Pembina releases first consolidated results following acquisition
of Provident Energy Ltd.; continues building its fee-for-service
business All financial figures are in Canadian dollars unless noted
otherwise. This report contains forward-looking statements and
information that are based on Pembina Pipeline Corporation's
current expectations, estimates, projections and assumptions in
light of its experience and its perception of historical trends.
Actual results may differ materially from those expressed or
implied by these forward-looking statements. Please see"
Forward-Looking Statements & Information" for more details.
This report also refers to financial measures that are not defined
by Canadian Generally Accepted Accounting Principles ("GAAP"). For
more information about the measures which are not defined by GAAP,
see "Non-GAAP Measures." CALGARY, Aug. 9, 2012 /CNW/ - On April 2,
2012 Pembina Pipeline Corporation ("Pembina" or the "Company")
completed its acquisition of Provident Energy Ltd. ("Provident")
(the "Arrangement"). The amounts disclosed herein for the three and
six month periods ending June 30, 2012 reflect results of the
post-Arrangement Pembina from April 2, 2012 together with results
of legacy Pembina alone, excluding Provident, from January 1
through April 1, 2012. The comparative figures reflect solely the
2011 results of legacy Pembina. For further information with
respect to the acquisition transaction, please refer to Note 3 of
the unaudited interim condensed consolidated financial statements
for the period ended June 30, 2012. Financial & Operating
Overview (unaudited) ($ millions, except 3 Months Ended 6 Months
Ended where noted) June 30 June 30 2012 2011 2012 2011 Revenue
870.9 512.4 1,346.4 907.3 Operating margin(1) 148.9 110.3 276.6
207.6 Gross profit 161.2 97.8 263.7 180.6 Earnings for the period
80.4 48.0 113.0 90.5 Earnings per share - basic and diluted
(dollars) 0.28 0.29 0.50 0.54 Adjusted EBITDA(1) 125.9 103.3 237.3
190.5 Cash flow from operating activities 24.1 49.5 89.4 124.0
Adjusted cash flow from operating activities(1) 89.5 81.8 188.3
157.8 Adjusted cash flow from operating activities per share (1)
0.31 0.49 0.83 0.94 Dividends declared 116.2 65.3 181.9 130.4
Dividends per common share (dollars) 0.41 0.39 0.80 0.78
((1) )Refer to "Non-GAAP Measures." Second Quarter Highlights
-- Consolidated operating margin during the second quarter
increased to $148.9 million compared to $110.3 million during the
same period of the prior year. Year-to-date, operating margin
totaled $276.6 million compared to $207.6 million in the first half
of 2011. Pembina's overall results for the quarter reflect
Pembina's legacy businesses combined with those acquired through
the Arrangement, which are reported as part of the Company's
Midstream business. Operating margin is a non-GAAP measure; see
"Non-GAAP Measures". -- Pembina generated $47.5 million in
operating margin from Conventional Pipelines, $27.8 million from
Oil Sands & Heavy Oil and $15.0 million from Gas Services. The
Midstream business saw a significant increase to $58.0 million
which includes operating margin generated by the assets acquired
through the Arrangement. Higher results from Pembina's legacy crude
oil midstream business were somewhat tempered by a weak propane
pricing environment which impacted the newly acquired NGL midstream
business. Industry propane inventory levels remain high due to
decreased demand for the commodity as a result of the relatively
warm winter across North America. -- The Company's earnings were
$80.4 million ($0.28 per share) during the second quarter of 2012
compared to $48.0 million ($0.29 per share) during the second
quarter of 2011. Earnings were $113.0 million ($0.50 per share)
during the first half of 2012 compared to $90.5 million ($0.54 per
share) during the same period of the prior year. Earnings for the
three and six month periods ended June 30, 2012 increased as a
result of the Arrangement and unrealized gains on commodity-related
derivative financial instruments. Earnings per share decreased
primarily due to the 116.5 million shares issued to complete the
Arrangement. -- Pembina generated adjusted EBITDA of $125.9 million
during the second quarter of 2012 compared to $103.3 million during
the second quarter of 2011 (adjusted EBITDA is a Non-GAAP measure;
see "Non-GAAP Measures"). Adjusted EBITDA for the six month period
ended June 30, 2012 was $237.3 million compared to $190.5 million
for the same period in 2011. The increase in quarterly and
year-to-date adjusted EBITDA was due to strong results from each of
Pembina's legacy businesses, new assets and services having been
brought on-stream and the growth in Pembina's operations since
completion of the Arrangement. -- Cash flow from operating
activities was $24.1 million ($0.08 per share) during the second
quarter of 2012 compared to $49.5 million ($0.30 per share) during
the second quarter of 2011. For the six months ended June 30, 2012,
cash flow from operating activities was $89.4 million ($0.39 per
share) compared to $124.0 million ($0.74 per share) during the same
period last year. The decrease in cash flow from operating
activities during the 2012 periods is primarily due to
acquisition-related expenses, higher interest expenses and an
increase in working capital reflecting a seasonal inventory build.
-- Adjusted cash flow from operating activities was $89.5 million
($0.31 per share) during the second quarter of 2012 compared to
$81.8 million ($0.49 share) during the second quarter of 2011
(adjusted cash flow from operating activities is a Non-GAAP
measure; see "Non-GAAP Measures"). Adjusted cash flow from
operating activities was $188.3 million ($0.83 per share) during
the first half of 2012 compared to $157.8 million ($0.94 share)
during the same period of last year. Adjusted cash flow from
operating activities per share decreased primarily due to the 116.5
million shares issued to complete the Arrangement. Growth and
Operational Update Following the acquisition of Provident, Pembina
is now one of Canada's largest integrated energy infrastructure
companies. The Company is focused on integrating the acquired
assets to realize efficiencies and revenue synergies in the future.
Pembina is also pursuing the largest capital spending program in
its history. Progress on Pembina's major projects includes:
Conventional Pipelines: -- Work to refurbish the Calmar booster
station was completed, which has expanded the capacity of Pembina's
Drayton Valley mainline (which serves the Cardium play) from 145
mbpd to 195 mbpd; -- A re-contracting initiative on the Northern
NGL pipeline is complete, and considerable progress on this project
was made. The first portion of the expansion is expected to be
in-service in the fourth quarter of 2012 and is expected to add
approximately 17 mbpd of additional NGL capacity, with an
additional 35 mbpd expected to be on stream by the fourth quarter
of 2013; -- The British Columbia Utilities Commission approved an
application on Pembina's Western System, which will allow Pembina
to fully recover anticipated geotechnical and integrity costs
associated with that pipeline, and extend customer arrangements and
the useful life of the asset. Gas Services: -- Site construction on
both the Saturn and Resthaven facilities is underway with
anticipated in-service dates of fourth quarter 2013 and first
quarter 2014, respectively. Once complete, the facilities will add
an additional 330 MMcf/d of enhanced liquids extraction capability;
-- A long-term arrangement was completed for the remaining 50
MMcf/d of spare capacity at Saturn, bringing the total contracted
capacity to 100 percent; -- The 50 MMcf/d Musreau shallow cut
expansion is being commissioned with start-up expected in August
2012. Midstream: -- A joint venture agreement was entered into with
a third party to develop a new full-service terminal (50 percent
interest net to Pembina) at Judy Creek to serve the production
expansion in the Beaverhill Lake and Swan Hills formations with an
anticipated in-service date of the first quarter of 2013; --
Development of seven fee-for-service cavern storage facilities
continued at Pembina's Redwater site, the first of which is
expected to come into service in the fourth quarter of 2012; -- An
expansion to the Redwater fractionator by approximately 8,000 bpd
was progressed, which is expected to be in-service in the fourth
quarter of 2012; -- Preliminary engineering work for a new 70,000
bpd C2+ fractionator at Pembina's Redwater facility was advanced
and the Company is currently soliciting customer support for the
project; -- An agreement with a third party producer was signed to
tie in its production of up to 60 MMcf/d to the Younger plant by
the first quarter of 2013. "This was a very productive quarter for
Pembina; we made significant progress to bring our two teams
together following our acquisition of Provident while maintaining
steady performance across our operations," said Bob Michaleski,
Pembina's Chief Executive Officer. "As well, we listed our shares
on the New York Stock Exchange and have made substantial strides to
integrate our newly acquired operations with those in our existing
businesses. Pembina will continue to focus on integration-related
activities and enhancing the value from the newly acquired assets,
including growing the 'fee-for-service' component across our
businesses. While we did have to deal with a lower propane price
environment, we're confident that the depth and breadth of service
we are now able to offer to our customers is a key differentiator
that positions Pembina for significant growth in the years to
come." Hedging Information Pembina has posted updated hedging
information on its website, www.pembina.com, under "Investor Centre
- Hedging". Conference Call & Webcast Pembina will host a
conference call Friday, August 10, at 9:00 a.m. MT (11:00 a.m. ET)
to discuss details related to the second quarter of 2012. The
conference call dial-in numbers for Canada and the U.S. are
647-427-7450 or 888-231-8191. A live webcast of the conference call
can be accessed on Pembina's website under "Investor Centre -
Presentation & Events," or by entering
http://event.on24.com/r.htm?e=489792&s=1&k=8609836C574E1C73A84090F0CE92BB87
in your web browser. MANAGEMENT'S DISCUSSION AND ANALYSIS The
following management's discussion and analysis ("MD&A") of the
financial and operating results of Pembina Pipeline Corporation
("Pembina" or the "Company") is dated August 9, 2012 and is
supplementary to, and should be read in conjunction with, Pembina's
condensed consolidated unaudited interim financial statements for
the period ended June 30, 2012 ("Interim Financial Statements") as
well as Pembina's consolidated audited annual financial statements
and MD&A for the year ended December 31, 2011 (the
"Consolidated Financial Statements"). All dollar amounts contained
in this MD&A are expressed in Canadian dollars unless otherwise
noted. Management is responsible for preparing the MD&A. This
MD&A has been reviewed and recommended by the Audit Committee
of Pembina's Board of Directors and approved by its Board of
Directors. This MD&A contains forward-looking statements (see
"Forward-Looking Statements & Information") and refers to
financial measures that are not defined by Canadian Generally
Accepted Accounting Principles ("GAAP"). For more information about
the measures which are not defined by GAAP, see "Non-GAAP
Measures." Acquisition of Provident Energy Ltd. ("Provident") On
April 2, 2012, Pembina completed its acquisition of Provident by
way of a plan of arrangement pursuant to Section 193 of the
Business Corporations Act (Alberta) (the "Arrangement"). Provident
shareholders received 0.425 of a Pembina share for each Provident
share held. In addition, Pembina has assumed all of the rights and
obligations of Provident relating to the 5.75 percent convertible
unsecured subordinated debentures of Provident maturing December
31, 2017 ("Series E Debentures") , and the 5.75 percent convertible
unsecured subordinated debentures of Provident maturing December
31, 2018 ("Series F Debentures") . On closing of the Arrangement,
Pembina listed its common shares, including those issued under the
Arrangement, on the NYSE under the symbol "PBA". Pursuant to the
Arrangement, Provident amalgamated with a wholly-owned subsidiary
of Pembina and was continued under the name "Pembina NGL
Corporation". The consolidated financial statements contained in
this MD&A and the Interim Financial Statements include
Pembina's post-Arrangement results from April 2, 2012. As such, the
amounts disclosed herein for the three and six month periods ending
June 30, 2012 reflect results of the post-Arrangement Pembina from
April 2, 2012 together with results of legacy Pembina alone,
excluding Provident, from January 1 through April 1, 2012. The
comparative figures reflect solely the 2011 results of legacy
Pembina. The results of the business acquired through the
Arrangement are reported as part of the Company's Midstream
business. For further information with respect to the Arrangement,
please refer to Note 3 to the Interim Financial Statements. About
Pembina Calgary-based Pembina Pipeline Corporation is a leading
transportation and midstream service provider with nearly 60 years
serving North America's energy industry. Pembina owns and operates:
pipelines that transport conventional crude oil and natural gas
liquids produced in western Canada; oil sands and heavy oil
pipelines; gas gathering and processing facilities; and, an oil and
natural gas liquids infrastructure and logistics business. With
facilities strategically located in western Canada and in natural
gas liquids markets in eastern Canada and the U.S., Pembina also
offers a full spectrum of midstream and marketing services that
span across its operations. Pembina's integrated assets and
commercial operations enable it to offer services needed by the
energy sector along each step of the hydrocarbon value chain.
Pembina is a trusted member of the communities in which it operates
and is committed to generating value for its investors through
operational excellence: running its businesses in a safe,
environmentally responsible manner that is respectful of community
stakeholders. Strategy Pembina's goal is to provide highly
competitive and reliable returns to investors through monthly
dividends while enhancing the long-term value of its common shares.
To achieve this, Pembina's strategy is to: -- Generate value by
providing customers with safe, cost-effective, reliable services.
-- Diversify Pembina's asset base to enhance profitability. A
diverse portfolio provides Pembina with the ability to respond to
market conditions, reduce risk and increase opportunities to
leverage existing businesses. A priority is placed on developing
businesses that support Pembina's core competency - operating crude
oil and NGL transportation systems, and gas gathering, processing
and fractionation infrastructure - which allow for expansion,
vertical integration and accretive growth. -- Implement growth
projects and conduct existing operations in a safe and
environmentally responsible manner. Growth is expected to occur
through expansion of existing businesses, additional acquisitions
and the development of new services. Pembina's investment criteria
include pursuing projects or assets that are expected to generate
increased cash flow per share and capture long-life, economic
hydrocarbon reserves. -- Maintain a strong balance sheet through
the application of prudent financial management to all business
decisions. Pembina is structured in four businesses: Conventional
Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream,
which are described in their respective sections of this MD&A.
Common Abbreviations The following is a list of abbreviations that
may be used in this MD&A: Measurement Other bbl barrel AECO
Alberta gas trading price kbbls thousands of AESO Alberta Electric
barrels Systems Operator mmbbls millions of BC British Columbia
barrels bpd barrels per day DRIP Premium Dividend™ and Dividend
Reinvestment Plan mbpd thousands of Frac Fractionation barrels per
day boe barrels of oil IFRS International equivalent Financial
Reporting Standards boe/d barrels of oil NGL Natural gas equivalent
per liquids day mboe thousands of NYMEX New York barrels of oil
Mercantile equivalent Exchange mboe/d thousands of NYSE New York
Stock barrels of oil Exchange equivalent per day MMcf millions of
cubic TET indicates product feet in the Texas Eastern Products
Pipeline at Mont Belvieu, Texas (Non- TET refers to product in a
location at Mont Belvieu other than in the Texas Eastern Products
pipeline) MMcf/d millions of cubic TSX Toronto Stock feet per day
Exchange bcf/d billions of cubic U.S. United States feet per day
MW/h megawatts per USD United States hour dollars GJ gigajoule WCSB
Western Canadian Sedimentary Basin km kilometre WTI West Texas
Intermediate (crude oil benchmark price) Financial & Operating
Overview (unaudited) 3 Months Ended 6 Months Ended June 30 June 30
($ millions, except where noted) 2012 2011 2012 2011 Average
throughput - conventional (mbpd) 433.9 411.4 450.4 400.9 Contracted
capacity - oil sands (mbpd) 870.0 775.0 870.0 775.0 Average
processing volume - gas services (mboe/dnet to Pembina) (1) 47.5
40.9 45.8 40.1 Total NGL sales volume (mbpd) 90.4 90.4(3) Revenue
870.9 512.4 1,346.4 907.3 Operations 67.7 37.6 116.1 82.4 Cost of
goods sold, including product purchases 641.9 364.3 941.0 618.5
Realized gain (loss) on commodity-related derivative financial
instruments (12.4) (0.2) (12.7) 1.2 Operating margin(2) 148.9 110.3
276.6 207.6 Depreciation and amortization included in operations
52.5 15.8 74.2 30.6 Unrealized gain on commodity-related derivative
financial instruments 64.8 3.3 61.3 3.6 Gross profit 161.2 97.8
263.7 180.6 Deduct/(add) General and administrative expenses 25.8
12.8 43.3 27.4 Acquisition-related and other expenses (income) 0.5
(0.6) 22.7 (0.6) Net finance costs 26.7 25.0 46.3 39.3 Share of
loss (profit) of investments in equity accounted investee, net of
tax 0.6 (2.6) 0.4 (4.8) Income tax expense 27.2 15.2 38.0 28.8
Earnings for the period 80.4 48.0 113.0 90.5 Earnings per share -
basic and diluted (dollars) 0.28 0.29 0.50 0.54 Adjusted
earnings(2) 37.4 65.4 102.7 118.1 Adjusted earnings per share(2)
0.13 0.39 0.45 0.71 Adjusted EBITDA(2) 125.9 103.3 237.3 190.5 Cash
flow from operating activities 24.1 49.5 89.4 124.0 Cash flow from
operating activities per share 0.08 0.30 0.39 0.74 Adjusted cash
flow from operating activities(2) 89.5 81.8 188.3 157.8 Adjusted
cash flow from operating activities per share (2) 0.31 0.49 0.83
0.94 Dividends declared 116.2 65.3 181.9 130.4 Dividends per common
share (dollars) 0.41 0.39 0.80 0.78 Capital expenditures 136.6 78.2
186.3 301.5 Total enterprise value ($ billions)(2) 9.9 5.8 9.9 5.8
Total assets ($ billions) 8.1 3.1 8.1 3.1 (1) Gas Services
processing volumes converted to mboe/d from MMcf/d at a 6:1 ratio.
(2) Refer to "Non-GAAP Measures." (3) Represents per day volumes
since the closing of the Arrangement. Revenue, net of cost of goods
sold, increased approximately 55 percent during the second quarter
of 2012 to $229.0 million compared to $148.1 million in the second
quarter of 2011. Year-to-date revenue, net of cost of goods sold,
in 2012 was $405.4 million, up 40 percent from the same period last
year. Revenue was higher in 2012 than the comparative periods in
2011 primarily due to the addition of results generated by the
assets acquired through the Arrangement, which are reported in the
Company's Midstream business, as well as continued strong
performance in each of Pembina's businesses. Operating expenses
were $67.7 million during the second quarter of 2012 compared to
$37.6 million in the second quarter of 2011. Operating expenses for
the six months ended June 30, 2012 were $116.1 million compared to
$82.4 million in the same period in 2011. The increase in operating
expenses for the second quarter and first half of 2012 was
primarily due to added costs associated with the growth in
Pembina's asset base since the Arrangement and higher variable
costs in each of the Company's businesses due to increased volumes.
Operating margin was $148.9 million during the second quarter, up
35 percent from the same period last year (operating margin is a
Non-GAAP measure; see "Non-GAAP Measures"). For the six months
ended June 30, 2012 operating margin was $276.6 million compared to
$207.6 million for the same period of 2011. These increases were
primarily due to higher revenue, as discussed above. Realized and
unrealized gains (losses) on commodity-related derivative financial
instruments are the result of Pembina's market risk management
program and are primarily related to outstanding positions acquired
on the closing of the Arrangement (see "Market Risk Management
Program" and Note 13 to the Interim Financial Statements). The
unrealized gains on commodity-related derivative financial
instruments of $64.8 million and $61.3 million recognized in the
three and six months ended June 30, 2012, respectively, reflect the
reduction in the future NGL price indices between April 2, 2012 and
June 30, 2012 (see "Business Environment"). Depreciation and
amortization (operational) increased to $52.5 million during the
second quarter of 2012 compared to $15.8 million during the same
period in 2011. For the six months ended June 30, 2012,
depreciation and amortization (operational) increased to $74.2
million, up from $30.6 million for the same period last year. Both
the quarterly and year-to-date increases reflect depreciation on
new capital additions including the assets acquired through the
Arrangement. The increases in revenue and operating margin combined
with an unrealized gain on commodity-related derivative financial
instruments contributed to gross profit of $161.2 million during
the second quarter and $263.7 million during the first six months
of 2012 compared to $97.8 million and $180.6 million during the
comparative periods of the prior year. General and administrative
expenses ("G&A") of $25.8 million were incurred during the
second quarter of 2012 compared to $12.8 million during the second
quarter of 2011. G&A for the first half of 2012 was $43.3
million compared to $27.4 million for the same period of 2011. The
increase in G&A for the three and six month periods in 2012
compared to the prior year is mainly due the addition of employees
who joined Pembina through the Arrangement, an increase in salaries
and benefits for existing and new employees, and increased rent for
new and expanded office space. Every $1 change in share price is
expected to change Pembina's annual share-based incentive expense
by $0.7 million. Pembina generated adjusted EBITDA of $125.9
million during the second quarter of 2012 compared to $103.3
million during the second quarter of 2011 (adjusted EBITDA is a
Non-GAAP measure; see "Non-GAAP Measures"). Adjusted EBITDA for the
six month period ended June 30, 2012 was $237.3 million compared to
$190.5 million for the same period in 2011. The increase in
quarterly and year-to-date adjusted EBITDA was due to strong
results from each of Pembina's legacy businesses, new assets and
services having been brought on-stream and the growth in Pembina's
operations since completion of the Arrangement. The Company's
earnings were $80.4 million ($0.28 per share) during the second
quarter of 2012 compared to $48.0 million ($0.29 per share) during
the second quarter of 2011. Earnings were $113.0 million ($0.50 per
share) during the first half of 2012 compared to $90.5 million
($0.54 per share) during the same period of the prior year.
Earnings for the three and six month periods ended June 30, 2012
increased as a result of the acquisition of Provident and
unrealized gains on commodity-related derivative financial
instruments. Earnings per share decreased primarily due to the
116.5 million shares issued as a result of the Arrangement.
Adjusted earnings were $37.4 million ($0.13 per share) during the
second quarter and $102.7 million ($0.45 per share) for the first
half of 2012, down from $65.4 million ($0.39 per share) and $118.1
million ($0.71 per share) for the comparative periods of 2011
(adjusted earnings is a Non-GAAP measure; see "Non-GAAP Measures").
The quarterly and year-to-date decrease is primarily due to
increased depreciation and amortization (operational) and higher
finance costs, which were partially offset by an increase in
operating margin. Cash flow from operating activities was $24.1
million ($0.08 per share) during the second quarter of 2012
compared to $49.5 million ($0.30 per share) during the second
quarter of 2011. For the six months ended June 30, 2012, cash flow
from operating activities was $89.4 million ($0.39 per share)
compared to $124.0 million ($0.74 per share) during the same period
last year. The decrease in cash flow from operating activities
during the 2012 periods is primarily due to acquisition-related
expenses, higher interest expenses and an increase in working
capital reflecting a seasonal inventory build. Adjusted cash flow
from operating activities was $89.5 million ($0.31 per share)
during the second quarter of 2012 compared to $81.8 million ($0.49
share) during the second quarter of 2011 (adjusted cash flow from
operating activities is a Non-GAAP measure; see "Non-GAAP
Measures"). Adjusted cash flow from operating activities was $188.3
million ($0.83 per share) during the first half of 2012 compared to
$157.8 million ($0.94 share) during the same period of last year.
Adjusted cash flow from operating activities per share decreased
primarily due to the 116.5 million shares issued as a result of the
Arrangement. Operating Results (unaudited) 3 Months Ended 6 Months
Ended June 30 June 30 2012 2011 2012 2011 Net Net Net Net Revenue
Operating Revenue Operating Revenue Operating Revenue Operating ($
millions) (1) Margin(2) (1) Margin(2) (1) Margin(2) (1) Margin(2)
Conventional Pipelines 78.4 47.5 72.4 50.1 160.6 101.9 141.7 94.1
Oil Sands & Heavy Oil 39.4 27.8 27.7 20.0 82.5 57.9 58.2 39.3
Gas Services 22.2 15.0 18.6 13.4 41.3 28.1 33.6 23.7 Midstream 89.0
58.0 29.3 26.8 121.0(3) 87.4(3) 55.3 50.5 Corporate 0.6 1.3 Total
229.0 148.9 148.0 110.3 405.4 276.6 288.8 207.6 (1) Midstream
revenue is net of $648.8 million in cost of goods sold for the
quarter ended June 30, 2012 (quarter ended June 30, 2011: $364.4
million) and $947.9 million in cost of goods sold for six months
ended June 30, 2012 (six months ended June 30, 2011: $618.5
million). (2) Refer to "Non-GAAP Measures." (3) Includes results
from operations generated by the acquired assets from Provident
since closing of the Arrangement. Conventional Pipelines 3 Months
Ended 6 Months Ended June 30 June 30 ($ millions, except where
noted) 2012 2011 2012 2011 Average throughput (mbpd) 433.9 411.4
450.4 400.9 Revenue 78.4 72.4 160.6 141.7 Operations 29.9 22.2 57.5
49.0 Realized gain (loss) on commodity-related derivative financial
instruments (1.0) (0.1) (1.2) 1.4 Operating margin(1) 47.5 50.1
101.9 94.1 Depreciation and amortization included in operations
12.2 10.4 24.1 20.1 Unrealized gain (loss) on commodity-related
derivative financial instruments 0.2 0.1 (2.8) 4.7 Gross profit
35.5 39.8 75.0 78.7 Capital expenditures 55.6 10.1 64.5 26.8
((1) )Refer to "Non-GAAP Measures." Business Overview
Pembina's Conventional Pipelines business is comprised of a
well-maintained and strategically located 7,850 km pipeline network
that extends across much of Alberta and B.C. It transports
approximately half of Alberta's conventional crude oil production,
about thirty percent of the NGL produced in western Canada, and
virtually all of the conventional oil and condensate produced in
B.C. This business' primary objective is to generate sustainable
operating margin while pursuing opportunities for increased
throughput and revenue. Conventional Pipelines endeavors to
maintain and/or improve operating margin by capturing incremental
volumes, expanding its pipeline systems, managing revenue and
adopting strong discipline relative to operating expenses.
Operational Performance: Throughput During the second quarter of
2012, Conventional Pipelines' throughput averaged 433.9 mbpd,
consisting of an average of 332.5 mbpd of crude oil and condensate
and 101.4 mbpd of NGL. This is approximately five percent higher
than the same period of 2011 when average throughput was 411.4
mbpd, with the increase being primarily due to continued production
growth from regional resource play development in the Cardium
(oil), Deep Basin Cretaceous (NGL), Montney (oil/NGL) and
Beaverhill Lake (oil) formations. Pipeline receipts during the
second quarter of 2012 increased on several of Conventional
Pipelines' systems including the Peace, Swan Hills and Northern
systems. However, NGL volumes were impacted during the second
quarter due to a turnaround at a third party delivery facility as
well as several extended third party gas plant maintenance outages
that were scheduled to coincide with the previously mentioned
delivery point outage. The producer growth in production discussed
above also contributed to a 12 percent increase in throughput for
the first six months of 2012 compared to the same period of the
prior year. Financial Performance During the second quarter of
2012, Conventional Pipelines generated revenue of $78.4 million, up
eight percent from the same quarter of 2011. This is due to higher
volumes generated by newly connected facilities on Pembina's larger
pipeline systems. For the first six months of 2012, revenue was
$160.6 million compared to $141.7 million for the same period in
2011. During the second quarter, operating expenses were higher at
$29.9 million compared to $22.2 million in the second quarter of
2011. Similarly, operating expenses for the six months ended June
30, 2012 increased to $57.5 million from $49.0 million during the
same period of 2011. These quarterly and year-to-date increases
resulted primarily from increased variable and power costs
associated with higher volumes and new assets that are now
in-service, as well as increased spending related to pipeline
integrity and geotechnical work. Operating margin for the second
quarter of 2012 was $47.5 million compared to $50.1 million during
the same period of 2011. This decrease was primarily due to
increased operating expenses which were partially offset by higher
revenue, as discussed above. On a year-to-date basis, operating
margin increased to $101.9 million from $94.1 million for the first
six months of 2011. Depreciation and amortization included in
operations increased to $12.2 million during the second quarter of
2012 from $10.4 million during the second quarter of 2011,
reflecting capital additions in this business. Depreciation and
amortization included in operations for the six months ended June
30, 2012 was $24.1 million, up from $20.1 million in the first half
of 2011. For the three and six months ended June 30, 2012, gross
profit was $35.5 million and $75.0 million, respectively, compared
to $39.8 million and $78.7 million for the same periods of the
prior year. These decreases are due to higher revenues being offset
by increased operating expenses and depreciation and amortization
included in operations during the 2012 periods for the reasons
discussed above. Capital expenditures for the second quarter of
2012 totaled $55.6 million compared to $10.1 million during the
second quarter of 2011 and capital expenditures for the first half
of 2012 were $64.5 million compared to $26.8 for the same period of
2011. The majority of this spending relates to the expansion of
certain pipeline assets as described below. New Developments:
Conventional Pipelines Liquids-Rich Natural Gas: Expansion of Peace
and Northern NGL Pipelines Pembina is progressing plans to expand
the NGL throughput capacity on its Peace and Northern pipelines
(together the "Northern NGL System") by 52 mbpd (the "NGL
Expansion") to accommodate increased customer demand following
strong drilling results and increased field liquids extraction by
area producers. As of August, Pembina has reached long-term
commercial agreements with its customers to underpin the $100
million NGL Expansion. Assuming regulatory approvals are obtained
in a timely manner, Pembina expects to bring 17 mbpd of the NGL
Expansion into service by the end of 2012 and the remaining 35 mbpd
by the end of 2013. During the second quarter of 2012, Pembina
received regulatory approval for and began construction on two of
the three pump stations as part of the first phase of the NGL
Expansion. Pembina's Northern NGL System is strategically located
across liquids-rich natural gas production areas in the WCSB and
serves producers in the Deep Basin, Montney, Cardium and emerging
Duvernay Shale plays. Currently, the Northern NGL System's capacity
is 115 mbpd. As at the beginning of August, average daily
throughput on the Northern NGL System was approximately 100 mbpd.
Once complete, the proposed NGL Expansion will increase capacity on
the Northern NGL System by 45 percent to 167 mbpd. Drayton Valley
Area In the area of the Cardium formation of west central Alberta,
Pembina continues to actively work with producers on numerous
connection and expansion opportunities. Pembina completed the
refurbishment of its Calmar booster station in May, 2012, adding 50
mbpd of capacity on the Drayton Valley mainline and bringing the
total capacity of the system to approximately 190 mbpd. Supporting
Gas Services' Saturn and Resthaven Projects Pembina's Conventional
Pipelines business is working closely with its Gas Services
business to construct the pipeline components of the Saturn and
Resthaven gas plant projects. These two pipeline projects will
gather NGL from the gas plants for delivery to Pembina's Peace
Pipeline system. During the second quarter of 2012, Pembina
continued its consultation activities related to the right-of-way
and pipeline routing for both of these projects with First Nations,
community stakeholders and the appropriate regulators, and has
continued to order long-lead equipment for the pipeline and pump
stations. Western System Subsequent to the quarter end, the British
Columbia Utilities Commission approved an application on Pembina's
Western System, which will allow Pembina to fully recover
anticipated geotechnical and integrity costs associated with that
pipeline, and extend customer arrangements and the useful life of
the asset. Oil Sands & Heavy Oil 3 Months Ended 6 Months Ended
June 30 June 30 ($ millions, except where noted) 2012 2011 2012
2011 Capacity under contract (mbpd) 870.0 775.0 870.0 775.0 Revenue
39.4 27.7 82.5 58.2 Operations 11.6 7.7 24.6 18.9 Operating
margin(1) 27.8 20.0 57.9 39.3 Depreciation and amortization
included in operations 4.9 2.1 9.8 4.0 Gross profit 22.9 17.9 48.1
35.3 Capital expenditures 30.1 6.0 129.9 ((1) )Refer to
"Non-GAAP Measures." Business Overview Pembina plays an important
role in supporting Alberta's oil sands and heavy oil industry.
Pembina is the sole transporter of crude oil for Syncrude Canada
Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources
Ltd.'s Horizon Oil Sands operation (via the Horizon Pipeline) to
delivery points near Edmonton, Alberta. Pembina also owns and
operates the Nipisi and Mitsue Pipelines, which provide
transportation for producers operating in the Pelican Lake and
Peace River heavy oil regions of Alberta, and the Cheecham Lateral
which transports product to oil sands producers operating southeast
of Fort McMurray, Alberta. The Oil Sands & Heavy Oil business
operates approximately 1,650 km of pipeline and accounts for about
one-third of the total take-away capacity from the Athabasca oil
sands region. These assets operate under long-term, extendible
contracts that provide for the flow-through of operating expenses
to customers. As a result, operating margin from this business is
primarily related to invested capital and is not sensitive to
fluctuations in operating expenses or actual throughput. Financial
Performance The Oil Sands & Heavy Oil business realized revenue
of $39.4 million in the second quarter of 2012 compared to $27.7
million in the second quarter of 2011. This 42 percent increase is
primarily due to contributions from the Nipisi and Mitsue
pipelines, which commenced operations in the third quarter of 2011.
For the same reason, year-to-date revenue in 2012 was $82.5 million
compared to $58.2 million for the same period in 2011. Operating
expenses in Pembina's Oil Sands & Heavy Oil business were $11.6
million during the second quarter of 2012 compared to $7.7 million
during the second quarter of 2011. For the first six months of
2012, operating expenses were $24.6 million compared to $18.9
million for the same period in 2011. These increases primarily
reflect the additional operating expenses related to the Nipisi and
Mitsue pipelines. For the three and six months ended June 30, 2012,
operating margin was $27.8 million and $57.9 million, higher than
the operating margin of $20.0 million and $39.3 million,
respectively, during the same periods in 2011, primarily due to the
same factors that contributed to the increase in revenue, as
discussed above. Depreciation and amortization included in
operations for the second quarter of 2012 totaled $4.9 million
compared to $2.1 million during the same period of the prior year.
For the first half of 2012, depreciation and amortization included
in operations was $9.8 million compared to $4.0 million in the
first half of 2011. These increases primarily reflect the
additional depreciation and amortization included in operations
related to the Nipisi and Mitsue pipelines. For the three and six
months ended June 30, 2012, gross profit was $22.9 million and
$48.1 million, higher than gross profit of $17.9 million and $35.3
million, respectively, during the same periods in 2011, primarily
due to higher operating margin as discussed above. For the six
months ended June 30, 2012, capital expenditures within the Oil
Sands & Heavy Oil business totaled $6.0 million compared to
$129.9 million during the same period in 2011. The majority of
Pembina's 2011 investment in this business related to completing
the Nipisi and Mitsue pipeline projects. Segmented Operating Margin
Syncrude Pipeline The Syncrude Pipeline has a capacity of 389 mbpd
and is fully contracted to the owners of Syncrude Canada Ltd. under
an extendible agreement that expires in 2035. Operating margin
generated by the Syncrude Pipeline during the second quarter and
first half of 2012 was $6.4 million and $13.1 million,
respectively, virtually unchanged from $6.3 million and $12.8
million during the same period in 2011. Cheecham Lateral Pembina's
Cheecham Lateral has a capacity of 136 mbpd and is fully contracted
to shippers under an extendible agreement that expires in 2032.
Operating margin generated by the Cheecham Lateral during the
second quarter and first half of 2012 was $1.1 million and $2.2
million, respectively, compared to $1.2 million and $2.3 million
during the same periods in 2011. Horizon Pipeline The Horizon
Pipeline has an ultimate capacity of 250 mbpd (with the addition of
pump stations) and is fully contracted to Canadian Natural
Resources Ltd. under an extendible agreement that expires in 2033.
Operating margin generated by the Horizon Pipeline during the
second quarter and first half of 2012 was $11.6 million and $22.8
million, respectively, compared to $12.1 million and $23.5 million
during the same period in 2011. Nipisi & Mitsue Pipelines In
June and July of 2011, Pembina completed construction of its Nipisi
and Mitsue pipelines. Pembina is in the process of installing two
remaining pump stations and expects it will bring the combined
capacity of the pipelines to approximately 122 mbpd in the second
quarter of 2013. Operating margin generated by these assets in the
second quarter of 2012 was $8.0 million and $18.5 million for the
first half of the year. New Developments: Oil Sands & Heavy Oil
Pembina continues to actively explore other oil sands and heavy oil
pipeline opportunities and believes the Company's strong foothold
and recent construction and community relations experience in the
oil sands region position it well to attract new business. Gas
Services 3 Months Ended 6 Months Ended June 30 June 30 ($ millions,
except where noted) 2012 2011 2012 2011 Average processing volume
(MMcf/d) 285.0 245.5 275.0 240.8 Average processing volume
(mboe/d)(1) 47.5 40.9 45.8 40.1 Revenue 22.2 18.6 41.3 33.6
Operations 7.2 5.2 13.2 9.9 Operating margin(2) 15.0 13.4 28.1 23.7
Depreciation and amortization included in operations 4.3 2.5 7.5
4.8 Gross profit 10.7 10.9 20.6 18.9 Capital expenditures 23.5 25.5
55.8 41.1 (1) Average processing volume converted to mboe/d from
MMcf/d at a 6:1 ratio. (2) Refer to "Non-GAAP Measures." Business
Overview Pembina's operations include a growing natural gas
gathering and processing business. Located approximately 100 km
south of Grande Prairie, Alberta, Pembina's key revenue-generating
Gas Services assets form the Cutbank Complex which comprises three
sweet gas processing plants with 360 MMcf/d of processing capacity
(305 MMcf/d net to Pembina), a new 205 MMcf/d ethane plus
extraction facility, as well as approximately 350 km of gathering
pipelines. The Cutbank Complex is connected to Pembina's Peace
Pipeline system and serves an active exploration and production
area in the WCSB. Pembina plans to expand its Gas Services business
by constructing the Saturn and Resthaven enhanced NGL extraction
facilities to meet the growing needs of producers in west central
Alberta. Financial Performance Gas Services recorded an increase in
revenue of approximately 19 percent during the second quarter of
2012, contributing $22.2 million compared to $18.6 million in the
second quarter of 2011. In the first half of the year, revenue was
$41.3 million compared to $33.6 million in the same period of 2011.
These increases primarily reflect higher processing volumes at
Pembina's Cutbank Complex. Average processing volume, net to
Pembina, was 285.0 MMcf/d during the second quarter of 2012, 16
percent higher than the 245.5 MMcf/d processed during the second
quarter of 2011. During the second quarter of 2012, operating
expenses were $7.2 million, an increase from the $5.2 million
incurred in the second quarter of 2011. Year-to-date operating
expenses totaled $13.2 million, up from $9.9 million during the
same period of the prior year. The quarterly and year-to-date
increases were mainly due to variable costs incurred to process
higher volumes at the Cutbank Complex. As a result of processing
higher volumes at the Cutbank Complex, Gas Services realized
operating margin of $15.0 million in the second quarter and $28.1
million in the first half of 2012 compared to $13.4 million and
$23.7 million during the same periods of the prior year.
Depreciation and amortization included in operations during the
second quarter of 2012 totaled $4.3 million, up from $2.5 million
during the same period of the prior year, primarily due to higher
in-service capital balances from additions to the Cutbank Complex
(including the Musreau Deep Cut Facility). For the same reason,
year-to-date depreciation and amortization included in operations
totaled $7.5 million, up from $4.8 million during the first half of
2011. For the three months ended June 30, 2012, gross profit was
$10.7 million, consistent with the same period of 2011. On a
year-to-date basis, gross profit was $20.6 million compared to
$18.9 million during the first half of 2011. For the six months
ended June 30, 2012, capital expenditures within Gas Services
totaled $55.8 million compared to $41.1 million during the same
period of 2011. This increase was due to the spending required to
complete the Musreau Deep Cut Facility, the expansion of the
shallow cut facility at the Cutbank Complex as well as capital
expenditures incurred to progress the Saturn and Resthaven enhanced
NGL extraction facilities. New Developments: Gas Services Pembina
continues to see significant growth opportunities resulting from
the trend towards liquids-rich gas drilling and the extraction of
valuable NGL from gas in the WCSB. Pembina expects the three
expansions detailed below to bring the Company's gas processing
capacity to 890 MMcf/d (net), including enhanced NGL extraction
capacity of approximately 535 MMcf/d (net) which would be processed
largely on a contracted, fee-for-service basis and result in
approximately 45 mbpd of incremental NGL to be transported for
additional toll revenue on Pembina's conventional pipelines by
early 2014. Musreau Deep Cut Facility Pembina completed
construction and began operations at its Musreau Deep Cut Facility,
a 205 MMcf/d ethane extraction facility, mid-February 2012. The
Musreau Deep Cut Facility experienced an unplanned outage in March
of 2012 and repairs are ongoing. Expansion at the Cutbank Complex:
Musreau Shallow Cut Expansion Pembina is expanding Musreau's
shallow cut gas processing capability by 50 MMcf/d at an estimated
cost of $17 million. With commissioning activities near completion,
Pembina expects the expansion to be in-service in August 2012. Once
in-service, the Cutbank Complex will have an aggregate raw shallow
gas processing capacity of 410 MMcf/d (355 MMcf/d net to Pembina),
an increase of 16 percent net to Pembina. Related to this
expansion, Pembina has entered into contracts with a minimum term
of five years with area producers for the entire capacity of the
expansion on a fee-for-service basis. Saturn Facility Pembina is
developing a $200 million 200 MMcf/d enhanced NGL extraction
facility (the "Saturn Facility") and associated NGL and gas
gathering pipelines in the Berland area of west central Alberta.
Once operational, Pembina expects the Saturn Facility will have the
capacity to extract up to 13.5 mbpd of NGL. Subject to regulatory
and environmental approval, Pembina expects the Saturn Facility and
associated pipelines to be in-service in the fourth quarter of
2013. In June, Pembina executed a long-term arrangement for the
remaining 50 MMcf/d of capacity at Saturn, bringing the total
contracted capacity to 100 percent. As of the beginning of August
2012, Pembina has ordered 90 percent of the major long-lead
equipment for the project and is progressing plant site
construction. Pipeline environmental field assessments have been
completed and stakeholder consultation is ongoing. Resthaven
Facility Pembina is developing a combined shallow cut and deep cut
NGL extraction facility (the "Resthaven Facility") by modifying and
expanding an existing gas plant, and is constructing a pipeline to
transport the extracted NGL from the Resthaven Facility to
Pembina's Peace Pipeline system for a total estimated cost of $230
million. Once complete, Pembina will own approximately 65 percent
of the Resthaven Facility and 100 percent of the NGL pipeline.
Pembina expects the initial phase of the Resthaven Facility will
have a gross capacity of 200 MMcf/d (130 MMcf/d net) and 13 mbpd of
liquids extraction capability, with ultimate processing capacity of
300 MMcf/d (195 MMcf/d net) and 18 mbpd of liquids extraction
capability. Subject to regulatory and environmental approvals,
Pembina expects these new assets to be in-service in the first
quarter of 2014. As of the beginning of August 2012, Pembina has
ordered 65 percent of the major long-lead equipment for the project
and is progressing plant site construction. Other activities
related to the project include pipeline stakeholder consultation,
environmental planning, route selection, engineering, and
right-of-way surveying. Midstream((1)) 3 Months Ended 6 Months
Ended June 30 June 30 ($ millions, except where noted) 2012 2011
2012 2011 Total NGL sales volume (mbpd) 90.4 90.4(3) Revenue 737.8
393.7 1,068.9 673.8 Operations 19.6 2.5 22.1 4.6 Cost of goods
sold, including product purchases 648.8 364.4 947.9 618.5 Realized
loss on commodity-related derivative financial instruments (11.4)
(11.5) (0.2) Operating margin(2) 58.0 26.8 87.4 50.5 Depreciation
and amortization included in operations 31.1 0.9 32.7 1.8
Unrealized gains (losses) on commodity-related derivative financial
instruments 64.6 3.2 64.0 (1.0) Gross profit 91.5 29.1 118.7 47.7
Capital expenditures 55.2 11.6 55.9 101.9 (1) Share of profit from
equity accounted investees not included in results above. (2) Refer
to "Non-GAAP Measures." (3) Represents per day volumes since the
closing of the Arrangement. Business Overview Pembina's Midstream
business is organized into two components: -- a crude oil midstream
business, which represents the Company's legacy midstream
operations is situated at key sites across Pembina's operations and
comprises a network of liquids truck terminals, terminalling at
downstream hub locations, including storage and pipeline
connectivity; and -- an NGL midstream business, which Pembina
acquired through the Arrangement, which includes two operating
systems: Redwater West and Empress East. o The Redwater West NGL
system includes the Younger extraction and fractionation facility
in B.C.; a 65,000 bpd fractionator, 6.3 mmbbls of cavern storage
and terminalling facilities at Redwater, Alberta; and, third party
fractionation capacity in Fort Saskatchewan, Alberta. o The Empress
East NGL system includes a 2.1 bcf/d interest in the straddle plant
at Empress, Alberta, and 20,000 bpd of fractionation capacity as
well as 6.4 mmbbls of cavern storage in Sarnia, Ontario. By
providing integrated services along the crude oil and NGL value
chains, this business has increased the range of services Pembina
is able to provide its customers. This business also contributes
throughput to the Company's Conventional Pipelines business, and
provides essential downstream services that support its Gas
Services business. Financial Performance In the Midstream business,
revenue, net of cost of goods sold, grew by 204 percent to $89.0
million during the second quarter of 2012 from $29.3 million during
the second quarter of 2011. Year-to-date revenue, net of cost of
goods sold, was $121.0 million in 2012 compared to $55.3 million in
2011. These increases were primarily due to the addition of the NGL
midstream business acquired through the Arrangement and increased
activity on Pembina's pipeline systems. Operating expenses during
the second quarter of 2012 were $19.6 million, up from the $2.5
million in the second quarter of 2011. Operating expenses for the
first half of the year were $22.1 million in 2012 and $4.6 million
in 2011. Operating expenses for the quarter and year-to-date were
higher due to the increase in Midstream's asset base since the
Arrangement. Operating margin was $58.0 million during the second
quarter of 2012 compared to $26.8 million during the second quarter
of 2011. Operating margin for the first six months of 2012 was
$87.4 million compared to $50.5 million in the same period of 2011.
This increase was largely due to the same factors that contributed
to the increase in revenue, net of cost of goods sold, as discussed
above. Depreciation and amortization included in operations during
the second quarter of 2012 totaled $31.1 million, up from $0.9
million during the same period of the prior year. Year-to-date
depreciation and amortization included in operations totaled $32.7
million, up from $1.8 million during the first half of 2011. The
quarterly and year-to-date increases reflect the additional assets
in Midstream since the closing of the Arrangement. For the three
and six months ended June 30, 2012, gross profit in this business
increased to $91.5 million and $118.7 million from $29.1 million
and $47.7 million during the same periods in 2011 as a result of
the addition of assets acquired through the Arrangement, higher
operating margin and unrealized gains on commodity-related
derivative financial instruments. For the six months ended June 30,
2012, capital expenditures within the Midstream business were
primarily related to cavern development and related infrastructure
as well as the expansion at the Redwater Facility by approximately
8,000 bpd and totaled $55.9 million compared to $101.9 million
during the same period of 2011. Capital spending in the first half
of 2011 had included the acquisition of a terminalling and storage
facility near Edmonton, Alberta and the acquisition of linefill for
the Peace Pipeline. Operating Margin by Activity Crude Oil
Midstream Pembina's crude oil midstream activity consists of a
network of terminals, pipeline-connected storage and hub locations
situated at key sites across the Company's conventional pipeline
system. This includes the development of the Pembina Nexus Terminal
("PNT") as well as a 50 percent non-operated interest in both the
Fort Saskatchewan Ethylene Storage Facility and the LaGlace
Full-Service Terminal. Operating margin for this activity during
the second quarter of 2012 was $30.8 million compared to $26.8
million during the second quarter of 2011. Year-to-date operating
margin was $60.2 million, up 19 percent from $50.5 million in the
same period last year. Strong second quarter and year-to-date 2012
results were primarily due to higher volumes and activity on
Pembina's pipeline systems and wider margins, as well as
opportunities associated with enhanced connectivity at PNT added in
the first quarter of 2012. NGL Midstream Operating margin for the
NGL midstream business, which was acquired by Pembina on April 2,
2012, was $27.2 million for the second quarter and year-to-date,
including an $11.2 million realized loss on commodity-related
derivative financial instruments (see "Market Risk Management
Program"). The second quarter of 2012 was a period of weak demand
for propane and lower NGL prices (see "Business Environment") which
impacted operating margin for the period and resulted in an $8.4
million impairment of the inventory balance at June 30, 2012.
Redwater West Redwater West purchases NGL mix from various natural
gas and natural gas liquids producers and fractionates it into
finished products at the Redwater fractionation facility near Fort
Saskatchewan, Alberta. Redwater West also includes NGL production
from the Younger NGL extraction and fractionation plant located at
Taylor in northeastern BC. The Younger plant supplies specification
NGL to local BC markets as well as NGL mix into the Fort
Saskatchewan area for fractionation and sale. Also located at the
Redwater facility is Pembina's industry-leading rail-based
condensate terminal, which serves the heavy oil industry's need for
diluent. Pembina's condensate terminal is the largest of its size
in western Canada. Operating margin during the second quarter of
2012, excluding realized losses from commodity-related derivative
financial instruments, was $36.2 million. Second quarter results
were impacted by weak propane prices and decreased gas throughput
volumes at the Younger plant. Propane margins were low in the
second quarter of 2012 due to inventory builds resulting from a
significantly warmer 2011-12 winter. Conversely, butane margins
were high, primarily due to strong refinery demand and increases in
market prices in the second quarter of 2012. Condensate sales also
contributed to the Redwater West gross operating margin in the
second quarter of 2012 as increased market prices offset slightly
lower condensate sales volumes. Overall, Redwater West NGL sales
volumes averaged 51.9 mbpd. Empress East Empress East extracts NGL
mix from natural gas at the Empress straddle plants and purchases
NGL mix from other producers/suppliers. Ethane and condensate are
generally fractionated out of the NGL mix at Empress and sold into
Alberta markets. The remaining NGL mix, consisting of primarily
propane and butane, is shipped on Pembina's 50 percent owned
Kerrobert Pipeline to a third party pipeline for transport to
Sarnia, Ontario where it is then fractionated into specification
products. Specification propane and butanes are sold into central
Canadian and eastern U.S. markets. Demand for propane is seasonal
and results in inventory that generally builds over the second and
third quarters of the year and is sold in the fourth quarter and
the first quarter of the following year during the winter heating
season. Operating margin during the second quarter of 2012,
excluding realized losses from commodity-related derivative
financial instruments, was $2.2 million. Second quarter results
were impacted by low sales volumes associated with weak demand for
propane but was offset by strong refinery demand for butane. Weak
demand and lower NGL sales prices were partially offset by lower
AECO natural gas prices. Overall, Empress East NGL sales volumes
averaged 38.5 mbpd. The lower market frac spreads in the second
quarter of 2012 (see "Business Environment") were further impacted
at Empress by the continued high cost of natural gas supply in the
form of extraction premiums, reflecting a higher long-term relative
frac spread. Empress extraction premiums were also higher as a
result of decreased volumes of natural gas flowing past the Empress
straddle plants and thus increased competition for NGL. Natural gas
throughput directly impacts production at the Empress facilities
which, in turn, reduces the supply of propane-plus available for
sale in Sarnia and in surrounding eastern markets. Pembina has
partially mitigated the impact of lower natural gas-based NGL
supply at Empress by purchasing NGL mix supply in western Canada.
The mix is then transported to the Sarnia market for fractionation
and sale. Pembina also purchases NGL mix supply from other Empress
plant owners and in the Edmonton market. New Developments:
Midstream The capital being deployed in the Midstream business is
primarily being directed towards fee-for-service projects which
will continue to increase its stability and predictability. The
Company continues to develop the PNT, which connects key
infrastructure in the Edmonton - Fort Saskatchewan - Namao, Alberta
area via pipelines to other Pembina infrastructure as well as
refineries and downstream terminals. PNT will enable Pembina to
create tailored products and services for customers while
facilitating growth opportunities for the Company's other
businesses. Pembina is also moving forward on its plans to expand
the services offered at a number of existing truck terminals and
construct new full-service terminals that focus on emulsion
treating (separating oil from impurities to meet shipping quality
requirements), produced water handling and water disposal. In
addition to earning fees for these services, Pembina's truck
terminals will secure volumes for its pipeline systems to generate
additional pipeline toll revenue. The Company has entered
into a joint venture agreement with a third party to develop a new
full-service terminal (50 percent interest net to Pembina) at Judy
Creek to serve the production expansion in the Beaverhill Lake and
Swan Hills formations with an anticipated in-service date of the
first quarter of 2013. Pembina continues to advance its other
full-service terminal initiatives and is presently involved with
assessing disposal well candidates prior to making binding
commitments. Pembina is continuing to develop seven fee-for-service
storage caverns at its Redwater site, the first of which is
expected to come into service in the fourth quarter of 2012. As
well, the Company is progressing an expansion to the Redwater
fractionator by approximately 8,000 bpd, which is expected to be
in-service in the fourth quarter of 2012. During the second
quarter, Pembina also signed an agreement with a third party
producer to tie in its production of up to 60 MMcf/d to the Younger
plant by the first quarter of 2013. Market Risk Management Program
Pembina is exposed to frac spread risk which is the difference
between the selling prices for propane-plus and the input cost of
natural gas required to produce respective NGL products.
Pembina has a risk management program and uses derivative financial
instruments to mitigate frac spread risk when possible to safeguard
a base level of operating cash flow. Pembina has entered into
derivative financial swap contracts through March 2013 to protect
the frac spread and to manage exposure to power costs, interest
rates and foreign exchange rates. Pembina's credit policy mitigates
risk of non-performance by counterparties of its derivative
financial instruments. Activities undertaken to reduce risk
include: regularly monitoring counterparty exposure to approved
credit limits; financial reviews of all active counterparties;
entering into International Swap Dealers Association ("ISDA")
agreements; and, obtaining financial assurances where warranted. In
addition, Pembina has a diversified base of available
counterparties. Management continues to actively monitor commodity
price risk and mitigage its impact through financial risk
management activities. Subject to market conditions and at
management's discretion, Pembina may hedge a portion of its natural
gas and NGL volumes. A summary of Pembina's current financial
derivative positions is available on Pembina's website at
www.pembina.com. In the second quarter of 2012, Pembina bought out
the remaining portion of Provident's legacy participating crude oil
hedges for $1.2 million as Pembina believed these did not represent
effective hedges for NGL prices. As a result, the Company no longer
has any propane or butane hedges linked to crude oil prices. A
summary of Pembina's risk management contracts executed during the
second quarter of 2012 is contained in the following table.
Activity in the second quarter Commodity Effective Year Description
Volume (Buy)/Sell Period Crude Oil U.S. $95.94 per July 1 -
bbl(2)(6)(7) 1,299 bpd December 31 U.S. $1.226 per July 1 - Propane
gallon(3)(6) (1,630) bpd December 31 2012 U.S. $1.725 per July 1 -
Condensate gallon(4)(7) (565) bpd December 31 Sell U.S. $1,400,000
per month at 0.994 July 1 - F/X (5)(9) December 31 Crude Oil U.S.
$104.22 per bbl(2)(6) January 1 - (7) 750 bpd April 30 U.S. $1.226
per January 1 - 2013 Propane gallon(3)(6) (1,667) bpd April 30 Sell
U.S. $1,400,000 per month at 0.994 January 1 - F/X (5)(9) March 31
Power July 1 - Cdn $65.86 per December 31, MW/h(8) (15) MW/h 2013
Cdn $67.95 per January 1 - MW/h(8) December 31, (10) MW/h 2014
Corporate Cdn $67.95 per January 1 - MW/h(8) December 31, (10) MW/h
2015 Cdn $68.00 per January 1 - MW/h(8) December 31, (5) MW/h 2016
(1) The above table represents a number of transactions entered
into over the second quarter of 2012. (2) Crude oil contracts are
settled against NYMEX WTI calendar average. (3) Propane contracts
are settled against Belvieu C3 TET. (4) Condensate contracts are
settled against Belvieu Non-TET natural gasoline. (5) Frac spread
contracts. (6) Management of physical contract exposure - NGL
product contracts. (7) Management of physical contract exposure -
rail contracts. (8) Power contracts are settled against the hourly
price of power as published by the AESO in $/MWh. (9) U.S. dollar
forward contracts are settled against the Bank of Canada noon rate
average. Selling notional U.S. dollars for Canadian dollar fixed
exchange rate results in a fixed Canadian dollar price for the
underlying commodity. The following table summarizes the impact of
commodity-related derivative financial contracts settled during the
first two quarters of 2012 and 2011 that were included in the
realized (loss) gain on commodity-related derivative financial
instruments. 3 Months Ended 6 Months Ended June 30 June 30 ($
thousands, except volumes) 2012 2011 2012 2011 Volume Volume $ (1)
$ Volume $ Volume $ Realized (loss) gain on commodity-related
derivative financial instruments Frac spread related Crude oil
(1,997) 0.1 (1,997) 0.1 Natural gas (7,762) 4.6 (7,762) 4.6 Propane
1,727 0.2 1,727 0.2 Butane 769 0.3 769 0.3 Condensate 272 0.2 272
0.2 Sub-total frac spread related (6,991) (6,991) Corporate Power
(1,608) (159) (1,764) 1,455 Management of exposure embedded in
physical contracts and other (3,870) 0.3 (3,941) 0.5 (204) Realized
(loss) gain on commodity-related derivative financial instruments
(12,469) (159) (12,696) 1,251 (1) The above table represents
aggregate net volumes that were bought/sold over the periods. Crude
oil and NGL volumes are listed in millions of barrels and natural
gas is listed in millions of gigajoules. The realized loss on
commodity-related derivative financial instruments for the second
quarter of 2012 was $12.5 million compared to $0.2 million in the
comparable period in 2011. The majority of the realized loss in the
second quarter of 2012 was driven by natural gas purchase
derivative contracts settling at a contracted price higher than the
market natural gas prices during the settlement period, crude oil
derivative sales contracts settling at contracted crude oil prices
lower than the crude oil market prices during the settlement
period, and power purchase derivative contracts settling at a
contracted price higher than the market prices during the
settlement period. Business Environment 3 Months ended 6 Months
ended June 30 June 30 % % 2012 2011 Change 2012 2011 Change WTI
crude oil (U.S.$ per barrel) 93.49 102.56 (9) 98.21 98.33 Exchange
rate (from U.S.$ to Cdn$) 1.01 0.97 4 1.01 0.98 3 WTI crude oil
(expressed in Cdn$ per barrel) 94.44 99.25 (5) 98.77 96.05 3 AECO
natural gas monthly index (Cdn$ per gj) 1.74 3.54 (51) 2.06 3.56
(42) Frac Spread Ratio(1) 54.3x 28.0x 94 47.9x 27.0x 77 Mont
Belvieu Propane (U.S.$ per U.S. gallon) 0.98 1.50 (35) 1.12 1.45
(23) Mont Belvieu Propane expressed as a percentage of WTI 44% 61%
(28) 48% 62% (23) Market Frac Spread in Cdn$ per barrel(2) 45.70
53.84 (15) 50.43 52.09 (3) (1) Frac spread ratio is the ratio of
WTI expressed in Canadian dollars per barrel to the AECO monthly
index (Cdn$ per gj). (2) Market frac spread is determined using
average spot prices at Mont Belvieu, weighted based on 65 percent
propane, 25 percent butane and 10 percent condensate, and the AECO
monthly index price for natural gas. The second quarter of 2012 saw
a 6.4 percent decrease in the S&P TSX Composite from the
previous quarter, with the value of the Index being down 11.5
percent since the same time a year ago. From early May through to
the end of the second quarter, the Canadian dollar weakened against
the U.S. dollar, due in part to a decline in commodity prices,
averaging $1.01 per U.S. dollar for the quarter from a value of
$0.97 per U.S. dollar over the same period in the previous year.
The benchmark WTI oil price also trended downward in May and June
after a period of stability in April, averaging U.S. $93 for the
quarter and exiting the quarter at U.S. $85. The Canadian light
crude oil benchmark, Edmonton Par, recovered from a
higher-than-average price differential to WTI in the second quarter
of 2012 following historically high differentials and volatility in
the first quarter which had been caused by increasing crude supply,
refinery downtime and export infrastructure constraints. The
Canadian heavy crude oil benchmark, Western Canadian Select,
continued to trade at relatively wide differentials to WTI
throughout the second quarter due primarily to downstream
infrastructure constraints which resulted in a tight supply-demand
balance following the return to service of certain Canadian heavy
oil assets. The weakened crude oil price environment coupled with
increasing cost inflation in Alberta has caused some smaller
producers in the WCSB to reduce their budgets. However, oil
drilling in the WCSB remained robust in the second quarter of 2012
compared to longer-term historic levels, which has continued to
benefit Pembina's oil gathering infrastructure. The opening and
potential construction, expansion and conversion of downstream
infrastructure in the U.S. Midwest and Gulf Coast is expected to
provide narrower differentials in the future as Canadian producers
gain access to premium markets with adequate transportation and
refining capacity. Despite historically high storage levels in both
Canada and the U.S., natural gas prices recovered slightly through
the second quarter because of the larger-than-anticipated decline
in Alberta production to below multi-year averages. The closing
first quarter AECO price was $1.61 per GJ, which increased 32
percent during the second quarter to exit at $2.13 per GJ with an
average of $1.74 per GJ over the quarter. While low natural gas
prices are generally favourable for NGL extraction and
fractionation economics, a sustained low-priced gas environment
could impact the availability and overall cost of natural gas and
NGL mix supply in western Canada as natural gas producers may elect
to shut-in production or reduce drilling activities. While this has
occurred to some extent through the second quarter of 2012, many
producers have mitigated the low price environment through non-core
asset sales, partnerships and targeted development, all of which
have served Pembina in developing long-term opportunities. The NGL
pricing environment in the second quarter of 2012 was weakened by a
supply-demand imbalance in North America which was caused by
sustained exploitation of liquids-rich and associated gas in shale
plays in the U.S. coupled with historically high opening
inventories during the inventory build season due to the relatively
warm winter. In the U.S., industry propane inventories were
approximately 62 million barrels at the end of the second quarter
of 2012, approximately 14 million barrels or 29 percent above the
five-year historical average; in Canada, industry propane
inventories increased to 2.1 million barrels higher than the
historic five-year average, or approximately 8.1 million barrels at
the end of the second quarter of 2012. The U.S. and Canadian
inventory builds for propane were primarily due to the relatively
warm 2011-12 winter and associated decreased demand. This
over-supply led to weak prices, where the Mont Belvieu propane
price averaged U.S. $0.98 per U.S. gallon (44 percent of WTI) in
the second quarter of 2012, significantly below its five-year
average of 61 percent of WTI. Butane and condensate sales prices
were also lower in the second quarter of 2012. Pembina believes
that the liquids market should balance out in North America in the
coming months and years. The Company expects to see increased
demand for heavier NGL due to unconventional oil development and
expanded processing, and greater export capacity for lighter NGL as
a result of increased infrastructure capacity at the two primary
U.S. NGL hubs in Conway, Kansas and Mont Belvieu, Texas. However,
downward price pressure is expected to continue in the near-term
while inventories are cleared and supply remains robust. Market
frac spreads averaged $45.70 per barrel during the second quarter
of 2012 compared to $55.17 per barrel in the first quarter of 2012
and $53.84 per barrel in the second quarter of 2011. Compared to
the first quarter of 2012, lower frac spreads resulted from lower
NGL sales prices combined with a higher AECO natural gas price. The
outlook for the energy infrastructure sector in the WCSB remains
positive for all of Pembina's businesses. Strong activity levels
within the oil sands region represent opportunities for the Company
to leverage existing assets to capitalize on additional growth
opportunities. Pembina also continues to benefit from the
combination of relatively high oil prices and low natural gas
prices which has resulted in oil and gas producers continuing to
extract the liquids value from their natural gas production and
favouring liquids-rich natural gas plays over dry natural gas.
Pembina's Conventional Pipelines, Gas Services and Midstream
businesses are well-positioned to capitalize on the increased
activity levels in key NGL-rich producing basins. Crude oil and NGL
plays being developed in the vicinity of its pipelines include
Cardium, Montney, Cretaceous, Duvernay and Swan Hills. While recent
weakness in liquids prices and an inflationary cost environment
have resulted in some producers scaling back activity in the WCSB,
it is expected that the growth profile will continue to be positive
for energy infrastructure as the liquids price environment remains
at historic highs. Non-Operating Expenses G&A Pembina incurred
G&A of $25.8 million during the second quarter of 2012 compared
to $12.8 million during the second quarter of 2011. G&A for the
first half of 2012 was $43.3 million compared to $27.4 million for
the same period of 2011. The increase in G&A for the three and
six month periods in 2012 compared to the prior year is mainly due
the addition of employees who joined Pembina through the
Arrangement, an increase in salaries and benefits for existing and
new employees, and increased rent for new and expanded office
space. Every $1 change in share price is expected to change
Pembina's annual share-based incentive expense by $0.7 million.
Depreciation & Amortization (Operational) Depreciation and
amortization (operational) increased to $52.5 million during the
second quarter of 2012 compared to $15.8 million during the same
period in 2011. For the six months ended June 30, 2012,
depreciation and amortization (operational) was $74.2 million, up
from $30.6 million for the same period last year. Both the
quarterly and year-to-date increases reflect depreciation on new
property, plant and equipment and depreciable intangibles including
those assets acquired through the Arrangement. Acquisition-Related
and Other Acquisition-related and other expenses during the second
quarter were $0.5 million which includes acquisition expenses of
$0.3 million and $0.2 million in other expenses. For the six months
ended June 30, 2012, acquisition-related and other expenses were
$22.7 million which includes acquisition expenses of $13.2 million
as well as $8.2 million due to the required make whole payment for
the redemption of the senior secured notes from the first quarter
of the year. See "Liquidity and Capital Resources." Net Finance
Costs Net finance costs in the second quarter of 2012 were $26.7
million compared to $25.0 million in the second quarter of 2011.
Year-to-date net finance costs in 2012 totaled $46.3 million, up
from $39.3 million in the same period of 2011. The increases relate
primarily to: an $8.4 million year-to-date increase in loans and
borrowings interest expense ($4.2 million for the second quarter of
2012) due to higher debt balances; a $1.9 million change in the
fair value of non-commodity-related derivative financial
instruments for the first half of the year; and quarterly and
year-to-date increased interest on convertible debentures totaling
$6.0 million due to the Provident debentures assumed on closing of
the Arrangement. These factors were offset by a $10.9 million
unrealized gain in the second quarter of 2012 on the conversion
feature of the convertible debentures. See Notes 10 and 13 to the
Interim Financial Statements for the period ended June 30, 2012.
The change in fair value of commodity-related derivative financial
instruments has been reclassified from net finance costs to gain on
commodity-related derivative financial instruments to be included
in operational results. Income Tax Expense Deferred income tax
expense arises from the difference between the accounting and tax
basis of assets and liabilities. An income tax expense of $27.2
million was recorded in the second quarter of 2012 compared to
$15.2 million in the second quarter of 2011. Year-to-date income
tax expense in 2012 totaled $38.0 million, up from $28.8 million in
the same period of 2011. The change in income tax expense is
consistent with the change in earnings before income tax and equity
accounted investees. Liquidity & Capital Resources ($ millions)
December 31, June 30, 2012 2011 Working Capital 102.0 (343.7)(1)
Variable rate debt(2) Bank debt 785.0 313.8 Variable rate debt
swapped to fixed (380.0) (200.0) Total variable rate debt
outstanding (average rate of 2.71%) 405.0 113.8 Fixed rate debt(2)
Senior secured notes 58.0 Senior unsecured notes 642.0 642.0 Senior
unsecured term debt 75.0 75.0 Senior unsecured medium term note
250.0 250.0 Subsidiary debt 9.3 Variable rate debt swapped to fixed
380.0 200.0 Total fixed rate debt outstanding (average rate of
5.27%) 1,356.3 1,225.0 Convertible debentures(2) 644.4 299.8
Finance lease liability 5.8 5.6 Total debt and debentures
outstanding 2,411.5 1,644.2 Cash and unutilized debt facilities
728.8 235.1 (1) As at December 31, 2011, working capital includes
$310 million of current, non-revolving unsecured credit facilities.
(2) Face value. Pembina anticipates cash flow from operating
activities will be more than sufficient to meet its short-term
operating obligations and fund its targeted dividend level. In the
medium-term, Pembina expects to source funds required for capital
projects from cash and unutilized debt facilities totaling $728.8
million as at June 30, 2012. Based on its successful access to
financing in the debt and equity markets during the past several
years, Pembina believes it would likely continue to have access to
funds at attractive rates. Additionally, Pembina has reinstated its
DRIP as of the January 25, 2012 record date to help fund its
ongoing capital program (see "Trading Activity and Total Enterprise
Value" for further details). Management remains satisfied that the
leverage employed in Pembina's capital structure is sufficient and
appropriate given the characteristics and operations of the
underlying asset base. Management may make adjustments to Pembina's
capital structure as a result of changes in economic conditions or
the risk characteristics of the underlying assets. To maintain or
modify Pembina's capital structure in the future, Pembina may
renegotiate new debt terms, repay existing debt and seek new
borrowing and/or issue equity. In connection with the closing of
the Arrangement on April 2, 2012, Pembina increased its $800
million facility to $1.5 billion for a term of five years. Upon
closing of the Arrangement, Pembina used the facility, in part, to
repay Provident's revolving term credit facility of $205 million.
Further, Pembina re-negotiated its operating facility to $30
million from $50 million. Pembina's credit facilities at June 30,
2012 consisted of an unsecured $1.5 billion revolving credit
facility due March 2017 and an operating facility of $30 million
due July 2013. Borrowings on the revolving credit facility and the
operating facility bear interest at prime lending rates plus nil
percent to 1.25 percent or Bankers' Acceptances rates plus 1.00
percent to 2.25 percent. Margins on the Bankers' Acceptances rate
are based on the credit rating of Pembina's senior unsecured debt.
There are no repayments due over the term of these facilities. As
at June 30, 2012, Pembina had $785.0 million drawn on bank debt,
$19.2 million in letters of credit and $3.0 million in cash,
leaving $728.8 million of unutilized debt facilities on the $1,530
million of established bank facilities. Other debt includes $75
million in senior unsecured term debt due 2014; $175 million in
senior unsecured notes due 2014; $267 million in senior unsecured
notes due 2019; $200 million in senior unsecured notes due 2021;
and $250 million in senior unsecured medium term notes due 2021. On
April 30, 2012, the senior secured notes were redeemed. Pembina has
recognized $8.2 million due to the associated make whole payment,
which has been included in acquisition-related and other expenses
in the first quarter of the year. At June 30, 2012, Pembina had
loans and borrowing (excluding amortization, letters of credit and
finance lease liabilities) of $1,761.3 million. Pembina's senior
debt to total capital at June 30, 2012 was 26 percent. Pembina
considers the maintenance of an investment grade credit rating as
important to its ongoing ability to access capital markets on
attractive terms. On March 30, 2012, DBRS lowered the BBB (high)
ratings of the senior unsecured notes of Pembina to 'BBB'. On April
3, 2012, Standard & Poor's lowered its ratings, including its
'BBB+' long-term corporate credit rating on Pembina to 'BBB'
following closing of the Arrangement (see "Acquisition of Provident
Energy Ltd."). These ratings are not recommendations to purchase,
hold or sell the securities in as much as such ratings do not
comment as to market price or suitability for a particular
investor. There is no assurance any rating will remain in effect
for any given period of time or that any rating will not be revised
or withdrawn entirely by a rating agency in the future if, in its
judgment, circumstances so warrant. Assumption of rights related to
the Provident Debentures On closing of the Arrangement on April 2,
2012, Pembina assumed all of the rights and obligations of
Provident relating to the 5.75 percent convertible unsecured
subordinated debentures of Provident maturing December 31, 2017 ,
and the 5.75 percent convertible unsecured subordinated debentures
of Provident maturing December 31, 2018 . Outstanding Provident
debentures at April 2, 2012 were $345 million. As of June 30, 2012,
$344.7 million of the debentures are still outstanding. Capital
Expenditures 3 Months Ended 6 Months Ended June 30 June 30 ($
millions) 2012 2011 2012 2011 Development capital Conventional 55.6
10.1 64.5 26.8 Pipelines Oil Sands & Heavy 30.1 6.0 129.9 Oil
Gas Services 23.5 25.5 55.8 41.1 Midstream 55.2 11.6 55.9 101.9
Corporate/other 2.3 0.9 4.1 1.8 projects Total development 136.6
78.2 186.3 301.5 capital For the three months ended June 30, 2012,
capital expenditures were $136.6 million compared to the $78.2
million expended in the same three months of 2011. During the first
half of 2012, capital expenditures were $186.3 million compared to
$301.5 million during the same six month period in 2011. Capital
expenditures for the same period of 2011 were significantly higher
than in 2012 due to construction of the Nipisi and Mitsue pipelines
and the acquisition of midstream assets in the Edmonton, Alberta
area (related to PNT) and linefill for the Peace Pipeline system.
The majority of the capital expenditures in the second quarter and
first half of 2012 were in Pembina's Conventional Pipelines, Gas
Services and Midstream businesses. Conventional Pipelines capital
was incurred to progress the Northern NGL Expansion and on various
new connections. Gas Services capital was deployed to complete the
Musreau Deep Cut Facility and to progress the expansion of the
shallow cut facility at the Cutbank Complex and the Saturn and
Resthaven enhanced NGL extraction facilities. Midstream's capital
expenditures were primarily directed towards cavern development and
related infrastructure as well as the expansion at the Redwater
Facility. Contractual Obligations at June 30, 2012 ($ thousands)
Payments Due By Period Contractual Less than After Obligations
Total 1 year 1 - 3 years 4 - 5 years 5 years Office and vehicle
leases 305,274 25,801 52,404 56,878 170,191 Loans and borrowings
(1) 2,117,526 62,238 383,242 863,329 808,717 Convertible debentures
(1) 923,169 39,156 118,351 246,170 519,492 Construction commitments
462,428 336,483 125,945 Provisions (2) 507,707 2,358 2,664 447
502,238 Total contractual obligations 4,316,104 466,036 682,606
1,166,824 2,000,638 (1) Excluding deferred financing costs; finance
leases included under "office and vehicle leases". (2) Includes
discounted constructive and legal obligations included in the
decommissioning provision. Pembina is, subject to certain
conditions, contractually committed to the construction and
operation of the Musreau Deep Cut Facility at its Cutbank Complex,
the Musreau Shallow Cut Expansion, the Saturn Facility and the
Resthaven Facility, and to the remaining capital expenditures
associated with the Nipisi and Mitsue pipelines. See
"Forward-Looking Statements & Information." Critical Accounting
Estimates Preparing the Interim Financial Statements in conformity
with IFRS requires management to make judgments, estimates and
assumptions based on the circumstances and estimates at the date of
the financial statements and affect the application of accounting
policies and the reported amounts of assets, liabilities, income
and expenses. Actual results may differ from these estimates.
Judgments, estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognized in
the period in which the estimates are revised and in any future
periods affected. Please refer to the "Critical Accounting
Estimates" section of Pembina's MD&A for the year ended
December 31, 2011 for more information. Changes in Accounting
Principles and Practices For a discussion of future changes to
Pembina's IFRS accounting policies, see Pembina's MD&A for the
year ended December 31, 2011. Subsequent to the Arrangement,
Pembina reviewed and compared legacy Provident's accounting
policies with the Company's existing policies and determined that
there were no significant differences. Controls and Procedures
Changes in internal control over financial reporting During the
second quarter of 2012, there have been no changes in the Company's
internal control over financial reporting that have materially
affected, or are reasonably likely to materially affect, the
Company's internal control over financial reporting, except as
noted below. In accordance with the provisions of National
Instrument 52-109 - Certification of Disclosure in Issuers' Annual
and Interim Filings, management, including the CEO and CFO, have
limited the scope of their design of the Company's disclosure
controls and procedures and internal control over financial
reporting to exclude controls, policies and procedures of
Provident. Pembina acquired the assets of Provident and its
subsidiaries on April 2, 2012. Provident's contribution to the
Company's unaudited condensed consolidated financial statements for
the quarter ended June 30, 2012 was approximately 38 percent of
consolidated net revenues and approximately 49 percent of
consolidated pre-tax earnings. Additionally, Provident's current
assets and current liabilities were approximately 70 percent and 56
percent of consolidated current assets and liabilities,
respectively, and its non-current assets and non-current
liabilities were approximately 58 percent and 35 percent of
consolidated non-current assets and non-current liabilities,
respectively. The scope limitation is primarily based on the time
required to assess Provident's disclosure controls and procedures
("DC&P") and internal controls over financial reporting
("ICFR") in a manner consistent with the Company's other
operations. Further details related to the Arrangement are
disclosed in "Acquisition of Provident Energy Ltd." of this
MD&A and in Note 3 in the Notes to the Company's Interim
Financial Statements for the second quarter of 2012. Trading
Activity and Total Enterprise Value( (1)) As at and for the 3
months ended ($ thousands, except where noted) August 7, 2012(2)
June 30, 2012 June 30, 2011 Trading volume and value Total volume
(shares) 9,851,046 56,667,601 10,543,451 Average daily volume
(shares) 394,042 899,486 167,356 Value traded 263,725 1,620,184
390,673 Shares outstanding (shares) 288,697,725 287,785,195
167,470,150 Closing share price (dollars) 26.40 26.02 25.39 Market
value Shares 7,621,627 7,488,171 4,252,067 5.75% convertible
debentures (PPL.DB.C) 326,252(3) 325,922(4) 310,500(5) 5.75%
convertible debentures (PPL.DB.E)(6) 195,399(7) 192,948(8) 5.75%
convertible debentures (PPL.DB.F)(6) 187,964(9) 186,205(10) Market
capitalization 8,331,242 8,193,246 4,562,567 Senior debt 1,782,000
1,752,000 1,229,041 Total enterprise value (11) 10,113,242
9,945,246 5,791,608 (1) Trading information in this table reflects
the activity of Pembina securities on the TSX. (2) Based on 25
trading days from June 30, 2012 to August 7, 2012 inclusive. (3)
$299.7 million principal amount outstanding at a market price of
$108.85 at August 7, 2012 and with a conversion price of $28.55.
(4) $299.7 million principal amount outstanding at a market price
of $108.47 at June 29, 2012 and with a conversion price of $28.55.
(5) $300 million principal amount outstanding at a market price of
$103.50 at June 30, 2011 and with a conversion price of $28.55. (6)
Pursuant to the Arrangement, Pembina assumed the rights and
obligations of Provident debentures, which are listed on the TSX
under PPL.DB.E and PPL.DB.F. (7) $172.2 million principal amount
outstanding at a market price of $113.50 at August 7, 2012 and with
a conversion price of $24.94. (8) $172.2 million principal amount
outstanding at a market price of $112.06 at June 29, 2012 and with
a conversion price of $24.94. (9) $172.4 million principal amount
outstanding at a market price of $109.00 at August 7, 2012 and with
a conversion price of $29.53. (10) $172.4 million principal amount
outstanding at a market price of $107.98 at June 29, 2012 and with
a conversion price of $29.53. (11) Refer to "Non-GAAP Measures." As
indicated in the previous table, Pembina's total enterprise value
was $9.9 billion at June 30, 2012 and issued and outstanding shares
of Pembina rose to 287.8 million by the end of the second quarter
2012 primarily due to shares issued under the Arrangement, compared
to 167.5 million in the same period of 2011. Dividends Pembina
announced on April 12, 2012 that following closing of the
Arrangement it increased its monthly dividend rate 3.8 percent from
$0.13 per share per month (or $1.56 annualized) to $0.135 per share
per month (or $1.62 annualized). Pembina is committed to providing
increased shareholder returns over time by providing stable
dividends and, where appropriate, further increases in Pembina's
dividend, subject to compliance with applicable laws and the
approval of Pembina's Board of Directors. Pembina has a history of
delivering dividend increases once supportable over the long term
by the underlying fundamentals of Pembina's businesses as a result
of, among other things, accretive growth projects or acquisitions
(see "Forward-Looking Statements & Information"). Dividends are
payable if, as, and when declared by Pembina's Board of Directors.
The amount and frequency of dividends declared and payable is at
the discretion of the Board of Directors, which will consider
earnings, capital requirements, the financial condition of Pembina
and other relevant factors. Eligible Canadian investors may benefit
from an enhanced dividend tax credit afforded to the receipt of
dividends, depending on individual circumstances. Dividends paid to
eligible U.S. investors should qualify for the reduced rate of tax
applicable to long-term capital gains but investors are encouraged
to seek independent tax advice in this regard. DRIP Pembina has
reinstated its DRIP as of January 25, 2012. Eligible Pembina
shareholders have the opportunity to receive, by reinvesting the
cash dividends declared payable by Pembina on their shares, either:
(i) additional common shares at a discounted subscription price
equal to 95 percent of the Average Market Price (as defined in the
DRIP), pursuant to the "Dividend Reinvestment Component" of the
DRIP, or (ii) a premium cash payment (the "Premium Dividend™")
equal to 102 percent of the amount of reinvested dividends,
pursuant to the "Premium Dividend™ Component" of the DRIP.
Additional information about the terms and conditions of the DRIP
can be found at www.pembina.com. Participation in the DRIP for the
second quarter was 58 percent of common shares outstanding for
proceeds of approximately $57.0 million. Listing on the NYSE On
April 2, 2012, Pembina listed its common shares, including those
issued under the Arrangement, on the NYSE under the symbol "PBA".
Risk Factors Management has identified the primary risk factors
that could potentially have a material impact on the financial
results and operations of Pembina. Such risk factors are presented
in Pembina's MD&A and Provident's MD&A for the year ended
December 31, 2011, in Pembina's Annual Information Form ("AIF") for
the year ended December 31, 2011 and in Provident's AIF for the
year ended December 31, 2011. Pembina's MD&A and AIF are
available at www.pembina.com and in Canada under Pembina's company
profile on www.sedar.com. Provident's MD&A is available at
www.pembina.com and its AIF can be found on Pembina NGL
Corporation's company profile on www.sedar.com or on Provident's
profile at www.sec.gov. Selected Quarterly Operating Information
2012 2011 2010 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Average throughput (mbpd)
Total Conventional Throughput 433.9 466.9 422.8 430.4 411.4 390.3
375.0 361.4 370.4 Oil Sands & Heavy Oil(1) 870.0 870.0 870.0
775.0 775.0 775.0 775.0 775.0 775.0 Gas Services Processing
(mboe/d)(2) 47.5 44.1 45.3 43.6 40.9 39.4 42.1 38.9 38.9 NGL sales
volume 90.4 (mboe/d) (3) (1) Oil Sands & Heavy Oil throughput
refers to contracted capacity. (2) Converted to mboe/d from MMcf/d
at a 6:1 ratio. (3) Represents per day volumes since the closing of
the Arrangement. Selected Quarterly Financial Information 2012 2011
2010 ($ millions, except where noted) Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2
Revenue 870.9 475.5 468.1 300.6 512.4 394.9 290.7 266.1 386.5
Operations 67.7 48.4 56.3 54.4 37.6 44.8 41.9 40.0 38.2 Cost of
goods sold 641.9 299.1 307.9 145.8 364.3 254.2 161.8 148.2 262.2
Realized gains (losses) on commodity-related derivative financial
instruments (12.4) (0.3) 0.8 (0.2) 1.4 (0.8) 0.3 1.2 Operating
margin(1) 148.9 127.7 104.7 100.4 110.3 97.3 86.2 78.2 87.3
Depreciation and amortization included in operations 52.5 21.7 19.5
17.8 15.8 14.8 15.6 15.3 15.3 Unrealized gains (losses) on
commodity-related derivative financial instruments 64.8 (3.5) 0.9
0.7 3.3 0.3 1.8 (3.2) 2.4 Gross profit 161.2 102.5 86.1 83.3 97.8
82.8 72.4 59.7 74.4 Adjusted EBITDA(1) 125.9 111.4 87.0 86.8 103.3
87.2 79.1 68.1 78.0 Cash flow from operating activities 24.1 65.3
74.3 88.0 49.5 74.5 54.6 66.6 69.6 Cash flow from operating
activities per common share ($ per share) 0.08 0.39 0.44 0.53 0.30
0.45 0.33 0.41 0.43 Adjusted cash flow from operating activities(1)
89.5 98.8 57.3 90.8 81.8 76.0 62.6 67.6 63.0 Adjusted cash flow
from operating activities per common share(1) ($ per share) 0.31
0.59 0.34 0.54 0.49 0.45 0.39 0.41 0.38 Earnings for the period
80.4 32.6 45.1 30.1 48.0 42.5 55.2 28.6 37.7 Earnings per common
share ($ per share): Basic 0.28 0.19 0.27 0.18 0.29 0.25 0.34 0.19
0.23 Diluted 0.28 0.19 0.27 0.18 0.29 0.25 0.33 0.19 0.23 Common
shares outstanding (millions): Weighted average (basic) 285.3 168.3
167.4 167.6 167.3 167.0 165.0 164.0 163.2 Weighted average
(diluted) 286.0 168.9 168.2 168.2 168.0 167.6 171.7 166.9 166.2 End
of period 287.8 169.0 167.9 167.7 167.5 167.1 166.9 164.5 163.6
Dividendsdeclared 116.2 65.7 65.4 65.4 65.3 65.1 64.6 64.0 63.8
Dividends per common share ($ per share): 0.41 0.39 0.39 0.39 0.39
0.39 0.39 0.39 0.39 ((1) )Refer to "Non-GAAP measures."
Additional Information Additional information about Pembina and
legacy Provident filed with Canadian securities commissions and the
United States Securities Commission ("SEC"), including quarterly
and annual reports, Annual Information Forms (filed with the SEC
under Form 40-F), Management Information Circulars and financial
statements can be found online at www.sedar.com, www.sec.gov and
Pembina's website at www.pembina.com. Non-GAAP Measures Throughout
this MD&A, Pembina has used the following terms that are not
defined by GAAP but are used by management to evaluate performance
of Pembina and its business. Since certain Non-GAAP financial
measures may not have a standardized meaning, securities
regulations require that Non-GAAP financial measures are clearly
defined, qualified and reconciled to their nearest GAAP measure.
Concurrent with the acquisition of Provident, certain Non-GAAP
Measures definitions have changed from those previously used to
better reflect the changes in aspects of Pembina's business
activities. Earnings before interest, taxes, depreciation and
amortization ("EBITDA") EBITDA is commonly used by management,
investors and creditors in the calculation of ratios for assessing
leverage and financial performance and is calculated as results
from operating activities plus share of profit from equity
accounted investees (before tax) plus depreciation and amortization
(included in operations and general and administrative expense) and
unrealized gains or losses on commodity-related derivative
financial instruments. Adjusted EBITDA is EBITDA excluding
acquisition-related expenses in connection with the Arrangement. 3
Months Ended 6 Months Ended June 30 June 30 ($ millions, except per
share amounts) 2012 2011 2012 2011 Results from operating
activities 134.9 85.6 197.7 153.7 Share of profit from equity
accounted investees (before tax, depreciation and amortization) 1.3
4.9 2.8 9.2 Depreciation and amortization 54.2 16.1 76.7 31.2
Unrealized gain on commodity-related derivative financial
instruments (64.8) (3.3) (61.3) (3.6) EBITDA 125.6 103.3 215.9
190.5 Add: Acquisition-related expenses 0.3 21.4 Adjusted EBITDA
125.9 103.3 237.3 190.5 EBITDA per common share - basic (dollars)
0.44 0.62 0.95 1.14 Adjusted EBITDA per common share - basic
(dollars) 0.44 0.62 1.05 1.14 Adjusted earnings Adjusted earnings
is commonly used by management for assessing and comparing
financial performance each reporting period and is calculated as
earnings before tax excluding unrealized gains or losses on
derivative financial instruments and acquisition-related expenses
in connection with the Arrangement plus share of profit from equity
accounted investees (before tax). 3 Months Ended 6 Months Ended
June 30 June 30 ($ millions, except per share amounts) 2012 2011
2012 2011 Earnings before income tax and equity accounted investees
108.2 60.6 151.4 114.5 Add (deduct): Unrealized change in fair
value of derivative financial instruments (70.2) 1.2 (69.5) (2.8)
Share of (loss) profit of investments in equity accounted investees
(after tax) (0.6) 2.7 (0.4) 4.8 Tax on share of profit of
investments in equity accounted investees (0.3) 0.9 (0.2) 1.6
Acquisition-related expenses 0.3 21.4 Adjusted earnings 37.4 65.4
102.7 118.1 Adjusted earnings per common share - basic (dollars)
0.13 0.39 0.45 0.71 Adjusted cash flow from operating activities
Adjusted cash flow from operating activities is commonly used by
management for assessing financial performance each reporting
period and is calculated as cash flow from operating activities
plus the change in non-cash working capital and excluding
acquisition-related expenses. 3 Months Ended 6 Months Ended June 30
June 30 ($ millions, except per 2012 2011 2012 2011 share amounts)
Cash flow from operating 24.1 49.5 89.4 124.0 activities Add:
Change in non-cash 65.1 32.3 77.5 33.8 working capital
Acquisition-related 0.3 21.4 expenses Adjusted cash flow from 89.5
81.8 188.3 157.8 operating activities Adjusted cash flow from 0.31
0.49 0.83 0.94 operating activities per common share - basic
(dollars) 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 6 Months Ended June 30 June
30 ($ millions) 2012 2011 2012 2011 Revenue 870.9 512.4 1,346.4
907.3 Cost of sales: Operations 67.7 37.6 116.1 82.4 Cost of goods
sold 641.9 364.3 941.0 618.5 Realized gain (12.4) (0.2) (12.7) 1.2
(loss) on commodity-related derivative financial instruments
Operating margin 148.9 110.3 276.6 207.6 Depreciation and 52.5 15.8
74.2 30.6 amortization included in operations Unrealized gain on
64.8 3.3 61.3 3.6 commodity-related derivative financial
instruments Gross profit 161.2 97.8 263.7 180.6 Unrealized gain on
commodity-related derivative financial instruments has been
reclassified from net finance costs to be included in gross profit.
Total enterprise value Total enterprise value, in combination with
other measures, is used by management and the investment community
to assess the overall market value of the business. Total
enterprise value is calculated based on the market value of common
shares and convertible debentures at a specific date plus senior
debt. Management believes these supplemental Non-GAAP measures
facilitate the understanding of Pembina's results from operations,
leverage, liquidity and financial positions. Investors should be
cautioned that EBITDA, adjusted EBITDA, adjusted earnings, adjusted
cash flow from operating activities, operating margin and total
enterprise value should not be construed as alternatives to net
earnings, cash flow from operating activities or other measures of
financial results determined in accordance with GAAP as an
indicator of Pembina's performance. Furthermore, these Non-GAAP
measures may not be comparable to similar measures presented by
other issuers. Forward-Looking Statements & Information In the
interest of providing our securityholders and potential investors
with information regarding Pembina, including management's
assessment of our future plans and operations, certain statements
contained in this MD&A constitute forward-looking statements or
information (collectively, "forward-looking statements") within the
meaning of the "safe harbour" provisions of applicable securities
legislation . Forward-looking statements are typically identified
by words such as "anticipate", "continue", "estimate", "expect",
"may", "will", "project", "should", "believe", "plan", "intend",
"design", "target", "undertake", "view", "indicate", "maintain",
"explore", "entail", "schedule", "objective", "strategy", "likely",
"potential", "envision", "aim", "outlook", "propose", "goal",
"would" and similar expressions suggesting future events or future
performance. By their nature, such forward-looking statements
involve known and unknown risks, uncertainties and other factors
that may cause actual results or events to differ materially from
those anticipated in such forward-looking statements. Pembina
believes the expectations reflected in those forward-looking
statements are reasonable but no assurance can be given that these
expectations will prove to be correct and such forward-looking
statements included in this MD&A should not be unduly relied
upon. These statements speak only as of the date of the MD&A.
In particular, this MD&A contains forward-looking statements,
including certain financial outlook, pertaining to the following:
-- the future levels of cash dividends that Pembina intends to pay
to its shareholders; -- capital expenditure estimates, plans,
schedules, rights and activities and the planning, development,
construction, operations and costs of pipelines, gas service
facilities, terminalling, storage and hub facilities and other
facilities or energy infrastructure, including, but not limited to,
in relation to the PNT, the expansions at the Cutbank Complex's
Musreau Gas Plant, the proposed Resthaven Facility and the proposed
Saturn Facility, the proposed expansion plans to strengthen
Pembina's transportation service options that it provides to
producers developing the Cardium oil formation located in Central
Alberta, the expansion of throughput capacity on the Northern NGL
System, the proposed expansion of a number of existing truck
terminals and construction of new full-service terminals, the
installation of two remaining pump stations on the Nipisi and
Mitsue pipelines, the development of seven fee-for-service storage
facilities at Redwater, the Redwater fractionator expansion, and
the proposed development of a C2+ fractionators at Redwater; --
future expansion of Pembina's pipelines and other infrastructure;
-- pipeline, processing and storage facility and system operations
and throughput levels; -- oil and gas industry exploration and
development activity levels; -- Pembina's strategy and the
development of new business initiatives; -- growth opportunities;
-- expectations regarding Pembina's ability to raise capital and to
carry out acquisition, expansion and growth plans; -- treatment
under governmental regulatory regimes including environmental
regulations and related abandonment and reclamation obligations; --
future G&A expenses at Pembina; -- increased throughput
potential due to increased activity and new connections and other
initiatives on Pembina's pipelines; -- future cash flows, potential
revenue and cash flow enhancements across Pembina's businesses and
the maintenance of operating margins; -- tolls and tariffs and
transportation, storage and services commitments and contracts; --
cash dividends and the tax treatment thereof; -- operating risks
(including the amount of future liabilities related to pipeline
spills and other environmental incidents) and related insurance
coverage and inspection and integrity programs; -- the expected
capacity of the proposed Resthaven Facility and the proposed Saturn
Facility; -- expectations regarding in-service dates for new
developments, including the Resthaven Facility, the Saturn Facility
and the Northern NGL System; -- expectations regarding incremental
NGL volumes to be transported on Pembina's conventional pipelines
by the end of 2013 as a result of new developments in Pembina's Gas
Services business; -- expectations regarding in-service dates for
the seven fee-for-service storage facilities at Redwater, the
Redwater fractionator expansion project and the proposed C2+
fractionator at Redwater; -- the possibility of renegotiating debt
terms, repayment of existing debt, seeking new borrowing and/or
issuing equity; -- expectations regarding participation in
Pembina's DRIP; -- the expected impact of changes in share price on
annual share-based incentive expense; -- expectations regarding the
potential construction, expansion and conversion of downstream
infrastructure in the U.S. Midwest and Gulf Coast; -- the impact of
approval from the British Columbia Utilities Commission of
Pembina's application on the Western System; -- inventory and
pricing levels in the North American liquids market; -- Pembina's
discretion to hedge natural gas and NGL volumes; and -- competitive
conditions. Various factors or assumptions are typically applied by
Pembina in drawing conclusions or making the forecasts,
projections, predictions or estimations set out in forward-looking
statements based on information currently available to Pembina.
These factors and assumptions include, but are not limited to: --
the success of Pembina's operations; -- prevailing commodity prices
and exchange rates; -- the availability of capital to fund future
capital requirements relating to existing assets and projects,
including but not limited to future capital expenditures relating
to expansion, upgrades and maintenance shutdowns; -- future
operating costs; -- geotechnical and integrity costs associated
with the Western System; -- in respect of the proposed Saturn
Facility and the proposed Resthaven Facility and their estimated
in-service dates of fourth quarter of 2013 and the first quarter of
2014, respectively; that all required regulatory and environmental
approvals can be obtained on the necessary terms in a timely
manner, that counterparties will comply with contracts in a timely
manner; that there are no unforeseen events preventing the
performance of contracts or the completion of such facilities; that
such facilities will be fully supported by long-term firm service
agreements accounting for the entire designed throughput at such
facilities at the time of such facilities' completion; that there
are no unforeseen construction costs related to the facilities; and
that there are no unforeseen material costs relating to the
facilities which are not recoverable from customers; -- in respect
of the expansion of NGL throughput capacity on the Northern NGL
System and the estimated in-service dates with respect to the same;
that Pembina will receive regulatory approval; that counterparties
will comply with contracts in a timely manner; that there are no
unforeseen events preventing the performance of contracts by
Pembina; that there are no unforeseen construction costs related to
the expansion; and that there are no unforeseen material costs
relating to the pipelines that are not recoverable from customers;
-- in respect of the proposed C2+ fractionator at Redwater; that
Pembina will receive regulatory approval; that Pembina will reach
satisfactory long-term arrangements with customers; that
counterparties will comply with such contracts in a timely manner;
that there are no unforeseen events preventing the performance of
contracts by Pembina; that there are no unforeseen construction
costs; and that there are no unforeseen material costs relating to
the proposed fractionators that are not recoverable from customers;
-- in respect of other developments, expansions and capital
expenditures planned, including the proposed expansion of a number
of existing truck terminals and construction of new full-service
terminals, the expectation of additional NGL volumes being
transported on the conventional pipelines, the proposed expansion
of the Musreau Gas Plant's shallow cut gas processing capability,
the proposed expansion plans to strengthen Pembina's transportation
service options that it provides to producers developing the
Cardium oil formation located in central Alberta, the installation
of two remaining pump stations on the Nipisi and Mitsue pipelines,
the development of seven fee-for-service storage facilities at
Redwater, and the Redwater fractionator expansion that
counterparties will comply with contracts in a timely manner; that
there are no unforeseen events preventing the performance of
contracts by Pembina; that there are no unforeseen construction
costs; and that there are no unforeseen material costs relating to
the developments, expansions and capital expenditures which are not
recoverable from customers; -- the future exploration for and
production of oil, NGL and natural gas in the capture area around
Pembina's conventional and midstream assets, including new
production from the Cardium formation in western Alberta, the
demand for gathering and processing of hydrocarbons, and the
corresponding utilization of Pembina's assets; -- in respect of the
stability of Pembina's dividend; prevailing commodity prices,
margins and exchange rates; that Pembina's future results of
operations will be consistent with past performance and management
expectations in relation thereto; the continued availability of
capital at attractive prices to fund future capital requirements
relating to existing assets and projects, including but not limited
to future capital expenditures relating to expansion, upgrades and
maintenance shutdowns; the success of growth projects; future
operating costs; that counterparties to material agreements will
continue to perform in a timely manner; that there are no
unforeseen events preventing the performance of contracts; and that
there are no unforeseen material construction or other costs
related to current growth projects or current operations; and --
prevailing regulatory, tax and environmental laws and regulations.
The actual results of Pembina could differ materially from those
anticipated in these forward-looking statements as a result of the
material risk factors set forth below: -- the regulatory
environment and decisions; -- the impact of competitive entities
and pricing; -- labour and material shortages; -- reliance on key
alliances and agreements; -- the strength and operations of the oil
and natural gas production industry and related commodity prices;
-- non-performance or default by counterparties to agreements which
Pembina or one or more of its affiliates has entered into in
respect of its business; -- actions by governmental or regulatory
authorities including changes in tax laws and treatment, changes in
royalty rates or increased environmental regulation; --
fluctuations in operating results; -- adverse general economic and
market conditions in Canada, North America and elsewhere, including
changes in interest rates, foreign currency exchange rates and
commodity prices; -- the failure to realize the anticipated
benefits of the Arrangement; -- the failure to integrate the
businesses of Pembina and Provident; and -- the other factors
discussed under "Risk Factors" in Pembina's MD&A and
Provident's MD&A for the year ended December 31, 2011, in
Pembina's Annual Information Form ("AIF") for the year ended
December 31, 2011 and in Provident's AIF for the year ended
December 31, 2011. Pembina's MD&A and AIF are available at
www.pembina.com and in Canada under Pembina's company profile on
www.sedar.com. Provident's MD&A is available at www.pembina.com
and its AIF can be found on Pembina NGL Corporation's company
profile on www.sedar.com or on Provident's profile at www.sec.gov.
These factors should not be construed as exhaustive. Unless
required by law, Pembina does not undertake any obligation to
publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. Any
forward-looking statements contained herein are expressly qualified
by this cautionary statement. CONDENSED CONSOLIDATED INTERIM
STATEMENT OF FINANCIAL POSITION (unaudited) June 30, December ($
thousands) Note 2012 31, 2011 Assets Current assets Cash and cash
equivalents 2,981 Trade receivables and other 289,204 148,267
Derivative financial instruments 13 37,770 4,643 Inventory 102,227
21,235 432,182 174,145 Non-current assets Property, plant and
equipment 4 4,827,773 2,747,530 Intangible assets and goodwill 5
2,657,479 243,904 Investments in equity accounted 158,116 161,002
investees Derivative financial instruments 13 724 1,807 Other
receivables 5,579 10,814 7,649,671 3,165,057 Total Assets 8,081,853
3,339,202 Liabilities and Shareholders' Equity Current liabilities
Bank indebtedness 676 Trade payables and accrued 251,640 166,646
liabilities Dividends payable 38,850 21,828 Loans and borrowings 6
9,963 323,927 Derivative financial instruments 13 29,768 4,725
330,221 517,802 Non-current liabilities Loans and borrowings 6
1,745,554 1,012,061 Convertible debentures 7 607,458 289,365
Derivative financial instruments 13 38,945 12,813 Employee benefits
15,281 16,951 Share-based payments 10,837 14,060 Deferred revenue
2,411 2,185 Provisions 8 501,192 405,433 Deferred tax liabilities
559,401 106,915 3,481,079 1,859,783 Total Liabilities 3,811,300
2,377,585 Shareholders' Equity Equity attributable to shareholders:
Share capital 9 5,184,564 1,811,734 Deficit (903,922) (834,921)
Accumulated other comprehensive (15,196) (15,196) income 4,265,446
961,617 Non-controlling interest 5,107 4,270,553 961,617 Total
Liabilities and Shareholders' 8,081,853 3,339,202 Equity
See accompanying notes to
condensed consolidated interim financial statements CONDENSED
CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME (unaudited)
3 Months Ended 6 Months Ended June 30 June 30 ($ thousands, except
Note 2012 2011 2012 2011 per share amounts) Revenues 870,929
512,406 1,346,420 907,294 Cost of sales 762,099 417,746 1,131,309
731,552 Gain on 13 52,351 3,142 48,577 4,849 commodity-related
derivative financial instruments Gross profit 11 161,181 97,802
263,688 180,591 General and 25,782 12,781 43,359 27,428
administrative Acquisition-related 538 (662) 22,669 (582) and other
expense (income) 26,320 12,119 66,028 26,846 Results from operating
134,861 85,683 197,660 153,745 activities Finance income (11,175)
(536) (11,441) (911) Finance costs 37,880 25,583 57,695 40,199 Net
finance costs 10 26,705 25,047 46,254 39,288 Earnings before income
tax and equity accounted investees 108,156 60,636 151,406 114,457
Share of loss (profit) of investments in equity accounted
investees, net of tax 570 (2,652) 398 (4,842) Income tax expense
27,178 15,245 38,048 28,764 Earnings and total 80,408 48,043
112,960 90,535 comprehensive income for the period Earnings and
comprehensive income attributable to: Shareholders 80,368 48,043
112,920 90,535 Non-controlling 40 40 interest 80,408 48,043 112,960
90,535 Earnings per share attributable to the shareholders of the
Company Basic and diluted 0.28 0.29 0.50 0.54 earnings per share
(dollars) See
accompanying notes to condensed consolidated interim financial
statements CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN
EQUITY (unaudited) 6 Months Ended June 30 ($ thousands) Note 2012
2011 Share Capital Balance, beginning of period 1,811,734 1,794,536
Common shares issued on 3,283,976 acquisition Dividend reinvestment
plan 84,974 Share-based payment transactions 3,516 9,417 Debenture
conversion 366 Other (2) (10) Balance, end of period 9 5,184,564
1,803,943 Deficit Balance, beginning of period (834,921) (739,351)
Earnings for the period 112,920 90,535 attributable to shareholders
Dividends declared (181,921) (130,416) Balance, end of period
(903,922) (779,232) Other Comprehensive Income (Loss) Balance,
beginning and end of (15,196) (4,577) period Non-controlling
interest Balance, beginning of period Assumed on acquisition 5,067
Earnings attributable to 40 non-controlling interest Balance, end
of period 5,107 Total Equity 4,270,553 1,020,134
See accompanying notes to
condensed consolidated interim financial statements CONDENSED
CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS (unaudited) 3 Months
Ended 6 Months Ended June 30 June 30 ($ thousands) Note 2012 2011
2012 2011 Cash provided by (used in): Operating activities:
Earnings for the period 80,408 48,043 112,960 90,535 Adjustments
for: Depreciation and 54,165 16,071 76,677 31,175 amortization
Unrealized gain on commodity-related derivative financial
instruments 13 (64,820) (3,301) (61,273) (3,598) Net finance costs
10 26,705 25,047 46,254 39,288 Share of loss (profit) of
investments in equity accounted investees (net of tax) 570 (2,652)
398 (4,842) Deferred income tax 27,780 15,245 38,650 28,764 expense
Share-based payments 2,689 3,911 6,299 7,889 Employee future 1,898
1,203 3,329 2,401 benefits expense Other (3) (146) 467 (62) Changes
in non-cash (65,093) (32,310) (77,522) (33,761) working capital
Distributions from investments in equity accounted investees 3,588
7,237 7,733 8,685 Decommissioning (1,310) (739) (2,367) (1,775)
liability expenditures Employer future (2,500) (2,000) (5,000)
(4,000) benefit contributions Net interest paid (40,004) (26,106)
(57,198) (36,718) Cash flow from operating 24,073 49,503 89,407
123,981 activities Financing activities: Bank borrowings 200,000
266,861 40,000 Repayment of loans and (57,315) (82,588) (60,037)
(85,100) borrowings Issuance of debt 250,000 Financing fees (2,275)
(54) (5,066) (1,756) Exercise of stock 1,611 5,266 2,647 9,086
options Issue of shares under 56,973 84,974 Dividend Reinvestment
Plan Dividends paid (99,338) (65,223) (164,900) (130,339) Cash flow
from financing 99,656 (142,599) 124,479 81,891 activities Investing
activities: Net capital (131,869) (89,094) (219,103) (296,672)
expenditures Cash acquired on 8,874 8,874 acquisition Cash flow
used in (122,995) (89,094) (210,229) (296,672) investing activities
Change in cash 734 (182,190) 3,657 (90,800) Cash (bank 2,247
216,787 (676) 125,397 indebtedness), beginning of period Cash and
cash 2,981 34,597 2,981 34,597 equivalents, end of period
See accompanying notes to
condensed consolidated interim financial statements NOTES TO THE
CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (unaudited) 1.
REPORTING ENTITY Pembina Pipeline Corporation ("Pembina" or the
"Company") is an energy transportation and service provider
domiciled in Canada. The condensed consolidated interim financial
statements ("Interim Financial Statements") include the accounts of
the Company, its subsidiary companies, partnerships and any
interests in associates and jointly controlled entities as at and
for the six months ending June 30, 2012. These Interim Financial
Statements and the notes thereto have been prepared in accordance
with IAS 34 - Interim Financial Reporting. They do not include all
of the information required for full annual financial statements
and should be read in conjunction with the consolidated financial
statements of the Company as at and for the year ended December 31,
2011. The Interim Financial Statements were authorized for issue by
the Board of Directors on August 9, 2012. Pembina owns or has
interests in pipelines that transport conventional crude oil and
natural gas liquids, oil sands and heavy oil pipelines, gas
gathering and processing facilities, and a natural gas liquids
infrastructure and logistics business. Facilities are located in
Canada and in the U.S. Pembina also offers midstream services that
span across its operations. 2. SIGNIFICANT ACCOUNTING POLICIES The
accounting policies are set out in the December 31, 2011 financial
statements. Those policies have been applied consistently to all
periods presented in these Interim Financial Statements except for
an addition to an accounting policy as a result of the acquisition
of Provident Energy Ltd. which is provided below. Inventories
Inventories are measured at the lower of cost and net realizable
value and consist primarily of crude oil and natural gas liquids.
The cost of inventories is determined using the weighted average
costing method and includes direct purchase costs and when
applicable, costs of production, extraction, fractionation costs,
and transportation costs. Net realizable value is the estimated
selling price in the ordinary course of business less the estimated
selling costs. All changes in the value of the inventories are
reflected in inventories and cost of sales. 3. ACQUISITION On April
2, 2012, Pembina acquired all of the outstanding Provident Energy
Ltd. ("Provident") common shares (the "Provident Shares") in
exchange for Pembina common shares valued at approximately $3.3
billion (the "Arrangement"). Provident shareholders received 0.425
of a Pembina common share for each Provident Share held for a total
of 116,535,750 Pembina common shares. On closing, Pembina assumed
all of the rights and obligations of Provident relating to the 5.75
percent convertible unsecured subordinated debentures of Provident
maturing December 31, 2017, and the 5.75 percent convertible
unsecured subordinated debentures of Provident maturing December
31, 2018 (collectively, the "Provident Debentures"). The face value
of the outstanding Provident Debentures at April 2, 2012 was $345
million. The debentures remain outstanding and continue with terms
and maturity as originally set out in their respective indentures.
Pursuant to the Arrangement, Provident amalgamated with a
wholly-owned subsidiary of Pembina and has continued under the name
"Pembina NGL Corporation". The results of the acquired business are
included as part of the Midstream business. The preliminary
purchase price allocation based on assessed fair values is
estimated as follows: ($ millions) Cash 9 Trade receivables and
other 195 Inventory 87 Property, plant and equipment 1,988
Intangible assets and goodwill (including $1,759 goodwill) 2,422
Trade payables and accrued liabilities (249) Derivative financial
instruments - current (53) Derivative financial instruments -
non-current (36) Loans and borrowings (215) Convertible debentures
(317) Provisions and other (128) Deferred tax liabilities (414)
Non-controlling interest (5) 3,284 The determination of fair values
and the allocation of the purchase price is based upon a
preliminary independent valuation which is pending finalization.
The primary drivers that generate goodwill are synergies and
business opportunities from the integration of Pembina and
Provident and the acquisition of a talented workforce. None of the
goodwill recognized is expected to be deductible for income tax
purposes. Upon closing of the Arrangement, Pembina repaid
Provident's revolving term credit facility of $205 million. The
Company has recognized $21.4 million in acquisition-related
expenses. These expenses are included in acquisition-related and
other expenses in the Condensed Consolidated Interim Statement of
Comprehensive Income. The Pembina Shares were listed and began
trading on the NSYE under the symbol "PBA" on April 2, 2012.
Revenues of the Provident business for the period from the
acquisition date of April 2, 2012 to June 30, 2012, net of
intersegment eliminations, were $328.8 million. Net earnings, net
of intersegment eliminations, for the same period were $35.9
million. Unaudited proforma consolidated revenues (prepared as if
the Provident acquisition had occurred on January 1, 2012) for the
six months ended June 30, 2012 are $1,886.5 million and net
earnings for the same period are $159.9 million. On closing of the
Arrangement, the following significant subsidiaries were acquired:
(percentages) Ownership Interest Pembina NGL Corporation 100
Pembina Facilities (NGL ) LP 100 Pembina Infrastructure and
Logistics LP 100 Pembina Empress NGL Partnership 100 Pembina
Resource Services Canada 100 Pembina Resource Services (U.S.A.) 100
Three Star Trucking Ltd. 67 4. PROPERTY, PLANT AND EQUIPMENT
Land Facilities Linefill Assets and and and Under Land Equipment
Other Construction ($ thousands) Rights Pipelines Total Cost
Balance at December 31, 200,726 3,603,950 2011 67,219 2,500,027
528,620 (1) 307,358 (1) Acquisition 18,093 280,481 1,281,091
321,287 87,319 1,988,271 (Note 3) Additions 2 (99) 104,051 5,422
76,912 186,288 Change in (28,811) (3,156) (31,967) decommissioning
provision Capitalized 3,173 696 1,977 5,846 interest Transfers 22
(67,116) 106,866 (18,126) (21,646) Disposals and (5,000) (917)
(621) 349 (6,189) other Balance at June 80,336 2,686,738 2,017,547
509,658 451,920 5,746,199 30, 2012 Depreciation Balance at 4,088
707,095 92,998 52,239 856,420 December 31, 2011 Depreciation 140
35,017 20,604 7,516 63,277 Transfers 1,217 24,328 (25,545)
Disposals and (567) (76) (628) (1,271) other Balance at June 4,228
742,762 137,854 33,582 918,426 30, 2012 Carrying amounts December
31, 63,131 1,792,932 435,622 148,487 307,358 2,747,530 2011 June
30, 2012 76,108 1,943,976 1,879,693 476,076 451,920 4,827,773 (1)
$1.5 millionwas reclassified from inventory to Linefill and Other
at December 31, 2011. Pipeline assets are generally depreciated
using the straight line method over 5 to 75 years (an average of 49
years) or declining balance method at rates ranging from 3 percent
to 48 percent per annum (an average rate of 15 percent per annum).
Facilities and equipment are depreciated using the straight line
method over 3 to 75 years (at an average rate of 34 years) or
declining balance method at rates ranging from 3 percent to 37
percent (at an average rate of 13 percent per annum). Other assets
are depreciated using the straight line method over 2 to 45 years
(an average of 10 years) or declining balance method at rates
ranging from 3 percent to 37 percent (at an average rate of 8
percent per annum). Commitments At June 30, 2012, the Company has
contractual commitments for the acquisition and or construction of
property, plant and equipment of $462.4 million (December 31, 2011:
$364.3 million). 5. INTANGIBLE ASSETS AND GOODWILL Other
Goodwill Intangibles Total ($ thousands) Cost Balance at December
31, 2011 222,670 23,038 245,708 Acquisition (Note 3) 1,759,356
662,732 2,422,088 Additions and other 5,000 5,000 Balance at June
30, 2012 1,982,026 690,770 2,672,796 Amortization Balance at
December 31, 2011 1,804 1,804 Amortization 13,513 13,513 Balance at
June 30, 2012 15,317 15,317 Carrying amounts December 31, 2011
222,670 21,234 243,904 June 30, 2012 1,982,026 675,453 2,657,479
Amortization is recognized in profit or loss on a straight-line or
declining balance basis over the estimated useful lives of
depreciable intangible assets from the date that they are available
for use. The estimated useful lives of other intangible assets with
finite useful lives range from 3 to 33 years (an average of 9
years). The preliminary allocation of the aggregate carrying amount
of intangible assets to each cash generating unit is as follows:
June 30, December 31, ($ thousands) 2012 2011 Conventional
Pipelines 194,370 194,370 Oil Sands and Heavy Oil 33,300 28,300 Gas
Services 20,885 21,234 Midstream 2,408,924 2,657,479 243,904 The
allocation is subject to change upon finalization of purchase price
analysis of the acquisition. See Note 3. 6. LOANS AND
BORROWINGS Carrying value terms and debt repayment schedule Terms
and conditions of outstanding loans were as follows: ($ thousands)
Carrying amount (3) Available Nominal Year of June 30, Dec. 31,
facilities interest maturity 2012 2011 rate prime + 0.50 Operating
or BA(2) + facility(1) 30,000 1.50 2013 3,139 prime + Revolving
0.50 unsecured credit or BA(2) + facility 1,500,000 1.50 2017
780,230 309,981 Senior secured 7.38 57,499 notes Senior unsecured
175,000 5.99 2014 174,570 174,462 notes - Series A Senior unsecured
200,000 5.58 2021 196,810 196,638 notes - Series C Senior unsecured
267,000 5.91 2019 265,504 265,403 notes - Series D Senior unsecured
75,000 6.16 2014 74,729 74,658 term facility Senior unsecured
250,000 4.89 2021 248,636 248,558 medium term notes Subsidiary debt
9,279 4.98 2014 9,279 Finance lease 5,759 5,650 liabilities Total
2,506,279 1,755,517 1,335,988 interest-bearing liabilities Less
current (9,963) (323,927) portion Total 1,745,554 1,012,061
non-current ((1)) Operating facility expected to be renewed on
an annual basis. ((2)) Bankers Acceptance. ((3)) Deferred
financing fees are all classified as non-current. Non-current
carrying amount of facilities are net of deferred financing fees.
7. CONVERTIBLE DEBENTURES ($ thousands) Series C Series E
Series F Total - 5.75% - 5.75% - 5.75% Conversion $28.55 $24.94
$29.53 price (dollars) Interest May 31 and June 30 and June 30 and
payable November 30 December 31 December 31 semi-annually in
arrears on: November 30, December 31, December 31, Maturity date
2020 2017 2018 Balance, 289,365 289,365 December 31, 2011 Assumed
on 158,471 158,343 316,814 acquisition (1) (Note 3) Conversions
(54) (264) (14) (332) and redemptions Accretion 280 229 509
Deferred 584 275 243 1,102 financing fee (net amortization)
Balance, June 289,895 158,762 158,801 607,458 30, 2012 ((1))
Excludes conversion feature of convertible debentures The
Company may, at its option on or after December 31, 2013 and prior
to December 31, 2015, elect to redeem the Series E debentures in
whole or in part, provided that the volume weighted average trading
price of the common price of the shares on the TSX during the 20
consecutive trading days ending on the fifth trading day preceding
the date on which the notice of redemption is given is not less
than 125 percent of the conversion price of the Series E
debentures. On or after December 31, 2015, the Series E debentures
may be redeemed in whole or in part at the option of the Company at
a price equal to their principal amount plus accrued and unpaid
interest. Any accrued unpaid interest will be paid in cash. The
Company may, at its option on or after December 31, 2014 and prior
to December 31, 2016, elect to redeem the Series F debentures in
whole or in part, provided that the volume weighted average trading
price of the common price of the shares on the TSX during the 20
consecutive trading days ending on the fifth trading day preceding
the date on which the notice of redemption is given is not less
than 125 percent of the conversion price of the Series F
debentures. On or after December 31, 2016, the Series F debentures
may be redeemed in whole or in part at the option of the Company at
a price equal to their principal amount plus accrued and unpaid
interest. Any accrued unpaid interest will be paid in cash. The
Company retains a cash conversion option on the Series E and F
convertible debentures, allowing the Company to pay cash to the
converting holder of the debentures, at the option of the Company.
For convertible debentures with a cash conversion option, the
equity conversion option is recognized as an embedded derivative
and accounted for as a stand-alone derivative financial instrument,
measured at fair value using an option pricing model. 8.
PROVISIONS ($ thousands) Total Balance at December 31,
2011(1) 416,153 Unwinding of discount rate 5,777 Incurred during
the period 1,766 Assumed on acquisition (Note 3) 124,579
Decommissioning liabilities settled during the period (2,367)
Change in rates (30,299) Change in estimate and other (7,902) Total
507,707 Less current portion (included in accrued liabilities)
6,515 501,192 ((1)) Includes current provision of $10,720 at
December 31, 2011 (included in accrued liabilities). 9. SHARE
CAPITAL ($ thousands, except share Number Share Capital amounts)
Balance December 31, 2011 167,908,271 1,811,734 Issued on
acquisition (Note 3) 116,535,750 3,283,976 Share based payment
transactions 175,203 3,516 Dividend reinvestment plan 3,151,670
84,974 Other 14,301 364 Balance June 30, 2012 287,785,195(1)
5,184,564 (1) Weighted average number of common shares outstanding
for the three months ended June 30, 2012 is 285.3 million (June 30,
2011: 167.3 million). On a fully diluted basis, the weighted
average number of common shares outstanding for the three months
ended June 30, 2012 is 286.0 million (June 30, 2011: 168.0
million).Weighted average number of common shares outstanding for
the six months ended June 30, 2012 is 226.8 million (June 30, 2011:
167.2 million). On a fully diluted basis, the weighted average
number of common shares outstanding for the six months ended June
30, 2012 is 250.7 million (June 30, 2011: 167.8 million).
Dividends The following dividends were declared and paid by
the Company: 6 Months Ended June 30 ($ thousands) 2012 2011 $0.80
per qualifying common share (2011: $0.78) 181,921 130,416 On July 9
, 2012, Pembina's Board of Directors declared a dividend for July
of $39.0 million, representing $0.135 per qualifying common share
($1.62 annualized). 10. NET FINANCE COSTS 3 Months Ended 6 Months
Ended June 30 June 30 ($ thousands) 2012 2011 2012 2011 Interest
income from: Related parties 220 263 410 Bank deposits 298 284 301
389 Foreign exchange gains 32 112 Change in fair value of
conversion 10,877 10,877 feature of convertible debentures Finance
income 11,175 536 11,441 911 Interest expense on financial
liabilities measured at amortized cost: Loans and borrowings 18,120
13,967 33,536 25,132 Convertible debentures 10,579 4,601 15,184
9,168 Finance leases 105 97 210 193 Unwinding of discount 3,327
2,393 5,801 4,905 Change in fair value of non-commodity-related
derivative financial instruments 5,475 4,525 2,659 801 Foreign
exchange losses 274 305 Finance costs 37,880 25,583 57,695 40,199
Net finance costs 26,705 25,047 46,254 39,288 11. OPERATING
SEGMENTS 3 Months Ended June Oil Sands Corporate & 30, 2012
Conventional & Gas Midstream Intersegment ($ thousands)
Pipelines(1) Heavy Oil Services (3) Eliminations Total Revenue:
Pipeline 78,410 39,412 (6,875) 110,947 transportation NGL product
and services, terminalling, storage and hub services 737,770
737,770 Gas Services 22,212 22,212 Total revenue 78,410 39,412
22,212 737,770 (6,875) 870,929 Operations 29,886 11,604 7,172
19,640 (624) 67,678 Cost of goods sold, including product purchases
648,794 (6,875) 641,919 Realized gain (loss) on commodity-related
derivative financial instruments (1,033) (11,436) (12,469)
Operating margin 47,491 27,808 15,040 57,900 624 148,863
Depreciation and amortization (operational) 12,179 4,938 4,332
31,053 52,502 Unrealized gain (loss) on commodity-related
derivative financial instruments 233 64,587 64,820 Gross profit
35,545 22,870 10,708 91,434 624 161,181 Depreciation 1,664 1,664
included in general and administrative Other general and 2,225 968
1,456 5,488 13,981 24,118 administrative Acquisition-related (311)
519 100 230 538 and other Reportable segment results from operating
activities 33,631 21,383 9,252 85,846 (15,251) 134,861 Net finance
costs 1,760 563 1,964 4,128 18,290 26,705 Reportable segment
earnings before tax and income from equity accounted investees
31,871 20,820 7,288 81,718 (33,541) 108,156 Share of loss (profit)
of investments in equity accounted investees, net of tax 570 570
Reportable segment 616,803 1,097,240 539,565 4,493,465(2) 1,334,780
8,081,853 assets Capital expenditures 55,632 23,459 55,240 2,277
136,608 Reportable segment 293,529 83,397 43,816 771,086 2,619,472
3,811,300 liabilities (1) 4.5 percent of Conventional Pipelines
revenue is under regulated tolling arrangements. (2) Includes
investments in equity accounted investees of $158.1 million. NGL
product and services, terminalling, storage and hub services (3)
revenue includes $28.7 million associated with U.S. midstream
sales. Oil Corporate & 3 Months Ended June Sands &
Intersegment 30, 2011 Conventional Heavy Gas Eliminations ($
thousands) Pipelines(1) Oil Services Midstream Total Revenue:
Pipeline transportation 72,407 27,707 100,114 NGL product and
services, terminalling, storage and hub services 393,679 393,679
Gas Services 18,613 18,613 Total revenue 72,407 27,707 18,613
393,679 512,406 Operations 22,177 7,753 5,193 2,474 37,597 Cost of
goods sold, including product purchases 364,356 364,356 Realized
gain (loss) on commodity-related derivative financial instruments
(159) (159) Operating margin 50,071 19,954 13,420 26,849 110,294
Depreciation and 10,356 2,037 2,512 888 15,793 amortization
(operational) Unrealized gain (loss) on commodity-related
derivative financial instruments 117 3,184 3,301 Gross profit
39,832 17,917 10,908 29,145 97,802 Depreciation included in general
and administrative 279 279 Other general and 1,412 553 938 1,098
8,501 12,502 administrative Acquisition-related (497) (107) (1) (9)
(48) (662) and other Reportable segment results from operating
activities 38,917 17,471 9,971 28,056 (8,732) 85,683 Net finance
costs 1,743 358 145 38 22,763 25,047 Reportable segment earnings
before tax and income from equity accounted investees 37,174 17,113
9,826 28,018 (31,495) 60,636 Share of loss (profit) of investments
in equity accounted investees, net of tax (2,652) (2,652)
Reportable segment 850,314 947,780 392,609 243,296(2) 621,671
3,055,670 assets Capital expenditures 10,088 30,135 25,467 11,564
942 78,196 Reportable segment 231,460 75,750 39,684 5,651 1,682,991
2,035,536 liabilities (1) 10.3 percent of Conventional Pipelines
revenue is under regulated tolling arrangements. (2) Includes
investments in equity accounted investees of $162,753. Oil 6 Months
Ended June Sands & Corporate & 30, 2012 Conventional Heavy
Gas Midstream Intersegment ($ thousands) Pipelines(1) Oil Services
(2) Eliminations Total Revenue: Pipeline 160,581 82,509 (6,875)
236,215 transportation NGL product and services, terminalling,
storage and hub services 1,068,942 1,068,942 Gas Services 41,263
41,263 Total revenue 160,581 82,509 41,263 1,068,942 (6,875)
1,346,420 Operations 57,461 24,606 13,198 22,149 (1,260) 116,154
Cost of goods sold, 947,848 (6,875) 940,973 including product
purchases Realized gain (loss) on commodity-related derivative
financial instruments (1,189) (11,507) (12,696) Operating margin
101,931 57,903 28,065 87,438 1,260 276,597 Depreciation and 24,124
9,829 7,494 32,735 74,182 amortization (operational) Unrealized
gain (loss) on commodity-related derivative financial instruments
(2,752) 64,025 61,273 Gross profit 75,055 48,074 20,571 118,728
1,260 263,688 Depreciation included in general and administrative
2,495 2,495 Other general and 3,123 1,907 1,977 6,775 27,082 40,864
administrative Acquisition-related 923 388 11 99 21,248 22,669 and
other Reportable segment results from operating activities 71,009
45,779 18,583 111,854 (49,565) 197,660 Net finance costs 3,364
1,040 2,134 4,170 35,546 46,254 Reportable segment earnings before
tax and income from equity accounted investees 67,645 44,739 16,449
107,684 (85,111) 151,406 Share of loss (profit) of investments in
equity accounted investees, net of tax 398 398 Capital expenditures
64,472 6,041 55,762 55,930 4,083 186,288 (1) 4.5 percent of
Conventional Pipelines revenue is under regulated tolling
arrangements. NGL product and services, terminalling, storage and
hub services (2) revenue includes $28.7 million associated with
U.S. midstream sales. Oil 6 Months Ended June Sands & Corporate
& 30, 2011 Conventional Heavy Gas Intersegment ($ thousands)
Pipelines(1) Oil Services Midstream Eliminations Total Revenue:
Pipeline 141,664 58,253 199,917 transportation NGL product and
services, terminalling, storage and hub services 673,790 673,790
Gas Services 33,587 33,587 Total revenue 141,664 58,253 33,587
673,790 907,294 Operations 49,006 18,959 9,883 4,568 82,416 Cost of
goods 618,489 618,489 sold, including product purchases Realized
gain (loss) on commodity-related derivative financial instruments
1,455 (204) 1,251 Operating margin 94,113 39,294 23,704 50,529
207,640 Depreciation and 20,112 3,980 4,800 1,755 30,647
amortization (operational) Unrealized gain (loss) on
commodity-related derivative financial instruments 4,652 (1,054)
3,598 Gross profit 78,653 35,314 18,904 47,720 180,591 Depreciation
included in general and administrative 528 528 Other general and
2,698 1,150 2,079 2,285 18,688 26,900 administrative
Acquisition-related (455) (107) 5 6 (31) (582) and other Reportable
segment results from operating activities 76,410 34,271 16,820
45,429 (19,185) 153,745 Net finance costs 3,544 674 458 39 34,573
39,288 Reportable segment earnings before tax and income from
equity accounted investees 72,866 33,597 16,362 45,390 (53,758)
114,457 Share of loss (profit) of investments in equity accounted
investees, net of tax (4,842) (4,842) Capital expenditures 26,786
129,898 41,093 101,909 1,792 301,478 (1) 11.5 percent of
Conventional Pipelines revenue is under regulated tolling
arrangements. 12. SHARE BASED PAYMENTS Long-term share unit award
incentive plan((1)) Grant date Restricted Share Units ("RSU")(3)
Contractual life to Officers,Non-Officers(2) and Directors of
options (Number of units in thousands) Units January 1, 2012 188
3.0 Years April 2, 2012 (on acquisition) 201 2.2 Years Grant date
Performance Share Units ("PSU")(4) Contractual life to Officers,
Non-Officers(2) and Directors of options (Number of units in
thousands) Units January 1, 2012 187 3.0 Years April 2, 2012 (on
acquisition) 177 2.2 Years Distribution Units are granted in
addition to RSU and PSU grants (1) based on notional accrued
dividends from RSU and PSU granted but not paid. (2) Non-Officers
defined as senior selected positions within the Company. One third
vests on the first anniversary of the grant date, one (3) third
vests on the second anniversary of the grant date, and one third
vests on the third anniversary of the grant date. Vest on the third
anniversary of the grant date. Actual PSUs (4) awarded is based on
the trading value of the shares and performance of the Company.
Disclosure of share option plan The number and weighted average
exercise prices of share options are as follows: Number of Options
Weighted Average Exercise Price Outstanding at December 2,674,380
20.24 31, 2011 Granted 74,100 29.52 Exercised (175,203) 15.69
Forfeited (80,493) 24.34 Outstanding as at June 2,492,784 20.71 30,
2012 13. FINANCIAL INSTRUMENTS The following table is a summary of
the net derivative financial instrument liability: As at As at June
30, December 31, ($ thousands) 2012 2011 Frac spread related
Natural gas (17,235) Propane 11,482 Butane 9,681 Condensate 8,001
Foreign exchange (1,149) Sub-total frac spread related 10,780
Management of exposure embedded in 397 2,267 physical contracts and
other Corporate Power 1,593 4,183 Interest rate (17,747) (17,538)
Other derivative financial instruments Conversion feature of
convertible (18,835) debentures Redemption liability related to
(6,407) acquisition of subsidiary Net derivative financial
instruments (30,219) (11,088) liability In conjunction with the
Arrangement, the Company acquired a two-thirds ownership interest
in Provident's subsidiary, Three Star Trucking Ltd. ("Three Star"),
which included a redemption liability that represents a put option,
held by the non-controlling interest of Three Star, to sell the
remaining one-third interest of the business to the Company after
the third anniversary of the original acquisition date by Provident
(October 3, 2014). The put price to be paid by the Company for the
residual interest upon exercise is based on a multiple of Three
Star's earnings during the period prior to exercise, adjusted for
associated capital expenditures and debt based on management
estimates. On acquisition, the Company recorded a $6.2 million
redemption liability associated with this put option. The
redemption liability will be accreted and subsequently fair valued
at each reporting date with changes in the value flowing through
profit and loss. At June 30, 2012 the fair value of the redemption
liability was determined to be $6.4 million, resulting in an
unrealized loss of $0.2 million in the second quarter of 2012
recorded in net finance costs. Also in conjunction with the
Arrangement, the Company assumed all of the rights and obligations
of Provident relating to the Provident Debentures which included a
$29.7 million liability for the conversion feature of the Provident
Debentures. These convertible debentures contain a cash conversion
option which is measured at fair value through profit and loss at
each reporting date, with any unrealized gains or losses arising
from fair value changes reported in the consolidated statement of
comprehensive income. This resulted in the Company recording a gain
of $10.9 million on the revaluation on the conversion feature of
convertible debentures in profit and loss in the second quarter of
2012 in net finance costs. The following tables show the impact on
gain (loss) on derivative financial instruments if the underlying
risk variables of the derivative financial instruments changed by a
specified amount, with other variables held constant. As at June
30, 2012 ($ + Change - Change thousands) Frac spread related
Natural gas (AECO +/- $1.00 per gj) 12,336 (12,336) NGLs (includes
propane, (Belvieu +/- U.S. $0.10 per (8,377) 8,377 butane) gal)
Foreign exchange (U.S.$ (FX rate +/- $0.05) (6,868) 6,868 vs. Cdn$)
Management of exposure embedded in physical contracts Crude oil
(WTI +/- $5.00 per bbl) (5,601) 5,601 NGLs (includes propane,
(Belvieu +/- U.S. $0.10 per 4,920 (4,920) butane and condensate)
gal) Corporate Interest rate (Rate +/- 100 basis points) 946 (946)
Power (AESO +/- $5.00 per MW/h) 3,217 (3,217) Conversion feature of
(Pembina share price +/- 2,101 (1,971) convertible debentures $0.50
per share) Commodity-Related 3 Months Ended 6 Months Ended
Derivative June 30 June 30 Financial Instruments 2012 2011 2012
2011 ($ thousands, Volume except volumes) $ (1) $ Volume $ Volume $
Volume Realized (loss) gain on commodity-related derivative
financial instruments Frac spread related Crude oil (1,997) 0.1
(1,997) 0.1 Natural gas (7,762) 4.6 (7,762) 4.6 Propane 1,727 0.2
1,727 0.2 Butane 769 0.3 769 0.3 Condensate 272 0.2 272 0.2
Sub-total frac (6,991) (6,991) spread related Corporate Power
(1,608) (159) (1,764) 1,455 Management of exposure embedded in
physical contracts and other (3,870) 0.3 (3,941) 0.5 (204) Realized
(loss) (12,469) (159) (12,696) 1,251 gain on derivative financial
instruments Unrealized gain on commodity-related derivative
financial instruments 64,820 3,301 61,273 3,598 Gain on
commodity-related derivative financial instruments 52,351 3,142
48,577 4,849 The above table represents aggregate volumes that were
bought/sold (1) over the periods. Crude oil and NGL volumes are
listed in millions of barrels and natural gas is listed in millions
of gigajoules. For non-commodity-related derivative financial
instruments see Note 10, Net Finance Costs. CORPORATE INFORMATION
............................................................................................................................................................................................................................................
HEAD OFFICE Pembina Pipeline Corporation Suite 3800, 525 - 8th
Avenue S.W. Calgary, Alberta T2P 1G1 AUDITORS KPMG LLP Chartered
Accountants Calgary, Alberta TRUSTEE, REGISTRAR & TRANSFER
AGENT Computershare Trust Company of Canada Suite 600, 530 - 8th
Avenue SW Calgary, Alberta T2P 3S8 1-800-564-6253 STOCK EXCHANGE
Pembina Pipeline Corporation TSX listing symbols for: Common
shares: PPL Convertible debentures: PPL.DB.C, PPL.DB.E, PPL.DB.F
NYSE listing symbol for: Common shares: PBA
Pembina Pipeline
Corporation CONTACT: INVESTOR INQUIRIES Phone: (403) 231-3156Fax:
(403) 237-0254Toll Free 1-855-880-7404Email:
investor-relations@pembina.comWebsite: www.pembina.com
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