Record adjusted EBITDA and adjusted cash flow from
operating activities per share
All financial figures are in Canadian dollars unless noted
otherwise. This report contains forward-looking statements and
information that are based on Pembina Pipeline Corporation's
("Pembina" or the "Company") current expectations, estimates,
projections and assumptions in light of its experience and its
perception of historic trends. Actual results may differ materially
from those expressed or implied by these forward-looking
statements. Please see "Forward-Looking Statements &
Information" in the accompanying Management's Discussion &
Analysis ("MD&A") for more details. This report also refers to
financial measures that are not defined by Generally Accepted
Accounting Principles ("GAAP"). For more information about the
measures which are not defined by GAAP, see "Non-GAAP Measures" of
the accompanying MD&A.
CALGARY, Mar. 1, 2013 /CNW/ - On April 2, 2012 Pembina completed its acquisition
of Provident Energy Ltd. ("Provident") (the "Acquisition"). The
amounts disclosed herein for the three and twelve month periods
ending December 31, 2012 reflect
results of the post-Acquisition Pembina from April 2, 2012. together with results of Legacy
Pembina excluding Provident ("Legacy Pembina"), from January 1 through April 1, 2012, if applicable.
The comparative figures reflect solely the 2011 results of Legacy
Pembina. For further information with respect to the Acquisition,
please refer to Note 5 of the Consolidated Financial Statements for
the year ended December 31, 2012.
Financial & Operating Overview
|
|
|
|
|
($ millions, except where
noted) |
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
|
2012 |
2011 |
2012 |
2011 |
Revenue |
1,265.7 |
468.1 |
3,427.4 |
1,676.0 |
Operating margin(1) |
222.1 |
105.9 |
676.2 |
417.1 |
Gross profit |
172.1 |
87.2 |
538.7 |
354.3 |
Earnings for the period |
81.3 |
45.0 |
225.0 |
165.7 |
Earnings per share - basic and diluted
(dollars) |
0.28 |
0.27 |
0.87 |
0.99 |
Adjusted EBITDA(1) |
199.0 |
88.2 |
590.1 |
368.6 |
Cash flow from operating activities |
139.5 |
73.8 |
359.8 |
285.5 |
Adjusted cash flow from operating
activities(1) |
172.3 |
66.0 |
493.8 |
305.8 |
Adjusted cash flow from operating activities per
share(1) |
0.59 |
0.39 |
1.91 |
1.83 |
Dividends declared |
118.4 |
65.4 |
417.6 |
261.2 |
Dividends per common share (dollars) |
0.41 |
0.39 |
1.61 |
1.56 |
(1) Refer to "Non-GAAP Measures." |
Fourth Quarter and Year End 2012 Financial Highlights
- Consolidated operating margin during the fourth quarter of 2012
increased to $222.1 million compared
to $105.9 million during the same
period of the prior year. Full year operating margin totalled
$676.2 million compared to
$417.1 million in 2011. Both the 2012
fourth quarter and full year operating margin were the highest in
the Company's history. Operating margin is a non-GAAP measure; see
"Non-GAAP Measures."
- During the fourth quarter of 2012, Pembina generated operating
margin of $57.9 million from its
Conventional Pipelines business, $29.6
million from Oil Sands & Heavy Oil and $14.4 million from Gas Services. For these three
businesses, operating margin was positively impacted by increased
volumes, as discussed below, and gas processed through Pembina's
new Musreau deep cut facility. The Company's Midstream business
also saw a significant increase in operating margin to $119.5 million, which includes results generated
by the assets acquired through the Acquisition. The performance of
Pembina's Midstream business was somewhat tempered by a continued
soft NGL pricing environment. These softer prices resulted from
excess industry inventory levels due to decreased propane demand,
which was caused by the relatively warm 2011/12 winter across
North America and a mild start to
the 2012/2013 winter season.
- For the full year of 2012, operating margin generated by
Pembina's businesses was as follows: Conventional Pipelines
increased to $209.3 million compared
to $181.5 million in 2011; Oil Sands
& Heavy Oil contributed $116.8
million compared to $90.9
million during the prior year; Gas Services totalled
$59 million for 2012 compared to
$49.1 million in 2011; and
Midstream's operating margin for 2012 was $288.5 million compared to $93.2 million in the previous year. The
significant variance in Midstream's operating margin is primarily
due to results generated by the acquired Provident assets.
- Operationally, Pembina experienced one of the strongest years
in its history. Conventional Pipelines transported an average of
456.3 mbpd in 2012, 10 percent more than 2011 when average volumes
were 413.9 mbpd. Notably, fourth quarter 2012 volumes in this
business averaged 480.2 mbpd, an increase of almost 14 percent over
the fourth quarter of 2011. Gas Services also saw an increase in
volumes of 8 percent, with the Cutbank Complex processing an
average of 275.2 MMcf/d during 2012 compared to 253.8 MMcf/d in
2011.
- The Company's earnings were $81.3
million ($0.28 per share) for
the fourth quarter of 2012 compared to $45
million ($0.27 per share) for
the fourth quarter of 2011. Earnings were $225 million ($0.87
per share) for the year ended December 31,
2012 compared to $165.7
million ($0.99 per share)
during the same period of 2011. These increases were due to both
the Acquisition as well as increased volumes transported and
processed, as mentioned above, and were impacted by unrealized
gains/losses on commodity-related derivative financial instruments.
Per share metrics were also impacted by the Acquisition.
- Pembina generated record adjusted EBITDA of $199 million during the fourth quarter of 2012
compared to $88.2 million during the
fourth quarter of 2011 (adjusted EBITDA is a non-GAAP measure; see
"Non-GAAP Measures"). Adjusted EBITDA for the year ended
December 31, 2012 was $590.1 million compared to $368.6 million for 2011. The increase in
quarterly and full year 2012 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 completion of the
Acquisition.
- Cash flow from operating activities was $139.5 million ($0.48 per share) for the fourth quarter of 2012
compared to $73.8 million
($0.44 per share) for the same period
in 2011, and was $359.8 million
($1.39 per share) for the year ended
December 31, 2012 compared to
$285.5 million ($1.71 per share) during the prior year. These
increases were primarily due to higher EBITDA, which was somewhat
offset by acquisition-related expenses, higher interest expenses
and an increase in working capital which was partially associated
with the integration of Provident.
- Adjusted cash flow from operating activities was a record
$172.3 million ($0.59 per share) for the fourth quarter of 2012
compared to $66 million ($0.39 per share) for the fourth quarter of 2011
(adjusted cash flow from operating activities is a Non-GAAP
measure; see "Non-GAAP Measures"). For the full year, adjusted cash
flow from operating activities was the highest in the Company's
history at $493.8 million
($1.91 per share) in 2012 compared to
$305.8 million ($1.83 per share) in 2011.
- As of April 2, 2012, following
the close of the Acquisition, the Company increased its monthly
dividend rate by 3.8 percent to $0.135 per share per month (or $1.62 annualized) from $0.13 per share per month (or $1.56 annualized). This marks the ninth dividend
increase since Pembina began trading publicly in 1997.
2012 Year in Review & Growth Update
2012 marked a pivotal year in Pembina's history. With the
Acquisition of Provident in April of 2012, Pembina launched a new
chapter as a much larger, more financially flexible and diversified
company. With assets along the majority of the liquids hydrocarbon
value chain, Pembina is now a truly integrated energy
infrastructure company with the scale and scope necessary to meet
the growing needs of Canada's and
North America's oil and gas
industry. The Acquisition provided for a stronger balance sheet,
more robust cash flow and the ability to strategically pursue
larger, more complex growth projects. Pembina is very well
positioned from a geological perspective to capture the broader
range of opportunities resulting from the Acquisition.
Integration of Provident's assets, business processes and
procedures is substantially complete. Pembina is now operating on a
single enterprise-wide financial system and all staff are
integrated within their respective departments.
While the Acquisition has brought with it new opportunities,
Pembina's core focus remains unchanged: pursuing responsible
growth, safe and reliable operations, and delivering long-term and
sustainable returns for our shareholders. This is evident in the
many growth-related accomplishments Pembina achieved throughout the
year, which we expect will provide attractive cash flows in the
years ahead:
- Pembina has undertaken numerous expansions on its Conventional
Pipeline systems to accommodate increased customer demand due to
strong drilling results and increased field liquids extraction by
producers in areas of Alberta
including Dawson Creek,
Grande Prairie, Kaybob and
Fox Creek.
-
- The expansion has been split into two phases. During the first
phase, the Company completed a re-contracting initiative in 2012 on
existing and new volumes on the Northern NGL System (the Peace and
Northern pipelines) to underpin the system's Phase 1 NGL
expansion.
- The Company is nearing completion of the Phase 1 NGL expansion,
which is expected to cost $30 million and add approximately 17
thousand barrels per day ("mbpd") of additional NGL capacity to the
Northern NGL System in the second quarter of 2013.
- The Phase 1 Peace high vapour pressure ("HVP") expansion, which
requires seven new or upgraded pump stations and associated
pipeline reinforcement work from west of Fox Creek to Fort
Saskatchewan, will add NGL capacity of approximately 35
mbpd. Pembina expects to commission three of the pump stations by
August 2013, and the remaining four
stations by October 2013 at an
estimated cost of $70 million.
- The Phase 1 low vapour pressure ("LVP") expansion requires
three upgraded pump stations and associated pipeline reinforcement
work between Fox Creek and
Edmonton, Alberta, and will
provide an additional 40 mbpd of crude oil and condensate capacity
on this segment. Pembina expects to commission one of the three
pump stations by June 2013, and the
remaining two stations by October
2013 at an estimated cost of $30 million.
- On February 13, 2013, Pembina
announced that it had reached its contractual threshold to proceed
with its previously announced plans to significantly expand its
crude oil and condensate throughput capacity on its Peace Pipeline
system by 55 mbpd ("Phase 2 LVP Expansion"):
-
- The Phase 2 LVP Expansion is expected to accommodate increased
producer crude oil and condensate volumes due to strong drilling
results in the Dawson Creek,
Grande Prairie and
Kaybob/Fox Creek areas of
Alberta. Pembina expects the total
cost of the Phase 2 LVP Expansion to be approximately $250 million (including the mainline expansion
and tie-ins). Subject to obtaining regulatory and environmental
approvals, Pembina anticipates being able to bring the expansion
into service by late-2014. Once complete, this expansion will
increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd. The
Phase 2 LVP Expansion is underpinned by long-term fee-for-service
agreements with area producers. The combined LVP expansions will
increase capacity by 61 percent from current levels.
- The Company is actively working to accelerate the timing of its
second previously announced NGL expansion (a portion of which is
subject to reaching commercial arrangements with its customers and
receipt of environmental and regulatory approvals):
-
- The Phase 2 NGL Expansion to the Company's Northern NGL System
will increase capacity from 167 mbpd to 220 mbpd. Pembina expects
this expansion to cost approximately $415
million (including the mainline expansion and tie-ins) and
to be complete in early to mid-2015.
- In addition, in 2012:
-
- Pembina completed and brought into service two expansions at
its existing Gas Services assets at its Cutbank Complex - the 205
MMcf/d Musreau deep cut and the 50 MMcf/d Musreau shallow cut
expansion;
- Pembina entered into a long-term arrangement for the remaining
50 MMcf/d of capacity at its Saturn liquids extraction facility,
bringing total contracted capacity to 100 percent;
- Pembina received the required environmental and regulatory
approvals, and awarded construction contracts, for the pipeline
portions of the Resthaven and Saturn projects and began
construction on both during the fall and winter of 2012/2013;
- Pembina successfully completed and commissioned an 8,000 bpd
expansion at its Redwater
fractionator on schedule and under budget in September 2012;
- Pembina increased the capacity of its Drayton Valley pipeline (which serves the
Cardium play) from 145 mbpd to 195 mbpd by refurbishing an existing
pump station;
- The Company began construction on a joint venture full-service
terminal in the Judy Creek, Alberta area which has an estimated project
completion date of April 2013;
and,
- In September of 2012, Pembina brought the first of seven
fee-for-service caverns into service at its Redwater site. Three additional caverns are
completed and Pembina is in the process of preparing them for
service. Pembina expects to be able to bring two caverns into
service in March 2013, and the third
cavern into service in June
2013.
- Pembina continues to advance preliminary engineering and work
on its proposed 73 mbpd ethane plus fractionator at its
Redwater site and is soliciting
customer support for the project.
- The Company is investigating offshore propane export
opportunities that would allow it to leverage its existing assets
and provide a solution for Canadian producers.
Pembina also secured financing in 2012 to support its long-term
objectives. The Company increased its credit facility from
$800 million prior to closing of the
Acquisition to $1.5 billion
post-close. This, along with the offering of $450 million of 10-year senior unsecured
medium-term notes due 2022 with an annual interest rate of 3.77%,
which closed in October, provides Pembina increased flexibility to
pursue its capital plans.
"2012 was a very successful year for Pembina. We delivered
steady operational and financial results, increased our dividend
and made substantial progress on a number of capital projects
across our business to support our customers and help secure
returns for our investors," said Bob
Michaleski, Pembina's Chief Executive Officer. "With the
integration of Provident substantially complete, we are looking to
the future and are excited to grow in ways that would not have been
possible on a stand-alone basis. 2013 will be about demonstrating
the benefits of our fully integrated platform post-Acquisition, and
we've kicked the year off on the right foot with our recent
announcement to proceed with our Phase 2 LVP Expansion."
"Our approved 2013 capital spending plan is the largest in the
Company's history - totalling $965
million - and we are confident in our ability to execute on
it," added Michaleski. "Including the 2013 capital spending plan,
we have approximately $4 billion in
unrisked growth opportunities which are in line with our core
strengths. Our team will be focused on achieving disciplined growth
and securing projects with the most attractive cash flows and
return on capital, all while minimizing overall risk."
Mick Dilger, Pembina's President
and Chief Operating Officer commented on Pembina's operational,
safety and environmental performance during the past year: "2012
was a very successful year in terms of continuing to offer safe and
reliable services. We exited the year with improved overall safety
performance metrics compared to 2011, which is in part due to the
initiation of a safety culture improvement project alongside our
robust integrity management program. For 2013 and beyond, Pembina
remains committed to being the industry neighbour of choice. That
means our people are highly committed to doing the right thing each
and every day and are focused on reliability, no harm to the
environment and personal safety."
2012 Online Annual Report
Pembina has published an online annual report on its website at
www.pembina.com under "Investor Centre" which is supplementary to
its annual management's discussion and analysis, financial
statements and notes. This interactive report includes an overview
of 2012 results, as well as videos featuring Pembina's senior
executives as they discuss the Company's future prospects.
While the online annual report will not be printed, investors
and other stakeholders may obtain a hard copy of Pembina's annual
management's discussion and analysis, financial statements and
notes by mail by contacting Investor Relations at
investor-relations@pembina.com.
Conference Call & Webcast
Pembina will host a conference call on March 4, 2013 at 8 a.m.
MT (10 a.m. ET) to discuss
details related to the 2012 fourth quarter and full year. 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=570212&s=1&k=126357DBB613EBB2DF3D9565F6C32327
in your web browser.
Hedging Information
Pembina has posted updated hedging information on its website,
www.pembina.com, under "Investor Centre - Hedging".
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 March 1, 2013 and is supplementary to, and should
be read in conjunction with, Pembina's audited consolidated annual
financial statements for the years ended December 31, 2012 and 2011 ("Consolidated
Financial Statements"). All dollar amounts contained in this
MD&A are expressed in Canadian dollars unless otherwise
noted.
Management is responsible for preparing the MD&A. This
MD&A has been reviewed and recommended by the Audit Committee
of Pembina's Board of Directors and approved by its Board of
Directors.
This MD&A contains forward-looking statements (see
"Forward-Looking Statements & Information") and refers to
financial measures that are not defined by Generally Accepted
Accounting Principles ("GAAP"). For more information about the
measures which are not defined by GAAP, see "Non-GAAP
Measures."
On April 2, 2012, Pembina
completed its acquisition of Provident Energy Ltd. ("Provident")
(the "Acquisition"). The amounts disclosed herein for the three and
twelve month periods ending December 31,
2012 reflect results of the post-Acquisition Pembina from
April 2, 2012 together with results
of legacy Pembina excluding Provident ("Legacy Pembina"), from
January 1 through April 1, 2012, if
applicable. The comparative figures reflect solely the 2011 results
of Legacy Pembina. The results of the business acquired through the
Acquisition are reported as part of the Company's Midstream
business. For further information with respect to the Acquisition,
please refer to Note 5 of the Consolidated Financial Statements for
the year ended December 31, 2012.
About Pembina
Calgary-based Pembina Pipeline
Corporation is a leading transportation and midstream service
provider that has been serving North
America's energy industry for nearly 60 years. Pembina owns
and operates: pipelines that transport conventional and synthetic
crude oil and natural gas liquids produced in western Canada; oil sands, heavy oil and diluent
pipelines; gas gathering and processing facilities; and, an oil and
natural gas liquids infrastructure and logistics business. With
facilities strategically located in western Canada and in natural gas liquids markets in
eastern Canada and the U.S.,
Pembina also offers a full spectrum of midstream and marketing
services that spans across its operations. Pembina's integrated
assets and commercial operations enable it to offer services needed
by the energy sector along the hydrocarbon value chain.
Pembina is a trusted member of the communities in which it
operates and is committed to generating value for its investors by
running its businesses in a safe, environmentally responsible
manner that is respectful of community stakeholders.
Strategy
Pembina's goal is to provide highly competitive and reliable
returns to investors through monthly dividends while enhancing the
long-term value of its shares. To achieve this, Pembina's strategy
is to:
- Preserve value by providing safe, responsible, cost-effective
and reliable services;
- Diversify Pembina's asset base along the hydrocarbon value
chain by providing integrated service offerings which enhance
profitability;
- Pursue projects or assets that are expected to generate
increased cash flow per share and capture long-life, economic
hydrocarbon reserves; and
- Maintain a strong balance sheet through the application of
prudent financial management to all business decisions.
Pembina is structured into four businesses: Conventional
Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream,
which are described in their respective sections of this
MD&A.
Common Abbreviations
The following is a list of abbreviations that may be used in
this MD&A:
Measurement |
|
|
|
Other |
|
bbl |
barrel |
|
|
AECO |
Alberta gas trading price |
mmbbls |
millions of barrels |
|
|
AESO |
Alberta Electric Systems Operator |
bpd |
barrels per day |
|
|
B.C. |
British Columbia |
mbpd |
thousands of barrels per day |
|
|
DRIP |
Premium Dividend™ and Dividend Reinvestment Plan |
mboe/d |
thousands of barrels of oil equivalent per
day |
|
|
Frac |
Fractionation |
MMcf/d |
millions of cubic feet per day |
|
|
IFRS |
International Financial Reporting Standards |
bcf/d |
billions of cubic feet per day |
|
|
NGL |
Natural gas liquids |
MW/h |
megawatts per hour |
|
|
NYMEX |
New York Mercantile Exchange |
GJ |
gigajoule |
|
|
NYSE |
New York Stock Exchange |
km |
kilometre |
|
|
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) |
|
|
|
|
TSX |
Toronto Stock Exchange |
|
|
|
|
U.S. |
United States |
|
|
|
|
WCSB |
Western Canadian Sedimentary Basin |
|
|
|
|
WTI |
West Texas Intermediate (crude oil benchmark price) |
Financial & Operating Overview
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except where
noted) |
2012 |
2011 |
2012 |
2011 |
Average throughput - Conventional
Pipelines (mbpd) |
480.2 |
422.8 |
456.3 |
413.9 |
Contracted capacity - Oil Sands &
Heavy Oil (mbpd) |
870.0 |
870.0 |
870.0 |
870.0 |
Average processing volume - Gas
Services (mboe/d) net to Pembina(1) |
46.0 |
45.3 |
45.9 |
42.3 |
NGL sales volume - NGL Midstream
(mbpd) |
115.8 |
|
97.7(3) |
|
Revenue |
1,265.7 |
468.1 |
3,427.4 |
1,676.0 |
Operations |
86.0 |
55.1 |
271.6 |
191.9 |
Cost of goods sold, including product
purchases |
968.6 |
308.0 |
2,475.0 |
1,072.3 |
Realized gain (loss) on
commodity-related derivative financial instruments |
11.0 |
0.9 |
(4.6) |
5.3 |
Operating margin(2) |
222.1 |
105.9 |
676.2 |
417.1 |
Depreciation and amortization included
in operations |
47.8 |
19.6 |
173.6 |
68.0 |
Unrealized gain (loss)
on commodity-related derivative financial instruments |
(2.2) |
0.9 |
36.1 |
5.2 |
Gross profit |
172.1 |
87.2 |
538.7 |
354.3 |
Deduct/(add) |
|
|
|
|
|
General and administrative expenses |
27.3 |
21.0 |
97.5 |
62.2 |
|
Acquisition-related and other expense |
0.5 |
0.8 |
24.7 |
1.4 |
|
Net finance costs |
35.7 |
22.1 |
115.1 |
91.9 |
|
Share of loss (profit) of investments in equity
accounted investee,
net of tax |
0.2 |
(1.5) |
1.1 |
(5.8) |
Income tax expense (reduction) |
27.1 |
(0.2) |
75.3 |
38.9 |
Earnings for the period |
81.3 |
45.0 |
225.0 |
165.7 |
Earnings per share - basic and diluted
(dollars) |
0.28 |
0.27 |
0.87 |
0.99 |
Adjusted earnings(2) |
115.8 |
43.7 |
283.7 |
208.9 |
Adjusted earnings per
share(2) |
0.40 |
0.26 |
1.10 |
1.25 |
Adjusted EBITDA(2) |
199.0 |
88.2 |
590.1 |
368.6 |
Cash flow from operating
activities |
139.5 |
73.8 |
359.8 |
285.5 |
Cash flow from operating activities
per share |
0.48 |
0.44 |
1.39 |
1.71 |
Adjusted cash flow from operating
activities(2) |
172.3 |
66.0 |
493.8 |
305.8 |
Adjusted cash flow from operating
activities per share(2) |
0.59 |
0.39 |
1.91 |
1.83 |
Dividends declared |
118.4 |
65.4 |
417.6 |
261.2 |
Dividends per common share
(dollars) |
0.41 |
0.39 |
1.61 |
1.56 |
Capital expenditures |
254.7 |
148.9 |
584.3 |
527.6 |
Total enterprise value ($
billions) (2) |
11.0 |
6.6 |
11.0 |
6.6 |
Total assets ($ billions) |
8.3 |
3.3 |
8.3 |
3.3 |
(1) Gas Services processing volumes converted
to mboe/d from MMcf/d at 6:1 ratio. |
(2) Refer to "Non-GAAP Measures." |
(3) Represents per day volumes since the
closing of the Acquisition. |
Revenue, net of cost of goods sold, increased over 85 percent to
$297.1 million during the fourth
quarter of 2012 from $160.1 million
during the same period of 2011. Full year revenue, net of cost of
goods sold, in 2012 was $952.4
million compared to $603.7
million in 2011. 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 Acquisition,
which are reported in the Company's Midstream business, as well as
improved performance in each of Pembina's legacy businesses, as
discussed in further detail below.
Operating expenses were $86
million during the fourth quarter and $271.6 million for the full year in 2012 compared
to $55.1 million and $191.9 million during the same periods in 2011.
The increases were primarily due to additional costs associated
with the growth in Pembina's asset base since the Acquisition and
higher variable costs in each of the Company's businesses because
of increased volumes.
Operating margin was $222.1
million during the fourth quarter, up almost 110 percent
from the same period last year when operating margin totalled
$105.9 million (operating margin is a
Non-GAAP measure; see "Non-GAAP Measures"). For the year ended
December 31, 2012, operating margin
was $676.2 million compared to
$417.1 million for the full year of
2011. These increases were primarily due to higher revenue, as
discussed above.
Realized and unrealized gains/losses on commodity-related
derivative financial instruments resulting from Pembina's market
risk management program are primarily related to outstanding
positions acquired on the closing of the Acquisition (see "Market
Risk Management Program" and Note 27 to the Consolidated Financial
Statements). The unrealized gain on commodity-related derivative
financial instruments was $36.1
million for 2012 reflecting changes in the future NGL and
natural gas price indices between April 2,
2012 and December 31, 2012
(see "Business Environment").
Depreciation and amortization (operational) increased to
$47.8 million during the fourth
quarter of 2012 compared to $19.6
million during the same period in 2011 and $173.6 million for the year ended December 31, 2012 compared to $68 million in 2011. Both the quarterly and full
year increases reflect depreciation on new capital additions
including those assets acquired through the Acquisition.
The increases in revenue and operating margin contributed to
gross profit of $172.1 million during
the fourth quarter and $538.7 million
for the full year of 2012 compared to $87.2
million and $354.3 million for
the same periods of 2011.
General and administrative expenses ("G&A") of $27.3 million were incurred during the fourth
quarter of 2012 compared to $21
million during the fourth quarter of 2011. The increase,
year-over-year, for the three month period was mainly due to the
addition of employees who joined Pembina through the Acquisition,
an increase in salaries and benefits for existing and new
employees, and increased rent for expanded office space. Full year
2012 G&A totaled $97.5 million
compared to $62.2 million incurred
during 2011. The primary driver of the year-over-year increase in
G&A was a $19.8 million increase
in salaries, benefits and consulting costs, $3 million increase in rent and $3.6 million in corporate depreciation. In
addition, every $1 change in share
price is expected to change Pembina's annual share-based incentive
expense by $1.2 million.
Pembina generated adjusted EBITDA of $199
million during the fourth quarter of 2012 compared to
$88.2 million during the fourth
quarter of 2011 (adjusted EBITDA is a Non-GAAP measure; see
"Non-GAAP Measures"). Adjusted EBITDA for the full year of 2012 was
$590.1 million compared to
$368.6 million in 2011. The increase
in quarterly and full year 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 of Pembina's
operations since completion of the Acquisition.
The Company's earnings were $81.3
million ($0.28 per share)
during the fourth quarter of 2012 compared to $45 million ($0.27
per share) during the fourth quarter of 2011 and $225 million ($0.87
per share) for the full year of 2012 compared to $165.7 million ($0.99 per share) in 2011. These increases were
the result of the Acquisition of Provident as well as improved
performance in each of the Company's legacy businesses. Per share
metrics were also impacted by the Acquisition.
Adjusted earnings were $115.8
million ($0.40 per share)
during the fourth quarter of 2012 compared to $43.7 million ($0.26 per share) during the fourth quarter of
2011 (adjusted earnings is a Non-GAAP measure; see "Non-GAAP
Measures"). For the full year of 2012, adjusted earnings totalled
$283.7 million ($1.10 per share) compared to $208.9 million ($1.25 per share) in 2011. The increases in
adjusted earnings were primarily due to higher operating margin, as
discussed above, which was partially offset by increased
depreciation and amortization (operational) resulting from a larger
asset base, and higher G&A and finance costs.
Cash flow from operating activities was $139.5 million ($0.48 per share) during the fourth quarter of
2012 and $359.8 million ($1.39 per share) for the full year in 2012
compared to $73.8 million
($0.44 per share) and $285.5 million ($1.71 per share), respectively, for the
comparative periods of 2011. The increases in cash flow from
operating activities was primarily due to an increase in adjusted
EBITDA, which was somewhat offset by acquisition-related expenses,
higher interest expenses and an increase in working capital, which
was partially associated with the integration of Provident.
Adjusted cash flow from operating activities was $172.3 million ($0.59 per share) during the fourth quarter of
2012, an increase of more than 160 percent, compared to
$66.0 million ($0.39 per share) during the fourth 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 a record $493.8
million ($1.91 per share)
during 2012 compared to $305.8
million ($1.83 per share)
during 2011 and was largely driven by strong performance in each of
Pembina's businesses.
Operating Results
|
|
|
|
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
|
2012 |
2011 |
2012 |
2011 |
($ 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 |
99.2 |
57.9 |
75.8 |
41.6 |
338.8 |
209.3 |
296.2 |
181.5 |
Oil Sands & Heavy Oil |
45.8 |
29.6 |
39.7 |
27.3 |
172.4 |
116.8 |
134.9 |
90.9 |
Gas Services |
23.3 |
14.4 |
19.1 |
13.0 |
88.3 |
59.0 |
71.5 |
49.1 |
Midstream |
128.8 |
119.5 |
25.5 |
23.4 |
352.9(3) |
288.5(3) |
101.1 |
93.2 |
Corporate |
|
0.7 |
|
0.6 |
|
2.6 |
|
2.4 |
Total |
297.1 |
222.1 |
160.1 |
105.9 |
952.4 |
676.2 |
603.7 |
417.1 |
(1) |
Midstream revenue is net of $975 million in cost of goods sold,
including product purchases, for the quarter ended December 31,
2012 (quarter ended December 31, 2011: $308 million) and $2,494.5
million in cost of goods sold, including product purchases, for the
twelve months ended December 31, 2012 (twelve months ended December
31, 2011: $1,072.3 million). |
(2) |
Refer to "Non-GAAP Measures." |
(3) |
Includes results from operations generated by the acquired
assets from Provident since closing of the Acquisition on April 2,
2012. |
Conventional Pipelines
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except where noted) |
2012 |
2011 |
2012 |
2011 |
Average throughput (mbpd) |
480.2 |
422.8 |
456.3 |
413.9 |
Revenue |
99.2 |
75.8 |
338.8 |
296.2 |
Operations |
42.1 |
35.5 |
129.6 |
119.1 |
Realized gain on commodity-related derivative
financial instruments |
0.8 |
1.3 |
0.1 |
4.4 |
Operating margin(1) |
57.9 |
41.6 |
209.3 |
181.5 |
Depreciation and amortization included in
operations |
7.8 |
11.1 |
44.0 |
41.6 |
Unrealized gain (loss) on commodity-related
derivative financial instruments |
0.8 |
(0.9) |
(9.0) |
3.7 |
Gross profit |
50.9 |
29.6 |
156.3 |
143.6 |
Capital expenditures |
88.1 |
24.9 |
187.3 |
72.0 |
(1) Refer to "Non-GAAP Measures." |
Business Overview
Pembina's Conventional Pipelines business comprises a
well-maintained and strategically located 7,850 km pipeline network
that extends across much of Alberta and B.C. It transports approximately
half of Alberta's conventional
crude oil production, about thirty percent of the NGL produced in
western Canada, and virtually all
of the conventional oil and condensate produced in B.C. This
business' primary objective is to generate sustainable operating
margin while pursuing opportunities for increased throughput and
revenue. Conventional Pipelines endeavours to maintain and/or
improve operating margin by capturing incremental volumes,
expanding its pipeline systems, managing revenue and following a
disciplined approach to its operating expenses.
Operational Performance: Throughput
During the fourth quarter of 2012, Conventional Pipelines'
throughput averaged 480.2 mbpd, consisting of an average of 352.5
mbpd of crude oil and condensate and 127.7 mbpd of NGL. This was
primarily due to continued production growth from regional resource
plays in the Cardium (oil), Deep Basin Cretaceous (NGL),
Montney (oil/NGL) and Beaverhill
Lake (oil) formations and represents an increase of 14 percent
compared to the same period of 2011, when average throughput was
422.8 mbpd. Producer production growth also contributed to a 10
percent increase in throughput for the full year of 2012 compared
to 2011.
Financial Performance
During the fourth quarter of 2012, Conventional Pipelines
generated revenue of $99.2 million
compared to $75.8 million in the same
quarter of the previous year. For 2012, revenue was $338.8 million compared to $296.2 million during 2011. The 31 and 14 percent
increases during the respective 2012 periods were primarily due to
strong volumes generated by newly connected facilities on Pembina's
Conventional Pipelines systems, as well as many deliveries being
received at higher toll locations along the Company's pipeline
network.
Quarterly operating expenses increased to $42.1 million compared to $35.5 million in the fourth quarter of 2011 due
to higher variable costs associated with increased throughput as
well as integrity and geotechnical expenditures. Operating expenses
for 2012 increased to $129.6 million
from $119.1 million in the same
period last year. This nine percent year-over-year increase was
because of the same factors that impacted quarterly operating
expenses.
As a result of higher revenue, operating margin for the fourth
quarter of 2012 was $57.9 million
compared to $41.6 million during the
same period of 2011. Full year revenue in 2012, which was offset
slightly by an increase in operating expenses, increased to
$209.3 million compared to
$181.5 million for 2011.
Depreciation and amortization included in operations was
$7.8 million during the fourth
quarter of 2012 compared to $11.1
million during the fourth quarter of 2011. This decrease is
due to a credit made to depreciation because of a re-measurement
reduction in the decommissioning provision in excess of the
carrying amount of the related asset. Depreciation and amortization
included in operations for the year ended December 31, 2012 was $44
million, up from $41.6 million
in 2011 due to capital additions.
For the three months ended December 31,
2012, Pembina recognized an unrealized gain on
commodity-related derivative financial instruments of $0.8 million compared to an unrealized loss of
$0.9 million in the fourth quarter of
2011. For the full year of 2012, Pembina recognized an unrealized
loss on commodity-related derivative financial instruments of
$9 million compared to an unrealized
gain of $3.7 million for 2011. The
2012 unrealized loss is the result of Pembina's forward fixed-price
power purchase program which is designed to mitigate operating
costs fluctuations.
For the three and twelve months ended December 31, 2012, gross profit was $50.9 million and $156.3
million, respectively, compared to $29.6 million and $143.6
million, respectively, during the same periods in 2011.
Higher operating margin in 2012 was partially offset by increased
depreciation and amortization and unrealized losses on
commodity-related derivative financial instruments.
Capital expenditures for the fourth quarter of 2012 totalled
$88.1 million compared to
$24.9 million during the fourth
quarter of 2011, and were $187.3
million during the year compared to $72 million in 2011. The majority of the spending
in 2012 related to the expansion of certain pipeline assets as
described below.
New Developments: Conventional Pipelines
During 2012, Pembina saw increased volumes on its Conventional
Pipelines due to the continued revitalization of many of the plays
near its systems. The trend towards increased exploration, drilling
and production in the WCSB has escalated over the past several
years, with plays such as the Alberta Deep Basin, Cardium,
Montney, Swan Hills and Duvernay being further developed by producers
and offering improved recoveries with the use of innovative
technology. Some of these plays were once considered mature or
unviable, and others were relatively unexplored; by using
horizontal drilling and multi-stage hydraulic fracturing
technology, these tight and previously uneconomic portions of
reservoirs began to represent attractive opportunities. For
Pembina, this producer activity has meant an increase in crude oil
and NGL volumes transported on its Conventional Pipeline systems
and the need to complete expansions of select segments to
accommodate customer demand.
- Pembina is pursuing numerous expansions on its Conventional
Pipeline systems to accommodate the increased customer demand
mentioned above in areas of Alberta including Dawson Creek, Grande
Prairie, Kaybob and Fox
Creek.
-
- The expansion has been split into two phases. During the first
phase, the Company completed a re-contracting initiative in 2012 on
existing and new volumes on the Northern NGL System (the Peace and
Northern pipelines) to underpin the system's Phase 1 NGL
expansion.
- The Company is nearing completion of the Phase 1 NGL expansion,
which is expected to cost $30 million
and add approximately 17 mbpd of additional NGL capacity to the
Northern NGL System in the second quarter of 2013.
- The Phase 1 Peace high vapour pressure ("HVP") expansion, which
requires seven new or upgraded pump stations and associated
pipeline reinforcement work from west of Fox Creek to Fort
Saskatchewan, will add NGL capacity of approximately 35
mbpd. Pembina expects to commission three of the pump stations by
August 2013, and the remaining four
stations by October 2013 at an
estimated cost of $70 million.
- The Phase 1 Peace low vapour pressure ("LVP") expansion
requires three upgraded pump stations and associated pipeline
reinforcement work between Fox
Creek and Edmonton,
Alberta, and will provide an additional 40 mbpd of crude oil
and condensate capacity on this segment. Pembina expects to
commission one of the three pump stations by June 2013, and the remaining two stations by
October 2013 at an estimated cost of
$30 million.
- On February 13, 2013, Pembina
announced that it had reached its contractual threshold to proceed
with its previously announced plans to significantly expand its
crude oil and condensate throughput capacity on its Peace Pipeline
system by 55 mbpd ("Phase 2 LVP Expansion"):
-
- The Phase 2 LVP Expansion is expected to accommodate increased
producer crude oil and condensate volumes due to strong drilling
results in the Dawson Creek,
Grande Prairie and
Kaybob/Fox Creek areas of
Alberta. Pembina expects the total
cost of the Phase 2 LVP Expansion to be approximately $250 million (including the mainline expansion
and tie-ins). Subject to obtaining regulatory and environmental
approvals, Pembina anticipates being able to bring the expansion
into service by late-2014. Once complete, this expansion will
increase LVP capacity on Pembina's Peace Pipeline to 250 mbpd. The
Phase 2 LVP Expansion is underpinned by long-term fee-for-service
agreements with area producers. The combined LVP expansions will
increase capacity by 61 percent from current levels.
- The Company is actively working to accelerate the timing of its
second previously announced NGL expansion (a portion of which is
subject to reaching commercial arrangements with its customers and
receipt of environmental and regulatory approvals):
-
- The Phase 2 NGL Expansion to the Company's Northern NGL System
will increase capacity from 167 mbpd to 220 mbpd. Pembina expects
this expansion to cost approximately $415
million (including the mainline expansion and tie-ins) and
to be complete in early to mid-2015.
- Conventional Pipelines is also constructing the pipeline
components of the Company's Saturn and Resthaven gas plant
projects. These two pipeline projects will gather NGL from the gas
plants for delivery to Pembina's Peace Pipeline system. Pembina has
received the required environmental and regulatory approvals, has
awarded construction contracts and has begun construction on both
projects.
Oil Sands & Heavy Oil
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except where noted) |
2012 |
2011 |
2012 |
2011 |
Capacity under contract (mbpd) |
870.0 |
870.0 |
870.0 |
870.0 |
Revenue |
45.8 |
39.7 |
172.4 |
134.9 |
Operations |
16.2 |
12.4 |
55.6 |
44.0 |
Operating margin(1) |
29.6 |
27.3 |
116.8 |
90.9 |
Depreciation and amortization included in
operations |
5.0 |
4.9 |
19.8 |
12.8 |
Gross profit |
24.6 |
22.4 |
97.0 |
78.1 |
Capital expenditures |
18.3 |
47.8 |
30.4 |
191.7 |
(1) Refer to "Non-GAAP Measures." |
Business Overview
Pembina plays an important role in supporting Alberta's oil sands and heavy oil industry.
Pembina is the sole transporter of crude oil for Syncrude Canada
Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources
Ltd.'s Horizon Oil Sands operation (via the Horizon Pipeline) to
delivery points near Edmonton,
Alberta. Pembina also owns and operates the Nipisi and
Mitsue Pipelines, which provide transportation for producers
operating in the Pelican Lake and Peace
River heavy oil regions of Alberta, and the Cheecham Lateral which
transports synthetic crude to oil sands producers operating
southeast of Fort McMurray,
Alberta. The Oil Sands & Heavy Oil business operates
approximately 1,650 km of pipeline and has 870 mbpd of capacity
under long-term, extendible contracts which provide for the
flow-through of operating expenses to customers. As a result,
operating margin from this business is proportionate to the amount
of capital invested and is predominantly not sensitive to
fluctuations in operating expenses or actual throughput.
Financial Performance
The Oil Sands & Heavy Oil business realized revenue of
$45.8 million in the fourth quarter
of 2012 compared to $39.7 million in
the fourth quarter of 2011. This 15 percent increase is primarily
due to higher flow-through operating expenses as well as higher
operating margin from the Syncrude and Nipisi pipelines. Full year
revenue in 2012 was $172.4 million
compared to $134.9 million for 2011,
largely because of contributions from the Nipisi and Mitsue
pipelines which were placed into service in June and July of
2011.
Operating expenses in Pembina's Oil Sands & Heavy Oil
business were $16.2 million during
the fourth quarter of 2012 compared to $12.4
million during the fourth quarter of 2011, and $55.6 million for the full year of 2012 compared
to $44 million in 2011. These
increases primarily reflect additional operating expenses related
to higher volumes being transported on the Nipisi and Mitsue
pipelines compared to the same periods of the prior year.
For the three and twelve months ended December 31, 2012, operating margin increased to
$29.6 million and $116.8 million compared to $27.3 million and $90.9
million, respectively, during the same periods in 2011. This
is primarily due to incremental contribution from the Nipisi and
Mitsue pipelines.
Depreciation and amortization included in operations for the
fourth quarter of 2012 totalled $5
million compared to $4.9
million during the same period of the prior year, and
$19.8 million for the twelve months
of 2012 compared to $12.8 million
during 2011. These increases primarily reflect the additional
Nipisi and Mitsue depreciation and amortization included in
operations.
For the three and twelve months ended December 31, 2012, gross profit was $24.6 million and $97
million, primarily due to higher operating margin as
discussed above, compared to $22.4
million and $78.1 million,
respectively, during the same periods of 2011.
For the year ended December 31,
2012, capital expenditures within the Oil Sands & Heavy
Oil business totalled $30.4 million
and were primarily related to Nipisi and Mitsue post-construction
clean-up costs and the construction of additional pump stations on
these pipelines. This compares to $191.7
million spent during the same period in 2011, the majority
of which related to completing the two projects.
New Developments: Oil Sands & Heavy Oil
In 2013, Pembina plans to spend approximately $45 million to increase capacity on the Nipisi
and Mitsue pipelines by 12 mbpd and 4 mbpd, respectively, while
also increasing connectivity in the Edmonton area.
Pembina continues to actively work with customers on oil sands
and heavy oil related solutions. With the Acquisition of Provident,
the Company has increased its access to diluent supply and can
offer customers condensate and butane products from various sources
including Pembina's conventional pipeline systems, the Redwater fractionator, rail imports and truck
racks.
Gas Services
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except where noted) |
2012 |
2011 |
2012 |
2011 |
Average processing volume (MMcf/d) net to
Pembina |
276.0 |
271.5 |
275.2 |
253.8 |
Average processing volume (mboe/d)
(1) net to Pembina |
46.0 |
45.3 |
45.9 |
42.3 |
Revenue |
23.3 |
19.1 |
88.3 |
71.5 |
Operations |
8.9 |
6.1 |
29.3 |
22.4 |
Operating margin(2) |
14.4 |
13.0 |
59.0 |
49.1 |
Depreciation and amortization included in
operations |
3.7 |
2.6 |
14.5 |
9.9 |
Gross profit |
10.7 |
10.4 |
44.5 |
39.2 |
Capital expenditures |
77.2 |
66.4 |
162.8 |
136.5 |
(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 425 MMcf/d
of processing capacity (368 MMcf/d net to Pembina), a 205 MMcf/d
ethane plus extraction facility, as well as approximately 350 km of
gathering pipelines. The Cutbank Complex is connected to Pembina's
Peace Pipeline system and serves an active exploration and
production area in the WCSB. Pembina has initiated construction on
two projects in its Gas Services business, 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 22 percent
during the fourth quarter of 2012, contributing $23.3 million compared to $19.1 million in the fourth quarter of 2011. For
the full year of 2012, revenue was $88.3
million compared to $71.5
million in 2011. These increases primarily reflect higher
processing volumes at Pembina's Cutbank Complex. Average processing
volumes, net to Pembina, were 276 MMcf/d during the fourth quarter
of 2012, approximately 2 percent higher than the 271.5 MMcf/d
processed during the fourth quarter of the previous year. Full year
volumes averaged 275.2 MMcf/d, up approximately 8 percent from 2011
when average volumes were 253.8 MMcf/d.
During the fourth quarter of 2012, operating expenses were
$8.9 million compared to $6.1 million incurred in the fourth quarter of
2011. Full year operating expenses in 2012 totalled $29.3 million, up from $22.4 million during the prior year. The
quarterly and full year increases were mainly due to variable costs
incurred to process higher volumes at the Cutbank Complex as well
as additional costs associated with running the Musreau shallow cut
expansion and deep cut facilities.
As a result of processing higher volumes at the Cutbank Complex
and additional processing associated with the Musreau deep cut
facility, Gas Services realized operating margin of $14.4 million in the fourth quarter compared to
$13 million during the same period of
the prior year. On a full year basis, Gas Services generated
$59 million in operating margin in
2012 compared to $49.1 million in
2011. Of the $9.9 million increase,
the Musreau deep cut facility contributed $6.7 million.
Depreciation and amortization included in operations during the
fourth quarter of 2012 totalled $3.7
million, up from $2.6 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 feep cut facility and shallow cut
expansion). For the same reason, depreciation and amortization
included in operations totalled $14.5
million in 2012 compared to $9.9
million in 2011.
For the three months ended December 31,
2012, gross profit was $10.7
million compared to $10.4
million in the same period of 2011, and was $44.5 million for the full year of 2012 compared
to $39.2 million in 2011. These
increases reflect higher operating margin during the periods which
was partially offset by increased depreciation and amortization
included in operations as discussed above.
For the year ended December 31,
2012, capital expenditures within Gas Services totalled
$162.8 million compared to
$136.5 million during the same period
of 2011. This increase was because of 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 natural gas drilling
and the extraction of valuable NGL from natural gas in the WCSB.
Pembina expects the expansions detailed below (some of which were
completed in 2012) to bring the Company's Gas Service's processing
capacity to 903 MMcf/d (net). This includes enhanced NGL extraction
capacity of approximately 535 MMcf/d (net). These volumes would be
processed on a contracted, fee-for-service basis and are expected
to result in approximately 45 mbpd of incremental NGL to be
transported for additional toll revenue on Pembina's conventional
pipelines by early 2014.
During the year, Pembina completed two expansions at its Musreau
gas plant, part of the Cutbank Complex: the 205 MMcf/d enhanced NGL
extraction deep cut facility and the 50 MMcf/d shallow cut
expansion. With these two expansions in place, the Cutbank Complex
now has an aggregate raw shallow gas processing capacity of 425
MMcf/d (368 MMcf/d net to Pembina), an increase of 13 percent net
to Pembina.
Pembina's Gas Services business is also constructing two new
fully contracted facilities and associated infrastructure: the
Saturn facility - a $200 million 200
MMcf/d enhanced NGL extraction facility (includes conventional
pipeline tie-ins) in the Berland area of west central Alberta; and, the Resthaven facility - a
$230 million 200 MMcf/d combined
shallow cut and deep cut NGL extraction facility (includes
conventional pipeline tie-ins) in the Resthaven, Alberta area.
Pembina expects the Saturn facility and associated pipelines to
be in service in the fourth quarter of 2013. Once operational,
Pembina expects the Saturn facility will have the capacity to
extract up to 13.5 mbpd of NGL.
For the Resthaven facility, Pembina is modifying and expanding
an existing gas plant, and is constructing a pipeline to transport
the extracted NGL from the Resthaven facility to its Peace Pipeline
system. Pembina will own approximately 65 percent of the Resthaven
facility and 100 percent of the NGL pipeline. Pembina expects the
Resthaven facility and associated pipelines to be in service in the
third quarter of 2014 due to potential scope changes from the
original project. Once operational, Pembina expects the Resthaven
facility will have the capacity to extract up to 13 mbpd of
NGL.
Construction on both facilities is underway, with over 95
percent of the major equipment ordered and on-site at the Saturn
facility and over 80 percent of the major equipment ordered for the
Resthaven facility.
Midstream(1)
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December
31(2) |
($ millions, except where noted) |
2012 |
2011 |
2012 |
2011 |
Revenue |
1,103.7 |
333.5 |
2,847.4 |
1,173.5 |
Operations |
19.4 |
1.7 |
59.7 |
8.8 |
Cost of goods sold, including product
purchases |
975.0 |
308.0 |
2,494.5 |
1,072.4 |
Realized gain (loss) on commodity related
derivative financial instruments |
10.2 |
(0.4) |
(4.7) |
0.9 |
Operating margin(3) |
119.5 |
23.4 |
288.5 |
93.2 |
Depreciation and amortization included in
operations |
31.3 |
0.9 |
95.3 |
3.6 |
Unrealized gain (loss) on commodity-related
derivative financial instruments |
(3.0) |
1.7 |
45.1 |
1.4 |
Gross profit |
85.2 |
24.2 |
238.3 |
91.0 |
Capital expenditures |
77.4 |
4.6 |
204.0 |
111.5 |
(1) Share of profit from equity accounted
investees not included in these results. |
(2) Includes results from NGL midstream since
the closing of the Acquisition. |
(3) Refer to "Non-GAAP Measures." |
Business Overview
Pembina offers customers a comprehensive suite of midstream
products and services through its Midstream business as
follows:
- Crude oil midstream targets oil and diluent-related
opportunities from key sites across Pembina's network, which
comprises 15 truck terminals (including one capable of emulsion
treating and water disposal), terminalling at downstream hub
locations, storage, and the Pembina Nexus Terminal ("PNT"). PNT
includes: 21 inbound pipelines connections, 13 outbound pipelines
connections, an excess of 1.2 million bpd of crude oil and
condensate connected to the terminal, and 310,000 barrels of
surface storage.
- NGL midstream, which Pembina acquired through the Acquisition,
includes two NGL operating systems, Redwater West and Empress
East:
-
- The Redwater West NGL system includes the Younger extraction
and fractionation facility in B.C.; the recently expanded 73,000
bpd Redwater NGL fractionator, 6.8 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 plants at Empress,
Alberta; 20,000 bpd of fractionation capacity as well as 1.1
mmbbls of cavern storage in Sarnia,
Ontario; and, approximately 5 mmbbls of hydrocarbon storage
at Corunna, Ontario.
Financial Performance
In the Midstream business, revenue, net of cost of goods sold,
grew to $128.8 million during the
fourth quarter of 2012 from $25.5
million during the fourth quarter of 2011. Full year
revenue, net of cost of goods sold, in 2012 was $352.9 million compared to $101.1 million in 2011. These increases were
primarily due to the addition of the NGL midstream business
acquired through the Acquisition and increased activity on
Pembina's pipeline systems.
Operating expenses during the fourth quarter of 2012 were
$19.4 million compared to
$1.7 million in the fourth quarter of
2011, and were $59.7 million for the
full year 2012 compared to $8.8
million in 2011. Operating expenses for the quarter and the
year were higher due to the increase in Midstream's asset base
since the Acquisition.
Operating margin was $119.5
million during the fourth quarter of 2012 compared to
$23.4 million during the fourth
quarter of 2011. Operating margin for the 2012 year was
$288.5 million compared to
$93.2 million in 2011. These
increases were 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
fourth quarter of 2012 totalled $31.3
million compared to $0.9
million during the same period of the prior year. Full year
2012 depreciation and amortization included in operations totalled
$95.3 million compared to
$3.6 million in 2011. Both increases
reflect the additional Midstream assets since the closing of the
Acquisition.
For the three months ended December 31,
2012, unrealized losses on commodity-related derivative
financial instruments were $3
million. For the full year, there was a gain of $45.1 million. These amounts reflect fluctuations
in the future NGL and natural gas price indices during the periods
(see "Market Risk Management Program" and Note 27 to the
Consolidated Financial Statements).
For the three and twelve months ended December 31, 2012, gross profit in this business
increased to $85.2 million and
$238.3 million, respectively, from
$24.2 million and $91 million, respectively, during the same
periods in 2011. This is due to the addition of assets acquired
through the Acquisition and higher operating margin generated by
Pembina's legacy midstream operations.
For the year ended December 31,
2012, capital expenditures within the Midstream business
totalled $204 million and were
primarily related to cavern development and associated
infrastructure as well as fractionation capacity expansion at the
Redwater facility by approximately
8,000 bpd. This compares to capital expenditures of $111.5 million during 2011, which included the
acquisition of a terminalling and storage facility near
Edmonton, Alberta and linefill for
the Peace Pipeline.
Crude Oil Midstream
Operating margin for the Company's crude oil midstream
activities during the fourth quarter of 2012 was $44.7 million compared to $23.4 million during the fourth quarter of 2011.
For the year ended December 31, 2012,
operating margin was $132.1 million,
representing an increase of 42 percent from $93.2 million in the same period last year.
Strong fourth quarter and full year 2012 results were primarily due
to higher volumes and increased activity on Pembina's pipeline
systems, wider margins, as well as opportunities associated with
enhanced connectivity at the PNT added in the first quarter of
2012. Throughput at the crude oil midstream truck terminals
increased by 18 percent compared to the end of 2011 to exit 2012 at
80,000 bpd.
NGL Midstream
Operating margin for Pembina's NGL midstream activities was
$74.8 million for the fourth quarter
and $156.4 million year-to-date since
the closing of the Acquisition, including a $5.8 million year-to-date realized loss on
commodity-related derivative financial instruments (see "Market
Risk Management Program").
NGL sales volumes during the fourth quarter of 2012 were 115.8
mbpd and 97.7 mbpd since the closing of the Acquisition.
Redwater West
Redwater West purchases NGL mix from various natural gas and NGL
producers and fractionates it into finished products at
fractionation facilities near Fort
Saskatchewan, Alberta. Redwater West also includes NGL
production from the Younger NGL extraction and fractionation plant
(Taylor, B.C.) that provides
specification NGL to B.C. markets. Also located at the Redwater facility are Pembina's
industry-leading rail-based terminal and more than 6.8 mmbbls of
underground hydrocarbon cavern storage, both of which service
Pembina's proprietary and customer needs. Pembina's condensate
terminal is the largest of its kind in western Canada.
Operating margin during the fourth quarter of 2012, excluding
realized losses from commodity-related derivative financial
instruments, was $49.1 million.
Year-to-date since closing of the Acquisition, operating margin,
excluding realized losses from commodity-related derivative
financial instruments, was $131.9
million. Realized propane margins were impacted by weak 2012
market prices and decreased gas volumes at the Younger plant during
the year. Overall, Redwater West NGL sales volumes averaged 59.1
mbpd since closing of the Acquisition.
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 is
transported by pipelines to Sarnia,
Ontario for fractionation and storage of specification
products. Propane and butane are sold into central Canadian and
eastern U.S. markets. Demand for propane is seasonal; inventory
generally builds over the second and third quarters of the year and
is sold in the fourth quarter and the first quarter of the
following year during the winter heating season.
Operating margin during the fourth quarter of 2012, excluding
realized losses from commodity-related derivative financial
instruments, was $16.5 million.
Year-to-date since closing of the Acquisition, operating margin,
excluding realized losses from commodity-related derivative
financial instruments, was $30.3
million. Results were impacted by low sales volumes, soft
2012 propane prices and high extraction premiums, but were offset
by strong refinery demand for butane and low AECO natural gas
prices since the Acquisition. Overall, Empress East NGL sales
volumes averaged 38.6 mbpd since closing of the Acquisition.
New Developments: Midstream
As a result of the Acquisition, Pembina's midstream asset base
has grown substantially. Future prospects related to this business
now span across the crude oil and NGL value chains. The capital
being deployed in the Midstream business is primarily directed
towards fee-for-service projects which are expected to continue to
increase its stability and predictability.
Pembina continues to advance a number of initiatives, as
follows:
- As part of its full service terminal ("FST") development
program, Pembina will be putting two new facilities into service in
2013. This includes a joint venture FST in the Judy Creek area of
Alberta to serve the production
from Beaverhill Lake and Swan
Hills and a second FST that serves producers in the Cynthia
area west of Drayton Valley.
Pembina continues to advance other prospects for approval in 2013
and development in 2014.
- During 2013, Pembina will enhance the connectivity of PNT, both
to third party infrastructure and to the Company's own facilities
between Edmonton and Fort Saskatchewan. Pembina will be adding a
truck terminal and constructing storage which will come on stream
in 2015. Pembina will also commission the first phase of a crude
oil rail loading facility. This latter project will capitalize on
synergies between capabilities and expertise acquired with
Provident and the crude oil midstream business.
- During 2012, Pembina successfully completed and commissioned an
8,000 bpd expansion at the Redwater fractionator, which required a 20-day
turn-around of the facility in September. The project was completed
on schedule and under budget. Also at Redwater, Pembina is currently in discussions
with customers and completing preliminary engineering work to
advance its proposed new 73,000 bpd ethane plus fractionator at its
site. This fractionator would essentially duplicate the existing
fractionator, and is being pursued by the Company to help ease
anticipated fractionation capacity constraints in the Fort Saskatchewan, Alberta area.
- In September of 2012, Pembina brought the first of seven
fee-for-service caverns into service at its Redwater site. Three additional caverns are
completed and Pembina is in the process of preparing them for
service. Pembina expects to be able to bring two caverns into
service in March 2013, and the third
cavern into service in June
2013.
- During the second quarter, Pembina entered into an agreement
with a joint venture partner and a third-party producer to tie in
its production of up to 60 MMcf/d and backstop a $12 million natural gas lateral connection to the
Younger plant by the first quarter of 2013. Pembina's share of NGL
extracted from this expanded gathering footprint will be
incremental supply to Pembina's marketing portfolio in both
Taylor, B.C. and Fort Saskatchewan, Alberta.
- Given the oversupply of propane in western Canada and North
America at large, and the associated pricing imbalance,
Pembina is investigating opportunities for offshore propane export
which would leverage its existing assets and help provide a
solution for Canadian producers.
Market Risk Management Program
Pembina is exposed to frac spread risk, which is the difference
between the selling price for propane-plus liquids and the input
cost of natural gas required to produce respective NGL products.
Pembina has a risk management program and uses derivative financial
instruments to mitigate frac spread risk, when possible, to
safeguard a base level of operating cash flow that covers the input
cost of natural gas. Pembina has entered into derivative financial
swap contracts to protect the frac spread and product margin, and
to manage exposure to power costs, interest rates and foreign
exchange rates.
Pembina's credit policy mitigates risk of non-performance by
counterparties of its derivative financial instruments. Activities
undertaken to reduce risk include: regularly monitoring
counterparty exposure to approved credit limits; financial reviews
of all active counterparties; entering into International Swap
Dealers Association agreements; and, obtaining financial assurances
where warranted. In addition, Pembina has a diversified base of
available counterparties.
Management continues to actively monitor commodity price risk
and mitigate its impact through financial risk management
activities. A summary of Pembina's current financial derivative
positions is available on Pembina's website at www.pembina.com.
A summary of Pembina's risk management contracts executed during
the fourth quarter of 2012 is contained in the following table:
Transactions entered into during the fourth quarter
|
|
|
|
|
|
Year |
Commodity |
Description |
Volume (Buy)/Sell |
Effective Period |
2013 |
Natural Gas |
CDN $3.29 per gj(1)(6) |
(19,500) |
gjpd |
April 1 - October 31 |
Crude Oil |
US $89.32 per bbl(2)(6) |
675 |
bpd |
April 1 - October 31 |
|
CDN $86.43 per bbl(2)(8) |
10,150 |
bpd |
January 1 - January 31 |
|
Propane |
US $0.955 per gallon(3)(6) |
528 |
bpd |
April 1 - December 31 |
Normal Butane |
US $1.507 per gallon(4)(6) |
500 |
bpd |
April 1 - October 31 |
ISO Butane |
US $1.636 per gallon(5)(6) |
250 |
bpd |
April 1 - October 31 |
Foreign Exchange |
Sell US $8,400,000 @ 0.9956(7) |
|
|
April 1 - October 31 |
|
Sell US $20,850,000
@ 0.9979(7) |
|
|
April 1 - December
31 |
2014 |
Propane |
US $0.955 per gallon(3)(6) |
745 |
bpd |
January 1 - March 31 |
Foreign
Exchange |
Sell US $2,700,000 @
0.9979(7) |
|
|
January 1 - March
31 |
(1) |
Natural gas contracts are settled against Canadian Gas Price
Reporter AECO's monthly index. |
(2) |
Crude oil contracts are settled against NYMEX WTI calendar
average in U.S. or CDN dollars. |
(3) |
Propane contracts are settled against OPIS Mont Belvieu C3
TET. |
(4) |
Normal butane contracts are settled against OPIS Mont Belvieu
NC4 NON TET. |
(5) |
ISO butane contracts are settled against OPIS Mont Belvieu IC4
NON TET. |
(6) |
Frac spread contracts entered into to manage revenue and costs
associated with natural gas based supply arrangements. |
(7) |
U.S. dollar forward contracts are settled against the Bank of
Canada noon rate average. Selling notional U.S. dollars for
Canadian dollars at a fixed exchange rate results in a fixed
Canadian dollar price for the underlying commodity. |
(8) |
Product margin contracts entered into to protect margins on
commodity contracts. |
The following table summarizes the impact of commodity-related
derivative financial contracts settled during 2012 and 2011 which
were included in the realized gain/loss on commodity-related
derivative financial instruments:
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions) |
2012 |
2011 |
2012 |
2011 |
Realized gain (loss) on commodity-related
derivative financial instruments |
|
|
|
|
Frac spread related |
5.7 |
|
(4.5) |
|
Product margin |
4.2 |
(0.4) |
(0.2) |
0.9 |
Power |
1.1 |
1.3 |
0.1 |
4.4 |
Realized gain (loss) on commodity-related
derivative financial instruments |
11.0 |
0.9 |
(4.6) |
5.3 |
The realized gain on commodity-related derivative financial
instruments for the fourth quarter of 2012 was $11 million compared to a realized gain of
$0.9 million in the comparable period
of 2011. The majority of the realized gain in the fourth quarter of
2012 was driven by NGL derivative sales contracts settling at
contracted prices higher than the current NGL market prices during
the settlement period and was partially offset by natural gas
derivative purchase contracts settling at contracted prices higher
than the market natural gas prices during the settlement period.
For the year ended December 31, 2012,
the Company recognized a realized loss on commodity-related
derivative financial instruments of $4.6
million which reflects natural gas derivative purchase
contracts settling at contracted prices higher than the market
natural gas prices during the settlement period.
For more information on financial instruments and financial risk
management, see Note 27 to the Consolidated Financial
Statements.
Business Environment
|
|
|
|
|
|
|
|
3 Months Ended
December 31 |
12 Months Ended
December 31 |
|
2012 |
2011 |
% Change |
2012 |
2011 |
% Change |
WTI crude oil (U.S. $ per bbl) |
$88.18 |
$94.06 |
(6) |
$94.21 |
$95.12 |
(1) |
Exchange rate (from U.S.$ to Cdn$) |
$0.99 |
$1.03 |
3 |
$1.00 |
$0.99 |
(1) |
WTI crude oil (expressed in Cdn$ per
bbl) |
$87.31 |
$96.68 |
(10) |
$94.12 |
$94.21 |
|
|
|
|
|
|
|
|
AECO natural gas index (Cdn$ per GJ) |
$2.90 |
$3.29 |
(12) |
$2.28 |
$3.48 |
(34) |
|
|
|
|
|
|
|
Mont Belvieu Propane (U.S.$ per U.S.
gallon) |
$0.88 |
$1.44 |
(39) |
$1.00 |
$1.47 |
(32) |
Mont Belvieu Propane expressed as a percentage of
WTI |
42% |
64% |
(34) |
45% |
65% |
(31) |
|
|
|
|
|
|
|
Market Frac Spread in Cdn$ per
bbl(1) |
$38.61 |
$58.41 |
(34) |
$44.70 |
$54.67 |
(18) |
(1) |
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. |
Overall, weaker commodity markets impacted the performance of
broader market indices. During the fourth quarter of 2012, the
S&P TSX Composite Index saw a one percent increase compared to
the previous quarter, with the value of the Index also realizing a
four percent increase over 2011.
The Canadian dollar declined modestly against the U.S. dollar
during most of the fourth quarter, averaging $0.99 per U.S. dollar; however, it was stronger
than an average value of $1.03 per
U.S. dollar during the fourth quarter of 2011.
With respect to commodity prices:
- The benchmark WTI oil price exited 2012 at U.S. $91.82/bbl, with prices remaining range-bound
after recovering from lows set earlier in the year. The Canadian
heavy crude oil benchmark differential, Western Canadian Select,
compared to WTI widened significantly in the fourth quarter as
infrastructure constraints were aggravated by continued production
growth from the WCSB. Compared to $17.17 per barrel differential in 2011, the
Western Canadian Select differential averaged $25.23 in 2012.
- Natural gas prices posted strong gains in the fourth quarter as
more seasonal temperatures returned to North America. An abnormally warm 2011/2012
winter depressed pricing through the first half of 2012 resulting
in a full year average of $2.28
compared to $3.48 in 2011. While low
natural gas prices are generally favourable for NGL extraction and
fractionation economics, a sustained low gas price could impact the
availability and overall cost of natural gas and NGL mix supply in
western Canada with the potential
for natural gas producers to elect to shut-in production or reduce
drilling activities.
- NGL prices in the fourth quarter of 2012 were mixed across
products and continued to be negatively impacted by a warm
2011/2012 winter and increasing production. This resulted in a
North American supply-demand imbalance.
-
- In the U.S., industry propane/propylene inventories were
approximately 66.7 million barrels at the end of 2012
(approximately 15.9 million barrels or 31 percent above the
five-year historical average for this period).
- In Canada, industry propane
inventories increased to 8.7 million barrels at the end of 2012
(2.5 million barrels, or 40 percent higher, than the historic
five-year average).
- This over-supply continues to exert pressure on prices, where
the Mont Belvieu propane price averaged U.S. $0.88 per U.S. gallon (42 percent of WTI) in the
fourth quarter of 2012 and U.S. $1.00
per U.S. gallon (44 percent of WTI) for the full year,
significantly below its five-year average of 58 percent of
WTI.
- Butane and condensate sales prices were robust in the fourth
quarter; however, price levels remained below those of 2011.
- Market frac spreads averaged $38.61 per barrel and $44.70 per barrel during the fourth quarter and
full year of 2012, respectively, compared to $58.41 per barrel and $54.67 per barrel during the same periods of the
prior year. The market frac spread does not include extraction
premiums, operating/transportation/storage costs and regional sales
prices.
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 Pembina's pipelines
include the Cardium, Montney,
Cretaceous, Duvernay and
Swan Hills. While recent
weaknesses in NGL prices and crude oil differentials as well as an
inflationary cost environment have resulted in some producers
scaling back activity in the WCSB, Pembina expects to see a
continued positive growth profile for energy infrastructure.
Non-Operating Expenses
G&A
Pembina incurred G&A (including corporate depreciation and
amortization) of $27.3 million during
the fourth quarter of 2012 compared to $21
million during the fourth quarter of 2011. G&A for the
year was $97.5 million compared to
$62.2 million in 2011. The increase
in G&A compared to the prior year is mainly due to the addition
of employees who joined Pembina through the Acquisition, an
increase in salaries and benefits for existing and new employees,
and increased rent for expanded office space. In addition, every
$1 change in share price is expected
to change Pembina's annual share-based incentive expense by
$1.2 million.
Depreciation & Amortization (operational)
Operational depreciation and amortization increased to
$47.8 million during the fourth
quarter of 2012 compared to $19.6
million during the same period in 2011. For the year ended
December 31, 2012, operational
depreciation and amortization was $173.6
million, up from $68 million
last year. Both increases reflect depreciation on new property,
plant and equipment and depreciable intangibles including those
assets acquired through the Acquisition.
Acquisition-Related and Other
Acquisition-related and other expenses during the fourth quarter
of 2012 were $0.5 million compared to
$0.8 million in 2011. For the year
ended December 31, 2012,
acquisition-related and other expenses were $24.7 million which includes acquisition expenses
of $15.9 million and $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 fourth quarter of 2012 were
$35.7 million compared to
$22.1 million in the fourth quarter
of 2011. Net finance costs for the full year of 2012 totalled
$115.1 million compared to
$91.9 million in 2011. The increases
primarily relate to a $16.2 million
year-over-year increase in loans and borrowings interest expense
due to higher debt balances and an increase in interest on
convertible debentures totalling $17.9
million, due to the debentures assumed on closing of the
Acquisition. These factors were offset by an $11.7 million increase in the change in the fair
value of non-commodity-related derivative financial instruments for
the year when compared to the same period in 2011. (See Notes 21
and 27 to the Consolidated Financial Statements for the year ended
December 31, 2012.) Beginning in the
second quarter of 2012, the change in fair value of
commodity-related derivative financial instruments was reclassified
from net finance costs to gain/loss on commodity-related derivative
financial instruments and is 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 $27.1 million was
recorded in the fourth quarter of 2012 compared to a reduction of
$0.2 million in the fourth quarter of
2011. Income tax expense in 2012 totalled $75.3 million compared to $38.9 million in 2011, which includes changes in
estimates from the prior year.
Pension Liability
Pembina maintains a defined contribution plan and
non-contributory defined benefit pension plans covering employees
and retirees. The defined benefit plans include a funded registered
plan for all employees and an unfunded supplemental retirement plan
for those employees affected by the Canada Revenue Agency maximum
pension limits. At the end of 2012, the pension plans carried a
deficit of $27.6 million compared to
a deficit of $15.8 million at the end
of 2011. At December 31, 2012, plan
obligations amounted to $128 million
(2011: $105.2 million) compared to
plan assets of $100.4 million (2011:
$89.4 million). In 2012, the pension
plans' expense was $7.2 million
(2011: $4.7 million). Contributions
to the pension plans totaled $10
million in 2012 and $8 million
in 2011.
In 2013, contributions to the pension plans are expected to be
$12.6 million and pension plans'
expenses are anticipated to be $10.6
million. Management anticipates a long-term return on the
pension plans' assets of 5.8 percent and an annual increase in
compensation of 4 percent, which are consistent with current
industry standards.
Liquidity & Capital Resources
|
|
|
($ millions) |
December 31, 2012 |
December 31, 2011 |
Working capital |
62.7 |
(343.7)(1) |
Variable rate debt(2) |
|
|
|
Bank debt |
525.0 |
313.8 |
|
Variable rate debt swapped to fixed |
(380.0) |
(200.0) |
Total variable rate
debt outstanding (average rate of 2.94%) |
145.0 |
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 1 |
250.0 |
250.0 |
|
Senior unsecured medium-term note 2 |
450.0 |
|
|
Subsidiary debt |
9.3 |
|
|
Variable rate debt swapped to fixed |
380.0 |
200.0 |
Total fixed rate debt outstanding
(average of 4.90%) |
1,806.3 |
1,225.0 |
Convertible
debentures(2) |
644.3 |
299.8 |
Finance lease liability |
5.8 |
5.6 |
Total debt and debentures
outstanding |
2,601.4 |
1,644.2 |
Cash and unutilized debt
facilities |
1,032.3 |
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 short-term, Pembina
expects to source funds required for capital projects from cash and
cash equivalents and unutilized debt facilities totalling
$1,032.3 million as at December 31, 2012. In addition, based on its
successful access to financing in the debt and equity markets
during the past several years, Pembina believes it would likely
continue to have access to funds at attractive rates. Pembina also
has reinstated its DRIP as of the January
25, 2012 dividend 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, seek new borrowing and/or
issue equity.
In connection with the closing of the Acquisition on
April 2, 2012, Pembina increased its
$800 million facility to $1.5 billion for a term of five years. Upon
closing of the Acquisition, Pembina used the facility, in part, to
repay Provident's revolving term credit facility of $205 million. Further, Pembina renegotiated its
operating facility to $30 million
from $50 million.
Pembina's credit facilities at December
31, 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 credit
facilities are based on the credit rating of Pembina's senior
unsecured debt. There are no repayments due over the term of these
facilities. As at December 31, 2012,
Pembina had $525 million drawn on
bank debt, $0.1 million in letters of
credit and $27.3 million in cash,
leaving $1,032.3 million of
unutilized debt facilities on the $1,530
million of established bank facilities. Pembina also had an
additional $14.3 million in letters
of credit issued in a separate demand letter of credit facility.
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; $250 million in
senior unsecured medium-term notes due 2021; and $450 million in senior unsecured medium-term
notes due 2022. 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
December 31, 2012, Pembina had loans
and borrowing (excluding amortization, letters of credit and
finance lease liabilities) of $1,951.3
million. Pembina's senior debt to total capital at
December 31, 2012 was 28 percent.
Offering of Medium-Term Notes
On October 22, 2012, Pembina
closed the offering of $450 million
principal amount of senior unsecured medium-term notes ("Notes").
The Notes have a fixed interest rate of 3.77% per annum, paid
semi-annually, and will mature on October
24, 2022. The net proceeds from the offering of the Notes
were used to repay a portion of Pembina's existing credit facility.
Standard & Poor's Rating Services ("S&P") and DBRS Limited
("DBRS") have assigned credit ratings of BBB to the Notes.
Credit Ratings
The following information with respect to Pembina's credit
ratings is provided as it relates to Pembina's financing costs and
liquidity. Specifically, credit ratings affect Pembina's ability to
obtain short-term and long-term financing and the cost of such
financing. A reduction in the current ratings on Pembina's debt by
its rating agencies, particularly a downgrade below investment
grade ratings, could adversely affect Pembina's cost of financing
and its access to sources of liquidity and capital. In addition,
changes in credit ratings may affect Pembina's ability to, and the
associated costs of, entering into normal course derivative or
hedging transactions. Credit ratings are intended to provide
investors with an independent measure of credit quality of any
issues of securities. The credit ratings assigned by the rating
agencies are not recommendations to purchase, hold or sell the
securities nor do the ratings comment on market price or
suitability for a particular investor. Any rating may not remain in
effect for a given period of time or may be revised or withdrawn
entirely by a rating agency in the future if in its judgement
circumstances so warrant.
DBRS rates Pembina's senior unsecured notes 'BBB'. S&P's
long-term corporate credit rating on Pembina is 'BBB'.
Assumption of rights related to the Series E and Series F
Debentures
On closing of the Acquisition on April 2,
2012, Pembina assumed all of the rights and obligations of
Provident relating to the 5.75 percent convertible unsecured
subordinated debentures maturing December
31, 2017 (TSX: PPL.DB.E), and the 5.75 percent convertible
unsecured subordinated debentures maturing December 31, 2018 (TSX: PPL.DB.F). Outstanding
Series E and Series F debentures at April 2,
2012 were $345 million. As of
December 31, 2012, $344.6 million of the debentures are still
outstanding.
Capital Expenditures
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions) |
2012 |
2011 |
2012 |
2011 |
Development capital |
|
|
|
|
|
Conventional Pipelines |
88.1 |
24.9 |
187.3 |
72.0 |
|
Oil Sands & Heavy Oil |
18.3 |
47.8 |
30.4 |
191.7 |
|
Gas Services |
77.2 |
66.4 |
162.8 |
136.5 |
|
Midstream |
77.4 |
4.6 |
204.0 |
111.5 |
Corporate/other projects |
(6.3) |
5.2 |
(0.2) |
15.9 |
Total development capital |
254.7 |
148.9 |
584.3 |
527.6 |
During 2012, capital expenditures were $584.3 million compared to $527.6 million in 2011. In the comparable period
in 2011, the Company's capital expenditures included the
construction of the Nipisi and Mitsue pipelines, the acquisition of
midstream assets in the Edmonton,
Alberta area (related to PNT), linefill for the Peace
Pipeline system as well as construction of the Musreau deep cut
facility.
The majority of the capital expenditures in the fourth quarter
and full year of 2012 were in Pembina's Conventional Pipelines, Gas
Services and Midstream businesses. Conventional Pipelines' capital
was incurred to progress the Northern NGL Expansion and on various
new connections. Gas Services' capital was deployed to complete the
Musreau deep cut facility and the expansion of the shallow cut
facility at the Cutbank Complex, as well as to progress the Saturn
and Resthaven enhanced NGL extraction facilities. Midstream's
capital expenditures were primarily directed towards cavern
development and related infrastructure as well as the 8,000 bpd
expansion at the Redwater
facility.
Contractual Obligations at December
31, 2012
|
|
|
|
|
|
($ millions) |
Payments Due By
Period |
Contractual
Obligations |
Total |
Less than
1 year |
1 - 3 years |
3 - 5 years |
After
5 years |
Operating and finance leases |
293.0 |
25.4 |
55.5 |
58.8 |
153.6 |
Loans and borrowings(1) |
2,446.7 |
80.6 |
368.9 |
637.2 |
1,360.0 |
Convertible debentures(1) |
903.5 |
39.2 |
78.9 |
251.7 |
533.7 |
Construction commitments |
362.8 |
324.2 |
38.6 |
|
|
Provisions(2) |
361.7 |
0.5 |
5.5 |
25.9 |
330.1 |
Total contractual obligations |
4,367.7 |
469.9 |
546.8 |
973.6 |
2,377.4 |
(1) Excluding deferred financing costs. |
(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 Saturn facility
and the Resthaven facility. See "Forward-Looking Statements &
Information."
The contractual obligations noted above have changed
significantly since December 31,
2011, due primarily to the assumption of the contractual
obligations of Provident as a result of the Acquisition.
Critical Accounting Estimates
The preparation of the Consolidated Financial Statements in
conformity with IFRS requires management to make judgments,
estimates and assumptions that are 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.
The following judgment and estimation uncertainties are those
management considers material to the Company's financial
statements:
Judgments
(i) Business combinations
Business combinations are accounted for using the acquisition
method of accounting. The determination of fair value often
requires management to make judgments about future possible events.
The assumptions with respect to determining the fair value of
property, plant and equipment and intangible assets acquired
generally require the most judgment.
(ii) Componentization
The componentization of the Company's assets are based on
management's judgment of which components constitute a significant
cost in relation to the total cost of an asset and whether these
components have similar or dissimilar patterns of consumption and
useful lives for purposes of calculating depreciation and
amortization.
(iii) Depreciation and amortization
Depreciation and amortization of property, plant and equipment
and intangible assets are based on management's judgment of the
most appropriate method to reflect the pattern of an asset's future
economic benefit expected to be consumed by the Company. Among
other factors, these judgments are based on industry standards and
historical experience.
Estimates
(i) Inventory
Due to the inherent limitations in metering and the physical
properties of storage caverns and pipelines, the determination of
precise volumes of NGL held in inventory at such locations is
subject to estimation. Actual inventories of NGL within storage
caverns can only be determined by draining the caverns.
(ii) Financial derivative instruments
The Company's financial derivative instruments are recognized on
the Statement of Financial Position at fair value based on
management's estimate of commodity prices, share price and
associated volatility, foreign exchange rates, interest rates and
the amounts that would have been received or paid to settle these
instruments prior to maturity given future market prices and other
relevant factors.
(iii) Business Combinations
Estimates of future cash flows, forecast prices, interest rates
and discount rates are made in determining the fair value of assets
acquired and liabilities assumed for allocation of the purchase
price. Changes in any of the assumptions or estimates used in
determining the fair value of acquired assets and liabilities could
impact the amounts assigned to assets, liabilities, intangibles and
goodwill in the purchase price analysis. Future net earnings can be
affected as a result of changes in future depreciation and
amortization, asset or goodwill impairment.
(iv) Defined benefit obligations
The calculation of the defined benefit obligation is sensitive
to many estimates, but most significantly the discount rate
applied.
(v) Provisions and contingencies
Provisions recognized are based on management's judgment about
assessing contingent liabilities and timing, scope and amount of
liabilities. Management uses judgment in determining the likelihood
of realization of contingent assets and liabilities to determine
the outcome of contingencies.
Based on the long-term nature of the decommissioning provision,
the biggest uncertainties in estimating the provision are the
discount rates used, the costs that will be incurred and the timing
of when these costs will occur. In addition, in determining the
provision it is assumed the Company will utilize technology and
materials that are currently available.
(vi) Share-based payments
Compensation costs pursuant to the share-based compensation
plans are subject to estimated fair values, forfeiture rates and
the future attainment of performance criteria.
(vii) Deferred taxes
The calculation of the deferred tax asset or liability is based
on assumptions about the timing of many taxable events and the
enacted or substantively enacted rates anticipated to apply to
income in the years in which temporary differences are expected to
be realized or reversed.
(viii) Depreciation and amortization
Estimated useful lives of property, plant and equipment is based
on management's assumptions and estimates of the physical useful
lives of the assets, the economic life, which may be associated
with the reserve life and commodity type of the production area, in
addition to the estimated residual value.
Changes in Accounting Principles and Practices
Subsequent to the Acquisition, Pembina reviewed and compared
legacy Provident's accounting policies with the Company's existing
policies and determined there were no significant differences.
New standards and interpretations not yet adopted
Certain new standards, interpretations, amendments and
improvements to existing standards were issued by the IASB or
International Financial Reporting Interpretations Committee
("IFRIC") for accounting periods beginning after January 1, 2013. The Company has reviewed these
and determined that the following:
IFRS 7 Financial Instruments: Disclosures - in
December 2011, the IASB issued
amendments to IFRS 7 which outline disclosures that are required
for any financial assets or liabilities that are offset in
accordance with IAS 32. The amendments to this standard are
required to be adopted for periods beginning January 1, 2013. The adoption of these amendments
is not expected to have a material impact on the Company's
Financial Statements.
IFRS 9 Financial Instruments - in November 2009 and revised in October 2010 the IASB issued IFRS 9. This
standard replaces the current multiple classification and
measurement model for financial assets and liabilities with a
proposed single model for only two classification categories:
amortized cost and fair value. The standard is currently required
to be adopted for periods beginning January
1, 2015. The extent of the impact of adoption of this
standard has not yet been determined.
IFRS 10 Consolidated Financial Statements - in
May 2011, the IASB issued IFRS 10
which provides additional guidance to determine whether an entity
should be included within the consolidated financial statements of
Pembina. The guidance applies to all investees, including special
purpose entities. The standard is required to be adopted for
periods beginning January 1, 2013.
The adoption of this standard is not expected to have a material
impact on the Company's Financial Statements.
IFRS 11 Joint Arrangements - in May 2011, the IASB issued IFRS 11 which presents
a new model for the financial reporting of joint arrangements. The
new model determines whether an entity should account for joint
arrangements using proportionate consolidation or the equity method
with emphasis on the substance rather than legal form of a joint
arrangement. The standard is required to be adopted for periods
beginning January 1, 2013. The
adoption of this standard is not expected to have a material impact
on the Company's Financial Statements.
IFRS 12 Disclosure of Interests in Other Entities - in
June 2011, the IASB issued IFRS 12
which provides guidance on the disclosure requirements for
subsidiaries, joint arrangements, associates and unconsolidated
structured entities. The standard is required to be adopted for
periods beginning January 1, 2013.
The adoption of this standard is not expected to have a material
impact on the Company's Financial Statements.
IFRS 13 Fair Value Measurement - in June 2011, the IASB issued IFRS 13 to provide
specific guidance for all standards where IFRS requires or permits
fair value measurement. The standard defines fair value and
provides guidance on disclosures about fair value measurements. The
standard is required to be adopted for periods beginning
January 1, 2013. The adoption of this
standard is not expected to have a material impact on the Company's
Financial Statements.
IAS 19 Employee Future Benefits - in June 2011, the IASB issued amendments to IAS 19
which limit the way actuarial gains and losses can be recorded and
the way finance costs can be calculated, along with requirements
for additional disclosures for defined benefit plans. The
amendments to this standard are required to be adopted for periods
beginning January 1, 2013. The
adoption of these amendments is not expected to have a material
impact on the Company's Financial Statements.
IAS 32 Financial Instruments: Presentation - in
December 2011, the IAS issued
amendments which clarify matters regarding offsetting financial
assets and financial liabilities. The amendments to this standard
are required to be adopted for periods beginning January 1, 2014. The Company is currently
evaluating the impact that these amendments will have on its
results of operations and financial position.
Controls and Procedures
As part of the requirements mandated by the Canadian securities
regulatory authorities under National Instrument 52-109 -
Certification of Disclosure in Issuers' Annual and Interim Filings
("NI 52-109"), Pembina's Chief Executive Officer ("CEO") and the
Chief Financial Officer ("CFO") have evaluated the design and
operation of Pembina's disclosure controls and procedures
("DC&P"), as such term is defined in NI 52-109, as at
December 31, 2012. Based on that
evaluation, the CEO and the CFO concluded that Pembina's DC&P
was effective as at December 31,
2012.
The CEO and CFO are also responsible for establishing and
maintaining internal controls over financial reporting ("ICFR"), as
such term is defined in NI 52-109. These controls are designed to
provide reasonable assurance regarding the reliability of Pembina's
financial reporting and compliance with GAAP. Pembina's CEO and CFO
have evaluated the design and operational effectiveness of such
controls as at December 31, 2012.
Based on the evaluation of the design and operating effectiveness
of Pembina's ICFR, the CEO and the CFO concluded that Pembina's
ICFR was effective as at December 31,
2012.
Changes in internal control over financial reporting
During 2012, there have been no changes to 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 NI 52-109, management,
including the CEO and CFO, have limited the scope of their design
of the Company's DC&P and ICFR 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 Consolidated
Financial Statements for the quarter and year ended December 31, 2012 were approximately 36 percent
and 32 percent of consolidated revenue, respectively, and
approximately 11 percent and 24 percent of consolidated pre-tax
earnings, respectively.
Additionally, as at December 31,
2012, Provident's current assets and current liabilities
were approximately 59 percent and 44 percent of consolidated
current assets and liabilities, respectively, and its non-current
assets and non-current liabilities were approximately 57 percent
and 34 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 DC&P and ICFR in a manner consistent with
the Company's other operations.
Further details related to the Acquisition are disclosed in Note
5 in the Notes to the Company's Consolidated Financial Statements
for the year ended December 31,
2012.
Trading Activity and Total Enterprise
Value(1)
|
|
|
|
|
|
As at and for the 12
months ended |
($ millions, except where
noted) |
February 26, 2013(2) |
December 31, 2012 |
December 31, 2011 |
Trading volume and value |
|
|
|
|
Total volume (shares) |
19,509,172 |
180,317,622 |
75,574,785 |
|
Average daily volume (shares) |
500,235 |
718,397 |
325,753 |
|
Value traded |
568.7 |
5,021.6 |
1,947.7 |
Shares outstanding
(shares) |
294,924,568 |
293,226,473 |
167,908,271 |
Closing share price
(dollars) |
28.89 |
28.46 |
29.66 |
Market value |
|
|
|
|
Shares |
8,520.4 |
8,345.2 |
4,980.2 |
|
5.75% convertible debentures (PPL.DB.C) |
334.0(3) |
332.7(4) |
326.8(5) |
|
5.75% convertible debentures (PPL.DB.E) |
205.3(6) |
201.4(7) |
|
|
5.75% convertible debentures (PPL.DB.F) |
193.5(8) |
191.0(9) |
|
Market capitalization |
9,253.2 |
9,070.3 |
5,306.9 |
Senior debt |
1,932.0 |
1,942.0 |
1,338.1 |
Total enterprise
value(10) |
11,185.2 |
11,012.3 |
6,645.0 |
(1) Trading information in this table reflects
the activity of Pembina securities on the TSX only.
(2) Based on 39 trading days from January 2, 2013 to February 26, 2013, inclusive.
(3) $299.7 million
principal amount outstanding at a market price of $111.42 at February 26,
2013 and with a conversion price of $28.55.
(4) $299.7 million
principal amount outstanding at a market price of $111.00 at December 31,
2012 and with a conversion price of $28.55.
(5) $300.0 million
principal amount outstanding at a market price of $102.95 at December 31,
2011 and with a conversion price of $28.55.
(6) $172.1 million
principal amount outstanding at a market price of $119.36 at February 26,
2013 and with a conversion price of $24.94.
(7) $172.1 million
principal amount outstanding at a market price of $117.00 at December 31,
2012 and with a conversion price of $24.94.
(8) $172.4 million
principal amount outstanding at a market price of $112.20 at February 26,
2013 and with a conversion price of $29.53.
(9) $172.4 million
principal amount outstanding at a market price of $110.75 at December 31,
2012 and with a conversion price of $29.53.
(10) Refer to "Non-GAAP Measures."
As indicated in the previous table, Pembina's total enterprise
value was $11 billion at December 31, 2012, and the Company's issued and
outstanding shares rose to 293.2 million at the end of 2012
compared to 167.9 million at the end of 2011 primarily due to
shares issued pursuant to the Acquisition.
Dividends
On April 12, 2012, following
closing of the Acquisition, Pembina announced a 3.8 percent
increase in its monthly dividend rate to $0.135 per share per month (or $1.62 annualized) from $0.13 per share per month previously (or
$1.56 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 reinstated its DRIP effective 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 full year of 2012 was
approximately 58 percent of common shares outstanding for proceeds
of approximately $218.7 million.
Listing on the NYSE
On April 2, 2012, Pembina listed
its common shares, including those issued under the Acquisition, on
the NYSE under the symbol "PBA."
Risk Factors
Pembina's value proposition is based on maintaining a very low
risk profile. In addition to contractually eliminating the majority
of its business risk, Pembina has formal risk management policies,
procedures and systems designed to mitigate any residual risks,
such as market price risk, credit risk and operational risk.
Certain of the risks associated with Pembina's business are
discussed below. For a full discussion of these and other risk
factors affecting the business and operation of Pembina and its
operating subsidiaries, readers are referred to Pembina's Annual
Information Form, an electronic copy of which is available at
www.pembina.com or on Pembina's SEDAR profile at www.sedar.com.
Shareholders and prospective investors should carefully consider
these risk factors before investing in Pembina's securities, as
each of these risks may negatively affect the trading price of
Pembina's securities, the amount of dividends paid to shareholders
and the ability of Pembina to fund its debt obligations, including
debt obligations under its outstanding convertible debentures and
any other debt securities that Pembina may issue from time to
time.
RISKS INHERENT IN PEMBINA'S BUSINESS
Operational Risks
Operational risks include: pipeline leaks, the breakdown or
failure of equipment, information systems or processes; the
performance of equipment at levels below those originally intended
(whether due to misuse, unexpected degradation or design,
construction or manufacturing defects); spills at truck terminals
and hubs; failure to maintain adequate supplies of spare parts;
operator error; labour disputes; disputes with interconnected
facilities and carriers; operational disruptions or apportionment
on third-party systems or refineries which may prevent the full
utilization of the Company's pipelines; and catastrophic events
such as natural disasters, fires, explosions, fractures, acts of
terrorists and saboteurs; and, other similar events, many of which
are beyond the control of Pembina. The occurrence or continuance of
any of these events could increase the cost of operating Pembina's
assets or reduce revenue, thereby impacting earnings.
Pembina is committed to preserving customer and shareholder
value by proactively managing operational risk through safe and
reliable operations. Senior managers are responsible for the daily
supervision of operational risk by ensuring appropriate policies
and procedures are in place within their business units and
internal controls are operating efficiently. Pembina also has an
extensive program to manage system integrity, which includes the
development and use of in-line inspection tools and various other
leak detection technologies. Maintenance, excavation and repair
programs are directed to the areas of greatest benefit, and pipe is
replaced or repaired as required. Pembina also maintains
comprehensive insurance coverage for significant pipeline leaks and
has a comprehensive security program designed to reduce
security-related risks. While Pembina feels the level of insurance
is adequate, it may not be sufficient to cover all potential
losses.
Midstream Business
Pembina's Midstream business includes product storage
terminalling and hub services. These activities expose Pembina to
certain risks including that Pembina may experience volatility in
revenue due to variations in commodity prices. Primarily, Pembina
enters into contracts to purchase and sell crude oil at floating
market prices. The prices of products that are marketed by Pembina
are subject to fluctuations as a result of such factors as seasonal
demand changes, general economic conditions, changes in crude oil
markets and other factors. Pembina manages its risk exposure by
balancing purchases and sales to lock-in margins. Notwithstanding
Pembina's management of price and quality risk, marketing margins
for crude oil can vary and has varied significantly from period to
period and this could have an adverse effect on the results of
Pembina's commercial Midstream business and Pembina's overall
results of operations. To assist in effectively smoothing that
variability, Midstream is investing in assets that have a fee-based
revenue component, and looking to expand this approach going
forward.
The Midstream business is exposed to possible price declines
between the time Pembina purchases NGL feedstock and sells NGL
products, and to narrowing frac spreads. Frac spread is the
difference between the selling prices for NGL products and the
input cost of the natural gas required to produce the respective
NGL products. The frac spread can change significantly from period
to period depending on the relationship between crude oil and
natural gas prices (the "frac spread ratio"), absolute commodity
prices, and changes in the Canadian to U.S. dollar foreign exchange
rate. There is also a differential between NGL product prices and
crude oil prices which can change prices received and margins
realized for midstream products separate from frac spread ratio
changes. The amount of profit or loss made on the extraction
portion of the NGL midstream business will generally increase or
decrease with the frac spread. This exposure could result in
material variability of cash flow generated by the NGL midstream
business, which could negatively affect Pembina and the cash
dividends of Pembina.
Reputation
Reputational risk is the potential for negative impacts that
could result from the deterioration of Pembina's reputation with
key stakeholders. The potential for harming Pembina's corporate
reputation exists in every business decision, and all risks can
have an impact on reputation, which in turn can negatively impact
Pembina's business and its securities. Reputational risk cannot be
managed in isolation from other forms of risk. Credit, market,
operational, insurance, liquidity, and regulatory and legal risks
must all be managed effectively to safeguard Pembina's reputation.
Negative impacts from a compromised reputation could include
revenue loss, reduction in customer base, delays in regulatory
approvals on growth projects, and decreased value of Pembina's
securities.
Pembina's reputation as a reliable and responsible energy
services provider with consistent financial performance and
long-term financial stability is one of its most valuable assets.
Key to effectively building and maintaining Pembina's reputation is
fostering a culture that promotes integrity and ethical conduct.
Ultimate responsibility for Pembina's reputation lies with the
executive team, who examines reputational risk and issues as part
of all business decisions. Nonetheless, every employee and
representative of Pembina has a responsibility to contribute in a
positive way to its reputation. This means ensuring ethical
practices are followed at all times, interactions with our
stakeholders are positive, and compliance with applicable policies,
legislation and regulations. Reputational risk is most effectively
managed when every individual works continuously to protect and
enhance Pembina's reputation.
Environmental Costs & Liabilities
Pembina's operations, facilities and petroleum product shipments
are subject to extensive national, regional and local
environmental, health and safety laws and regulations governing,
among other things, discharges to air, land and water, the handling
and storage of petroleum compounds and hazardous materials, waste
disposal, the protection of employee health, safety and the
environment, and the investigation and remediation of
contamination. Pembina's facilities could experience incidents,
malfunctions or other unplanned events that result in spills or
emissions in excess of permitted levels and result in personal
injury, fines, penalties or other sanctions and property damage.
Pembina could also incur liability in the future for environmental
contamination associated with past and present activities and
properties. Pembina's facilities and pipelines must maintain a
number of environmental and other permits from various governmental
authorities in order to operate, and these facilities are subject
to inspection from time to time. Failure to maintain compliance
with these requirements could result in operational interruptions,
fines or penalties, or the need to install potentially costly
pollution control technology.
While Pembina believes its current operations are in compliance
with all applicable environmental and safety regulations, there can
be no assurance that substantial costs or liabilities will not be
incurred. Moreover, it is possible that other developments, such as
increasingly strict environmental and safety laws, regulations and
enforcement policies thereunder, claims for damages to persons or
property resulting from Pembina's operations, and the discovery of
pre-existing environmental liabilities in relation to any of
Pembina's existing or future properties or operations, could result
in significant costs and liabilities to Pembina. In addition, the
costs of environmental liabilities in relation to spill sites of
which Pembina is currently aware could be greater than Pembina
currently anticipates, and any such differences could be
substantial. If Pembina were not able to recover the resulting
costs or increased costs through insurance or increased tariffs,
cash flow available to pay dividends to shareholders and to service
obligations under its convertible debentures and other debt
obligations could be adversely affected.
While Pembina maintains insurance in respect of damage caused by
seepage or pollution in an amount it considers prudent and in
accordance with industry standards, certain provisions of such
insurance may limit the availability in respect of certain
occurrences unless they are discovered within fixed timed periods.
These periods can range from 72 hours to 30 days. Although Pembina
believes it has adequate leak detection systems in place to monitor
a significant spill of product, if Pembina is unaware of a problem
or is unable to locate the problem within the relevant time period,
insurance coverage may not be available. However, Pembina believes
it has adequate leak detection systems in place to detect and
monitor a significant spill.
Pembina is committed to protecting the health and safety of
employees, contractors and the general public, and to sound
environmental stewardship. Pembina believes that prevention of
incidents and injuries, and protection of the environment, benefits
everyone and delivers increased value to shareholders, customers
and employees.
Pembina has health, safety and environmental management systems
and established policies, programs and practices for conducting
safe and environmentally sound operations. Pembina conducts regular
reviews and audits to assess compliance with legislation and
company policy.
Abandonment Costs
Pembina is responsible for compliance with all applicable laws
and regulations regarding the abandonment of its pipeline and other
assets at the end of their economic life, and these abandonment
costs may be substantial. The proceeds of the disposition of
certain assets associated with Pembina's pipeline systems,
including, in respect of certain pipeline systems, linefill may be
available to offset abandonment costs. However, it is not possible
to definitively predict abandonment costs since they will be a
function of regulatory requirements at the time, and the value of
Pembina's assets, including linefill, may then be more or less than
the abandonment costs. Pembina may, in the future, determine it
prudent or be required by applicable laws or regulations to
establish and fund one or more reclamation funds to provide for
payment of future abandonment costs. Such reserves could decrease
cash flow available for dividends to shareholders and to service
obligations under Pembina's outstanding convertible debentures and
other debt obligations.
On May 26, 2009 the NEB issued its
Reasons for Decision RH-2-2008 with respect to the Land Matters
Consultation Initiative - Stream 3 which dealt with financial
issues of pipeline abandonment for pipelines under the NEB's
jurisdiction. The NEB decided in principle to set an ultimate goal
to have all companies under its jurisdiction begin setting aside
funds for the abandonment of pipelines no later than 5 years from
the date of the decision. The NEB recommended an action plan to
achieve this ultimate goal that would require pipelines to submit
to the NEB preliminary cost estimates and fund collection
mechanisms for pipeline abandonment prior to the setting aside of
funds. In November 2011, Pembina (and
formally Provident) submitted preliminary cost estimates totalling
$11,350,000 to the NEB for its
affected approximately 275 km segments of pipeline. Pembina is
working towards a pipeline abandonment fund collection plan and set
aside mechanism to present to the NEB by May
31, 2013 prior to the setting aside of funds.
Reserve Replacement, Throughput and Product Demand
Pembina's Conventional Pipeline tariff revenue is based upon a
variety of tolling arrangements, including "ship or pay" contracts,
cost of service arrangements and market-based tolls. As a result,
certain pipeline tariff revenue is heavily dependent upon
throughput levels of crude oil, NGL and condensate. Future
throughput on Pembina's crude oil and NGL pipelines and replacement
of oil and gas reserves in the service areas will be dependent upon
the success of producers operating in those areas in exploiting
their existing reserve bases and exploring for and developing
additional reserves. Without reserve additions, or expansion of the
service areas, throughput on such pipelines will decline over time
as reserves are depleted. As oil and gas reserves are depleted,
production costs may increase relative to the value of the
remaining reserves in place, causing producers to shut-in
production and seek lower cost alternatives for transportation. If
the level of tariffs collected by Pembina decreases as a result,
cash flow available for dividends to shareholders, to service
obligations under the convertible debentures and the Company's
other debt obligations could be adversely affected.
Over the long-term, Pembina's business will depend, in part, on
the level of demand for crude oil, condensate, NGL and natural gas
in the markets served by Pembina's crude oil and NGL pipelines and
gas processing and gathering infrastructure in which Pembina has an
interest. The global events of 2008 and 2009 had a substantial
downward effect on the demand for and prices of such products.
Although prices rebounded in 2010 and remained relatively strong
through 2012, Pembina cannot predict the impact of future economic
conditions on the energy and petrochemical industries or future
demand for and prices of natural gas, crude oil, condensate and
NGL. Future prices of these products are determined by supply and
demand factors, including weather and general economic conditions
as well as political and other conditions in other oil and natural
gas regions, all of which are beyond Pembina's control.
The volumes of natural gas processed through Pembina's gas
processing assets and of NGL and other products transported in the
pipelines depend on production of natural gas in the areas serviced
by the business and pipelines. Without reserve additions,
production will decline over time as reserves are depleted and
production costs may rise. Producers may shut-in production at
lower product prices or higher production costs. Producers in the
areas serviced by the business may not be successful in exploring
for and developing additional reserves, and the gas plants and the
pipelines may not be able to maintain existing volumes of
throughput. Commodity prices may not remain at a level which
encourages producers to explore for and develop additional reserves
or produce existing marginal reserves. Lower production volumes
will also increase the competition for natural gas supply at gas
processing plants which could result in higher shrinkage premiums
being paid to natural gas producers.
The rate and timing of production from proven natural gas
reserves tied into the gas plants is at the discretion of the
producers and is subject to regulatory constraints. The producers
have no obligation to produce natural gas from these lands.
Pembina's gas processing assets are connected to various
third-party trunkline systems. Operational disruptions or
apportionment on those third-party systems may prevent the full
utilization of the business.
Over the long-term, business will depend, in part, on the level
of demand for NGL and natural gas in the geographic areas in which
deliveries are made by pipelines and the ability and willingness of
shippers having access or rights to utilize the pipelines to supply
such demand. Pembina cannot predict the impact of future economic
conditions, fuel conservation measures, alternative fuel
requirements, governmental regulation or technological advances in
fuel economy and energy generation devices, all of which could
reduce the demand for natural gas and NGL.
Operating and Capital Costs
Operating and capital costs of Pembina's business may vary
considerably from current and forecast values and rates and
represent significant components of the cost of providing service.
In general, as equipment ages, costs associated with such equipment
may increase over time. Dividends may be reduced if significant
increases in operating or capital costs are incurred.
Although operating costs are to be recaptured through the
tariffs charged on natural gas volumes processed and oil and NGL
transported, respectively, to the extent such charges escalate,
producers may seek lower cost alternatives or stop production of
their natural gas.
Completion of the Resthaven Facility and Saturn
Facility
The Resthaven facility and the Saturn facility are currently
under development by Pembina and the successful completion of these
facilities is dependent on numerous factors outside of Pembina's
control. These factors include completion of the construction of
the Resthaven facility and Saturn facility on schedule, as well as
construction and labour costs that may change depending on supply,
demand and/or inflation. Under the agreements governing the
construction and operation of the Resthaven facility and the Saturn
facility, Pembina is obligated to construct the facilities and
Pembina bears the risk for its share of any cost overruns. While
Pembina is not currently aware of any significant cost overruns at
the date hereof, any such cost overruns in the future could reduce
Pembina's expected return on the Resthaven facility and the Saturn
facility and adversely affect Pembina's results of operations
which, in turn, could reduce the level of cash available for
dividends to shareholders.
Expansion of the Peace/Northern NGL System
The Company has announced plans to expand throughput capacity on
the Peace/Northern NGL System (Phase I: 52,000, Phase 2: 55,000
bpd) and Peace Crude and Condensate System (Phase I: 40,000 bpd and
Phase 2: 55,000). The successful completion of these expansions is
dependent on numerous factors outside of the Company's control.
These factors include receipt of regulatory approval and reaching
long-term commercial arrangements with customers in respect of
certain portions of the expansions, completion of the construction
of the expansions on schedule, as well as construction costs that
may change depending on supply, demand and/or inflation. Any
agreements with customers entered into with respect to the
expansions may require that the Company bears the risk for any cost
overruns and any such cost overruns could reduce the Company's
expected return on the expansions and adversely affect the
Company's results of operations which, in turn, could reduce the
level of cash available for dividends to shareholders. There is no
certainty, nor can the Company provide any assurance, that
regulatory approval will be received or that satisfactory
commercial arrangements with customers will be reached where needed
on a timely basis or at all.
Possible Failure to Realize Anticipated Benefits of
Acquisitions
As part of its ongoing strategy, Pembina has completed
acquisitions, such as the Provident Acquisition, and may complete
additional acquisitions of assets or other entities in the future.
Achieving the benefits of completed and future acquisitions depends
in part on successfully consolidating functions and integrating
operations, procedures and personnel in a timely and efficient
manner, as well as Pembina's ability to realize the anticipated
growth opportunities and synergies from combining the acquired
businesses and operations with those of Pembina. The integration of
acquired businesses and entities requires the dedication of
substantial management effort, time and resources which may divert
management's focus and resources from other strategic opportunities
and from operational matters during this process. The integration
process may result in the loss of key employees and the disruption
of ongoing business, customer and employee relationships that may
adversely affect Pembina's ability to achieve the anticipated
benefits of any acquisitions.
Competition
Pembina competes with other pipelines, midstream and marketing
and gas processing and handling services providers in its service
areas as well as other transporters of crude oil and NGL. The
introduction of competing transportation alternatives into the
Company's service areas could potentially have the impact of
limiting the Company's ability to adjust tolls as it may deem
necessary. Additionally, potential pricing differentials on the
components of NGL may result in these components being transported
by competing gas pipelines. Pembina believes it is prepared for and
determined to meet these existing and potential competitive
pressures.
Execution Risk
Pembina's ability to successfully execute the development of its
organic growth projects may be influenced by capital constraints,
third-party opposition, changes in shipper support over time,
delays in or changes to government and regulatory approvals, cost
escalations, construction delays, shortage and in-service delays.
Pembina's growth plans may strain its resources and may be subject
to high cost pressures in the North American energy sector. Early
stage project risks include right-of-way procurement, special
interest group opposition, Aboriginal consultation, and
environmental and regulatory permitting. Cost escalations may
impact project economics. Construction delays due to slow delivery
of materials, contractor non-performance, weather conditions and
shortages may impact project development. Labour shortages and
productivity issues may also affect the successful completion of
projects.
Pembina has a centralized and clearly defined governance
structure and process for all major projects with dedicated
resources organized to lead and execute each major project. Capital
constraints and cost escalation risks are mitigated through
structuring of commercial agreements, typically where shippers
retain complete or a share of capital cost excess. Pembina's
emphasis on corporate social responsibility promotes generally
positive relationships with landowners, aboriginal groups and
governments, which help to facilitate right-of-way acquisition,
permitting and scheduling. Detailed cost tracking and centralized
purchasing is used on all major projects to facilitate optimum
pricing and service terms. Strategic relationships have been
developed with suppliers and contractors. Compensation programs,
communications and the working environment are aligned to attract,
develop and retain qualified personnel.
Shipper and Processing Contracts
Throughput on Pembina's pipelines is or will be governed by
transportation contracts or tolling arrangements with various
producers of petroleum products. In addition, Pembina is party to
numerous contracts of varying durations in respect of its gas
gathering, processing and fractionating facilities. Any default by
counterparties under such contracts or any expirations of such
contracts or tolling arrangements without renewal or replacement
may have an adverse effect on Pembina's business. Furthermore, some
of the contracts associated with its gas gathering, processing and
fractionating facilities are comprised of a mixture of firm and
interruptible service contracts and the revenue that Pembina earns
on the contracts which are based on interruptible service is
dependent on the volume of natural gas and NGL produced by
producers in the relevant geographic areas and lower than
historical production volumes in these areas (for reasons such as
low commodity prices) may have an adverse effect on Pembina's
revenue.
GENERAL RISK FACTORS
Risk Factors Relating to the Structure of Pembina and its
Common Shares
Dilution of Shareholders
Pembina is authorized to issue, among other classes of shares,
an unlimited number of common shares for consideration and on terms
and conditions as established by the Board of Directors without the
approval of the shareholders in certain instances. The shareholders
will have no pre-emptive rights in connection with such further
issues.
Risk Factors Relating to the Activities of Pembina and the
Ownership of Common Shares
The following is a list of certain risk factors relating to the
activities of Pembina and the ownership its common shares:
- the level of Pembina's indebtedness from time to time could
impair Pembina's ability to obtain additional financing on a timely
basis to take advantage of business opportunities that may
arise;
- the uncertainty of future dividend payments by Pembina and the
level thereof as Pembina's dividend policy and the funds available
for the payment of dividends from time to time will be dependent
upon, among other things, operating cash flow generated by Pembina
and its subsidiaries, financial requirements for Pembina's
operations and the execution of its growth strategy and the
satisfaction of solvency tests imposed by the Alberta Business
Corporations Act for the declaration and payment of dividends;
- Pembina may make future acquisitions or may enter into
financings or other transactions involving the issuance of
securities of Pembina which may be dilutive; and
- the risk that the market value of the common shares may
materially deteriorate if Pembina is unable to meet its cash
dividend targets or make cash dividends in the future.
Market Value of Common Shares and Other Securities
Pembina cannot predict at what price the common shares,
convertible debentures or other securities issued by Pembina will
trade in the future. Common shares, convertible debentures and
other securities of Pembina will not necessarily trade at values
determined solely by reference to the underlying value of Pembina's
assets. One of the factors that may influence the market price of
such securities is the annual yield on the common shares and the
convertible debentures. An increase in market interest rates may
lead purchasers of common shares or convertible debentures to
demand a higher annual yield and this could adversely affect the
market price of the common shares or convertible debentures. In
addition, the market price for the common shares and the
convertible debentures may be affected by changes in general market
conditions, fluctuations in the market for equity or debt
securities and numerous other factors beyond the control of
Pembina.
Shareholders are encouraged to obtain independent legal, tax and
investment advice in their jurisdiction of residence with respect
to the holding of common shares.
Regulation
Legislation in Alberta and B.C.
exists to ensure that producers have fair and reasonable
opportunities to produce, process and market their reserves. In
Alberta, the Energy Resources
Conservation Board and in B.C., the British Columbia Utilities
Commission, may, on application and following a hearing (and in
Alberta with the approval of the
Lieutenant Governor in Council), declare the operator of a pipeline
a common carrier of oil or NGL and, as such, must not discriminate
between producers who seek access to the pipeline. Producers and
shippers may also apply to the regulatory authorities for a review
of tariffs, and such tariffs may then be regulated if it is proven
that the tariffs are not just and reasonable. Applications by
producers to have a pipeline operator declared a common carrier are
usually accompanied by an application to have the tariffs set by
the regulatory authorities. The extent to which regulatory
authorities in such instances can override existing transportation
or processing contracts has not been fully decided. The potential
for direct regulation of tolls, other than for the Company's
provincially regulated B.C. pipelines, while considered remote by
the Company, could result in toll levels that are less advantageous
to the Company and could impair the economic operation of such
regulated pipeline systems.
Additional Financing and Capital Resources
The timing and amount of Pembina's capital expenditures, and the
ability of Pembina to repay or refinance existing debt as it
becomes due, directly affects the amount of cash dividends that
Pembina pays to shareholders. Future acquisitions, expansions of
Pembina's pipeline systems and midstream operations, other capital
expenditures, including the capital expenditures that Pembina has
committed to in respect of the Resthaven facility, the Saturn
facility and the expansion of the Northern NGL System and the
repayment or refinancing of existing debt as it becomes due will be
financed from sources such as cash generated from operations, the
issuance of additional shares or other securities (including debt
securities) of Pembina, and borrowings. Dividends may be reduced,
or even eliminated, at times when significant capital or other
expenditures are made. There can be no assurance that sufficient
capital will be available on terms acceptable to Pembina, or at
all, to make additional investments, fund future expansions or make
other required capital expenditures. To the extent that external
sources of capital, including the issuance of additional shares or
other securities or the availability of additional credit
facilities, become limited or unavailable on favourable terms or at
all due to credit market conditions or otherwise, the ability of
Pembina to make the necessary capital investments to maintain or
expand its operations, to repay outstanding debt and to invest in
assets, as the case may be, may be impaired. To the extent Pembina
is required to use cash flow to finance capital expenditures or
acquisitions or to repay existing debt as it becomes due, the level
of dividends to shareholders of Pembina may be reduced.
Counterparty credit risk
Pembina is subject to counterparty credit risk arising out of
its operations. A majority of Pembina's accounts receivable are
with customers in the oil and gas industry and are subject to
normal industry counterparty credit risk. Counterparty credit risk
is managed through credit approval and monitoring procedures. The
credit worthiness assessment takes into account available
qualitative and quantitative information about the counterparty,
including, but not limited to, financial status and external credit
ratings. Depending on the outcome of each assessment, guarantees or
some other credit enhancement may be requested as security. Pembina
attempts to mitigate its exposure by entering into contracts with
customers that may permit netting or entitle Pembina to lien or
take product in-kind and/or allow for termination of the contract
on the occurrence of certain events of default. Each business
segment monitors outstanding accounts receivable on an ongoing
basis. Historically, Pembina has collected its accounts receivable
in full.
Debt Service
At the end of 2012, Pembina had exposure to floating interest
rates on $525 million in debt. This
debt exposure is managed by using derivative financial instruments.
A one percent change in short-term interest rates would have an
annualized impact of $1.4 million on
net cash flows. Variations in interest rates and scheduled
principal repayments, if required under the terms of the banking
agreements could result in significant changes in the amounts
required to be applied to debt service before payment of any
dividends to Pembina's shareholders. Certain covenants in the
agreements with the lenders may also limit payments by Pembina's
operating subsidiaries. Although Pembina believes that the existing
credit facilities are sufficient, there can be no assurance that
the amount will be adequate for Pembina's financial obligations or
that additional funds can be obtained.
Pembina and its subsidiaries are permitted to borrow funds to
finance the purchase of pipelines and other energy infrastructure
assets, to fund capital expenditures and other financial
obligations or expenditures in respect of those assets and for
working capital purposes. Amounts paid in respect of interest and
principal on debt incurred in respect of those assets reduce the
amount of cash flow available for dividends to shareholders.
Variations in interest rates and scheduled principal repayments for
which Pembina may not be able refinance at favourable rates or at
all, could result in significant changes in the amount required to
be applied to service debt, which could have detrimental effects on
the amount of cash available for dividends to shareholders. Certain
covenants contained in the agreements with Pembina's lenders may
also limit dividend payments. Although Pembina believes the
existing credit facilities are sufficient for immediate
requirements, there can be no assurance that the amount will be
adequate for the future financial obligations of Pembina or that
additional funds will be able to be obtained on terms favourable to
Pembina or at all.
The lenders under Pembina's unsecured credit facilities and
senior notes have also been provided with similar guarantees and
subordination agreements. If Pembina becomes unable to pay its debt
service charges or otherwise commits an event of default such as
bankruptcy, payments to all of the lenders will rank in priority to
dividends to shareholders and payments to holders of convertible
debentures.
Pembina, on a consolidated basis, is also required to meet
certain financial covenants under the credit facilities and the
senior notes and is subject to customary restrictions on its
operations and activities, including restrictions on the granting
of security, incurring indebtedness and the sale of its assets.
Credit Ratings
Rating agencies regularly evaluate Pembina, basing their ratings
of its long-term and short-term debt on a number of factors. This
includes Pembina's financial strength as well as factors not
entirely within its control, including conditions affecting the
industry in which Pembina operates generally and the wider state of
the economy. There can be no assurance that one or more of
Pembina's credit ratings will not be downgraded.
Pembina's borrowing costs and ability to raise funds are
directly impacted by its credit ratings. Credit ratings may be
important to suppliers or counterparties when they seek to engage
in certain transactions. A credit rating downgrade could
potentially impair Pembina's ability to enter into arrangements
with suppliers or counterparties, to engage in certain
transactions, and could limit Pembina's access to private and
public credit markets and increase the costs of borrowing under its
existing credit facilities. A downgrade could also limit Pembina's
access to debt markets and increase its cost of borrowing.
The occurrence of a downgrade in Pembina's credit ratings could
adversely affect Pembina's ability to execute portions of its
business strategy and could have a material adverse effect on its
liquidity, results of operations and capital position.
Changes in Legislation
There can be no assurance that income tax laws, regulatory and
environmental laws or policies and government incentive programs
relating to the pipeline or oil and natural gas industry, will not
be changed in a manner which adversely affects Pembina or its
shareholders or other securityholders.
Reliance on Management
Shareholders and other securityholders of Pembina will be
dependent on senior management and directors of Pembina in respect
of the governance, administration and management of all matters
relating to Pembina and its operations and administration. The loss
of the services of key individuals could have a detrimental effect
on Pembina.
Potential Conflicts of Interest
Shareholders are dependent upon senior management of Pembina and
the directors of Pembina for the governance, administration and
management of Pembina. Additionally, certain directors and officers
of Pembina may be directors or officers of entities in competition
to Pembina. As such, these directors or officers of Pembina may
encounter conflicts of interest in the administration of their
duties with respect to Pembina.
Litigation
Pembina and its various subsidiaries and affiliates are, in the
course of their business, subject to lawsuits and other claims.
Defence and settlement costs associated with such lawsuits and
claims can be substantial, even with respect to lawsuits and claims
that have no merit. Due to the inherent uncertainty of the
litigation process, the resolution of any particular legal
proceeding could have a material adverse effect on the financial
position or operating results of Pembina.
Variations in Interest Rates and Foreign Exchange
Rates
Variations in interest rates could result in a significant
change in the amount Pembina pays to service debt, potentially
impacting dividends to shareholders. Variations in the exchange
rate for the Canadian dollar versus the U.S. dollar could affect
future dividends.
Selected Quarterly Operating Information
|
|
|
|
|
|
|
|
|
|
|
2012 |
2011 |
2010 |
|
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Average volume
(mbpd unless stated otherwise) |
|
|
|
|
|
|
|
|
|
Conventional Throughput |
480.2 |
443.9 |
433.9 |
466.9 |
422.8 |
430.4 |
411.4 |
390.3 |
375.0 |
Oil Sands & Heavy Oil(1) |
870.0 |
870.0 |
870.0 |
870.0 |
870.0 |
775.0 |
775.0 |
775.0 |
775.0 |
Gas Services Processing
(mboe/d)(2) |
46.0 |
45.8 |
47.5 |
44.1 |
45.3 |
43.6 |
40.9 |
39.4 |
42.1 |
NGL sales volume (mboe/d) |
115.8 |
86.7 |
90.4 |
|
|
|
|
|
|
(1) Oil Sands & Heavy Oil throughput refers
to contracted capacity. |
(2) Converted to mboe/d from MMcf/d at a 6:1
ratio. |
Selected Quarterly Financial Information
|
|
|
|
|
|
|
|
|
|
|
2012 |
2011 |
2010 |
($ millions, except where
noted) |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Q3 |
Q2 |
Q1 |
Q4 |
Revenue |
1,265.7 |
815.3 |
870.9 |
475.5 |
468.1 |
300.6 |
512.4 |
394.9 |
290.7 |
Operations |
86.0 |
69.5 |
67.7 |
48.4 |
55.1 |
54.4 |
37.6 |
44.8 |
41.9 |
Cost of goods sold including product
purchases |
968.6 |
565.5 |
641.9 |
299.1 |
308.0 |
145.8 |
364.3 |
254.2 |
161.8 |
Realized gain (loss) on
commodity-related derivative financial instruments |
11.0 |
(2.8) |
(12.4) |
(0.3) |
0.9 |
3.2 |
(0.2) |
1.4 |
(0.8) |
Operating margin(1) |
222.1 |
177.5 |
148.9 |
127.7 |
105.9 |
103.6 |
110.3 |
97.3 |
86.2 |
Depreciation and amortization included
in operations |
47.8 |
51.6 |
52.5 |
21.7 |
19.6 |
17.8 |
15.8 |
14.8 |
15.6 |
Unrealized gain (loss) on
commodity-related derivative financial instruments |
(2.2) |
(23.0) |
64.8 |
(3.5) |
0.9 |
0.7 |
3.3 |
0.3 |
1.8 |
Gross profit |
172.1 |
102.9 |
161.2 |
102.5 |
87.2 |
86.5 |
97.8 |
82.8 |
72.4 |
Adjusted EBITDA(1) |
199.0 |
153.8 |
125.9 |
111.4 |
88.2 |
89.9 |
103.3 |
87.2 |
79.1 |
Cash flow from operating
activities |
139.5 |
130.9 |
24.1 |
65.3 |
73.8 |
87.7 |
49.5 |
74.5 |
54.6 |
Cash flow from
operating activities per common share ($ per share) |
0.48 |
0.45 |
0.08 |
0.39 |
0.44 |
0.52 |
0.30 |
0.45 |
0.33 |
Adjusted cash flow from operating
activities(1) |
172.3 |
133.2 |
89.5 |
98.8 |
66.0 |
82.0 |
81.8 |
76.0 |
62.6 |
Adjusted cash flow
from operating activities per common share(1) ($
per share) |
0.59 |
0.46 |
0.31 |
0.59 |
0.39 |
0.49 |
0.49 |
0.45 |
0.39 |
Earnings for the period |
81.3 |
30.7 |
80.4 |
32.6 |
45.0 |
30.1 |
48.0 |
42.5 |
55.2 |
Earnings per common share
($ per share) |
|
|
|
|
|
|
|
|
|
|
Basic |
0.28 |
0.11 |
0.28 |
0.19 |
0.27 |
0.18 |
0.29 |
0.25 |
0.34 |
|
Diluted |
0.28 |
0.11 |
0.28 |
0.19 |
0.27 |
0.18 |
0.29 |
0.25 |
0.33 |
Common shares outstanding
(millions): |
|
|
|
|
|
|
|
|
|
|
Weighted average (basic) |
291.9 |
289.2 |
285.3 |
168.3 |
167.4 |
167.6 |
167.3 |
167.0 |
165.0 |
|
Weighted average (diluted) |
292.5 |
289.7 |
286.0 |
168.9 |
168.2 |
168.2 |
168.0 |
167.6 |
171.7 |
|
End of period |
293.2 |
290.5 |
287.8 |
169.0 |
167.9 |
167.7 |
167.5 |
167.1 |
166.9 |
Dividends declared |
118.4 |
117.3 |
116.2 |
65.7 |
65.4 |
65.4 |
65.3 |
65.1 |
64.6 |
Dividends per common share ($
per share) |
0.405 |
0.405 |
0.405 |
0.390 |
0.390 |
0.390 |
0.390 |
0.390 |
0.390 |
(1) Refer to "Non-GAAP measures." |
During the above periods, Pembina's results were influenced by
the following factors and trends:
- Increased oil production from customers operating in the
Cardium and Deep Basin Cretaceous formations of west central
Alberta, which has resulted in
increased service offerings in these areas, as well as new
connections and capacity expansions;
- Increased liquids-rich natural gas production from producers in
the WCBS (Deep Basin, Montney,
Cardium and emerging Duvernay Shale plays), which has resulted in
increased gas gathering and processing at the Company's gas
services assets and additional associated NGL transported on its
pipelines;
- Revenue contribution from the Nipisi and Mitsue Pipelines,
which were completed in June and July of 2011; and
- The Acquisition of Provident, which closed on April 2, 2012 (for more details please see Note 5
of the Consolidated Financial Statements for the year ended
December 31, 2012).
Selected Annual Financial Information
|
|
|
|
($ millions, except where
noted) |
2012 |
2011 |
2010 |
Revenue |
3,427.4 |
1,676.0 |
1,231.8 |
Earnings |
225.0 |
165.7 |
175.8 |
|
Per share - basic |
0.87 |
0.99 |
1.08 |
|
Per share - diluted |
0.87 |
0.99 |
1.07 |
Total assets |
8,276.5 |
3,339.2 |
2,856.8 |
Long-term financial
liabilities(1) |
3,004.7 |
1,752.9 |
1,599.4 |
Declared dividends per share ($ per
share) |
1.61 |
1.56 |
1.56 |
(1) |
Includes loans and borrowings, convertible debentures,
long-term derivative financial instrument, provisions and other
long-term liabilities. |
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. Except as otherwise indicated, these Non-GAAP measures
are calculated and disclosed on a consistent basis from period to
period. Specific adjusting items may only be relevant in certain
periods.
Earnings before interest, taxes, depreciation and
amortization ("EBITDA")
EBITDA is commonly used by Management, investors and creditors
in the calculation of ratios for assessing leverage and financial
performance and is calculated as results from operating activities
plus share of profit from equity accounted investees (before tax)
plus depreciation and amortization (included in operations and
general and administrative expense) and unrealized gains or losses
on commodity-related derivative financial instruments.
Adjusted EBITDA is EBITDA excluding acquisition-related expenses
in connection with the Acquisition.
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except per share amounts) |
2012 |
2011 |
2012 |
2011 |
Results from operating activities |
144.3 |
65.5 |
416.5 |
290.7 |
Share of profit from equity accounted
investees
(before tax, depreciation and
amortization) |
2.0 |
3.2 |
6.2 |
12.9 |
Depreciation and amortization |
49.5 |
20.4 |
179.4 |
70.2 |
Unrealized loss (gain) on commodity-related
derivative financial instruments |
2.2 |
(0.9) |
(36.1) |
(5.2) |
EBITDA |
198.0 |
88.2 |
566.0 |
368.6 |
Add: |
|
|
|
|
Acquisition-related expenses |
1.0 |
|
24.1 |
|
Adjusted EBITDA |
199.0 |
88.2 |
590.1 |
368.6 |
EBITDA per common share - basic
(dollars) |
0.68 |
0.53 |
2.19 |
2.20 |
Adjusted EBITDA per common share - basic
(dollars) |
0.68 |
0.53 |
2.28 |
2.20 |
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 Acquisition plus share of profit
from equity accounted investees (before tax).
|
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions, except per share amounts) |
2012 |
2011 |
2012 |
2011 |
Earnings before income tax and equity accounted
investees |
108.5 |
43.3 |
301.3 |
198.8 |
Add (deduct): |
|
|
|
|
Unrealized (gains) losses on fair value of
derivative financial instruments |
6.4 |
(1.6) |
(40.2) |
2.4 |
Share of (loss) profit of investments in equity
accounted investees (before tax) |
(0.1) |
2.0 |
(1.5) |
7.7 |
Acquisition-related expenses |
1.0 |
|
24.1 |
|
Adjusted earnings |
115.8 |
43.7 |
283.7 |
208.9 |
Adjusted earnings per common share - basic
(dollars) |
0.40 |
0.26 |
1.10 |
1.25 |
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
December 31
(unaudited) |
12 Months
Ended
December 31 |
($ millions, except per share amounts) |
2012 |
2011 |
2012 |
2011 |
Cash flow from operating activities |
139.5 |
73.8 |
359.8 |
285.5 |
Add (deduct): |
|
|
|
|
Change in non-cash working capital |
31.8 |
(7.8) |
109.9 |
20.3 |
Acquisition-related expenses |
1.0 |
|
24.1 |
|
Adjusted cash flow from operating activities |
172.3 |
66.0 |
493.8 |
305.8 |
Adjusted cash flow from operating activities per
common share - basic (dollars) |
0.59 |
0.39 |
1.91 |
1.83 |
Operating margin
Operating margin is commonly used by Management for assessing
financial performance and is calculated as gross profit before
depreciation and amortization included in operations and unrealized
gain/loss on commodity-related derivative financial
instruments.
Reconciliation of operating margin to gross profit:
|
|
|
|
|
|
3 Months Ended
December 31
(unaudited) |
12 Months Ended
December 31 |
($ millions) |
2012 |
2011 |
2012 |
2011 |
Revenue |
1,265.7 |
468.1 |
3,427.4 |
1,676.0 |
Cost of sales: |
|
|
|
|
|
Operations |
86.0 |
55.1 |
271.6 |
191.9 |
|
Cost of goods sold, including product
purchases |
968.6 |
308.0 |
2,475.0 |
1,072.3 |
|
Realized gain (loss) on commodity-related
derivative financial instruments |
11.0 |
0.9 |
(4.6) |
5.3 |
Operating margin |
222.1 |
105.9 |
676.2 |
417.1 |
Depreciation and amortization included
in operations |
47.8 |
19.6 |
173.6 |
68.0 |
Unrealized gain (loss)
on commodity-related derivative financial instruments |
(2.2) |
0.9 |
36.1 |
5.2 |
Gross profit |
172.1 |
87.2 |
538.7 |
354.3 |
Beginning in the second quarter of 2012, unrealized gain/loss 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", "could",
"believe", "plan", "intend", "design", "target", "undertake",
"view", "indicate", "maintain", "explore", "entail", "schedule",
"objective", "strategy", "likely", "potential", "envision", "aim",
"outlook", "propose", "goal", "would", and similar expressions
suggesting future events or future performance.
By their nature, such forward-looking statements involve known
and unknown risks, uncertainties and other factors that may cause
actual results or events to differ materially from those
anticipated in such forward-looking statements. Pembina believes
the expectations reflected in those forward-looking statements are
reasonable but no assurance can be given that these expectations
will prove to be correct and such forward-looking statements
included in this MD&A should not be unduly relied upon. These
statements speak only as of the date of the MD&A.
In particular, this MD&A contains forward-looking
statements, including certain financial outlook, pertaining to the
following:
- the future levels of cash dividends that Pembina intends to pay
to its shareholders;
- capital expenditure-estimates, plans, schedules, rights and
activities and the planning, development, construction, operations
and costs of pipelines, gas service facilities, terminalling,
storage and hub facilities and other facilities or energy
infrastructure, including, but not limited to, the Northern NGL
System, the Peace HVP expansion between Fox Creed and Fort Saskatchewan, the LVP expansion between
Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion,
the Phase 2 NGL Expansion, the joint venture full-service terminal
in the Judy Creek area of Alberta
area, the development program in the Cynthia area west of
Drayton Valley, offshore export
opportunities for propane, the Nipisi and Mitsue pipelines
expansions, the Saturn facility and associated pipelines, the
Resthaven facility and associated pipelines, the Nexus expansion,
the Redwater expansion;
- future expansion of Pembina's pipelines and other
infrastructure;
- pipeline, processing and storage facility and system operations
and throughput levels;
- oil and gas industry exploration and development activity
levels;
- Pembina's strategy and the development of new business
initiatives;
- growth opportunities;
- expectations regarding Pembina's ability to raise capital and
to carry out acquisition, expansion and growth plans;
- treatment under government regulatory regimes including
environmental regulations and related abandonment and reclamation
obligations;
- future G&A expenses at Pembina
- increased throughput potential due to increased activity and
new connections and other initiatives on Pembina's pipelines;
- future cash flows, potential revenue and cash flow enhancements
across Pembina's businesses and the maintenance of operating
margins;
- tolls and tariffs and transportation, storage and services
commitments and contracts;
- cash dividends and the tax treatment thereof;
- operating risks (including the amount of future liabilities
related to pipeline spills and other environmental incidents) and
related insurance coverage and inspection and integrity
programs;
- the expected capacity, incremental volumes and in-services
dates of proposed expansions and new developments, including the
Northern NGL System, the Peace HVP expansion between Fox Creek and Fort
Saskatchewan, the LVP expansion between Fox Creek and Edmonton, Alberta, the Phase 2 LVP Expansion,
the Phase 2 NGL Expansion, the Nipisi and Mitsue pipelines, the
Saturn facility, the Resthaven facility and Nexus;
- the possibility of offshore export opportunities for
propane;
- the possibility of renegotiating debt terms, repayment of
existing debt, seeking new borrowing and/or issuing equity;
- expectations regarding participation in Pembina's DRIP;
- the expected impact of changes in share price on annual
share-based incentive expense;
- inventory and pricing levels in the North American liquids
market;
- Pembina's discretion to hedge natural gas and NGL volumes;
and
- competitive conditions.
Various factors or assumptions are typically applied by Pembina
in drawing conclusions or making the forecasts, projections,
predictions or estimations set out in forward-looking statements
based on information currently available to Pembina. These factors
and assumptions include, but are not limited to:
- the success of Pembina's operations;
- prevailing commodity prices and exchange rates and the ability
of Pembina to maintain current credit ratings;
- the availability of capital to fund future capital requirements
relating to existing assets and projects, including but not limited
to future capital expenditures relating to expansion, upgrades and
maintenance shutdowns;
- future operating costs;
- geotechnical and integrity costs associated with the Western
System;
- in respect of the proposed Saturn facility and the Resthaven
facility and their estimated in-service dates; that all required
regulatory and environmental approvals can be obtained on the
necessary terms in a timely manner, that counterparties will comply
with contracts in a timely manner; that there are no unforeseen
events preventing the performance of contracts or the completion of
such facilities; that such facilities will be fully supported by
long-term firm service agreements accounting for the entire
designed throughput at such facilities at the time of such
facilities' completion; that there are no unforeseen construction
costs related to the facilities; and that there are no unforeseen
material costs relating to the facilities which are not recoverable
from customers;
- in respect of the expansion of NGL throughput capacity on the
Northern NGL System and the crude throughput capacity on the Peace
crude 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 expansion of 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 and crude volumes
being transported on the conventional pipelines, 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
Acquisition;
- the failure to complete remaining integration of the businesses
of Pembina and Provident; and
- the other factors discussed under "Risk Factors" in Pembina's
Annual Information Form ("AIF") for the year ended December 31, 2012. Pembina's MD&A and AIF are
available at www.pembina.com and in Canada under Pembina's company profile on
www.sedar.com and in the U.S. on the Company's profile at
www.sec.gov.
These factors should not be construed as exhaustive. Unless
required by law, Pembina does not undertake any obligation to
publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. Any
forward-looking statements contained herein are expressly qualified
by this cautionary statement.
MANAGEMENT'S RESPONSIBILITY
The Consolidated Financial Statements of Pembina Pipeline
Corporation (the "Company") are the responsibility of Pembina's
management. The financial statements have been prepared in
accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board, using
management's best estimates and judgments, where appropriate.
Management is responsible for the reliability and integrity of
the financial statements, the notes to the financial statements and
other financial information contained in this report. In the
preparation of these financial statements, estimates are sometimes
necessary because a precise determination of certain assets and
liabilities is dependent on future events. Management believes such
estimates have been based on careful judgments and have been
properly reflected in the accompanying financial statements.
Management maintains a system of internal controls designed to
provide reasonable assurance that assets are safeguarded and that
accounting systems provide timely, accurate and reliable financial
information.
The Board of Directors of the Company (the "Board") is
responsible for ensuring management fulfils its responsibilities
for financial reporting and internal control. The Board is assisted
in exercising its responsibilities through the Audit Committee,
which consists of four non-management directors. The Audit
Committee meets periodically with management and the auditors to
satisfy itself that management's responsibilities are properly
discharged, to review the financial statements and to recommend
approval of the financial statements to the Board.
KPMG LLP, the independent auditors, have audited the Company's
financial statements in accordance with Canadian generally accepted
auditing standards and their report follows. The independent
auditors have full and unrestricted access to the Audit Committee
to discuss their audit and their related findings.
[signed] |
|
|
[signed] |
|
|
|
|
Robert B. Michaleski |
|
|
Peter D. Robertson |
Chief Executive Officer |
|
|
Vice President, Finance & Chief Financial Officer |
Pembina Pipeline Corporation |
|
|
Pembina Pipeline Corporation |
|
|
|
|
March 1, 2013 |
|
|
INDEPENDENT AUDITORS' REPORT
To the Shareholders of Pembina Pipeline Corporation
We have audited the accompanying consolidated financial
statements of Pembina Pipeline Corporation, which comprise the
consolidated statement of financial position as at December 31, 2012 and December 31, 2011, the consolidated statements of
comprehensive income, changes in equity and cash flows for the
years then ended, and notes, comprising a summary of significant
accounting policies and other explanatory information.
Management's Responsibility for the Consolidated Financial
Statements
Management is responsible for the preparation and fair
presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board, and for
such internal control as management determines is necessary to
enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or
error.
Auditors' Responsibility
Our responsibility is to express an opinion on these
consolidated financial statements based on our audits. We conducted
our audits in accordance with Canadian generally accepted auditing
standards. Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are
free from material misstatement.
An audit involves performing procedures to obtain audit evidence
about the amounts and disclosures in the consolidated financial
statements. The procedures selected depend on our judgment,
including the assessment of the risks of material misstatement of
the consolidated financial statements, whether due to fraud or
error. In making those risk assessments, we consider internal
control relevant to the entity's preparation and fair presentation
of the consolidated financial statements in order to design audit
procedures that are appropriate in the circumstances, but not for
the purpose of expressing an opinion on the effectiveness of the
entity's internal control. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness
of accounting estimates made by management, as well as evaluating
the overall presentation of the consolidated financial
statements.
We believe that the audit evidence we have obtained in our
audits is sufficient and appropriate to provide a basis for our
audit opinion.
Opinion
In our opinion, the consolidated financial statements present
fairly, in all material respects, the consolidated financial
position of Pembina Pipeline Corporation as at December 31, 2012 and December 31, 2011, and its consolidated financial
performance and its consolidated cash flows for the years then
ended in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards
Board.
[signed]
KPMG LLP
Calgary, Alberta
March 1, 2013
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
|
|
|
|
As at December 31
($ thousands) |
Note |
2012 |
2011 |
Assets
Current assets |
|
|
|
|
Cash and cash equivalents |
|
27,336 |
|
|
Trade receivables and other |
6 |
331,692 |
148,267 |
|
Derivative financial instruments |
27 |
7,528 |
4,643 |
|
Inventory |
|
108,096 |
21,235 |
|
|
474,652 |
174,145 |
Non-current assets |
|
|
|
|
Property, plant and equipment |
7 |
5,014,542 |
2,747,530 |
|
Intangible assets and goodwill |
8 |
2,622,677 |
243,904 |
|
Investments in equity accounted investees |
9 |
161,205 |
161,002 |
|
Derivative financial instruments |
27 |
343 |
1,807 |
|
Other receivables |
6 |
3,080 |
10,814 |
|
|
7,801,847 |
3,165,057 |
Total Assets |
|
8,276,499 |
3,339,202 |
Liabilities and Shareholders'
Equity
Current liabilities |
|
|
|
|
Bank indebtedness |
|
|
676 |
|
Trade payables and accrued liabilities |
11 |
344,740 |
166,646 |
|
Dividends payable |
|
39,586 |
21,828 |
|
Loans and borrowings |
12 |
11,652 |
323,927 |
|
Derivative financial instruments |
27 |
15,932 |
4,725 |
|
|
411,910 |
517,802 |
Non-current liabilities |
|
|
|
|
Loans and borrowings |
12 |
1,932,774 |
1,012,061 |
|
Convertible debentures |
13 |
609,968 |
289,365 |
|
Derivative financial instruments |
27 |
51,759 |
12,813 |
|
Employee benefits |
25 |
28,623 |
16,951 |
|
Share-based payments |
|
17,239 |
14,060 |
|
Deferred revenue |
|
3,099 |
2,185 |
|
Provisions |
14 |
361,206 |
405,433 |
|
Deferred tax liabilities |
10 |
584,489 |
106,915 |
|
|
3,589,157 |
1,859,783 |
Total Liabilities |
|
4,001,067 |
2,377,585 |
Shareholders' Equity |
|
|
|
Equity attributable to shareholders of
the Company: |
|
|
|
|
Share capital |
15 |
5,324,058 |
1,811,734 |
|
Deficit |
|
(1,027,678) |
(834,921) |
|
Accumulated other comprehensive income |
|
(26,123) |
(15,196) |
|
|
4,270,257 |
961,617 |
Non-controlling interest |
|
5,175 |
|
Total Equity |
|
4,275,432 |
961,617 |
Total Liabilities and Shareholders'
Equity |
|
8,276,499 |
3,339,202 |
See accompanying notes to the consolidated
financial statements
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
|
|
|
|
|
Year Ended December 31
($ thousands, except per share amounts) |
Note |
2012 |
2011 |
Revenue |
16 |
3,427,402 |
1,676,050 |
Cost of sales |
17 |
2,920,208 |
1,332,205 |
Gain on commodity-related derivative
financial instruments |
27 |
31,529 |
10,471 |
Gross profit |
|
538,723 |
354,316 |
|
|
|
|
|
General and administrative |
18 |
97,488 |
62,191 |
|
Acquisition-related and other expense |
|
24,748 |
1,429 |
|
|
122,236 |
63,620 |
|
|
|
|
Results from operating
activities |
|
416,487 |
290,696 |
|
|
|
|
|
Finance income |
|
(6,611) |
(1,374) |
|
Finance costs |
|
121,751 |
93,301 |
|
Net finance costs |
21 |
115,140 |
91,927 |
|
|
|
|
Earnings before income tax and
equity accounted investees |
|
301,347 |
198,769 |
|
|
|
|
|
Share of loss (profit) of investments in equity
accounted investees, net of tax |
|
1,056 |
(5,766) |
|
|
|
|
|
Income tax expense |
10 |
75,339 |
38,869 |
|
|
|
|
Earnings for the year |
|
224,952 |
165,666 |
|
|
|
|
Other comprehensive income
(loss) |
|
|
|
|
Defined benefit plan actuarial losses |
|
(14,568) |
(14,159) |
|
Income tax benefit |
10 |
3,641 |
3,540 |
|
Other comprehensive loss for the year |
25 |
(10,927) |
(10,619) |
Total comprehensive income for the
year |
|
214,025 |
155,047 |
Earnings attributable to: |
|
|
|
|
Shareholders of the Company |
|
224,844 |
165,666 |
|
Non-controlling interest |
|
108 |
|
|
|
224,952 |
165,666 |
Total comprehensive income
attributable to: |
|
|
|
|
Shareholders of the Company |
|
213,917 |
155,047 |
|
Non-controlling interest |
|
108 |
|
|
|
214,025 |
155,047 |
Earnings per share attributable to
shareholders of the Company: |
|
|
|
Basic and diluted earnings per share
(dollars) |
23 |
0.87 |
0.99 |
See accompanying notes to the consolidated
financial statements
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
|
|
|
|
|
|
|
|
|
|
Attributable to Shareholders of the Company |
|
|
($
thousands) |
Note |
Share
Capital |
Deficit |
Accumulated
Other
Comprehensive
Income |
Total |
Non-controlling
Interest |
Total
Equity |
December 31, 2010 |
|
1,794,536 |
(739,351) |
(4,577) |
1,050,608 |
|
1,050,608 |
Total comprehensive income for
period |
|
|
|
|
|
|
|
|
Earnings |
|
|
165,666 |
|
165,666 |
|
165,666 |
Other comprehensive income |
|
|
|
|
|
|
|
|
Defined benefit plan actuarial losses, net of
tax |
25 |
|
|
(10,619) |
(10,619) |
|
(10,619) |
Total comprehensive income for the
year |
|
|
165,666 |
(10,619) |
155,047 |
|
155,047 |
Transactions with shareholders of
the Company |
|
|
|
|
|
|
|
|
Share-based payment transactions |
15 |
16,978 |
|
|
16,978 |
|
16,978 |
|
Debenture conversions and other |
15 |
220 |
|
|
220 |
|
220 |
|
Dividends declared |
15 |
|
(261,236) |
|
(261,236) |
|
(261,236) |
Total transactions with shareholders
of the Company |
|
17,198 |
(261,236) |
|
(244,038) |
|
(244,038) |
December 31, 2011 |
|
1,811,734 |
(834,921) |
(15,196) |
961,617 |
|
961,617 |
|
|
|
|
|
|
|
|
Total comprehensive income for
period |
|
|
|
|
|
|
|
Earnings |
|
|
224,844 |
|
224,844 |
108 |
224,952 |
Other comprehensive income |
|
|
|
|
|
|
|
Defined benefit plan actuarial losses,
net of tax |
25 |
|
|
(10,927) |
(10,927) |
|
(10,927) |
Total comprehensive income (loss) for
the year |
|
|
224,844 |
(10,927) |
213,917 |
108 |
214,025 |
Transactions with shareholders of
the Company |
|
|
|
|
|
|
|
Share-based payment transactions |
15 |
9,221 |
|
|
9,221 |
|
9,221 |
Debenture conversions and other |
15 |
432 |
|
|
432 |
|
432 |
Dividends declared |
15 |
|
(417,601) |
|
(417,601) |
|
(417,601) |
Common shares issued on
acquisition |
5 |
3,283,976 |
|
|
3,283,976 |
|
3,283,976 |
Dividend reinvestment plan |
15 |
218,695 |
|
|
218,695 |
|
218,695 |
Total transactions
with shareholders of the Company |
|
3,512,324 |
(417,601) |
|
3,094,723 |
|
3,094,723 |
Non-controlling interest assumed on
acquisition |
5 |
|
|
|
|
5,067 |
5,067 |
December 31, 2012 |
|
5,324,058 |
(1,027,678) |
(26,123) |
4,270,257 |
5,175 |
4,275,432 |
See accompanying notes to the consolidated
financial statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
Year Ended December 31 ($
thousands) |
Note |
2012 |
2011 |
Cash provided by (used
in): |
|
|
|
Operating activities: |
|
|
|
Earnings for the year |
|
224,952 |
165,666 |
Adjustments for: |
|
|
|
|
Depreciation and amortization |
19 |
179,386 |
70,219 |
|
Unrealized gain on commodity-related derivative
financial instruments |
|
(36,100) |
(5,176) |
|
Net finance costs |
21 |
115,140 |
91,927 |
|
Share of loss (profit) of investments in equity
accounted investees, net of tax |
|
1,056 |
(5,766) |
|
Deferred income tax expense |
10 |
75,802 |
38,869 |
|
Share-based payments expense |
26 |
17,028 |
18,651 |
|
Employee future benefits expense |
25 |
7,225 |
4,825 |
|
Other |
|
1,006 |
989 |
|
Changes in non-cash working capital |
24 |
(109,881) |
(20,297) |
|
Payments from equity accounted investees |
9 |
17,428 |
16,869 |
|
Decommissioning liability expenditures |
14 |
(4,944) |
(3,123) |
|
Employer future benefit contributions |
25 |
(10,000) |
(8,000) |
|
Net interest paid |
|
(118,291) |
(80,115) |
Cash flow from operating
activities |
|
359,807 |
285,538 |
Financing activities: |
|
|
|
|
Bank borrowings |
|
6,861 |
153,137 |
|
Repayment of loans and borrowings |
|
(61,332) |
(90,596) |
|
Issuance of debt |
|
450,000 |
250,000 |
|
Financing fees |
|
(7,343) |
(1,774) |
|
Exercise of stock options |
|
7,295 |
16,059 |
|
Dividends paid (net of shares issued under the
Dividend Reinvestment Plan) |
15 |
(181,148) |
(261,102) |
Cash flow from financing
activities |
|
214,333 |
65,724 |
Investing activities: |
|
|
|
|
Net capital expenditures |
|
(546,820) |
(477,335) |
|
Contributions to equity accounted investees |
|
(8,182) |
|
|
Cash acquired on acquisition |
|
8,874 |
|
Cash flow used in investing
activities |
|
(546,128) |
(477,335) |
Change in cash |
|
28,012 |
(126,073) |
Cash (bank indebtedness), beginning of
year |
|
(676) |
125,397 |
Cash and cash equivalents (bank
indebtedness), end of year |
|
27,336 |
(676) |
See accompanying notes to the consolidated
financial statements
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. REPORTING ENTITY
Pembina Pipeline Corporation ("Pembina" or the "Company") is an
energy transportation and service provider domiciled in
Canada. The consolidated financial
statements ("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
year ended December 31, 2012. These
Financial Statements present fairly the financial position,
financial performance and cash flows of the Company.
Pembina owns or has interests in pipelines that transport
conventional crude oil and natural gas liquids ("NGL"), oil sands
and heavy oil pipelines, gas gathering and processing facilities,
and an NGL infrastructure and logistics business. Facilities are
located in Canada and in the U.S.
Pembina also offers midstream services that span across its
operations.
2. BASIS OF PREPARATION
a. Statement of compliance
The Financial Statements have been prepared in accordance with
International Financial Reporting Standards ("IFRS"), as issued by
the International Accounting Standards Board ("IASB").
The Financial Statements were authorized for issue by the Board
of Directors on March 1, 2013.
b. Basis of measurement
The Financial Statements have been prepared on the historical
cost basis except for the following material items in the statement
of financial position:
- derivative financial instruments are measured at estimated fair
value; and
- liabilities for cash-settled share-based payment arrangements
are measured at estimated fair value.
c. Functional and presentation currency
The Financial Statements are presented in Canadian dollars,
which is the Company's functional currency. All financial
information presented in Canadian dollars has been disclosed in
thousands except where noted.
d. Use of estimates and judgments
The preparation of the Financial Statements in conformity with
IFRS requires management to make judgments, estimates and
assumptions that are 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.
The following judgment and estimation uncertainties are those
management considers material to the Company's financial
statements:
Judgments
(i) Business combinations
Business combinations are accounted for using the acquisition
method of accounting. The determination of fair value often
requires Management to make judgments about future possible events.
The assumptions with respect to determining the fair value of
property, plant and equipment and intangible assets acquired
generally require the most judgment.
(ii) Componentization
The componentization of the Company's assets are based on
management's judgment of what components constitute a significant
cost in relation to the total cost of an asset and whether these
components have similar or dissimilar patterns of consumption and
useful lives for purposes of calculating depreciation and
amortization.
(iii) Depreciation and amortization
Depreciation and amortization of property, plant and equipment
and intangible assets are based on management's judgment of the
most appropriate method to reflect the pattern of an asset's future
economic benefit expected to be consumed by the Company. Among
other factors, these judgments are based on industry standards and
historical experience.
Estimates
(i) Inventory
Due to the inherent limitations in metering and the physical
properties of storage caverns and pipelines, the determination of
precise volumes of NGL held in inventory at such locations is
subject to estimation. Actual inventories of NGL within storage
caverns can only be determined by draining of the caverns.
(ii) Financial derivative instruments
The Company's financial derivative instruments are recognized on
the statement of financial position at fair value based on
management's estimate of commodity prices, share price and
associated volatility, foreign exchange rates, interest rates and
the amounts that would have been received or paid to settle these
instruments prior to maturity given future market prices and other
relevant factors.
(iii) Business Combinations
Estimates of future cash flows, forecast prices, interest rates
and discount rates are made in determining the fair value of assets
acquired and liabilities assumed for allocation of the purchase
price. Changes in any of the assumptions or estimates used in
determining the fair value of acquired assets and liabilities could
impact the amounts assigned to assets, liabilities, intangible
assets and goodwill in the purchase price analysis. Future net
earnings can be affected as a result of changes in future
depreciation and amortization, asset or goodwill impairment.
(iv) Defined benefit obligations
The calculation of the defined benefit obligation is sensitive
to many estimates, but most significantly of which include the
discount rate and long-term rate of return on assets applied.
(v) Provisions and contingencies
Provisions recognized are based on management's judgment about
assessing contingent liabilities and timing, scope and amount of
liabilities. Management uses judgment in determining the likelihood
of realization of contingent assets and liabilities to determine
the outcome of contingencies.
Based on the long-term nature of the decommissioning provision,
the biggest uncertainties in estimating the provision are the
discount rates used, the costs that will be incurred and the timing
of when these costs will occur. In addition, in determining the
provision it is assumed that the Company will utilize technology
and materials that are currently available.
(vi) Share-based payments
Compensation costs pursuant to the share-based compensation
plans are subject to estimated fair values, forfeiture rates and
the future attainment of performance criteria.
(vii) Deferred taxes
The calculation of the deferred tax asset or liability is based
on assumptions about the timing of many taxable events and the
enacted or substantively enacted rated anticipated to apply to
income in the years in which temporary differences are expected to
be realized or reversed.
(viii) Depreciation and amortization
Estimated useful lives of property, plant and equipment is based
on management's assumptions and estimates of the physical useful
lives of the assets, the economic life, which may be associated
with the reserve life and commodity type of the production area, in
addition to the estimated residual value.
3. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies are set out below have been applied
consistently to all periods presented in these Financial
Statements.
a. Basis of consolidation
i) Business combinations
The Company measures goodwill as the fair value of the
consideration transferred including the recognized amount of any
non-controlling interest in the acquiree, less the net recognized
amount (generally fair value) of the identifiable assets acquired
and liabilities assumed, all measured as of the acquisition date.
When the excess is negative, a bargain purchase gain is recognized
immediately in profit or loss.
The Company elects on a transaction-by-transaction basis whether
to measure non-controlling interest at its fair value, or at its
proportionate share of the recognized amount of the identifiable
net assets, at the acquisition date.
Non-controlling interests represent equity interests in
subsidiaries owned by outside parties. The share of net assets of
subsidiaries attributable to non-controlling interests is presented
as a separate component of equity. Their share of net income and
other comprehensive income is also recognized in this separate
component of equity. Changes in the Company's ownership interest in
subsidiaries that do not result in a loss of control are accounted
for as equity transactions. Adjustments to non-controlling
interests are based on a proportionate amount of the net assets of
the subsidiary. No adjustments are made to goodwill and no gain or
loss is recognized in profit or loss.
Transaction costs, other than those associated with the issue of
debt or equity securities, that the Company incurs in connection
with a business combination are expensed as incurred.
ii) Subsidiaries
Subsidiaries are entities controlled by the Company. The
financial statements of subsidiaries are included in the Financial
Statements from the date that control commences until the date that
control ceases. The accounting policies of subsidiaries are aligned
with the policies adopted by the Company.
iii) Investments in associates and jointly controlled
entities (equity accounted investees)
Associates are those entities in which the Company has
significant influence, but not control or joint control, over the
financial and operating policies. Significant influence is presumed
to exist when the Company holds between 20 and 50 percent of the
voting power of another entity. Joint ventures are those entities
over whose activities the Company has joint control, established by
contractual agreement and requiring unanimous consent for strategic
financial and operating decisions.
The Financial Statements include the Company's share of the
profit or loss and other comprehensive income, after adjustments to
align the accounting policies with those of the Company, from the
date that significant influence or joint control commences until
the date that significant influence or joint control ceases. The
Company's investments in its associates and joint ventures are
accounted for using the equity method and are recognized initially
at cost, including transaction costs.
When the Company's share of losses exceeds its interest in an
equity accounted investee, the carrying amount of that interest,
including any long-term investments, is reduced to nil, and the
recognition of further losses is discontinued except to the extent
that the Company has an obligation or has made payments on behalf
of the investee.
iv) Jointly controlled operations
A jointly controlled operation is a joint venture carried on by
each venture using its own assets in pursuit of the joint
operations. The Financial Statements include the assets that the
Company controls and the liabilities that it incurs in the course
of pursuing the joint operation, and the expenses that the Company
incurs and its share of the income that it earns from the joint
operation.
v) Transactions eliminated on consolidation
Intra-group balances and transactions, and any unrealized
revenue and expenses arising from intra-group transactions, are
eliminated in preparing the consolidated financial statements.
Unrealized gains arising from transactions with equity-accounted
investees are eliminated against the investment to the extent of
the Company's interest in the investee. Unrealized losses are
eliminated in the same way as unrealized gains, but only to the
extent that there is no evidence of impairment.
vi) Foreign currency
Transactions in foreign currencies are translated to the
Company's functional currency, Canadian dollars, at exchange rates
at the dates of the transactions. Monetary assets and liabilities
denominated in foreign currencies at the reporting date are
retranslated to the Company's functional currency at the exchange
rate at that date. The foreign currency gain or loss on monetary
items is the difference between amortized cost in the functional
currency at the beginning of the period, adjusted for effective
interest and payments during the period, and the amortized cost in
foreign currency translated at the exchange rate at the end of the
reporting period.
Non-monetary assets and liabilities denominated in foreign
currencies that are measured at fair value are retranslated to the
functional currency at the exchange rate at the date that the fair
value was determined. Non-monetary items that are measured in terms
of historical cost in a foreign currency are translated using the
exchange rate at the date of the transaction.
Foreign currency differences arising on retranslation are
recognized in profit or loss.
b. Inventories
Inventories are measured at the lower of cost and net realizable
value and consist primarily of crude oil and NGL. 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.
c. Financial instruments
Financial assets and liabilities are offset and the net amount
presented in the statement of financial position when, and only
when, the Company has a legal right to offset the amounts and
intends either to settle on a net basis or to realize the asset and
settle the liability simultaneously.
i) Non-derivative financial assets
The Company initially recognizes loans and receivables and
deposits on the date that they are originated. All other financial
assets (including assets designated at fair value through profit or
loss) are recognized initially on the trade date at which the
Company becomes a party to the contractual provisions of the
instrument.
The Company derecognizes a financial asset when the contractual
rights to the cash flows from the asset expire, or it transfers the
rights to receive the contractual cash flows on the financial asset
in a transaction in which substantially all the risks and rewards
of ownership of the financial asset are transferred. Any interest
in transferred financial assets that is created or retained by the
Company is recognized as a separate asset or liability.
The Company classifies non-derivative financial assets into the
following categories:
Cash and cash equivalents
Cash and cash equivalents comprise cash balances, call deposits
and short-term investments with original maturities of ninety days
or less that are subject to an insignificant risk of changes in
their fair value, and are used by the Company in the management of
its short-term commitments.
Trade and other receivables
Trade and other receivables are financial assets with fixed or
determinable payments that are not quoted in an active market. Such
assets are recognized initially at fair value plus any directly
attributable transaction costs. Subsequent to initial recognition,
loans and receivables are measured at amortized cost using the
effective interest method less any impairment losses.
ii) Non-derivative financial liabilities
The Company initially recognizes debt securities issued and
subordinated liabilities on the date that they are originated. All
other financial liabilities (including liabilities designated at
fair value through profit or loss) are recognized initially on the
trade date at which the Company becomes a party to the contractual
provisions of the instrument.
The Company derecognizes a financial liability when its
contractual obligations are discharged, cancelled or expire.
The Company's non-derivative financial liabilities are comprised
of the following: bank indebtedness, trade payables and accrued
liabilities, dividends payable, loans and borrowings including
finance lease obligations and the liability component of
convertible debentures.
Such financial liabilities are recognized initially at fair
value plus any directly attributable transaction costs. Subsequent
to initial recognition these financial liabilities are measured at
amortized cost using the effective interest method.
Bank overdrafts that are repayable on demand and form an
integral part of the Company's cash management are included as a
component of cash and cash equivalents for the purpose of the
statement of cash flows.
iii) Share capital
Common shares
Common shares are classified as equity. Incremental costs
directly attributable to the issue of common shares and share
options are recognized as a deduction from equity, net of any tax
effects.
iv) Compound financial instruments
The Company's convertible debentures are compound financial
instruments consisting of a financial liability and an embedded
conversion feature. In accordance with IAS 39, the embedded
derivatives are required to be separated from the host contracts
and accounted for as stand-alone instruments.
Debentures containing a cash conversion option allow Pembina to
pay cash to the converting holder of the debentures, at the option
of the Company. As such, the conversion feature is presented as a
financial derivative liability within long-term derivative
financial instruments. Debentures without a cash conversion option
are settled in shares on conversion, and therefore the conversion
feature is presented within equity, in accordance with its
contractual substance.
On initial recognition and at each reporting date, the embedded
conversion feature is measured using a method whereby the fair
value is measured using an option pricing model. Subsequent to
initial recognition, any unrealized gains or losses arising from
fair value changes are recognized through profit or loss in the
statement of comprehensive income at each reporting date. If the
conversion feature is included in equity, it is not remeasured
subsequent to initial recognition. On initial recognition, the debt
component, net of issue costs, is recorded as a financial liability
and accounted for at amortized cost. Subsequent to initial
recognition, the debt component is accreted to the face value of
the debentures using the effective interest rate method. Upon
conversion, the corresponding portions of the debt and equity are
removed from those captions and transferred to share capital.
v) Derivative financial instruments
The Company holds derivative financial instruments to manage its
interest rate, commodity, power costs and foreign exchange risk
exposures as well as cash conversion features on convertible
debentures and a redemption liability. Embedded derivatives are
separated from the host contract and accounted for separately if
the economic characteristics and risks of the host contract and the
embedded derivative meet the definition of a derivative, and the
combined instrument is not measured at fair value through profit or
loss. Derivatives are recognized initially at fair value with
attributable transaction costs recognized in profit or loss as
incurred. Subsequent to initial recognition, derivatives are
measured at fair value and changes in non-commodity-related
derivatives are recognized immediately in profit or loss in net
finance costs and changes in commodity-related derivatives are
recognized immediately in profit or loss in operating
activities.
d. Property, plant and equipment
i) Recognition and measurement
Items of property, plant and equipment are measured at cost less
accumulated depreciation and accumulated impairment losses.
Cost includes expenditures that are directly attributable to the
acquisition of the asset. The cost of self-constructed assets
includes the cost of materials and direct labour, any other costs
directly attributable to bringing the assets to a working condition
for their intended use, estimated decommissioning provisions and
borrowing costs on qualifying assets.
Cost also may include any gain or loss realized on foreign
currency transactions directly attributable to the purchase or
construction of property, plant and equipment. Purchased software
that is integral to the functionality of the related equipment is
capitalized as part of that equipment.
When parts of an item of property, plant and equipment have
different useful lives, they are accounted for as separate
components of property, plant and equipment.
The gain or loss on disposal of an item of property, plant and
equipment is determined by comparing the proceeds from disposal
with the carrying amount of property, plant and equipment, and are
recognized within other expense (income) in profit or loss.
ii) Subsequent costs
The cost of replacing a part of an item of property, plant and
equipment is recognized in the carrying amount of the item if it is
probable that the future economic benefits embodied within the part
will flow to the Company, and its cost can be measured reliably.
The carrying amount of the replaced part is derecognized. The cost
of maintenance and repair expenses of the property, plant and
equipment are recognized in profit or loss as incurred.
iii) Depreciation
Depreciation is based on the cost of an asset less its residual
value. Significant components of individual assets, other than
land, are assessed and if a component has a useful life that is
different from the remainder of the asset, that component is
depreciated separately.
Depreciation is recognized in profit or loss on a straight line
or declining balance basis, which most closely reflects the
expected pattern of consumption of the future economic benefits
embodied in the asset. Pipeline assets and facilities are generally
depreciated using the straight line method over 3 to 75 years (an
average of 47 years) or declining balance method at rates ranging
from 3 percent to 37 percent per annum (an average rate of 15
percent per annum). Facilities and equipment are depreciated using
straight line method over 3 to 75 years (at an average rate of 35
years) or declining balance method at rates ranging from 3 to 37
percent (at an average rate of 12 percent per annum). Other assets
are depreciated using the straight line method over 2 to 45 years
(an average of 17 years) or declining balance method at rates
ranging from 3 percent to 37 percent (at an average rate of 2
percent per annum). These rates are established to depreciate
remaining net book value over the economic lives or contractual
duration of the related assets.
Leased assets are depreciated over the shorter of the lease term
and their useful lives unless it is reasonably certain that the
Company will obtain ownership by the end of the lease term.
Depreciation methods, useful lives and residual values are
reviewed annually and adjusted if appropriate.
e. Intangible assets
i) Goodwill
Goodwill that arises upon acquisitions is included in intangible
assets. See note 3(a)(i) for the policy on measurement of goodwill
at initial recognition.
Subsequent measurement
Goodwill is measured at cost less accumulated impairment
losses.
In respect of equity accounted investees, the carrying amount of
goodwill is included in the carrying amount of the investment, and
an impairment loss on such an investment is allocated to the
investment and not to any asset, including goodwill, that forms the
carrying amount of the equity accounted investee.
ii) Other intangible assets
Other intangible assets acquired individually by the Company and
have finite useful lives are recognized and measured at cost less
accumulated amortization and accumulated impairment losses.
iii) Subsequent expenditures
Subsequent expenditures are capitalized only when it increases
the future economic benefits embodied in the specific asset to
which it relates. All other expenditures are recognized in profit
or loss as incurred.
iv) Amortization
Amortization is based on the cost of an asset less its residual
value.
Amortization is recognized in profit or loss on a straight-line
basis over the estimated useful lives of intangible assets, other
than goodwill, 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 25 years (at an average of 17
years).
Amortization methods, useful lives and residual values are
reviewed annually and adjusted if appropriate.
f. Leased assets
Leases which the Company assumes substantially all the risks and
rewards of ownership are classified as finance leases. The leased
asset is initially recognized at an amount equal to the lower of
its fair value and the present value of the minimum lease payments.
Subsequent to initial recognition, the asset is accounted for in
accordance with the accounting policy applicable to that asset.
Other leases are operating leases and are not recognized in the
Company's statement of financial position.
g. Lease payments
Payments made under operating leases are recognized in profit or
loss on a straight-line basis over the term of the lease. Lease
incentives received are recognized as an integral part of the total
lease expense, over the term of the lease.
Minimum lease payments made under finance leases are apportioned
between the finance cost and the reduction of the outstanding
liability. The finance cost is allocated to each period during the
lease term so as to produce a constant periodic rate of interest on
the remaining balance of the liability. Contingent lease payments
are accounted for by revising the minimum lease payments over the
remaining life.
i) Determining whether an arrangement contains a
lease
At inception of an arrangement, the Company determines whether
such an arrangement is or contains a lease. A specific asset is the
subject of a lease if fulfilment of the arrangement is dependent on
the use of that specified asset. An arrangement conveys the right
to use the asset if the arrangement conveys to a lessee the right
to control the use of the underlying asset.
At inception or upon reassessment of the arrangement, the
Company separates payments and other consideration required by such
an arrangement into those for the lease and those for other
elements on the basis of their relative fair values. If the Company
concludes for a finance lease that it is impracticable to separate
the payments reliably, an asset and liability are recognized at an
amount equal to the fair value of the underlying asset.
Subsequently, the liability is reduced as payments are made and an
imputed finance cost on the liability is recognized using the
Company's incremental borrowing rate.
h. Impairment
i) Non-derivative financial assets
A financial asset not carried at fair value through profit or
loss is assessed at each reporting date to determine whether there
is objective evidence that it is impaired. A financial asset is
impaired if there is objective evidence of impairment as a result
of one or more events that occurred after the initial recognition
of the asset, and that a loss event had a negative effect on the
estimated future cash flows of that asset and the impact can be
estimated reliably.
Objective evidence that financial assets are impaired can
include default or delinquency by a debtor, restructuring of an
amount due to the Company on terms that the Company would not
consider otherwise, indications that a debtor or issuer will enter
bankruptcy, adverse changes in the payment status of borrowers or
issuers in the Company, economic conditions that correlate with
defaults or the disappearance of an active market for a security or
a significant or prolonged decline in the fair value below
cost.
Trade and other receivables ("Receivables")
The Company considers evidence of impairment for Receivables at
both a specific asset and collective level. All individually
significant Receivables are assessed for specific impairment. All
individually significant Receivables found not to be specifically
impaired are then collectively assessed for any impairment that has
been incurred but not yet identified. Receivables that are not
individually significant are collectively assessed for impairment
by grouping together Receivables with similar risk
characteristics.
In assessing collective impairment, the Company uses historical
trends of the probability of default, timing of recoveries and the
amount of loss incurred, adjusted for management's judgment as to
whether current economic and credit conditions are such that the
actual losses are likely to be greater or less than suggested by
historical trends.
An impairment loss in respect of a financial asset measured at
amortized cost is calculated as the difference between its carrying
amount and the present value of the estimated future cash flows
discounted at the asset's original effective interest rate. Losses
are recognized in profit or loss and reflected in an allowance
account against Receivables. Interest on the impaired asset
continues to be recognized through the unwinding of the discount.
When a subsequent event causes the amount of impairment loss to
decrease, the decrease in impairment loss is reversed through
profit or loss.
ii) Non-financial assets
The carrying amounts of the Company's non-financial assets,
other than line fill and assets arising from employee benefits and
deferred tax assets, are reviewed at each reporting date to
determine whether there is any indication of impairment. If any
such indication exists, then the asset's recoverable amount is
estimated.
For goodwill and intangible assets that have indefinite useful
lives or that are not yet available for use, the recoverable amount
is estimated each year at the same time. An impairment loss is
recognized if the carrying amount of an asset or its related Cash
Generating Unit ("CGU") exceeds its estimated recoverable
amount.
The recoverable amount of an asset or CGU is the greater of its
value in use and its fair value less costs to sell. In assessing
value in use, the estimated future cash flows are discounted to
their present value using a pre-tax discount rate that reflects
current market assessments of the time value of money and the risks
specific to the asset or CGU. For the purpose of impairment
testing, assets that cannot be tested individually are grouped
together into the smallest group of assets that generates cash
inflows from continuing use that are largely independent of the
cash inflows of other assets or CGUs. Subject to an operating
segment ceiling test, for the purpose of goodwill impairment
testing, CGUs to which goodwill has been allocated are aggregated
so that the level at which impairment testing is performed reflects
the lowest level at which goodwill is monitored for internal
purposes. Goodwill acquired in a business combination is allocated
to CGUs or groups of CGUs that are expected to benefit from the
synergies of the combination.
The Company's corporate assets do not generate separate cash
inflows and are utilized by more than one CGU. Corporate assets are
allocated to CGUs on a reasonable and consistent basis and tested
for impairment as part of the testing of the CGU to which the
corporate asset is allocated. If there is an indication that a
corporate asset may be impaired, then the recoverable amount is
determined for the CGU to which the corporate asset belongs.
Impairment losses are recognized in profit or loss. An
impairment loss is recognized if the carrying amount of an asset or
its CGU exceeds its estimated recoverable amount. Impairment losses
recognized in respect of CGUs are allocated first to reduce the
carrying amount of any goodwill allocated to the CGU (group of
CGUs), and then to reduce the carrying amounts of the other assets
in the CGU (group of CGUs) on a pro rata basis.
An impairment loss in respect of goodwill is not reversed. In
respect of other assets, impairment losses recognized in prior
periods are assessed at each reporting date for any indications
that the loss has decreased or no longer exists. An impairment loss
is reversed if there has been a change in the estimates used to
determine the recoverable amount. An impairment loss is reversed
only to the extent that the asset's carrying amount does not exceed
the carrying amount that would have been determined, net of
depreciation or amortization, if no impairment loss had been
recognized.
Goodwill that forms part of the carrying amount of an investment
in an associate is not recognized separately, and therefore is not
tested for impairment separately. Instead, the entire amount of the
investment in an associate is tested for impairment as a single
asset when there is objective evidence that the investment in an
associate may be impaired.
i. Employee benefits
i) Defined contribution plans
A defined contribution plan is a post-employment benefit plan
under which an entity pays fixed contributions into a separate
entity and will have no legal or constructive obligation to pay
further amounts. Obligations for contributions to defined
contribution pension plans are recognized as an employee benefit
expense in profit or loss in the periods during which services are
rendered by employees. Prepaid contributions are recognized as an
asset to the extent that a cash refund or a reduction in future
payments is available. Contributions to a defined contribution plan
that are due more than 12 months after the end of the period in
which the employees render the service are discounted to their
present value.
ii) Defined benefit pension plans
A defined benefit pension plan is a post-employment benefit plan
other than a defined contribution plan. The Company's net
obligation in respect of Defined Benefit Pension Plans ("Plans") is
calculated separately for each plan by estimating the amount of
future benefit that employees have earned in return for their
service in the current and prior periods, discounted to determine
its present value. Unrecognized past service costs and the fair
value of any plan assets are deducted. The discount rate used to
determine the present value is comprised of the following:
estimated returns for each major asset class consistent with market
conditions on the valuation date and the target asset mix specified
in the Plans investment policy, additional net returns assumed to
be achievable due to active equity management, implicit provision
for expenses determined as the average rate of investment and
administrative expenses paid by the Plans over the last five years,
and a margin for adverse deviations, based on the proportion of the
Plans' assets invested in equities in excess of the return expected
on equities, over government bond yields.
The calculation is performed, at a minimum, every three years by
a qualified actuary using the actuarial cost method. When the
calculation results in a benefit to the Company, the recognized
asset is limited to the total of any unrecognized past service
costs and the present value of economic benefits available in the
form of any future refunds from the plan or reductions in future
contributions to the plan. In order to calculate the present value
of economic benefits, consideration is given to any minimum funding
requirements that apply to any plan in the Company. An economic
benefit is available to the Company if it is realizable during the
life of the plan or on settlement of the plan liabilities.
When the benefits of a plan are improved, the portion of the
increased benefit relating to past service by employees is
recognized in profit or loss on a straight-line basis over the
average period until the benefits become vested. To the extent that
the benefits vest immediately, the expense is recognized
immediately in profit or loss.
The Company recognizes all actuarial gains and losses arising
from defined benefit plans in other comprehensive income and
expenses related to defined benefit plans in personnel expenses in
profit or loss.
The Company recognizes gains or losses on the curtailment or
settlement of a defined benefit plan when the curtailment or
settlement occurs. The gain or loss on curtailment comprises any
resulting change in the fair value of plan assets, change in the
present value of defined benefit obligation and any related
actuarial gains or losses and past service cost that had not
previously been recognized.
iii) Other long-term employee benefits
The Company's net obligation in respect of long-term employee
benefits other than pension plans is the amount of future benefit
that employees have earned in return for their service in the
current and prior periods is discounted to determine its present
value, and the fair value of any related assets is deducted. The
discount rate is comprised of the following: estimated returns for
each major asset class consistent with market conditions on the
valuation date and the target asset mix specified in the Plans
investment policy, additional net returns assumed to be achievable
due to active equity management, implicit provision for expenses
determined as the average rate of investment and administrative
expenses paid from the Plans over the last five years, and a margin
for adverse deviations, based on the proportion of the Plans assets
invested in equities in excess return expected on equities, over
government yield bonds.
The calculation is performed using an actuary.
iv) Short-term employee benefits
Short-term employee benefit obligations are measured on an
undiscounted basis and are expensed as the related service is
provided.
A liability is recognized for the amount expected to be paid
under short-term cash bonus if the Company has a present legal or
constructive obligation to pay this amount as a result of past
service provided by the employee, and the obligation can be
estimated reliably.
v) Share-based payment transactions
For equity settled share-based payment plans, the fair value of
the share-based payment at grant date is recognized as an expense,
with a corresponding increase in equity, over the period that the
employees unconditionally become entitled to the awards. The amount
recognized as an expense is adjusted to reflect the number of
awards for which the related service and non-market vesting
conditions are expected to be met, such that the amount ultimately
recognized as an expense is based on the number of awards that meet
the related service conditions at the vesting date.
For cash settled share-based payment plans, the fair value of
the amount payable to employees is recognized as an expense with a
corresponding increase in liabilities, over the period that the
employees unconditionally become entitled to payment. The liability
is remeasured at each reporting date and at settlement date. Any
changes in the fair value of the liability are recognized as an
expense in profit or loss.
j. Provisions
A provision is recognized if, as a result of a past event, the
Company has a present legal or constructive obligation that can be
estimated reliably, and it is probable that an outflow of economic
benefits will be required to settle the obligation. Provisions are
determined by discounting the expected future cash flows at a
pre-tax rate that reflects current market assessments of the time
value of money and the risks specific to the liability. Provisions
are remeasured at each reporting date based on the best estimate of
the settlement amount. The unwinding of the discount rate
(accretion) is recognized as a finance cost.
Decommissioning obligation
The Company's activities give rise to dismantling,
decommissioning and site disturbance remediation activities. A
provision is made for the estimated cost of site restoration and
capitalized in the relevant asset category.
Decommissioning obligations are measured at the present value,
based on a risk free rate, of management's best estimate of
expenditure required to settle the obligation at the balance sheet
date. Subsequent to the initial measurement, the obligation is
adjusted at the end of each period to reflect the passage of time,
changes in the risk free rate and changes in the estimated future
cash flows underlying the obligation. The increase in the provision
due to the passage of time is recognized as finance costs whereas
increases/decreases due to changes in the estimated future cash
flows or risk free rate are added to or deducted from the cost of
the related asset.
k. Revenue
Revenue in the course of ordinary activities is measured at the
fair value of the consideration received or receivable. Revenue is
recognized when persuasive evidence exists that the significant
risks and rewards of ownership have been transferred to the
customer or the service has been provided, recovery of the
consideration is probable, the associated costs can be estimated
reliably, there is no continuing management involvement with the
goods, and the amount of revenue can be measured reliably.
The timing of the transfer of significant risks and rewards
varies depending on the individual terms of the sales or service
agreement. For product sales, usually transfer of significant risks
and rewards occurs when the product is delivered to a customer. For
pipeline transportation revenues and storage revenue, transfer of
significant risks and rewards usually occurs when the service is
provided as per the contract with the customer. For rate or
contractually regulated pipeline operations, revenue is recognized
in a manner that is consistent with the underlying rate design as
mandated by agreement or regulatory authority.
Certain commodity buy/sell arrangements where the risks and
rewards of ownership have not transferred are recognized on a net
basis in profit or loss.
l. Finance income and finance costs
Finance income comprises interest income on funds deposited and
invested, gains on non-commodity-related derivatives measured at
fair value through profit or loss and foreign exchange gains.
Interest income is recognized as it accrues in profit or loss,
using the effective interest method.
Finance costs comprise interest expense on loans and borrowings,
unwinding of discount rate on provisions, losses on disposal of
available for sale financial assets, losses on
non-commodity-related derivatives, impairment losses recognized on
financial assets (other than trade and other receivables) and
foreign exchange losses.
Borrowing costs that are not directly attributable to the
acquisition, or construction of a qualifying asset are recognized
in profit or loss using the effective interest method.
m. Income tax
Income tax expense comprises current and deferred tax. Current
and deferred tax are recognized in profit or loss except to the
extent that it relates to a business combination, or items are
recognized directly in equity or in other comprehensive income.
Current tax is the expected tax payable or receivable on the
taxable income or loss for the period, using tax rates enacted or
substantively enacted at the reporting date, and any adjustment to
tax payable in respect of previous years.
Deferred tax is recognized in respect of temporary differences
between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for taxation
purposes. Deferred tax is not recognized for:
- temporary differences on the initial recognition of assets or
liabilities in a transaction that is not a business combination and
that affects neither accounting nor taxable profit or loss;
- temporary differences relating to investments in subsidiaries
and jointly controlled entities to the extent that it is probable
that they will not reverse in the foreseeable future; and
- taxable temporary differences arising on the initial
recognition of goodwill.
The measurement of deferred tax reflects the tax consequences
that would follow the manner in which the Company expects, at the
end of the reporting period, to recover or settle the carrying
amount of its assets and liabilities.
Deferred tax is measured at the tax rates that are expected to
be applied to temporary differences when they reverse, based on the
laws that have been enacted or substantively enacted by the
reporting date.
Deferred tax assets and liabilities are offset if there is a
legally enforceable right to offset current tax liabilities and
assets, and they relate to income taxes levied by the same tax
authority on the same taxable entity, or on different tax entities,
but they intend to settle current tax liabilities and assets on a
net basis or their tax assets and liabilities will be realized
simultaneously.
A deferred tax asset is recognized for unused tax losses, tax
credits and deductible temporary differences, to the extent that it
is probable that future taxable profits will be available against
which they can be utilized. Deferred tax assets are reviewed at
each reporting date and are reduced to the extent that it is no
longer probable that the related tax benefit will be realized.
In determining the amount of current and deferred tax, the
Company takes into account the impact of uncertain tax positions
and whether additional taxes and interest may be due. This
assessment relies on estimates and assumptions and may involve a
series of judgments about future events. New information may become
available that causes the Company to change its judgment regarding
the adequacy of existing tax liabilities, such changes to tax
liabilities will impact tax expense in the period that such a
determination is made.
n. Earnings per share
The Company presents basic and diluted earnings per share
("EPS") data for its common shares. Basic EPS is calculated by
dividing the profit or loss attributable to common shareholders of
the Company by the weighted average number of common shares
outstanding during the period. Diluted EPS is determined by
adjusting the profit or loss attributable to common shareholders
and the weighted average number of common shares outstanding, for
the effects of all potentially dilutive common shares, which
comprise convertible debentures and share options granted to
employees ("Convertible Instruments"). Only outstanding and
Convertible Instruments that will have a dilutive effect are
included in fully diluted calculations.
The dilutive effect of Convertible Instruments is determined
whereby outstanding Convertible Instruments at the end of the
period are assumed to have been converted at the beginning of the
period or at the time issued if issued during the year. Amounts
charged to income or loss relating to the outstanding Convertible
Instruments are added back to net income for the diluted
calculations. The shares issued upon conversion are included in the
denominator of per share basic calculations for the date of
issue.
o. Segment reporting
An operating segment is a component of the Company that engages
in business activities from which it may earn revenues and incur
expenses, including revenues and expenses that relate to
transactions with any of the Company's other components. All
operating segments' operating results are reviewed regularly by the
Company's Chief Executive Officer ("CEO"), Chief Financial Officer
("CFO") and Chief Operating Officer ("COO") to make decisions about
resources to be allocated to the segment and assess its
performance, and for which discrete financial information is
available.
Segment results that are reported to the CEO, CFO and COO
include items directly attributable to a segment as well as those
that can be allocated on a reasonable basis. Unallocated items
comprise mainly corporate assets, head office expenses, finance
income and costs and income tax assets and liabilities.
Segment capital expenditure is the total cost incurred during
the period to acquire property, plant and equipment, and intangible
assets other than goodwill.
p. Cash flow statements
The cash flow statement is prepared using the indirect method.
Changes in balance sheet items that have not resulted in cash flows
such as share-based payment expense, unrealized gains and losses,
depreciation and amortization, employee future benefit expenses,
deferred income tax expense, share of profit from equity accounted
investees, among others, have been eliminated for the purpose of
preparing this statement. Dividends paid to ordinary shareholders,
among other expenditures, are included in financing activities.
Interest paid is included in operating activities.
q. New standards and interpretations not yet
adopted
Certain new standards, interpretations, amendments and
improvements to existing standards were issued by the IASB or
International Financial Reporting Interpretations Committee
("IFRIC") for accounting periods beginning after January 1, 2013. The Company has reviewed these
and determined the following:
Amendments to IFRS 7 Financial Instruments: Disclosures
are effective for annual periods beginning on or after January 1, 2013. The adoption of these amendments
is not expected to have a material impact on the Company's
Financial Statements.
IFRS 9 (2010) Financial Instruments is effective for
annual periods beginning on or after January
1, 2015, with early adoption permitted. The Company intends
to adopt IFRS 9 (2010) in its financial statements for the annual
period beginning January 1, 2015. The
extent of the impact of adoption of IFRS 9 (2010) has not yet been
determined.
IFRS 10 Consolidated Financial Statements, IFRS 11
Joint Arrangements, IFRS 12 Disclosure of Interest in
Other Entities and IFRS 13 Fair Value Measurement are
effective for annual periods beginning on or after January 1, 2013. The adoption of these standards
is not expected to have a material impact on the Company's
financial statements.
Amendments to IAS 19 Employee Future Benefits are effective for
annual periods beginning on or after January
1, 2013. The adoption of these amendments is not expected to
have a material impact on the Company's Financial Statements.
IAS 32 Financial Instruments: Presentation is effective
for annual periods beginning on or after January 1, 2014. The Company is currently
evaluating the impact that the standard will have on its results of
operations and financial position.
4. DETERMINATION OF FAIR VALUES
A number of the Company's accounting policies and disclosures
require the determination of fair value, for both financial and
non-financial assets and liabilities. Fair values have been
determined for measurement and/or disclosure purposes based on the
following methods. When applicable, further information about the
assumptions made in determining fair values is disclosed in the
notes specific to that asset or liability.
i) Property, plant and equipment
The fair value of property, plant and equipment recognized as a
result of a business combination is based on market values when
available and depreciated replacement cost when appropriate.
Depreciated replacement cost reflects adjustments for physical
deterioration as well as functional and economic obsolescence.
ii) Intangible assets
The fair value of intangible assets acquired in a business
combination is determined using the multi-period excess earnings
method, whereby the subject asset is valued after deducting a fair
return on all other assets that are part of creating the related
cash flows.
The fair value of other intangible assets is based on the
discounted cash flows expected to be derived from the use and
eventual sale of the assets.
iii) Derivatives
Fair value of derivatives, with the exception of the redemption
liability which is related to the acquisition of the Company's
subsidiary, are estimated by reference to independent monthly
forward settlement prices, interest rate yield curves, currency
rates, quoted market prices per share and volatility rates at the
period ends.
The redemption liability related to one of the Company's
subsidiaries represents a put option, held by the non-controlling
interest, to sell the remaining one-third of the business to the
Company after the third anniversary of the acquisition date
(October 3, 2014). The put price to
be paid by the Company for the residual interest upon exercise is
based on a multiple of the subsidiary's earnings during the three
year period prior to exercise, adjusted for associated capital
expenditures and debt based on management estimates (see Note 27
"Financial Instruments and Financial Risk Management").
Fair values reflect the credit risk of the instrument and
include adjustments to take account of the credit risk of the
Company entity and counterparty when appropriate.
iv) Non-derivative financial assets and
liabilities
Fair value, which is determined for disclosure purposes, is
calculated based on the present value of future principal and
interest cash flows, discounted at the market rate of interest at
the reporting date. In respect of the convertible debentures, the
fair value is determined by the market price of the convertible
debenture on the reporting date. For finance leases the market rate
of interest is determined by reference to similar lease
agreements.
v) Share-based payment transactions
The fair value of the employee share options is measured using
the Black-Scholes formula. Measurement inputs include share price
on measurement date, exercise price of the instrument, expected
volatility (based on weighted average historic volatility adjusted
for changes expected due to publicly available information),
weighted average expected life of the instruments (based on
historical experience and general option holder behaviour),
expected dividends, expected forfeitures and the risk-free interest
rate (based on government bonds). Service and non-market
performance conditions attached to the transactions are not taken
into account in determining fair value.
The fair value of the long-term share unit award incentive plan
and associated distribution units are measured based on the
reporting date market price of the Company's shares. Expected
dividends are not taken into account in determining fair value as
they are issued as additional distribution share units.
vi) Inventories
The net realizable value of inventories is determined based on
the estimated selling price in the ordinary course of business less
estimated cost to sell.
5. 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 "Acquisition"). 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 $345
million. The debentures remain outstanding and continue with
terms and maturity as originally set out in their respective
indentures. Pursuant to the Acquisition, Provident amalgamated with
a wholly-owned subsidiary of Pembina and has continued under the
name "Pembina NGL Corporation". The results of the acquired
business are included as part of the Midstream business.
The purchase price equation, subject to finalization of deferred
tax liabilities, is based on assessed fair values and is estimated
as follows:
|
|
|
|
|
|
($ millions) |
|
|
|
|
|
Cash |
|
|
|
|
9 |
Trade receivables and other |
|
|
|
|
195 |
Inventory |
|
|
|
|
87 |
Property, plant and equipment |
|
|
|
|
1,988 |
Intangible assets and goodwill (including $1,753
goodwill) |
|
|
|
|
2,414 |
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 |
|
|
|
|
(406) |
Non-controlling interest |
|
|
|
|
(5) |
|
|
|
|
|
3,284 |
The determination of fair values and the purchase price equation
are based upon an independent valuation. 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. The recognized goodwill is generally not
expected to be deductible for tax purposes.
Upon closing of the Acquisition, Pembina repaid Provident's
revolving term credit facility of $205
million.
The Company has recognized $24.1
million in acquisition-related expenses. These expenses are
included in acquisition-related and other expenses in the Financial
Statements.
The Pembina Shares were listed and began trading on the NYSE
under the symbol "PBA" on April 2,
2012.
Revenue generated by the Provident business for the period from
the Acquisition date of April 2, 2012
to December 31, 2012, before
intersegment eliminations, was $1,151.4
million. Net earnings, before intersegment eliminations, for
the same period were $54.2
million.
Unaudited proforma consolidated revenue (prepared as if the
Provident Acquisition had occurred on January 1, 2012) for the year ended December 31, 2012 are $3,967.5 million and net earnings for the same
period are $277 million.
6. TRADE AND OTHER RECEIVABLES
|
|
|
|
|
|
|
|
|
December 31 ($ thousands) |
|
|
|
2012 |
|
|
|
2011 |
Trade accounts receivable from customers |
|
|
|
310,364 |
|
|
|
116,809 |
Trade accounts receivable and other receivables
from related parties |
|
|
|
10,814 |
|
|
|
28,864 |
Prepayments |
|
|
|
10,514 |
|
|
|
2,594 |
Total current trade and other receivables |
|
|
|
331,692 |
|
|
|
148,267 |
Non-current holdbacks receivable |
|
|
|
3,080 |
|
|
|
|
Receivable due from related parties |
|
|
|
|
|
|
|
10,814 |
|
|
|
|
334,772 |
|
|
|
159,081 |
On March 29, 2012 the Musreau Deep
Cut experienced a gear box failure, resulting in an interruption to
business until Pembina brought the Deep Cut compressor back into
service on September 2, 2012.
Business interruption and capital insurance claims are currently
being pursued. Pembina has recognized a receivable based on
information on the claim status as of the reporting date.
7. 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, 2010 |
|
57,248 |
|
|
1,997,267 |
|
|
483,765 |
|
|
149,117 |
|
|
260,819 |
|
|
2,948,216 |
Additions |
|
10,006 |
|
|
216,293 |
|
|
30,208 |
|
|
48,891 |
|
|
222,196 |
|
|
527,594 |
Change in decommissioning
provision |
|
|
|
|
117,491 |
|
|
|
|
|
|
|
|
|
|
|
117,491 |
Capitalized interest |
|
|
|
|
207 |
|
|
|
|
|
|
|
|
10,015 |
|
|
10,222 |
Transfers |
|
104 |
|
|
169,354 |
|
|
15,075 |
|
|
1,139 |
|
|
(185,672) |
|
|
|
Disposals and other |
|
(139) |
|
|
(585) |
|
|
(428) |
|
|
1,579 |
|
|
|
|
|
427 |
Balance at December 31, 2011 |
|
67,219 |
|
|
2,500,027 |
|
|
528,620 |
|
|
200,726(1) |
|
|
307,358 |
|
|
3,603,950(1) |
Acquisition (Note 5) |
|
18,093 |
|
|
276,225 |
|
|
1,319,286 |
|
|
287,319 |
|
|
87,273 |
|
|
1,988,196 |
Additions |
|
5,900 |
|
|
20,315 |
|
|
38,533 |
|
|
31,021 |
|
|
488,545 |
|
|
584,314 |
Change in decommissioning
provision |
|
|
|
|
(139,468) |
|
|
(31,441) |
|
|
|
|
|
|
|
|
(170,909) |
Capitalized interest |
|
|
|
|
570 |
|
|
98 |
|
|
|
|
|
13,821 |
|
|
14,489 |
Transfers |
|
1,793 |
|
|
(61,401) |
|
|
217,928 |
|
|
(13,149) |
|
|
(145,171) |
|
|
|
Disposals and other |
|
(5,001) |
|
|
(2,534) |
|
|
(828) |
|
|
626 |
|
|
|
|
|
(7,737) |
Balance at December 31, 2012 |
|
88,004 |
|
|
2,593,734 |
|
|
2,072,196 |
|
|
506,543 |
|
|
751,826 |
|
|
6,012,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010 |
|
4,043 |
|
|
659,277 |
|
|
76,498 |
|
|
49,301 |
|
|
|
|
|
789,119 |
Depreciation |
|
45 |
|
|
48,334 |
|
|
16,768 |
|
|
4,374 |
|
|
|
|
|
69,521 |
Disposals |
|
|
|
|
(516) |
|
|
(268) |
|
|
(1,436) |
|
|
|
|
|
(2,220) |
Balance at December 31, 2011 |
|
4,088 |
|
|
707,095 |
|
|
92,998 |
|
|
52,239 |
|
|
|
|
|
856,420 |
Depreciation |
|
279 |
|
|
70,795 |
|
|
54,476 |
|
|
19,629 |
|
|
|
|
|
145,179 |
Transfers |
|
|
|
|
917 |
|
|
24,628 |
|
|
(25,545) |
|
|
|
|
|
|
Disposals and other |
|
|
|
|
(2,099) |
|
|
(225) |
|
|
(1,514) |
|
|
|
|
|
(3,838) |
Balance at December 31, 2012 |
|
4,367 |
|
|
776,708 |
|
|
171,877 |
|
|
44,809 |
|
|
|
|
|
997,761 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amounts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011 |
|
63,131 |
|
|
1,792,932 |
|
|
435,622 |
|
|
148,487 |
|
|
307,358 |
|
|
2,747,530 |
December 31, 2012 |
|
83,637 |
|
|
1,817,026 |
|
|
1,900,319 |
|
|
461,734 |
|
|
751,826 |
|
|
5,014,542 |
(1) $1.5 million
was reclassified from inventory to Linefill and Other at
December 31, 2011.
Property, plant and equipment under construction
Costs of assets under construction at December 31, 2012 totalled $751.8 million ($2011: $307.4
million). Such amounts include capitalized borrowing
costs.
For the year ended December 31,
2012, capitalized borrowing costs related to the
construction of the new pipelines or facilities amounted to
$14.5 million (2011: $10.2 million), with capitalization rates ranging
from 4.29 percent to 4.77 percent (2011: 4.91 percent to 5.36
percent).
Commitments
At December 31, 2012, the Company
has contractual commitments for the acquisition and or construction
of property, plant and equipment of $362.8
million (December 31, 2011:
$364.3 million).
8. INTANGIBLE ASSETS AND GOODWILL
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Intangible Assets |
|
|
|
|
|
|
Goodwill |
|
Purchase and
Sale Contracts |
|
Customer
Relationships |
|
Purchase
Options |
|
Total Other
Intangible
Assets |
|
Total
Goodwill
& Intangible
Assets |
Cost |
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2010 and 2011 |
|
222,670 |
|
23,038 |
|
|
|
|
|
23,038 |
|
245,708 |
Acquisition (Note 5) |
|
1,752,942 |
|
157,051 |
|
226,497 |
|
277,350 |
|
660,898 |
|
2,413,840 |
Additions and other |
|
|
|
5,000 |
|
|
|
|
|
5,000 |
|
5,000 |
Balance at December 31, 2012 |
|
1,975,612 |
|
185,089 |
|
226,497 |
|
277,350 |
|
688,936 |
|
2,664,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated amortization at
December 31, 2010 |
|
|
|
1,106 |
|
|
|
|
|
1,106 |
|
1,106 |
Amortization |
|
|
|
698 |
|
|
|
|
|
698 |
|
698 |
Accumulated amortization at
December 31, 2011 |
|
|
|
1,804 |
|
|
|
|
|
1,804 |
|
1,804 |
Amortization |
|
|
|
24,778 |
|
15,289 |
|
|
|
40,067 |
|
40,067 |
Accumulated amortization at
December 31, 2012 |
|
|
|
26,582 |
|
15,289 |
|
|
|
41,871 |
|
41,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying amounts |
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2011 |
|
222,670 |
|
21,234 |
|
|
|
|
|
21,234 |
|
243,904 |
December 31, 2012 |
|
1,975,612 |
|
158,507 |
|
211,208 |
|
277,350 |
|
647,065 |
|
2,622,677 |
Other intangible assets consist of customer purchase and sale
contracts with several producers acquired through business
combinations. In addition, Pembina has a purchase option of
$277.3 million to acquire property,
plant and equipment. The purchase option is not being amortized
because it is not exercisable until 2018.
The aggregate carrying amount of intangible assets and goodwill
allocated to each operating segment is as follows:
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Conventional Pipelines |
|
|
|
|
315,470 |
|
|
|
|
194,370 |
Oil Sands and Heavy Oil |
|
|
|
|
33,300 |
|
|
|
|
28,300 |
Gas Services |
|
|
|
|
196,136 |
|
|
|
|
21,234 |
Midstream |
|
|
|
|
2,077,771 |
|
|
|
|
|
|
|
|
|
|
2,622,677 |
|
|
|
|
243,904 |
Impairment testing
For the purpose of impairment testing, goodwill is allocated to
the Company's operating divisions which represent the lowest level
within the Company at which the goodwill is monitored for internal
management purposes, which is not higher than the Company's
operating segments. Impairment testing for goodwill was performed
on December 31, 2012. The recoverable
amounts were based on their value in use and were determined to be
higher than their carrying amounts.
Value in use was determined by discounting the future cash flows
generated from the continuing use of each cash generating unit. The
calculation of the value in use was based on the following key
assumptions:
Cash flows were projected based on past experience, actual
operating results and the first 5 years of the business plan
approved by management. Cash flows for periods up to 68 years
(2011: 75 years) were extrapolated using a constant growth rate of
2 percent (2011: 1.9 percent), which does not exceed the long-term
average growth rate for the industry. Pre-tax discount rates
between 7.49 percent and 8.63 percent (2011: 7.51 percent and 8.84
percent) were applied in determining the recoverable amount of the
cash generating units. The discount rates were estimated based on
past experience, the Company's risk free rate and average cost of
debt in addition to estimates of the specific cash generating
unit's equity risk premium, size premium, small capitalization
premium, projection risk, betas, tax rate and industry targeted
debt to equity ratios.
9. INVESTMENTS IN EQUITY ACCOUNTED INVESTEES
The Company has a 50 percent interest in two jointly controlled,
equity accounted investees that are reported using the equity
method of accounting. The carrying value of the investment at
December 31, 2012 is $161.2 million (2011: $161
million).
|
|
|
|
|
|
|
|
|
Pembina's Proportionate Share of
Balance As At |
|
Pembina's Proportionate Share of
Transaction Value For The Year Ended |
|
Payments
from
Equity Accounted
Investees |
|
|
Current
Assets |
|
Non-Current
Assets |
|
Current
Liabilities |
|
Non-Current
Liabilities |
|
Revenues |
|
Expenses |
|
Profit and
Loss |
|
|
($ thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fort Saskatchewan Ethylene Storage Corporation
(FSESC) |
|
316 |
|
11 |
|
1 |
|
|
|
78 |
|
2 |
|
76 |
|
|
Fort Saskatchewan Ethylene Storage Limited
Partnership (FSESLP) |
|
3,271 |
|
26,216 |
|
20,125 |
|
12,087 |
|
45,925 |
|
7,082 |
|
38,843 |
|
16,869 |
December 31, 2011 |
|
3,587 |
|
26,227 |
|
20,126 |
|
12,087 |
|
46,003 |
|
7,084 |
|
38,919 |
|
16,869 |
FSESC |
|
331 |
|
4 |
|
2 |
|
|
|
12 |
|
4 |
|
8 |
|
|
FSESLP |
|
2,917 |
|
41,343 |
|
16,950 |
|
21,457 |
|
14,646 |
|
8,788 |
|
5,858 |
|
17,428 |
December 31, 2012 |
|
3,248 |
|
41,347 |
|
16,952 |
|
21,457 |
|
14,658 |
|
8,792 |
|
5,866 |
|
17,428 |
On acquisition, Pembina recognized a fair value adjustment which
is amortized over the useful life of the assets. Pembina's share of
profit of investments in equity accounted investees includes
amortization of the fair value adjustment of $7.7 million (2011: $5.2
million), derecognition of fair value adjustment of $nil
(2011: $25.2 million), income tax
benefit (expense) of $0.5 million
(2011: $(1.9) million) and other
$0.3 million (2011: $(0.7) million) In 2012, Pembina made
contributions for the construction of caverns of $8.2 million (2011: $nil).
Commitments
At December 31, 2012, the
Company's share of investment in equity accounted investees
contractual commitments for the construction of property, plant and
equipment is $31.6 million
(December 31, 2011: $42.7 million).
10. INCOME TAXES
The components of the deferred assets and deferred tax
liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Asset: |
|
|
|
|
|
|
|
|
|
|
Intangible assets |
|
|
|
|
|
|
|
|
|
2,512 |
Derivative financial instruments |
|
|
|
|
22,787 |
|
|
|
|
2,772 |
Employee benefits |
|
|
|
|
7,156 |
|
|
|
|
4,238 |
Share-based payments |
|
|
|
|
7,971 |
|
|
|
|
3,515 |
Provisions |
|
|
|
|
114,617 |
|
|
|
|
101,358 |
Benefit of loss carryforwards |
|
|
|
|
76,702 |
|
|
|
|
62,426 |
Other deductible temporary differences |
|
|
|
|
2,783 |
|
|
|
|
4,240 |
Total deferred tax asset |
|
|
|
|
232,016 |
|
|
|
|
181,061 |
|
|
|
|
|
|
|
|
|
|
|
Liability: |
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
589,909 |
|
|
|
|
203,178 |
Intangible assets |
|
|
|
|
127,467 |
|
|
|
|
|
Investments in equity accounted investees |
|
|
|
|
21,841 |
|
|
|
|
25,802 |
Taxable limited partnership income deferral |
|
|
|
|
75,295 |
|
|
|
|
50,175 |
Other taxable temporary differences |
|
|
|
|
1,993 |
|
|
|
|
8,821 |
Total deferred tax liability |
|
|
|
|
816,505 |
|
|
|
|
287,976 |
Total deferred tax liability |
|
|
|
|
584,489 |
|
|
|
|
106,915 |
The Company's consolidated effective tax rate for the year ended
December 31, 2012 was 25 percent
(2011: 19.6 percent).
Reconciliation of effective tax rate
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Earnings before income tax |
|
|
|
|
301,347 |
|
|
|
|
198,769 |
|
|
|
|
|
|
|
|
|
|
|
Statutory tax rate |
|
|
|
|
25.0% |
|
|
|
|
26.5% |
|
|
|
|
|
|
|
|
|
|
|
Income tax at statutory rate |
|
|
|
|
75,337 |
|
|
|
|
52,674 |
|
|
|
|
|
|
|
|
|
|
|
Tax rate changes on deferred income tax
balances |
|
|
|
|
1,948 |
|
|
|
|
(5,051) |
Changes in estimate from prior year |
|
|
|
|
(2,160) |
|
|
|
|
(8,880) |
Other |
|
|
|
|
214 |
|
|
|
|
126 |
Income tax expense |
|
|
|
|
75,339 |
|
|
|
|
38,869 |
In 2007, the Canadian federal government enacted a change in the
federal income tax rate from 16.5 percent in 2011 to 15 percent in
2012.
Income tax expense
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($
thousands) |
|
|
|
|
2012 |
|
|
|
2011 |
Current tax benefit |
|
|
|
|
|
|
|
|
|
|
Adjustment for prior period |
|
|
|
|
(463) |
|
|
|
|
|
Total current tax benefit |
|
|
|
|
(463) |
|
|
|
|
Deferred tax expense |
|
|
|
|
|
|
|
|
|
|
Origination and reversal of temporary
differences |
|
|
|
|
58,005 |
|
|
|
23,826 |
|
Tax rate changes on deferred tax balances |
|
|
|
|
1,948 |
|
|
|
(5,075) |
|
Decrease in tax loss carry forward |
|
|
|
|
15,849 |
|
|
|
20,118 |
|
Total deferred tax expense |
|
|
|
|
75,802 |
|
|
|
38,869 |
Total income tax expense |
|
|
|
|
75,339 |
|
|
|
38,869 |
|
|
|
|
|
|
|
|
|
|
The movement of the deferred tax
liability is as follows: |
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
2012 |
|
|
|
2011 |
Opening balance, January 1 |
|
|
|
|
106,915 |
|
|
|
69,686 |
Deferred income tax expense |
|
|
|
|
75,802 |
|
|
|
38,869 |
Tax benefit on share of (loss) profit
of equity accounted investees |
|
|
|
|
(458) |
|
|
|
1,900 |
Income tax benefit in other
comprehensive income |
|
|
|
|
(3,641) |
|
|
|
(3,540) |
Acquisition (Note 5) |
|
|
|
|
405,847 |
|
|
|
|
Other |
|
|
|
|
24 |
|
|
|
|
Deferred income taxes, December
31 |
|
|
|
|
584,489 |
|
|
|
106,915 |
11. TRADE PAYABLES AND ACCRUED LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Trade payables |
|
|
|
|
301,936 |
|
|
|
|
141,452 |
Non-trade payables & accrued
liabilities(1) |
|
|
|
|
42,804 |
|
|
|
|
25,194 |
|
|
|
|
|
344,740 |
|
|
|
|
166,646 |
(1) Includes current portion of decommissioning
provision of $532 (2011 -
$10,720).
U.S. dollar trade payables at December
31, 2012 are $0.3 million
(December 31, 2011: Nil).
12. LOANS AND BORROWINGS
This note provides information about the contractual terms of
the Company's interest-bearing loans and borrowings, which are
measured at amortized cost.
Carrying value terms and debt repayment schedule
Terms and conditions of outstanding loans were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
|
|
|
|
|
|
Carrying amount(3) |
|
|
Available
facilities at
December 31,
2012 |
|
|
Nominal
interest rate |
|
|
Year
of
maturity |
|
|
December
31,
2012 |
|
|
December
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 |
|
|
520,676 |
|
|
309,981 |
Senior secured notes |
|
|
|
|
7.38 |
|
|
|
|
|
|
|
|
57,499 |
Senior unsecured notes - Series
A |
|
175,000 |
|
|
5.99 |
|
|
2014 |
|
|
174,677 |
|
|
174,462 |
Senior unsecured notes - Series
C |
|
200,000 |
|
|
5.58 |
|
|
2021 |
|
|
196,983 |
|
|
196,638 |
Senior unsecured notes - Series
D |
|
267,000 |
|
|
5.91 |
|
|
2019 |
|
|
265,604 |
|
|
265,403 |
Senior unsecured term
facility |
|
75,000 |
|
|
6.16 |
|
|
2014 |
|
|
74,800 |
|
|
74,658 |
Senior unsecured medium-term notes
1 |
|
250,000 |
|
|
4.89 |
|
|
2021 |
|
|
248,714 |
|
|
248,558 |
Senior unsecured medium-term notes
2 |
|
450,000 |
|
|
3.77 |
|
|
2022 |
|
|
447,825 |
|
|
|
Subsidiary debt |
|
9,347 |
|
|
5.04 |
|
|
2014 |
|
|
9,347 |
|
|
|
Finance lease liabilities |
|
|
|
|
|
|
|
|
|
|
5,800 |
|
|
5,650 |
Total interest bearing
liabilities |
|
2,956,347 |
|
|
|
|
|
|
|
|
1,944,426 |
|
|
1,335,988 |
Less current portion |
|
|
|
|
|
|
|
|
|
|
(11,652) |
|
|
(323,927) |
Total non-current |
|
|
|
|
|
|
|
|
|
|
1,932,774 |
|
|
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. |
All facilities are governed by specific debt covenants which
Pembina has been in compliance with during the years ended
December 31, 2012 and 2011.
For more information about the Company's exposure to interest
rate, foreign currency and liquidity risk, see financial
instruments and financial risk management Note 27.
13. CONVERTIBLE DEBENTURES
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except as
noted) |
|
|
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, 2010 |
|
|
288,635 |
|
|
|
|
|
|
|
|
288,635 |
Conversions |
|
|
(220) |
|
|
|
|
|
|
|
|
(220) |
Deferred financing fees (net of
amortization) |
|
|
950 |
|
|
|
|
|
|
|
|
950 |
Balance, December 31, 2011 |
|
|
289,365 |
|
|
|
|
|
|
|
|
289,365 |
Assumed on
acquisition(1) (Note 5) |
|
|
|
|
|
158,471 |
|
|
158,343 |
|
|
316,814 |
Conversions and redemptions |
|
|
(54) |
|
|
(351) |
|
|
(55) |
|
|
(460) |
Accretion of liability |
|
|
|
|
|
841 |
|
|
688 |
|
|
1,529 |
Deferred financing fee (net
amortization) |
|
|
1,168 |
|
|
826 |
|
|
726 |
|
|
2,720 |
Balance, December 31, 2012 |
|
|
290,479 |
|
|
159,787 |
|
|
159,702 |
|
|
609,968 |
(1) Excludes conversion feature of convertible
debentures.
The Series C debentures may be converted at the option of the
holder at a conversion price of $28.55 per share at any time prior to maturity
and may be redeemed by the Company. The Company may, at its option
after November 30, 2016, (or after
November 30, 2014, provided that the
volume weighted average trading price of the common shares on the
TSX during the 20 consecutive trading days ending on the fifth
trading day preceding the date on when the notice of redemption is
given is not less than 125 percent of the conversion price of the
debentures) elect to redeem the debentures by issuing shares. The
Company may also elect to pay interest on the debentures by issuing
shares.
The Series E debentures may be converted at the option of the
holder at a conversion price of $24.94 per share at any time prior to maturity
and may be redeemed by the Company. 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 Series F debentures may be converted at the option of the
holder at a conversion price of $29.53 per share at any time prior to maturity
and may be redeemed by the Company. 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
conversion feature is recognized as an embedded derivative and
accounted for as a derivative financial instrument, measured at
fair value using an option pricing model.
14. PROVISIONS
The Company has estimated the net present value of its total
decommissioning obligations based on a total future liability of
$361.7 million (2011: $416.2 million). The estimate has applied a
medium-term inflation rate and current discount rate and includes a
revision in the decommissioning assumptions and associated costs
and timing of payments. The obligations are expected to be paid
over the next 75 years with majority being paid between 30 and 40
years. The Company applied a 2 percent inflation rate per annum
(2011: 2.4 percent) and a risk free rate of 2.36 percent (2011:
2.49 percent) to calculate the present value of the decommissioning
provision. During the year ended December
31, 2012, the Company estimated a decrease of $54.5 million (2011: increase of $134.5 million) in the total decommissioning
obligation, including an increase of $124.6
million assumed on the Acquisition, offset by a $144.8 million decrease due to revised
assumptions which the Company believes are more in line with
industry, a $46.7 million decrease
(2011: increase of $106.8 million)
based on a change in the discount and inflation rates used to
remeasure the obligation and $7
million (2011: $7.1 million)
for unwinding of the discount rate, net of any settlements and a
$5.4 million increase (2011:
$20.6 million increase) representing
the present value of additional obligations. The remeasured
decommissioning provision decreased property, plant and equipment
and decommissioning provision liability. $5.9 million of the re-measurement reduction in
the decommissioning provision was in excess of the carrying amount
of the related asset and is recognized as a credit to depreciation
expense (2011: nil).
The property, plant and equipment of the Company consist
primarily of underground pipelines, above ground equipment
facilities and storage assets. No amount has been recorded relating
to the removal of the underground pipelines or the storage assets
as the potential obligations relating to these assets cannot be
reasonably estimated due to the indeterminate timing or scope of
the asset retirement. As the timing and scope of retirement become
determinable for these assets, the fair value of the liability and
the cost of retirement will be recorded.
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Balance at January 1 |
|
|
|
|
416,153 |
|
|
|
|
281,694 |
Unwinding of discount rate |
|
|
|
|
11,956 |
|
|
|
|
10,141 |
Assumed on acquisition (Note 5) |
|
|
|
|
124,579 |
|
|
|
|
|
Decommissioning liabilities settled during the
period |
|
|
|
|
(4,944) |
|
|
|
|
(3,123) |
Change in rates |
|
|
|
|
(46,654) |
|
|
|
|
106,793 |
Change in estimates and other |
|
|
|
|
(139,352) |
|
|
|
|
20,648 |
Total |
|
|
|
|
361,738 |
|
|
|
|
416,153 |
Less current portion (included in accrued
liabilities) |
|
|
|
|
532 |
|
|
|
|
10,720 |
Balance at December 31 |
|
|
|
|
361,206 |
|
|
|
|
405,433 |
15. SHARE CAPITAL
Share capital
Pembina is authorized to issue an unlimited number of common
shares and an unlimited number of a class of preferred shares
designated as Preferred Shares, Series A. The holders of the common
shares are entitled to receive notice of, attend at and vote at any
meeting of the shareholders of the Company, receive dividends
declared and share in the remaining property of the Company upon
distribution of the assets of the Company among its shareholders
for the purpose of winding-up its affairs.
Pembina has adopted a shareholder rights plan ("Plan") as a
mechanism designed to assist the board in ensuring the fair and
equal treatment of all shareholders in the face of an actual or
contemplated unsolicited bid to take control of the company.
Take-over bids may be structured in such a way as to be coercive or
discriminatory in effect, or may be initiated at a time when it
will be difficult for the board to prepare an adequate response.
Such offers may result in shareholders receiving unequal or unfair
treatment, or not realizing the full or maximum value of their
investment in Pembina. The Plan discourages the making of any such
offers by creating the potential of significant dilution to any
offeror who does so.
|
|
|
|
|
|
|
|
|
|
|
($ thousands, except share
amounts) |
|
|
|
|
Number
of
Common Shares |
|
|
|
|
Share Capital |
Balance December 31, 2010 |
|
|
|
|
166,876,651 |
|
|
|
|
1,794,536 |
Share-based payment
transactions |
|
|
|
|
1,023,916 |
|
|
|
|
16,978 |
Debenture conversions and
other |
|
|
|
|
7,704 |
|
|
|
|
220 |
Balance December 31, 2011 |
|
|
|
|
167,908,271 |
|
|
|
|
1,811,734 |
Issued on acquisition (Note
5) |
|
|
|
|
116,535,750 |
|
|
|
|
3,283,976 |
Share-based payment
transactions |
|
|
|
|
427,934 |
|
|
|
|
9,221 |
Dividend reinvestment plan |
|
|
|
|
8,338,254 |
|
|
|
|
218,695 |
Debenture conversions and
other |
|
|
|
|
16,264 |
|
|
|
|
432 |
Balance December 31, 2012 |
|
|
|
|
293,226,473 |
|
|
|
|
5,324,058 |
Dividends
The following dividends were declared by the Company:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
$1.61 per qualifying common share (2011: $1.56
) |
|
|
|
|
417,601 |
|
|
|
|
261,236 |
On January 8, 2013 and
February 12, 2013, Pembina announced
that the Board of Directors declared a dividend for each of January
and February of $0.135 per qualifying
common share ($1.62 annualized) in
the total amount of $79.5
million.
16. REVENUES
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
2012 |
|
|
|
2011 |
Rendering of Services: |
|
|
|
|
|
|
|
|
Conventional pipeline transportation |
|
|
|
338,772 |
|
|
|
296,190 |
Oil Sands and Heavy Oil pipeline
transportation |
|
|
|
172,429 |
|
|
|
134,874 |
Midstream and marketing terminalling, storage and
hub services (net) |
|
|
|
2,847,403 |
|
|
|
1,173,480 |
Gas services gathering and processing
services |
|
|
|
88,285 |
|
|
|
71,506 |
Intersegment eliminations |
|
|
|
(19,487) |
|
|
|
|
|
|
|
|
3,427,402 |
|
|
|
1,676,050 |
17. COST OF SALES
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Operating expense |
|
|
|
|
271,566 |
|
|
|
|
191,923 |
Cost of goods sold, including product
purchases |
|
|
|
|
2,475,038 |
|
|
|
|
1,072,270 |
Depreciation and amortization - operating |
|
|
|
|
173,604 |
|
|
|
|
68,012 |
|
|
|
|
|
2,920,208 |
|
|
|
|
1,332,205 |
18. GENERAL AND ADMINISTRATIVE EXPENSE
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Other general & administrative expense |
|
|
|
|
91,706 |
|
|
|
|
59,984 |
Depreciation and amortization - general and
administrative |
|
|
|
|
5,782 |
|
|
|
|
2,207 |
|
|
|
|
|
97,488 |
|
|
|
|
62,191 |
19. DEPRECIATION AND AMORTIZATION
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Cost of sales |
|
|
|
|
173,604 |
|
|
|
|
68,012 |
General and administrative |
|
|
|
|
5,782 |
|
|
|
|
2,207 |
|
|
|
|
|
179,386 |
|
|
|
|
70,219 |
20. PERSONNEL EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Salaries and wages |
|
|
|
|
82,350 |
|
|
|
|
57,564 |
Canada Pension Plan and EI remittances |
|
|
|
|
2,436 |
|
|
|
|
1,717 |
Share-based payment transactions |
|
|
|
|
17,028 |
|
|
|
|
18,651 |
Short-term incentive plan (bonus) |
|
|
|
|
11,430 |
|
|
|
|
8,393 |
Defined contribution plan expense |
|
|
|
|
1,685 |
|
|
|
|
878 |
Defined benefit pension plan expense |
|
|
|
|
7,225 |
|
|
|
|
4,828 |
Health and dental benefit expense |
|
|
|
|
3,459 |
|
|
|
|
2,232 |
Employee Savings plan expense |
|
|
|
|
3,946 |
|
|
|
|
2,172 |
Other benefits |
|
|
|
|
1,573 |
|
|
|
|
1,064 |
|
|
|
|
|
131,132 |
|
|
|
|
97,499 |
21. NET FINANCE COSTS
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($
thousands) |
|
|
|
2012 |
|
|
|
2011 |
Interest income from: |
|
|
|
|
|
|
|
|
Related parties |
|
|
|
(262) |
|
|
|
(876) |
Bank deposits |
|
|
|
(1,200) |
|
|
|
(414) |
Interest expense on financial
liabilities measured at amortized cost: |
|
|
|
|
|
|
|
|
|
Loans and borrowings |
|
|
|
72,956 |
|
|
|
56,722 |
|
Convertible debentures |
|
|
|
36,348 |
|
|
|
18,415 |
|
Finance leases |
|
|
|
426 |
|
|
|
404 |
|
Unwinding of discount |
|
|
|
12,021 |
|
|
|
10,141 |
(Gain) loss in fair value of
non-commodity-related derivative financial instruments |
|
|
|
(4,087) |
|
|
|
7,619 |
Foreign exchange gains |
|
|
|
(1,062) |
|
|
|
(84) |
Net finance costs |
|
|
|
115,140 |
|
|
|
91,927 |
22. OPERATING SEGMENTS
The Company determines its reportable segments based on the
nature of operations and includes four operating segments:
Conventional Pipelines, Oil Sands & Heavy Oil, Gas Services and
Midstream.
Conventional Pipelines consists of the tariff based operations
of pipelines and related facilities to deliver crude oil,
condensate and NGL in Alberta and
B.C.
Oil Sands & Heavy Oil consists of the Syncrude, Horizon,
Nipisi and Mitsue Pipelines, and the Cheecham Lateral. These
pipelines and related facilities deliver synthetic crude oil
produced from oil sands under long-term cost-of-service
arrangements.
Gas Services consists of natural gas gathering and processing
facilities, including three gas plants, twelve compressor stations
and over 300 kilometres of gathering systems.
Midstream consists of the Company's interests in extraction and
fractionation facilities, terminalling and storage hub services
under a mixture of short, medium and long-term contractual
arrangements.
The financial results of the business segments is included
below. Performance is measured based on results from operating
activities, net of depreciation and amortization, as included in
the internal management reports that are reviewed by the Company's
CEO, CFO and COO. The segments results from operating activities,
before depreciation and amortization, is used to measure
performance as management believes that such information is the
most relevant in evaluating results of certain segments relative to
other entities that operate within these industries. Intersegment
transactions are recorded at market value and eliminated under
corporate and intersegment eliminations.
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2012 ($ thousands)
|
|
Conventional
Pipelines(1) |
|
Oil Sands
&
Heavy Oil |
|
Gas
Services |
|
Midstream(2) |
|
Corporate
&
Intersegment
Eliminations |
|
Total |
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation |
|
338,772 |
|
172,429 |
|
|
|
|
|
(19,487) |
|
491,714 |
|
NGL product and services,
terminalling, storage and hub services |
|
|
|
|
|
|
|
2,847,403 |
|
|
|
2,847,403 |
|
Gas Services |
|
|
|
|
|
88,285 |
|
|
|
|
|
88,285 |
Total revenue |
|
338,772 |
|
172,429 |
|
88,285 |
|
2,847,403 |
|
(19,487) |
|
3,427,402 |
|
Operations |
|
129,555 |
|
55,629 |
|
29,260 |
|
59,685 |
|
(2,563) |
|
271,566 |
|
Cost of goods sold, including
product purchases |
|
|
|
|
|
|
|
2,494,525 |
|
(19,487) |
|
2,475,038 |
|
Realized gain (loss) on
commodity-related derivative financial instruments |
|
111 |
|
|
|
|
|
(4,682) |
|
|
|
(4,571) |
Operating
margin |
|
209,328 |
|
116,800 |
|
59,025 |
|
288,511 |
|
2,563 |
|
676,227 |
|
Depreciation and amortization
(operational) |
|
43,959 |
|
19,800 |
|
14,546 |
|
95,299 |
|
|
|
173,604 |
|
Unrealized gain (loss) on
commodity-related derivative financial instruments |
|
(9,043) |
|
|
|
|
|
45,143 |
|
|
|
36,100 |
Gross
profit |
|
156,326 |
|
97,000 |
|
44,479 |
|
238,355 |
|
2,563 |
|
538,723 |
|
Depreciation included in general
and administrative |
|
|
|
|
|
|
|
|
|
5,782 |
|
5,782 |
|
Other general and
administrative |
|
6,692 |
|
3,771 |
|
4,130 |
|
15,478 |
|
61,635 |
|
91,706 |
|
Acquisition-related and other
expenses (income) |
|
957 |
|
297 |
|
11 |
|
434 |
|
23,049 |
|
24,748 |
Reportable segment
results from operating activities |
|
148,677 |
|
92,932 |
|
40,338 |
|
222,443 |
|
(87,903) |
|
416,487 |
Net finance costs
(income) |
|
6,192 |
|
1,889 |
|
800 |
|
3,205 |
|
103,054 |
|
115,140 |
Reportable segment
earnings (loss) before tax and income from equity accounted
investees |
|
142,485 |
|
91,043 |
|
39,538 |
|
219,238 |
|
(190,957) |
|
301,347 |
Share of loss of
investments in equity accounted investees, net of tax |
|
|
|
|
|
|
|
1,056 |
|
|
|
1,056 |
Capital
expenditures |
|
187,264 |
|
30,432 |
|
162,838 |
|
203,969 |
|
(189) |
|
584,314 |
(1) |
|
5.1 percent of Conventional Pipelines revenue is under
regulated tolling arrangements. |
(2) |
|
NGL product and services, terminalling, storage and hub
services revenue includes $97.1 million associated with U.S.
midstream sales. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2011
($ thousands)
|
|
Conventional
Pipelines(1) |
|
Oil Sands
&
Heavy Oil |
|
Gas
Services |
|
Midstream |
|
Corporate
&
Intersegment
Eliminations |
|
Total |
Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline transportation |
|
296,190 |
|
134,874 |
|
|
|
|
|
|
|
431,064 |
|
Terminalling, storage and hub
services |
|
|
|
|
|
|
|
1,173,480 |
|
|
|
1,173,480 |
|
Gas Services |
|
|
|
|
|
71,506 |
|
|
|
|
|
71,506 |
Total revenue |
|
296,190 |
|
134,874 |
|
71,506 |
|
1,173,480 |
|
|
|
1,676,050 |
|
Operations |
|
119,093 |
|
43,986 |
|
22,407 |
|
8,833 |
|
(2,396) |
|
191,923 |
|
Cost of goods sold, including
product purchases |
|
|
|
|
|
|
|
1,072,270 |
|
|
|
1,072,270 |
|
Realized gain (loss) on
commodity-related derivative financial instruments |
|
4,413 |
|
|
|
|
|
882 |
|
|
|
5,295 |
Operating
margin |
|
181,510 |
|
90,888 |
|
49,099 |
|
93,259 |
|
2,396 |
|
417,152 |
|
Depreciation and amortization
(operational) |
|
41,595 |
|
12,786 |
|
9,921 |
|
3,710 |
|
|
|
68,012 |
|
Unrealized gain (loss) on
commodity-related derivative financial instruments |
|
3,743 |
|
|
|
|
|
1,433 |
|
|
|
5,176 |
Gross
profit |
|
143,658 |
|
78,102 |
|
39,178 |
|
90,982 |
|
2,396 |
|
354,316 |
|
Depreciation included in general
and administrative |
|
|
|
|
|
|
|
|
|
2,207 |
|
2,207 |
|
Other general and
administrative |
|
6,421 |
|
2,898 |
|
4,117 |
|
5,234 |
|
41,314 |
|
59,984 |
|
Acquisition-related and other
expenses (income) |
|
1,018 |
|
(127) |
|
6 |
|
2 |
|
530 |
|
1,429 |
Reportable segment
results from operating activities |
|
136,219 |
|
75,331 |
|
35,055 |
|
85,746 |
|
(41,655) |
|
290,696 |
Net finance costs |
|
7,110 |
|
1,729 |
|
999 |
|
109 |
|
81,980 |
|
91,927 |
Reportable segment
earnings (loss) before tax and income from equity accounted
investees |
|
129,109 |
|
73,602 |
|
34,056 |
|
85,637 |
|
(123,635) |
|
198,769 |
Share of loss (profit)
of investments in equity accounted investees, net of tax |
|
|
|
|
|
|
|
(5,766) |
|
|
|
(5,766) |
Capital
expenditures |
|
72,034 |
|
191,723 |
|
136,505 |
|
111,480 |
|
15,852 |
|
527,594 |
(1) |
|
4.8 percent of Conventional Pipelines revenue is under
regulated tolling arrangements. |
23. EARNINGS PER SHARE
Basic earnings per share
The calculation of basic earnings per share at December 31, 2012 was based on the earnings
attributable to common shareholders of $224.8 million (2011: $165.7 million) and a weighted average number of
common shares outstanding of 258.9 million (2011: 167.4
million).
Diluted earnings per share
The calculation of diluted earnings per share at December 31, 2012 was based on earnings
attributable to common shareholders of $224.8 million (December
31, 2011: $165.7 million), and
weighted average number of common shares outstanding after
adjustment for the effects of all dilutive potential common shares
of 259.5 million (2011: 168.2 million), calculated as follows:
Weighted average number of common shares
|
|
|
|
|
|
|
|
|
(In thousands of shares) |
|
|
|
2012 |
|
|
|
2011 |
Issued common shares at January 1 |
|
|
|
167,908 |
|
|
|
166,877 |
Effect of shares issued on acquisition |
|
|
|
87,243 |
|
|
|
|
Effect of share options exercised |
|
|
|
185 |
|
|
|
556 |
Effect of conversion of convertible
debentures |
|
|
|
9 |
|
|
|
|
Effect of shares issued under dividend
reinvestment plan |
|
|
|
3,524 |
|
|
|
|
Weighted average number of common shares at
December 31 (basic) |
|
|
|
258,869 |
|
|
|
167,433 |
|
|
|
|
|
|
|
|
|
Dilutive effect of conversion of convertible
debentures |
|
|
|
|
|
|
|
|
Dilutive effect of share options on issue |
|
|
|
614 |
|
|
|
742 |
Weighted average number of common shares at
December 31 (diluted) |
|
|
|
259,483 |
|
|
|
168,175 |
|
|
|
|
|
|
|
|
|
Basic earnings per share ($) |
|
|
|
0.87 |
|
|
|
0.99 |
Diluted earnings per share ($) |
|
|
|
0.87 |
|
|
|
0.99 |
At December 31, 2012, the effect
of the conversion of the convertible debentures was excluded from
the diluted earnings per share calculation as the impact was
anti-dilutive. If the convertible debentures were included, an
additional 23.3 million (2011: 10.5 million) common shares would be
added to the weighted average number of common shares and
$27.3 million (2011: $13.8 million) would be added to earnings,
representing after tax interest expense of the convertible
debentures.
The average market value of the Company's shares for purposes of
calculating the dilutive effect of share options was based on
quoted market prices for the period during which the options were
outstanding.
24. CHANGES IN NON-CASH WORKING CAPITAL
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Accounts receivable, inventory and other |
|
|
|
|
6,043 |
|
|
|
|
(30,388) |
Accounts payable and accrued liabilities |
|
|
|
|
(115,924) |
|
|
|
|
10,091 |
Change in non-cash operating working capital |
|
|
|
|
(109,881) |
|
|
|
|
(20,297) |
25. EMPLOYEE BENEFITS
|
|
|
|
|
|
|
|
|
|
|
December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Registered defined benefit obligation |
|
|
|
|
21,394 |
|
|
|
|
10,755 |
Supplemental defined benefit obligation |
|
|
|
|
6,180 |
|
|
|
|
5,092 |
Other accrued benefit obligations |
|
|
|
|
1,049 |
|
|
|
|
1,104 |
Employee benefit obligations |
|
|
|
|
28,623 |
|
|
|
|
16,951 |
The Company maintains a defined contribution plan and
non-contributory defined pension plans covering its employees. The
defined benefit plans include a funded registered plan for all
employees and an unfunded supplemental retirement plan for those
employees affected by the Canada
Revenue Agency maximum pension limits. The Company also has other
accrued benefit obligations which include a non-contribution
unfunded post employment extended health and dental plan provided
to a few remaining retired employees. Benefits under the plans are
based on the length of service and the annual average best three
years of earnings during last ten years of service of the employee.
Benefits paid out of the plans are not indexed. The Company
measures its accrued benefit obligations and the fair value of plan
assets for accounting purposes as at December 31 of each year. The most recent
actuarial valuation was at December 31,
2009.
Defined benefit obligations
|
|
|
|
|
|
|
December 31 |
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Present value of unfunded obligations |
|
|
|
|
|
6,180 |
|
|
|
|
|
5,092 |
Present value of funded obligations |
|
|
121,783 |
|
|
|
|
|
100,138 |
|
|
|
Total present value of obligations |
|
|
121,783 |
|
|
6,180 |
|
|
100,138 |
|
|
5,092 |
Fair value of plan assets |
|
|
100,389 |
|
|
|
|
|
89,383 |
|
|
|
Recognized liability for defined benefit
obligations |
|
|
(21,394) |
|
|
(6,180) |
|
|
(10,755) |
|
|
(5,092) |
The Company funds the defined benefit obligation plans in
accordance with government regulations by contributing to trust
funds administered by an independent trustee. The funds are
invested primarily in equities and bonds. Defined benefit plan
contributions totalled $10 million
for the year ended December 31, 2012
(2011: $8 million).
The Company has determined that, in accordance with the terms
and conditions of the defined benefit plans, and in accordance with
statutory requirements of the plans, the present value of refunds
or reductions in future contributions is not lower than the balance
of the total fair value of the plan assets less the total present
value of obligations. As such, no decreases in the defined benefit
asset is necessary at December 31,
2012 and December 31,
2011.
Registered defined benefit pension plan assets
comprise
|
|
|
|
|
|
|
|
|
|
|
|
December 31 (percentages) |
|
|
|
|
|
2012 |
|
|
|
|
2011 |
Equity securities |
|
|
|
|
|
65.1 |
|
|
|
|
64.1 |
Debt |
|
|
|
|
|
30.1 |
|
|
|
|
30.8 |
Other |
|
|
|
|
|
4.8 |
|
|
|
|
5.1 |
|
|
|
|
|
|
100.0 |
|
|
|
|
100.0 |
Movement in the present value of the pension
obligation
|
|
|
|
|
|
|
Year Ended December 31 |
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Defined benefits obligations at
January 1 |
|
|
100,138 |
|
|
5,092 |
|
|
90,090 |
|
|
4,382 |
Benefits paid by the plan |
|
|
(5,896) |
|
|
(66) |
|
|
(6,108) |
|
|
|
Current service costs and
interest |
|
|
12,009 |
|
|
504 |
|
|
9,944 |
|
|
402 |
Actuarial losses in other
comprehensive income |
|
|
15,532 |
|
|
650 |
|
|
6,212 |
|
|
308 |
Defined benefit obligations at
December 31 |
|
|
121,783 |
|
|
6,180 |
|
|
100,138 |
|
|
5,092 |
Movement in the present value of registered defined benefit
pension plan assets
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Fair value of plan assets at January 1 |
|
|
|
|
89,383 |
|
|
|
|
89,609 |
Contributions paid into the plan |
|
|
|
|
10,000 |
|
|
|
|
8,000 |
Benefits paid by the plan |
|
|
|
|
(5,896) |
|
|
|
|
(6,108) |
Expected return on plan assets |
|
|
|
|
5,288 |
|
|
|
|
5,521 |
Actuarial (losses) gains in other comprehensive
income |
|
|
|
|
1,614 |
|
|
|
|
(7,639) |
Fair value of registered plan assets at December
31 |
|
|
|
|
100,389 |
|
|
|
|
89,383 |
Expense recognition in profit or loss
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 |
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Current service costs |
|
|
6,655 |
|
|
232 |
|
|
4,780 |
|
|
149 |
Interest on obligation |
|
|
5,354 |
|
|
272 |
|
|
5,164 |
|
|
253 |
Expected return on plan
assets |
|
|
(5,288) |
|
|
|
|
|
(5,521) |
|
|
|
|
|
|
6,721 |
|
|
504 |
|
|
4,423 |
|
|
402 |
The expense is recognized in the following line items in the
statement of comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 |
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Operating expenses |
|
|
3,734 |
|
|
|
|
|
2,771 |
|
|
|
General and administrative
expense |
|
|
2,987 |
|
|
504 |
|
|
1,652 |
|
|
402 |
|
|
|
6,721 |
|
|
504 |
|
|
4,423 |
|
|
402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets |
|
|
6,902 |
|
|
|
|
|
(2,118) |
|
|
|
Actuarial gains and losses recognized in other comprehensive
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Total |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Total |
Cumulative amount at January
1 |
|
|
15,050 |
|
|
146 |
|
|
15,196 |
|
|
4,662 |
|
|
(85) |
|
|
4,577 |
Recognized during the period after
tax |
|
|
10,439 |
|
|
488 |
|
|
10,927 |
|
|
10,388 |
|
|
231 |
|
|
10,619 |
Cumulative amount at December
31 |
|
|
25,489 |
|
|
634 |
|
|
26,123 |
|
|
15,050 |
|
|
146 |
|
|
15,196 |
Principal actuarial assumptions used as at December 31 (expressed as weighted averages):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012 |
|
|
|
|
2011 |
Discount rate |
|
|
|
|
|
4.4% |
|
|
|
|
5.2% |
Expected long-term rate of return on plan
assets |
|
|
|
|
|
5.8% |
|
|
|
|
6.1% |
Future pension earning increases |
|
|
|
|
|
4.0% |
|
|
|
|
4.0% |
Assumptions regarding future mortality are based on published
statistics and mortality tables. The current longevities underlying
the values of the liabilities in the defined plans are as
follows:
|
|
|
|
|
|
|
|
|
|
|
December 31 (years) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Longevity at age 65 for current
pensioners |
|
|
|
|
|
|
|
|
|
|
Males |
|
|
|
|
19.8 |
|
|
|
|
19.7 |
Females |
|
|
|
|
22.1 |
|
|
|
|
22.1 |
|
|
|
|
|
|
|
|
|
|
|
Longevity at age 65 for current member aged
45 |
|
|
|
|
|
|
|
|
|
|
Males |
|
|
|
|
21.3 |
|
|
|
|
21.2 |
Females |
|
|
|
|
22.9 |
|
|
|
|
22.9 |
The calculation of the defined benefit obligation is sensitive
to the discount rate, compensation increases, retirements and
termination rates as set out above. An increase or decrease of the
estimated discount rate of 4.4 percent by 100 basis points at
December 31, 2012 is considered
reasonably possible in the next financial year. A discount rate of
5.4 percent would decrease the obligation by $18.2 million. A discount rate of 3.4 percent
would increase the obligation by $23.2
million.
The overall expected long-term rate of return on assets is 5.8
percent. The expected long-term rate of return is based on the
portfolio as a whole and not the sum of the returns on individual
asset categories. The return is based exclusively on historical
returns, without adjustments.
Historical information
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
2011 |
|
|
2010 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Present value of the defined
benefit obligation |
|
|
100,138 |
|
|
5,092 |
|
|
90,090 |
|
|
4,382 |
Fair value of plan assets |
|
|
89,383 |
|
|
|
|
|
89,609 |
|
|
|
(Deficit) in the plan |
|
|
(10,755) |
|
|
(5,092) |
|
|
(481) |
|
|
(4,382) |
Experience adjustments arising on
plan liabilities |
|
|
|
|
|
|
|
|
886 |
|
|
356 |
Experience adjustments arising on
plan assets |
|
|
7,639 |
|
|
|
|
|
(2,968) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
2009 |
|
|
2008 |
($ thousands) |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
|
|
Registered
Plan |
|
|
Supplemental
Plan |
Present value of the defined
benefit obligation |
|
|
76,873 |
|
|
4,110 |
|
|
58,359 |
|
|
3,000 |
Fair value of plan assets |
|
|
78,852 |
|
|
|
|
|
60,682 |
|
|
|
(Deficit)/surplus in the plan |
|
|
1,979 |
|
|
(4,110) |
|
|
2,323 |
|
|
(3,000) |
Experience adjustments arising on
plan liabilities |
|
|
1,402 |
|
|
(14) |
|
|
|
|
|
211 |
Experience adjustments arising on
plan assets |
|
|
(7,417) |
|
|
|
|
|
17,702 |
|
|
|
The Company expects $12.6 million
in contributions to be paid to its defined benefit plans in
2013.
26. SHARE-BASED PAYMENTS
At December 31, 2012, the Company
has the following share-based payment arrangements:
Share option plan (equity settled)
The Company has a share option plan under which employees are
eligible to receive options to purchase shares in the Company.
Long-term share unit award incentive (cash-settled)
plan
In 2005, the Company established a long-term share unit award
incentive plan. Under the share-based compensation plan, awards of
restricted (RSU) and performance (PSU) share units are made to
officers, non-officers and directors. The plan results in
participants receiving cash compensation based on the value of the
underlying notional shares granted under the plan. Payments are
based on a trading value of the Company's common shares plus
notional dividends and performance of the Company.
Terms and conditions of share option plan and share unit
award incentive plan
The terms and conditions relating to the grants of the share
option program and the long-term share unit award incentive plans
are listed in the tables below:
|
|
|
|
|
|
|
|
|
Grant date share options granted to
employees
(Number of units in thousands) |
|
|
|
Number of
options
in thousands |
|
|
|
Contractual
life
of options |
August 3, 2011 |
|
|
|
1,052 |
|
|
|
7 years |
October 1, 2011 |
|
|
|
48 |
|
|
|
7 years |
January 3, 2012 |
|
|
|
55 |
|
|
|
7 years |
April 2, 2012 |
|
|
|
19 |
|
|
|
7 years |
August 9, 2012 |
|
|
|
1,372 |
|
|
|
7 years |
October 1, 2012 |
|
|
|
49 |
|
|
|
7 years |
One third vest on the first anniversary of the grant date, one
third vest on the second anniversary of the grant date, and one
third vest on the third anniversary of the grant date.
Long-term share unit award incentive
plan(1)
|
|
|
|
|
|
|
|
|
Grant date PSUs to Officers,
Non-Officers(2) and Directors
(Number of units in thousands) |
|
|
|
Units |
|
|
|
Contractual
life
of PSU |
January 1, 2011 |
|
|
|
284 |
|
|
|
3.0 years |
January 1, 2012 |
|
|
|
188 |
|
|
|
3.0 years |
April 2, 2012 (on acquisition) |
|
|
|
201 |
|
|
|
2.2 years |
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.
|
|
|
|
|
|
|
|
|
Grant date RSUs to Officers,
Non-Officers(2) and Directors
(Number of units in thousands) |
|
|
|
Units |
|
|
|
Contractual
life
of RSU |
January 1, 2011 |
|
|
|
185 |
|
|
|
3.0 years |
January 1, 2012 |
|
|
|
186 |
|
|
|
3.0 Years |
April 2, 2012 (on acquisition) |
|
|
|
177 |
|
|
|
2.2 Years |
One third vest on the first anniversary of the grant date, one
third vest on the second anniversary of the grant date, and one
third vest on the third anniversary of the grant date.
(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. |
|
|
|
Disclosure of share option plan
The number and weighted average exercise prices of share options
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
Options |
|
|
|
Weighted Average Exercise
Price |
Outstanding at December 31,
2010 |
|
|
|
|
2,759,259 |
|
|
|
16.43 |
Granted |
|
|
|
|
1,100,800 |
|
|
|
25.29 |
Exercised |
|
|
|
|
(1,023,916) |
|
|
|
15.48 |
Forfeited |
|
|
|
|
(161,763) |
|
|
|
19.75 |
Outstanding at December 31, 2011 |
|
|
|
|
2,674,380 |
|
|
|
20.24 |
Granted |
|
|
|
|
1,495,050 |
|
|
|
26.70 |
Exercised |
|
|
|
|
(427,934) |
|
|
|
16.96 |
Forfeited or expired |
|
|
|
|
(209,858) |
|
|
|
24.73 |
Outstanding as at December 31,
2012 |
|
|
|
|
3,531,638 |
|
|
|
23.11 |
As of December 31, 2012, the
following options are outstanding:
|
|
|
|
|
|
|
|
|
|
Exercise Price
(dollars) |
|
|
Number
outstanding
at December 31, 2012 |
|
|
Options
Exercisable |
|
|
Weighted average
remaining life (years) |
$14.18 - $17.99 |
|
|
589,433 |
|
|
589,433 |
|
|
1.5 |
$18.00 -
20.99 |
|
|
593,380 |
|
|
369,124 |
|
|
4.6 |
$21.00 - $30.06 |
|
|
2,348,825 |
|
|
288,723 |
|
|
6.2 |
The weighted average share price at the date of exercise for
share options exercised in the year ended December 31, 2012 was $28.28 (December 31,
2011: $24.64).
Expected volatility estimated by considering historic average
share price volatility. The weighted average inputs used in the
measurement of the fair values at grant date of share options are
the following:
Share options granted
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
|
|
|
|
|
|
(dollars) |
|
|
|
|
2012 |
|
|
|
2011 |
Weighted average |
|
|
|
|
|
|
|
|
|
|
Fair value at grant date |
|
|
|
|
$2.10 |
|
|
|
$2.72 |
|
Share price at grant date |
|
|
|
|
$26.68 |
|
|
|
$25.72 |
|
Exercise price |
|
|
|
|
$26.70 |
|
|
|
$25.29 |
|
Expected volatility |
|
|
|
|
21.4% |
|
|
|
24.7% |
|
Expected option life (years) |
|
|
|
|
3.67 |
|
|
|
3.67 |
Expected annual dividends per
option |
|
|
|
|
$1.61 |
|
|
|
$1.56 |
Expected forfeitures |
|
|
|
|
7.9% |
|
|
|
7.0% |
Risk-free interest rate (based on
government bonds) |
|
|
|
|
1.3% |
|
|
|
1.6% |
Disclosure of long-term share unit award incentive
plan
The long-term share unit award incentive plan was valued using
the reporting date market price of the Company's shares of
$28.46 (December 31, 2011: $29.66). Actual payment may differ from amount
valued based on market price and company performance.
Long-term share unit award incentive units granted
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31 |
|
|
|
|
2012 |
|
|
|
|
2011 |
Number of share units granted |
|
|
|
|
752,187 |
|
|
|
|
469,253 |
Employee expenses
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
2012 |
|
|
|
2011 |
Share option plan, equity settled |
|
|
|
|
1,828 |
|
|
|
1,097 |
Long-term share unit award incentive plan |
|
|
|
|
15,200 |
|
|
|
17,554 |
Total expense recognized as employee costs |
|
|
|
|
17,028 |
|
|
|
18,651 |
|
|
|
|
|
|
|
|
|
|
Total carrying amount of liabilities for cash
settled arrangements |
|
|
|
|
33,506 |
|
|
|
22,971 |
Total intrinsic value of liability for vested
benefits |
|
|
|
|
16,267 |
|
|
|
8,911 |
27. FINANCIAL INSTRUMENTS AND FINANCIAL RISK
MANAGEMENT
Economic hedges
The Company has entered into derivative financial instruments to
limit the exposures to changes in commodity prices, interest rates,
cost of power and foreign currency exchange rates. Hedge accounting
has not been applied, however the Company still considers that
there is an economic hedge which limits the exposure to
fluctuations in revenue and expenses.
Financial risk
The Company has exposure to credit risk, liquidity risk and
market risk. The Company's Board of Directors has the overall
responsibility for the oversight of these risks and reviews the
Company's policies on an ongoing basis to ensure that these risks
are appropriately managed. The Company's Audit Committee oversees
how management monitors compliance with the Company's risk
management policies and procedures and reviews the adequacy of this
risk framework in relation to the risks faced by the Company. The
Company's Risk Management function assists in managing these risks.
The Company's primary risk management objective is to protect
capital resources, earnings and cash flow.
Counterparty credit risk
Counterparty credit risk is the risk of financial loss to the
Company if a customer, partner or counterparty to a financial
instrument failed to meet its contractual obligations in accordance
with the terms and conditions of the financial instruments with the
Company and which arise primarily from the Company's cash and cash
equivalents, trade and other receivables, and from counterparties
to its derivative financial instruments. The carrying amount of the
financial assets represents the maximum credit exposure to the
Company. The maximum counterparty credit exposure to counterparty
credit risk at the reporting date was:
|
|
|
|
|
|
|
|
|
Carrying Amount |
December 31
($ thousands) |
|
|
|
2012 |
|
|
|
2011 |
Cash and cash equivalents |
|
|
|
27,336 |
|
|
|
|
Trade and other receivables |
|
|
|
334,772 |
|
|
|
159,081 |
Derivative financial instruments |
|
|
|
7,871 |
|
|
|
6,450 |
|
|
|
|
369,979 |
|
|
|
165,531 |
The Company manages counterparty credit risk for its cash and
cash equivalents by maintaining bank accounts with Schedule 1
banks. The Company has minimal counterparty credit risk related to
its receivables as a majority of these amounts are with large
established counterparties in the oil and gas industry and are
subject to the terms of the Company's shipping rules and
regulations or pursuant to contracts. The rules and regulations
permit the Company to receive and hold financial assurances against
a counterparty to cover current and aged receivables when
warranted. Balances are generally payable the 25th day of the
following month. This date coincides with the date on which oil and
gas companies receive payment from industry partners and
counterparties. Typically, the Company has collected its
receivables in full and at December 31,
2012, approximately 93 percent were current. The Company
also maintains lien rights on the oil and NGL that are in its
custody during the transportation of such products on the pipeline
as well as the right to offset for single shipper operations.
Therefore, the risk of non-collection is considered to be low and
no impairment of receivables has been made.
Additionally, counterparty credit risk is mitigated through
established credit management techniques, including conducting
comprehensive financial and other assessments for all new
counterparties and regular reviews of existing counterparties to
establish and monitor a counterparty's creditworthiness, setting
exposure limits, monitoring exposures against these limits, using
contract netting arrangements and obtaining financial assurances
when warranted. In general, financial assurances include
guarantees, letters of credit and cash. The Company monitors and
manages its concentration of counterparty credit risk on an ongoing
basis. The Company believes these measures minimize its
counterparty credit risk but there is no certainty that they will
protect it against all material losses. Letters of credit mitigate
the counterparty credit risk on $44.6
million (December 31, 2011:
$7.8 million) of the receivables
balance. The Company's assessment of a counterparty's
creditworthiness includes external credit ratings, where available,
and in other cases, detailed financial and other assessments which
generate an internal credit rating based on financial ratios.
Counterparty exposure limits are established for each counterparty
representing the maximum unsecured dollar amount in conjunction
with an associated counterparty exposure limit approval authority
matrix which has been approved by the Risk Management Committee.
The Company continues to closely monitor and reassess its
counterparty exposure limits on an ongoing basis.
Liquidity risk
Liquidity risk is the risk the Company will not be able to meet
its financial obligations as they come due. The following are the
contractual maturities of financial liabilities, including
estimated interest payments and excluding the impact of netting
agreements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding balances due by period |
|
|
December 31, 2012
($ thousands) |
|
Carrying
Amount |
|
Expected
Cash Flows |
|
6 Months
or Less |
|
6 - 12
Months |
|
1 - 2 Years |
|
2 - 5 Years |
|
More Than
5 Years |
Trade payables and accrued liabilities |
|
344,208 |
|
344,208 |
|
344,208 |
|
|
|
|
|
|
|
|
Loans and borrowings |
|
1,938,626 |
|
2,446,733 |
|
44,927 |
|
35,637 |
|
312,765 |
|
693,389 |
|
1,360,015 |
Finance lease liabilities |
|
5,800 |
|
7,101 |
|
1,327 |
|
1,327 |
|
1,823 |
|
2,624 |
|
|
Convertible debentures |
|
609,968 |
|
903,475 |
|
19,607 |
|
19,607 |
|
39,360 |
|
291,204 |
|
533,697 |
Dividends payable |
|
39,586 |
|
39,586 |
|
39,586 |
|
|
|
|
|
|
|
|
Derivative financial liabilities |
|
67,691 |
|
67,691 |
|
11,532 |
|
4,400 |
|
16,774 |
|
25,115 |
|
9,870 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding balances due by period |
|
|
December 31, 2011
($ thousands) |
|
Carrying
Amount |
|
Expected
Cash Flows |
|
6 Months
or Less |
|
6 - 12
Months |
|
1 - 2 Years |
|
2 - 5 Years |
|
More Than
5 Years |
Bank overdraft |
|
676 |
|
676 |
|
676 |
|
|
|
|
|
|
|
|
Trade payables and accrued liabilities |
|
155,926 |
|
155,926 |
|
155,926 |
|
|
|
|
|
|
|
|
Unsecured notes and credit facilities |
|
1,272,838 |
|
1,663,644 |
|
27,120 |
|
340,285 |
|
350,445 |
|
117,494 |
|
828,300 |
Senior secured notes |
|
57,499 |
|
70,909 |
|
6,257 |
|
6,257 |
|
25,027 |
|
33,368 |
|
|
Finance lease liabilities |
|
5,650 |
|
7,742 |
|
1,273 |
|
1,273 |
|
1,942 |
|
3,254 |
|
|
Convertible debentures |
|
289,365 |
|
299,780 |
|
|
|
|
|
|
|
|
|
299,780 |
Dividends payable |
|
21,828 |
|
21,828 |
|
21,828 |
|
|
|
|
|
|
|
|
Derivative financial liabilities |
|
17,539 |
|
18,460 |
|
2,385 |
|
2,385 |
|
3,670 |
|
6,438 |
|
3,582 |
The Company's approach to managing liquidity risk is to ensure
funds and credit facilities are available to meet its short-term
obligations. Management monitors daily cash positions and performs
cash forecasts weekly to determine cash requirements. On a monthly
basis, Management typically forecasts cash flows for a period of 12
months to identify financing requirements. These financing
requirements are then addressed through a combination of credit
facilities and through access to capital markets if required.
Market risk
Market risk is the risk that the fair value of a financial
instrument will fluctuate because of changes in market prices.
Market risk is generally comprised of price risk, currency risk and
interest rate risk.
a. Price risk
Commodity price volatility and market location differentials
affect the Midstream business. In addition, Midstream is exposed to
possible price declines between the time Pembina purchases NGL
feedstock and sells NGL products, and to narrowing frac spreads.
Frac spreads are the difference between the selling prices for
propane-plus and the input cost of the natural gas required to
produce the respective NGL products.
Pembina responds to these risks using a market risk management
program to protect margins on a portion of its natural gas based
supply sales contracts, and to manage physical contract exposure
while retaining some ability to participate in a widening margin
environment. The Company uses derivative financial instruments to
manage exposure to commodity prices and power costs. The Company
does not trade financial instruments for speculative purposes. The
derivative instruments include participating swaps and fixed price
swap contracts that settle against indexed reference pricing.
Participating swaps are contracts that provide a floor and ceiling
for a certain percentage of the volume of a contract. A swap
contract is an agreement where a floating price is exchanged for a
fixed price over a specified period.
b. Currency risk
Pembina's commodity sales are exposed to both positive and
negative effects of fluctuations in the Canadian/U.S. exchange
rate. Pembina manages this exposure by matching a significant
portion of the cash costs that it expects with revenues in the same
currency. In addition, Pembina uses derivative instruments to
manage the U.S. cash requirements of its business.
Pembina regularly sells or purchases a portion of expected U.S.
cashflows. Pembina's also manages the exposure it has to
fluctuations in the U.S./Canadian dollar exchange rate when the
underlying commodity price is based upon a U.S. index price.
Pembina may also use derivative products that provide for
protection against a stronger Canadian dollar, while allowing it to
participate if the currency weakens relative to the U.S.
dollar.
c. Interest rate risk
At the reporting date, the interest rate profile of the
Company's interest-bearing financial instruments was:
|
|
|
|
|
($ thousands) |
|
|
|
Carrying Amounts of
Financial Liability |
December 31 |
|
|
|
2012 |
|
|
2011 |
Fixed rate instruments |
|
|
|
(1,417,950) |
|
|
(1,324,758) |
Variable rate instruments |
|
|
|
(520,675) |
|
|
(319,465) |
The Company uses swap contracts to manage exposure to variable
interest rates.
Cash flow sensitivity analysis for variable rate
instruments
A change of 100 basis points in interest rates at the reporting
date would have (increased) decreased profit or loss by the amounts
shown below. This analysis assumes that all other variables remain
constant.
|
|
|
|
|
|
|
|
|
|
|
December 31($
thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
|
|
|
|
|
± 100 bp |
|
|
|
|
± 100 bp |
Variable rate instruments |
|
|
|
|
± 5,250 |
|
|
|
|
± 3,149 |
Interest rate swap |
|
|
|
|
± (3,800) |
|
|
|
|
± (2,000) |
Profit or loss sensitivity
(net) |
|
|
|
|
± 1,450 |
|
|
|
|
± 1,149 |
Fair values
The fair values of financial assets and liabilities, together
with the carrying amounts shown in the statement of financial
position, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
2012 |
|
|
2011 |
($ thousands) |
|
|
Carrying
Amount |
|
|
Fair
Value |
|
|
Carrying
Amount |
|
|
Fair
Value |
Financial assets carried at
fair value |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial
instruments |
|
|
7,871 |
|
|
7,871 |
|
|
6,450 |
|
|
6,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial assets carried at
amortized cost |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
27,336 |
|
|
27,336 |
|
|
|
|
|
|
Trade and other receivables |
|
|
334,772 |
|
|
334,772 |
|
|
159,081 |
|
|
159,081 |
|
|
|
362,108 |
|
|
362,108 |
|
|
159,081 |
|
|
159,081 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities carried
at fair value |
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial
instruments |
|
|
67,691 |
|
|
67,691 |
|
|
17,538 |
|
|
17,538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial liabilities carried
at amortized cost |
|
|
|
|
|
|
|
|
|
|
|
|
Bank overdraft |
|
|
|
|
|
|
|
|
676 |
|
|
676 |
Trade payables and accrued
liabilities |
|
|
344,208 |
|
|
344,208 |
|
|
155,926 |
|
|
155,926 |
Finance lease liabilities |
|
|
5,800 |
|
|
6,170 |
|
|
5,650 |
|
|
5,948 |
Dividends payable |
|
|
39,586 |
|
|
39,586 |
|
|
21,828 |
|
|
21,828 |
Loans and borrowings |
|
|
1,938,626 |
|
|
2,083,505 |
|
|
1,272,838 |
|
|
1,391,895 |
Senior secured notes |
|
|
|
|
|
|
|
|
57,499 |
|
|
65,567 |
Convertible debentures |
|
|
609,968(1) |
|
|
725,074 |
|
|
289,365 |
|
|
326,760 |
|
|
|
2,938,188 |
|
|
3,198,543 |
|
|
1,803,782 |
|
|
1,968,600 |
(1) Carrying amount excludes conversion feature
of convertible debentures.
The basis for determining fair values is disclosed in Note
4.
Interest rates used for determining fair value
The interest rates used to discount estimated cash flows, when
applicable, are based on the government yield curve at the
reporting date plus and adequate credit spread, and were as
follows:
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
|
2012 |
|
|
|
|
2011 |
Derivatives |
|
|
|
|
1.2% - 2.5% |
|
|
|
|
1.1% - 1.8% |
Loans and borrowings |
|
|
|
|
2.0% - 3.7% |
|
|
|
|
2.2% - 4.2% |
Leases |
|
|
|
|
4.4% |
|
|
|
|
4.8% |
Fair value of power derivatives are based on market rates
reflecting forward curves.
Fair value hierarchy
The fair value of financial instruments carried at fair value is
classified according to the following hierarchy based on the amount
of observable inputs used to value the instruments.
Level 1: Unadjusted quoted prices are available in active
markets for identical assets or liabilities as the reporting date.
Pembina does not use Level 1 inputs for any of its fair value
measurements.
Level 2: Inputs other than quoted prices included within Level 1
that are observable for the asset or liability, either directly
(i.e. as prices) or indirectly (i.e. derived from prices). Level 2
valuations are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be
substantially observed or corroborated in the marketplace.
Instruments in this category include non-exchange traded
derivatives such as over-the-counter physical forwards and options,
including those that have prices similar to quoted market prices.
Pembina obtains quoted market prices for commodities, future power
contracts, interest rates and foreign exchange rates from
information sources including banks, Bloomberg Terminals and
Natural Gas Exchange (NGX). With the exception of one item
described under Level 3, all of Pembina's financial instruments
carried at fair value are valued using Level 2 inputs.
Level 3: Valuations in this level require the most significant
judgments and consist primarily of unobservable or non-market based
inputs. Level 3 inputs include longer-term transactions,
transactions in less active markets or transactions at locations
for which pricing information is not available. In these instances,
internally developed methodologies are used to determine fair
value. The redemption liability related to Three Star is classified
as a Level 3 instrument, as the fair value is determined by using
inputs that are not based on observable market data. The liability
represents a put option, held by the non-controlling interest of
Three Star, to sell the remaining one-third of the business to
Pembina after the third anniversary of the original acquisition
date (October 3, 2014). The put price
to be paid by the Company for the residual interest upon exercise
is based on a multiple of Three Star's earnings during the three
year period prior to exercise, adjusted for associated capital
expenditures and debt based on management estimates. These
estimates are subject to measurement uncertainty and the effect on
the financial statements of future periods could be material.
Financial instruments classified as Level 3
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
|
2012 |
|
|
|
|
2011 |
Redemption liability, beginning of
year |
|
|
|
|
|
|
|
|
|
|
|
Assumed on acquisition |
|
|
|
|
|
6,183 |
|
|
|
|
|
Accretion of liability |
|
|
|
|
|
65 |
|
|
|
|
|
Gain on revaluation |
|
|
|
|
|
(962) |
|
|
|
|
|
Redemption liability, end of year |
|
|
|
|
|
5,286 |
|
|
|
|
|
The following table is a summary of the net derivative financial
instrument liability:
|
|
|
|
|
|
|
|
|
|
|
As at December 31 ($
thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Frac spread related |
|
|
|
|
(3,068) |
|
|
|
|
|
Product margin |
|
|
|
|
(1,088) |
|
|
|
|
2,267 |
Corporate |
|
|
|
|
|
|
|
|
|
|
|
Power |
|
|
|
|
(7,100) |
|
|
|
|
4,183 |
|
Interest rate |
|
|
|
|
(14,302) |
|
|
|
|
(17,538) |
|
Foreign exchange |
|
|
|
|
653 |
|
|
|
|
|
Other derivative financial
instruments |
|
|
|
|
|
|
|
|
|
|
|
Conversion feature of convertible debentures (Note
13) |
|
|
|
|
(29,629) |
|
|
|
|
|
|
Redemption liability related to acquisition of
subsidiary |
|
|
|
|
(5,286) |
|
|
|
|
|
Net derivative financial
instruments liability |
|
|
|
|
(59,820) |
|
|
|
|
(11,088) |
In conjunction with the Acquisition, 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 $0.1 million on
the revaluation on the conversion feature of convertible debentures
in profit and loss in net finance costs for the year ended
December 31, 2012.
|
|
|
|
Commodity-Related Derivative
Financial Instruments |
|
|
Year Ended
December 31 |
($ thousands) |
|
|
2012 |
|
|
2011 |
Realized (loss) gain on commodity-related
derivative financial instruments |
|
|
|
|
|
|
Frac spread related |
|
|
(4,497) |
|
|
|
Product margin |
|
|
(141) |
|
|
882 |
Power |
|
|
67 |
|
|
4,413 |
Realized (loss) gain on commodity-related
derivative financial instruments |
|
|
(4,571) |
|
|
5,295 |
Unrealized gain on commodity-related derivative
financial instruments |
|
|
36,100 |
|
|
5,176 |
Gain on commodity-related derivative financial
instruments |
|
|
31,529 |
|
|
10,471 |
For non-commodity-related derivative financial instruments see
Note 21, Net Finance Costs.
Sensitivity analysis
The following table shows the impact on earnings if the
underlying risk variables of the derivative financial instruments
changed by a specified amount, with other variables held
constant.
|
|
|
|
|
|
|
|
|
|
|
As at December 31, 2012 ($
thousands) |
|
|
|
|
|
|
+
Change |
|
|
-
Change |
Frac spread related |
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
|
(AECO +/- $1.00 per GJ) |
|
|
6,724 |
|
|
(6,724) |
|
NGL (includes propane, butane) |
|
|
|
(Belvieu +/- U.S.
$0.10 per gal) |
|
|
(3,991) |
|
|
3,991 |
|
Foreign exchange (U.S.$ vs. Cdn$) |
|
|
|
(FX rate +/- $0.05) |
|
|
(3,637) |
|
|
3,637 |
Product margin |
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
|
(WTI +/- $5.00 per bbl) |
|
|
(6,387) |
|
|
6,387 |
|
NGL (includes propane, butane and condensate) |
|
|
|
(Belvieu +/- U.S. $0.10 per gal) |
|
|
6,112 |
|
|
(6,112) |
Corporate |
|
|
|
|
|
|
|
|
|
|
|
Interest rate |
|
|
|
(Rate +/- 50 basis points) |
|
|
3,857 |
|
|
(3,857) |
|
Power |
|
|
|
(AESO +/- $5.00 per MW/h) |
|
|
3,631 |
|
|
(3,631) |
Conversion feature of convertible
debentures |
|
|
|
(Pembina share price
+/- $0.50 per share) |
|
|
(2,761) |
|
|
2,629 |
28. OPERATING LEASES
Leases as lessee
Operating lease rentals are payable as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31 ($ thousands) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Less than 1 year |
|
|
|
|
22,754 |
|
|
|
|
6,237 |
Between 1 and 5 years |
|
|
|
|
109,542 |
|
|
|
|
20,021 |
More than 5 years |
|
|
|
|
153,574 |
|
|
|
|
40,494 |
|
|
|
|
|
285,870 |
|
|
|
|
66,752 |
The Company leases a number of offices, warehouses, vehicles and
rail cars under operating leases. The leases run for a period of
one to fifteen years, with an option to renew the lease after that
date. The Company has sublet office space up to 2022 and has
contracted sub-lease payments of $51.4
million over the term.
During the year ended December 31,
2012, an amount of $7.1
million was recognized as an expense in profit or loss in
respect of operating leases (December 31,
2011: $3.8 million).
29. CAPITAL MANAGEMENT
The Company's objective when managing capital is to safeguard
the Company's ability to provide a stable stream of dividends to
shareholders that is sustainable over the long-term. The Company
manages its capital structure and makes adjustments to it in light
of changes in economic conditions and risk characteristics of its
underlying asset base and based on requirements arising from
significant capital development activities. Pembina manages and
monitors its capital structure and short-term financing
requirements using Non-GAAP measures; the ratios of debt to EBITDA,
debt to Enterprise Value (market value of common shares and
convertible debentures), adjusted cash flow to debt and debt to
equity. The metrics are used to measure the Company's overall debt
position and measure the strength of the Company's balance sheet.
The Company remains satisfied that the leverage currently employed
in the Company's capital structure is sufficient and appropriate
given the characteristics and operations of the underlying asset
base. The Company, upon approval from its Board of Directors, will
balance its overall capital structure through new equity or debt
issuances as required.
The Company maintains a conservative capital structure that
allows it to finance its day-to-day cash requirements through its
operations, without requiring external sources of capital. The
Company funds its operating commitments, short-term capital
spending as well as its dividends to shareholders through this cash
flow, while new borrowing and equity issuances are reserved for the
support of specific significant development activities. The capital
structure of the Company consists of shareholder's equity plus
long-term liabilities. Long-term debt is comprised of bank credit
facilities, unsecured notes, finance lease obligations and
convertible debentures.
Pembina is subject to certain financial covenants in its credit
facility agreements and is in compliance with all financial
covenants as of December 31,
2012.
Note 15 of these financial statements demonstrates the change in
Share Capital for the year ended December
31, 2012.
30. GROUP ENTITIES
Significant subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Interest |
December 31 (percentages) |
|
|
|
|
2012 |
|
|
|
|
2011 |
Pembina Pipeline |
|
|
|
|
100 |
|
|
|
|
100 |
Pembina Gas Services Limited Partnership |
|
|
|
|
100 |
|
|
|
|
100 |
Pembina Oil Sands Pipeline LP |
|
|
|
|
100 |
|
|
|
|
100 |
Pembina Midstream Limited Partnership |
|
|
|
|
100 |
|
|
|
|
100 |
Pembina North Limited Partnership |
|
|
|
|
100 |
|
|
|
|
100 |
Pembina West Limited Partnership |
|
|
|
|
100 |
|
|
|
|
100 |
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 |
|
|
|
|
|
31. RELATED PARTIES
All transactions with related parties were made on terms
equivalent to those that prevail in arm's length transactions.
Investments in equity accounted investees
Officers of Pembina Pipeline Corporation, the ultimate
controlling party, are Directors of Fort Saskatchewan Ethylene
Storage Corporation ("FSESC"), the parent of Fort Saskatchewan
Ethylene Storage Limited Partnership ("FSESLP"). FSESLP and FSESC
are both recognized as investments in joint ventures under the
equity method on Pembina's financial statements. Results from
operating activities are recorded as Share of Profit from Equity
Accounted Investees on Pembina's Statement of Comprehensive Income,
representing a 50 percent interest in the joint ventures.
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
|
|
|
|
Transaction
Value
Year Ended December 31 |
|
|
Balance
Outstanding
As At December 31 |
|
|
|
|
|
|
|
|
|
2012 |
|
|
2011 |
|
|
2012 |
|
|
2011 |
Related Party |
|
|
Transaction |
|
|
Note |
|
|
|
|
|
|
|
|
|
|
|
|
FSESLP |
|
|
Interest revenue |
|
|
|
|
|
262 |
|
|
876 |
|
|
|
|
|
|
|
|
|
Loan receivable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,903 |
Key management personnel and director compensation
Key management consists of the Company's directors and certain
key officers.
Compensation
In addition to short-term employee benefits - including
salaries, director fees and bonuses - the Company also provides key
management personnel with share-based compensation, contributes to
post employment pension plans and provides car allowances, parking
and business club memberships.
Key management personnel compensation comprised:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31 ($ thousands) |
|
|
|
|
|
2012 |
|
|
|
|
2011 |
Short term employee benefits |
|
|
|
|
|
2,743 |
|
|
|
|
2,802 |
Post-employment benefits |
|
|
|
|
|
231 |
|
|
|
|
207 |
Share-based compensation |
|
|
|
|
|
5,806 |
|
|
|
|
6,150 |
Other compensation |
|
|
|
|
|
121 |
|
|
|
|
112 |
Total compensation of key
management |
|
|
|
|
|
8,901 |
|
|
|
|
9,271 |
Transactions
Key management personnel and directors of the Company control
0.5 percent (2011: 0.8 percent) of the voting common shares of the
Company. Certain directors and key management personnel also hold
Pembina convertible debentures. Dividend and interest payments
received for the common shares and debentures held are commensurate
with other non-related holders of those instruments.
Certain officers are subject to employment agreements in the
event of termination without just cause or change of control.
Post employment benefit plans
Pembina has significant influence over the pension plans for the
benefit of their respective employees.
Transactions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($ thousands) |
|
|
|
|
|
|
Transaction Value
Year Ended December 31 |
|
|
Balance Outstanding
As At December 31 |
Post-employment
benefit plan |
|
|
|
Transaction |
|
|
2012 |
|
2011 |
|
|
2012 |
|
2011 |
Defined benefit
plan |
|
|
|
Funding |
|
|
10,000 |
|
8,000 |
|
|
|
|
|
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
INVESTOR INQUIRIES
Phone: (403) 231-3156
Fax: (403) 237-0254
Toll Free: 1-855-880-7404
Email: investor-relations@pembina.com
Website: www.pembina.com
SOURCE Pembina Pipeline Corporation