Pembina Pipeline Corporation 2012 second quarter results
Pembina releases first consolidated results following acquisition of
Provident Energy Ltd.; continues building its fee-for-service business
All financial figures are in Canadian dollars unless noted otherwise.
This report contains forward-looking statements and information that
are based on Pembina Pipeline Corporation’s current expectations,
estimates, projections and assumptions in light of its experience and
its perception of historical trends. Actual results may differ
materially from those expressed or implied by these forward-looking
statements. Please see” Forward-Looking Statements & Information” for
more details. This report also refers to financial measures that are
not defined by Canadian Generally Accepted Accounting Principles
(“GAAP”). For more information about the measures which are not defined
by GAAP, see “Non-GAAP Measures.”
CALGARY, Aug. 9, 2012 /PRNewswire/ – On April 2, 2012 Pembina Pipeline
Corporation (“Pembina” or the “Company”) completed its acquisition of
Provident Energy Ltd. (“Provident”) (the “Arrangement”). The amounts
disclosed herein for the three and six month periods ending June 30,
2012 reflect results of the post-Arrangement Pembina from April 2, 2012
together with results of legacy Pembina alone, excluding Provident,
from January 1 through April 1, 2012. The comparative figures reflect
solely the 2011 results of legacy Pembina. For further information with
respect to the acquisition transaction, please refer to Note 3 of the
unaudited interim condensed consolidated financial statements for the
period ended June 30, 2012.
Financial & Operating Overview
(unaudited)
($ millions, except 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”) (TSX Trading Symbol: PPL.DB.E), and the 5.75
percent convertible unsecured subordinated debentures of Provident
maturing December 31, 2018 (“Series F Debentures”) (TSX Trading Symbol:
PPL.DB.F). On closing of the Arrangement, Pembina listed its common
shares, including those issued under the Arrangement, on the NYSE under
the symbol “PBA”. Pursuant to the Arrangement, Provident amalgamated
with a wholly-owned subsidiary of Pembina and was continued under the
name “Pembina NGL Corporation”.
The consolidated financial statements contained in this MD&A and the
Interim Financial Statements include Pembina’s post-Arrangement results
from April 2, 2012. As such, the amounts disclosed herein for the three
and six month periods ending June 30, 2012 reflect results of the
post-Arrangement Pembina from April 2, 2012 together with results of
legacy Pembina alone, excluding Provident, from January 1 through April
1, 2012. The comparative figures reflect solely the 2011 results of
legacy Pembina. The results of the business acquired through the
Arrangement are reported as part of the Company’s Midstream business.
For further information with respect to the Arrangement, please refer
to Note 3 to the Interim Financial Statements.
About Pembina
Calgary-based Pembina Pipeline Corporation is a leading transportation
and midstream service provider with nearly 60 years serving North
America’s energy industry. Pembina owns and operates: pipelines that
transport conventional crude oil and natural gas liquids produced in
western Canada; oil sands and heavy oil pipelines; gas gathering and
processing facilities; and, an oil and natural gas liquids
infrastructure and logistics business. With facilities strategically
located in western Canada and in natural gas liquids markets in eastern
Canada and the U.S., Pembina also offers a full spectrum of midstream
and marketing services that span across its operations. Pembina’s
integrated assets and commercial operations enable it to offer services
needed by the energy sector along each step of the hydrocarbon value
chain.
Pembina is a trusted member of the communities in which it operates and
is committed to generating value for its investors through operational
excellence: running its businesses in a safe, environmentally
responsible manner that is respectful of community stakeholders.
Strategy
Pembina’s goal is to provide highly competitive and reliable returns to
investors through monthly dividends while enhancing the long-term value
of its common shares. To achieve this, Pembina’s strategy is to:
-- Generate value by providing customers with safe,
cost-effective, reliable services.
-- Diversify Pembina's asset base to enhance profitability. A
diverse portfolio provides Pembina with the ability to respond
to market conditions, reduce risk and increase opportunities to
leverage existing businesses. A priority is placed on
developing businesses that support Pembina's core competency -
operating crude oil and NGL transportation systems, and gas
gathering, processing and fractionation infrastructure - which
allow for expansion, vertical integration and accretive growth.
-- Implement growth projects and conduct existing operations in a
safe and environmentally responsible manner. Growth is expected
to occur through expansion of existing businesses, additional
acquisitions and the development of new services. Pembina's
investment criteria include pursuing projects or assets that
are expected to generate increased cash flow per share and
capture long-life, economic hydrocarbon reserves.
-- Maintain a strong balance sheet through the application of
prudent financial management to all business decisions.
Pembina is structured in four businesses: Conventional Pipelines, Oil
Sands & Heavy Oil, Gas Services and Midstream, which are described in
their respective sections of this MD&A.
Common Abbreviations
The following is a list of abbreviations that may be used in this MD&A:
Measurement Other
bbl barrel AECO Alberta gas
trading price
kbbls thousands of AESO Alberta Electric
barrels Systems Operator
mmbbls millions of BC British Columbia
barrels
bpd barrels per day DRIP Premium
Dividend(TM)
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 (TSX: PPL.DB.E), and the 5.75 percent convertible
unsecured subordinated debentures of Provident maturing December 31,
2018 (TSX: PPL.DB.F). Outstanding Provident debentures at April 2, 2012
were $345 million. As of June 30, 2012, $344.7 million of the
debentures are still outstanding.
Capital Expenditures
3 Months Ended 6 Months Ended
June 30 June 30
($ 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(TM)”) equal to 102 percent of the
amount of reinvested dividends, pursuant to the “Premium Dividend(TM)
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
SOURCE Pembina Pipeline Corporation
