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