ratings;
• the availability of capital to fund future capital requirements relating to existing assets and projects, including but not limited to future capital expenditures relating to expansion, upgrades and maintenance shutdowns;
• future operating costs;
• geotechnical and integrity costs;
• in respect of the proposed Cornerstone Pipeline system and its estimated in-service date: that Statoil sanctions the oil sands projects that the pipeline will support; that commercial agreements can be reached in respect of construction of, and transportation on, the pipeline; that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner; that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of the pipeline; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;
• in respect of the proposed Musreau II facility, Saturn I and II facilities and the Resthaven facility and their estimated in-service dates: that all required regulatory and environmental approvals can be obtained on the necessary terms in a timely manner, that counterparties will comply with contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts or the completion of such facilities; that such facilities will be fully supported by long-term firm service agreements accounting for the entire designed throughput at such facilities at the time of such facilities' completion; that there are no unforeseen construction costs related to the facilities; and that there are no unforeseen material costs relating to the facilities which are not recoverable from customers;
• in respect of the expansion of NGL throughput capacity on the Peace/Northern NGL System and the crude throughput capacity on the Peace crude system (in respect of the Phase I and II NGL and LVP expansions) 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 expansion of the Redwater fractionator (RFS II): that Pembina will receive regulatory approval; counterparties will comply with such contracts in a timely manner; that there are no unforeseen events preventing the performance of contracts by Pembina; that there are no unforeseen construction costs; and that there are no unforeseen material costs relating to the proposed fractionators that are not recoverable from customers;
• in respect of other developments, expansions and capital expenditures planned, including the proposed expansion of a number of existing truck terminals and construction of new full-service terminals, the expectation of additional NGL and crude volumes being transported on the conventional pipelines, the installation of the remaining pump station on the Mitsue pipeline, the development of fee-for-service storage facilities at Redwater 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, 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 relationships and agreements;
• the strength and operations of the oil and natural gas production industry and related commodity prices;
• non-performance or default by counterparties to agreements which Pembina or one or more of its affiliates has entered into in respect of its business;
• actions by governmental or regulatory authorities including changes in tax laws and treatment, changes in royalty rates or increased environmental regulation;
• fluctuations in operating results;
• adverse general economic and market conditions in Canada, North America and elsewhere, including changes in interest rates, foreign currency exchange rates and commodity prices;
• the failure to realize the anticipated benefits of the Acquisition;
• the failure to complete remaining integration of the businesses of Pembina and Provident; and
• the other factors discussed under "Risk Factors" in Pembina's AIF for the year ended December 31, 2012. Pembina's MD&A and AIF are available at www.pembina.com and in Canada under Pembina's company profile on www.sedar.com and in the U.S. on the Company's profile at www.sec.gov.

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

CONDENSED CONSOLIDATED INTERIM STATEMENT OF FINANCIAL POSITION
(unaudited)

($ millions)		Note	June 30 2013	December 31 2012
Assets
Current assets
	Cash and cash equivalents		9.8	27.3
	Trade receivables and other		375.6	331.7
	Derivative financial instruments	11	4.9	7.6
	Inventory		107.2	108.1
			497.5	474.7
Non-current assets
	Property, plant and equipment	5	5,277.0	5,014.5
	Intangible assets and goodwill		2,590.2	2,622.7
	Investments in equity accounted investees		164.7	161.2
	Derivative financial instruments	11	0.7	0.3
	Other receivables			3.1
	Deferred tax assets		14.8	7.7
			8,047.4	7,809.5
Total Assets			8,544.9	8,284.2
Liabilities and Shareholders' Equity
Current liabilities
	Trade payables and accrued liabilities		408.0	344.7
	Dividends payable		41.8	39.6
	Loans and borrowings	6	261.4	11.7
	Derivative financial instruments	11	10.5	15.9
			721.7	411.9
Non-current liabilities
	Loans and borrowings	6	1,462.2	1,932.8
	Convertible debentures		611.3	610.0
	Derivative financial instruments	11	71.6	51.8
	Employee benefits		28.2	28.6
	Share-based payments		9.7	17.2
	Deferred revenue		4.3	3.1
	Provisions	7	307.6	361.2
	Deferred tax liabilities		640.9	592.2
			3,135.8	3,596.9
Total Liabilities			3,857.5	4,008.8
Shareholders' Equity
Equity attributable to shareholders of the Company:
	Share capital	8	5,797.7	5,324.0
	Deficit		(1,089.5)	(1,027.7)
	Accumulated other comprehensive income		(26.1)	(26.1)
			4,682.1	4,270.2
Non-controlling interest			5.3	5.2
Total Equity			4,687.4	4,275.4
Total Liabilities and Shareholders' Equity			8,544.9	8,284.2

See accompanying notes to the condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME
(unaudited)

			3 Months Ended June 30		6 Months Ended June 30
($ millions, except per share amounts)		Note	2013	2012	2013	2012
Revenue			1,175.0	870.9	2,423.5	1,346.4
Cost of sales			1,003.7	762.1	2,056.3	1,131.3
Gain on commodity-related derivative financial instruments		11	5.5	52.4	13.4	48.6
Gross profit			176.8	161.2	380.6	263.7
	General and administrative		26.2	25.8	58.8	43.4
	Acquisition-related and other expense		0.6	0.5		22.6
			26.8	26.3	58.8	66.0
Results from operating activities			150.0	134.9	321.8	197.7
	Finance income		(7.4)	(11.1)	(8.9)	(11.4)
	Finance costs		31.8	37.9	84.1	57.7
	Net finance costs	9	24.4	26.8	75.2	46.3
Earnings before income tax and equity accounted investees			125.6	108.1	246.6	151.4
	Share of loss of investments in equity accounted investees, net   of tax		0.4	0.6	0.7	0.4
	Current tax expense (benefit)		8.3	(0.6)	12.5	(0.6)
	Deferred tax expense		23.1	27.7	49.1	38.6
	Income tax expense		31.4	27.1	61.6	38.0
Earnings and total comprehensive income for the period			93.8	80.4	184.3	113.0
Earnings and total comprehensive income (loss) attributable to:
	Shareholders of the Company		93.9	80.4	184.2	113.0
	Non-controlling interest		(0.1)		0.1
			93.8	80.4	184.3	113.0
Basic and diluted earnings per share attributable to shareholders   of the Company (dollars)			0.30	0.28	0.61	0.50

See accompanying notes to the condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY
(unaudited)

			Attributable to Shareholders of the Company
($ millions)		Note	Share       Capital	Deficit	Accumulated Other Comprehensive Income	Total	Non- controlling Interest	Total Equity
December 31, 2012			5,324.0	(1,027.7)	(26.1)	4,270.2	5.2	4,275.4
Earnings and total comprehensive income   for period				184.2		184.2	0.1	184.3
Transactions with shareholders of the   Company
	Share-based payment transactions	8	6.3			6.3		6.3
	Dividends declared	8		(246.0)		(246.0)		(246.0)
	Common shares issued, net of issue costs	8	334.6			334.6		334.6
	Dividend reinvestment plan	8	137.5			137.5		137.5
	Debenture conversions and other	8	(4.7)			(4.7)		(4.7)
Total transactions with shareholders of   the Company			473.7	(246.0)		227.7		227.7
June 30, 2013			5,797.7	(1,089.5)	(26.1)	4,682.1	5.3	4,687.4
December 31, 2011			1,811.7	(834.9)	(15.2)	961.6		961.6
Earnings and total comprehensive income   for period				113.0		113.0		113.0
Transactions with shareholders of the   Company
	Share-based payment transactions		3.5			3.5		3.5
	Debenture conversions and other		0.3			0.3		0.3
	Dividends declared			(181.9)		(181.9)		(181.9)
	Common shares issued on acquisition		3,284.0			3,284.0		3,284.0
	Dividend reinvestment plan		85.0			85.0		85.0
Total transactions with shareholders of   the Company			3,372.8	(181.9)		3,190.9		3,190.9
Non-controlling interest assumed on   acquisition							5.1	5.1
June 30, 2012			5,184.5	(903.8)	(15.2)	4,265.5	5.1	4,270.6

See accompanying notes to the condensed consolidated interim financial statements

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CASH FLOWS
(unaudited)

			3 Months Ended June 30		6 Months Ended June 30
($ millions)		Note	2013	2012	2013	2012
Cash provided by (used in):
Operating activities:
Earnings for the period			93.8	80.4	184.3	113.0
Adjustments for:
	Depreciation and amortization		34.8	54.2	77.9	76.7
	Unrealized gain on commodity-related derivative financial   instruments	11	(1.4)	(64.8)	(7.2)	(61.3)
	Net finance costs	9	24.4	26.8	75.2	46.3
	Share of loss of investments in equity accounted investees, net   of tax		0.4	0.6	0.7	0.4
	Deferred income tax expense		23.1	27.7	49.1	38.6
	Share-based payments expense		5.7	2.7	14.8	6.3
	Employee future benefits expense		2.6	1.9	5.3	3.3
	Other		0.2	(0.1)	0.6	0.5
	Changes in non-cash working capital		(3.7)	(65.1)	17.2	(77.5)
	Payments from equity accounted investees		4.4	3.6	9.2	7.7
	Decommissioning liability expenditures			(1.3)	(0.3)	(2.4)
	Employer future benefit contributions		(3.1)	(2.5)	(6.3)	(5.0)
	Net interest paid		(41.0)	(40.0)	(51.3)	(57.2)
Cash flow from operating activities			140.2	24.1	369.2	89.4
Financing activities:
	Bank borrowings		80.0	200.0	80.0	266.9
	Repayment of loans and borrowings		(176.6)	(57.3)	(501.9)	(60.0)
	Issuance of debt		200.0		200.0
	Issuance of common shares				345.2
	Common share issue costs		(0.3)		(14.1)
	Financing fees		(1.9)	(2.3)	(2.9)	(5.1)
	Exercise of stock options		2.5	1.6	5.1	2.6
	Dividends paid (net of shares issued under the Dividend   reinvestment plan)		(54.2)	(42.3)	(106.3)	(79.9)
Cash flow from financing activities			49.5	99.7	5.1	124.5
Investing activities:
	Capital expenditures		(222.7)	(136.6)	(359.8)	(186.3)
	Changes in non-cash investing working capital and other		(0.3)	4.7	(23.9)	(32.8)
	Contributions to equity accounted investees		(3.3)		(8.1)
	Cash acquired on acquisition			8.9		8.9
Cash flow used in investing activities			(226.3)	(123.0)	(391.8)	(210.2)
Change in cash			(36.6)	0.8	(17.5)	3.7
Cash (bank indebtedness), beginning of period			46.4	2.2	27.3	(0.7)
Cash and cash equivalents, end of period			9.8	3.0	9.8	3.0

See accompanying notes to the condensed consolidated interim financial statements

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

1. REPORTING ENTITY

Pembina Pipeline Corporation ("Pembina" or the "Company") is an energy transportation and service provider domiciled in Canada. The condensed consolidated unaudited interim financial statements ("Interim Financial Statements") include the accounts of the Company, its subsidiary companies, partnerships and any interests in associates and jointly controlled entities as at and for the six months ended June 30, 2013. 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, 2012. The interim financial statements were authorized for issue by the Board of Directors on August 9, 2013.

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

The comparative statement of financial position as at December 31, 2012 was reclassified to present deferred tax assets of $7.7 million from one tax jurisdiction separate from deferred tax liabilities of another tax jurisdiction.

2. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies are set out in the December 31, 2012 financial statements. Those policies have been applied consistently to all periods presented in these Interim Financial Statements.

New standards

The following new standards, interpretations, amendments and improvements to existing standards issued by the International Accounting Standard Board or International Financial Reporting Interpretations Committee were adopted as of January 1, 2013 without any material impact to Pembina's Financial Statements: IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of interests in Other Entities, IFRS 13 Fair Value Measurement, and IAS 19 Employee Future Benefits.

3. DETERMINATION OF FAIR VALUES

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

i) Property, plant and equipment

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

ii) Intangible assets

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

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

iii) Derivatives

Fair value of derivatives, with the exception of the redemption liability which is related to the acquisition of the Company's subsidiary, are estimated by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, quoted market prices per share and volatility rates at the period ends.

The redemption liability related to one of the Company's subsidiaries represents a put option, held by the non-controlling interest, to sell the remaining one-third of the business to the Company after the third anniversary of the acquisition date (October 3, 2014). The put price to be paid by the Company for the residual interest upon exercise is based on a multiple of the subsidiary's earnings during the three year period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates (see Note 11 "Financial Instruments and Financial Risk Management").

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

iv) Non-derivative financial assets and liabilities

Fair value, which is determined for disclosure purposes, is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date. In respect of the convertible debentures, the fair value is determined by the market price of the convertible debenture on the reporting date. For finance leases the market rate of interest is determined by reference to similar lease agreements. For disclosure purposes, carrying value is a reasonable approximation for fair value for cash and cash equivalents, trade receivables and other, trade payables and accrued liabilities, finance lease liabilities and dividends payable.

v) Share-based payment transactions

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

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

4. ACQUISITION

On April 2, 2012, Pembina acquired all of the outstanding Provident Energy Ltd. ("Provident") common shares in exchange for 116,535,750 Pembina common shares valued at approximately $3.3 billion (the "Acquisition").

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

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

Revenue generated by the Provident business for the six months ending June 30, 2013, before intersegment eliminations was $945.9 million. Gross profit, before intersegment eliminations, for the same period was $110.7 million.

For more information, please see Note 5 of the Consolidated Financial Statements for the year ended December 31, 2012.

5. PROPERTY, PLANT AND EQUIPMENT

($ millions)	Land and Land Rights	Pipelines	Facilities and Equipment	Linefill and Other	Assets Under Construction	Total
Cost
Balance at December 31, 2012	88.0	2,593.7	2,072.2	506.6	751.8	6,012.3
Additions	0.2	0.9	3.6	5.3	346.8	356.8
Change in decommissioning provision		(15.5)	(21.8)			(37.3)
Capitalized interest					14.1	14.1
Transfers	9.3	8.3	12.1	1.0	(30.7)
Disposals and other		(0.1)		1.8		1.7
Balance at June 30, 2013	97.5	2,587.3	2,066.1	514.7	1,082.0	6,347.6
Accumulated Depreciation
Balance at December 31, 2012	4.4	776.7	171.9	44.8		997.8
Depreciation	0.1	28.1	32.3	12.2		72.7
Disposals			(0.2)	0.3		0.1
Balance at June 30, 2013	4.5	804.8	204.0	57.3		1,070.6
Carrying amounts
December 31, 2012	83.6	1,817.0	1,900.3	461.8	751.8	5,014.5
June 30, 2013	93.0	1,782.5	1,862.1	457.4	1,082.0	5,277.0

Commitments

At June 30, 2013, the Company had contractual commitments for the acquisition and or construction of property, plant and equipment of $817.8 million (December 31, 2012: $362.8 million).

6. LOANS AND BORROWINGS

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

Carrying value terms and debt repayment schedule

Terms and conditions of outstanding loans were as follows:

($ millions)				Carrying amount(3)
	Available facilities at June 30, 2013	Nominal interest rate	Year of maturity	June 30, 2013	December 31, 2012
Operating facility(1)	30.0	prime + 0.45 or BA(2) + 1.45	2014
Revolving unsecured credit facility	1,500.0	prime + 0.45 or BA(2) + 1.45	2018	100.3	520.7
Senior unsecured notes - Series A	175.0	5.99	2014	174.8	174.7
Senior unsecured notes - Series C	200.0	5.58	2021	197.1	197.0
Senior unsecured notes - Series D	267.0	5.91	2019	265.7	265.6
Senior unsecured term facility	75.0	6.16	2014	74.9	74.8
Senior unsecured medium-term notes 1	250.0	4.89	2021	248.8	248.7
Senior unsecured medium-term notes 2	450.0	3.77	2022	447.8	447.9
Senior unsecured medium-term notes 3	200.0	4.75	2043	198.1
Subsidiary debt	8.8	5.04	2014	8.8	9.3
Finance lease liabilities				7.3	5.8
Total interest bearing liabilities	3,155.8			1,723.6	1,944.5
Less current portion				(261.4)	(11.7)
Total non-current				1,462.2	1,932.8

(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.

Pembina's $1.5 billion revolving unsecured credit facility was extended by one year from March 2017 to March 2018 and the $30 million operating facility was also extended by one year from July 2013 to July 2014.

7. PROVISIONS

($ millions)						Total
Balance at December 31, 2012(1)						361.7
Unwinding of discount rate						4.2
Decommissioning liabilities settled during the period						(0.3)
Change in estimates and other						(57.8)
Total						307.8
Less current portion (included in accrued liabilities)						(0.2)
Balance at June 30, 2013						307.6

(1)	Includes current portion of $0.5 million (included in accrued liabilities).

The Company applied a 2 percent inflation rate per annum (December 31, 2012: 2 percent) and a risk-free rate of 2.89 percent (December 31, 2012: 2.36 percent) to calculate the present value of the decommissioning provision. The remeasured decommissioning provision decreased property, plant and equipment and decommissioning provision liability. Of the re-measurement reduction of the decommissioning provision, $20.9 million was in excess of the carrying amount of the related asset and is recognized as a credit to depreciation expense.

8. SHARE CAPITAL

($ millions, except share amounts)	Number of Common Shares	Share Capital
Balance December 31, 2012	293,226,473	5,324.0
Common shares issued, net of issue costs	11,206,750	334.6
Share-based payment transactions	291,442	6.3
Dividend reinvestment plan	4,675,500	137.5
Debenture conversions and other	49,897	(4.7)
Balance June 30, 2013	309,450,062(1)	5,797.7

(1)

Weighted average number of common shares outstanding for the three months ended June 30, 2013 is 308.3 million (June 30, 2012: 285.3 million). On a fully diluted basis, the weighted average number of common shares outstanding for the three months ended June 30, 2013 is 309.2 million (June 30, 2012: 286.0 million). Weighted average number of common shares outstanding for the six months ended June 30, 2013 is 302.1 million (June 30, 2012: 226.8 million). On a fully diluted basis, the weighted average number of common shares outstanding for the six months ended June 30, 2013 is 303.0 million (June 30, 2012: 227.5 million).

On March 21, 2013, Pembina closed a bought deal offering of 11,206,750 shares at a price of $30.80 per share for aggregate gross proceeds of $345.2 million ($334.6 million, net of issue costs).

Dividends

The following dividends were declared by the Company:

6 Months Ended June 30 ($ millions, except per share amounts)					2013	2012
$0.81 per qualifying common share (2012: $0.80)					246.0	181.9

On July 11, 2013, Pembina announced that the Board of Directors declared a dividend for July of $0.135 per qualifying common share ($1.62 annualized) in the total amount of $41.9 million.

9. NET FINANCE COSTS

		3 Months Ended June 30		6 Months Ended June 30
($ millions)		2013	2012	2013	2012
Interest income from:
	Related parties				(0.3)
	Bank deposits and other	(4.0)	(0.3)	(4.6)	(0.3)
Interest expense on financial liabilities measured at amortized cost:
	Loans and borrowings	12.9	18.1	29.9	33.5
	Convertible debentures	10.6	10.6	21.2	15.2
	Finance leases	0.4	0.1	0.7	0.2
	Unwinding of discount	2.1	3.3	4.2	5.8
(Gain) loss in fair value of non-commodity-related derivative financial   instruments		(3.4)	5.5	(4.1)	2.7
Loss (gain) on revaluation of conversion feature on convertible debentures		5.7	(10.8)	28.1	(10.8)
Foreign exchange (gains) loss		0.1	0.3	(0.2)	0.3
Net finance costs		24.4	26.8	75.2	46.3

10. OPERATING SEGMENTS

3 Months Ended June 30, 2013 ($ millions)			Conventional Pipelines(1)	Oil Sands & Heavy Oil	Gas Services	Midstream(2)	Corporate & Intersegment Eliminations	Total
Revenue:
		Pipeline transportation	101.5	50.9			(12.0)	140.4
		Midstream services				1,006.0		1,006.0
		Gas Services			28.6			28.6
Total revenue			101.5	50.9	28.6	1,006.0	(12.0)	1,175.0
		Operations	37.7	18.3	11.1	24.7	(0.7)	91.1
		Cost of goods sold(3)				892.2	(12.0)	880.2
		Realized gain (loss) on commodity-related   derivative financial instruments	1.8			2.3		4.1
Operating margin			65.6	32.6	17.5	91.4	0.7	207.8
		Depreciation and amortization (operational)	(2.1)	4.9	3.6	26.0		32.4
		Unrealized gain (loss) on commodity-related   derivative financial instruments	1.4					1.4
Gross profit			69.1	27.7	13.9	65.4	0.7	176.8
		Depreciation included in general and   administrative					2.3	2.3
		Other general and administrative	1.7	1.1	1.4	5.3	14.4	23.9
		Acquisition-related and other expenses (income)	0.6	(0.1)			0.1	0.6
Results from operating activities			66.8	26.7	12.5	60.1	(16.1)	150.0
Net finance costs			1.0	0.3	0.2	(2.0)	24.9	24.4
Earnings (loss) before tax and equity accounted   investees			65.8	26.4	12.3	62.1	(41.0)	125.6
Share of loss of investments in equity accounted   investees, net of tax						0.4		0.4
Capital expenditures			58.9	12.5	83.8	65.9	1.6	222.7
3 Months Ended June 30, 2012 ($ millions)
Revenue:
		Pipeline transportation	78.4	39.4			(6.9)	110.9
		Midstream services				737.8		737.8
		Gas Services			22.2			22.2
Total revenue			78.4	39.4	22.2	737.8	(6.9)	870.9
		Operations	30.0	11.6	7.1	19.7	(0.7)	67.7
		Cost of goods sold(3)				648.8	(6.9)	641.9
		Realized gain (loss) on commodity-related   derivative financial instruments	(0.9)			(11.5)		(12.4)
Operating margin			47.5	27.8	15.1	57.8	0.7	148.9
		Depreciation and amortization (operational)	12.2	4.9	4.3	31.1		52.5
		Unrealized gain (loss) on commodity-related   derivative financial instruments	0.3			64.5		64.8
Gross profit			35.6	22.9	10.8	91.2	0.7	161.2
		Depreciation included in general and   administrative					1.7	1.7
		Other general and administrative	2.2	0.9	1.5	5.5	14.0	24.1
		Acquisition-related and other expenses (income)	(0.3)	0.5		0.1	0.2	0.5
Results from operating activities			33.7	21.5	9.3	85.6	(15.2)	134.9
Net finance costs			1.8	0.5	2.0	4.2	18.3	26.8
Earnings (loss) before tax and equity accounted   investees			31.9	21.0	7.3	81.4	(33.5)	108.1
Share of loss of investments in equity accounted   investees, net of tax						0.6		0.6
Capital expenditures			55.6		23.5	55.2	2.3	136.6

(1)	3.7 percent of Conventional Pipelines revenue is under regulated tolling arrangements (4.5 percent for quarter ending June 30, 2012).
(2)	Midstream services revenue includes $17.7 million associated with U.S. midstream sales ($28.7 million for quarter ending June 30, 2012).
(3)	Including product purchases.

6 Months Ended June 30, 2013 ($ millions)		Conventional Pipelines(1)	Oil Sands & Heavy Oil	Gas Services	Midstream(2)	Corporate & Intersegment Eliminations	Total
Revenue:
	Pipeline transportation	197.3	94.3			(25.1)	266.5
	Midstream services				2,100.9		2,100.9
	Gas Services			56.1			56.1
Total revenue		197.3	94.3	56.1	2,100.9	(25.1)	2,423.5
	Operations	73.0	30.2	20.0	46.5	(1.4)	168.3
	Cost of goods sold(3)				1,838.9	(25.1)	1,813.8
	Realized gain (loss) on commodity-related   derivative financial instruments	1.8			4.4		6.2
Operating margin		126.1	64.1	36.1	219.9	1.4	447.6
	Depreciation and amortization (operational)	(0.5)	9.8	7.2	57.7		74.2
	Unrealized gain (loss) on commodity-related   derivative financial instruments	2.3			4.9		7.2
Gross profit		128.9	54.3	28.9	167.1	1.4	380.6
	Depreciation included in general and   administrative					3.6	3.6
	Other general and administrative	4.2	2.1	2.7	11.7	34.5	55.2
	Acquisition-related and other expenses (income)	0.6	(0.1)		0.1	(0.6)
Results from operating activities		124.1	52.3	26.2	155.3	(36.1)	321.8
Net finance costs		2.0	0.6	0.3	(1.9)	74.2	75.2
Earnings (loss) before tax and equity accounted   investees		122.1	51.7	25.9	157.2	(110.3)	246.6
Share of loss of investments in equity accounted   investees, net of tax					0.7		0.7
Capital expenditures		120.3	24.6	122.3	89.8	2.8	359.8
6 Months Ended June 30, 2012 ($ millions)
Revenue:
	Pipeline transportation	160.6	82.5			(6.9)	236.2
	Midstream services				1,068.9		1,068.9
	Gas Services			41.3			41.3
Total revenue		160.6	82.5	41.3	1,068.9	(6.9)	1,346.4
	Operations	57.5	24.6	13.2	22.1	(1.3)	116.1
	Cost of goods sold(3)				947.9	(6.9)	941.0
	Realized gain (loss) on commodity-related   derivative financial instruments	(1.2)			(11.5)		(12.7)
Operating margin		101.9	57.9	28.1	87.4	1.3	276.6
	Depreciation and amortization (operational)	24.1	9.8	7.5	32.8		74.2
	Unrealized gain (loss) on commodity-related   derivative financial instruments	(2.7)			64.0		61.3
Gross profit		75.1	48.1	20.6	118.6	1.3	263.7
	Depreciation included in general and   administrative					2.5	2.5
	Other general and administrative	3.1	1.9	2.0	6.8	27.1	40.9
	Acquisition-related and other expenses (income)	0.9	0.4		0.1	21.2	22.6
Results from operating activities		71.1	45.8	18.6	111.7	(49.5)	197.7
Net finance costs		3.4	1.0	2.1	4.2	35.6	46.3
Earnings (loss) before tax and equity accounted   investees		67.7	44.8	16.5	107.5	(85.1)	151.4
Share of loss of investments in equity accounted   investees, net of tax					0.4		0.4
Capital expenditures		64.5	6.0	55.8	55.9	4.1	186.3

(1)	4.6 percent of Conventional Pipelines revenue is under regulated tolling arrangements (4.5 percent for quarter ending June 30, 2012).
(2)	Midstream services revenue includes $68.2 million associated with U.S. midstream sales ($28.7 million for six months ending June 30, 2012).
(3)	Including product purchases.

11. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT

Fair values

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

	June 30, 2013		December 31, 2012
($ millions)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Financial assets carried at fair value
Derivative financial instruments	5.6	5.6	7.9	7.9
Financial liabilities carried at fair value
Derivative financial instruments	82.1	82.1	67.7	67.7
Financial liabilities carried at amortized cost
Loans and borrowings	1,723.6	1,850.9	1,944.5	2,089.7
Convertible debentures	611.3(1)	770.2	610.0(1)	725.0
	2,334.9	2,621.1	2,554.5	2,814.7

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

The basis for determining fair values is disclosed in Note 3.

Fair value hierarchy

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

Level 1: Unadjusted quoted prices are available in active markets for identical assets or liabilities as the reporting date. Pembina uses Level 1 inputs for the disclosed fair value measurements of the convertible debentures.

Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices). Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices. Pembina obtains quoted market prices for commodities, future power contracts, interest rates and foreign exchange rates from information sources including banks, Bloomberg Terminals and Natural Gas Exchange (NGX). With the exception of one item described under Level 3, all of Pembina's financial instruments carried at fair value are valued using Level 2 inputs.

Level 3: Valuations in this level require the most significant judgments and consist primarily of unobservable or non-market based inputs. Level 3 inputs include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value. The redemption liability related to acquisition of subsidiary is classified as a Level 3 instrument, as the fair value is determined by using inputs that are not based on observable market data. The liability represents a put option, held by the non-controlling interest of Three Star Trucking Ltd. ("Three Star"), to sell the remaining one-third of the business to Pembina after the third anniversary of the original acquisition date (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 three year period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates. These estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.

Financial instruments classified as Level 3

($ millions)						2013
Redemption liability, January 1, 2013						5.3
Gain on revaluation						(1.1)
Redemption liability, June 30, 2013						4.2

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

($ millions)		June 30 2013	December 31 2012
Frac spread related		1.1	(3.1)
Product margin		(2.0)	(1.1)
Corporate
	Power	(3.2)	(7.1)
	Interest rate	(8.9)	(14.3)
	Foreign exchange	(1.7)	0.7
Other derivative financial instruments
	Conversion feature of convertible debentures	(57.6)	(29.6)
	Redemption liability related to acquisition of subsidiary	(4.2)	(5.3)
Net derivative financial instruments liability		(76.5)	(59.8)

Commodity-Related Derivative Financial Instruments	3 Months Ended       June 30		6 Months Ended       June 30
($ millions)	2013	2012	2013	2012
Realized gain (loss) on commodity-related derivative financial instruments
Frac spread related	0.4	(7.0)	1.0	(7.0)
Product margin	0.6	(3.9)	2.1	(3.9)
Power	3.1	(1.5)	3.1	(1.8)
Realized gain (loss) on commodity-related derivative financial instruments	4.1	(12.4)	6.2	(12.7)
Unrealized gain on commodity-related derivative financial instruments	1.4	64.8	7.2	61.3
Gain on commodity-related derivative financial instruments	5.5	52.4	13.4	48.6

For non-commodity-related derivative financial instruments see Note 9, Net Finance Costs.

Sensitivity analysis

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

As at June 30, 2013 ($ millions)			+ Change	- Change
Frac spread related
	Natural gas	(AECO +/- $1.00 per GJ)	4.3	(4.3)
	NGL (includes propane, butane)	(Belvieu +/- U.S. $0.10 per gal)	(1.0)	1.0
	Foreign exchange (U.S.$ vs. Cdn$)	(FX rate +/- $0.05)	(1.8)	1.8
Product margin
	Crude oil	(WTI +/- $5.00 per bbl)	(3.8)	3.8
	NGL (includes propane, butane and condensate)	(Belvieu +/- U.S. $0.10 per gal)	0.3	(0.3)
Corporate
	Interest rate	(Rate +/- 50 basis points)	2.9	(2.9)
	Power	(AESO +/- $5.00 per MW/h)	4.6	(4.6)
Conversion feature of convertible debentures		(Pembina share price +/- $0.50 per share)	(3.1)	3.1

12. SUBSEQUENT EVENTS

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

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

Pembina announced on August 9, 2013, that it increased its monthly dividend rate by 3.7 percent from $0.135 per common share per month (or $1.62 annualized) to $0.14 per common share per month (or $1.68 annualized) effective as of the August 25, 2013 record date, payable September 13, 2013.

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
Preferred shares: PPL.PR.A
Convertible debentures: PPL.DB.C, PPL,DB.E, PPL.DB.F

NYSE listing symbol for:
Common shares: PBA

 

SOURCE: Pembina Pipeline Corporation