CONTINUING MOMENTUM
DELIVERING ON PLAN
as promised
ANNUAL REPORT 2013
DCP Midstream Partners, LP (NYSE: DPM), or the Partnership, is a
midstream master limited partnership that gathers, compresses, treats,
processes, transports, stores and sells natural gas; produces, fractionates,
transports, stores and sells NGLs and recovers and sells condensate; and
transports, stores and sells propane in wholesale markets.
The Partnership within DCP enterprise
Michigan
System
Wyoming
System
Piceance
System
Front
Range
Pipeline
O’Connor Plant
Wattenberg
Pipeline
Southern
Oklahoma
System
N. Louisiana
System
Pelico
Intrastate
Pipeline
East Texas
System
Southern
Hills
Pipeline
Black
Lake
Pipeline
Texas
Express
Pipeline
Sand Hills
Pipeline
Southeast
Texas
System
Discovery
System
Eagle Ford
System
MAP KEY
Owners
Asset Types
(vary by color indicating owner)
W
N
S
E
DCP Midstream
Partners
Natural Gas Plant
Wholesale Propane Terminal
Fractionator and/or Plant
Treater Facility
Natural Gas Pipeline
Shale
DCP Midstream
Storage Facility
As of 12/31/2013
Plant Under Construction
NGL Pipeline
Pipeline Under Construction
COMPANY OVERVIEW
The Partnership is managed by its general
partner, DCP Midstream GP, LP, which in turn is
managed by its general partner, DCP Midstream
GP, LLC. DCP Midstream GP, LLC is 100 percent
owned by DCP Midstream, LLC (DCP Midstream),
a joint venture between its owners Phillips 66 and
Spectra Energy Corp. DCP Midstream and DCP
50% Owned
50% Owned
22.1% Limited Partner Interest
0.4% General Partner Interest
PUBLIC
77.5% Limited
Partner Interest
Midstream Partners are collectively referred to as
As of December 31, 2013
the “DCP enterprise.” The DCP enterprise is one
of the nation’s largest natural gas gatherers and
processors, and the largest producer of natural gas liquids in the U.S. Phillips 66
(NYSE: PSX) is one of the largest independent downstream energy companies
with refining, marketing, midstream and chemicals businesses operating across
the globe. Spectra Energy Corp (NYSE: SE) is one of North America’s premier
natural gas infrastructure companies connecting natural gas supply sources to
premium markets in the United States and Canada. Collectively, we call these
entities our “sponsors” and our affiliation with them provides us with significant
business opportunities. Through the ownership of our general partner and
22.1 percent of our limited partner units, our sponsors are invested in, and
committed to, the success of the Partnership.
TO OUR UNITHOLDERS
Wouter T. van Kempen
Chairman and CEO
DCP Midstream Partners
From Our Chairman and CEO
The Partnership had an exceptional year in 2013 enjoying record results and executing on
a strong growth program. The Partnership enjoys the strong support of its general partner,
DCP Midstream. One strategy guides both companies —our “growth for growth” strategy which
I’ll describe more in a moment. In October, we paid tribute to a leader whose vision guided
this strategy by naming the Partnership’s first Colorado natural gas processing plant after
our former CEO and chairman, Tom O’Connor. We could think of no more fitting honor to
acknowledge his contributions to the enterprise.
In 2013, we checked off a very important box on our visionary list—becoming a fully
integrated midstream service provider. And that’s at both the Partnership and at
DCP Midstream.
As we talk with investors, we’ve been devoting more time to explaining the synergistic
relationship between the Partnership and DCP Midstream. It’s a powerful interplay that
is creating a long list of growth projects resulting in long-term sustainable distribution growth.
We call this strategy “growth for growth.” In its simplest terms, the Partnership is the
funding vehicle for growing the overall DCP enterprise, which in turn, grows the Partnership
through dropdown transactions. For the second straight year, the Partnership has received
over $1 billion in dropdowns from DCP Midstream, and over the course of the next three
years, we see the opportunity for an additional $3 to $5 billion of dropdowns. On top of this,
the Partnership is at the size and scale to grow organically, and already we have put in service
several new organic projects.
It’s this strategy that has doubled the size of the Partnership in three years, and
In 2013, we checked
off a very important
box on our visionary
list—becoming a
fully integrated
midstream provider.
we are well on our way to double it again.
Already in 2014, we are fast out of the gates, having announced a $1.15 billion
dropdown transaction, which grows further our NGL Logistics segment, takes
the Eagle Ford system ownership to 100 percent, builds our presence in the
rapidly expanding liquids-rich Permian, and grows our footprint in the prolific
Denver-Julesburg basin.
We are confident in our ability to identify a clear line of sight to new projects
within the DCP enterprise. And what’s more, we have one of the most enviable
footprints in key liquids-rich basins, supported by strong customer relationships.
And at the heart of our business is a complement of 3,200 employees who
manage and operate our business always with an eye to integrity and safety. They proudly
serve this country’s energy needs, executing on our growth projects while balancing safe and
reliable operations. We pride ourselves on being a premier operator with an industry leading
safety record. All said, we believe the Partnership makes for a very compelling investment
opportunity, providing long-term sustainable distribution growth to our unitholders.
Thank you for your support!
Wouter T. van Kempen
Chairman of the Board and Chief Executive Officer
2
DCP MIDSTREAM PARTNERS
From Our President
We know that it’s essential to our investors to deliver on our promises. With that
expectation, we are very proud of what we accomplished in 2013 that resulted in continued
distribution growth.
We often discuss how we balance our capital investment, distribution growth, and strong
financial metrics. It’s a balance we thoughtfully manage—all with the intent of providing
sustainable, consistent value to our unitholders. In 2013,
you saw that with our 13th consecutive quarterly distribution
increase. To put this in perspective, our unitholders have
enjoyed total shareholder returns of about 60 percent
including a 17 percent increase in distributions over the
last three years.
The O’Connor Plant in the
prolific DJ basin.
That’s the strength of the DCP enterprise. We’re able to drive
unitholder value by using both companies’ best attributes.
Since 2012, we’ve received $2.1 billion of dropdowns and
executed on about $860 million of organic growth projects at
the Partnership.
In 2013 and early into 2014, we brought into service
numerous projects including our Eagle and Goliad plants in the Eagle Ford, our O’Connor
plant in the Denver-Julesburg basin, our interest in the Texas Express and Front Range
pipelines, and started up our O’Connor expansion and Marysville, Michigan ethane project.
We’re proud of our financial strength, and particularly our strong investment grade ratings,
which is a differentiator compared with many other master limited partnerships. We also
minimize our earnings volatility through a diversified business model that is 95 percent
fee-based or hedged.
In this report, we look forward to sharing our progress in our three business segments and
profiling some of our people who contribute to our achievements.
Thank you for your continued interest in the Partnership. We are already executing on our
2014 plan that will deliver the results we promised to you, our investors.
William S. Waldheim
President and Director
DCP Midstream Partners
William S. Waldheim
President and Director
Quarterly Distributions Since IPO
.
9
5
0
$
.
7
5
0
$
.
5
5
0
$
.
3
5
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
0
6
0
$
.
1
6
0
$
.
1
6
0
$
5
6
4
0
$
.
5
0
4
0
$
.
.
3
4
0
$
.
8
3
0
$
.
5
3
0
$
5
7
1
6
0
$
.
0
5
2
6
0
$
.
5
2
3
6
0
$
.
.
4
6
0
$
.
5
6
0
$
.
6
6
0
$
.
7
6
0
$
.
8
6
0
$
.
9
6
0
$
.
0
7
0
$
5
2
3
7
0
$
.
.
1
7
0
$
.
2
7
0
$
1Q 2Q 3Q 4Q
2006
1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q
2007
2008
2009
2010
2011
2012
1Q 2Q 3Q 4Q
2013
2013 ANNUAL REPORT
3
For the years ended (amounts in millions, except per unit amounts)
Statements of Operations Data
Adjusted EBITDA(1)
Adjusted net income attributable to partners(1)
Adjusted net income per limited partner unit – basic and diluted(1)
Wtd avg limited partners units outstanding – basic
Wtd avg limited partners units outstanding – diluted
As of (amounts in millions)
Balance Sheet Data
Total assets
Long-term debt
Total partners’ equity
Noncontrolling interests
Other Financial Data
(2)
12/31/13
$
$
$
365
217
1.80
78.4
78.4
$ 4,526
$ 1,590
$ 1,945
$
228
(2)
12/31/12
$
$
$
302
177
1.89
54.5
54.5
$ 3,603
$ 1,620
$ 1,405
$
189
(2)
12/31/11
$ 269
$
$
123
1.26
43.5
43.6
$ 2,912
$
747
$ 1,256
$ 306
Cash distributions declared per unit (3)
$ 2.863
$ 2.700
$ 2.548
For the years ended
Operating Statistics
Natural gas throughput (MMcf/d)
NGL gross production (Bbls/d)
NGL pipelines throughput (BBls/d)
Propane sales volume (BBls/d)
2,270
118,578
89,361
19,553
2,322
112,032
78,508
19,111
1,951
85,917
62,555
24,743
(1) Denotes a financial measure not presented in accordance with U.S. generally accepted accounting principles, or GAAP. Each such non-GAAP financial measure is
reconciled to its most directly comparable GAAP financial measure on the inside back cover of this document.
(2) On January 1, 2011, we acquired our initial 33.33% interest in DCP Southeast Texas Holdings, GP (Southeast Texas) from DCP Midstream, LLC, and on March 30, 2012, we
acquired the remaining 66.67% interest. On November 2, 2012, we acquired our initial 33.33% interest in DCP SC Texas GP (Eagle Ford System) from DCP Midstream,
LLC, and on March 28, 2013, we acquired an additional 46.67% interest. Our financial information gives retroactive effect to the 100% interest in Southeast Texas and 80%
interest in the Eagle Ford System as a combination of entities under common control, and have been accounted for similar to a pooling of interests. Earnings for periods
prior to these acquisitions are allocated to predecessor operations to derive adjusted net income per limited partner unit - basic and diluted.
(3) Cash distributions declared per limited partner unit represent cash distributions declared with respect to the four fiscal quarters of each year presented.
Comparative Total Returns 12/01/05 - 12/31/13
$450
$400
$350
$300
$250
$200
$150
$100
$50
$0
2005
DPM
AMZ Total Return Index(1)
S&P 500 Index
DPM 314%
AMZ 221%
S&P 74%
2006
2007
2008
2009
2010
2011
2012
2013
The Partnership has outperformed the MLP sector and S&P 500 indexes on a total return basis since our initial public offering in December 2005.
(1) The Alerian MLP Total Return Index (NYSE: AMZX) is a composite of the 50 most prominent energy master limited partnerships that provides a comprehensive
benchmark for this asset class. The index, which is calculated using a float-adjusted, capitalization-weighted methodology, is disseminated real-time on a
total-return basis.
4
DCP MIDSTREAM PARTNERS
NATURAL GAS GATHERING
AND PROCESSING
LOGISTICS AND MARKETING
Natural Gas
Production
Gathering &
Compression
Processing &
Treatment
Residue Gas
Utilities
Industrial
Residential
Residue Gas & Raw NGL Mix
Gas Transportation
Raw NGL Mix
LOGISTICS AND MARKETING
Marketing
Raw NGL Mix
Transportation
NGL Fractionation
NGL Storage and Distribution
Ethane
Propane
Butanes
Petanes+
Chemical Plants
Refineries
Propane Distributors
As gas is produced at
the wellhead, it is first
gathered and delivered
to a centralized point
for processing. The
gas processing plant
collectively separates
the natural gas liquids
(NGLs) — ethane,
propane, butane, and
other NGLs — from
the gas stream. The
processed gas now
meets long-haul gas
pipeline specifications
and is transported
to end-users. The
separated NGLs are
transported by NGL
pipelines or trucks to
a fractionation facility
where the NGLs are
further separated into
their constituent parts
before transport to
end-use markets.
OUR BUSINESS
The midstream natural gas industry is the link
between the exploration and production of natural
gas, and the delivery of its components to
end-use markets.
We are a must-run sector that gathers, compresses,
treats, processes, transports, stores, and sells natural
gas, as well as produces, fractionates, transports,
stores and sells natural gas liquids and recovers and
sells condensate, and transports, stores and sells
propane in wholesale markets.
Approximately 75 percent of the country’s natural
gas must be processed after it is produced and before
it can enter the marketplace and serve end-users.
Our three business segments are Natural Gas
Services, Natural Gas Liquids (NGL) Logistics, and
Wholesale Propane Logistics.
OUR STRATEGY
Partnering with DCP Midstream to Grow the
DCP Enterprise.
Third Party
Acquisitions
20%
20%
60%
Dropdowns
Growth Since IPO
We employ a multifaceted
strategy of dropdowns,
building, and acquiring
assets to deliver sustainable
distribution growth to our
unitholders. We have a
talented team of operations
and commercial managers,
diligently maximizing the profitability of our existing
assets. Since our initial public offering, we have
invested over $4 billion in growth capital, with the
majority deployed on dropdowns. Our access to capital
markets supports our ability to be a key funding
vehicle for the DCP enterprise growth.
Organic
Projects
2013 ANNUAL REPORT
5
NATURAL GAS SERVICES
Within our largest business
segment, Natural Gas
Services, not only did we
experience growth from
dropdowns and organic
projects in 2013, our assets
are performing as, if not
better than, expected.
Working closely with our customers, we are
positioned to anticipate growth around our footprint
and execute on projects to meet their needs. Then
it’s our equal obligation to operate our assets reliably
and safely.
Since the end of 2012, we have put in service three
new natural gas processing plants. We added the
Eagle Plant, a 200 million cubic feet/day (MMcf/d)
facility as well as the 200 MMcf/d Goliad plant in
early 2014, both in the Eagle Ford basin. We just
announced that we expect to close on a transaction
with DCP Midstream by the end of March to receive
the remaining 20 percent of the Eagle Ford system.
Our position in this
basin is enviable. The
Partnership will now
own 100 percent of the
Eagle Ford system—an
integrated system of
seven plants with a total
of 1.2 Bcf per day of
processing capacity.
We also extended
1.2Bcf
per day of
processing capacity
in Eagle Ford
our footprint into the prolific Denver-Julesburg basin
in Colorado with the dropdown of the 110 MMcf/d
O’Connor plant, and its expansion to 160 MMcf/d
which started up in early 2014. This plant is almost
at capacity. Included in our recent transaction
announcement, we have begun to break ground on our
Lucerne 2 plant in Colorado—another 200 MMcf/d
facility. We will also receive the 35 MMcf/d Lucerne 1
plant from DCP Midstream. With these three plants,
the Partnership will process about half of the
Ghazi Shahin,
vice president of operations,
South and Midcontinent
business units
Operational excellence is
about being the best in
everything we do. We make
sure everybody has the tools
and skills to do their jobs
the best way every day. Our
goal is to develop processes,
systems and measures to
make sure we can repeat
that performance. There
are lots of interactions and
teamwork where people
are connecting the dots to
make sure we are constantly
improving, constantly
performing at our best. You
need to assess even new
plants. You always have
opportunities. As we brought
in Eagle Plant, we learned
quite a bit: things we needed
to pay attention to, things
we needed to enhance to
make it more efficient and
more productive. We use
operational excellence as
a springboard to continue
our growth plan in the Eagle
Ford shale and other areas
in the company. Bottom line,
we strive to have operational
excellence at the heart of
our culture.
Natural Gas Services
Wyoming
System
Piceance
System
O’Connor
Plant
Michigan
System
Southern
Oklahoma
System
East Texas
System
Southeast Texas System
N. Louisiana
System
Eagle Plant
Eagle Ford
System
Discovery
System
W
N
S
E
MAP KEY
Asset Types
Natural Gas Plant
Storage Facility
Natural Gas Pipeline
Fractionator and/or Plant
Plant Under Construction
Pipeline Under Construction
As of 12/31/2013
Treater Facility
DCP enterprise’s 800 MMcf/d volume in this basin. These plants will be connected
to the Front Range Pipeline for NGL takeaway through Texas Express and delivered
to the premier Mt. Belvieu market.
Altogether, since the start of 2012, the Partnership has brought online about
560 MMcf/d of incremental processing capacity through dropdowns and
organic growth.
Looking ahead, we are progressing on our Discovery system’s Keathley Canyon
connector project in the deepwater Gulf of Mexico, which is operated by Williams
Partners and expected to be in service by the end of 2014, and on multiple other
projects throughout our footprint.
2013 ANNUAL REPORT
7
NGL LOGISTICS
Our NGL Logistics segment continues
to show strong growth. Volumes across
all of our pipelines and fractionators
continue to perform well resulting in
strong fee-based earnings.
“
As we look ahead,
our NGL Logistics
segment will
continue to have
significant growth...
”
Marysville NGL Storage Expansion
Stephanie Brunk, project engineer
I started with DCP out of school (B.S., chemical
engineering, 2011). I’m managing the engineering
firm and working with David to get everything
designed and ordered. DCP definitely throws you
into things right away. I think that’s the best way
to get experience. I’ve enjoyed working with David.
He’s got a lot of experience and knowledge. We
divide and conquer and move forward.
David Graham, project manager
It’s been really nice to have Stephanie on this
project. Her background helped her understand
how the cavern works. She took the ball and dealt
with the engineering firm. If we need to coordinate
a feature with the engineering firm, she makes
it happen. I manage budgets, schedules, hiring
contractors, procuring equipment – oversee all
the activities to execute on the project.
We celebrated several significant milestones in 2013
and early 2014, with the Texas Express and Front Range
natural gas liquid pipelines placed into service. The
Partnership holds an interest in both of these pipelines
which are interconnected and ultimately reach the
premier Mt. Belvieu market. These pipelines are
underpinned by ship or pay contracts, which provide
earnings stability.
We also expect to welcome into the Partnership DCP
Midstream’s one-third interest in each of the Sand Hills
and Southern Hills NGL
pipelines, both of which
deliver to Mt. Belvieu.
With the anticipated
ownership of Sand Hills,
the Partnership will now
gain entry into the rapidly
expanding Permian basin.
And with the Southern Hills
pipeline, the Partnership
will enter the Granite
Wash and SCOOP areas
in Oklahoma. We foresee
continued organic expansion with laterals and other
bolt-on projects to these pipelines.
In 2013, we also completed construction of the first
phase of our Marysville, Michigan ethane expansion
project. This asset is well positioned to serve the
producer storage needs resulting from new production
in the Utica shale. It is underpinned by a long-term
ethane storage agreement with Nova Chemical and
we began injecting ethane in December.
As we look ahead, our NGL Logistics segment will
continue to have significant growth as we ramp up
our NGL volumes and execute on the many bolt-on
opportunities to connect additional volumes.
8
DCP MIDSTREAM PARTNERS
NGL Logistics
MI
Marysville
NGL Storage
MAP KEY
Asset Types
Wattenberg
Pipeline
Conway Hub
Front Range
Pipeline
Texas
Express
Pipeline
Seabreeze
Pipeline
Wilbreeze
Pipeline
Mont Belvieu Hub
Black
Lake
Pipeline
W
N
S
E
Fractionator and/or Plant
NGL Pipeline
Storage Facility
Pipeline Under Construction
Delivery Point
As of 12/31/2013
13%
increase in
gross margin
in 2013
2013 ANNUAL REPORT
9
WHOLESALE PROPANE LOGISTICS
The Partnership’s Wholesale Propane business segment is progressing on two
organic projects, which underscore its strong logistics capability.
In 2013, we initiated the first phase of a project to
debottleneck product distribution into and out of our
Chesapeake propane terminal in Virginia. Ultimately,
we are well poised to export butane from this facility,
and have signed a memorandum of understanding
with a third party.
In 2013, our wholesale propane business stepped
up to support the broader industry source propane
for the Northeast, responding to one of the coldest
winters on record. By securing shipments from
Western Europe, the Partnership was able to help
alleviate the supply need.
Wholesale Propane Logistics
Berlin
Albany
NEW YORK
VERMONT
MAINE
Bangor
Auburn
MASS.
Westfield
RHODE
ISLAND
Providence
Midland
OHIO
PENNSYLVANIA
York
VIRGINA
Chesapeake
W
N
S
E
MAP KEY
Asset Types
Wholesale Propane Terminal
As of 12/31/2013
Kevin Grey,
supervisor of operations at
Chesapeake terminal
I spent eight years in the Navy
onboard submarines. The Navy’s
nuclear reactor program is
absolutely the best run, safest
program you can imagine. What
struck me about coming to
work for the DCP Midstream
enterprise was the way we
administer safety is very similar
to the way it’s done in the
Navy’s nuclear program. DCP’s
approach to process safety
management has a lot of the
same hallmarks. It goes way
beyond administrative ideals
to the care in which we do our
job every day and the focus
and the training and these just
incredibly high standards we
hold ourselves to with regard
to safety. At the time I came to
work for DCP, I’d been out of the
Navy for about four years. On
some level, you could say it was
like coming home.
13%
of operating
revenues in 2013
10
DCP MIDSTREAM PARTNERS
CORPORATE OFFICERS
Wouter T. van Kempen
Chairman and CEO
William S. Waldheim
President and Director
Sean P. O’Brien
Group Vice President
and CFO
Michael S. Richards
Vice President, General
Counsel and Secretary
BOARD OF DIRECTORS
Wouter T. van Kempen
Chairman and CEO
Paul F. Ferguson, Jr.
Director
Frank A. McPherson
Director
Thomas C. Morris
Director
Stephen R. Springer
Director
William S. Waldheim
President and Director
R. Mark Fiedorek
Director
Alan N. Harris
Director
Andy Viens
Director
Brian R. Wenzel
Director
Reconciliation of non-GAAP measures
(amounts in millions, except per unit amounts)
Net income attributable to partners
Interest expense, net
Depreciation, amortization and income tax expense,
(cid:3)net of noncontrolling interests
Non-cash commodity derivative mark-to-market
Adjusted EBITDA
Net cash provided by operating activities
Interest expense, net
Distributions from unconsolidated affiliates, net of earnings
Net changes in operating assets and liabilities
Net income attributable to noncontrolling interests,
(cid:3)net of depreciation and income tax
Discontinued construction projects
Non-cash commodity derivative mark-to-market
Other, net
Adjusted EBITDA
Net income attributable to partners
Non-cash derivative mark-to-market
Adjusted net income attributable to partners
Less: Adjusted net income attributable to predecessor operations
Adjusted general partner’s interest in net income
Adjusted net income allocable to limited partners
Adjusted net income per limited partner unit – basic and diluted
(1)
12/31/13
(1)
12/31/12
(1)
12/31/11
$
$
$
$
$
$
$
$
181
52
95
37
365
324
52
(6)
(8)
(23)
(8)
37
(3)
365
181
36
217
(6)
(70)
141
1.80
$
$
$
$
$
$
$
$
198
42
83
(21)
302
82
42
–
219
(20)
–
(21)
–
302
198
(21)
177
(33)
(41)
103
1.89
$
$
$
$
$
$
$
$
163
34
114
(42)
269
387
34
(2)
(83)
(50)
–
(42)
25
269
163
(40)
123
(43)
(25)
55
1.26
(1) On January 1, 2011, we acquired our initial 33.33% interest in DCP Southeast Texas Holdings, GP (Southeast Texas) from DCP Midstream, LLC, and on March 30, 2012,
we acquired the remaining 66.67% interest. On November 2, 2012, we acquired our initial 33.33% interest in DCP SC Texas GP (Eagle Ford System) from DCP Midstream,
LLC, and on March 28, 2013, we acquired an additional 46.67% interest. Our financial information gives retroactive effect to the 100% interest in Southeast Texas and 80%
interest in the Eagle Ford System as a combination of entities under common control, and have been accounted for similar to a pooling of interests. Earnings for periods
prior to these acquisitions are allocated to predecessor operations to derive adjusted net income per limited partner unit - basic and diluted.
12
DCP MIDSTREAM PARTNERS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2013
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number: 001-32678
DCP MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction
of incorporation or organization)
370 17th Street, Suite 2500
Denver, Colorado
(Address of principal executive offices)
03-0567133
(I.R.S. Employer
Identification No.)
80202
(Zip Code)
Registrant’s telephone number, including area code: (303) 633-2900
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:
Name of Each Exchange on Which Registered:
Common Units Representing Limited Partner Interests
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Exchange Act of 1934, or the Act. Yes No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Act during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form
10-K.
Large accelerated filer
Non-accelerated filer
Accelerated filer
Smaller reporting company
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2013, was approximately $3,156,209,000. The aggregate
market value was computed by reference to the last sale price of the registrant’s common units on the New York Stock Exchange on June 28, 2013.
As of February 20, 2014, there were outstanding 89,045,139 common units representing limited partner interests.
DOCUMENTS INCORPORATED BY REFERENCE:
None.
DCP MIDSTREAM PARTNERS, LP
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2013
TABLE OF CONTENTS
Page
1
22
46
46
46
47
47
48
51
85
91
156
156
158
158
164
176
178
183
183
189
190
Item
1.
1A.
Business
Risk Factors
1B.
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
2.
3.
4.
5.
6.
7.
PART I
PART II
Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
7A.
Quantitative and Qualitative Disclosures about Market Risk
8.
9.
9A.
9B.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
10.
11.
Directors, Executive Officers and Corporate Governance
Executive Compensation
PART III
12.
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
13.
Certain Relationships and Related Transactions, and Director Independence
14.
Principal Accountant Fees and Services
15.
Exhibits and Financial Statement Schedules
PART IV
Signatures
Exhibit Index
i
The following is a list of certain industry terms used throughout this report:
GLOSSARY OF TERMS
Bbl
Bbls/d
Bcf
Bcf/d
Btu
Fractionation
MBbls
MBbls/d
MMBtu
MMBtu/d
MMcf
MMcf/d
NGLs
Throughput
barrel
barrels per day
billion cubic feet
billion cubic feet per day
British thermal unit, a measurement of energy
the process by which natural gas liquids are separated
into individual components
thousand barrels
thousand barrels per day
million Btus
million Btus per day
million cubic feet
million cubic feet per day
natural gas liquids
the volume of product transported or passing through a
pipeline or other facility
ii
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Our reports, filings and other public announcements may from time to time contain statements that do not directly or
exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities
Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as
“may,” “could,” “should,” “intend,” “assume,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,”
“forecast” and other similar words.
All statements that are not statements of historical facts, including statements regarding our future financial position, business
strategy, budgets, projected costs and plans and objectives of management for future operations, are forward-looking statements.
These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and
are subject to risks, uncertainties and other factors, many of which are outside our control. Important factors that could cause actual
results to differ materially from the expectations expressed or implied in the forward-looking statements include known and
unknown risks. Known risks and uncertainties include, but are not limited to, the risks set forth in “Item 1A. Risk Factors” in this
Annual Report on Form 10-K, including the following risks and uncertainties:
•
•
•
•
•
•
•
•
•
•
the extent of changes in commodity prices and the demand for our products and services, our ability to effectively limit a
portion of the adverse impact of potential changes in prices through derivative financial instruments, and the potential
impact of price and producers’ access to capital on natural gas drilling, demand for our services, and the volume of NGLs
and condensate extracted;
general economic, market and business conditions;
our ability to hire as well as retain qualified personnel to execute our business strategy;
volatility in the price of our common units;
the level and success of natural gas drilling around our assets, the level and quality of gas production volumes around our
assets and our ability to connect supplies to our gathering and processing systems in light of competition;
our ability to grow through contributions from affiliates, acquisitions, or organic growth projects, and the successful
integration and future performance of such assets;
our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market
conditions, our financial and operating results, inflation rates, interest rates, our ability to comply with the covenants in our
loan agreements and our debt securities, as well as our ability to maintain our credit ratings;
the demand for NGL products by the petrochemical, refining or other industries;
our ability to purchase propane from our suppliers and make associated profitable sales transactions for our wholesale
propane logistics business;
our ability to construct facilities on budget and in a timely fashion, which is partially dependent on obtaining required
construction, environmental and other permits issued by federal, state and municipal governments, or agencies thereof, the
availability of specialized contractors and laborers, and the price of and demand for materials;
the creditworthiness of counterparties to our transactions;
•
• weather, weather related conditions and other natural phenomena, including their potential impact on demand for the
commodities we sell and the operation of company-owned and third party-owned infrastructure;
security threats such as military campaigns, terrorist attacks, and cybersecurity breaches, against, or otherwise impacting,
our facilities and systems;
new, additions to and changes in laws and regulations, particularly with regard to taxes, safety and protection of the
environment, including climate change legislation, regulation of over-the-counter derivatives market and entities, and
hydraulic fracturing regulations, or the increased regulation of our industry, and their impact on producers and customers
served by our systems;
our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our
losses;
the amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate,
transport and store, may be reduced if the pipelines and storage and fractionation facilities to which we deliver the natural
gas or NGLs are capacity constrained and cannot, or will not, accept the gas or NGLs;
industry changes, including the impact of consolidations, alternative energy sources, technological advances and changes in
competition;
the amount of collateral we may be required to post from time to time in our transactions; and
our ability to execute our asset integrity and safety programs to continue the safe and reliable operation of our assets.
•
•
•
•
•
•
•
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur
or might occur to a different extent or at a different time than we have described. The forward-looking statements in this report
speak as of the filing date of this report. We undertake no obligation to publicly update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise.
iii
Item 1. Business
OUR PARTNERSHIP
PART I
DCP Midstream Partners, LP (along with its consolidated subsidiaries, “we,” “us,” “our,” or the “partnership”) is a
Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of
complementary midstream energy assets. We are currently engaged in the business of gathering, compressing, treating,
processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs and
recovering and selling condensate; and transporting, storing and selling propane in wholesale markets. Supported by our
relationship with DCP Midstream, LLC and its owners, Phillips 66 and Spectra Energy Corp and its affiliates, or Spectra
Energy, we are dedicated to executing our growth strategy by acquiring and constructing additional assets.
Our operations are organized into three business segments: Natural Gas Services, NGL Logistics and Wholesale Propane
Logistics. A map representing the geographic location and type of our assets for all segments is set forth below. Additional
maps detailing the individual assets can be found on our website at www.dcppartners.com. Our website and the information
contained on that site, or connected to that site, are not incorporated by reference into this report. For more information on our
segments, see the “Our Operating Segments” discussion below.
1
NOTE: Map includes assets to be contributed by or acquired from DCP Midstream, LLC pursuant to the February 25, 2014 transaction
documents described in Recent Events in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
and Note 22 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data".
OVERVIEW AND STRATEGIES
Our Business Strategies
Our primary business objectives are to have sustained company profitability, a strong balance sheet and profitable growth
thereby increasing our cash distribution per unit over time. We intend to accomplish these objectives by executing the following
business strategies:
2
Dropdown: maximize opportunities provided by our partnership with DCP Midstream, LLC. We plan to execute our
growth in part through pursuing economically attractive dropdown opportunities from DCP Midstream, LLC. We believe
there will continue to be significant opportunities as DCP Midstream, LLC continues to build its infrastructure. However,
we cannot say with any certainty that these opportunities will be made available to us, or that we will choose to pursue
any such opportunity.
Build: capitalize on organic expansion opportunities. We continually evaluate economically attractive organic
expansion opportunities to construct midstream systems in new or existing operating areas. For example, we believe there
are opportunities to expand several of our gas gathering systems to attach increased volumes of natural gas produced in
the areas of our operations or to build new processing capacity. We also believe there are opportunities to continue to
expand our NGL Logistics and Wholesale Propane Logistics businesses.
Acquire: pursue strategic third party acquisitions. We pursue economically attractive and strategic third party
acquisition opportunities within the midstream energy industry, both in new and existing lines of business, and geographic
areas of operation.
Our Competitive Strengths
We believe that we are well positioned to execute our business strategies and achieve one of our primary business
objectives of increasing our cash distribution per unit because of the following competitive strengths:
Affiliation with DCP Midstream, LLC and its owners. Our relationship with DCP Midstream, LLC and its owners,
Phillips 66 and Spectra Energy, should continue to provide us with significant business opportunities. DCP Midstream,
LLC is the largest processor of natural gas, the largest producer of NGLs and the third-largest NGL pipeline operator in
the United States. This relationship also provides us with access to a significant pool of management talent. We believe
our strong relationships throughout the energy industry, including with major producers of natural gas and NGLs in the
United States, will help facilitate the implementation of our strategies. Additionally, we believe DCP Midstream, LLC,
which operates most of our assets on our behalf, has established a reputation in the midstream business as a reliable and
cost-effective supplier of services to our customers, and has a track record of safe, efficient and environmentally
responsible operation of our facilities.
We believe we are an important growth vehicle and a key source of funding for DCP Midstream, LLC to pursue the
organic construction, expansion and acquisition of midstream natural gas, NGL, wholesale propane and other
complementary midstream energy businesses and assets. DCP Midstream, LLC has also provided us with growth
opportunities through acquisitions directly from it and joint ventures with it. We believe we will have future opportunities
to make additional acquisitions with or directly from DCP Midstream, LLC as well as form joint ventures with it;
however, we cannot say with any certainty which, if any, of these opportunities may be made available to us, or if we will
choose to pursue any such opportunity. In addition, through our relationship with DCP Midstream, LLC and its owners,
we believe we have strong commercial relationships throughout the energy industry and access to DCP Midstream, LLC’s
broad operational, commercial, technical, risk management and administrative infrastructure.
DCP Midstream, LLC has a significant interest in us through its approximately 1% general partner interest in us, its
ownership of our incentive distribution rights and an approximately 22% limited partner interest in us.
Strategically located assets. Each of our business segments has assets that are strategically located in areas with the
potential for increasing each of our business segments’ volume throughput and cash flow generation. Our Natural Gas
Services segment has a strategic presence in several active natural gas producing areas including Colorado, the Gulf of
Mexico, Louisiana, Michigan, Oklahoma, Texas, and Wyoming. These systems provide a variety of services to our
customers including gathering, compressing, treating, processing, transporting and storing natural gas, and fractionating
NGLs. The strategic location of our assets, coupled with their geographic diversity, presents us with continuing
opportunities to provide competitive natural gas services to our customers and attract new natural gas production. Our
NGL Logistics segment has strategically located NGL transportation pipelines in Colorado, Kansas, Louisiana, and Texas
which are major NGL producing regions, NGL fractionation facilities in Colorado and the Gulf Coast and an NGL storage
facility in Michigan. Our NGL pipelines connect to various natural gas processing plants and transport the NGLs to large
fractionation facilities, a petrochemical plant, a third party underground NGL storage facility and other markets along the
Gulf Coast. Our NGL storage facility in Michigan is strategically adjacent to the Sarnia, Canada refinery and
petrochemical corridor. Our Wholesale Propane Logistics Segment has terminals in the mid-Atlantic, northeastern and
upper midwestern states that are strategically located to receive and deliver propane to some of the largest demand areas
for propane in the United States.
3
Stable cash flows. Our operations consist of a favorable mix of fee-based and commodity-based services, which
together with our commodity hedging program, generate relatively stable cash flows. While certain of our gathering and
processing contracts subject us to commodity price risk, we have mitigated a significant portion of our currently
anticipated natural gas, NGL and condensate commodity price risk associated with the equity volumes from our gathering
and processing operations through 2017 with fixed price commodity swaps.
Integrated package of midstream services. We provide an integrated package of services to natural gas producers,
including gathering, compressing, treating, processing, transporting, storing and selling natural gas, as well as producing,
fractionating, transporting, storing and selling NGLs and recovering and selling condensate. We believe our ability to
provide all of these services gives us an advantage in competing for new supplies of natural gas because we can provide
substantially all services that producers, marketers and others require to move natural gas and NGLs from wellhead to
market on a cost-effective basis.
Comprehensive propane logistics systems. We have multiple propane supply sources and terminal locations to
transport, store and sell propane in wholesale markets. We believe our diversity of supply sources and logistics
capabilities along with our propane storage assets and services allow us to provide our customers with reliable supplies of
propane during periods of tight supply. These capabilities also allow us to moderate the effects of commodity price
volatility and reduce significant fluctuations in our sales volumes.
Experienced management team. Our senior management team and board of directors include some of the most senior
officers of DCP Midstream, LLC and other energy companies who have extensive experience in the midstream industry.
We believe our management team has a proven track record of enhancing value through dropdowns, organic growth and
the acquisition, optimization and integration of midstream assets.
Midstream Natural Gas Industry Overview (Natural Gas Services and NGL Logistics)
General
The midstream natural gas industry is the link between exploration and production of natural gas and the delivery of its
components to end-use markets, and consists of the gathering, compressing, treating, processing, transporting, storing and
selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs.
Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use
markets. The following diagram illustrates the natural gas gathering, processing, fractionation, storage and transportation
process, which ultimately results in natural gas and its components being delivered to end-users.
4
Natural Gas Gathering
The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once the well is
completed, the well is connected to a gathering system. Onshore gathering systems generally consist of a network of small
diameter pipelines that collect natural gas from points near producing wells and transport it to larger pipelines for further
transmission.
Natural Gas Compression
Gathering systems are generally operated at design pressures that will maximize the total throughput from all connected
wells. Since wells produce at progressively lower field pressures as they deplete, it becomes increasingly difficult to deliver the
remaining lower pressure production from the well against the prevailing gathering system pressures. Natural gas compression
is a mechanical process in which a volume of wellhead gas is compressed to a desired higher pressure, allowing gas to flow into
a higher pressure downstream pipeline to be brought to market. Field compression is typically used to lower the pressure of a
gathering system or to provide sufficient pressure to deliver gas into a higher pressure downstream pipeline. If field
compression is not installed, then the remaining natural gas in the ground will not be produced because it cannot overcome the
higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production
that otherwise would not be produced.
Natural Gas Processing
The principal component of natural gas is methane, but most natural gas produced at the wellhead also contains varying
amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs have economic value and
are utilized as a feedstock in the petrochemical and oil refining industries or directly as heating, engine or industrial fuels.
Long-haul natural gas pipelines have residue natural gas specifications as to the maximum NGL content of the gas to be
shipped. In order to meet quality standards for long-haul pipeline transportation, natural gas collected at the wellhead through a
gathering system may need to be processed to separate hydrocarbon liquids from the natural gas that may have higher values as
NGLs. NGLs are typically recovered by cooling the natural gas until the NGLs become separated through condensation.
Cryogenic recovery methods are processes where this is accomplished at temperatures lower than negative 150°F. These
methods provide higher NGL recovery yields.
In addition to NGLs, natural gas collected at the wellhead through a gathering system may also contain impurities, such as
water, sulfur compounds, nitrogen or helium, which must also be removed to meet the quality standards for long-haul pipeline
5
transportation. As a result, gathering systems and natural gas processing plants will typically provide ancillary services prior to
processing such as dehydration, treating to remove impurities and condensate separation. Dehydration removes water from the
natural gas stream, which can form ice when combined with natural gas and cause corrosion when combined with carbon
dioxide or hydrogen sulfide. Natural gas with a carbon dioxide or hydrogen sulfide content higher than permitted by pipeline
quality standards requires treatment with chemicals called amines at a separate treatment plant prior to processing. Condensate
separation involves the removal of liquefied hydrocarbons from the natural gas stream. Once the condensate has been removed,
it may be stabilized for transportation away from the processing plant via truck, rail, or pipeline.
Natural Gas and NGL Transportation and Storage
After gas collected through a gathering system is processed to meet quality standards required for transportation and
NGLs have been extracted from natural gas, the residue natural gas is shipped on long-haul pipelines or injected into storage
facilities. The NGLs are typically transported via NGL pipelines or trucks to a fractionator for separation of the NGLs into their
individual components. Natural gas and NGLs may be held in storage facilities to meet future seasonal and customer demands.
Storage facilities can include marine, pipeline and rail terminals, and underground facilities consisting of salt caverns and
aquifers used for storage of natural gas and various liquefied petroleum gas products including propane, mixed butane, and
normal butane. Rail, truck and pipeline connections provide varying ways of transporting natural gas and NGLs to and from
storage facilities.
Wholesale Propane Logistics Overview
General
Wholesale propane logistics covers the receipt of propane from processing plants, fractionation facilities and crude oil
refineries, the transportation of that propane by pipeline, rail or ship to terminals and storage facilities, the storage of propane
and the delivery of propane to distributors.
Production of Propane
Propane is extracted from the natural gas stream at processing plants, separated from NGLs at fractionation facilities or
separated from crude oil during the refining process. Most of the propane that is consumed in the United States is produced at
processing plants, fractionation facilities and refineries located in the United States or in foreign locations, particularly Canada,
the North Sea, East Africa and the Middle East. There are a number of processing plants, fractionation facilities and
corresponding propane production in the northeastern United States.
Propane Demand
Propane demand is typically highest in suburban and rural areas where natural gas is not readily available, such as the
northeastern United States. Propane is supplied by wholesalers to retailers to be sold to residential and commercial consumers
primarily for heating and industrial applications. Propane demand is typically highest in the winter heating season months of
October through April.
Transportation and Storage
Due to the nature of the regions’ propane production and relatively high demand, the mid-Atlantic and northeastern
United States are importers of propane. These areas rely on pipeline, marine and rail sources for incoming supplies from both
domestic and foreign locations. Independent terminal operators and wholesale distributors, own, lease or have access to
propane storage facilities that receive supplies via pipeline, rail or ship. Generally, inventories in the propane storage facilities
increase during the spring and summer months for delivery to customers during the fall and winter heating season when
demand is typically at its peak.
Delivery
Often, upon receipt of propane at pipeline, rail and marine terminals, product is delivered to customer trucks or is stored
in tanks located at the terminals or in off-site bulk storage facilities for future delivery to customers. Most terminals and storage
facilities have a tanker truck loading facility commonly referred to as a “rack.” Typically independent retailers will rely on
independent trucking companies to pick up propane at the propane wholesaler's rack and transport it to the retailer at its
location.
6
OUR OPERATING SEGMENTS
Natural Gas Services Segment
NOTE: Map includes assets to be contributed by or acquired from DCP Midstream, LLC pursuant to the February 25, 2014 transaction
documents described in Recent Events in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”
and Note 22 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data".
General
Our Natural Gas Services segment consists of a geographically diverse complement of assets and ownership interests that
provide a varied array of wellhead to market services for our producer customers. These services include gathering,
compressing, treating, processing, transporting and storing natural gas, and fractionating NGLs. These assets are positioned in
certain areas with active drilling programs and opportunities for organic growth. Our Natural Gas Services segment operates in
seven states in the continental United States: Arkansas, Colorado, Louisiana, Michigan, Oklahoma, Texas and Wyoming. The
assets in these states include our 80% interest in the Eagle Ford system (of which an additional 46.67% was acquired in March
2013), our 100% owned Eagle plant, our East Texas system, our Southeast Texas system, our Michigan system, our Northern
Louisiana system, our Southern Oklahoma system, our Wyoming system, our 75% operating interest in the Piceance system,
our 40% limited liability company interest in the Discovery system located off and onshore in Southern Louisiana and our
O'Connor plant (acquired in August 2013). This geographic diversity helps to mitigate our natural gas supply risk in that we are
not tied to one natural gas resource type or producing area. We believe our current geographic mix of assets will be an
important factor for maintaining overall volumes and cash flow for this segment.
7
During 2013, the volume throughput on our assets was in excess of 2.2 Bcf/d, originating from a diversified mix of
customers. Our systems each have significant customer acreage dedications that will continue to provide opportunities for
growth as those customers execute their drilling plans over time. Our gathering systems also attract new natural gas volumes
through numerous smaller acreage dedications and also by contracting with undedicated producers who are operating in or
around our gathering footprint. During 2013, the combined NGL production from our processing facilities was in excess of
118,000 Bbls/d and was delivered and sold into various NGL takeaway pipelines or transported by truck.
Our natural gas gathering systems have the ability to deliver gas into numerous downstream transportation pipelines and
markets. Many of our outlets transport gas to premium markets in the eastern United States, further enhancing the
competitiveness of our commercial efforts in and around our natural gas gathering systems.
Gathering and Transmission Systems, Plants, Fractionators and Storage Facilities
The following is operating data for our systems:
Approximate
Gas
Gathering
and
Transmission
Systems
(Miles)
6,000
—
675
900
440
40
1,455
300
225
1,400
—
11,435
2013 Operating Data
Approximate
Net
Nameplate
Plant
Capacity
(MMcf/d) (a)
610
200
400
860
420
150
160
240
Fractionators
3
—
—
1
—
—
—
1
—
—
—
5
—
—
110
3,150
Plants
5(b)
1(b)
3(b)
3(b)(e)
3(c)(f)
1(c)
2(b)
1(b)
—
—
1(b)
20
Approximate
Natural Gas
Storage
Capacity
(Bcf)
Natural
Gas
Throughput
(MMcf/d)
(a)
—
—
14
—
—
—
1(d)
—
—
—
—
15
582
125
200
660
281
47
166
132
17
40
20
2,270
NGL
Production
(Bbls/d) (a)
41,611
12,065
11,524
33,962
—
1,529
3,960
5,690
1,953
3,796
2,488
118,578
System
Eagle Ford
Eagle plant
Southeast Texas
East Texas
Michigan
Piceance
N. Louisiana
Discovery (d)
Southern
Oklahoma
Wyoming
O'Connor plant
Total
_______________
(a) Represents total capacity or total volumes allocated to our proportionate ownership share for 2013 divided by 365
days. In 2013, we had an 80% interest in our Eagle Ford system, a 75% interest in our Piceance system and a 40%
limited liability company interest in Discovery.
(b) Represents NGL extraction plants.
(c) Represents treating plants.
(d) Represents an asset operated by a third party.
(e) Our East Texas system is comprised of one gas processing complex containing four plants, as well as the
Crossroads and George Gray processing plants.
(f) Excludes our idled East Caledonia plant.
In November 2012 and March 2013, we acquired a 33.33% and 46.67% interest, respectively, in DCP SC Texas GP, or the
Eagle Ford system, from DCP Midstream, LLC. The Eagle Ford system is a fully integrated midstream business which includes
6,000 miles of gathering systems, production from 900,000 acres supported by acreage dedications or throughput commitments
under long-term predominantly percent-of-proceeds agreements, five cryogenic natural gas processing plants totaling 760
MMcf/d of processing capacity, and three fractionation locations with total capacity of 36 MBbls/d. In February 2014, we
entered into an agreement with DCP Midstream, LLC for the contribution of the remaining 20% interest in DCP SC Texas GP.
This transaction is expected to close in March 2014, subject to customary closing conditions.
The Eagle Ford system recently completed an additional cryogenic plant with 200 MMcf/d of processing capacity in Goliad
County, Texas. The Goliad plant was placed into service in February 2014 and further expands the Eagle Ford system.
Our 100% owned Eagle natural gas processing plant, in Jackson County in the Eagle Ford area, commenced operations in
the first quarter of 2013.
8
Our Southeast Texas system is a fully integrated midstream business which includes natural gas pipelines, three natural
gas processing plants in Liberty and Jefferson Counties, of which two are temporarily idled, and natural gas storage assets in
Beaumont.
Our East Texas system includes one gas processing complex containing four natural gas processing plants, as well as the
George Gray and the Crossroads processing plants. Our East Texas system gathers, transports, compresses, treats and processes
natural gas and NGLs. Our East Texas facility may also fractionate NGLs, which can be marketed at nearby petrochemical
facilities. Our East Texas system, located near Carthage, Texas, includes a natural gas processing complex that is connected to
its gathering system, as well as third party gathering systems.
Our Michigan system consists of three natural gas treating plants, a gas gathering system and various residue pipeline
interests.
Our Piceance system is comprised of a 75% operating interest in Collbran Valley Gas Gathering, LLC, or Collbran, and
consists of assets in the southern Piceance Basin that gather natural gas at high pressure from over 20,000 dedicated and
producing acres in western Colorado. The remaining 25% interest in the joint venture is held by Occidental Petroleum
Corporation who is the primary producer on the system.
Our Northern Louisiana system includes our Minden and Ada systems, which gather natural gas from producers and
deliver it for processing to the processing plants. It also includes our Pelico system, which stores natural gas and transports it to
markets. Through our Northern Louisiana system, we offer producers and customers wellhead-to-market services. Our
Northern Louisiana system has numerous market outlets for the natural gas we gather, including several intrastate and interstate
pipelines, major industrial end-users and major power plants. The system is strategically located to facilitate the transportation
of natural gas from Texas and northern Louisiana to pipeline connections linking to markets in the eastern areas of the United
States.
We have a 40% limited liability company interest in Discovery Producer Services LLC, or Discovery, with the remaining
60% owned by Williams Partners L.P. The Discovery system is operated by Williams Partners L.P. and offers a full range of
wellhead-to-market services to both onshore and offshore natural gas producers. The assets are primarily located in the eastern
Gulf of Mexico and Lafourche Parish, Louisiana. We, along with Williams Partners L.P., are expanding the Discovery natural
gas gathering pipeline system in the deepwater Gulf of Mexico. Discovery is constructing the Keathley Canyon Connector, a
20-inch diameter, 215-mile subsea natural gas gathering pipeline for production from the Keathley Canyon, Walker Ridge and
Green Canyon areas in the central deepwater Gulf of Mexico. The Keathley Canyon Connector is expected to be completed in
the fourth quarter of 2014.
Our Southern Oklahoma system is located in the Golden Trend area of McClain, Garvin and Grady counties in southern
Oklahoma. The system is adjacent to assets owned by DCP Midstream, LLC. Natural gas gathered by the system is delivered to
DCP Midstream, LLC processing plants.
Our Wyoming system consists of natural gas gathering pipelines that cover more than 4,000 square miles in the Powder
River Basin in Wyoming. The system gathers primarily rich casing-head gas from oil wells at low pressure and delivers the gas
to a third party for processing under a fee-based agreement.
In August 2013, we acquired DCP LaSalle Plant LLC which owns the O'Connor plant, a gas processing plant in the DJ
Basin in Weld County, Colorado. The O'Connor plant commenced operations in the fourth quarter of 2013 and its expansion to
160 MMcf/d is mechanically complete as of February 2014. Prior to the start of commercial operations, the O'Connor plant was
known as the LaSalle plant.
Natural Gas and NGL Markets
The Eagle Ford system has natural gas residue outlets including interstate and intrastate pipelines. The system delivers NGLs
to the Gulf Coast petrochemical markets and to Mont Belvieu through the Sand Hills pipeline, owned approximately one-third
each by DCP Midstream, LLC, Phillips 66 and Spectra Energy Partners, LP, and other third party NGL pipelines. Our 100% owned
Eagle plant has delivery options into the Trunkline and Transco gas pipeline systems. In February 2014, we entered into an
agreement with DCP Midstream, LLC for the contribution of its one-third interest in the Sand Hills pipeline. This transaction is
expected to close in March 2014, subject to customary closing conditions.
The Southeast Texas system has numerous local natural gas market outlets and delivers residue gas into various interstate
and intrastate pipelines. The Southeast Texas system also makes NGL market deliveries directly to Exxon Mobil.
The East Texas system delivers gas primarily through its Carthage Hub which delivers residue gas to multiple interstate
and intrastate pipelines. Certain of the lighter NGLs, consisting of ethane and propane, are fractionated at the East Texas facility
9
and sold to regional petrochemical purchasers. The remaining NGLs, including butanes and natural gasoline, are purchased by
DCP Midstream, LLC and shipped to Mont Belvieu for fractionation and sale.
The Michigan system delivers Antrim Shale gas to our four treating plants and the gas is then transported to a third party
power plant with connections to several intrastate pipelines.
The Piceance system gathers, compresses and delivers unprocessed gas to a third party natural gas processing plant.
The Northern Louisiana system has numerous market outlets for the natural gas that we gather on the system. In addition,
our natural gas pipelines in northern Louisiana have access to gas that flows through numerous pipelines, are connected to
major industrial end-users and makes deliveries to various power plants. The NGLs extracted from the natural gas at the
Minden processing plant are delivered to our Black Lake NGL pipeline, in our NGL Logistics segment, through our Minden
NGL pipeline. The Black Lake NGL pipeline delivers NGLs to Mont Belvieu and other NGL markets.
The Discovery assets have access to downstream pipelines and markets. The NGLs are fractionated, then delivered
downstream to third-party purchasers consisting of a mix of local petrochemical facilities and wholesale distribution companies
as well as pipelines that transport product to the storage and distribution center near Napoleonville, Louisiana or other similar
product hubs.
The Southern Oklahoma system has access to a mix of mid-continent pipelines and markets through DCP Midstream,
LLC owned processing plants.
The Wyoming system delivers unprocessed gas to a third party natural gas processing plant. Residue gas and NGLs are
delivered to third party and affiliate pipelines.
The O'Connor plant delivers to the Conway hub in Bushton, Kansas via our Wattenberg pipeline and to the Mont Belvieu
hub in Mont Belvieu, Texas via our Front Range and Texas Express pipelines in our NGL Logistics segment.
Customers and Contracts
The suppliers of natural gas to our Natural Gas Services segment are a broad cross-section of the natural gas producing
community. We actively seek new producing customers of natural gas on all of our systems to increase throughput volume and
to offset natural declines in the production from connected wells. We obtain new natural gas supplies in our operating areas by
contracting for production from new wells, by connecting new wells drilled on dedicated acreage and by obtaining natural gas
that has been directly received or released from other gathering systems.
Our contracts with our producing customers in our Natural Gas Services segment are a mix of commodity sensitive
percent-of-proceeds and percent-of-liquids contracts and non-commodity sensitive fee-based contracts. Our gross margin
generated from percent-of-proceeds contracts is directly related to the price of natural gas, NGLs and condensate and our gross
margin generated from percent-of-liquids contracts is directly related to the price of NGLs and condensate. Additionally, these
contracts may include fee-based components. Generally, the initial term of these purchase agreements is for three to five years
or, in some cases, the life of the lease. The largest percentage of volume at our Southern Oklahoma and Eagle Ford systems are
processed under percent-of-proceeds contracts. The producer contracts at our East Texas and Southeast Texas systems are
primarily percent-of-liquids. The majority of the contracts for our Piceance and Michigan systems, as well as our O'Connor
plant, are fee-based. Our Wyoming system has a combination of percent-of-proceeds and fee-based contracts. Discovery has
percent-of-liquids, fee-based and keep-whole contracts. Our Northern Louisiana system has a combination of percent-of-
proceeds, keep-whole and fee-based contracts.
Our Southeast Texas gas storage facility is primarily managed by us for our own account.
Discovery’s 100% owned subsidiary, Discovery Gas Transmission, owns the mainline and the Federal Energy Regulatory
Commission, or FERC, regulated laterals, which generate revenues through a tariff on file with FERC for several types of
service: traditional firm transportation service with reservation fees; firm transportation service on a commodity basis with
reserve dedication; and interruptible transportation service. In addition, for any of these general services, Discovery Gas
Transmission has the authority to negotiate a specific rate arrangement with an individual shipper and has several of these
arrangements currently in effect.
In conjunction with our acquisition and construction of the O'Connor plant, we entered into a 15-year fee-based
processing agreement with DCP Midstream, LLC which provides us with a fixed demand charge of 75% of the plant's capacity
and a throughput fee on all volumes processed.
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Competition
The natural gas services business is highly competitive in our markets and includes major integrated oil and gas
companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store and/or market
natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods
of high commodity prices for crude oil, natural gas and/or NGLs. Competition is also increased in those geographic areas where
our commercial contracts with our customers are shorter term and therefore must be renegotiated on a more frequent basis.
NGL Logistics Segment
NOTE: Map includes assets to be contributed by or acquired from DCP Midstream, LLC pursuant to the February 25, 2014 transaction documents
described in Recent Events in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 22
of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data".
General
We operate our NGL Logistics business in the states of Colorado, Kansas, Louisiana, Michigan, and Texas.
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Our NGL pipelines transport NGLs from natural gas processing plants to fractionation facilities, a petrochemical plant
and a third party underground NGL storage facility. Our pipelines provide transportation services to customers primarily on a
fee basis. Therefore, the results of operations for this business are generally dependent upon the volume of product transported
and the level of fees charged to customers. The volumes of NGLs transported on our pipelines are dependent on the level of
production of NGLs from processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL
prices, it is less profitable to recover NGLs from natural gas because of the higher value of natural gas compared to the value of
NGLs. As a result, we have experienced periods, and will likely experience periods in the future, when higher relative natural
gas prices reduce the volume of NGLs produced at plants connected to our NGL pipelines.
Our NGL fractionation facilities in the Denver-Julesburg Basin, or DJ Basin, in Colorado, and our partially owned
facilities in Mont Belvieu, Texas, separate NGLs received from processing plants into their individual components. The
fractionation facilities provide services on a fee basis. Therefore, the results of operations for this business are generally
dependent upon the volume of NGLs fractionated and the level of fees charged to customers.
Our NGL storage facility is located in Marysville, Michigan with strategic access to Canadian NGLs. Our facility serves
regional refining and petrochemical demand, and helps to balance the seasonality of propane distribution in the midwestern and
northeastern United States and in Sarnia, Canada. We provide services to customers primarily on a fee basis. Therefore, the
results of operations for this business are generally dependent upon the volume of product injected, stored and withdrawn, and
the level of fees charged to customers.
NGL Pipelines
The following is operating data for our NGL pipelines:
System
Wattenberg
Seabreeze
Wilbreeze
Black Lake
Texas Express
Other
Total
2013 Operating Data
Approximate
System Length
(Miles)
Approximate
Capacity
(MBbls/d) (a)
Pipeline
Throughput
(MBbls/d) (a)
480
56
39
317
583
25
1,500
22
41
11
40
28
10
152
20,570
24,685
24,192
17,096
592
2,226
89,361
_______________
(a) Represents total capacity and throughput allocated to our proportionate ownership share for 2013 divided by 365 days.
The Wattenberg interstate NGL pipeline originates in the DJ Basin in Colorado and terminates near the Conway hub in
Bushton, Kansas. The pipeline is currently connected to DCP Midstream, LLC plants and our O'Connor plant in the DJ Basin.
The Seabreeze intrastate NGL pipeline is located in Matagorda, Jackson and Calhoun Counties, Texas. The Seabreeze
pipeline receives NGLs from the Wilbreeze NGL pipeline and a third party plant and pipeline. The Seabreeze pipeline delivers
the NGLs it receives from these sources to a third party fractionator, its associated storage facility, and a third party pipeline.
The Wilbreeze intrastate NGL pipeline is located in Lavaca and Jackson Counties, Texas. The Wilbreeze pipeline receives
NGLs from the Eagle Ford system, the Sand Hills pipeline, as well as a third party plant, and delivers the NGLs it receives
from these sources to the Seabreeze pipeline and Enterprise’s Eagle pipeline.
The Black Lake interstate NGL pipeline originates in northwestern Louisiana and terminates in Mont Belvieu,
Texas. Black Lake receives NGLs from gas processing plants in northwestern Louisiana and southeastern Texas, including our
Northern Louisiana system and multiple third party plants, the Sand Hills pipeline and a third party storage facility. Black Lake
delivers the NGLs it receives from these sources to fractionation plants in Mont Belvieu, Texas including our partially owned
Enterprise and Mont Belvieu 1 fractionators.
The Texas Express intrastate NGL pipeline, of which we own 10%, originates near Skellytown in Carson County, Texas,
and extends to Enterprise’s natural gas liquids fractionation and storage complex at Mont Belvieu, Texas. The 20-inch diameter
pipeline also provides access to other third party facilities in the area. The Texas Express Pipeline, was completed and
commenced operations in the fourth quarter of 2013. Enterprise is the operator of the pipeline.
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The Front Range interstate NGL pipeline, of which we own 33.33%, is a new raw NGL mix pipeline that originates in the
DJ Basin and extends approximately 435 miles to Skellytown, Texas. The Front Range pipeline connects to the O'Connor plant
as well as third party and DCP Midstream, LLC plants in the DJ Basin. Enterprise is the operator of the pipeline, which was
placed into service in February 2014.
NGL Fractionation Facilities
Our DJ Basin NGL fractionators in Colorado are located on DCP Midstream, LLC’s processing plant sites and are
operated by DCP Midstream, LLC, which delivers NGLs to the fractionators under a long-term fractionation agreement.
Our NGL fractionation facilities in Mont Belvieu, Texas consist of a 12.5% interest in the Enterprise fractionator operated
by Enterprise Products Partners L.P., and a 20% interest in the Mont Belvieu 1 fractionator operated by ONEOK Partners.
NGL Storage Facility
Our NGL storage facility is located in Marysville, Michigan and includes nine underground salt caverns with
approximately 7 MMBbls of storage capacity and rail, truck and pipeline connections providing an important supply point for
refiners, petrochemical plants and wholesale propane distributors in the Sarnia, midwestern and northeastern markets. The
Marysville NGL storage project, once completed, will increase our number of underground salt caverns to ten.
Customers and Contracts
Our contracts with our customers in our NGL Logistics segment are primarily non-commodity sensitive fee-based contracts.
The Wattenberg pipeline is an open access pipeline with access to numerous gas processing facilities in the DJ Basin. The
Wattenberg pipeline is supported by a 10-year dedication and transportation agreement with a subsidiary of DCP Midstream,
LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are dedicated for
transportation on the Wattenberg pipeline. We collect fee-based transportation revenue under our tariff.
The Wilbreeze pipeline is supported by an NGL product dedication agreement with DCP Midstream, LLC.
DCP Midstream, LLC is the sole shipper on the Seabreeze pipeline under a long-term transportation agreement. The
Seabreeze pipeline collects fee-based transportation revenue under this agreement.
DCP Midstream, LLC has historically been the largest active shipper on the Black Lake pipeline, accounting for
approximately 31% of total throughput in 2013. The Black Lake pipeline generates revenue primarily through a FERC-
regulated tariff.
The Texas Express pipeline has long-term, fee-based, ship-or-pay transportation agreements in place with affiliates of
DCP Midstream, LLC and others.
The Front Range pipeline has long-term, fee-based, ship-or-pay transportation agreements in place with affiliates of DCP
Midstream, LLC and others.
DCP Midstream, LLC supplies certain committed NGLs to our DJ Basin NGL fractionators under fee-based agreements
that are effective through March 2018.
Our Marysville NGL storage facility serves retail and wholesale propane customers, as well as refining and petrochemical
customers, under one to three-year term storage agreements. Our revenues for this facility are primarily fee-based.
Competition
The NGL logistics business is highly competitive in our markets and includes interstate and intrastate pipelines, integrated
oil and gas companies that produce, fractionate, transport, store and sell NGLs, and underground storage facilities. Competition
is often the greatest in geographic areas experiencing robust drilling by producers and strong petrochemical demand and during
periods of high NGL prices relative to natural gas. Competition is also increased in those geographic areas where our contracts
with our customers are shorter term and therefore must be renegotiated on a more frequent basis.
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Wholesale Propane Logistics Segment
General
We operate a wholesale propane logistics business in the states of Connecticut, Maine, Massachusetts, New Hampshire,
New York, Ohio, Pennsylvania, Rhode Island, Vermont and Virginia. Our operations serve the large propane markets in the
northeastern, mid-Atlantic, and upper midwestern states.
Due to our multiple propane supply sources, annual and long-term propane supply purchase arrangements, storage
capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our propane
distribution customers with reliable, low cost deliveries and greater volumes of propane during periods of tight supply such as
the winter months. We believe these factors generally result in our maintaining favorable relationships with our customers and
allowing us to remain a supplier to many of the large distributors in the northeastern and mid-Atlantic United States. As a
result, we serve as the baseload provider of propane supply to many of our propane distribution customers.
Pipeline deliveries to the northeastern and mid-Atlantic markets in the winter season are generally at capacity and
competing pipeline-dependent terminals can have supply constraints or outages during peak market conditions. Our system of
terminals has excess capacity, which provides us with opportunities to increase our volumes with minimal additional cost.
Our Terminals
Our operations include one owned and one leased propane marine terminal, one propane pipeline terminal and six owned
propane rail terminals, with a combined capacity of approximately 975 MBbls, and access to several open access pipeline
terminals. We own our rail terminals and lease the land on which the terminals are situated under long-term leases, except for
the York terminal where we own the land. Our leased marine terminal is on a lease agreement through April 2014. Each of our
rail terminals consist of two to three propane tanks that provide additional capacity for storage, and two high volume racks for
loading propane into trucks. Each truck can be fully loaded within 15 minutes, providing for an aggregate truck-loading
capacity of approximately 400 trucks per day. Each facility also has the ability to unload multiple railcars simultaneously. We
have numerous railcar leases that allow us to increase our storage and throughput capacity as propane demand increases.
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Propane Supply
Our wholesale propane business has a strategic network of supply arrangements under annual and multi-year agreements
with index-based pricing. The remaining supply is purchased on month-to-month terms to match our anticipated sale
requirements. Our primary suppliers of propane include a subsidiary of DCP Midstream, LLC, MarkWest, BP Canada and
Petredec Limited. We may also obtain supply from our NGL storage facility in Marysville, Michigan.
For our rail terminals, we contract for propane at various major supply points in the United States and Canada, and
transport the product to our terminals under long-term rail commitments, which provide fixed transportation costs that are
subject to prevailing fuel surcharges. We also purchase propane supply from natural gas fractionation plants and crude oil
refineries located in the Texas and Louisiana Gulf Coast. Through this process, we take custody of the propane and either sell it
in the wholesale market or store it at our facilities.
Based on the carrying value of our inventory, timing of inventory transactions and the volatility of the market value of
propane, we have historically and may periodically recognize non-cash lower of cost or market inventory adjustments, which
occur when the market value of our commodities declines below our carrying value.
Customers and Contracts
We typically sell propane to propane distributors under annual sales agreements, negotiated each spring, that specify
floating price terms that provide us a margin in excess of our floating index-based supply costs under our supply purchase
arrangements. In the event that a propane distributor desires to purchase propane from us on a fixed price basis, we may enter
into fixed price sales agreements with terms of generally up to one year. We manage this commodity price risk by purchasing
and storing propane, by entering into physical purchase agreements or by entering into offsetting financial derivative
instruments, with DCP Midstream, LLC or third parties, that generally match the quantities of propane subject to these fixed
price sales agreements. Our ability to help our clients manage their commodity price exposure by offering propane at a fixed
price may lead to improved margins and a larger customer base. Historically, the majority of the gross margin generated by our
wholesale propane business is earned in the heating season months of October through April, which corresponds to the general
market demand for propane.
We had two third-party customers in our Wholesale Propane Logistics segment that accounted for greater than 10% of our
segment revenues for the year ended December 31, 2013.
Competition
The wholesale propane business is highly competitive in the mid-Atlantic, upper midwestern and northeastern regions of
the United States. Our wholesale propane business’ competitors include integrated oil and gas and energy companies, interstate
and intrastate pipelines, as well as marketers and other wholesalers.
Other Segment Information
For additional information on our segments, please see Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” and Note 17 of the Notes to Consolidated Financial Statements in Item 8. “Financial
Statements and Supplementary Data.”
We have no revenue attributable to international activities.
REGULATORY AND ENVIRONMENTAL MATTERS
Safety and Maintenance Regulation
We are subject to regulation by the United States Department of Transportation, or DOT, under the Hazardous Liquids
Pipeline Safety Act of 1979, as amended, or HLPSA, and comparable state statutes with respect to design, installation, testing,
construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products,
including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such
regulations, to permit access to and copying of records and to file certain reports and provide information as required by the
United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that
we are in compliance in all material respects with these HLPSA regulations.
We are also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, or NGPSA, and the Pipeline Safety
Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of
gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States oil and
15
natural gas transportation pipelines in high-consequence areas within 10 years. DOT, through the Pipeline and Hazardous
Materials Safety Administration (PHMSA), has developed regulations implementing the Pipeline Safety Improvement Act that
requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety
protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.
Pipeline safety legislation enacted in 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, (the
Pipeline Safety and Job Creations Act) reauthorizes funding for federal pipeline safety programs through 2015, increases
penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies
of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the
expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency
of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure,
incident notification, and other pipeline-safety related requirements. New rules proposed by DOT’s PHMSA address many
areas of this legislation. Extending the integrity management requirements to our gathering lines would impose additional
obligations on us and could add material cost to our operations.
The Pipeline Safety and Job Creation Act requires more stringent oversight of pipelines and increased civil penalties for
violations of pipeline safety rules. The legislation gives PHMSA civil penalty authority up to $200,000 per day, with a maximum
of $2 million for any related series of violations. Any material penalties or fines under these or other statues, rules, regulations or
orders could have a material adverse impact on our business, financial condition, results of operation and cash flows.
We currently estimate we will incur between $4 million and $6 million between 2014 and 2018 to implement integrity
management program testing along certain segments of our natural gas transmission and NGL pipelines. We believe that we are
in compliance in all material respects with the NGPSA and the Pipeline Safety Improvement Act of 2002 and the Pipeline
Safety and Job Creation Act.
States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing
intrastate pipeline regulations at least as stringent as the federal standards. In practice, states vary considerably in their authority
and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws
and regulations in those states in which we or the entities in which we own an interest operate. Our natural gas transmission and
regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance
with pipeline safety and pollution control requirements.
In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and
comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline
industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community
right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state
statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this
information be provided to employees, state and local government authorities and citizens. We and the entities in which we own
an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the
consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any
process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas,
pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric
tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. We have
an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe
that we are in compliance in all material respects with all applicable laws and regulations relating to worker health and safety.
Propane Regulation
National Fire Protection Association Codes No. 54 and No. 58, which establish rules and procedures governing the safe
handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we
operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level.
With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor
Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the DOT. We
conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We
maintain various permits that are necessary to operate our facilities, some of which may be material to our propane operations.
We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are
consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.
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FERC Regulation of Operations
FERC regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may
affect certain aspects of our business and the market for our products and services.
Interstate Natural Gas Pipeline Regulation
The Discovery 105-mile mainline, approximately 60 miles of laterals and its market expansion project are subject to
regulation by FERC, under the Natural Gas Act of 1938, as amended, or NGA. Natural gas companies may not charge rates that
have been determined to be unjust or unreasonable. In addition, FERC authority over natural gas companies that provide
natural gas pipeline transportation services in interstate commerce includes:
•
•
•
•
•
•
•
•
•
certification and construction of new facilities;
extension or abandonment of services and facilities;
maintenance of accounts and records;
acquisition and disposition of facilities;
initiation and discontinuation of services;
terms and conditions of services and service contracts with customers;
depreciation and amortization policies;
conduct and relationship with certain affiliates; and
various other matters.
Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of
and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providing
service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The maximum
applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC-approved gas tariff. Rate
design and the allocation of costs also can impact a pipeline’s profitability. FERC-regulated natural gas pipelines are permitted
to discount their firm and interruptible rates without further FERC authorization down to the minimum rate or variable cost of
performing service, provided they do not “unduly discriminate.”
Tariff changes can only be implemented upon approval by FERC. Two primary methods are available for changing the
rates, terms and conditions of service of an interstate natural gas pipeline. Under the first method, the pipeline voluntarily seeks
a tariff change by making a tariff filing with FERC justifying the proposed tariff change and providing notice, generally
30 days, to the appropriate parties. If FERC determines, as required by the NGA, that a proposed change is just and reasonable,
FERC will accept the proposed change and the pipeline will implement such change in its tariff. However, if FERC determines
that a proposed change may not be just and reasonable as required by NGA, then FERC may suspend such change for up to five
months beyond the date on which the change would otherwise go into effect and set the matter for an administrative hearing.
Subsequent to any suspension period ordered by FERC, the proposed change may be placed into effect by the company,
pending final FERC approval. In most cases, a proposed rate increase is placed into effect before a final FERC determination
on such rate increase, and the proposed increase is collected subject to refund (plus interest). Under the second method, FERC
may, on its own motion or based on a complaint, initiate a proceeding seeking to compel the company to change its rates, terms
and/or conditions of service. If FERC determines that the existing rates, terms and/or conditions of service are unjust,
unreasonable, unduly discriminatory or preferential, then any rate reduction or change that it orders generally will be effective
prospectively from the date of FERC order requiring this change.
The natural gas industry historically has been heavily regulated; therefore, there is no assurance that a more stringent
regulatory approach will not be pursued by FERC and Congress, especially in light of potential market power abuse by
marketing affiliates of certain pipeline companies engaged in interstate commerce. In response to this issue, Congress, in the
Energy Policy Act of 2005, or EPACT 2005, and FERC have implemented requirements to ensure that energy prices are not
impacted by the exercise of market power or manipulative conduct. EPACT 2005 prohibits the use of any “manipulative or
deceptive device or contrivance” in connection with the purchase or sale of natural gas, electric energy or transportation subject
to FERC jurisdiction. In addition, EPACT 2005 gave FERC increased penalty authority for these violations. FERC may now
issue civil penalties of up to $1 million per day per violation, and possible criminal penalties of up to $1 million per violation
and five years in prison. FERC may also order disgorgement of profits obtained in violation of FERC rules. FERC adopted the
17
Market Manipulation Rules and the Market Behavior Rules to implement the authority granted under EPACT 2005. These
rules, which prohibit fraud and manipulation in wholesale energy markets, are subject to broad interpretation. In the past two
years, FERC has relied on its EPACT 2005 enforcement authority in issuing a number of natural gas enforcement actions
giving rise to the imposition of aggregate penalties of approximately $2 million and aggregate disgorgements of approximately
$13 million. These orders reflect FERC’s view that it has broad latitude in determining whether specific behavior violates the
rules. Given FERC’s broad mandate granted in EPACT 2005, if energy prices are high, or exhibit what FERC deems to be
“unusual” trading patterns, FERC will investigate energy markets to determine if behavior unduly impacted or “manipulated”
energy prices.
Intrastate Natural Gas Pipeline Regulation
Intrastate natural gas pipeline operations are not generally subject to rate regulation by FERC, but they are subject to
regulation by various agencies in the respective states where they are located. While the regulatory regime varies from state to
state, state agencies typically require intrastate gas pipelines to file their rates with the agencies and permit shippers to
challenge existing rates or proposed rate increases. However, to the extent that an intrastate pipeline system transports natural
gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under
Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, intrastate pipelines providing interstate service may
avoid jurisdiction that would otherwise apply under the NGA. Section 311 regulates, among other things, the provision of
transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas
pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair
and equitable rates are subject to refund with interest. Rates for service pursuant to Section 311 of the NGPA are generally
subject to review and approval by FERC at least once every five years. The rate review may, but does not necessarily, involve
an administrative-type hearing before FERC staff panel and an administrative appellate review. Additionally, the terms and
conditions of service set forth in the intrastate pipeline’s Statement of Operating Conditions are subject to FERC approval.
Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply
with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service
established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA
jurisdiction by FERC and/or the imposition of administrative, civil and criminal penalties. Among other matters, EPACT 2005
amends the NGPA to give FERC authority to impose civil penalties for violations of the NGPA up to $1 million per day per
violation and possible criminal penalties of up to $1 million per violation and five years in prison for violations occurring after
August 8, 2005. The Pelico, Cipco and EasTrans (part of our East Texas system) systems are subject to FERC jurisdiction under
Section 311 of the NGPA.
Gathering Pipeline Regulation
Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We
believe that our natural gas gathering facilities meet the traditional tests FERC has used to establish a pipeline’s status as a
gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and
federally unregulated gathering services continues to be a current issue in various FERC proceedings with respect to facilities
that interconnect gathering and processing plants with nearby interstate pipelines, so the classification and regulation of our
gathering facilities may be subject to change based on future determinations by FERC and the courts. State regulation of
gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take
requirements, and in some instances complaint-based rate regulation.
Our purchasing, gathering and intrastate transportation operations are subject to ratable take and common purchaser
statutes in the states in which they operate. The ratable take statutes generally require gatherers to take, without undue
discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes
generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are
designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source
of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we
contract to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels where FERC has
recognized a jurisdictional exemption for the gathering activities of interstate pipeline transmission companies and a number of
such companies have transferred gathering facilities to unregulated affiliates. Many of the producing states have adopted some
form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state
regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering
operations could be adversely affected should they be subject in the future to the application of state or federal regulation of
rates and services. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We
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cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur
additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Sales of Natural Gas
The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not
subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any
related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations
enforced by FERC and/or the Commodity Futures Trading Commission, or CFTC. Should we violate the anti-market
manipulation laws and regulations, we could be subject to related third party damage claims by, among others, market
participants, sellers, royalty owners and taxing authorities.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the
price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually
proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably
interstate natural gas transmission companies that remain subject to FERC jurisdiction. These initiatives also may affect the
intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is
to promote competition among the various sectors of the natural gas industry. We cannot predict the ultimate impact of these
regulatory changes to our natural gas marketing operations.
Interstate NGL Pipeline Regulation
The Black Lake, Wattenberg and Front Range pipelines are interstate NGL pipelines subject to FERC regulation. FERC
regulates interstate NGL pipelines under its Oil Pipeline Regulations, the Interstate Commerce Act of 1887, as amended, or
ICA, and the Elkins Act of 1903, as amended. FERC requires that interstate NGL pipelines file tariffs containing all the rates,
charges and other terms for services performed. The ICA requires that tariffs apply to the interstate movement of NGLs, as is
the case with the Black Lake, Wattenberg and Front Range pipelines. Pursuant to the ICA, rates can be challenged at FERC
either by protest when they are initially filed or increased or by complaint at any time they remain on file with FERC.
In October 1992, Congress passed EPACT, which among other things, required FERC to issue rules establishing a
simplified and generally applicable ratemaking methodology for pipelines regulated by FERC pursuant to the ICA. FERC
responded to this mandate by issuing several orders, including Order No. 561. Beginning January 1, 1995, Order No. 561
enables petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Specifically,
the indexing methodology allows a pipeline to increase its rates annually by a percentage equal to the change in the producer
price index for finished goods, PPI-FG, plus 2.65% to the new ceiling level. Rate increases made pursuant to the indexing
methodology are subject to protest, but such protests must show that the portion of the rate increase resulting from application
of the index is substantially in excess of the pipeline’s increase in costs. If the PPI-FG falls and the indexing methodology
results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate
to comply with the lower ceiling unless doing so would reduce a rate “grandfathered” by EPACT (see below) below the
grandfathered level. A pipeline must, as a general rule, utilize the indexing methodology to change its rates. FERC, however,
retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach, which
alternatives may be used in certain specified circumstances. FERC’s indexing methodology is subject to review every five
years; the current methodology remains in place through June 30, 2016.
EPACT deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPACT that
had not been subject to complaint, protest or investigation during that 365-day period to be just and reasonable under the ICA.
Generally, complaints against such “grandfathered” rates may only be pursued if the complainant can show that a substantial
change has occurred since the enactment of EPACT in either the economic circumstances of the petroleum pipeline, or in the
nature of the services provided, that were a basis for the rate. EPACT places no such limit on challenges to a provision of a
petroleum pipeline tariff as unduly discriminatory or preferential.
Intrastate NGL Pipeline Regulation
Intrastate NGL and other petroleum pipelines are not generally subject to rate regulation by FERC, but they are subject to
regulation by various agencies in the respective states where they are located. While the regulatory regime varies from state to
state, state agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to
challenge existing rates or proposed rate increases.
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Environmental Matters
General
Our operation of pipelines, plants and other facilities for gathering, compressing, processing, transporting, fractionating or
storing natural gas, NGLs and other products is subject to stringent and complex federal, state and local laws and regulations
governing the emission or discharge of materials into the environment or otherwise relating to the protection of the
environment.
As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local
levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
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requiring the acquisition of permits to conduct regulated activities;
restricting the way we can handle or dispose of our wastes;
limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions or areas inhabited
by endangered species;
requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former
operations; and
enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued
pursuant to such environmental laws and regulations.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement
measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders
enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up
and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for
neighboring landowners and other third parties to file claims for property damage or possibly personal injury allegedly caused
by the release of substances or other waste products into the environment.
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the
environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance
or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate
future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing
environmental laws and regulations, participate as applicable in the public process to ensure such new requirements are well
founded and reasonable or to revise them if they are not, and to manage the costs of such compliance. For instance, we or the
entities in which we own an interest inspect the pipelines regularly using equipment rented from third party suppliers. Third
parties also assist us in interpreting the results of the inspections. We also actively participate in industry groups that help
formulate recommendations for addressing existing or future regulations.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material
adverse effect on our business, financial position or results of operations. Below is a discussion of the more significant
environmental laws and regulations that relate to our business.
Impact of Climate Change and Air Quality Standards
A number of states have adopted programs to reduce “greenhouse gases,” or GHG and depending on the particular
program or jurisdiction, we could be required to purchase and surrender allowances, either for GHG emissions resulting from
our operations (e.g., compressor units) or from combustion of fuels (e.g., oil or natural gas) that we process. Also, the U.S.
Environmental Protection Agency, or EPA, has declared that GHGs “endanger” public health and welfare, and is regulating
GHG emissions from mobile sources such as cars and trucks. According to the EPA, this final action on the GHG vehicle
emission rule triggered regulation of carbon dioxide and other GHG emissions from stationary sources under certain Clean Air
Act programs at both the federal and state levels, particularly the Prevention of Significant Deterioration program and Title V
permitting. These requirements for stationary sources took effect on January 2, 2011. On June 26, 2012, the DC Circuit upheld
the EPA’s GHG rules in their entirety. The EPA has also published various rules relating to the mandatory reporting of GHG
emissions, including mandatory reporting requirements of GHGs from petroleum and natural gas systems. The permitting and
reporting program taken as a whole increases the costs and complexity of operating oil and gas operations in compliance with
these legal requirements, with resulting potential to adversely affect our cost of doing business, demand for the oil and gas we
transport and may require us to incur certain capital expenditures in the future for air pollution control equipment in connection
with obtaining and maintaining operating permits and approvals for air emissions.
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Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous
substances or solid wastes, including petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment,
transportation and disposal of solid and hazardous waste, and may impose strict, joint and several liability for the investigation
and remediation of areas at a facility where hazardous substances may have been released or disposed. For instance, the
Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the
Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include
current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the
disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict
liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to
natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third
parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of
persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses
natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the
course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs
required to clean up sites at which these hazardous substances have been released into the environment.
We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Resource
Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes. While RCRA regulates both solid and
hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous
wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible
that these wastes, which could include wastes currently generated during our operations, will in the future be designated as
hazardous wastes and therefore be subject to more rigorous and costly disposal requirements. Any such changes in the laws and
regulations could have a material adverse effect on our maintenance capital expenditures and operating expenses.
We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years.
Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum
hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or
under the other locations where these petroleum hydrocarbons and wastes have been taken for treatment or disposal. In
addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum
hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to
CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property
(including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently
aware of any facts, events or conditions relating to the application of such requirements that could reasonably have a material
impact on our operations or financial condition.
Water
The Federal Water Pollution Control Act of 1972, as amended, also referred to as the Clean Water Act, or CWA, and
analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant
to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state and federal waters. The CWA
also requires implementation of spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in
connection with on-site storage of threshold quantities of oil. The CWA imposes substantial potential civil and criminal
penalties for non-compliance. State laws for the control of water pollution also provide varying civil and criminal penalties and
liabilities. In addition, some states maintain groundwater protection programs that require permits for discharges or operations
that may impact groundwater conditions. The EPA has promulgated regulations that require us to have permits in order to
discharge certain storm water. The EPA has entered into agreements with certain states in which we operate whereby the
permits are issued and administered by the respective states. These permits may require us to monitor and sample the storm
water discharges. We believe that compliance with existing permits and compliance with foreseeable new permit requirements
will not have a material adverse effect on our financial condition or results of operations.
The Oil Pollution Act of 1990, as amended ("OPA") addresses prevention, containment and cleanup, and liability
associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities, including terminals, pipelines,
and transfer facilities. OPA subjects owners of such facilities to strict liability for containment and removal costs, natural
resource damages, and certain other consequences of oil spills into jurisdictional waters. Any unpermitted release of petroleum
or other pollutants from our operations could result in government penalties and civil liability.
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Anti-Terrorism Measures
The federal Department of Homeland Security regulates the security of chemical and industrial facilities pursuant to
regulations known as the Chemical Facility Anti-Terrorism Standards. These regulations apply to oil and gas facilities, among
others, that are deemed to present “high levels of security risk.” Pursuant to these regulations, certain of our facilities are required
to comply with certain regulatory provisions, including requirements regarding inspections, audits, recordkeeping, and protection
of chemical-terrorism vulnerability information.
Employees
Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its
general partner, DCP Midstream GP, LLC, or the General Partner, which is 100% owned by DCP Midstream, LLC. As of
December 31, 2013, the General Partner or its affiliates employed 7 people directly and approximately 614 people who
provided direct support for our operations through DCP Midstream, LLC. Our executive management personnel are employees
of DCP Midstream, LLC. In 2014, our chief executive officer and group vice president and chief financial officer are expected
to devote approximately 25% of their time to our matters. Other executive management, including our president and vice
president, general counsel are expected to devote substantially all of their time to our matters. See additional discussion in
Item 10. Directors, Executive Officers and Corporate Governance.
General
We make certain filings with the Securities and Exchange Commission, or SEC, including our annual report on Form 10-
K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments and exhibits to those reports, which are
available free of charge through our website, www.dcppartners.com, as soon as reasonably practicable after they are filed with
the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington,
D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at www.sec.gov. Our annual reports
to unitholders, press releases and recent analyst presentations are also available on our website. We have also posted our code
of business ethics on our website.
Item 1A. Risk Factors
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to
which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should
consider carefully the following risk factors together with all of the other information included in this annual report in
evaluating an investment in our common units.
If any of the following risks were actually to occur, our business, financial condition or results of operations could be
materially affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the
trading price of our common units could decline and you could lose all or part of your investment.
Risks Related to Our Business
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and
expenses, including cost reimbursements to our general partner, to enable us to continue to make cash distributions to
holders of our common units at our current distribution rate.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our
operations, which will fluctuate from quarter to quarter based on, among other things:
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the fees we charge and the margins we realize for our services;
the prices of, level of production of, and demand for natural gas, condensate and NGLs, and propane;
the success of our commodity and interest rate hedging programs in mitigating fluctuations in commodity prices
and interest rates;
the volume and quality of natural gas we gather, compress, treat, process, transport and sell, and the volume of
NGLs we process, transport, sell, and store and the volume of propane we transport, sell, and store;
the operational performance and efficiency of our assets, including our plants and equipment;
the operational performance and efficiency of third-party processing, fractionation or other facilities that provide
services to us;
the relationship between natural gas, NGL and crude oil prices;
the level of competition from other energy companies;
the impact of weather conditions on the demand for natural gas, NGLs and propane;
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the level of our operating and maintenance and general and administrative costs; and
prevailing economic conditions.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which
are beyond our control, including:
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the level of capital expenditures we make;
the cost and form of payment for acquisitions;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets at reasonable rates;
restrictions contained in our debt agreements;
the timing of our producers' obligations to make volume deficiency payments to us;
the amount of cash distributions we receive from our equity interests;
the amount of cost reimbursements to our general partner;
the amount of cash reserves established by our general partner; and
new, additions to and changes in laws and regulations.
We have partial ownership interests in certain joint venture legal entities, including Discovery, the Mont Belvieu
fractionators, Texas Express, CrossPoint and Front Range which could adversely affect our ability to operate and control
these entities. In addition, we may be unable to control the amount of cash we will receive from the operation of these
entities and we could be required to contribute significant cash to fund our share of their operations, which could adversely
affect our ability to distribute cash to our unitholders.
Our inability, or limited ability, to control the operations and management of joint venture legal entities that we have a
partial ownership interest in may mean that we will not receive the amount of cash we expect to be distributed to us. In
addition, for entities in which we have a minority ownership interest, we will be unable to control ongoing operational
decisions, including the incurrence of capital expenditures that we may be required to fund. Specifically,
• we have limited ability to control decisions with respect to the operations of these entities and their subsidiaries,
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including decisions with respect to incurrence of expenses and distributions to us;
these entities may establish reserves for working capital, capital projects, environmental matters and legal
proceedings which would otherwise reduce cash available for distribution to us;
these entities may incur additional indebtedness, and principal and interest made on such indebtedness may
reduce cash otherwise available for distribution to us; and
these entities may require us to make additional capital contributions to fund working capital and capital
expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.
All of these items could significantly and adversely impact our ability to distribute cash to our unitholders.
The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow
and not solely on profitability.
Profitability may be significantly affected by non-cash items. As a result, we may make cash distributions during periods
when we record losses for financial accounting purposes and may not make cash distributions during periods when we record
net earnings for financial accounting purposes.
Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources
of supplies of natural gas and NGLs.
Our gathering and transportation pipeline systems are connected to or dependent on the level of production from natural
gas wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will
also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems
and NGL pipelines and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies.
The primary factors affecting our ability to obtain new supplies of natural gas and NGLs, and to attract new customers to our
assets include the level of successful drilling activity near these assets, the demand for natural gas and crude oil, producers’
desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production
performance, surface access and infrastructure issues, and our ability to compete for volumes from successful new wells. If we
are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of
competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which
could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to
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make cash distributions.
Current economic conditions may adversely affect natural gas and NGL producers’ drilling activity and transportation spending
levels, which may in turn negatively impact our volumes and results of operations and our ability to make distributions to our
unitholders.
The level of drilling activity is dependent on economic and business factors beyond our control. Among the factors that impact
drilling decisions are commodity prices, the liquids content of the natural gas production, drilling requirements for producers to
hold leases, the cost of finding and producing natural gas and the general condition of the credit and financial markets. Natural
gas prices have declined substantially compared to historical periods. For example, the twelve-month average New York Mercantile
Exchange, or NYMEX, price of natural gas futures contracts per MMBtu was $4.19, $3.54, and $3.24 as of December 31, 2013,
2012 and 2011, respectively. The twelve-month average price per gallon for NGLs was $0.84, $1.08 and $1.39 as of December 31,
2013, 2012 and 2011, respectively, and the price of crude oil per barrel was $98.04, $94.16 and $95.12 as of December 31, 2013,
2012 and 2011, respectively. Commodity prices historically have been volatile and continue to be volatile. Crude oil prices have
generally remained at favorable levels, while natural gas liquids prices have softened in relation to crude prices. Natural gas prices
have recovered slightly, while natural gas liquids prices are currently below levels seen in recent years due to increasing supplies
and higher inventory levels. Natural gas drilling activity levels vary by geographic area, but in general, drilling remains firm in
areas with liquids rich gas. Drilling remains weak in certain areas with dry gas where low commodity prices currently do not
support the economics of drilling. However, advances in technology, such as horizontal drilling and hydraulic fracturing in shale
plays, have led to certain geographic areas becoming increasingly accessible.
Furthermore, a sustained decline in commodity prices could result in a decrease in exploration and development activities in
the fields served by our gathering and pipeline transportation systems and our natural gas treating and processing plants, and our
NGL and natural gas storage assets, which could lead to reduced utilization of these assets. During periods of natural gas price
decline and/or if the price of NGLs and crude oil declines, the level of drilling activity could decrease. When combined with a
reduction of cash flow resulting from lower commodity prices, a reduction in our producers’ borrowing base under reserve-based
credit facilities and lack of availability of debt or equity financing for our producers may result in a significant reduction in our
producers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline systems.
Other factors that impact production decisions include the ability of producers to obtain necessary drilling and other governmental
permits and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our
assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the
declines resulting from reductions in drilling activity, throughput on our pipelines and the utilization rates of our treating, processing
and storage facilities would decline, which could have a material adverse effect on our business, results of operations, financial
position and cash flows and our ability to make cash distributions.
The cash flow from our Natural Gas Services segment is affected by natural gas, NGL and condensate prices.
Our Natural Gas Services segment is affected by the level of natural gas, NGL and condensate prices. NGL and condensate
prices generally fluctuate on a basis that relates to fluctuations in crude oil prices. In the past, the prices of natural gas and
crude oil have been volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs,
condensate and crude oil depend upon factors beyond our control and may not always have a close relationship. These factors
include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and
other factors, including:
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the impact of weather, including abnormally mild winter or summer weather that cause lower energy usage for
heating or cooling purposes, respectively, or extreme weather that may disrupt our operations or related upstream
or downstream operations;
the level of domestic and offshore production;
a general downturn in economic conditions, including demand for NGLs;
the availability of natural gas, NGLs and crude oil and the demand in the U.S. and globally for these
commodities;
actions taken by foreign oil and gas producing nations;
the availability of local, intrastate and interstate transportation systems;
the availability and marketing of competitive fuels; and
the extent of governmental regulation and taxation.
Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-
proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers for an
agreed percentage of the proceeds from the sale of residue gas and/or NGLs resulting from our processing activities, and then
sell the resulting residue gas and NGLs at market prices. Under these types of arrangements, our revenues and our cash flows
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increase or decrease, whichever is applicable, as the price of natural gas and NGLs fluctuate. We have mitigated a significant
portion of our share of anticipated natural gas, NGL and condensate commodity price risk associated with the equity volumes
from our gathering and processing operations through 2017 with derivative instruments.
Our hedging activities and the application of fair value measurements may have a material adverse effect on our earnings,
profitability, cash flows, liquidity and financial condition.
We are exposed to risks associated with fluctuations in commodity prices. The extent of our commodity price risk is related
largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on
posted market prices, which may differ significantly from the actual natural gas, NGL and condensate prices that we realize in
our operations. To mitigate a portion of our cash flow exposure to fluctuations in the price of NGLs, we have entered into
derivative financial instruments relating to the future price of crude oil and NGLs. If the price relationship between NGLs and
crude oil declines, our commodity price risk will increase. Furthermore, we have entered into derivative transactions related to
only a portion of the volume of our expected natural gas supply and production of NGLs and condensate from our processing
plants; as a result, we will continue to have direct commodity price risk to the open portion. Our actual future production may
be significantly higher or lower than we estimate at the time we entered into the derivative transactions for that period. If the
actual amount is higher than we estimate, we will have greater commodity price risk than we intended. If the actual amount is
lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of
our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, reducing
our liquidity.
We have mitigated a significant portion of our expected natural gas, NGL and condensate commodity price risk relating to
the equity volumes from our gathering and processing operations through 2017 by entering into fixed price derivative financial
instruments. The intent of these arrangements is to reduce the volatility in our cash flows resulting from fluctuations in
commodity prices.
We have mitigated a portion of our interest rate risk with interest rate swaps and forward-starting interest rate swaps that
reduce our exposure to market rate fluctuations by converting variable interest rates on our existing debt to fixed interest rates
and locking in rates on our anticipated future fixed-rate debt, respectively. The interest rate swap agreements convert the
interest rate associated with our variable-rate debt to a fixed-rate obligation, thereby reducing the exposure to market rate
fluctuations. The forward-starting interest rate swap agreements lock in the interest rate associated with our anticipated future
fixed-rate debt, thereby reducing the exposure to market rate fluctuations prior to issuance.
We record all of our derivative financial instruments at fair value on our balance sheets primarily using information readily
observable within the marketplace. In situations where market observable information is not available, we may use a variety of
data points that are market observable, or in certain instances, develop our own expectation of fair value. We will continue to
use market observable information as the basis for our fair value calculations, however, there is no assurance that such
information will continue to be available in the future. In such instances, we may be required to exercise a higher level of
judgment in developing our own expectation of fair value, which may be significantly different from the historical fair values,
and may increase the volatility of our earnings.
We will continue to evaluate whether to enter into any new derivative arrangements, but there can be no assurance that we
will enter into any new derivative arrangement or that our future derivative arrangements will be on terms similar to our
existing derivative arrangements. Although we enter into derivative instruments to mitigate a portion of our commodity price
and interest rate risk, we also forego the benefits we would otherwise experience if commodity prices or interest rates were to
change in our favor.
The counterparties to our derivative instruments may require us to post collateral in the event that our potential payment
exposure exceeds a predetermined collateral threshold. Depending on the movement in commodity prices, the amount of
collateral posted may increase, reducing our liquidity.
As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash
flows and, in certain circumstances, may actually increase the volatility of our earnings and cash flows. In addition, even
though our management monitors our hedging activities, these activities can result in material losses. Such losses could occur
under various circumstances, including if a counterparty does not or is unable to perform its obligations under the applicable
derivative arrangement, the derivative arrangement is imperfect or ineffective, or our risk management policies and procedures
are not properly followed or do not work as planned.
Volumes of natural gas dedicated to our systems in the future may be less than we anticipate.
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As a result of the unwillingness of producers to provide reserve information as well as the cost of such evaluation, we do
not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the reserves
connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas,
then the volumes of natural gas on our systems in the future could be less than we anticipate.
The amount of gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate,
transport, sell and store, may be reduced if the pipelines and storage fractionation facilities to which we deliver the natural
gas or NGLs are capacity constrained and cannot, or will not, accept the gas or NGLs.
The natural gas we gather, compress, treat, process, transport, sell and store is delivered into pipelines for further delivery
to end-users. If these pipelines are capacity constrained and cannot, or will not, accept delivery of the gas due to downstream
constraints on the pipeline or changes in interstate pipeline gas quality specifications, we may be forced to limit or stop the
flow of gas through our pipelines and processing and treating facilities. In addition, interruption of pipeline service upstream of
our processing facilities would limit or stop flow through our processing and fractionation facilities. Likewise, if the pipelines
into which we deliver NGLs are interrupted, we may be limited in, or prevented from conducting, our NGL transportation
operations. Any number of factors beyond our control could cause such interruptions or constraints on pipeline service,
including necessary and scheduled maintenance, or unexpected damage to the pipelines. Because our revenues and net
operating margins depend upon (i) the volumes of natural gas we process, gather and transmit, (ii) the throughput of NGLs
through our transportation, fractionation and storage facilities and (iii) the volume of natural gas we gather and transport, any
reduction of volumes could adversely affect our operations and cash flows available for distribution to our unitholders.
We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs.
We identify as primary natural gas suppliers those suppliers individually representing 10% or more of our total natural gas
supply. We had one natural gas supplier representing 10% or more of our total natural gas supply during the year ended
December 31, 2013. In our NGL Logistics segment, our largest NGL supplier is DCP Midstream, LLC, who obtains NGLs
from various third- party producer customers. While some of these customers are subject to long-term contracts, we may be
unable to negotiate extensions or replacements of these contracts on favorable terms, if at all. The loss of all or even a portion
of the natural gas and NGL volumes supplied by these customers, as a result of competition or otherwise, could have a material
adverse effect on our business.
If we are not able to purchase propane from our principal suppliers, or we are unable to secure transportation under our
transportation arrangements, our results of operations in our wholesale propane logistics business would be adversely
affected.
Most of our propane purchases are made under supply contracts that have a term of between annual and multi-year
agreements and provide various index-based pricing formulas. We identify primary suppliers as those individually representing
10% or more of our total propane supply. Our four primary suppliers of propane, one of which is an affiliated entity,
represented approximately 85% of our propane supplied during the year ended December 31, 2013. In the event that we are
unable to purchase propane from our significant suppliers due to their failure to perform under contractual obligations or
otherwise, replace terminated or expired supply contracts, or if there are domestic or international supply disruptions, our
failure to obtain alternate sources of supply at competitive prices and on a timely basis would affect our ability to satisfy
customer demand, reduce our revenues and adversely affect our results of operations. In addition, if we are unable to transport
propane supply to our terminals, our ability to satisfy customer demand, our revenue and results of operations would be
adversely affected.
The adoption of financial reform legislation by the United States Congress could have an adverse effect on our ability to use
derivative instruments to hedge risks associated with our business.
We hedge a portion of our commodity risk and our interest rate risk. The United States Congress adopted comprehensive
financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities,
including businesses like ours, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform
and Consumer Protection Act, or Act, was signed into law by the President on July 21, 2010, and requires the Commodities Futures
Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation. In its
rulemaking under the Act, the CFTC adopted regulations to set position limits for certain futures and option contracts in the major
energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in Federal district
court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely
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vacated by the court. The CFTC filed a notice of appeal with respect to this ruling but on October 29, 2013, voted to voluntarily
dismiss the appeal. On November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core
futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide
hedging transactions. Comments on these new rules were due in early January 2014, and as these new position limit rules are not
yet final, the impact of those provisions on us is uncertain at this time. Under the rules adopted by the CFTC, we believe our
hedging transactions will qualify for the non-financial, commercial end user exception, which exempts derivatives intended to
hedge or mitigate commercial risk from the mandatory swap clearing requirement. The Act may also require us to comply with
margin requirements in connection with our hedging activities, although the application of those provisions to us is uncertain at
this time. The Act may also require the counterparties to our derivative instruments to spin off some of their hedging activities to
a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and related regulations could
significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which could
adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives
to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase
our exposure to less creditworthy counterparties, particularly if we are unable to utilize the commercial end user exception with
respect to certain of our hedging transactions. If we reduce our use of hedging as a result of the legislation and regulations, our
results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our
ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to
reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and
commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the
legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our
business, our financial condition, and our results of operations.
We may not be able to grow or effectively manage our growth.
A principal focus of our strategy is to continue to grow the per unit distribution on our units by expanding our business.
Our future growth will depend upon a number of factors, some of which we can control and some of which we cannot. These
factors include our ability to:
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participate in dropdown opportunities with DCP Midstream, LLC;
identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other
midstream assets for acquisitions, joint ventures and construction projects;
consummate accretive acquisitions or joint ventures and complete construction projects;
appropriately identify liabilities associated with acquired businesses or assets;
integrate acquired or constructed businesses or assets successfully with our existing operations and into our
operating and financial systems and controls;
hire, train and retain qualified personnel to manage and operate our growing business; and
obtain required financing for our existing and new operations at reasonable rates.
A deficiency in any of these factors could adversely affect our ability to achieve growth in the level of our cash flows or
realize benefits from acquisitions, joint ventures or construction projects. In addition, competition from other buyers could
reduce our acquisition opportunities. DCP Midstream, LLC and its affiliates are not restricted from competing with us. DCP
Midstream, LLC and its affiliates may acquire, construct or dispose of midstream or other assets in the future without any
obligation to offer us the opportunity to purchase or construct those assets.
Furthermore, we have recently grown significantly through a number of acquisitions. If we fail to properly integrate these
acquired assets successfully with our existing operations, if the future performance of these acquired assets does not meet our
expectations, if we did not properly value the acquired assets, or we did not identify significant liabilities associated with the
acquired assets, the anticipated benefits from these acquisitions may not be fully realized.
Our ability to manage and grow our business effectively could be adversely affected if we fail to attract and retain key
management personnel and skilled employees.
We rely on our executive management team to manage our day-to-day affairs and establish and execute our strategic
business and operational plans. Our executive management team has significant experience in the midstream energy industry.
The loss of any of our executives or failure to fill new positions created by expansion, turnover or retirement could adversely
affect our ability to implement our business strategy. In addition, our operations require engineers, operational and field
technicians and other highly skilled employees. Competition for experienced executives and skilled employees is intense and
increases when the demand from other energy companies for such personnel is high. Our ability to execute on our business
strategy and to grow or continue our level of service to our current customers may be impaired and our business may be
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adversely impacted if we are unable to attract, train and retain such personnel, which may have an adverse effect on our results
of operations and ability to make cash distributions.
We may not successfully balance our purchases and sales of natural gas and propane.
We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas
gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. In
addition, in our wholesale propane logistics business, we purchase propane from a variety of sources and resell the propane to
distributors. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver
contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes.
Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and
sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have
increased volatility in our operating income and cash flows.
Our NGL pipelines could be adversely affected by any decrease in NGL prices relative to the price of natural gas.
The profitability of our NGL pipelines is dependent on the level of production of NGLs from processing plants. When
natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of
natural gas compared to the value of NGLs and because of the increased cost (principally that of natural gas as a feedstock and
fuel) of separating the NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices
relative to NGL prices reduce the volume of natural gas processed at plants connected to our NGL pipelines, as well as
reducing the amount of NGL extraction, which would reduce the volumes and gross margins attributable to our NGL pipelines
and NGL storage facilities.
Third party pipelines and other facilities interconnected to our natural gas and NGL pipelines and facilities may become
unavailable to transport, process or produce natural gas and NGLs.
We depend upon third party pipelines and other facilities that provide delivery options to and from our pipelines and
facilities for the benefit of our customers. Since we do not own or operate any of these third-party pipelines or other facilities,
their continuing operation is not within our control and may become unavailable to transport, process or produce natural gas
and NGLs.
A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel markets could
materially adversely affect our results of operations and financial condition.
The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and
refining blend stocks. A reduction in demand for NGL products, whether because of general or industry specific economic
conditions, new government regulations, global competition, reduced demand by consumers for products made with NGL
products (for example, reduced petrochemical demand observed due to lower activity in the automobile and construction
industries), increased competition from petroleum-based feedstocks due to pricing differences, mild winter weather for some
NGL applications or other reasons, could result in a decline in the volume of NGL products we handle or reduce the fees we
charge for our services.
Service at our propane terminals may be interrupted.
Historically, a substantial portion of the propane we purchase to support our wholesale propane logistics business is
delivered at our rail terminals or by ship at our leased marine terminal in Providence, Rhode Island and at our owned marine
terminal in Chesapeake, Virginia. We also rely on shipments of propane via the Buckeye Pipeline for our Midland Terminal and
via TEPPCO Partners, LP’s pipeline to open access terminals. Any significant interruption in the service at these terminals
would adversely affect our ability to obtain propane, which could reduce the amount of propane that we distribute and impact
our revenues or cash available for distribution.
Our operating results for our Wholesale Propane Logistics Segment fluctuate on a seasonal and quarterly basis.
Revenues from our Wholesale Propane Logistics Segment have seasonal characteristics. In many parts of the country,
demand for propane and other fuels peaks during the winter months. As a result, our overall operating results fluctuate on a
seasonal basis. Demand for propane and other fuels could vary significantly from our expectations depending on the nature and
location of our facilities and pipeline systems and the terms of our transportation arrangements relative to demand created by
unusual weather patterns.
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We operate in a highly competitive business environment.
We compete with similar enterprises in our respective areas of operation. Some of our competitors are large oil, natural gas
and petrochemical companies that have greater financial resources and access to supplies of natural gas, propane and NGLs
than we do. Some of these competitors may expand or construct gathering, processing and transportation systems that would
create additional competition for the services we provide to our customers. Likewise, our customers who produce NGLs may
develop their own systems to transport NGLs. Additionally, our wholesale propane distribution customers may develop their
own sources of propane supply. Our ability to renew or replace existing contracts with our customers at rates sufficient to
maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers.
Our assets and operations can be affected by weather, weather related conditions and other natural phenomena.
Our assets and operations can be adversely affected by hurricanes, floods, tornadoes, wind, lightning, cold weather and
other natural phenomena, which could impact our results of operations and make it more difficult for us to realize historic rates
of return. Although we carry insurance on the vast majority of our assets, insurance may be inadequate to cover our loss and in
some instances, we have been unable to obtain insurance on some of our assets on commercially reasonable terms, if at all. If
we incur a significant disruption in our operations or a significant liability for which we were not fully insured, our financial
condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.
Competition from alternative energy sources, conservation efforts and energy efficiency and technological advances may
reduce the demand for propane.
Competition from alternative energy sources, including natural gas and electricity, has been increasing as a result of
reduced regulation of many utilities. In addition, propane competes with heating oil primarily in residential applications.
Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a
less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and availability of
natural gas in the northeast, which has historically depended upon propane, could reduce the demand for propane, which could
adversely affect the volumes of propane that we distribute. In addition, stricter conservation measures in the future or
technological advances in heating, energy generation or other devices could reduce the demand for propane.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a
change in policy by those agencies may result in increased regulation of our assets.
The majority of our natural gas gathering and intrastate transportation operations are exempt from FERC regulation under
the NGA but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC’s
policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on
open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In
recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However,
we cannot assure that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that
may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated
transmission services and federally unregulated gathering services has been the subject of regular litigation, so the classification
and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on any
reassessment by us of the jurisdictional status of our facilities or on future determinations by FERC and the courts.
In addition, the rates, terms and conditions of some of the transportation services we provide on our Cipco pipeline system,
EasTrans Pipeline system, and Pelico pipeline system are subject to FERC regulation under Section 311 of the NGPA. Under
Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable
rates are subject to refund with interest. The Cipco and Pelico systems are currently charging rates for its Section 311
transportation services that were deemed fair and equitable under a rate settlement approved by FERC. The EasTrans system is
currently charging rates for its Section 311 transportation services that were deemed fair and equitable under an order approved
by the Railroad Commission of Texas. The Black Lake, Wattenberg, and Front Range pipelines are interstate transporters of
NGLs and are subject to FERC jurisdiction under the Interstate Commerce Act and the Elkins Act.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be
subject to substantial penalties and fines. Under EPACT 2005, FERC has civil penalty authority under the NGA and the NGPA
to impose penalties for current violations of up to $1 million per day for each violation and possible criminal penalties of up to
$1 million per violation and five years in prison.
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Other state and local regulations also affect our business. Our non-proprietary gathering lines are subject to ratable take
and common purchaser statutes in Louisiana. Ratable take statutes generally require gatherers to take, without undue
discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser
statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes
restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas.
Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted
complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers
to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate
discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of
natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production
allowable from gas wells. While our proprietary gathering lines are currently subject to limited state regulation, there is a risk
that state laws will be changed, which may give producers a stronger basis to challenge the proprietary status of a line, or the
rates, terms and conditions of a gathering line providing transportation service.
Discovery’s interstate tariff rates are subject to review and possible adjustment by federal regulators. Moreover, because
Discovery is a non-corporate entity, it may be disadvantaged in calculating its cost-of-service for rate-making purposes.
FERC, pursuant to the NGA, regulates many aspects of Discovery’s interstate pipeline transportation service, including the
rates that Discovery is permitted to charge for such service. Under the NGA, interstate transportation rates must be just and
reasonable and not unduly discriminatory. If FERC fails to permit tariff rate increases requested by Discovery, or if FERC
lowers the tariff rates Discovery is permitted to charge its customers, on its own initiative, or as a result of challenges raised by
Discovery’s customers or third parties, Discovery’s tariff rates may be insufficient to recover the full cost of providing interstate
transportation service. In certain circumstances, FERC also has the power to order refunds.
Under current policy, FERC permits pipelines to include, in the cost-of-service used as the basis for calculating the
pipeline’s regulated rates, a tax allowance reflecting the actual or potential income tax liability on public utility income
attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or
potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability
will be reviewed by FERC on a case-by-case basis. In a future rate case, Discovery may be required to demonstrate the extent
to which inclusion of an income tax allowance in Discovery’s cost-of-service is permitted under the current income tax
allowance policy.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be
subject to substantial penalties and fines. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose
penalties for current violations of up to $1 million per day for each violation and possible criminal penalties of up to $1 million
per violation and five years in prison.
Recent spills and their aftermath could lead to additional governmental regulation of the offshore exploration and
production industry, which may result in substantial cost increases or delays in our offshore natural gas gathering activities.
In April 2010, a deepwater exploration well located in the Gulf of Mexico, owned and operated by companies unrelated to
us, sustained a blowout and subsequent explosion leading to the leaking of hydrocarbons. In response to this event, certain
federal agencies and governmental officials ordered additional inspections of deepwater operations in the Gulf of Mexico. On
May 28, 2010, a six-month federal moratorium was implemented on all offshore deepwater drilling projects. On October 12,
2010, the Department of the Interior announced it was lifting the deepwater drilling moratorium. Despite the fact that the
drilling moratorium was lifted, this spill and its aftermath has led to additional governmental regulation of the offshore
exploration and production industry and delays in the issuance of drilling permits, which may result in volume impacts, cost
increases or delays in our offshore natural gas gathering activities, which could materially impact Discovery’s operations, its
Keathley Canyon construction, and our business, financial condition and results of operations. We cannot predict with any
certainty what form any additional regulation or limitations will take.
Recently proposed or finalized rules imposing more stringent requirements on the oil and gas industry could cause our
customers and us to incur increased capital expenditures and operating costs as well as reduce the demand for our services.
On August 16, 2012, the EPA issued final regulations under the Clean Air Act that, among other things, require additional
emissions controls for natural gas and natural gas liquids production, including New Source Performance Standards, or NSPS,
to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to
address hazardous air pollutants frequently associated with such production activities. The final regulations require, among
other things, the reduction of VOC emissions from existing natural gas wells that are re-fractured as well as newly-drilled and
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fractured wells through the use of reduced emission completions or “green completions” and well completion combustion
devices, such as flaring, as of January 1, 2015. In addition, these rules establish specific requirements regarding emissions from
compressors and controllers at natural gas gathering and boosting stations and processing plants together with emissions
reduction requirements for dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering
and boosting stations. The rules further establish new requirements for detection and repair of leaks exceeding 500 parts per
million in concentration at natural gas processing plants. In January 2013, the EPA stated that it intends to reconsider portions
of the rule, and on September 23, 2013, the EPA issued limited revisions to the rule regarding standards for storage tanks
subject to the NSPS. The EPA has stated that it continues to review other issues raised in petitions for reconsideration; the rule
is also the subject of petitions for review before the U.S. Circuit Court of Appeals for the District of Columbia. These
regulations could require modifications to the operations of our natural gas exploration and production customers as well as our
operations including the installation of new equipment and new emissions management practices, which could result in
significant additional costs, both increased capital expenditures and operating costs. The incurrence of such expenditures and
costs by our customers could result in reduced production by those customers and thus translate into reduced demand for our
services, which could in turn have an adverse effect on our business and cash available for distributions.
We may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing
environmental regulations or an accidental release of hazardous substances or hydrocarbons into the environment.
Our operations are subject to stringent and complex federal, state and local environmental laws and regulations. These
include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to
air emissions; (2) the federal RCRA and comparable state laws that impose requirements for the management, storage and
disposal of hazardous and solid waste from our facilities; (3) the Comprehensive Environmental Response Compensation and
Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of
hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to
which we have sent waste for disposal; and (4) the Clean Water Act and the Oil Pollution Act, and comparable state laws that
impose requirements on discharges to waters as well as requirements to prevent and respond to releases of hydrocarbons to
waters of the United States. Failure to comply with these laws and regulations or newly adopted laws or regulations may trigger
a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the
imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental regulations,
including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to
clean up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, it
is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage
allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural
gas, NGLs and other petroleum products, air emissions related to our operations, and historical industry operations and waste
management and disposal practices. For example, an accidental release from one of our facilities could subject us to substantial
liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third
parties for personal injury and property damage and governmental claims for natural resource damages or fines or penalties for
related violations of environmental laws or regulations. In addition, it is possible that stricter laws, regulations or enforcement
policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may
not be able to recover some or any of these costs from insurance or from indemnification from DCP Midstream, LLC.
We may incur significant costs in the future associated with proposed climate change regulation and legislation.
The United States Congress and some states where we have operations are considering legislation related to greenhouse
gas emissions. In addition, there have recently been international conventions and efforts to establish standards for the
reduction of greenhouse gases globally. The United States Congress may consider a legislation that would compel greenhouse
gas emission reductions. Some of these proposals may include limitations, or caps, on the amount of greenhouse gas that can be
emitted, as well as a system of emissions allowances. Legislation passed by the US House of Representatives in 2010, which
was not taken up by the Senate, would have placed the entire burden of obtaining allowances for the carbon content of NGLs
on the owners of NGLs at the point of fractionation. In June 2013, the President announced a climate action plan that targets
methane emissions from the oil and gas sector as part of a comprehensive interagency methane reduction strategy. Any
requirements for methane reductions could be in addition to the recent EPA rules governing permitting of new or modified large
sources of greenhouse gases. The EPA also has issued rules requiring reporting of greenhouse gas, on an annual basis, for
certain onshore natural gas and oil production facilities beginning 2012. To the extent legislation is enacted or additional rules
are promulgated that regulate greenhouse gas emissions, it could significantly increase our costs to (i) acquire allowances; (ii)
permit new large facilities; (iii) operate and maintain our facilities; (iv) install new emission controls; and (v) manage a
greenhouse gas emissions program. If such legislation becomes law or additional rules are promulgated in the United States or
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any states in which we have operations and we are unable to pass these costs through as part of our services, it could have an
adverse effect on our business and cash available for distributions.
Increased regulation of hydraulic fracturing could result in reductions, delays or increased costs in drilling and completing
new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas that we
gather, process and transport.
Certain of our customers' natural gas is developed from formations requiring hydraulic fracturing as part of the completion
process. Fracturing is a process where water, sand, and chemicals are injected under pressure into subsurface formations to
stimulate hydrocarbon production. While the underground injection of fluids is regulated by the U.S. EPA under the Safe
Drinking Water Act, or SDWA, fracturing is excluded from regulation unless the injection fluid is diesel fuel. Congress recently
considered legislation that would repeal the exclusion, allowing EPA to more generally regulate fracturing, and requiring
disclosure of chemicals used in the fracturing process. If enacted, such legislation could require fracturing to meet permitting
and financial responsibility requirements, as well as siting and technical specifications relating to well construction, plugging
and abandonment. EPA is also considering various regulatory programs directed at hydraulic fracturing. For example, the EPA
intends to propose regulations in 2014 under the federal Clean Water Act to further regulate wastewater discharges from
hydraulic fracturing and other natural gas production. The adoption of new federal laws or regulations imposing reporting
obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult for our
customers to complete oil and natural gas wells in shale formations and increase their costs of compliance. In addition, the U.S.
EPA is currently studying the potential adverse impact that each stage of hydraulic fracturing may have on the environment.
Several states in which our customers operate have also adopted regulations requiring disclosure of fracturing fluid components
or otherwise regulate their use more closely.
In addition, federal agencies have recently initiated certain other regulatory initiatives or reviews of certain aspects of
hydraulic fracturing that could further increase our natural gas exploration and production customer’s costs and decrease their
levels of production. On May 4, 2012, the federal Bureau of Land Management, or BLM, announced draft rules that, if
adopted, would require disclosure of chemicals used in hydraulic fracturing activities upon Native American Indian and other
federal lands; a revised rule was released for public comment on May 25, 2013. The adoption and implementation of rules
relating to hydraulic fracturing could result in increased expenditures for our natural gas exploration and production customers,
which could cause them to reduce their production and thereby result in reduced demand for our services by these customers.
We may incur significant costs and liabilities resulting from implementing and administering pipeline and asset integrity
programs and related repairs.
Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to
develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in
“high consequence areas.” The regulations require operators to:
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perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
Pipeline safety legislation enacted in 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the
Pipeline Safety and Job Creations Act, reauthorizes funding for federal pipeline safety programs through 2015, increases
penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies
of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the
expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency
of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure,
incident notification, and other pipeline-safety related requirements. New rules proposed by DOT’s PHMSA, address many
areas of this legislation. Extending the integrity management requirements to our gathering lines would impose additional
obligations on us and could add material cost to our operations.
Although many of our natural gas facilities fall within a class that is not subject to current pipeline integrity requirements,
we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures
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associated with non-exempt pipelines. Such costs and liabilities might relate to repair, remediation, preventative or mitigating
actions that may be determined to be necessary as a result of the testing program, or new requirements that may be imposed as
a result of the Pipeline Safety and Job Creation Act, as well as lost cash flows resulting from shutting down our pipelines
during the pendency of such repairs. Additionally, we may be affected by the testing, maintenance and repair of pipeline
facilities downstream from our own facilities. With the exception of our Wattenberg pipeline, our NGL pipelines are also
subject to integrity management and other safety regulations imposed by the Texas Railroad Commission, or TRRC.
We currently estimate that we will incur between $4 million and $6 million between 2014 and 2018 to implement pipeline
integrity management program testing along certain segments of our natural gas and NGL pipelines. This does not include the
costs, if any, of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of
the testing program, or new requirements that may be imposed as a result of the Pipeline Safety and Job Creation Act, which
costs could be substantial.
We currently transport NGLs produced at our processing plants on our owned and third party NGL pipelines. Accordingly,
in the event that an owned or third party NGL pipeline becomes inoperable due to any necessary repairs resulting from integrity
testing program or for any other reason for any significant period of time, we would need to transport NGLs by other means.
There can be no assurance that we will be able to enter into alternative transportation arrangements under comparable terms.
Any new or expanded pipeline integrity requirements or the adoption of other asset integrity requirements could also
increase our cost of operation and impair our ability to provide service during the period in which assessments and repairs take
place, adversely affecting our business. Further, execution of and compliance with such integrity programs may cause us to
incur greater than expected capital and operating expenditures for repairs and upgrades that are necessary to ensure the
continued safe and reliable operation of our assets.
Construction of new assets is subject to regulatory, environmental, political, legal, economic and other risks that may
adversely affect our financial results.
The construction of new midstream facilities or additions or modifications to our existing midstream asset systems or
propane terminals involves numerous regulatory, environmental, political and legal and economic uncertainties beyond our
control and may require the expenditure of significant amounts of capital. Construction expenditures may occur over an
extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully
operational. Moreover, our cash flow from a project may be delayed or may not meet our expectations. These projects may not
be completed on schedule or within budgeted cost, or at all. We may construct facilities to capture anticipated future growth in
production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and
development of natural gas and oil reserves, we often do not have access to third party estimates of potential reserves in an area
prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct
new systems or additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties
inherent in estimating quantities of future production. As a result, these facilities may not be able to attract enough throughput
to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The
construction of new systems or additions to our existing gathering, transportation and propane terminal assets may require us to
obtain new rights-of-way prior to constructing these facilities. We may be unable to obtain such rights-of-way to connect new
natural gas supplies to our existing gathering lines, expand our network of propane terminals, or capitalize on other attractive
expansion opportunities. The construction of new systems or additions to our existing gathering, transportation and propane
terminal assets may require us to rely on third parties downstream of our facilities to have available capacity for our delivered
natural gas, NGLs, or propane. If such third party facilities are not constructed or operational at the time that the addition to our
facilities is completed, we may experience adverse effects on our results of operations and financial condition. The construction
of additional systems may require greater capital investment if the commodity prices of certain supplies such as steel increase.
Construction also subjects us to risks related to the ability to construct projects within anticipated costs, including the risk of
cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond our control that
could adversely affect results of operations, financial position or cash flows.
If we do not make acquisitions on economically acceptable terms, our future growth could be limited.
Our ability to make acquisitions that are accretive to our cash generated from operations per unit is based upon our ability
to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them and obtain financing for these
acquisitions on economically acceptable terms. Furthermore, even if we do make acquisitions that we believe will be accretive,
these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit. Additionally, net assets
contributed by DCP Midstream, LLC represent a transfer of net assets between entities under common control, and are
recognized at DCP Midstream, LLC’s basis in the net assets transferred. The amount of the purchase price in excess of DCP
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Midstream, LLC’s basis in the net assets, if any, is recognized as a reduction to partners’ equity. Conversely, the amount of the
purchase price less than DCP Midstream’s basis in the net assets, if any, is recognized as an increase to partners’ equity.
Any acquisition involves potential risks, including, among other things:
• mistaken assumptions about volumes, future contract terms with customers, revenues and costs, including
synergies;
an inability to successfully integrate the businesses we acquire;
the assumption of unknown liabilities;
limitations on rights to indemnity from the seller;
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• mistaken assumptions about the overall costs of equity or debt;
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the diversion of management’s and employees’ attention from other business concerns;
change in competitive landscape;
unforeseen difficulties operating in new product areas or new geographic areas; and
customer or key employee losses at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and
unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will
consider in determining the application of these funds and other resources.
In addition, any limitations on our access to substantial new capital to finance strategic acquisitions will impair our ability
to execute this component of our growth strategy. If the cost of such capital becomes too expensive, our ability to develop or
acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The
primary factors that influence our cost of capital include market conditions and offering or borrowing costs such as interest
rates or underwriting discounts.
We do not own all of the land on which our pipelines, facilities and rail terminals are located, which may subject us to
increased costs.
Upon contract lease renewal, we may be subject to more onerous terms and/or increased costs to retain necessary land use
if we do not have valid rights of way or if such rights of way lapse or terminate. Certain of our leases contain renewal
provisions that allow for our continued use and access of the subject land and, although we review and renew our leases as a
routine business matter, there may be instances where we may not be able to renew our contract leases on commercially
reasonable terms or may have to commence eminent domain proceedings to establish our right to continue and use the land. We
obtain the rights to construct and operate our pipelines, surface sites and rail terminals on land owned by third parties and
governmental agencies for a specific period of time.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.
Our operations, and the operations of third parties, are subject to many hazards inherent in the gathering, compressing,
treating, processing, storing, transporting and fractionating, as applicable, of natural gas, propane and NGLs, including:
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damage to pipelines, plants, terminals, storage facilities and related equipment and surrounding properties caused
by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
inadvertent damage from construction, farm and utility equipment;
leaks of natural gas, propane, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage
facilities, or losses of natural gas, propane or NGLs as a result of the malfunction of equipment or facilities;
contaminants in the pipeline system;
fires and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of
property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our
related operations. We are not fully insured against all risks inherent to our business, including offshore wind. Although we
insure most of our underground pipeline systems against property damage, certain of our gathering pipelines are not covered.
We are not insured against all environmental accidents that might occur, which may include toxic tort claims, other than those
considered to be sudden and accidental. In some instances, certain insurance could become unavailable or available only for
reduced amounts of coverage, or may become prohibitively expensive, and we may elect not to carry such a policy.
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Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.
We face cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable.
Cybersecurity threats are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access
to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of
confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to
financial losses from remedial actions, loss of business or potential liability.
Volatility in the capital markets may adversely impact our liquidity.
The capital markets may experience volatility, which may lead to financial uncertainty. Our access to funds under the
Credit Agreement is dependent on the ability of the lenders that are party to the Credit Agreement to meet their funding
obligations. Those lenders may not be able to meet their funding commitments if they experience shortages of capital and
liquidity. If lenders under the Credit Agreement were to fail to fund their share of the Credit Agreement, our available
borrowings could be further reduced. In addition, our borrowing capacity may be further limited by the Credit Agreement’s
financial covenant requirements.
A significant downturn in the economy could adversely affect our results of operations, financial position or cash flows. In
the event that our results were negatively impacted, we could require additional borrowings. A deterioration of the capital
markets could adversely affect our ability to access funds on reasonable terms in a timely manner.
Future disruptions in the global credit markets may make equity and debt markets less accessible and capital markets more
costly, create a shortage in the availability of credit and lead to credit market volatility, which could disrupt our financing plans
and limit our ability to grow.
From time to time, public equity markets experience significant declines, and global credit markets experience a shortage in
overall liquidity and a resulting disruption in the availability of credit. Future disruptions in the global financial marketplace,
including the bankruptcy or restructuring of financial institutions, could make equity and debt markets inaccessible and adversely
affect the availability of credit already arranged and the availability and cost of credit in the future. We have availability under
our Credit Agreement to borrow additional capital, but our ability to borrow under that facility could be impaired if one or more
of our lenders fails to honor its contractual obligation to lend to us.
As a publicly traded partnership, these developments could significantly impair our ability to make acquisitions or finance
growth projects. We distribute all of our available cash, as defined in our partnership agreement, to our unitholders on a quarterly
basis. We rely upon external financing sources, including the issuance of debt and equity securities and bank borrowings, to fund
acquisitions or expansion capital expenditures or fund routine periodic working capital needs. Any limitations on our access to
external capital, including limitations caused by illiquidity or volatility in the capital markets, may impair our ability to complete
future acquisitions and construction projects on favorable terms, if at all. As a result, we may be at a competitive disadvantage as
compared to businesses that reinvest all of their available cash to expand ongoing operations, particularly under adverse economic
conditions.
A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent
third parties determine our credit ratings outside of our control.
A downgrade of our credit rating might increase our cost of borrowing and could require us to post collateral with third parties,
negatively impacting our available liquidity. Our ability to access capital markets could also be limited by a downgrade of our
credit or the credit rating of our general partner, DCP Midstream, LLC. Credit rating agencies perform independent analysis when
assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and
operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and
various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy,
sell or hold our securities, although such credit ratings may affect the market value of our debt instruments. Ratings are subject
to revision or withdrawal at any time by the ratings agencies and no assurance can be given that we or DCP Midstream, LLC will
maintain the current credit ratings.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
We continue to have the ability to incur additional debt, subject to limitations within our Credit Agreement. Our level of
debt could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or
other purposes may be impaired or such financing may not be available on favorable terms;
an increased amount of cash flow will be required to make interest payments on our debt;
our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the
economy generally; and
our debt level may limit our flexibility in responding to changing business and economic conditions.
Our ability to obtain new debt funding or service our existing debt will depend upon, among other things, our future
financial and operating performance, which will be affected by prevailing economic conditions and financial, business,
regulatory and other factors. In addition, our ability to service debt under our Credit Agreement will depend on market interest
rates. If our operating results are not sufficient to service our current or future indebtedness, we may take actions such as
reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling
assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these
actions on satisfactory terms, or at all.
Restrictions in our loan agreements may limit our ability to make distributions to unitholders and may limit our ability to
capitalize on acquisitions and other business opportunities.
Our loan agreements contain covenants limiting our ability to make distributions, incur indebtedness, grant liens,
make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our loan agreements
contain covenants requiring us to maintain a certain leverage ratio and certain other tests. Any subsequent replacement of our
loan agreements or any new indebtedness could have similar or greater restrictions. If our covenants are not met, whether as a
result of reduced production levels of natural gas and NGLs as described above or otherwise, our financial condition, results of
operations and ability to make distributions to our unitholders could be materially adversely affected.
Changes in interest rates may adversely impact our ability to issue additional equity or incur debt, as well as the ability of
exploration and production companies to finance new drilling programs around our systems.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to
increase. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied
distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for
investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield
requirements of investors who invest in our units, and a rising interest rate environment could impair our ability to issue
additional equity or incur debt to make acquisitions, for other purposes. Increased interest costs could also inhibit the financing
of new capital drilling programs by exploration and production companies served by our systems.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
The partnership is a holding company, and our subsidiaries conduct all of our operations and own all of our operating
assets. We do not have significant assets other than equity in our subsidiaries and equity investees. As a result, our ability to
make required payments on our notes depends on the performance of our subsidiaries and their ability to distribute funds to us.
The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit instruments,
applicable state business organization laws and other laws and regulations. If our subsidiaries are prevented from distributing
funds to us, we may be unable to pay all the principal and interest on the notes when due.
Our outstanding notes are senior unsecured obligations of our operating subsidiary, DCP Midstream Operating, LP, or DCP
Operating, and are not guaranteed by any of our subsidiaries. As a result, our notes are effectively junior to DCP
Operating’s existing and future secured debt and to all debt and other liabilities of its subsidiaries.
Our 3.25% Senior Notes due 2015, 2.50% Senior Notes due 2017, 4.95% Senior Notes due 2022 and 3.875% Senior Notes
due 2023, or our notes, are senior unsecured obligations of our indirect 100% owned subsidiary, DCP Operating, and rank
equally in right of payment with all of its other existing and future senior unsecured debt. All of our operating assets are owned
by our subsidiaries, and none of these subsidiaries guarantee DCP Operating’s obligations with respect to the notes. Creditors
of DCP Operating’s subsidiaries may have claims with respect to the assets of those subsidiaries that rank effectively senior to
the notes. In the event of any distribution or payment of assets of such subsidiaries in any dissolution, winding up, liquidation,
reorganization or bankruptcy proceeding, the claims of those creditors would be satisfied prior to making any such distribution
or payment to DCP Operating in respect of its direct or indirect equity interests in such subsidiaries. Consequently, after
satisfaction of the claims of such creditors, there may be little or no amounts left available to make payments in respect of our
notes. As of December 31, 2013, DCP Operating’s subsidiaries had no debt for borrowed money owing to any unaffiliated third
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parties. However, such subsidiaries are not prohibited under the indenture governing the notes from incurring indebtedness in
the future.
In addition, because our notes and our guarantee of our notes are unsecured, holders of any secured indebtedness of us
would have claims with respect to the assets constituting collateral for such indebtedness that are senior to the claims of the
holders of our notes. Currently, we do not have any secured indebtedness. Although the indenture governing our notes places
some limitations on our ability to create liens securing debt, there are significant exceptions to these limitations that will allow
us to secure significant amounts of indebtedness without equally and ratably securing the notes. If we incur secured
indebtedness and such indebtedness is either accelerated or becomes subject to a bankruptcy, liquidation or reorganization, our
assets would be used to satisfy obligations with respect to the indebtedness secured thereby before any payment could be made
on our notes. Consequently, any such secured indebtedness would effectively be senior to our notes and our guarantee of our
notes, to the extent of the value of the collateral securing the secured indebtedness. In that event, our noteholders may not be
able to recover all the principal or interest due under our notes.
Our significant indebtedness and the restrictions in our debt agreements may adversely affect our future financial and
operating flexibility.
As of December 31, 2013, our consolidated indebtedness was $1,935 million, which excludes $10 million in amortized
discount. Our significant indebtedness and the additional debt we may incur in the future for potential acquisitions may
adversely affect our liquidity and therefore our ability to make interest payments on our notes.
Debt service obligations and restrictive covenants in our Credit Agreement, and the indenture and commercial paper dealer
agreements governing our notes may adversely affect our ability to finance future operations, pursue acquisitions and fund
other capital needs as well as our ability to make cash distributions to our unitholders. In addition, this leverage may make our
results of operations more susceptible to adverse economic or operating conditions by limiting our flexibility in planning for, or
reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as
compared to our competitors that have less debt.
If we incur any additional indebtedness, including trade payables, that ranks equally with our notes, the holders of that debt
will be entitled to share ratably with the holders of our notes in any proceeds distributed in connection with any insolvency,
liquidation, reorganization, dissolution or other winding up of us or DCP Operating. This may have the effect of reducing the
amount of proceeds paid to our noteholders. If new debt is added to our current debt levels, the related risks that we now face
could intensify.
Due to our lack of industry diversification, adverse developments in our midstream operations or operating areas would
reduce our ability to make distributions to our unitholders.
We rely on the cash flow generated from our midstream energy businesses, and as a result, our financial condition depends
upon prices of, and continued demand for, natural gas, propane, condensate and NGLs. Due to our lack of diversification in
industry type, an adverse development in one of these businesses may have a significant impact on our company.
We are exposed to the credit risks of our key producer customers and propane purchasers, and any material nonpayment or
nonperformance by our key producer customers or our propane purchasers could reduce our ability to make distributions to
our unitholders.
We are subject to risks of loss resulting from nonpayment or nonperformance by our producer customers and propane
purchasers. Any material nonpayment or nonperformance by our key producer customers or our propane purchasers could
reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers or our propane
purchasers may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that
they may default on their obligations to us.
Terrorist attacks, the threat of terrorist attacks, and sustained military campaigns may adversely impact our results of
operations.
The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001 and the threat of future
terrorist attacks on our industry in general, and on us in particular, is not known at this time. Increased security measures taken
by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertainty surrounding
continued hostilities in the Middle East and North Africa or other sustained military conflicts may affect our operations in
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unpredictable ways, including disruptions of crude oil supplies, propane shipments or storage facilities, and markets for refined
products, and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.
Recent acquisitions may not be beneficial to us.
Acquisitions involve numerous risks, including:
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the failure to realize expected profitability, growth or accretion;
an increase in indebtedness and borrowing costs;
potential environmental or regulatory compliance matters or liabilities;
potential title issues;
the incurrence of unanticipated liabilities and costs; and
the temporary diversion of management’s attention from managing the remainder of our assets to the process of
integrating the acquired businesses.
The assets recently acquired will also be subject to many of the same risks as our existing assets. If any of these risks or
unanticipated liabilities or costs were to materialize, any desired benefits of these acquisitions may not be fully realized, if at
all, and our future financial performance and results of operations could be negatively impacted.
Risks Inherent in an Investment in Our Common Units
Conflicts of interest may exist between our individual unitholders and DCP Midstream, LLC, our general partner, which
has sole responsibility for conducting our business and managing our operations.
DCP Midstream, LLC owns and controls our general partner. Some of our general partner’s directors, and some of its
executive officers, are directors or officers of DCP Midstream, LLC or its owners. Therefore, conflicts of interest may arise
between DCP Midstream, LLC and its affiliates and our unitholders. In resolving these conflicts of interest, our general partner
may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among
others, the following situations:
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neither our partnership agreement nor any other agreement requires DCP Midstream, LLC to pursue a business
strategy that favors us. DCP Midstream, LLC’s directors and officers have a fiduciary duty to make these
decisions in the best interests of the owners of DCP Midstream, LLC, which may be contrary to our interests;
our general partner is allowed to take into account the interests of parties other than us, such as DCP Midstream,
LLC and its affiliates, in resolving conflicts of interest;
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• DCP Midstream, LLC and its affiliates, including Phillips 66 and Spectra Energy, are not limited in their ability to
compete with us. Please read “DCP Midstream, LLC and its affiliates are not limited in their ability to compete
with us” below;
once certain requirements are met, our general partner may make a determination to receive a quantity of our
Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights
without the approval of the special committee of our general partner or our unitholders;
some officers of DCP Midstream, LLC and DCP Midstream GP, LLC who provide services to us also will devote
significant time to the business of DCP Midstream, LLC, and will be compensated by DCP Midstream, LLC for
the services rendered to it;
our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies
available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of
additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to
unitholders;
our general partner determines the amount and timing of any capital expenditures and whether a capital
expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital
expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is
distributed to our unitholders;
our general partner determines which costs incurred by it and its affiliates are reimbursable by us;
our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any
services rendered to us or entering into additional contractual arrangements with any of these entities on our
behalf;
our general partner intends to limit its liability regarding our contractual and other obligations and, in some
circumstances, is entitled to be indemnified by us;
our general partner may exercise its limited right to call and purchase common units if it and its affiliates own
more than 80% of the common units;
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our general partner controls the enforcement of obligations owed to us by our general partner and its
affiliates; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
DCP Midstream, LLC and its affiliates are not limited in their ability to compete with us, which could cause conflicts of
interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of
operations and cash available for distribution to our unitholders.
Neither our partnership agreement nor the Services Agreement, as amended, between us, DCP Midstream, LLC and others
will prohibit DCP Midstream, LLC and its affiliates, including Phillips 66 and Spectra Energy, from owning assets or engaging
in businesses that compete directly or indirectly with us. In addition, DCP Midstream, LLC and its affiliates, including Phillips
66 and Spectra Energy, may acquire, construct or dispose of additional midstream or other assets in the future, without any
obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established
participant in the midstream energy business, and each has significantly greater resources and experience than we have, which
factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for
acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and cash
available for distribution.
Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our
general partner, will be material.
Pursuant to the Services Agreement, as amended, we entered into with DCP Midstream, LLC, our general partner and
others, DCP Midstream, LLC will receive reimbursement for the payment of operating expenses related to our operations and
for the provision of various general and administrative services for our benefit. Payments for these services will be material. In
addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and
environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner.
To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are
unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make
payments of these obligations and liabilities. These factors may reduce the amount of cash otherwise available for distribution
to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units.
Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the
directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its
owner, DCP Midstream, LLC. Our partnership agreement contains provisions that reduce the standards to which our general
partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general
partner to make a number of decisions either in its individual capacity, as opposed to in its capacity as our general partner or
otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and
factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include:
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the exercise of its right to reset the target distribution levels of its incentive distribution rights at higher levels and
receive, in connection with this reset, a number of Class B units that are convertible at any time following the first
anniversary of the issuance of these Class B units into common units;
its limited call right;
its voting rights with respect to the units it owns;
its registration rights; and
its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the
partnership agreement.
By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership
agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general
partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions taken by
our general partner that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its
capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best
interests of our partnership;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the special
committee of the board of directors of our general partner and not involving a vote of our unitholders must be on
terms no less favorable to us than those generally being provided to or available from unrelated third parties or
must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining
whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the
relationships between the parties involved, including other transactions that may be particularly advantageous or
beneficial to us; and provides that our general partner and its officers and directors will not be liable for monetary
damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-
appealable judgment entered by a court of competent jurisdiction determining that the general partner or those
other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter,
acted with knowledge that the conduct was criminal.
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution
levels related to our general partner’s incentive distribution rights without the approval of the special committee of our
general partner or holders of our common units. This may result in lower distributions to holders of our common units in
certain situations.
Our general partner currently has the right to reset the initial cash target distribution levels at higher levels based on the
distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum
quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the
two fiscal quarters immediately preceding the reset election, or the reset minimum quarterly distribution, and the target
distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum
quarterly distribution amount. Currently, our distribution to our general partner related to its incentive distribution rights is at
the highest level.
In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of
Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be
convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of
common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on
the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right
in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per
common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a
time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its
incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash
distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions
based on the initial target distribution levels. As a result, in certain situations, a reset election may cause our common
unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not
issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general
partner incentive distribution rights.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our
business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not
elect our general partner or its board of directors, and have no right to elect our general partner or its board of directors on an
annual or other continuing basis. The board of directors of our general partner are chosen by the members of our general
partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence
or reduction of a takeover premium in the trading price.
Our common units may experience price volatility.
Our common unit price has experienced volatility in the past, and volatility in the price of our common units may occur in
the future as a result of any of the risk factors contained herein and the risks described in our other public filings with the SEC.
For instance, our common units may experience price volatility as a result of changes in investor sentiment with respect to our
competitors, our business partners and our industry in general, which may be influenced by volatility in prices for NGLs,
natural gas and crude oil. In addition, the securities markets have from time to time experienced significant price and volume
40
fluctuations that are unrelated to the operating performance of particular companies but affect the market price of their
securities. These market fluctuations may also materially and adversely affect the market price of our common units.
Even if holders of our common units are dissatisfied, they may be unable to remove our general partner without its consent.
The unitholders may be unable to remove our general partner without its consent because our general partner and its
affiliates own a significant percentage of our outstanding units. The vote of the holders of at least 66 2/3% of all outstanding
units voting together as a single class is required to remove the general partner. As of December 31, 2013, our general partner
and its affiliates owned approximately 23% of our aggregate outstanding common units.
Our partnership agreement restricts the voting rights of our unitholders owning 20% or more of our common units.
Our unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by
a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their
transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot
vote on any matter. Our partnership agreement also contains provisions limiting the ability of our unitholders to call meetings
or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the
manner or direction of management.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price
of our common units and could have a material adverse effect on our business.
Our assets include a 50% interest in CrossPoint Pipeline, LLC, a 40% interest in the Discovery system, a 33.33% interest
in Front Range, a 28.5% interest in Web Duvall, a 20% interest in the Mont Belvieu 1 Fractionator, a 12.5% interest in the
Mont Belvieu Enterprise Fractionator and a 10% interest in the Texas Express Pipeline, which may be deemed to be
“investment securities” within the meaning of the Investment Company Act of 1940. In the future, we may acquire additional
minority owned interests in joint ventures that could be deemed "investment securities." If a sufficient amount of our assets are
deemed to be “investment securities” within the meaning of the Investment Company Act, we would either have to register as
an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our
organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an
investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including
the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or
engage in other transactions involving leverage and require us to add additional directors who are independent of us or our
affiliates. The occurrence of some or all of these events may have a material adverse effect on our business.
Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income
tax purposes in which case we would be treated as a corporation for federal income tax purposes, and be subject to federal
income tax at the corporate tax rate, significantly reducing the cash available for distributions. Additionally, distributions to our
unitholders would be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow
through to our unitholders.
Additionally, as a result of our desire to avoid having to register as an investment company under the Investment Company
Act, we may have to forego potential future acquisitions of interests in companies that may be deemed to be investment
securities within the meaning of the Investment Company Act or dispose of our current interests in any of our assets that are
deemed to be “investment securities.”
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all
of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the
owners of our general partner from transferring all or a portion of their respective ownership interest in our general partner to a
third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of
the general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
We may issue additional units without our unitholders’ approval, which would dilute our unitholders’ existing ownership
interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time
without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or
41
senior rank will have the following effects:
•
•
•
•
•
our unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.
Our general partner including its affiliates may sell units in the public or private markets, which could reduce the market
price of our outstanding common units.
If our general partner or its affiliates holding unregistered units were to dispose of a substantial portion of these units in the
public market, whether in a single transaction or series of transactions, it could reduce the market price of our outstanding
common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell
our common units in the future.
Our general partner has a limited call right that may require our unitholders to sell their units at an undesirable time or
price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have
the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the
common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders
may be required to sell their common units at an undesirable time or price and may not receive any return on their investment.
Our unitholders may also incur a tax liability upon a sale of their units.
The liability of holders of limited partner interests may not be limited if a court finds that unitholder action constitutes
control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those
contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is
organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders
of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other
states in which we do business. Holders of limited partner interests could be liable for any and all of our obligations as if such
holder were a general partner if:
•
•
a court or government agency determined that we were conducting business in a state but had not complied with
that particular state’s partnership statute; or
the right of holders of limited partner interests to act with other unitholders to remove or replace the general
partner, to approve some amendments to our partnership agreement or to take other actions under our partnership
agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under
Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if
the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of
three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the
time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.
Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known
to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be
determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are
non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our being subject to
minimal entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation
for federal income tax purposes, or we become subject to a material amount of entity-level taxation for state tax purposes, it
would substantially reduce the amount of cash available for distribution to our unitholders.
42
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding
our status as a partnership.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon
our current operations that we will be treated as a corporation, the IRS could disagree with the positions we take or a change in
our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or
otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates.
Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and
accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder.
Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be
substantially reduced. Therefore, treatment of us as a corporation for federal tax purposes would result in a material reduction
in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our
common units.
The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax
purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of
that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common
units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal
income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could
make it more difficult or impossible for us to meet the exception which allows publicly traded partnerships that generate
qualifying income to be treated as partnerships (rather than corporations) for U.S. federal income tax purposes, affect or cause
us to change our business activities, or affect the tax consequences of an investment in our common units. For example,
members of the U.S. Congress considered, and the President’s Administration has proposed, substantive changes to the existing
U.S. federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. We are unable to
predict whether any of these changes, or other proposals, will ultimately be enacted. Any such change could negatively impact
the value of an investment in our common units.
Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are
required to pay the State of Texas a margin tax that is assessed at 0.975% of taxable margin apportioned to Texas. Imposition of
such a tax on us by any other state will reduce the cash available for distribution to a unitholder. The partnership agreement
provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum
quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.
Changes in tax laws could adversely affect our performance
We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and
transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes
in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted,
and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.
The IRS may adopt positions that differ from the conclusions of our counsel or from the positions we take, and the IRS's
positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or
all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or
43
positions we take. Any contest with the IRS, and the outcome of any IRS contest, may materially and adversely impact the
market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne
indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
Our unitholders may be required to pay taxes on income from us even if the unitholders do not receive any cash
distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income, which could be different in
amount than the cash we distribute, unitholders will be required to pay any federal income taxes and, in some cases, state and
local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not
receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from
that income.
In the event we issue additional units or engage in certain other transactions in the future, the allocable share of
nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units.
Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder
and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain
circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds
such unitholder’s tax basis in its units.
In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future
offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay
indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income
tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to the our
assets.
Tax gain or loss on disposition of common units could be more or less than expected.
If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount
realized and their tax basis in those common units. Because distributions to unitholders in excess of the total net taxable income
allocated to them for a common unit decreases their tax basis in that common unit, the amount, if any, of such prior excess
distributions will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in
that common unit, even if the price is less than their original cost. Furthermore, a substantial portion of the amount realized,
whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation
recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder
sells its units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax
consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans
and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are
exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which
may be taxable to them. Distributions to non-U.S. persons will be reduced by federal withholding taxes at the highest
applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their
share of our taxable income. If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax
advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common
units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt
depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS
challenge to those positions could adversely affect the amount of tax benefits available to the unitholders. It also could affect
the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the
value of our common units or result in audit adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is
44
transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and
deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is
transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Although the U.S.
Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded
partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee
unitholders, such regulations are not final and do not specifically authorize the use of the proration method we have adopted.
Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge our proration method
or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and
deduction among our unitholders.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed
of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units
during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having
disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units
during the period of the loan to the short seller and such unitholder may recognize gain or loss from such disposition.
Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units
may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a
loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing
their units.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the
general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the
common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and
allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.
Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss
and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover,
subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment
allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation
methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of
income, gain, loss and deduction between the general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss
being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could
have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without
the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the
termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated as a partnership for federal income tax purposes if there is a sale or
exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination, among
other things, would result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns
(and our unitholders could receive two Schedule K-1s if relief from the IRS was not granted, as described below) for one
calendar year. Our termination could also result in a significant deferral of depreciation deductions allowable in computing our
taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year
may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of
termination. Under current law, a technical termination would not affect our classification as a partnership for federal income
tax purposes, but instead, after our termination we would be treated as a new partnership for tax purposes. If treated as a new
partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination
occurred. The IRS has announced a publicly traded partnership technical termination relief procedure, whereby if a publicly
traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership
45
will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting
from the technical termination.
Unitholders may be subject to state and local taxes and return filing requirements in states where they do not reside as a
result of investing in our units.
In addition to federal income taxes, unitholders may be subject to other taxes, including foreign, state and local taxes,
unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which
we conduct business or own property, even if the unitholders do not live in any of those jurisdictions. Unitholders may be
required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these
jurisdictions. Further, the unitholder may be subject to penalties for failure to comply with those requirements. As we make
acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or
an entity level tax. It is each unitholder’s responsibility to file all United States federal, foreign, state and local tax returns.
Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage
of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding the amount of which
may be greater or less than a particular unitholder’s income tax liability to the state generally does not relieve the nonresident
unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for
purposes of determining the amounts distributed by us.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
For details on our plants, fractionation and storage facilities, propane terminals and pipeline systems, please read
“Business - Natural Gas Services Segment,” “Business - NGL Logistics Segment” and “Business - Wholesale Propane
Logistics Segment.” We believe that our properties are generally in good condition, well maintained and are suitable and
adequate to carry on our business at capacity for the foreseeable future.
Our real property falls into two categories: (1) parcels that we own in fee; and (2) parcels in which our interest derives
from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of
such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in
fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and
major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as
lessors. We, or our predecessors, have leased these lands for many years without any material challenge known to us relating to
the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands.
We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or
license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have
satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.
Our principal executive offices are located at 370 17th Street, Suite 2500, Denver, Colorado 80202, our telephone number
is 303-633-2900 and our website address is www.dcppartners.com.
Item 3. Legal Proceedings
We are not a party to any significant legal proceedings, other than those listed below, but are a party to various
administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business.
Management currently believes that the ultimate resolution of these matters, taken as a whole, and after consideration of
amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect upon our
consolidated results of operations, financial position or cash flows. For more information, please read “Environmental
Matters.”
Prospect — In 2011, we received an arbitration claim, or the Claim, filed with the American Arbitration Association by
Prospect Street Energy, LLC and Prospect Street Ventures I, LLC, or together, the Claimants, against EE Group, LLC, or EE
Group, and a number of other parties that previously owned, directly or indirectly, our Marysville NGL storage facility, or
collectively, the Respondents. EE Group is our indirect subsidiary which we acquired in connection with our acquisition
of Marysville Hydrocarbons Holdings, LLC, or Marysville, on December 30, 2010. The Claim involves actions taken and time
periods prior to our ownership of EE Group and Marysville, and includes several causes of action including claims of civil
46
conspiracy, breach of fiduciary duty and fraud. As of February 2014, we have entered into separate settlement agreements with
the Claimants and the other Respondents involved in the arbitration. We believe these settlement agreements substantially
mitigate our liability in this matter and therefore, we consider this matter closed.
Environmental — The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing,
transporting, producing, fractionating, storing or selling natural gas, NGLs and other products is subject to stringent and
complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we
must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality,
hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing,
constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and
regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil
and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties,
the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that,
based on currently known information, compliance with these laws and regulations will not have a material adverse effect on
our consolidated results of operations, financial position or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Market Information
Our common units have been listed on the New York Stock Exchange, or the NYSE, under the symbol “DPM” since
December 2, 2005. The following table sets forth intra-day high and low sales prices of the common units, as reported by the
NYSE, as well as the amount of cash distributions declared per quarter for 2013 and 2012.
Quarter Ended
High
Low
December 31, 2013
September 30, 2013
June 30, 2013
March 31, 2013
December 31, 2012
September 30, 2012
June 30, 2012
March 31, 2012
50.50
58.50
54.38
46.93
47.05
46.50
46.36
49.93
45.02
46.14
45.01
40.44
37.78
39.94
36.47
44.55
Distribution
Per Common
Unit
0.7325
0.7200
0.7100
0.7000
0.6900
0.6800
0.6700
0.6600
As of February 20, 2014, there were approximately 39 unitholders of record of our common units. This number does not
include unitholders whose units are held in trust by other entities. As of February 20, 2014, there were approximately 29,595
beneficial owners (held in street name) of our common units.
Distributions of Available Cash
General - Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our
Available Cash (defined below) to unitholders of record on the applicable record date, as determined by our general partner.
Definition of Available Cash - Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the
end of that quarter:
•
less the amount of cash reserves established by our general partner to:
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments or other agreements; or
47
•
provide funds for distributions to our unitholders and to our general partner for any one or more of the
next four quarters;
•
plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of
determination of Available Cash for the quarter.
Minimum Quarterly Distribution - The Minimum Quarterly Distribution, as set forth in the partnership agreement, is
$0.35 per unit per quarter, or $1.40 per unit per year. Our current quarterly distribution is $0.7325 per unit, or $2.93 per unit
annualized. There is no guarantee that we will maintain our current distribution or pay the Minimum Quarterly Distribution on
the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under
our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of
our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of
Operations - Capital Requirements - Description of Credit Agreement” for a discussion of the restrictions included in our Credit
Agreement that may restrict our ability to make distributions.
General Partner Interest and Incentive Distribution Rights - As of December 31, 2013, the general partner is entitled to
a percentage of all quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest
of 1%. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain
its current general partner interest. The general partner’s interest may be reduced if we issue additional units in the future and
our general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest.
The incentive distribution rights held by our general partner entitle it to receive an increasing share of Available Cash as
pre-defined distribution targets have been achieved. Currently, our distribution to our general partner related to its incentive
distribution rights is at the highest level. Our general partner’s incentive distribution rights were not reduced as a result of our
recent common unit offerings, and will not be reduced if we issue additional units in the future and the general partner does not
contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions
of Available Cash after the Subordination Period section in Note 12 of the Notes to Consolidated Financial Statements in Item
8. “Financial Statements and Supplementary Data” for more details about the distribution targets and their impact on the
general partner’s incentive distribution rights.
On January 28, 2014, we announced that the board of directors of DCP Midstream GP, LLC declared a quarterly
distribution of $0.7325 per unit, which was paid on February 14, 2014, to unitholders of record on February 7, 2014.
Equity Compensation Plans
The information relating to our equity compensation plans required by Item 5 is incorporated by reference to such
information as set forth in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related
Unitholder Matters” contained herein.
Item 6. Selected Financial Data
The following table shows our selected financial data for the periods and as of the dates indicated, which is derived from
the consolidated financial statements. These consolidated financial statements include our accounts, which have been combined
with the historical assets, liabilities and operations of our 100% interest in our East Texas system of which we acquired a
controlling additional 25.1% interest and the remaining 49.9% interest from DCP Midstream, LLC in April 2009 and January
2012, respectively; our 100% interest in our Southeast Texas system of which 33.33% and 66.67% were acquired from DCP
Midstream, LLC in January 2011 and March 2012, respectively; commodity derivative hedge instruments related to the
Southeast Texas storage business, which we acquired from DCP Midstream, LLC in March 2012; and our 80% interest in the
Eagle Ford system, of which 33.33% and 46.67% were acquired from DCP Midstream, LLC in November 2012 and March
2013, respectively. Prior to our acquisition of an additional 25.1% interest in East Texas, we accounted for our initial 25%
interest as an unconsolidated affiliate using the equity method of accounting. Subsequent to our acquisition of the additional
25.1% interest in East Texas, we owned 50.1% of East Texas which we account for as a consolidated subsidiary. We currently
own 100% of East Texas, which we continue to account for as a consolidated subsidiary. Prior to our acquisition of the
remaining 66.67% interest in Southeast Texas, we accounted for our initial 33.33% interest as an unconsolidated affiliate using
the equity method of accounting. Subsequent to our acquisition of the remaining 66.67% interest in Southeast Texas, we own
100% of Southeast Texas which we account for as a consolidated subsidiary. Prior to our acquisition of the additional 46.67%
interest in the Eagle Ford system, we accounted for our initial 33.33% interest as an unconsolidated affiliate using the equity
method of accounting. Subsequent to our acquisition of the additional 46.67% interest in the Eagle Ford system, we own 80%
of the Eagle Ford system which we account for as a consolidated subsidiary. These transactions were between entities under
common control and represented a change in reporting entity; accordingly, our financial information includes the historical
results of entities and interests contributed to us by DCP Midstream, LLC for all periods presented. The information contained
48
herein should be read together with, and is qualified in its entirety by reference to, the consolidated financial statements and the
accompanying notes included elsewhere in this Form 10-K.
Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the data
included herein to not be indicative of our future financial condition or results of operations. A discussion on our critical
accounting estimates is included in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of
Operations”.
The table should also be read together with Item 7. “Management’s Discussion and Analysis of Financial Condition and
Results of Operations.”
2013 (a)
Year Ended December 31,
2012 (a)
2010 (a)
2011 (a)
(Millions, except per unit amounts)
2009 (a)
Statements of Operations Data:
Sales of natural gas, propane, NGLs and condensate
Transportation, processing and other
Gains (losses) from commodity derivative activity,
net (b) (c)
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Step acquisition - equity interest re-measurement
gain
Other expense (income)
Other income - affiliates
Total operating costs and expenses
Operating income
Interest expense
Earnings from unconsolidated affiliates (d)
Income before income taxes
Income tax expense
Net income
Net income attributable to noncontrolling interests
Net income attributable to partners
Less:
Net income attributable to predecessor operations (e)
General partner interest in net income
Net income (loss) allocable to limited partners
Net income (loss) per limited partner unit-basic
Net income (loss) per limited partner unit-diluted
$
$
$
$
$
2,459
232
70
2,761
2,177
193
89
74
—
—
—
2,533
228
(42)
26
212
(1)
211
(13)
198
(33)
(41)
124
2.28
2.28
$
$
$
$
$
3,487
205
8
3,700
3,100
188
133
75
—
(1)
—
3,495
205
(34)
23
194
(1)
193
(30)
163
(63)
(25)
75
1.73
1.72
$
$
$
$
$
3,038
160
3
3,201
2,758
155
115
66
(9)
(2)
(3)
3,080
121
(29)
23
115
(2)
113
(12)
101
(53)
(17)
31
0.86
0.86
$
$
$
$
$
2,274
131
(56)
2,349
2,025
139
103
61
—
1
—
2,329
20
(28)
18
10
(1)
9
(7)
2
(20)
(13)
(31)
(0.99)
(0.99)
2,695
268
17
2,980
2,381
211
93
62
—
8
—
2,755
225
(52)
33
206
(8)
198
(17)
181
(6)
(70)
105
1.34
1.34
$
$
$
$
$
49
Balance Sheet Data (at period end):
Property, plant and equipment, net
Total assets
Accounts payable
Long-term debt
Partners’ equity
Noncontrolling interests
Total equity
Other Information:
Cash distributions declared per unit
Cash distributions paid per unit
2013 (a)
Year Ended December 31,
2012 (a)
2010 (a)
2011 (a)
(Millions, except per unit amounts)
2009 (a)
$
$
$
$
$
$
$
$
$
3,005
4,526
275
1,590
1,945
228
2,173
2.863
2.820
$
$
$
$
$
$
$
$
$
2,550
3,603
223
1,620
1,405
189
1,594
2.700
2.660
$
$
$
$
$
$
$
$
$
2,114
2,912
414
747
1,256
306
1,562
2.548
2.515
$
$
$
$
$
$
$
$
$
1,816
2,607
305
648
1,128
288
1,416
2.438
2.420
$
$
$
$
$
$
$
$
$
1,573
2,171
283
613
798
279
1,077
2.400
2.400
(a) Includes the effect of the following acquisitions prospectively from their respective dates of acquisition: (1) certain
companies acquired from MichCon Pipeline Company in November 2009; (2) the Wattenberg pipeline acquired from
Buckeye Partners, L.P. in January 2010; (3) an additional 5% interest in Collbran Valley Gas Gathering LLC,
acquired from Delta Petroleum Company in February 2010; (4) the Raywood processing plant and Liberty gathering
system acquired in June 2010; (5) an additional 50% interest in Black Lake Pipeline Company, or Black Lake,
acquired from an affiliate of BP PLC in July 2010; (6) Atlantic Energy acquired from UGI Corporation in July 2010;
(7) Marysville Hydrocarbons Holdings, LLC acquired in December 2010; (8) the DJ Basin NGL fractionators
acquired in March 2011; (9) our 100% owned Eagle Plant in August 2011; (10) the remaining 49.9% interest in East
Texas acquired from DCP Midstream, LLC in January 2012; (11) a 10% ownership interest in the Texas Express
Pipeline acquired from Enterprise Products Partners, L.P. in April 2012; (12) a 12.5% interest in the Enterprise
fractionator and a 20% interest in the Mont Belvieu 1 fractionator, acquired from DCP Midstream, LLC in July 2012;
(13) the Crossroads processing plant and 50% interest in CrossPoint Pipeline, LLC, acquired from Penn Virginia
Resource Partners, L.P. in July 2012; (14) the O'Connor plant acquired from DCP Midstream, LLC in August 2013
and (15) the Front Range pipeline acquired from DCP Midstream, LLC in August 2013.
(b) Includes the effect of the commodity derivative hedge instruments related to the Eagle Ford system, of which 33.33%
was acquired from DCP Midstream, LLC in November 2012 and 46.67% was acquired in March 2013; the Goliad
plant, of which 33.33% was acquired from DCP Midstream, LLC in December 2012 and 46.67% was acquired in
March 2013; the Southeast Texas storage business acquired from DCP Midstream, LLC in March 2012 and the NGL
Hedge acquired from DCP Midstream, LLC in April 2009 in connection with the acquisition of a 25.1% interest in
East Texas.
(c) Prior to the acquisition of the remaining 49.9% limited liability company interest in East Texas in January 2012, we
hedged our proportionate ownership of East Texas. Results shown include the unhedged portion of East Texas owned
by DCP Midstream, LLC. Our consolidated results depict 75% of East Texas unhedged in all periods prior to the
second quarter of 2009 and the remaining 49.9% of East Texas unhedged for all periods from the second quarter of
2009 through the fourth quarter of 2011. Our consolidated results depict 100% of the Southeast Texas system
unhedged in 2009 and 2010 and 66.67% unhedged in 2011 and through March 2012 corresponding with DCP
Midstream, LLC’s ownership interest in Southeast Texas. Our consolidated results depict 100% of the Eagle Ford
system unhedged in 2009 and through October 2012, and 66.67% from November 2012 through March 2013, and
20% from April 2013 through December 31, 2013 corresponding with DCP Midstream, LLC’s ownership interest in
the Eagle Ford system.
(d) Includes our proportionate share of the earnings of our unconsolidated affiliates. Earnings include the amortization of
the net difference between the carrying amount of the investments and the underlying equity of the entities.
(e) Includes the net income attributable to an additional 25.1% limited liability company interest in East Texas prior to
the date of our acquisition from DCP Midstream, LLC in April 2009; the initial 33.33% interest in Southeast Texas
prior to the date of our acquisition from DCP Midstream, LLC in January 2011; the remaining 66.67% interest in
Southeast Texas and commodity derivative hedge instruments prior to the date of our acquisition from DCP
Midstream, LLC in March 2012; the initial 33.33% interest in the Eagle Ford system prior to the date of our
acquisition from DCP Midstream, LLC in November 2012; and the additional 46.67% interest in the Eagle Ford
system prior to the date of our acquisition from DCP Midstream, LLC in March 2013.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion analyzes our financial condition and results of operations. You should read the following
discussion of our financial condition and results of operations in conjunction with our consolidated financial statements and
notes included elsewhere in this annual report.
Overview
We are a Delaware limited partnership formed by DCP Midstream, LLC to own, operate, acquire and develop a
diversified portfolio of complementary midstream energy assets. Our operations are organized into three business segments:
Natural Gas Services, NGL Logistics and Wholesale Propane Logistics.
Our business is impacted by commodity prices, which we significantly mitigate on an overall Partnership basis through a
multi-year hedging program, volumes of throughput and sales of natural gas, NGLs and condensate. Various factors impact
both commodity prices and volumes. Commodity prices historically have been volatile and continue to be volatile. Crude oil
prices have generally remained at favorable levels, while NGL and natural gas prices remain modest due to increasing supplies.
The twelve-month average New York Mercantile Exchange, or NYMEX, price of natural gas futures contracts per MMBtu was
$4.19, $3.54, and $3.24 as of December 31, 2013, 2012 and 2011, respectively. The twelve-month average price per gallon for
NGLs was $0.84, $1.08 and $1.39 as of December 31, 2013, 2012 and 2011, respectively, and the price of crude oil per barrel
was $98.04, $94.16 and $95.12 as of December 31, 2013, 2012 and 2011, respectively.
Although we have not experienced a significant impact to our natural gas throughput volumes as a result of decreased
commodity prices, if commodity prices remain weak for a sustained period, our natural gas throughput volumes may be
impacted, particularly if producers were to shut in gas. Natural gas drilling activity levels vary by geographic area, but in
general, drilling remains firm in areas with liquids rich gas. Drilling remains weak in certain areas with dry gas where relatively
lower commodity prices currently do not support the economics of drilling. However, advances in technology, such as
horizontal drilling and hydraulic fracturing in shale plays, have led to certain geographic areas becoming increasingly
accessible. Our long-term view is that commodity prices will be at levels that we believe will support sustained or increasing
levels of domestic natural gas production. We use direct NGL hedges to mitigate a significant portion of our NGL price
exposure; however, weakening of the relationship of natural gas liquids to crude oil prices does modestly impact the
effectiveness of our hedging program to mitigate our exposure to price fluctuations where we use crude oil to hedge our NGL
price exposure.
Our fee-based business which represents a significant portion of our estimated margins, plus our highly hedged
commodity position, mitigated a significant portion of our natural gas, NGL, and condensate commodity price risk.
NGL prices are also impacted by the demand from petrochemical and refining industries. The petrochemical industry is
making significant investment in building or expanding facilities to convert chemical plants from heavier oil-based feed stock
to lighter NGL-based feed stock, including ethane. This increased demand should support increasing ethane supplies. In
addition, propane export facilities are being expanded or built, which is supporting increasing propane supply. Although there
can be, and has been, near-term volatility in NGL prices, longer term we believe there will be sufficient demand in NGLs to
support increasing supply.
The global economic outlook continues to be cause for concern for U.S. financial markets and businesses and investors
alike. This uncertainty may contribute to volatility in financial and commodity markets.
The amount of NGLs we produce, fractionate, transport, sell and store, may be reduced if the pipelines and storage and
fractionation facilities to which we deliver NGLs are capacity constrained and cannot, or will not, accept the NGLs. Recent
capacity expansions are coming online, which we believe will mitigate the risk of these NGL capacity constraints.
Increased activity levels in liquids rich gas basins combined with access to capital markets at relatively low historical
costs have enabled us to continue executing our multi-faceted growth strategy, with an emphasis on dropdowns from DCP
Midstream, LLC. Our multi-faceted growth strategy may take numerous forms such as dropdown opportunities from DCP
Midstream, LLC, joint venture opportunities, organic build opportunities within our footprint and third-party acquisitions.
Dropdowns from DCP Midstream, LLC in 2013 totaled over $1 billion. In 2014, we will continue executing our multi-faceted
growth strategy, with an emphasis on dropdowns from DCP Midstream, LLC and organic growth.
51
Some of our recent growth projects include the following:
• On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC for the
contribution or acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership
interest in each DCP Southern Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills
Pipeline, LLC, which owns the Sand Hills pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant
located in Weld County, Colorado, or the Lucerne 1 plant; and (iv) a 200 MMcf/d cryogenic natural gas processing
plant also located in Weld County, Colorado, which is currently under construction, or the Lucerne 2 plant. Total
consideration for this transaction at closing is $1,220 million, subject to certain working capital and other
customary adjustments. This transaction is expected to close in March 2014, subject to customary closing
conditions, and components of the transaction may close separately.
• On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP
Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP LaSalle Plant
LLC, or the LaSalle Transaction, for consideration of $209 million, subject to certain customary purchase price
adjustments. DCP LaSalle Plant LLC owns the O'Connor plant, a cryogenic natural gas processing plant with
initial capacity of 110 MMcf/d, previously known as the LaSalle plant, in the DJ Basin in Weld County, Colorado.
In connection with the LaSalle Transaction, we also entered into a 15-year fee-based processing agreement with an
affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of
75% of the plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor
plant. The processing agreement commenced with commercial operations of the new plant in October 2013. As of
February 2014, the O'Connor plant expansion to 160 MMcf/d is mechanically complete.
• On August 5, 2013, we entered into a purchase and sale agreement with a 100% owned subsidiary of DCP
Midstream, LLC pursuant to which the Partnership acquired all of the membership interests in DCP Midstream
Front Range LLC, or Front Range, for consideration of $86 million, subject to certain customary purchase price
adjustments. Front Range owns a 33.33% equity interest in Front Range Pipeline LLC, a joint venture with
affiliates of Enterprise and Anadarko Petroleum Corporation, which was formed to construct the Front Range
pipeline, a new raw NGL mix pipeline that originates in the DJ Basin and extends approximately 435 miles to
Skellytown, Texas. Enterprise is the operator of the pipeline, which was placed into service in February 2014.
• On March 28, 2013, we acquired an additional 46.67% interest in the Eagle Ford system from DCP Midstream,
LLC and fixed price commodity derivative hedges for a three-year period for aggregate consideration of $626
million. We have an 80% interest in the construction of the Goliad 200 MMcf/d natural gas processing plant,
including fixed price commodity price hedges, representing a total investment of approximately $290 million,
which was placed into service in February 2014.
• The construction of the Texas Express pipeline, of which we own a 10% interest, is complete and commenced
operations in the fourth quarter of 2013. Originating near Skellytown in Carson County, Texas, the 20-inch
diameter Texas Express pipeline extends approximately 580 miles to Enterprise’s natural gas liquids fractionation
and storage complex at Mont Belvieu, Texas, and provides access to other third party facilities in the area.
• Our construction of our 100% owned Eagle 200 MMcf/d natural gas processing plant is complete and commenced
operations in the first quarter of 2013.
• Our expansion plan for Discovery's Keathley Canyon natural gas gathering pipeline system is progressing and is
expected to be completed in the fourth quarter of 2014.
Our capital markets execution has positioned us well in terms of both liquidity and cost of capital to execute our growth
plans, including dropdown opportunities with DCP Midstream, LLC. During the year ended December 31, 2013, we received
net proceeds of $1,082 million from the issuance of 24,897,977 of our common units and $490 million through a public debt
offering of 3.875% 10-year Senior Notes, which were used to finance our growth opportunities. In October 2013, we entered
into a Commercial Paper Program pursuant to which we had $335 million outstanding as of December 31, 2013 which is
included short-term borrowings in our consolidated balance sheets. As of December 31, 2013, the unused capacity under the
Credit Agreement was $664 million, all of which was available for general working capital purposes, providing liquidity to
continue to execute on our growth plans.
We raised our distribution for the fourth quarter of 2013, resulting in a 6% increase in our quarterly distribution rate over
the rate declared for the fourth quarter of 2012. The distribution reflects our business results as well as our recent execution on
growth opportunities.
52
General Trends and Outlook
During 2014, our strategic objectives will continue to focus on maintaining stable distributable cash flows from our
existing assets and executing on growth opportunities to increase our long-term distributable cash flows. We believe the key
elements to stable distributable cash flows are the diversity of our asset portfolio, our fee-based business which represents a
significant portion of our estimated margins, plus our highly hedged commodity position, the objective of which is to protect
against downside risk in our distributable cash flows.
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance
capital expenditures of between $35 million and $45 million, and approved expenditures for expansion capital of between $500
million and $600 million, for the year ending December 31, 2014. Expansion capital expenditures include construction of
Discovery’s Keathley Canyon Connector, which is shown as investments in unconsolidated affiliates, construction of the
Lucerne 2 plant, the Marysville NGL storage project and expansion of our Chesapeake facility, among other projects. The
board of directors may, at its discretion, approve additional growth capital during the year.
We expect to continue to pursue a multi-faceted growth strategy, which includes maximizing dropdown opportunities
provided by our partnership with DCP Midstream, LLC, capitalizing on organic expansion and opportunities pursuing strategic
third party acquisitions in order to grow our distributable cash flows. Given the significant level of growth opportunities
currently in DCP Midstream, LLC’s footprint, we would expect substantial emphasis on our dropdown objective over the next
few years.
We anticipate our business to continue to be affected by the following key trends. Our expectations are based on
assumptions made by us and information currently available to us. To the extent our underlying assumptions about or
interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural Gas Gathering and Processing Margins - Except for our fee-based contracts, which may be impacted by
throughput volumes, our natural gas gathering and processing profitability is dependent upon commodity prices, natural gas
supply, and demand for natural gas, NGLs and condensate. Commodity prices, which are impacted by the balance between
supply and demand, have historically been volatile. Throughput volumes could decline, particularly in areas with lower NGL
content, should natural gas prices and drilling levels continue to experience weakness. Our long-term view is that as economic
conditions improve, commodity prices should remain at levels that would support continued natural gas production in the
United States. During 2013, petrochemical demand remained for NGLs as NGLs were a lower cost feedstock when compared
to crude oil derived feedstocks. We anticipate demand for NGLs by the petrochemical industry will continue in 2014.
NGL Logistics - The volumes of NGLs transported on our pipelines, fractionated in our fractionation facilities and stored
in our storage facility are dependent on the level of production of NGLs from processing plants connected to our assets. When
natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of
natural gas compared to the value of NGLs and because of the increased cost of separating the NGLs from the natural gas. As a
result, we have experienced periods in the past, in which higher natural gas or lower NGL prices reduce the volume of NGLs
extracted at plants connected to our NGL pipelines, fractionation and storage facilities and, in turn, lower the NGL throughput
on our assets.
Wholesale Propane Supply and Demand - Due to our multiple propane supply sources, propane supply contractual
arrangements, significant storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally
able to provide our propane distribution customers with reliable supplies of propane during peak demand periods of tight
supply, usually in the winter months when their customers consume the most propane for heating.
Factors That May Significantly Affect Our Results
Transfers of net assets between entities under common control that represent a change in reporting entity are accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative
information similar to the pooling method. Accordingly, our consolidated financial statements have been adjusted to include the
historical results of our 80% interest in the Eagle Ford system and 100% interest in Southeast Texas for all periods presented,
similar to the pooling method. The financial statements of our predecessor have been prepared from the separate records
maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the
results of operations if our predecessor had been operated as an unaffiliated entity.
Natural Gas Services Segment
53
Our results of operations for our Natural Gas Services segment are impacted by (1) increases and decreases in the volume
and quality of natural gas that we gather and transport through our systems, which we refer to as throughput, (2) the associated
Btu content of our system throughput and our related processing volumes, (3) the prices of and relationship between
commodities such as NGLs, crude oil and natural gas, (4) the operating efficiency and reliability of our processing facilities, (5)
potential limitations on throughput volumes arising from downstream and infrastructure capacity constraints, (6) the terms of
our processing contract arrangements with producers, and (7) increases and decreases in the volume, price and basis
differentials of natural gas associated with our natural gas storage and pipeline assets, as well as our underlying derivatives
associated with these assets. This is not a complete list of factors that may impact our results of operations but, rather, are those
we believe are most likely to impact those results.
Throughput and operating efficiency generally are driven by wellhead production, plant recoveries, operating availability
of our facilities, physical integrity and our competitive position on a regional basis, and more broadly by demand for natural
gas, NGLs and condensate. Historical and current trends in the price changes of commodities may not be indicative of future
trends. Throughput and prices are also driven by demand and take-away capacity for residue natural gas and NGLs.
Our processing contract arrangements can have a significant impact on our profitability and cash flow. Our actual contract
terms are based upon a variety of factors, including natural gas quality, geographic location, the commodity pricing
environment at the time the contract is executed, customer requirements and competition from other midstream service
providers. Our gathering and processing contract mix and, accordingly, our exposure to natural gas, NGL and condensate
prices, may change as a result of producer preferences, impacting our expansion in regions where certain types of contracts are
more common as well as other market factors.
The capacity on certain downstream NGL and natural gas infrastructure has tightened in recent periods and can be further
constrained seasonally or when there is severe weather. Constrained market outlets may restrict us from operating our facilities
optimally.
Our Natural Gas Services segment operating results are impacted by market conditions causing variability in natural gas,
crude oil and NGL prices. The midstream natural gas industry is cyclical, with the operating results of companies in the
industry significantly affected by the prevailing price of NGLs. Although the prevailing price of residue natural gas has less
short-term significance to our operating results than the price of NGLs, in the long-term, the growth and sustainability of our
business depends on commodity prices being at levels sufficient to provide incentives and capital for producers to explore and
produce natural gas.
The prices of NGLs, crude oil and natural gas can be extremely volatile for periods of time, and may not always have a
close relationship. Due to our hedging program, changes in the relationship of the price of NGLs and crude oil may cause our
commodity price exposure to vary, which we have attempted to capture in our commodity price sensitivities in “Quantitative
and Qualitative Disclosures about Market Risk.” Our results may also be impacted as a result of non-cash lower of cost or
market inventory or imbalance adjustments, which occur when the market value of commodities decline below our carrying
value.
The natural gas services business is highly competitive in our markets and includes major integrated oil and gas
companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store and/or
market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during
periods of high commodity prices for crude oil, natural gas and/or natural gas liquids. Competition is also increased in those
geographic areas where our commercial contracts with our customers are shorter in length of term and therefore must be
renegotiated on a more frequent basis.
NGL Logistics Segment
Our NGL Logistics segment operating results are impacted by, among other things, the throughput volumes of the NGLs
we transport on our NGL pipelines and the volumes of NGLs we fractionate and store. We transport, fractionate and store
NGLs primarily on a fee basis. Throughput may be negatively impacted as a result of our customers operating their processing
plants in ethane rejection mode, often as a result of low ethane prices relative to natural gas prices. Factors that impact the
supply and demand of NGLs, as described above in our Natural Gas Services segment, may also impact the throughput and
volume for our NGL Logistics segment.
54
Wholesale Propane Logistics Segment
Our Wholesale Propane Logistics segment operating results are impacted by our ability to provide our propane
distribution customers with reliable supplies of propane. We use physical inventory, physical purchase agreements and financial
derivative instruments, with DCP Midstream, LLC or third parties, which typically match the quantities of propane subject to
fixed price sales agreements to mitigate our commodity price risk. Our results may also be impacted as a result of non-cash
lower of cost or market inventory adjustments, which occur when the market value of propane declines below our carrying
value. We generally recover lower of cost or market inventory adjustments in subsequent periods through the sale of inventory,
or settlement of financial derivative instruments. There may be positive or negative impacts on sales volumes and gross margin
from supply disruptions and weather conditions in the mid-Atlantic, upper midwestern and northeastern areas of the United
States. Our annual sales volumes of propane may decline when these areas experience periods of milder weather in the winter
months. Volumes may also be impacted by conservation and reduced demand in a recessionary environment.
The wholesale propane business is highly competitive in our market areas which include the mid-Atlantic, upper midwest
and northeastern areas of the United States. Our competitors include major integrated oil and gas and energy companies,
interstate and intrastate pipelines, as well as marketers and wholesalers.
Weather
The economic impact of severe weather may negatively affect the nation’s short-term energy supply and demand, and
may result in commodity price volatility. Additionally, severe weather may restrict or prevent us from fully utilizing our assets,
by damaging our assets, interrupting utilities, and through possible NGL and natural gas curtailments downstream of our
facilities, which restricts our production. These impacts may linger past the time of the actual weather event. Severe weather
may also impact the supply availability and propane demand in our Wholesale Propane Logistics segment. Although we carry
insurance on the vast majority of our assets, insurance may be inadequate to cover our loss in some instances, and in certain
circumstances we have been unable to obtain insurance on commercially reasonable terms, if at all. We have recently
experienced cold weather and freezing temperatures in certain regions where our assets are located but the effects did not have
a material impact on our operations.
Capital Markets
Volatility in the capital markets may impact our business in multiple ways, including limiting our producers’ ability to
finance their drilling programs and limiting our ability to fund our operations through dropdowns, organic growth projects and
acquistions. These events may impact our counterparties’ ability to perform under their credit or commercial obligations.
Where possible, we have obtained additional collateral agreements, letters of credit from highly rated banks, or have managed
credit lines to mitigate a portion of these risks.
Impact of Inflation
Inflation has been relatively low in the United States in recent years. However, the inflation rates impacting our business
fluctuate throughout the broad economic and energy business cycles. Consequently, our costs for chemicals, utilities, materials
and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of
relatively high energy commodity prices.
Other
The above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline
in our unit price, may negatively impact our results of operations, and may increase the likelihood of a non-cash impairment
charge or non-cash lower of cost or market inventory adjustments.
Recent Events
On January 28, 2014, we announced that the board of directors of the General Partner declared a quarterly distribution of
$0.7325 per unit, payable on February 14, 2014 to unitholders of record on February 7, 2014.
On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC for the contribution or
acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern
Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills
pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant;
55
and (iv) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under
construction, or the Lucerne 2 plant. Total consideration for this transaction at closing is $1,220 million, subject to certain
working capital and other customary adjustments. This transaction is expected to close in March 2014, subject to customary
closing conditions, and components of the transaction may close separately. The Southern Hills pipeline is engaged in the
business of transporting NGLs, and consists of approximately 800 miles of pipeline, with an expected capacity of 175 MBbls/d
after completion of planned pump stations. The pipeline provides NGL takeaway service from the Midcontinent to fractionation
facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub.The Southern Hills pipeline began taking flows
in the first quarter of 2013 and was placed into service in June 2013. The Sand Hills pipeline is also engaged in the business of
transporting NGLs and consists of approximately 720 miles of pipeline, with an expected initial capacity of 200 MBbls/d after
completion of pump stations, and possible further capacity increases with the installation of additional pump stations. The
pipeline provides NGL takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas
Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills pipeline began taking flows in the fourth quarter of 2012
and was placed into service in June 2013.
Our Operations
We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided
into our Natural Gas Services segment, our NGL Logistics segment and our Wholesale Propane Logistics segment.
Natural Gas Services Segment
Results of operations from our Natural Gas Services segment are determined primarily by the volumes of natural gas
gathered, compressed, treated, processed, transported, stored and sold through our gathering, processing and pipeline systems;
the volumes of NGLs and condensate sold; and the level of our realized natural gas, NGL and condensate prices. We generate
our revenues and our gross margin for our Natural Gas Services segment principally from contracts that contain a combination
of the following arrangements:
• Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the
following services: gathering, compressing, treating, processing, transporting or storing natural gas. Our fee-based
arrangements include natural gas arrangements pursuant to which we obtain natural gas at the wellhead or other
receipt points, at an index related price at the delivery point less a specified amount, generally the same as the
transportation fees we would otherwise charge for transportation of natural gas from the wellhead location to the
delivery point. The revenues we earn are directly related to the volume of natural gas or NGLs that flows through
our systems and are not directly dependent on commodity prices. However, to the extent a sustained decline in
commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced.
• Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase
natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our
gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and
condensate based on index prices from published index market prices. We remit to the producers either an agreed-
upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and
condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs
and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between
the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we
do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference
between the proceeds received and the amount remitted back to the producer related to NGLs and condensate.
Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue
natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these
arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate
directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements
relate directly with the price of NGLs and condensate.
56
In addition to the above contract types, we have keep-whole arrangements, which are estimated to generate an insignificant
portion of our gross margin. Discovery, in which we have a 40% interest, also has keep-whole arrangements. Under the terms
of a keep-whole processing contract, natural gas is gathered from the producer for processing, the NGLs and condensate are
sold and the residue natural gas is returned to the producer with a Btu content equivalent to the Btu content of the natural gas
gathered. This arrangement keeps the producer whole to the thermal value of the natural gas received. Under this type of
contract, we are exposed to the frac spread. The frac spread is the difference between the value of the NGLs and condensate
extracted from processing and the value of the Btu equivalent of the residue natural gas. We benefit in periods when NGL and
condensate prices are higher relative to natural gas prices when that frac spread exceeds our operating costs. Fluctuations in
commodity prices are expected to continue to impact the operating costs of these entities.
The natural gas supply for our gathering pipelines and processing plants is derived primarily from natural gas wells located
in Arkansas, Colorado, Louisiana, Michigan, Oklahoma, Texas, Wyoming and the Gulf of Mexico. We identify primary
suppliers as those individually representing 10% or more of our total natural gas supply. We had one supplier of natural gas
representing 10% or more of our total natural gas supply during the year ended December 31, 2013. We actively seek new
supplies of natural gas, both to offset natural declines in the production from connected wells and to increase throughput
volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting
new wells drilled on dedicated acreage, or by obtaining natural gas that has been directly received or released from other
gathering systems.
We sell natural gas to marketing affiliates of natural gas pipelines, integrated oil companies and DCP Midstream, LLC,
national wholesale marketers, industrial end-users and gas-fired power plants. We typically sell natural gas under market index
related pricing terms. The NGLs extracted from the natural gas at our processing plants are sold at market index prices to DCP
Midstream, LLC or its affiliates, or to third parties. In addition, under our merchant arrangements, various DCP Midstream
LLC affiliates purchase natural gas from third parties at wellheads, pipeline interconnect and pooling points, as well as residue
gas from our Northern Louisiana system, and then resell the aggregated natural gas to third parties.
We manage the commodity price risk of our supply portfolio and sales portfolio with both physical and financial
transactions. As a service to our customers, we may enter into physical fixed price natural gas purchases and sales, utilizing
financial derivatives to swap this fixed price risk back to market index. We manage commodity price risk related to our natural
gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas
storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal
short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection,
withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk
of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our
physical purchases and sales of gas, including injections and withdrawals from storage.
NGL Logistics Segment
Our pipelines, fractionation facilities and storage facility provide transportation, fractionation and storage services for
customers, primarily on a fee basis. We have entered into contractual arrangements with DCP Midstream, LLC and others that
generally require customers to pay us to transport or store NGLs pursuant to a fee-based rate that is applied to volumes.
Therefore, the results of operations for this business segment are generally dependent upon the volume of product transported,
fractionated or stored and the level of fees charged to customers. We do not take title to the products transported on our NGL
pipelines, fractionated in our fractionation facilities or stored in our storage facility; rather, the customer retains title and the
associated commodity price risk. DCP Midstream, LLC provides 100% of volumes transported on the Wattenberg and
Seabreeze pipelines. The volumes of NGLs transported on our pipelines are dependent on the level of production of NGLs from
processing plants connected to our NGL pipelines. When natural gas prices are high relative to NGL prices, it is less profitable
to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased
cost of separating the NGLs from the natural gas. As a result, we have experienced periods in the past, in which higher natural
gas or lower NGL prices reduce the volume of NGLs extracted at plants connected to our NGL pipelines and, in turn, lower the
NGL throughput on our assets. DCP Midstream, LLC, the largest gatherer and processor in the DJ Basin, delivers NGLs to our
fractionation facilities under a long-term fractionation agreement. Our storage facility in Marysville, Michigan provides storage
and related services primarily to regional refining and petrochemical companies and NGL marketers operating in the liquid
hydrocarbons industry.
Wholesale Propane Logistics Segment
57
We operate a wholesale propane logistics business in the mid-Atlantic, upper midwest and northeastern United States. We
purchase large volumes of propane supply from natural gas processing plants and fractionation facilities, and crude oil
refineries, primarily located in the Texas and Louisiana Gulf Coast area, Canada and other international sources, and transport
these volumes of propane supply by pipeline, rail or ship to our terminals and storage facilities in the mid-Atlantic, midwest
and the northeastern areas of the United States. We identify primary suppliers as those individually representing 10% or more
of our total propane supply. Our four primary suppliers of propane, one of which is an affiliated entity, represented
approximately 85% of our propane supplied during the year ended December 31, 2013. We primarily sell propane on a
wholesale basis to propane distributors who in turn resell propane to their customers. We also sell propane in the wholesale
market.
Due to our multiple propane supply sources, annual and long-term propane supply purchase arrangements, significant
storage capabilities, and multiple terminal locations for wholesale propane delivery, we are generally able to provide our
propane distribution customers with reliable supplies of propane during periods of tight supply, such as the winter months when
their customers generally consume the most propane for home heating. In particular, we generally offer our customers the
ability to obtain propane supply volumes from us in the winter months that are generally significantly greater than their
purchases of propane from us in the summer. We believe these factors allow us to maintain our generally favorable
relationships with our customers.
We manage our wholesale propane margins by selling propane to propane distributors under annual sales agreements
negotiated each spring which specify floating price terms that provide us a margin in excess of our floating index-based supply
costs under our supply purchase arrangements. Our portfolio of multiple supply sources and storage capabilities allows us to
actively manage our propane supply purchases and to lower the aggregate cost of supplies. Based on the carrying value of our
inventory, timing of inventory transactions and the volatility of the market value of propane, we have historically and may
continue to periodically recognize non-cash lower of cost or market inventory adjustments. In addition, we may use financial
derivatives to manage the value of our propane inventories.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These
measurements include the following: (1) volumes; (2) gross margin and segment gross margin; (3) operating and maintenance
expense, and general and administrative expense; (4) adjusted EBITDA, (5) adjusted segment EBITDA; and (6) distributable
cash flow. Gross margin, segment gross margin, adjusted EBITDA, adjusted segment EBITDA, and distributable cash flow are
not measures under accounting principles generally accepted in the United States of America, or GAAP. To the extent
permitted, we present certain non-GAAP measures and reconciliations of those measures to their most directly comparable
financial measures as calculated and presented in accordance with GAAP. These non-GAAP measures may not be comparable
to a similarly titled measure of another company because other entities may not calculate these non-GAAP measures in the
same manner.
Volumes - We view throughput and storage volumes for our Natural Gas Services segment and our NGL Logistics
segment, and sales volumes for our Wholesale Propane Logistics segment as important factors affecting our profitability. We
gather and transport some of the natural gas and NGLs under fee-based transportation contracts. Revenue from these contracts
is derived by applying the rates stipulated to the volumes transported. Pipeline throughput volumes from existing wells
connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or to increase throughput
levels on these pipelines and the utilization rate of our natural gas processing plants, we must continually obtain new supplies
of natural gas and NGLs. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are
impacted by: (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas
currently dedicated to our pipelines; and (2) our ability to compete for volumes from successful new wells in other areas. The
throughput volumes of NGLs and gas on our pipelines are substantially dependent upon the quantities of NGLs and gas
produced at our processing plants, as well as NGLs and gas produced at other processing plants that have pipeline connections
with our NGL and gas pipelines. We regularly monitor producer activity in the areas we serve and in which our pipelines are
located, and pursue opportunities to connect new supply to these pipelines. We also monitor our inventory in our NGL and gas
storage facilities, as well as overall demand for storage based on seasonal patterns and other market factors such as weather and
overall demand.
Reconciliation of Non-GAAP Measures
Gross Margin and Segment Gross Margin — We view our gross margin as an important performance measure of the
core profitability of our operations. We review our gross margin monthly for consistency and trend analysis.
58
We define gross margin as total operating revenues, including commodity derivative activity, less purchases of natural
gas, propane and NGLs, and we define segment gross margin for each segment as total operating revenues, including
commodity derivative activity, for that segment less commodity purchases for that segment. Our gross margin equals the sum
of our segment gross margins. Gross margin and segment gross margin are primary performance measures used by
management, as these measures represent the results of product sales and purchases, a key component of our operations. As an
indicator of our operating performance, gross margin and segment gross margin should not be considered an alternative to, or
more meaningful than, operating revenues, net income or loss, net income or loss attributable to partners, operating income,
cash flows from operating activities or any other measure of financial performance presented in accordance with accounting
principles generally accepted in the United States of America, or GAAP.
Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners less interest income,
noncontrolling interest in depreciation and income tax expense and non-cash commodity derivative gains, plus interest expense,
income tax expense, depreciation and amortization expense and non-cash commodity derivative losses. Our adjusted EBITDA
may not be comparable to a similarly titled measure of another company because other entities may not calculate this measure
in the same manner.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or loss, net income or
loss attributable to partners, operating income, cash flows from operating activities or any other measure of financial
performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt
obligations.
Adjusted EBITDA is used as a supplemental liquidity and performance measure and adjusted segment EBITDA is used
as a supplemental performance measure by our management and by external users of our financial statements, such as
investors, commercial banks, research analysts and others to assess:
•
•
•
•
financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to those of other companies in the midstream energy
industry, without regard to financing methods or capital structure;
viability and performance of acquisitions and capital expenditure projects and the overall rates of return on
investment opportunities; and
in the case of Adjusted EBITDA, the ability of our assets to generate cash sufficient to pay interest costs, support
our indebtedness, make cash distributions to our unitholders and general partner, and finance maintenance capital
expenditures.
Adjusted Segment EBITDA — We define adjusted segment EBITDA for each segment as segment net income or loss
attributable to partners less non-cash commodity derivative gains for that segment, plus depreciation and amortization expense
and non-cash commodity derivative losses for that segment, adjusted for any noncontrolling interest on depreciation and
amortization expense for that segment. Our adjusted segment EBITDA may not be comparable to similarly titled measures of
other companies because they may not calculate adjusted segment EBITDA in the same manner.
Adjusted segment EBITDA should not be considered in isolation or as an alternative to our financial measures presented
in accordance with GAAP, including operating revenues, net income or loss attributable to Partners, or any other measure of
performance presented in accordance with GAAP.
The accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment
EBITDA to its most directly comparable GAAP financial measure.
Distributable Cash Flow — We define Distributable Cash Flow as net cash provided by or used in operating activities,
less maintenance capital expenditures, net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of
derivative instruments, proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation
and income tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used
in operating activities. Maintenance capital expenditures are cash expenditures made to maintain our cash flows, operating or
earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance
and safety improvements. Maintenance capital expenditures also include certain well connects, and may include the acquisition
or construction of new capital assets. Non-cash mark-to-market of derivative instruments is considered to be non-cash for the
purpose of computing Distributable Cash Flow because settlement will not occur until future periods, and will be impacted by
future changes in commodity prices and interest rates. Distributable Cash Flow is used as a supplemental liquidity and
59
performance measure by our management and by external users of our financial statements, such as investors, commercial
banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.
Our Distributable Cash Flow may not be comparable to a similarly titled measure of another company because other
entities may not calculate Distributable Cash Flow in the same manner. Our gross margin, segment gross margin, adjusted
EBITDA and adjusted segment EBITDA may not be comparable to a similarly titled measure of another company because
other entities may not calculate these measures in the same manner. The following table sets forth our reconciliation of certain
non-GAAP measures:
60
Reconciliation of Non-GAAP Measures
Reconciliation of net income attributable to partners
to gross margin:
Net income attributable to partners
Interest expense
Income tax expense
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other expense (income)
Earnings from unconsolidated affiliates
Net income attributable to noncontrolling interests
Gross margin
Non-cash commodity derivative mark-to-market (a)
Reconciliation of segment net income attributable to
partners to segment gross margin:
Natural Gas Services segment:
Segment net income attributable to partners
Operating and maintenance expense
Depreciation and amortization expense
Other expense
Earnings from unconsolidated affiliates
Net income attributable to noncontrolling interests
Segment gross margin
Non-cash commodity derivative mark-to-market (a)
NGL Logistics segment:
Segment net income attributable to partners
Operating and maintenance expense
Depreciation and amortization expense
Other expense (income)
Earnings from unconsolidated affiliates
Segment gross margin
Wholesale Propane Logistics segment:
Segment net income attributable to partners
Operating and maintenance expense
Depreciation and amortization expense
Other expense
Segment gross margin
Non-cash commodity derivative mark-to-market (a)
$
$
$
$
$
$
$
$
$
$
$
2013
Year Ended December 31,
2012
(Millions)
2011
$
181
52
8
211
93
62
8
(33)
17
$
599
(37) $
$
193
180
85
1
(1)
17
475
$
(36) $
79
16
6
3
(32)
72
$
$
$
31
15
2
4
52
$
(1) $
198
42
1
193
89
74
—
(26)
13
584
21
237
162
81
—
(15)
13
478
20
53
16
6
—
(11)
64
25
15
2
—
42
1
$
$
$
$
$
$
$
$
$
$
$
163
34
1
188
133
75
(1)
(23)
30
600
42
211
157
122
—
(23)
30
497
42
29
16
8
(1)
—
52
33
15
3
—
51
—
(a) Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for
our commodity derivative contracts.
61
Reconciliation of net income attributable to
partners to adjusted segment EBITDA:
Natural Gas Services segment:
Segment net income attributable to partners (a)
Non-cash commodity derivative mark-to-market
Depreciation and amortization expense
Noncontrolling interest on depreciation and
income tax
Adjusted Segment EBITDA
NGL Logistics segment:
Segment net income attributable to partners
Depreciation and amortization expense
Adjusted Segment EBITDA
Wholesale Propane Logistics segment:
Segment net income attributable to partners (b)
Non-cash commodity derivative mark-to-market
Depreciation and amortization expense
Adjusted Segment EBITDA
$
$
$
$
$
$
2013
Year Ended December 31,
2012
(Millions)
2011
193
36
85
(6)
308
79
6
85
31
1
2
34
$
$
$
$
$
$
237
(20)
81
(7)
291
53
6
59
25
(1)
2
26
$
$
$
$
$
$
211
(42)
122
(20)
271
29
8
37
33
—
3
36
(a) Includes $2 million, $4 million and $5 million of lower of cost or market adjustments for the years ended December 31,
2013, 2012, and 2011, respectively.
(b) Includes $2 million, $15 million and $1 million of lower of cost or market adjustments for the years ended
December 31, 2013, 2012, and 2011, respectively.
Operating and Maintenance and General and Administrative Expense - Operating and maintenance expenses are costs
associated with the operation of a specific asset and are primarily comprised of direct labor, ad valorem taxes, repairs and
maintenance, lease expenses, utilities and contract services. These expenses fluctuate depending on the activities performed
during a specific period. General and administrative expenses are as follows:
General and administrative expense
General and administrative expense - affiliate:
Services/Omnibus Agreement
Other - DCP Midstream, LLC
Total affiliate
Total
$
$
2013
Year Ended December 31,
2012
(Millions)
2011
17
$
17
$
29
16
45
62
$
26
31
57
74
$
19
10
46
56
75
We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under
the Services Agreement, which replaced the Omnibus Agreement on February 14, 2013, we are required to reimburse DCP
Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and
repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an
annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf,
including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety
and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the
annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other
expenses and expenditures incurred or payments made on our behalf. Pursuant to the Services Agreement, we will reimburse
DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.
62
In addition to the fees paid pursuant to the Services and Omnibus Agreements, we incurred allocated expenses, including
insurance and internal audit fees with DCP Midstream, LLC of $2 million for the year ended December 31, 2013 and $1
million for each of the years ended December 31, 2012 and 2011, respectively. The Eagle Ford system incurred $14 million for
the year ended December 31, 2013 and $27 million for each of the years ended December 31, 2012 and 2011, respectively, in
general and administrative expenses directly from DCP Midstream, LLC, which relates to the difference in the Eagle Ford
system's ownership structure during these periods. For the years ended December 31, 2012 and 2011, Southeast Texas incurred
$3 million and $10 million in general and administrative expenses directly from DCP Midstream, LLC, before the addition of
Southeast Texas to the Omnibus Agreement in March 2012. During the year ended December 31, 2011, East Texas incurred $8
million in general and administrative expenses directly from DCP Midstream, LLC.
We also incurred third party general and administrative expenses, which were primarily related to compensation and
benefit expenses of the personnel who provide direct support to our operations. Also included are expenses associated with
annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees,
due diligence and acquisition costs, costs associated with the Sarbanes-Oxley Act of 2002, investor relations activities, registrar
and transfer agent fees, incremental director and officer liability insurance costs, and director compensation.
63
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three years ended
December 31, 2013, 2012, and 2011. The results of operations by segment are discussed in further detail following this
consolidated overview discussion:
Year Ended December 31,
Variance
2013 vs. 2012
Variance
2012 vs. 2011
2013
(a)
2012
(a)(b)
2011
(a)(b)
Increase
(Decrease)
Percent
Increase
(Decrease)
Percent
(Millions, except operating data)
Operating revenues (c):
Natural Gas Services
NGL Logistics
Wholesale Propane Logistics
Intra-segment eliminations
$
2,527
$
2,282
$
3,012
$
73
380
—
64
415
—
57
633
(2)
Total operating revenues
2,980
2,761
3,700
Gross margin (d):
Natural Gas Services
NGL Logistics
Wholesale Propane Logistics
Total gross margin
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other (expense) income
Earnings from unconsolidated affiliates (e)
Interest expense
Income tax expense
Net income attributable to noncontrolling
interests
Net income attributable to partners
Other data:
Non-cash commodity derivative
mark-to-market
$
$
475
72
52
599
(211)
(93)
(62)
(8)
33
(52)
(8)
(17)
478
64
42
584
(193)
(89)
(74)
—
26
(42)
(1)
(13)
497
52
51
600
(188)
(133)
(75)
1
23
(34)
(1)
(30)
11 % $
(730)
245
9
(35)
—
219
(3)
8
10
15
18
4
(12)
8
7
10
7
4
14 %
(8)%
— %
8 %
(1)%
13 %
24 %
3 %
9 %
4 %
(16)%
100 %
27 %
24 %
700 %
31 %
(24)%
12 %
(34)%
100 %
(25)%
(4)%
23 %
(18)%
(3)%
3 %
7
(218)
2
(939)
(19)
12
(9)
(16)
5
(44)
(33)%
(1)
(1)
3
8
—
(1)%
(100)%
13 %
24 %
— %
(17)
35
(57)%
21 %
181
$
198
$
163
$
(17)
(9)% $
(37) $
21
$
42
$
Natural gas throughput (MMcf/d) (f)
2,270
2,322
NGL gross production (Bbls/d) (f)
118,578
112,032
NGL pipelines throughput (Bbls/d) (f)
Propane sales volume (Bbls/d)
89,361
19,553
78,508
19,111
1,951
85,917
62,555
24,743
(58)
(52)
6,546
10,853
442
(276)% $
(2)%
6 %
14 %
2 %
(21)
371
26,115
15,953
(50)%
19 %
30 %
26 %
(5,632)
(23)%
(a) Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle
Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013.
(b) Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast
Texas on January 1, 2011, and a 66.67% interest on March 30, 2012.
(c) Operating revenues include the impact of commodity derivative activity.
(d) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural
gas, propane and NGLs. Segment gross margin for each segment consists of total operating revenues for that segment,
less commodity purchases for that segment. Please read “Reconciliation of Non-GAAP Measures” above.
64
(e) Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our
40% ownership of Discovery, 20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu
Enterprise fractionator and 10% ownership of Texas Express. Earnings for Discovery, the Mont Belvieu 1 fractionator
and Texas Express include the amortization of the net difference between the carrying amount of the investments and
the underlying equity of the entities.
(f) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of
unconsolidated affiliates.
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased $219 million in 2013 compared to 2012 as a result of the
following:
•
•
•
$245 million increase for our Natural Gas Services segment primarily due to higher volumes, an increase
attributable to commodity prices and an increase in fee revenue, partially offset by a decrease in commodity
derivative activity related to hedge settlement timing on our natural gas storage and pipeline assets; and
$9 million increase for our NGL Logistics segment primarily due to increased throughput on certain of our
pipelines and increased activity at our NGL storage facility.
These increases were partially offset by:
$35 million decrease for our Wholesale Propane Logistics segment primarily due to lower propane prices and
commodity derivative activity related to favorable hedge settlement timing in 2012, partially offset by increased
volumes.
Gross Margin — Gross margin increased $15 million in 2013 compared to 2012, primarily as a result of the following.
•
•
•
$10 million increase for our Wholesale Propane Logistics segment, primarily due to increased unit margins and
exporting of propane, partially offset by a decrease related to commodity derivative activity. 2012 results reflect a
non-cash lower of cost or market inventory adjustment and reduced demand; and
$8 million increase for our NGL Logistics segment as a result of increased throughput on certain of our pipelines
and increased activity at our NGL storage facility.
These increases were partially offset by:
$3 million decrease for our Natural Gas Services segment, primarily related to decreased commodity derivative
activity, lower commodity prices and lower volumes across certain assets, partially offset by improved NGL
recoveries and an annual minimum volume commitment fee at our Eagle Ford system, a decrease in a lower of cost
or market adjustment recognized in 2013 and extensive turnaround activity at our East Texas system in 2012.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2013 compared to 2012
primarily as a result of growth and asset reliability expenditures.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2013 compared to 2012
primarily as a result of growth in our business, partially offset by a change in the estimated depreciable lives of our fixed assets
in the second quarter of 2012. The key contributing factors to the change in depreciable lives was an increase in the producers’
estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic
fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction
processes, along with improved technology used to locate commodity reserves, is giving producers greater access to
unconventional commodities.
General and Administrative Expense — General and administrative expense decreased in 2013 compared to 2012
primarily due to the difference in the Eagle Ford system's ownership structure in each period.
Other Expense — Other expense represents a write off of approximately $8 million in construction work in progress in
2013 due to discontinued projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2013 compared to 2012
primarily as a result of increased volumes in our NGL Logistics segment, in part due to the acquisition of the Mont Belvieu
fractionators in July 2012. 2012 results for the Mont Belvieu 1 fractionator reflect lower margin and higher operating expenses.
65
This increase was partially offset by lower NGL prices and volumes, a non-cash write off of fixed assets, a third party outage
and higher operating expenses at Discovery. 2012 results for Discovery reflect the favorable settlement of commercial disputes.
Interest Expense — Interest expense increased in 2013 compared to 2012 as a result of higher outstanding debt balances.
Income Tax Expense — Income tax expense increased in 2013 compared to 2012 primarily due to growth in our business.
Net Income Attributable to Noncontrolling Interests — Net income attributable to noncontrolling interests increased in
2013 compared to 2012, primarily as a result of higher volumes, improved NGL recoveries and an annual minimum volume
commitment fee at our Eagle Ford system.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $939 million in 2012 compared to 2011 primarily as a
result of the following:
•
•
$730 million decrease for our Natural Gas Services segment primarily due to lower commodity prices in 2012 and
the East Texas recovery settlement in 2011, partially offset by increases related to commodity derivative activity,
fee revenue and volumes; and
$218 million decrease for our Wholesale Propane Logistics segment due to lower volumes and prices, partially
offset by an increase related to commodity derivative activity.
These decreases were partially offset by:
•
$9 million increase for our NGL Logistics segment due to an increase in volumes.
Gross Margin — Gross margin decreased $16 million in 2012 compared to 2011, primarily as a result of the following:
•
$19 million decrease for our Natural Gas Services segment, primarily related to lower commodity prices, the East
Texas recovery settlement in 2011 and decreased volumes and differences in gas quality across certain assets,
partially offset by increased commodity derivative activity and increased volumes across certain assets; and
•
$9 million decrease for our Wholesale Propane Logistics segment primarily from a lack of demand.
These decreases were partially offset by:
•
$12 million increase for our NGL Logistics segment primarily as a result of increased throughput and rates on
certain of our assets and our acquisition of the DJ Basin NGL fractionators, partially offset by lower volumes at
certain connected processing facilities due to ethane rejection.
Operating and Maintenance Expense - Operating and maintenance expense increased in 2012 compared to 2011 primarily
as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased
costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011
primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in
depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from
widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production
in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity
reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, increased in 2012 compared to 2011
primarily as a result of our acquisition of the Mont Belvieu Fractionators in July 2012.
Net Income Attributable to Noncontrolling Interests - Net income attributable to noncontrolling interests decreased in 2012
compared to 2011 as a result of our acquisition of the remaining 49.9% of our East Texas system.
66
Results of Operations — Natural Gas Services Segment
This segment consists of our 80% interest in the Eagle Ford system, our 100% owned Eagle Plant, our East Texas system,
our Southeast Texas system, our Michigan system, our Northern Louisiana system, our Southern Oklahoma system, our
Wyoming system, our 75% interest in the Piceance system, our 40% interest in Discovery, and our O'Connor plant:
Year Ended December 31,
Variance
2013 vs. 2012
Variance
2012 vs. 2011
2013
(a)
2012
(a)(b)
2011
(a)(b)
Increase
Percent
(Decrease)
(Millions, except operating data)
Increase
(Decrease)
Percent
Operating revenues:
Sales of natural gas, NGLs and
condensate
$
2,315
$
2,062
$
2,850
$
Transportation, processing and other
196
168
153
Gains from commodity derivative
activity
Total operating revenues
16
2,527
52
2,282
9
3,012
Purchases of natural gas and NGLs
(2,052)
(1,804)
(2,515)
Segment gross margin (c)
Operating and maintenance expense
Depreciation and amortization
expense
Other expense
Earnings from unconsolidated
affiliates (d)
Segment net income
Segment net income attributable to
noncontrolling interests
475
(180)
(85)
(1)
1
210
478
(162)
(81)
—
15
250
497
(157)
(122)
—
23
241
(17)
(13)
(30)
Segment net income attributable to partners
$
193
$
237
$
211
$
Other data:
253
28
(36)
245
248
(3)
18
4
1
(14)
(40)
4
(44)
12 % $
(788)
17 %
(69)%
11 %
14 %
(1)%
11 %
5 %
100 %
(93)%
(16)%
31 %
(19)% $
15
43
(730)
(711)
(19)
5
(41)
—
(8)
9
(17)
26
Non-cash commodity derivative mark-
to-market
$
(36) $
20
$
42
$
Natural gas throughput (MMcf/d) (e)
2,270
2,322
NGL gross production (Bbls/d) (e)
118,578
112,032
1,951
85,917
(56)
(52)
6,546
(280)% $
(2)%
6 %
(22)
371
26,115
(28)%
10 %
478 %
(24)%
(28)%
(4)%
3 %
(34)%
— %
(35)%
4 %
(57)%
12 %
(52)%
19 %
30 %
(a) Includes our 80% interest in the Eagle Ford system, retrospectively adjusted. We acquired a 33.33% interest in the Eagle
Ford system on November 2, 2012, and a 46.67% interest on March 28, 2013.
(b) Includes our 100% interest in Southeast Texas, retrospectively adjusted. We acquired a 33.33% interest in Southeast
Texas on January 1, 2011, and a 66.67% interest on March 30, 2012.
(c) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of
natural gas and NGLs. Please read “Reconciliation of Non-GAAP Measures” above.
(d) Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our
40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference between the
carrying amount of our investment and the underlying equity of the entity.
(e) Includes our share, based on our ownership percentage, of the throughput volumes and NGL production of
unconsolidated affiliates.
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased $245 million in 2013 compared to 2012, primarily as a
result of the following:
67
•
•
•
•
•
•
•
$208 million increase primarily attributable to higher volumes and improved NGL recoveries at our Eagle Ford
and East Texas systems, partially offset by lower volumes across certain assets, primarily our Southeast Texas
system, and a plant turnaround at our Eagle Ford system. 2012 results reflect extensive turnaround activity at our
East Texas system;
$176 million increase attributable to increased natural gas prices;
$83 million increase attributable to increased prices related to our natural gas storage and pipeline assets at our
Southeast Texas and Northern Louisiana systems; and
$28 million increase in fee revenue primarily attributable to higher volumes at our Eagle Ford and East Texas
systems, and the operation of our O'Connor plant.
These increases were partially offset by:
$144 million decrease attributable to decreased NGL prices;
$70 million decrease attributable to decreased volumes related to our natural gas storage and pipeline assets at our
Southeast Texas and Northern Louisiana systems; and
$36 million decrease related to commodity derivative activity. This includes unrealized commodity derivative
losses in 2013 compared to gains in 2012 due to movements in forward prices of commodities for a net impact of
$56 million, partially offset by an increase in realized cash settlement gains in 2013 compared to 2012 of $20
million.
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased $248 million in 2013 compared to
2012 primarily as a result of higher natural gas prices, increased volumes at our Eagle Ford and East Texas systems and
extensive turnaround activity at our East Texas system in 2012, partially offset by decreased NGL prices, decreased volumes
related to our natural gas storage and pipeline assets at our Southeast Texas and Northern Louisiana systems, lower volumes
across certain gathering and processing assets, primarily our Southeast Texas system, and a plant turnaround at our Eagle Ford
system.
Segment Gross Margin — Segment gross margin decreased $3 million in 2013 compared to 2012, primarily as a result of
the following:
•
•
•
•
$36 million decrease related to commodity derivative activity as discussed above;
$24 million decrease as a result of lower NGL prices, which primarily reflects the unhedged portion of the Eagle
Ford system associated with DCP Midstream, LLC’s ownership during the year ended December 31, 2013; and
$2 million decrease attributable to lower volumes associated with our natural gas storage and pipeline assets at our
Southeast Texas and Northern Louisiana systems; partially offset by a decrease in the lower of cost or market
adjustment recognized in 2013 as compared to 2012.
These decreases were partially offset by:
$59 million increase as a result of growth from the operation of our fee-based O'Connor plant, higher volumes and
improved NGL recoveries at our Eagle Ford and East Texas systems and an annual minimum volume commitment
fee at our Eagle Ford system, partially offset by lower volumes across certain assets. 2012 results reflected
extensive turnaround activity at our East Texas system.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2013 compared to 2012
primarily as a result of growth and asset reliability expenditures.
Depreciation and Amortization Expense — Depreciation and amortization expense increased in 2013 compared to 2012
primarily as a result of growth in our business, offset by a change in the estimated depreciable lives of our fixed assets in the
second quarter of 2012. The key contributing factors to the change in depreciable lives was an increase in the producers’
estimated remaining economically recoverable reserves, resulting from widespread application of techniques, such as hydraulic
fracturing and horizontal drilling, that improve commodity production in the regions our assets serve. Advances in extraction
processes, along with improved technology used to locate commodity reserves, is giving producers greater access to
unconventional commodities.
68
Other Expense — Other expense represents a write off of approximately $1 million in construction work in progress in
2013 due to discontinued projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, primarily representing our 40%
ownership of Discovery, decreased in 2013 compared to 2012 as a result of lower NGL prices, reduced throughput volumes, a
non-cash write off of fixed assets, a third party outage and higher operating expenses, partially offset by a foreign currency
translation gain related to the Keathley Canyon project. 2012 results reflect the favorable settlement of commercial disputes.
Commodity derivative activity associated with our exposure on our unconsolidated affiliates is included in segment gross
margin.
Segment Net Income Attributable to Noncontrolling Interests - Segment net income attributable to noncontrolling interests
increased in 2013 compared to 2012, primarily as a result of higher volumes, improved NGL recoveries and an annual
minimum volume commitment fee at our Eagle Ford system.
Natural Gas Throughput - Natural gas throughput decreased slightly in 2013 compared to 2012 primarily as a result of
lower volumes across certain assets, partially offset by higher volumes due to the operation of our 100% owned Eagle and
O'Connor plants in 2013, and extensive turnaround activity at our East Texas system in 2012.
NGL Gross Production - NGL production increased in 2013 compared to 2012 primarily as a result of higher volumes due
to the operation of our 100% owned Eagle and O'Connor plants, and improved NGL recoveries at our Eagle Ford and East
Texas systems, partially offset by lower volumes across certain assets. 2012 results reflect lower volumes as certain of our
assets were required to curtail NGL production due to a downstream outage and extensive turnaround activity at our East Texas
system.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $730 million in 2012 compared to 2011, primarily as a
result of the following:
•
•
$623 million decrease attributable to the impact of lower commodity prices on our gathering and processing
business;
$167 million decrease primarily attributable to decreased prices for physical sales related to our natural gas
storage and pipeline assets, as well as a decrease in volumes; and
•
$6 million decrease as a result of the East Texas recovery settlement in 2011.
These decreases were partially offset by:
•
•
•
$43 million increase related to commodity derivative activity. This includes a change in unrealized commodity
derivative activity in 2012 compared to 2011 of $22 million due to movements in forward prices of commodities,
and realized cash settlement gains in 2012 compared to realized cash settlement losses in 2011 for a net increase
of $65 million. Included in our derivative activity are an increase in unrealized losses of $38 million and an
increase in realized gains of $33 million from the predecessor’s Southeast Texas storage business;
$15 million in fee revenue primarily attributable to contractual amendments such that certain revenues changed
from a gross presentation to a net fee presentation; and
$8 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by
decreased volumes across certain assets, differences in gas quality and extensive turnaround activity at our East
Texas system.
Purchases of Natural Gas and NGLs - Purchases of natural gas and NGLs decreased $711 million in 2012 compared to
2011 primarily as a result of higher natural gas prices, increased volumes at our Eagle Ford system and across certain assets,
partially offset by contractual amendments such that certain revenues changed from a gross presentation to a net fee
presentation, decreased NGL prices and a plant turnaround at our Eagle Ford system.
69
Segment Gross Margin — Segment gross margin decreased $19 million in 2012 compared to 2011, primarily as a result
of the following:
•
•
$92 million decrease as a result of lower commodity prices; and
$6 million decrease as a result of the East Texas recovery settlement in 2011.
These decreases were partially offset by:
•
•
$43 million increase related to commodity derivative activities as discussed in the Operating Revenues section
above; and
$36 million increase primarily attributable to increased volumes at our Eagle Ford system, partially offset by
decreased volumes and differences in gas quality across certain assets, and extensive turnaround activity at our
East Texas system.
Operating and Maintenance Expense - Operating and maintenance expense increased in 2012 compared to 2011 primarily
as a result of our acquisition of the Crossroads system in July 2012, turnaround activity at our Eagle Ford system and increased
costs associated with the organic growth projects completed in 2011 at our Eagle Ford system.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011
primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in
depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from
widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production
in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity
reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, primarily representing our 40%
ownership of Discovery, decreased in 2012 compared to 2011 primarily as a result of lower commodity prices and reduced
throughput volumes on Discovery, partially offset by the timing of expenditures at Discovery. Commodity derivative activity
associated with our exposure on our unconsolidated affiliates is included in segment gross margin.
Segment Net Income Attributable to Noncontrolling Interests - Segment net income attributable to noncontrolling interests
decreased in 2012 compared to 2011 as a result of the acquisition of the remaining 49.9% of the East Texas system.
Natural Gas Throughput - Natural gas transported, processed and/or treated increased in 2012 compared to 2011 primarily
as a result of our acquisition of the remaining 49.9% of the East Texas system and Crossroads system, partially offset by
decreased volumes across certain assets and turnaround at our East Texas system.
NGL Gross Production - NGL production increased in 2012 compared to 2011 primarily as a result of our acquisition of the
remaining 49.9% of the East Texas system and Crossroads system, partially offset by decreased volumes and differences in gas
quality across certain assets and turnaround at East Texas.
70
Results of Operations — NGL Logistics Segment
This segment includes the NGL storage facility in Michigan, our 20% interest in the Mont Belvieu 1 fractionator, our
12.5% interest in the Mont Belvieu Enterprise fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ
Basin NGL fractionators in Colorado, the Seabreeze and Wilbreeze intrastate NGL pipeline, our 33.33% interest in the Front
Range interstate NGL pipeline (under construction as of December 31, 2013), and our 10% interest in the Texas Express
intrastate NGL pipeline:
Year Ended December 31,
Variance
2013 vs. 2012
Variance
2012 vs. 2011
2013
2012
Increase
(Decrease)
(Millions, except operating data)
Percent
2011
Increase
(Decrease)
Percent
Operating revenues:
Sales of NGLs
$
Transportation, processing and other
Total operating revenues
Purchases of NGLs
Segment gross margin (a)
Operating and maintenance expense
Depreciation and amortization
expense
Other (expense) income
Earnings from unconsolidated
affiliates (b)
Segment net income attributable to
partners
Other data:
1
72
73
(1)
72
(16)
(6)
(3)
32
$
— $
64
64
—
64
(16)
(6)
—
11
$
5
52
57
(5)
52
(16)
(8)
1
—
$
79
$
53
$
29
$
1
8
9
1
8
—
—
3
21
26
100% $
13%
14%
100%
13%
—%
—%
100%
191%
49% $
(5)
12
7
(5)
12
—
(2)
(1)
11
24
(100)%
23 %
12 %
(100)%
23 %
— %
(25)%
(100)%
100 %
83 %
NGL pipelines throughput (Bbls/d) (c)
89,361
78,508
62,555
10,853
14%
15,953
26 %
(a) Segment gross margin consists of total operating revenues less purchases of NGLs. Please read “Reconciliation of Non-
GAAP Measures” above.
(b) Includes our share, based on our ownership percentage, of the earnings of all unconsolidated affiliates which include our
20% ownership of the Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and
10% ownership of Texas Express. Earnings for Mont Belvieu 1 and Texas Express include the amortization of the net
difference between the carrying amount of our investments and the underlying equity of the entities.
(c) Includes our share, based on our ownership percentage, of the throughput volumes of unconsolidated affiliates.
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues increased in 2013 compared to 2012 as result of increased
throughput on certain of our pipelines and increased activity at our NGL storage facility.
Segment Gross Margin — Segment gross margin increased in 2013 compared to 2012 as result of increased throughput on
certain of our pipelines and increased activity at our NGL storage facility.
Operating and Maintenance Expense — Operating and maintenance expense remained constant in 2013 compared to
2012.
Depreciation and Amortization Expense — Depreciation and amortization remained constant in 2013 compared to 2012.
Other Expense — Other expense represents a write off of approximately $3 million in construction work in progress in
2013 due to a discontinued project.
71
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates, representing 20% ownership of the
Mont Belvieu 1 fractionator, 12.5% ownership of the Mont Belvieu Enterprise fractionator and 10% ownership of Texas
Express, increased in 2013 compared to 2012 primarily as a result of the acquisition of the Mont Belvieu fractionators in July
2012 and the Mont Belvieu Enterprise fractionator de-bottleneck project in the third quarter of 2013. 2012 results for the Mont
Belvieu 1 fractionator reflect lower margin and higher operating expenses related to a planned turnaround.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2013 compared to 2012 as a result of volume
growth on our pipelines.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues increased in 2012 compared to 2011 as result of increased
throughput and rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition
of the DJ Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected
processing facilities.
Segment Gross Margin - Segment gross margin increased in 2012 compared to 2011 as result of increased throughput and
rates on certain of our pipelines, the completion of the Wattenberg capital expansion project, and our acquisition of the DJ
Basin NGL fractionators, partially offset by lower throughput volumes due to ethane rejection at certain connected processing
facilities.
Operating and Maintenance Expense - Operating and maintenance expense remained relatively constant in 2012 compared
to 2011due to the completion of the Wattenberg capital expansion project, and our acquisition of the DJ Basin NGL
fractionators, offset by timing of expenditures.
Depreciation and Amortization Expense - Depreciation and amortization expense decreased in 2012 compared to 2011
primarily as a result of a change in the estimated useful lives of our assets. The key contributing factors to the change in
depreciable lives was an increase in the producers’ estimated remaining economically recoverable reserves, resulting from
widespread application of techniques, such as hydraulic fracturing and horizontal drilling, that improve commodity production
in the regions our assets serve. Advances in extraction processes, along with improved technology used to locate commodity
reserves, is giving producers greater access to unconventional commodities.
Earnings from Unconsolidated Affiliates - Earnings from unconsolidated affiliates, representing 20% ownership of the
Mont Belvieu 1 Fractionator and 12.5% ownership of the Mont Belvieu Enterprise Fractionator, increased in 2012 compared to
2011 as a result the acquisition of the Mont Belvieu Fractionators in July 2012.
NGL Pipelines Throughput - NGL pipelines throughput increased in 2012 compared to 2011 as a result of volume growth
on our pipelines and the completion of the Wattenberg capital expansion project, partially offset by lower throughput volumes
due to ethane rejection at certain connected processing facilities.
72
Results of Operations — Wholesale Propane Logistics Segment
This segment consists of our propane terminals, which include six owned and operated rail terminals, one owned marine
import terminal, one leased marine terminal, one pipeline terminal and access to several open-access propane pipeline
terminals.
Year Ended December 31,
Variance
2013 vs. 2012
Variance
2012 vs. 2011
2013
2012
2011
Increase
(Decrease)
Percent
Increase
(Decrease)
Percent
(Millions, except operating data)
$
379
$
397
$
634
$
(18)
(5)% $
(237)
(37)%
1
380
(328)
52
(15)
(2)
(4)
18
415
(373)
42
(15)
(2)
—
(1)
633
(582)
51
(15)
(3)
—
31
$
25
$
33
$
(17)
(35)
(45)
10
—
—
4
6
(94)%
(8)%
(12)%
24 %
— %
— %
100 %
24 % $
19
(218)
(209)
(9)
—
(1)
—
(8)
*
(34)%
(36)%
(18)%
— %
(33)%
— %
(24)%
Operating revenues:
Sales of propane
Gains (losses) from commodity
derivative activity
Total operating revenues
Purchases of propane
Segment gross margin (a)
Operating and maintenance
expense
Depreciation and amortization
expense
Other expense
Segment net (loss) income attributable
to partners
Other data:
Non-cash commodity derivative
mark-to-market
$
$
Propane sales volume (Bbls/d)
19,553
19,111
24,743
_________________
* Percentage change is not meaningful.
(1) $
1
$
— $
(2)
442
(200)% $
1
2 %
(5,632)
100 %
(23)%
(a) Segment gross margin consists of total operating revenues, including commodity derivative activity, less purchases of
propane. Please read “Reconciliation of Non-GAAP Measures” above.
Year Ended December 31, 2013 vs. Year Ended December 31, 2012
Total Operating Revenues — Total operating revenues decreased by $35 million in 2013 compared to 2012, primarily as a
result of the following:
•
•
•
$25 million decrease attributable to lower propane prices; and
$17 million decrease related to commodity derivative activity. This includes a decrease in realized cash settlement gains
in 2013 compared to 2012 of $16 million, and unrealized commodity derivative losses in 2013 of $1 million due to
movements in forward prices of commodities.
These decreases were partially offset by:
$7 million increase attributable to increased volumes in part due to the export of propane from our Chesapeake terminal
in the first quarter of 2013. 2012 results reflect a lack of demand due to the industry’s excess inventory resulting from
near record warm weather.
Purchases of Propane — Purchases of propane decreased in 2013 compared to 2012 primarily due to lower propane
prices, which impacts both sales and purchases, a 2012 non-cash lower of cost or market inventory adjustment of $15 million,
partially offset by increased volumes due to the export of propane from our Chesapeake terminal in the first quarter of 2013 and
reduced demand in 2012 due to the industry’s excess inventory resulting from near record warm weather.
73
Segment Gross Margin — Segment gross margin increased in 2013 compared to 2012 primarily due to increased unit
margins and exporting propane from our Chesapeake terminal in the first quarter of 2013, partially offset by a $17 million
decrease related to commodity derivative activities as discussed above. 2012 results reflect a non-cash lower of cost or market
inventory adjustment of $15 million and reduced demand due to the industry’s excess inventory resulting from near record
warm weather.
Operating and Maintenance Expense — Operating and maintenance expense remained constant in 2013 compared to
2012.
Depreciation and Amortization Expense — Depreciation and amortization expense remained constant in 2013 compared
to 2012.
Other Expense — Other expense represents a write off of approximately $4 million in construction work in progress in
2013 due to a discontinued project.
Propane Sales Volume — Propane sales volumes increased in 2013 compared to 2012 due to the export of propane from
our Chesapeake terminal in the first quarter. 2012 results reflect a lack of demand due to the industry’s excess inventory
resulting from near record warm weather.
Year Ended December 31, 2012 vs. Year Ended December 31, 2011
Total Operating Revenues — Total operating revenues decreased $218 million in 2012 compared to 2011, primarily as a
result of the following:
•
$152 million decrease attributable to reduced sales volumes primarily as a result of a lack of demand due to the
industry’s excess inventory resulting from record warm weather last heating season; and
•
$85 million decrease attributable to lower propane prices.
These decreases were partially offset by:
•
$19 million increase related to a change in unrealized commodity derivative activity of $1 million and a change in
realized commodity derivative activity of $18 million.
Purchases of Propane - Purchases of propane decreased in 2012 compared to 2011 primarily due to reduced volumes as a
result of inventory build resulting from record warm weather last heating season and lower propane prices, partially offset by a
non-cash lower of cost or market inventory adjustment of $15 million in 2012, offset by a significant recovery through the sale
of inventory.
Segment Gross Margin - Segment gross margin decreased in 2012 compared to 2011 primarily from a lack of demand due
to the industry’s excess inventory resulting from record warm weather last heating season and lower per unit margins. A non-
cash lower of cost or market inventory adjustment of $15 million was offset by a significant recovery through the sale of
inventory and hedging activity.
Operating and Maintenance Expense - Operating and maintenance expense remained relatively constant in 2012 compared
to 2011.
Depreciation and Amortization Expense - Depreciation and amortization expense remained relatively constant in 2012
compared to 2011.
Propane Sales Volume - Propane sales volumes decreased in 2012 compared to 2011 as a result of a lack of demand due to
the industry’s excess inventory resulting from record warm weather last heating season.
Liquidity and Capital Resources
We expect our sources of liquidity to include:
•
cash generated from operations;
74
•
•
•
•
•
•
•
cash distributions from our unconsolidated affiliates;
borrowings under our revolving Credit Agreement;
issuance of commercial paper under our Commercial Paper Program;
borrowings under term loans;
issuance of additional common units, including issuances we may make to DCP Midstream, LLC;
debt offerings; and
letters of credit.
We anticipate our more significant uses of resources to include:
•
•
•
•
•
quarterly distributions to our unitholders and general partner;
capital expenditures;
contributions to our unconsolidated affiliates to finance our share of their capital expenditures;
business and asset acquisitions, including transactions with DCP Midstream, LLC; and
collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may,
at times, be significant depending on commodity price movements, and letters of credit we have posted.
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements,
long-term capital expenditure and acquisition requirements, and quarterly cash distributions for the next twelve months. In the
event these sources are not sufficient, we would reduce our discretionary spending.
We routinely evaluate opportunities for strategic investments or acquisitions. Future material investments or acquisitions
may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the option
to utilize both equity and debt instruments as vehicles for the long-term financing of our investment activities and acquisitions.
Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to
conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, impact
our credit ratings, raise our financing costs, as well as impact our compliance with our financial covenant requirements under
our Credit Agreement.
Our Credit Agreement consists of a senior unsecured revolving credit facility with capacity of $1 billion, which matures
on November 10, 2016. Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements.
Except in the case of a default, which would make the borrowings under the Credit Agreement fully callable, amounts
borrowed under the Credit Agreement will not mature prior to the November 10, 2016 maturity date. In October 2013, we
entered into a commercial paper program, or the Commercial Paper Program, which serves as an alternative source of funding
and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper Program may be
borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of notes outstanding,
combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the aggregate. Amounts
undrawn under our revolving credit facility are available to repay the unsecured commercial paper notes, or the Notes, if
necessary. The maturities of the Notes will vary, but may not exceed 397 days from the date of issue. The proceeds of the
issuances of the Notes are expected to be used for capital expenditures and other general partnership purposes. As of
February 20, 2014, we had $445 million of commercial paper outstanding as short-term borrowings and had approximately
$555 million of unused capacity under the Credit Agreement.
In March 2013, we issued $500 million of 3.875% 10-year Senior Notes due March 15, 2023. We received proceeds of
$490 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $10 million, which we used to fund
a portion of the acquisition of an additional 46.67% interest in the Eagle Ford system.
During the year ended December 31, 2013, we issued 1,408,547 of our common units pursuant to an equity distribution
agreement entered into in August 2011, or the 2011 equity distribution agreement. We received proceeds of $67 million, net of
commissions and offering costs of $2 million, which were used to finance growth opportunities and for general corporate
purposes. The 2011 equity distribution agreement provided for the offer and sale of common units having an aggregate offering
75
amount of up to $150 million. As of December 31, 2013, no common units remain available for sale pursuant to this equity
distribution agreement and we have deregistered the corresponding registration statement.
In November 2013, we entered into an equity distribution agreement, or the 2013 equity distribution agreement, with a
group of financial institutions as sales agents. The agreement provides for the offer and sale from time to time, through our
sales agents, of common units having an aggregate offering amount of up to $300 million. During the year ended December 31,
2013, we issued 1,839,430 of our common units pursuant to the 2013 equity distribution agreement and received proceeds of
$87 million, net of accrued commissions and offering costs of $1 million, which were used to finance growth opportunities and
for general corporate purposes. As of December 31, 2013, approximately $212 million aggregate offering price of our common
units remain available for sale pursuant to the 2013 equity distribution agreement.
In August 2013, we issued 9,000,000 common units at $50.04 per unit. We received proceeds of $434 million, net of
offering costs.
In March 2013, we issued 12,650,000 common units at $40.63 per unit. We received proceeds of $494 million, net of
offering costs.
In March 2013, we issued 2,789,739 common units to DCP Midstream, LLC as partial consideration for the additional
46.67% interest in the Eagle Ford system.
Changes in natural gas, NGL and condensate prices and the terms of our processing arrangements have a direct impact on
our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working
capital. We have mitigated a significant portion of our anticipated commodity price risk associated with the equity volumes
from our gathering and processing activities through 2017 with fixed price commodity swaps. For additional information
regarding our derivative activities, please read Item 7A. “Quantitative and Qualitative Disclosures about Market Risk”.
The counterparties to certain of our commodity swap contracts are investment-grade rated financial institutions. Under
these contracts, we may be required to provide collateral to the counterparties in the event that our potential payment exposure
exceeds a predetermined collateral threshold. Collateral thresholds are set by us and each counterparty, as applicable, in the
master contract that governs our financial transactions based on our and the counterparty’s assessment of creditworthiness. The
assessment of our position with respect to the collateral thresholds are determined on a counterparty by counterparty basis, and
are impacted by the representative forward price curves and notional quantities under our swap contracts. Due to the
interrelation between the representative crude oil and natural gas forward price curves, it is not practical to determine a pricing
point at which our swap contracts will meet the collateral thresholds as we may transact multiple commodities with the same
counterparty. Depending on daily commodity prices, the amount of collateral posted can go up or down on a daily basis. The
counterparty to our remaining commodity swaps contracts is DCP Midstream, LLC.
Working Capital — Working capital is the amount by which current assets exceed current liabilities. Current assets are
reduced by our quarterly distributions, which are required under the terms of our partnership agreement based on Available
Cash, as defined in the partnership agreement. In general, our working capital is impacted by changes in the prices of
commodities that we buy and sell, inventory levels, and other business factors that affect our net income and cash flows. Our
working capital is also impacted by the timing of operating cash receipts and disbursements, borrowings of and payments on
debt, capital expenditures, and increases or decreases in other long-term assets.
We had working capital liabilities of $219 million as of December 31, 2013, compared to working capital assets of $23
million as of December 31, 2012. Included in these working capital amounts are net derivative working capital assets of $51
million and $18 million as of December 31, 2013 and December 31, 2012, respectively. The change in working capital is
primarily attributable to the factors described above, as well as our commercial paper borrowings. We expect that our future
working capital requirements will be impacted by these same factors.
As of December 31, 2013, we had $12 million in cash and cash equivalents. Cash held by consolidated subsidiaries with
noncontrolling interests totaled $1 million. The remaining cash balance was available for general partnership purposes.
Cash Flow — Operating, investing and financing activities were as follows:
76
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Year Ended December 31,
2013
2012
(Millions)
2011
$
$
$
324
$
(1,387) $
$
1,073
82
$
(1,383) $
$
1,295
387
(537)
151
Our predecessor’s sources of liquidity, prior to its acquisition by us, included cash generated from operations and funding
from DCP Midstream, LLC. Our predecessor’s cash receipts were deposited in DCP Midstream, LLC’s bank accounts and all
cash disbursements were made from these accounts. Cash transactions for our predecessor were handled by DCP Midstream,
LLC and were reflected in partners’ equity as net changes in parent advances to predecessors from DCP Midstream, LLC.
Net Cash Provided by Operating Activities — The changes in net cash provided by operating activities are attributable to
our net income adjusted for non-cash charges as presented in the consolidated statements of cash flows, and changes in working
capital as discussed above.
We received $54 million for our net hedge cash settlements for the year ended December 31, 2013, of which less than $1
million was associated with rebalancing our portfolio, and approximately $49 million and $34 million for our net hedge cash
settlements for the years ended December 31, 2012 and 2011.
We received cash distributions from unconsolidated affiliates of $39 million, $24 million and $25 million during the
years ended December 31, 2013, 2012, and 2011, respectively. Distributions exceeded earnings by $6 million for the year
ended December 31, 2013.
Net Cash Used in Investing Activities — Net cash used in investing activities during the year ended December 31, 2013
was comprised of: (1) acquisition expenditures of $782 million related to our acquisition of the additional 46.67% interest in
the Eagle Ford system for $486 million, the O'Connor plant for $210 million and Front Range for $86 million; (2) capital
expenditures of $363 million (our portion of which was $325 million and the noncontrolling interests portion was $38 million)
consisting of construction of the Goliad plant, construction and expansion of the O'Connor plant, expansion and upgrades to
our Southeast Texas complex, expansion of the Marysville NGL storage facility, expansion of our Chesapeake facility and other
projects; and (3) investments in unconsolidated affiliates of $242 million consisting of $133 million to Discovery, $55 million
to Texas Express, $48 million to Front Range and $6 million to Mont Belvieu Enterprise Fractionator.
Net cash used in investing activities during 2012 was comprised of: (1) acquisition expenditures of $745 million, of
which $282 million is related to our acquisition of the initial 33.33% interest in the Eagle Ford system, $193 million is related
to our acquisition of the remaining 66.67% interest in Southeast Texas, $120 million related to our acquisition of the remaining
49.9% interest in East Texas, $63 million related to our acquisition of Crossroads, $57 million related to the acquisition of the
Goliad plant by the Eagle Ford system, and $30 million related to our acquisition of the Mont Belvieu fractionators; (2) capital
expenditures of $483 million (of which our portion was $410 million and the noncontrolling interest holders’ portion and the
reimbursable projects portion was $73 million); and (3) investments in unconsolidated affiliates of $158 million; partially offset
by (4) proceeds from sales of assets of $2 million; and (5) a return of investment from unconsolidated affiliate of $1 million.
Net cash used in investing activities during 2011 was comprised of: (1) capital expenditures of $384 million (our portion
of which was $321 million and the noncontrolling interest holders’ portion was $63 million), which includes $23 million of
capital expenditures related to our Eagle Plant construction; (2) acquisition expenditures of $114 million, representing the
carrying value of the net assets acquired, related to our acquisition of an initial 33.33% interest in Southeast Texas; (3)
acquisition expenditures of $30 million related to our acquisition of our DJ Basin NGL fractionators and a payment of $8
million to the seller of Michigan Pipeline & Processing, LLC in relation to our contingent payment agreement; and (4)
investments in unconsolidated affiliates of $8 million; partially offset by (5) proceeds from sales of assets of $5 million; and (6)
a return of investment from unconsolidated affiliates of $2 million.
Net Cash Provided by Financing Activities — Net cash provided by financing activities during 2013 was comprised of:
(1) proceeds from long-term debt of $1,957 million, offset by payments of $1,988 million, for net repayment of long-term debt
of $31 million; (2) proceeds from the issuance of commercial paper of $335 million; (3) proceeds from the issuance of common
units, net of offering costs, of $1,083 million; (4) contributions from noncontrolling interests of $46 million; (5) net change in
advances to predecessor from DCP Midstream, LLC of $32 million; and (6) contributions from DCP Midstream, LLC of $1
million; partially offset by (7) distributions to our limited partners and general partner of $277 million; (8) excess purchase
price over acquired interests and commodity hedges of $85 million; (9) distributions to noncontrolling interests of $24 million;
77
(10) payment of deferred financing costs of $4 million; and (11) distributions to DCP Midstream, LLC of $3 million relating to
capital expenditures for reimbursable projects.
During the year ended December 31, 2013, total outstanding indebtedness under our $1 billion Credit Agreement, which
includes borrowings under our revolving credit facility and letters of credit issued under the Credit Agreement, was not less
than $1 million and did not exceed $607 million. The weighted-average indebtedness outstanding under the revolving credit
facility was $429 million, $201 million, $265 million and $130 million for the first, second, third and fourth quarters of 2013,
respectively.
The weighted-average indebtedness outstanding under the Commercial Paper Program was $273 million for the fourth
quarter of 2013.
As of December 31, 2013, we had unused capacity under the revolving credit facility of $664 million, all of which was
available for general working capital purposes.
During the year ended December 31, 2013, we had the following movements on our revolving credit facility:
•
•
•
•
•
•
•
$494 million repayment financed by the issuance of 12,650,000 common units in March 2013;
$434 million repayment financed by the issuance of 9,000,000 common units in August 2013; and
$335 million repayment financed by borrowings under our Commercial Paper Program; partially offset by
$209 million borrowings to fund the acquisition of the O'Connor plant;
$363 million net borrowings for general working capital purposes;
$86 million borrowings to fund the acquisition of the Front Range pipeline; and
$80 million borrowings primarily to reimburse DCP Midstream, LLC for its proportionate share of the capital
spent to date, at closing, by the Eagle Ford system for the construction of the Goliad plant and for preformation
capital expenditures.
Net cash provided by financing activities during 2012 was comprised of: (1) proceeds from long-term debt of $2,665
million, offset by payments of $1,792 million, for net borrowing of long-term debt of $873 million; (2) proceeds from the
issuance of common units net of offering costs of $455 million; (3) net change in advances to predecessor from DCP
Midstream, LLC of $355 million; (4) contributions from noncontrolling interest of $25 million; (5) contributions from DCP
Midstream, LLC of $10 million; partially offset by (6) distributions to our limited partners and general partner of $181 million;
(7) excess purchase price over acquired interests of $225 million (8) distributions to noncontrolling interests of $9 million; and
(9) payment of deferred financing costs of $8 million.
During 2012, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our
revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $268 million and did not
exceed $576 million. The weighted-average indebtedness outstanding under the Credit Agreement was $496 million, $369
million, $321 million and $455 million for the first, second, third and fourth quarters of 2012, respectively.
We had unused capacity, which is available for commitments under the Credit Agreement, of $732 million, $649 million,
$699 million and $474 million at the end of the first, second, third and fourth quarters of 2012, respectively.
During 2012, we had the following movements on our revolving credit facility:
•
•
•
$63 million borrowing to fund the acquisition of the Crossroads system; and
$199 million net borrowings for general working capital purposes; partially offset by
$234 million repayment with proceeds from the issuance of 5,148,500 common units in March 2012.
78
Net cash provided by financing activities during 2011 was comprised of: (1) proceeds from the issuance of common units,
net of offering costs, of $170 million; (2) net borrowing of long-term debt of $99 million; (3) net change in advances to
predecessor from DCP Midstream, LLC of $81 million; and (4) contributions from noncontrolling interests of $18 million;
partially offset by (5) distributions to our unitholders and general partner of $132 million; (6) distributions to noncontrolling
interests of $45 million; (7) excess purchase price over the acquired net assets of Southeast Texas of $36 million; and (8)
payment of deferred financing costs of $4 million.
During 2011, total outstanding indebtedness under our $1 billion Credit Agreement, which includes borrowings under our
revolving credit facility and letters of credit issued under the Credit Agreement, was not less than $426 million and did not
exceed $591 million. The weighted-average indebtedness outstanding under the revolving credit facility was $519 million,
$454 million, $484 million and $517 million for the first, second, third and fourth quarters of 2011, respectively.
We had unused capacity, which is available for commitments under the Credit Agreement of $424 million, $388 million,
$373 million and $502 million at the end of the first, second, third and fourth quarters of 2011, respectively.
During 2011, we had the following movements on our revolving credit facility:
•
•
•
•
•
•
$150 million borrowing to fund the acquisition of our initial 33.33% interest in Southeast Texas;
$30 million borrowing to fund the purchase of the DJ Basin NGL fractionators;
$30 million borrowing to fund the Marysville tax payment;
$23 million borrowing to fund the purchase of certain tangible assets and land located in the Eagle Ford Shale;
and
$6 million net borrowings; partially offset by
$140 million repayment financed by the issue of 3,596,636 common units in March 2011.
We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and
general partner. See Note 12 of the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.”
Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to
maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue
to consist of the following:
• maintenance capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings
capacity. These expenditures add on to or improve capital assets owned, including certain system integrity,
compliance and safety improvements. Maintenance capital expenditures also include certain well connects, and
may include the acquisition or construction of new capital assets; and
•
expansion capital expenditures, which are cash expenditures to increase our cash flows, operating or earnings
capacity. Expansion capital expenditures include acquisitions or capital improvements (where we add on to or
improve the capital assets owned, or acquire or construct new gathering lines and well connects, treating facilities,
processing plants, fractionation facilities, pipelines, terminals, docks, truck racks, tankage and other storage,
distribution or transportation facilities and related or similar midstream assets).
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. We anticipate maintenance
capital expenditures of between $35 million and $45 million, and approved expenditures for expansion capital of between $500
million and $600 million, for the year ending December 31, 2014. Expansion capital expenditures include construction of
Discovery’s Keathley Canyon Connector, which is shown as investments in unconsolidated affiliates, construction of the
Lucerne 2 plant, the Marysville NGL storage project and expansion of our Chesapeake facility, among other projects. The
board of directors may, at its discretion, approve additional growth capital during the year.
79
The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities:
Year Ended December 31, 2013
Year Ended December 31, 2012
Maintenance
Capital
Expenditures
Expansion
Capital
Expenditures
Total
Consolidated
Capital
Expenditures
Maintenance
Capital
Expenditures
Expansion
Capital
Expenditures
Total
Consolidated
Capital
Expenditures
Our portion
Noncontrolling interest portion and
reimbursable projects (a)
Total
$
$
23
$
302
$
(Millions)
325
$
22
$
388
$
2
25
36
38
$
338
$
363
$
8
30
65
$
453
$
410
73
483
Year Ended December 31, 2011
Maintenance
Capital
Expenditures
Expansion
Capital
Expenditures
Total
Consolidated
Capital
Expenditures
Our portion
Noncontrolling interest portion and
reimbursable projects (a)
Total
$
$
(Millions)
18
$
303
$
6
24
57
$
360
$
321
63
384
(a) In conjunction with our acquisitions of our East Texas and Southeast Texas systems, we entered into agreements with
DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for certain expenditures on capital projects.
These reimbursements are for certain capital projects which have commenced within three years from the respective
acquisition dates.
In addition, we invested cash in unconsolidated affiliates of $242 million, $158 million and $8 million net of returns,
during the year ended December 31, 2013, 2012 and 2011 respectively, to fund our share of capital expansion projects.
We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we
expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we
will rely upon external financing sources, which will include debt and common unit issuances, to fund our acquisition and
expansion capital expenditures.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit
Agreement, the issuance of additional partnership units and the issuance of Commercial Paper and long-term debt. If these
sources are not sufficient, we will reduce our discretionary spending.
Cash Distributions to Unitholders — Our partnership agreement requires that, within 45 days after the end of each
quarter, we distribute all Available Cash, as defined in the partnership agreement. We made cash distributions to our unitholders
and general partner of $277 million, $181 million and $132 million during the years ended December 31, 2013, 2012 and 2011,
respectively. We intend to continue making quarterly distribution payments to our unitholders and general partner to the extent
we have sufficient cash from operations after the establishment of reserves.
Description of the Credit Agreement — The Credit Agreement consists of a $1 billion revolving credit facility that
matures November 10, 2016. As of December 31, 2013, there was no outstanding balance on the revolving credit facility
resulting in unused revolver capacity of $664 million, all of which was available for general working capital purposes.
Our obligations under the revolving credit facility are unsecured. The unused portion of the revolving credit facility may
be used for letters of credit up to a maximum of $500 million of outstanding letters of credit. At December 31, 2013 and
December 31, 2012, we had $1 million outstanding letters of credit issued under the Credit Agreement. Amounts undrawn
under the revolving credit facility are available to repay amounts borrowed under our Commercial Paper Program, if necessary.
80
We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of
prepayment of London Interbank Offered Rate, or LIBOR, borrowings. Indebtedness under the Credit Agreement bears interest
at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current credit rating; or (2) (a) the base rate which shall
be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index rate plus
1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The revolving credit facility incurs an annual
facility fee of 0.25% based on our current credit rating. This fee is paid on drawn and undrawn portions of the revolving credit
facility.
The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our
consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and on a temporary
basis for not more than three consecutive quarters (including the quarter in which such acquisition is consummated) following
the consummation of asset acquisitions in the midstream energy business of not more than 5.5 to 1.0.
Description of Commercial Paper Program – In October 2013, we entered into a Commercial Paper Program under
which we may issue unsecured commercial paper notes, or the Notes. The Commercial Paper Program serves as an alternative
source of funding and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper
Program may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of Notes
outstanding, combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the
aggregate. Amounts undrawn under our revolving credit facility are available to repay the Notes, if necessary. The maturities of
the Notes will vary, but may not exceed 397 days from the date of issue. The Notes will be sold under customary terms in the
commercial paper market and may be issued at a discount from par, or, alternatively, may be sold at par and bear varying
interest rates on a fixed or floating basis. The proceeds of the issuances of the Notes are expected to be used for capital
expenditures and other general partnership purposes. As of December 31, 2013, we had $335 million of commercial paper
outstanding which is included in short-term borrowings in our consolidated balance sheets.
The weighted-average interest rate on our commercial paper was 1.14% per annum, excluding the impact of interest rate
swaps.
Description of Debt Securities – On March 14, 2013, we issued $500 million of 3.875% 10-year Senior Notes due
March 15, 2023. We received proceeds of $490 million, net of underwriters’ fees, related expenses and unamortized discounts
totaling $10 million, which we used to fund the cash portion of the purchase price for the acquisition of an additional 46.67%
interest in the Eagle Ford system. Interest on the notes will be paid semi-annually on March 15 and September 15 of each year,
commencing September 15, 2013. The notes will mature on March 15, 2023, unless redeemed prior to maturity. The
underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be
amortized over the term of the notes.
On November 27, 2012, we issued $500 million of our 2.50% 5-year Senior Notes due December 1, 2017. We received
net proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $6 million, which
were used to repay our then-outstanding term loans. Interest on the notes will be paid semi-annually on June 1 and December 1
of each year, commencing June 1, 2013. The notes will mature on December 1, 2017, unless redeemed prior to maturity. The
underwriters’ fees and related expenses are deferred in other long-term assets in our consolidated balance sheets and will be
amortized over the term of the notes.
On March 13, 2012, we issued $350 million of our 4.95% 10-year Senior Notes due April 1, 2022. We received net
proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discounts totaling $4 million, which we
used to fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds
borrowed under our Term Loan and Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of
each year. The notes will mature on April 1, 2022, unless redeemed prior to maturity. The underwriters’ fees and related
expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of the
notes.
On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net
proceeds of $248 million, net of underwriters’ fees, related expense and unamortized discounts of $2 million, which we used to
repay funds borrowed under the revolver portion of our Credit Agreement. Interest on the notes is paid semi-annually on April
1 and October 1 of each year. The notes will mature on October 1, 2015, unless redeemed prior to maturity. The underwriters’
fees and related expense are deferred in other long-term assets in our consolidated balance sheets and will be amortized over
the term of the notes.
81
The series of notes are senior unsecured obligations, ranking equally in right of payment with our existing unsecured
indebtedness, including indebtedness under our Credit Facility. We are not required to make mandatory redemption or sinking
fund payments with respect to any of these notes, and they are redeemable at a premium at our option.
Total Contractual Cash Obligations and Off-Balance Sheet Obligations
A summary of our total contractual cash obligations as of December 31, 2013, is as follows:
Debt (a)
Operating lease obligations (b)
Purchase obligations (c)
Other long-term liabilities (d)
Total
Payments Due by Period
Total
Less than
1 year
1-3 years
(Millions)
3-5 years
Thereafter
$
$
2,333
94
280
27
2,734
$
$
392
16
199
—
607
$
$
357
26
59
3
445
$
$
586
19
19
—
624
$
$
998
33
3
24
1,058
(a) Includes interest payments on debt securities that have been issued. These interest payments are $57 million, $107
million, $86 million, and $148 million for less than one year, one to three years, three to five years, and thereafter,
respectively. The above table does not include estimated payments associated with our interest rate swaps as the
repayment date and/or future interest rate are indeterminable.
(b) Our operating lease obligations are contractual obligations, and primarily consist of our leased marine propane terminal
and railcar leases, both of which provide supply and storage infrastructure for our Wholesale Propane Logistics
business. Operating lease obligations also include natural gas storage in our Northern Louisiana system. The natural gas
storage arrangement enables us to maximize the value between the current price of natural gas and the futures market
price of natural gas.
(c) Our purchase obligations are contractual obligations and include purchase orders for capital expenditures, various non-
cancelable commitments to purchase physical quantities of propane supply for our Wholesale Propane Logistics
business and other items. For contracts where the price paid is based on an index, the amount is based on the forward
market prices as of December 31, 2013. Purchase obligations exclude accounts payable, accrued interest payable and
other current liabilities recognized in the consolidated balance sheets. Purchase obligations also exclude current and
long-term unrealized losses on derivative instruments included in the consolidated balance sheet, which represent the
current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts
may be settled financially at the difference between the future market price and the contractual price and may result in
cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the
underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to
purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from the
table.
(d) Other long-term liabilities include $24 million of asset retirement obligations, $1 million of environmental reserves and
$2 million of firm transportation commitments recognized in the December 31, 2013 consolidated balance sheet. In
addition, $11 million of deferred state income taxes was excluded as cash payments for income taxes are determined
primarily by taxable income for each discrete fiscal year.
We have no items that are classified as off balance sheet obligations.
82
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make
estimates and assumptions. We believe that the following are the more critical judgment areas in the application of our
accounting policies that currently affect our financial condition and results of operations. These accounting policies are
described further in Note 2 of the Notes to Consolidated Financial Statements in Item 8. "Financial Statements and
Supplementary Data."
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
Inventories
Inventories, which consist of NGLs
and natural gas, are recorded at the
lower of weighted-average cost or
market value.
Impairment of Goodwill
We evaluate goodwill for impairment
annually in the third quarter, and
whenever events or changes in
circumstances indicate it is more
likely than not that the fair value of a
reporting unit is less than its carrying
amount.
Judgment is required in determining
the market value of inventory, as the
geographic location impacts market
prices, and quoted market prices may
not be available for the particular
location of our inventory.
If the market value of our inventory is
lower than the cost, we may be
exposed to losses that could be
material. If commodity prices were to
decrease by 10% below our
December 31, 2013 weighted-average
cost, our net income would be
affected by approximately $7 million.
We determine fair value using widely
accepted valuation techniques,
namely discounted cash flow and
market multiple analyses. These
techniques are also used when
assigning the purchase price to
acquired assets and liabilities. These
types of analyses require us to make
assumptions and estimates regarding
industry and economic factors and the
profitability of future business
strategies. It is our policy to conduct
impairment testing based on our
current business strategy in light of
present industry and economic
conditions, as well as future
expectations.
We primarily use a discounted cash
flow analysis, supplemented by a
market approach analysis, to perform
the assessment. Key assumptions in
the analysis include the use of an
appropriate discount rate, terminal
year multiples, and estimated future
cash flows including an estimate of
operating and general and
administrative costs. In estimating
cash flows, we incorporate current
market information, as well as
historical and other factors, into our
forecasted commodity prices. If our
assumptions are not appropriate, or
future events indicate that our
goodwill is impaired, our net income
would be impacted by the amount by
which the carrying value exceeds the
fair value of the reporting unit, to the
extent of the balance of goodwill. We
have not recorded any impairment
charges on goodwill during the year
ended December 31, 2013.
83
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
Impairment of Long-Lived Assets
We periodically evaluate whether the
carrying value of long-lived assets
has been impaired when
circumstances indicate the carrying
value of those assets may not be
recoverable. This evaluation is based
on undiscounted cash flow projections
expected to be realized over the
remaining useful life of the primary
asset. The carrying amount is not
recoverable if it exceeds the sum of
undiscounted cash flows expected to
result from the use and eventual
disposition of the asset. If the
carrying value is not recoverable, the
impairment loss is measured as the
excess of the asset’s carrying value
over its fair value.
Our impairment analyses require
management to apply judgment in
estimating future cash flows as well
as asset fair values, including
forecasting useful lives of the assets,
assessing the probability of different
outcomes, and selecting the discount
rate that reflects the risk inherent in
future cash flows. If the carrying
value is not recoverable, we assess the
fair value of long-lived assets using
commonly accepted techniques, and
may use more than one method,
including, but not limited to, recent
third party comparable sales and
discounted cash flow models. These
techniques are also used when
assigning the purchase price to
acquired assets and liabilities.
Impairment of Investments in Unconsolidated Affiliates
We evaluate our investments in
unconsolidated affiliates for
impairment whenever events or
changes in circumstances indicate, in
management’s judgment, that the
carrying value of such investment
may have experienced a decline in
value. When evidence of loss in value
has occurred, we compare the
estimated fair value of the investment
to the carrying value of the investment
to determine whether an impairment
has occurred.
Our impairment analyses require
management to apply judgment in
estimating future cash flows and asset
fair values, including forecasting
useful lives of the assets, assessing
the probability of differing estimated
outcomes, and selecting the discount
rate that reflects the risk inherent in
future cash flows. When there is
evidence of loss in value, we assess
the fair value of our unconsolidated
affiliates using commonly accepted
techniques, and may use more than
one method, including, but not limited
to, recent third party comparable sales
and discounted cash flow models.
Using the impairment review
methodology described herein, we
have not recorded any impairment
charges on long-lived assets during
the year ended December 31, 2013. If
actual results are not consistent with
our assumptions and estimates or our
assumptions and estimates change due
to new information, we may be
exposed to an impairment charge.
Using the impairment review
methodology described herein, we
have not recorded any impairment
charges on investments in
unconsolidated affiliates during the
year ended December 31, 2013. If the
estimated fair value of our
unconsolidated affiliates is less than
the carrying value, we would
recognize an impairment loss for the
excess of the carrying value over the
estimated fair value.
84
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
When available, quoted market prices
or prices obtained through external
sources are used to determine a
contract’s fair value. For contracts
with a delivery location or duration
for which quoted market prices are
not available, fair value is determined
based on pricing models developed
primarily from historical information
and the expected relationship with
quoted market prices.
Accounting for Risk Management Activities and Financial Instruments
Each derivative not qualifying for the
normal purchases and normal sales
exception is recorded on a gross basis
in the consolidated balance sheets at
its fair value as unrealized gains or
unrealized losses on derivative
instruments. Derivative assets and
liabilities remain classified in our
consolidated balance sheets as
unrealized gains or unrealized losses
on derivative instruments at fair value
until the contractual settlement period
impacts earnings. Values are adjusted
to reflect the credit risk inherent in the
transaction as well as the potential
impact of liquidating open positions
in an orderly manner over a
reasonable time period under current
conditions.
Accounting for Asset Retirement Obligations
Asset retirement obligations
associated with tangible long-lived
assets are recorded at fair value in the
period in which they are incurred, if a
reasonable estimate of fair value can
be made, and added to the carrying
amount of the associated asset. This
additional carrying amount is then
depreciated over the life of the asset.
The liability is determined using a
credit adjusted risk free interest rate,
and accretes due to the passage of
time based on the time value of money
until the obligation is settled.
Estimating the fair value of asset
retirement obligations requires
management to apply judgment to
evaluate the necessary retirement
activities, estimate the costs to
perform those activities, including the
timing and duration of potential future
retirement activities, and estimate the
risk free interest rate. When making
these assumptions, we consider a
number of factors, including historical
retirement costs, the location and
complexity of the asset and general
economic conditions.
If our estimates of fair value are
inaccurate, we may be exposed to
losses or gains that could be material.
A 10% difference in our estimated fair
value of derivatives at December 31,
2013 would have affected net income
by approximately $14 million based
on our net derivative position for the
year ended December 31, 2013.
If actual results are not consistent
with our assumptions and judgments
or our assumptions and estimates
change due to new information, we
may experience material changes in
our asset retirement obligations.
Establishing an asset retirement
obligation has no initial impact on net
income. A 10% change in
depreciation and accretion expense
associated with our asset retirement
obligations during the year ended
December 31, 2013 would have less
than a $1 million impact on our net
income.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Market risk is the risk of loss arising from adverse changes in market prices and rates. We are exposed to market risks,
including changes in commodity prices and interest rates. We may use financial instruments such as forward contracts, swaps
and futures to mitigate a portion of the effects of identified risks. In general, we attempt to mitigate a portion of the risks related
to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so
that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and
similar requirements.
Risk Management Policy
We have established a comprehensive risk management policy, or Risk Management Policy, and a risk management
committee, or the Risk Management Committee, to monitor and manage market risks associated with commodity prices and
counterparty credit. Our Risk Management Committee is composed of senior executives who receive regular briefings on
positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk
Management Committee is responsible for the overall management of counterparty credit risk and commodity price risk,
including monitoring exposure limits.
See Note 11, Risk Management and Hedging Activities, of the Notes to Consolidated Financial Statements in Item 8.
“Financial Statements and Supplementary Data” for further discussion of the accounting for derivative contracts.
85
Credit Risk
Our principal customers in the Natural Gas Services segment are large, natural gas marketers and industrial end-users. In
the NGL Logistics Segment, our principal customers include an affiliate of DCP Midstream, LLC, producers and marketing
companies. Our principal customers in the Wholesale Propane Logistics segment are primarily propane distributors.
Substantially all of our natural gas, propane and NGL sales are made at market-based prices. This concentration of credit risk
may affect our overall credit risk, as these customers may be similarly affected by changes in economic, regulatory or other
factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement,
establish credit limits, and monitor the appropriateness of these limits on an ongoing basis. We operate under DCP Midstream,
LLC’s corporate credit policy. DCP Midstream, LLC’s corporate credit policy, as well as the standard terms and conditions of
our agreements, prescribe the use of financial responsibility and reasonable grounds for adequate assurances. These provisions
allow our credit department to request that a counterparty remedy credit limit violations by posting cash or letters of credit for
exposure in excess of an established credit line. The credit line represents an open credit limit, determined in accordance with
DCP Midstream, LLC’s credit policy. Our standard agreements also provide that the inability of a counterparty to post
collateral is sufficient cause to terminate a contract and liquidate all positions. The adequate assurance provisions also allow us
to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment to us
in a satisfactory form.
Interest Rate Risk
Interest rates on future credit agreement draws and debt offerings could be higher than current levels, causing our
financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we
expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar
circumstances. We may mitigate a portion of our future interest rate risk with interest rate swaps that reduce our exposure to
market rate fluctuations by converting variable interest rates on our debt to fixed interest rates and locking in rates on our
anticipated future fixed-rate debt, respectively.
At December 31, 2013, we had interest rate swap agreements extending through June 2014 with notional values totaling
$150 million, which are accounted for under the mark-to-market method of accounting and reprice prospectively approximately
every 30 days. Under the terms of the interest rate swap agreements, we pay fixed-rates ranging from 2.94% to 2.99%, and
receive interest payments based on the one-month LIBOR. Prior to August of 2013, these interest rate swaps were designated as
cash flow hedges whereby the effective portions of changes in fair value were recognized in AOCI in the consolidated balance
sheets.
At December 31, 2013, the effective weighted-average interest rate on our outstanding debt was 3.42%, taking into
account our interest rate swap agreements with notional values totaling $150 million.
Based on the annualized unhedged borrowings under our Commercial Paper Program of $335 million as of December 31,
2013, a 0.5% annual movement in the interest rates would result in an approximately $2 million annualized increase or
decrease in interest expense.
Commodity Price Risk
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our
gathering, processing, sales and storage activities. For gathering services, we receive fees or commodities from producers to
bring the natural gas from the wellhead to the processing plant. For processing and storage services, we either receive fees or
commodities as payment for these services, depending on the types of contracts. We employ established policies and
procedures to manage our risks associated with these market fluctuations using various commodity derivatives, including
forward contracts, swaps, costless collars and futures.
Commodity Cash Flow Protection Activities - We closely monitor the risks associated with commodity price changes on
our future operations and, where appropriate, use various fixed price swaps and costless collar arrangements to mitigate a
portion of the effect pricing fluctuations may have on the value of our assets and operations. Depending on our risk
management objectives, we may periodically settle a portion of these instruments prior to their maturity.
We enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and
condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Our
commodity derivative instruments used for our hedging program are a combination of direct NGL product, crude oil, and
natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we have used crude oil swaps and
costless collars to mitigate a portion of our commodity price exposure to NGLs. Historically, prices of NGLs have generally
been related to crude oil prices, however there are periods of time when NGL pricing may be at a greater discount to crude oil,
86
resulting in additional exposure to NGL commodity prices. During 2013, the relationship of NGLs to crude oil has been lower
than historical relationships, however a significant amount of our NGL hedges from 2014 through 2017 are direct product
hedges. When our crude oil swaps become short-term in nature, we have periodically converted certain crude oil derivatives to
NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps.
The derivative financial instruments we have entered into are typically referred to as “swap” contracts. The swap
contracts entitle us to receive payment at settlement from the counterparty to the contract to the extent that the reference price is
below the swap price stated in the contract, and we are required to make payment at settlement to the counterparty to the extent
that the reference price is higher than the swap price stated in the contract.
We use the mark-to-market method of accounting for all commodity cash flow protection activities, which has
significantly increased the volatility of our results of operations as we recognize, in current earnings, all non-cash gains and
losses from the mark-to-market on derivative activity.
The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural
gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our
gathering operations, as of February 20, 2014:
Commodity Swaps
Period
Commodity
Notional
Volume
- (Short)/Long
Positions
Reference Price
January 2014 — December 2014
January 2014 — December 2014
Natural Gas
(500) MMBtu/d
Natural Gas
(21,422) MMBtu/d
IFERC Monthly Index Price for Colorado
Interstate Gas Pipeline (a)
IFERC Monthly Index Price for Houston Ship
Channel (e)
February 2014 — December 2014
Natural Gas
(2,500) MMBtu/d
NYMEX Final Settlement Price (g)
January 2015 — December 2015
January 2016 — March 2016
Natural Gas
(24,738) MMBtu/d
Natural Gas
(16,163) MMBtu/d
IFERC Monthly Index Price for Houston Ship
Channel (e)
IFERC Monthly Index Price for Houston Ship
Channel (e)
Price Range
$5.06/MMBtu
$4.50/MMBtu
$4.50/MMBtu
$4.50/MMBtu
$4.50/MMBtu
January 2014 — December 2014
Natural Gas
(6,766) MMBtu/d
IFERC Monthly Index Price for Henry Hub (f)
$4.50/MMBtu
January 2015 — December 2015
Natural Gas
(8,677) MMBtu/d
IFERC Monthly Index Price for Henry Hub (f)
$4.50/MMBtu
January 2016 — March 2016
Natural Gas
(4,041) MMBtu/d
IFERC Monthly Index Price for Henry Hub (f)
$4.50/MMBtu
January 2017 — December 2017
Natural Gas
(7,500) MMBtu/d
NYMEX Final Settlement Price (g)
January 2014 — December 2014
February 2014 — December 2014
January 2015 — March 2015
April 2015 — December 2015
January 2016 — March 2016
January 2014 — December 2014
January 2015 — December 2015
January 2016 — March 2016
April 2016 — December 2016
January 2014 — December 2014
January 2015 — December 2015
NGL's
NGL's
NGL's
NGL's
NGL's
Crude Oil
Crude Oil
Crude Oil
Crude Oil
(14,334) Bbls/d
(2,220) Bbls/d
(16,893) Bbls/d
(15,168) Bbls/d
(8,937) Bbls/d
Mt.Belvieu Non-TET (d)
Mt.Belvieu Non-TET (d)
Mt.Belvieu Non-TET (d)
Mt.Belvieu Non-TET (d)
Mt.Belvieu Non-TET (d)
$4.17/MMBtu
$0.64-$2.60/Gal
$1.12-$1.97/Gal
$0.64-$2.60/Gal
$0.64-$1.89/Gal
$0.64-$1.89/Gal
(1,893) Bbls/d
Asian-pricing of NYMEX crude oil futures (c)
$74.90 - $96.08/Bbl
(2,043) Bbls/d
Asian-pricing of NYMEX crude oil futures (c)
$87.60-$100.04/Bbl
(1,642) Bbls/d
Asian-pricing of NYMEX crude oil futures (c)
$85.15-$101.30/Bbl
(1,500) Bbls/d
Asian-pricing of NYMEX crude oil futures (c)
$85.15-$101.30/Bbl
Natural Gas
5,000 MMBtu/d
NYMEX Final Settlement Price (g)
$3.93 - $4.02/MMBtu
Natural Gas
7,500 MMBtu/d
NYMEX Final Settlement Price (g)
$4.15 - $4.22/MMBtu
January 2014 — December 2014
Natural Gas
500 MMBtu/d
Texas Gas Transmission Price (b)
$4.93/MMBtu
(a) The Inside FERC index price for natural gas delivered into the Colorado Interstate Gas (CIG) pipeline.
(b) The Inside FERC index price for natural gas delivered into the Texas Gas Transmission pipeline in the North Louisiana
area.
(c) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract (CL).
(d) The average monthly OPIS price for Mt. Belvieu Non-TET.
(e) The Inside FERC monthly published index price for Houston Ship Channel.
(f) The inside FERC monthly published index price for Henry Hub.
(g) NYMEX final settlement price for natural gas futures contracts (NG).
87
Our sensitivities for 2014 as shown in the table below are estimated based on our average estimated commodity price
exposure and commodity cash flow protection activities for the calendar year 2014, and exclude the impact from non-cash
mark-to-market on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to mitigate
a significant portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with
our unhedged condensate, natural gas and NGL volumes.
Commodity Sensitivities Excluding Non-Cash Mark-To-Market
Per Unit Decrease
Unit of
Measurement
Estimated
Decrease in
Annual Net
Income
Attributable to
Partners
(Millions)
Natural gas prices
Crude oil prices
NGL prices
$
$
$
0.10
1.00
0.01
MMBtu
Barrel
Gallon
$
$
$
—
—
0.7
In addition to the linear relationships in our commodity sensitivities above, additional factors cause us to be less sensitive
to commodity price declines. A portion of our net income is derived from fee-based contracts and a portion from percentage of
liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based
arrangements as NGL prices decline.
The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not
process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above
sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production
based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the
natural gas would yield favorable processing margins. Less than 10% of our gas throughput is associated with these
arrangements.
We estimate the following non-cash sensitivities for 2014 related to the mark-to-market on our commodity derivatives
associated with our commodity cash flow protection activities:
Non-Cash Mark-To-Market Commodity Sensitivities
Per Unit
Increase
Unit of
Measurement
Estimated
Mark-to-
Market Impact
(Decrease in
Net Income
Attributable to
Partners)
(Millions)
Natural gas prices
Crude oil prices
NGL prices
$
$
$
0.10
1.00
0.01
MMBtu
Barrel
Gallon
$
$
$
2
2
5
While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have
on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in
the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these
estimates.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly
affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil. Although the
prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the
long-term the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide
incentives and capital for producers to increase natural gas exploration and production. To minimize potential future
commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result
88
of these transactions, we have mitigated a significant portion of our expected natural gas, NGL and condensate commodity
price risk relating to the equity volumes associated with our gathering and processing activities through 2017.
Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the
long-term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large
part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in
the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. However, the level of
NGL exports has increased in recent years. We believe that future natural gas prices will be influenced by North American
supply deliverability, the severity of winter and summer weather, the level of North American production and drilling activity
of exploration and production companies and the balance of imports and exports of liquid natural gas, or LNG, from and to
foreign locations. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could
also reduce North American drilling activity. Limited access to capital could also decrease drilling. Lower drilling levels over a
sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply
were to fall relative to demand levels.
Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline
assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our
natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our
natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis
spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal
short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection,
withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk
of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our
physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these
transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded
in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of
average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and
any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have
economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our
physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market
volatility.
The following tables set forth additional information about our derivative instruments used to mitigate a portion of our
natural gas price risk associated with our Southeast Texas storage operations, as of December 31, 2013:
Inventory
Period ended
Commodity
Notional Volume -
Long
Positions
Fair Value
(millions)
Weighted
Average Price
December 31, 2013
Natural Gas
9,944,991 MMBtu
$
36
$3.58/MMBtu
Commodity Swaps
Period
Commodity
Notional Volume -
(Short)/Long
Positions
Fair Value
(millions)
Price Range
January 2014-December 2015
January 2014-December 2015
Natural Gas
(52,982,500) MMBtu
Natural Gas
40,990,000 MMBtu
$
$
(16)
9
$3.56-$4.44/MMBtu
$3.56-$4.50/MMBtu
Our wholesale propane logistics business is generally designed to establish stable margins by entering into supply
arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide
for floating prices that are tied to our variable supply costs plus a margin. Occasionally, we may enter into fixed price sales
agreements in the event that a propane distributor desires to purchase propane from us on a fixed price basis. We manage this
risk with both physical and financial transactions, sometimes using non-trading derivative instruments, which generally allow
89
us to swap our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may on
occasion use financial derivatives to manage the value of our propane inventories.
We manage our commodity derivative activities in accordance with our Risk Management Policy which limits exposure
to market risk and requires regular reporting to management of potential financial exposure.
Valuation - Valuation of a contract’s fair value is validated by an internal group independent of the marketing group.
While common industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying
assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or
prices obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or
duration for which quoted market prices are not available, fair value is determined based on pricing models developed
primarily from historical and expected relationships with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such
estimates may change in the near term.
The fair value of our interest rate swaps and commodity non-trading derivatives is expected to be realized in future
periods, as detailed in the following table. The amount of cash ultimately realized for these contracts will differ from the
amounts shown in the following table due to factors such as market volatility, counterparty default and other unforeseen events
that could impact the amount and/or realization of these values.
Sources of Fair Value
Total
Maturity in
2014
Maturity in
2015-2016
Maturity in
2017-2018
Maturity in
2019 and
Thereafter
Fair Value of Contracts as of December 31, 2013
(Millions)
Prices supported by quoted market
prices and other external sources
Prices based on models or other
valuation techniques
Total
$
$
(3) $
(14) $
11
$
— $
140
137
$
65
51
$
75
86
$
—
— $
—
—
—
The “prices supported by quoted market prices and other external sources” category includes our interest rate swaps, our
New York Mercantile Exchange, or NYMEX, positions in natural gas, NGLs and crude oil. In addition, this category includes
our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then
validated through an internal process which includes the use of independent broker quotes. This category also includes our
forward positions in NGLs at points for which over-the-counter, or OTC, broker quotes for similar assets or liabilities are
available for the full term of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or
indirectly observable from external sources and then modeled to daily or monthly prices as appropriate.
The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to
the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of
the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was
constructed as a result of the long dated nature of the transaction or the illiquidity of the market point.
90
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
DCP MIDSTREAM PARTNERS, LP CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2013 and 2012
Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Changes in Equity for the years ended December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements
92
93
94
95
96
99
100
91
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream GP, LLC
Denver, Colorado
We have audited the accompanying consolidated balance sheets of DCP Midstream Partners, LP and subsidiaries (the
"Company") as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income
(loss), changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. These financial
statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the
Company as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of
America.
The consolidated financial statements give retrospective effect for the Company’s acquisition of the 100% ownership interest in
DCP Southeast Texas Holdings, GP, of which 33.33% and 66.67% was acquired on January 1, 2011 and March 30, 2012,
respectively, from DCP Midstream, LLC, as a combination of entities under common control, which has been accounted for in
a manner similar to a pooling of interests, as described in Note 1 to the consolidated financial statements.
The consolidated financial statements give retrospective effect for the Company’s acquisition of the 80% ownership interest in
DCP SC Texas, GP, of which 33.33% and 46.7% was acquired on November 2, 2012 and March 28, 2013, respectively, from
DCP Midstream, LLC, as a combination of entities under common control, which has been accounted for in a manner similar to
a pooling of interests, as described in Note 1 to the consolidated financial statements.
Also as described in Note 1 to the consolidated financial statements, the portion of the accompanying consolidated financial
statements for the three years in the period ended December 31, 2013 attributable to DCP Southeast Texas Holdings, GP and
DCP SC Texas, GP has been prepared from the separate records maintained by DCP Midstream, LLC and may not necessarily
be indicative of the conditions that would have existed or the results of operations if DCP Southeast Texas Holdings, GP and
DCP SC Texas, GP had been operated as unaffiliated entities. Portions of certain expenses represent allocations made from, and
are applicable to, DCP Midstream, LLC as a whole.
The consolidated financial statements give retrospective effect to new disclosure requirements regarding information related to
balance sheet offsetting of assets and liabilities as disclosed in Note 11 to the consolidated financial statements.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the Company’s internal control over financial reporting as of December 31, 2013, based on the criteria established in the
Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 26, 2014 expressed an unqualified opinion on the Company’s internal control over
financial reporting.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2014
92
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
Current assets:
Cash and cash equivalents
Accounts receivable:
ASSETS
Trade, net of allowance for doubtful accounts of $1 million and less than $1
million, respectively
Affiliates
Inventories
Unrealized gains on derivative instruments
Other
Total current assets
Property, plant and equipment, net
Goodwill
Intangible assets, net
Investments in unconsolidated affiliates
Unrealized gains on derivative instruments
Other long-term assets
Total assets
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade
Affiliates
Short-term borrowings
Unrealized losses on derivative instruments
Capital spending accrual
Other
Total current liabilities
Long-term debt
Unrealized losses on derivative instruments
Other long-term liabilities
Total liabilities
Commitments and contingent liabilities
Equity:
Predecessor equity
Limited partners (89,045,139 and 61,346,058 common units issued and outstanding,
respectively)
General partner
Accumulated other comprehensive loss
Total partners’ equity
Noncontrolling interests
Total equity
Total liabilities and equity
See accompanying notes to consolidated financial statements.
December 31,
2013
December 31,
2012
(Millions)
$
12
$
2
130
212
67
79
3
503
3,005
154
129
627
87
21
4,526
232
43
335
28
24
60
722
1,590
1
40
2,353
$
$
—
1,948
8
(11)
1,945
228
2,173
4,526
$
107
132
76
49
2
368
2,550
154
137
304
70
20
3,603
151
72
—
31
44
47
345
1,620
8
36
2,009
357
1,063
—
(15)
1,405
189
1,594
3,603
$
$
$
93
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Operating revenues:
Sales of natural gas, propane, NGLs and condensate
Sales of natural gas, propane, NGLs and condensate to
affiliates
Transportation, processing and other
Transportation, processing and other to affiliates
(Losses) gains from commodity derivative activity, net
Gains from commodity derivative activity, net — affiliates
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and NGLs
Purchases of natural gas, propane and NGLs from affiliates
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
General and administrative expense — affiliates
Other expense (income)
Total operating costs and expenses
Operating income
Interest expense
Earnings from unconsolidated affiliates
Income before income taxes
Income tax expense
Net income
Net income attributable to noncontrolling interests
Net income attributable to partners
Net income attributable to predecessor operations
General partner’s interest in net income
Net income allocable to limited partners
Net income per limited partner unit — basic
Net income per limited partner unit — diluted
Weighted-average limited partner units outstanding — basic
Weighted-average limited partner units outstanding — diluted
$
$
$
Year Ended December 31,
2013
2012
2011
(Millions, except per unit amounts)
$
932
$
820
$
1,171
1,763
211
57
(5)
22
2,980
2,159
222
211
93
17
45
8
2,755
225
(52)
33
206
(8)
198
(17)
181
(6)
(70)
105
1.34
1.34
78.4
78.4
$
$
$
1,639
179
53
17
53
2,761
1,807
370
193
89
17
57
—
2,533
228
(42)
26
212
(1)
211
(13)
198
(33)
(41)
124
2.28
2.28
54.5
54.5
$
$
$
2,316
169
36
7
1
3,700
2,445
655
188
133
19
56
(1)
3,495
205
(34)
23
194
(1)
193
(30)
163
(63)
(25)
75
1.73
1.72
43.5
43.6
See accompanying notes to consolidated financial statements.
94
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income
Other comprehensive income (loss):
Reclassification of cash flow hedge losses into
earnings
Net unrealized losses on cash flow hedges
Net unrealized losses on cash flow hedges -
predecessor operations
Total other comprehensive income
Total comprehensive income
Total comprehensive income attributable to
noncontrolling interests
Total comprehensive income attributable to partners
$
Year Ended December 31,
2013
2012
(Millions)
2011
$
198
$
211
$
193
4
—
—
4
202
10
—
(1)
9
220
(17)
185
$
(13)
207
$
21
(13)
(2)
6
199
(30)
169
See accompanying notes to consolidated financial statements.
95
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Partners’ Equity
Predecessor
Equity
Limited Partners General Partner
Accumulated Other
Comprehensive
(Loss) Income
Noncontrolling
Interests
Total
Equity
Balance, January 1, 2013
$
357
$
1,063
$
(Millions)
— $
(15) $
189
$
1,594
Net income
Other comprehensive income
Net change in parent advances
Acquisition of an additional
46.67% interest in the Eagle
Ford system
Issuance of units for the Eagle
Ford system
Excess purchase price over
carrying value of acquired
investment of 33.33% interest
in the Eagle Ford system and
NGL hedge
Excess purchase price over
carrying value of acquired
additional 46.67% interest in
the Eagle Ford system and
commodity hedge
Issuance of 24,897,977
common units
Distributions to limited
partners and general partner
Distributions to
noncontrolling interests
Contributions from
noncontrolling interests
Contributions from DCP
Midstream, LLC
6
—
32
(395)
—
—
—
—
—
—
—
—
105
—
—
—
125
(7)
(203)
1,082
(215)
—
—
1
Distributions to DCP
Midstream, LLC
Balance, December 31, 2013 $
—
— $
(3)
1,948
$
70
—
—
—
—
—
—
—
(62)
—
—
—
—
8
—
4
—
—
—
—
—
—
—
—
—
—
17
—
—
—
—
198
4
32
(395)
125
—
(7)
—
—
—
(203)
1,082
(277)
(24)
(24)
46
—
46
1
$
—
(11) $
—
228
$
(3)
2,173
See accompanying notes to consolidated financial statements.
96
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Partners’ Equity
Predecessor
Equity
Limited
Partners
General
Partner
Accumulated
Other
Comprehensive
(Loss) Income
Noncontrolling
Interests
Total
Equity
Balance, January 1, 2012
$
628
$
(Millions)
(5) $
41
(21) $
—
Net income
Other comprehensive (loss) income
Net change in advances to
predecessor from DCP Midstream,
LLC
Acquisition of 33.33% interest in
the Eagle Ford system
Acquisition of additional 66.67%
interest in Southeast Texas and
NGL Hedge
Acquisition of additional 49.9%
interest in East Texas
Issuance of units for Southeast
Texas
Issuance of units for East Texas
Issuance of units for Mont Belvieu
fractionators
Issuance of units for 33.33%
interest in the Eagle Ford system
Deficit purchase price under
carrying value of acquired net
assets for Southeast Texas and East
Texas
Excess purchase price over
carrying value of acquired
investments in Mont Belvieu
fractionators
Excess purchase price over
carrying value of acquired
investment of 33.33% interest in
the Eagle Ford system and NGL
Hedge
Excess purchase price over
carrying value of acquired net
assets by the Eagle Ford system for
Goliad and NGL Hedge
Issuance of 11,285,956 common
units
Distributions to limited partners
and general partner
Distributions to noncontrolling
interests
Contributions from noncontrolling
interests
Contributions from DCP
Midstream, LLC
Balance, December 31, 2012
$
654
124
—
—
—
40
—
48
33
60
88
36
(175)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(156)
(9)
455
(145)
(36)
—
—
10
—
—
—
33
(1)
200
(232)
(248)
—
—
—
—
—
—
—
(23)
—
—
—
—
—
306
$
1,562
13
—
40
—
—
(176)
—
—
—
—
—
—
211
9
240
(232)
(208)
(176)
48
33
60
88
32
(175)
—
(156)
(10)
—
—
(9)
25
—
(42)
455
(181)
(9)
25
10
189
$
1,594
10
—
—
—
—
—
—
—
—
(4)
—
—
—
—
—
—
—
—
(15) $
$
357
$
1,063
$
— $
See accompanying notes to consolidated financial statements.
97
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Partners’ Equity
Predecessor
Equity
Limited
Partners
General
Partner
Accumulated
Other
Comprehensive
(Loss) Income
Noncontrolling
Interests
Total
Equity
Balance, January 1, 2011
$
610
$
552
$
Net income
Other comprehensive (loss)
income
Net change in advances to
predecessor from DCP
Midstream, LLC
Acquisition of Southeast
Texas
Excess purchase price over
acquired assets
Issuance of 4,357,921
common units
Equity-based compensation
Distributions to DCP
Midstream, LLC
Distributions to limited
partners and general partner
Distributions to
noncontrolling interests
Contributions from
noncontrolling interests
Balance, December 31, 2011 $
63
(2)
71
(114)
—
—
—
—
—
—
—
75
—
—
—
(35)
170
3
(3)
(108)
—
—
628
$
654
$
(Millions)
(6) $
25
(28) $
—
—
—
—
—
—
—
—
(24)
—
—
(5) $
8
—
—
(1)
—
—
—
—
—
—
(21) $
288
$
1,416
30
—
15
—
—
—
—
—
—
(45)
18
193
6
86
(114)
(36)
170
3
(3)
(132)
(45)
18
306
$
1,562
See accompanying notes to consolidated financial statements.
98
DCP MIDSTREAM PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2013
2012
(Millions)
2011
$
198
$
211
$
193
OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization expense
Earnings from unconsolidated affiliates
Distributions from unconsolidated affiliates
Net unrealized losses (gains) on derivative instruments
Deferred income taxes, net
Other, net
Change in operating assets and liabilities, which (used) provided
cash, net of effects of acquisitions:
Accounts receivable
Inventories
Accounts payable
Accrued interest
Other current assets and liabilities
Other long-term assets and liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES:
Capital expenditures
Acquisitions, net of cash acquired
Acquisition of unconsolidated affiliates
Investments in unconsolidated affiliates
Return of investment from unconsolidated affiliate
Proceeds from sales of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from long-term debt
Payments of long-term debt
Proceeds from issuance of commercial paper
Payments of deferred financing costs
Excess purchase price over acquired interests and commodity hedges
Proceeds from issuance of common units, net of offering costs
Net change in advances to predecessor from DCP Midstream, LLC
Distributions to limited partners and general partner
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Distributions to DCP Midstream, LLC
Contributions from DCP Midstream, LLC
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
$
93
(33)
39
36
5
14
(89)
9
51
5
(2)
(2)
324
(363)
(696)
(86)
(242)
—
—
(1,387)
1,957
(1,988)
335
(4)
(85)
1,083
32
(277)
(24)
46
(3)
1
1,073
10
2
12
$
89
(26)
24
(21)
—
3
(11)
14
(194)
5
(4)
(8)
82
(483)
(433)
(312)
(158)
1
2
(1,383)
2,665
(1,792)
—
(8)
(225)
455
355
(181)
(9)
25
—
10
1,295
(6)
8
2
$
133
(23)
25
(40)
(29)
5
34
(14)
106
—
2
(5)
387
(384)
(38)
(114)
(8)
2
5
(537)
1,524
(1,425)
—
(4)
(36)
170
81
(132)
(45)
18
—
—
151
1
7
8
See accompanying notes to consolidated financial statements.
99
DCP MIDSTREAM PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2013, 2012 and 2011
1. Description of Business and Basis of Presentation
DCP Midstream Partners, LP, with its consolidated subsidiaries, or us, we, our or the Partnership, is engaged in the
business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating,
transporting, storing and selling NGLs and recovering and selling condensate; and transporting, storing and selling propane in
wholesale markets.
We are a Delaware limited partnership that was formed in August 2005. Our partnership includes: our natural gas services
segment (which includes our 80% interest in the Eagle Ford system, our 100% owned Eagle Plant; our East Texas system; our
Southeast Texas system; our Michigan system; our Northern Louisiana system; our Southern Oklahoma system; our Wyoming
system; a 75% interest in Collbran Valley Gas Gathering, LLC, or Collbran or our Piceance system; our 40% interest in
Discovery Producer Services LLC, or Discovery; and our O'Connor plant), our NGL logistics segment (which includes the
NGL storage facility in Michigan, our 12.5% interest in the Mont Belvieu Enterprise fractionator, our 20% interest in the Mont
Belvieu 1 fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ Basin NGL fractionators, the Seabreeze
and Wilbreeze intrastate NGL pipelines, our 33.33% interest in the Front Range interstate NGL pipeline, and our 10% interest
in the Texas Express intrastate NGL pipeline), and our wholesale propane logistics segment (which includes six rail terminals,
two marine terminals and one pipeline terminal).
Our operations and activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by
its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and is 100% owned by DCP Midstream,
LLC. DCP Midstream, LLC and its subsidiaries and affiliates, collectively referred to as DCP Midstream, LLC, is owned 50%
by Phillips 66 and 50% by Spectra Energy Corp and its affiliates, or Spectra Energy. DCP Midstream, LLC directs our business
operations through its ownership and control of the General Partner. DCP Midstream, LLC and its affiliates’ employees provide
administrative support to us and operate most of our assets. DCP Midstream, LLC owns approximately 23% of us.
The consolidated financial statements include the accounts of the Partnership and all majority-owned subsidiaries where
we have the ability to exercise control. Investments in greater than 20% owned affiliates that are not variable interest entities
and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the
ability to exercise significant influence, are accounted for using the equity method. All intercompany balances and transactions
have been eliminated.
Our predecessor operations consist of a 66.67% interest in Southeast Texas and commodity derivative hedge instruments
related to the Southeast Texas storage business, which we acquired from DCP Midstream, LLC in March 2012, and an 80%
interest in the Eagle Ford system, of which we acquired 33.33% and 46.67% in November 2012 and March 2013, respectively,
from DCP Midstream, LLC. Prior to our acquisition of the remaining 66.67% interest in Southeast Texas, we accounted for our
initial 33.33% interest as an unconsolidated affiliate using the equity method. Subsequent to the March 2012 transaction, we
own 100% of Southeast Texas which we account for as a consolidated subsidiary. Prior to our acquisition of the additional
46.67% interest in the Eagle Ford system in March 2013, we accounted for our initial 33.33% interest as an unconsolidated
affiliate using the equity method. Subsequent to the March 2013 transaction, we own 80% of the Eagle Ford system which we
account for as a consolidated subsidiary. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish
comparative information, similar to the pooling method. Accordingly, our consolidated financial statements include the
historical results of our 100% interest in Southeast Texas and the commodity derivative hedge instruments associated with the
storage business, and 80% interest in the Eagle Ford system for all periods presented. We recognize transfers of net assets
between entities under common control at DCP Midstream, LLC’s basis in the net assets contributed. The amount of the
purchase price in excess or in deficit of DCP Midstream, LLC’s basis in the net assets is recognized as a reduction or an
addition to limited partners’ equity. The financial statements of our predecessor have been prepared from the separate records
maintained by DCP Midstream, LLC and may not necessarily be indicative of the conditions that would have existed or the
results of operations if our predecessor had been operated as an unaffiliated entity. In addition, the results of operations for
acquisitions accounted for as business combinations have been included in the consolidated financial statements since their
respective acquisition dates.
100
2. Summary of Significant Accounting Policies
Use of Estimates - Conformity with GAAP requires management to make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and notes. Although these estimates are based on management’s best
available knowledge of current and expected future events, actual results could differ from those estimates.
Cash and Cash Equivalents - We consider investments in highly liquid financial instruments purchased with an original
stated maturity of 90 days or less and temporary investments of cash in short-term money market securities to be cash
equivalents.
Inventories - Inventories, which consist primarily of NGLs and natural gas, are recorded at the lower of weighted-average
cost or market value. Transportation costs are included in inventory.
Property, Plant and Equipment - Property, plant and equipment are recorded at historical cost. The cost of maintenance
and repairs, which are not significant improvements, are expensed when incurred. Depreciation is computed using the straight-
line method over the estimated useful lives of the assets.
Goodwill and Intangible Assets - Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired
business. We perform an annual impairment test of goodwill at the reporting unit level during the third quarter, and update the
test during interim periods when we believe events or changes in circumstances indicate that we may not be able to recover the
carrying value of a reporting unit. We primarily use a discounted cash flow analysis, supplemented by a market approach
analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal
year multiples, and estimated future cash flows including an estimate of operating and general and administrative costs. In
estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted
commodity prices.
Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts,
and related relationships. These intangible assets are amortized on a straight-line basis over the period of expected future
benefit. Intangible assets are removed from the gross carrying amount and the total of accumulated amortization in the period
in which they become fully amortized.
Long-Lived Assets - We periodically evaluate whether the carrying value of long-lived assets, including intangible assets,
has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is
based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the sum of the undiscounted
cash flows expected to result from the use and eventual disposition of the asset. We consider various factors when determining
if these assets should be evaluated for impairment, including but not limited to:
•
•
•
•
•
•
significant adverse change in legal factors or business climate;
a current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a
projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
an accumulation of costs significantly in excess of the amount originally expected for the acquisition or
construction of a long-lived asset;
significant adverse changes in the extent or manner in which an asset is used, or in its physical condition;
a significant adverse change in the market value of an asset; or
a current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its
estimated useful life.
If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its
fair value. We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one
method, including, but not limited to, recent third party comparable sales and discounted cash flow models. Significant changes
in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the
asset would generally require management to reassess the cash flows related to the long-lived assets.
Asset Retirement Obligations - Our asset retirement obligations relate primarily to the retirement of various gathering
pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use.
We adjust our asset retirement obligation each quarter for any liabilities incurred or settled during the period, accretion expense
and any revisions made to the estimated cash flows.
101
Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which
they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset.
This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free
interest rate, and accretes due to the passage of time based on the time value of money until the obligation is settled.
Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20%
owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments
in less than 20% owned affiliates where we have the ability to exercise significant influence.
We evaluate our investments in unconsolidated affiliates for impairment whenever events or changes in circumstances
indicate that the carrying value of such investments may have experienced a decline in value. When there is evidence of loss in
value, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether
impairment has occurred. We assess the fair value of our investments in unconsolidated affiliates using commonly accepted
techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and
discounted cash flow models. If the estimated fair value is considered to be permanently less than the carrying value, the excess
of the carrying value over the estimated fair value is recognized as an impairment loss.
Unamortized Debt Expense - Expenses incurred with the issuance of long-term debt are amortized over the term of the
debt using the effective interest method. These expenses are recorded on the consolidated balance sheet as other long-term
assets.
Noncontrolling Interest - Noncontrolling interest represents any third party or affiliate interest in non-wholly owned
entities that we consolidate. For financial reporting purposes, the assets and liabilities of these entities are consolidated with
those of our own, with any third party or affiliate interest in our consolidated balance sheet amounts shown as noncontrolling
interest in equity. Distributions to and contributions from noncontrolling interests represent cash payments to and cash
contributions from, respectively, such third party and affiliate investors.
Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives
are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset,
liability or firm commitment (fair value hedge), or normal purchases or normal sales. The remaining non-trading derivatives,
which are related to asset-based activities for which the normal purchase or normal sale exception is not elected, are recorded at
fair value in the consolidated balance sheets as unrealized gains or unrealized losses in derivative instruments, with changes in
the fair value recognized in the consolidated statements of operations. For each derivative, the accounting method and
presentation of gains and losses or revenue and expense in the consolidated statements of operations are as follows:
Classification of Contract
Accounting Method
Cash Flow Hedge
Hedge method (a)
Fair Value Hedge
Hedge method (a)
Normal Purchases or Normal Sales
Accrual method (b)
Presentation of Gains & Losses or Revenue & Expense
Gross basis in the same consolidated statements of
operations category as the related hedged item
Gross basis in the same consolidated statements of
operations category as the related hedged item
Gross basis upon settlement in the corresponding
consolidated statements of operations category based on
purchase or sale
Other Non-Trading Derivative Activity
______________
Mark-to-market
method (c)
Net basis in gains and losses from commodity derivative
activity
(a) Hedge method - An accounting method whereby the change in the fair value of the asset or liability is recorded in the
consolidated balance sheets as unrealized gains or unrealized losses on derivative instruments. For cash flow hedges,
there is no recognition in the consolidated statements of operations for the effective portion until the service is
provided or the associated delivery period impacts earnings. For fair value hedges, the change in the fair value of the
asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated
statements of operations in the same category as the related hedged item.
(b) Accrual method - An accounting method whereby there is no recognition in the consolidated balance sheets or
consolidated statements of operations for changes in fair value of a contract until the service is provided or the
associated delivery period impacts earnings.
(c) Mark-to-market method - An accounting method whereby the change in the fair value of the asset or liability is
recognized in the consolidated statements of operations in gains and losses from commodity derivative activity during
the current period.
102
Cash Flow and Fair Value Hedges - For derivatives designated as a cash flow hedge or a fair value hedge, we maintain
formal documentation of the hedge. In addition, we formally assess both at the inception of the hedging relationship and on an
ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items.
All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.
The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized
gains or unrealized losses on derivative instruments. The change in fair value of the effective portion of a derivative designated
as a cash flow hedge is recorded in partners’ equity in accumulated other comprehensive income, or AOCI, and the ineffective
portion is recorded in the consolidated statements of operations. During the period in which the hedged transaction impacts
earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations
in the same line item as the item being hedged. Hedge accounting is discontinued prospectively when it is determined that the
derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not occur. When
hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to
the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheets
at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses
related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction
impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were
previously deferred in AOCI will be immediately recognized in current period earnings.
The fair value of a derivative designated as a fair value hedge is recorded for balance sheet purposes as unrealized gains
or unrealized losses on derivative instruments. We recognize the gain or loss on the derivative instrument, as well as the
offsetting loss or gain on the hedged item in earnings in the current period. All derivatives designated and accounted for as fair
value hedges are classified in the same category as the item being hedged in the results of operations.
Valuation - When available, quoted market prices or prices obtained through external sources are used to determine a
contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair
value is determined based on pricing models developed primarily from historical relationships with quoted market prices and
the expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such
estimates may change in the near term.
Revenue Recognition - We generate the majority of our revenues from gathering, compressing, treating, processing,
transporting, storing and selling of natural gas, and producing, fractionating, transporting, storing and selling NGLs and
recovering and selling condensate. Once natural gas is produced from wells, producers then seek to deliver the natural gas and
its components to end-use markets. We realize revenues either by selling the residue natural gas, NGLs and condensate, or by
receiving fees. We also generate revenue from transporting, storing and selling propane.
We obtain access to commodities and provide our midstream services principally under contracts that contain a
combination of one or more of the following arrangements:
• Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the
following services: gathering, compressing, treating, processing, transporting or storing natural gas; and
fractionating, storing and transporting NGLs. Our fee-based arrangements include natural gas arrangements
pursuant to which we obtain natural gas at the wellhead or other receipt points, at an index related price at the
delivery point less a specified amount, generally the same as the transportation fees we would otherwise charge
for transportation of natural gas from the wellhead location to the delivery point. The revenues we earn are
directly related to the volume of natural gas or NGLs that flows through our systems and are not directly
dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a
decline in volumes, our revenues from these arrangements would be reduced.
• Percent-of-proceeds/liquids arrangements - Under percent-of-proceeds arrangements, we generally purchase
natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our
gathering system, treat and process the natural gas, and then sell the resulting residue natural gas, NGLs and
condensate based on index prices from published index market prices. We remit to the producers either an agreed-
upon percentage of the actual proceeds that we receive from our sales of the residue natural gas, NGLs and
condensate, or an agreed-upon percentage of the proceeds based on index related prices for the natural gas, NGLs
and condensate, regardless of the actual amount of the sales proceeds we receive. We keep the difference between
the proceeds received and the amount remitted back to the producer. Under percent-of-liquids arrangements, we
103
do not keep any amounts related to residue natural gas proceeds and only keep amounts related to the difference
between the proceeds received and the amount remitted back to the producer related to NGLs and condensate.
Certain of these arrangements may also result in the producer retaining title to all or a portion of the residue
natural gas and/or the NGLs, in lieu of us returning sales proceeds to the producer. Additionally, these
arrangements may include fee-based components. Our revenues under percent-of-proceeds arrangements relate
directly with the price of natural gas, NGLs and condensate. Our revenues under percent-of-liquids arrangements
relate directly with the price of NGLs and condensate.
• Propane sales arrangements - Under propane sales arrangements, we generally purchase propane from natural
gas processing plants and fractionation facilities, and crude oil refineries. We sell propane on a wholesale basis to
propane distributors, who in turn resell to their customers. Our sales of propane are not contingent upon the resale
of propane by propane distributors to their customers.
Our marketing of natural gas and NGLs consists of physical purchases and sales, as well as positions in derivative
instruments.
We recognize revenues for sales and services under the four revenue recognition criteria, as follows:
• Persuasive evidence of an arrangement exists - Our customary practice is to enter into a written contract.
• Delivery - Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based
arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the
inventory is subsequently sold and custody is transferred to the third party purchaser.
•
The fee is fixed or determinable - We negotiate the fee for our services at the outset of our fee-based arrangements. In
these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual
terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of
custody.
• Collectability is reasonably assured - Collectability is evaluated on a customer-by-customer basis. New and existing
customers are subject to a credit review process, which evaluates the customers’ financial position (for example, credit
metrics, liquidity and credit rating) and their ability to pay. If collectability is not considered probable at the outset of
an arrangement in accordance with our credit review process, revenue is not recognized until the cash is collected.
We generally report revenues gross in the consolidated statements of operations, as we typically act as the principal in
these transactions, take custody to the product, and incur the risks and rewards of ownership. We recognize revenues for non-
trading commodity derivative activity net in the consolidated statements of operations as gains and losses from commodity
derivative activity. These activities include mark-to-market gains and losses on energy trading contracts and the settlement of
financial and physical energy trading contracts.
Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers,
producers or pipelines are recorded monthly as accounts receivable or accounts payable using current market prices or the
weighted-average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas
or NGLs, or with cash.
Significant Customers - There were no third party customers that accounted for more than 10% of total operating
revenues for the years ended December 31, 2013, 2012 and 2011. We had significant transactions with affiliates.
Environmental Expenditures - Environmental expenditures are expensed or capitalized as appropriate, depending upon
the future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not generate
current or future revenue are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when
environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities
included in the consolidated balance sheets as other current liabilities amounted to $1 million, and other long-term liabilities
amounted to $1 million at both December 31, 2013 and 2012.
Equity-Based Compensation - Equity classified share-based compensation cost is measured at fair value, based on the
closing common unit price at grant date, and is recognized as expense over the vesting period. Liability classified share-based
compensation cost is remeasured at each reporting date at fair value, based on the closing common unit price, and is recognized
as expense over the requisite service period. Compensation expense for awards with graded vesting provisions is recognized on
a straight-line basis over the requisite service period of each separately vesting portion of the award. Awards granted to non-
employees for acquiring, or in conjunction with selling, goods and services are measured at the estimated fair value of the
goods or services, or the fair value of the award, whichever is more reliably measured.
104
Allowance for Doubtful Accounts - Management estimates the amount of required allowances for the potential non-
collectability of accounts receivable generally based upon the number of days past due, past collection experience and
consideration of other relevant factors. However, past experience may not be indicative of future collections and therefore
additional charges could be incurred in the future to reflect differences between estimated and actual collections.
Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax
purposes. Our income tax expense includes certain jurisdictions, including state, local, franchise and margin taxes of the master
limited partnership and subsidiaries. We follow the asset and liability method of accounting for income taxes. Under this method,
deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying
amounts and the tax basis of the assets and liabilities. Our taxable income or loss, which may vary substantially from the net
income or loss reported in the consolidated statements of operations, is proportionately included in the federal returns of each
partner.
Net Income or Loss per Limited Partner Unit - Basic and diluted net income or loss per limited partner unit, or LPU, is
calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs
during the period. Diluted net income or loss per limited partner unit is computed based on the weighted average number of
units plus the effect of dilutive potential units outstanding during the period using the two-class method.
Capitalized Interest - We capitalize interest during construction of major projects. Interest is calculated on the monthly
outstanding capital balance and ceases in the month that the asset is placed into service. We also capitalize interest on our equity
method investments which are devoting substantially all efforts to establishing a new business and have not yet begun planned
principal operations. Capitalization ceases when the investee commences planned principal operations. The rates used to calculate
capitalized interest are the weighted-average cost of debt, including the impact of interest rate swaps.
3. Acquisitions
On August 5, 2013, we entered into a purchase and sale agreement with DCP Midstream, LP, or Midstream LP, a 100%
owned subsidiary of DCP Midstream, LLC, pursuant to which the Partnership acquired from Midstream LP all of the
membership interests in DCP LaSalle Plant LLC, or the LaSalle Transaction, for consideration of $209 million, subject to
certain customary purchase price adjustments. The LaSalle Transaction was financed at closing using borrowings under our
revolving credit facility.
DCP LaSalle Plant LLC owns the O'Connor plant, a cryogenic natural gas processing plant in Weld County, Colorado
with initial capacity of 110 MMcf/d. Prior to the start of commercial operations in October 2013, the O'Connor plant was
known as the LaSalle plant. The LaSalle Transaction represents a transfer of assets between entities under common control. The
results of the O'Connor plant are included prospectively from the date of contribution in our Natural Gas Services segment. As
of February 2014, the O'Connor plant expansion to 160 MMcf/d is mechanically complete.
On August 5, 2013, we entered into a purchase and sale agreement with Midstream LP pursuant to which the Partnership
acquired from Midstream LP all of the membership interests in DCP Midstream Front Range LLC, or Front Range, for
consideration of $86 million, subject to certain customary purchase price adjustments, or the Front Range Transaction. The
Front Range Transaction was financed at closing using borrowings under our revolving credit facility.
Front Range owns a 33.33% equity interest in Front Range Pipeline LLC, a joint venture with affiliates of Enterprise
Products Partners L.P., or Enterprise, and Anadarko Petroleum Corporation. The joint venture was formed to construct a new
raw NGL mix pipeline that originates in the DJ Basin and extends approximately 435 miles to Skellytown, Texas, or the Front
Range pipeline. With connections to the Mid-America pipeline, and to the Texas Express pipeline, in which the Partnership
owns a 10% interest, the Front Range pipeline provides takeaway capacity and market access to the Gulf Coast for the
expanding production of NGLs in the DJ Basin. The Front Range pipeline connects to the O'Connor plant as well as third party
and DCP Midstream, LLC plants in the DJ Basin. The initial capacity of the Front Range pipeline is expected to be 150 MBbls/
d, which could be expanded to 230 MBbls/d with the installation of additional pump stations. Enterprise is the operator of the
pipeline, which was placed into service in February 2014. The Front Range pipeline currently has transportation agreements in
place with affiliates of DCP Midstream, LLC and others. The transportation agreements provide for ship-or-pay arrangements
for the first 10 years for a minimum volume specified in the agreement, with the last five years under plant dedication
arrangements. The Front Range transaction represents a transfer of assets between entities under common control. The results
of Front Range are included prospectively from the date of contribution in our NGL Logistics segment.
On March 28, 2013, we acquired an additional 46.67% interest in DCP SC Texas GP, or the Eagle Ford system, from DCP
Midstream, LLC and an $87 million fixed price commodity derivative hedge for a three-year period for aggregate consideration
of $626 million, plus customary working capital and other purchase price adjustments. $490 million of the consideration was
financed with the net proceeds from our 3.875% 10-year Senior Notes offering, $125 million was financed by the issuance at
105
closing of an aggregate 2,789,739 of our common units to DCP Midstream, LLC and the remaining $11 million was paid with
cash on hand. We also reimbursed DCP Midstream, LLC $50 million for 46.67% of the capital spent to date by the Eagle Ford
system for the construction of the Goliad plant, plus an incremental payment of $23 million as reimbursement for 46.67% of
preformation capital expenditures. The $203 million excess purchase price over the carrying value of the acquired interest in the
Eagle Ford system, as adjusted for customary working capital and other purchase price adjustments, was recorded as a decrease
in limited partners’ equity. Prior to the acquisition of the additional interest in the Eagle Ford system, we owned a 33.33%
interest which we accounted for as an unconsolidated affiliate using the equity method. The Eagle Ford system acquisition
represents a transaction between entities under common control and a change in reporting entity. Accordingly, our consolidated
financial statements have been adjusted to retrospectively include the historical results of our 80% interest in the Eagle Ford
system for all periods presented, similar to the pooling method.
The results of our 80% interest in the Eagle Ford system are included in the consolidated balance sheets as of
December 31, 2012. The following table presents the previously reported December 31, 2012 consolidated balance sheet,
adjusted for the acquisition of the additional 46.67% interest in the Eagle Ford system from DCP Midstream, LLC:
As of December 31, 2012
DCP
Midstream
Partners, LP
(As previously
reported on Form
10-K filed on
2/27/13) (a)
Remove Eagle
Ford system
Investment in
Unconsolidated
Affiliate (c)
Consolidated
DCP
Midstream
Partners, LP
(As currently
reported)
Consolidate
Eagle Ford
system (b)
(Millions)
$
$
$
Current assets:
ASSETS
Cash and cash equivalents
Accounts receivable
Inventories
Other
Total current assets
Property, plant and equipment, net
Goodwill and intangible assets, net
Investments in unconsolidated affiliates
Other non-current assets
Total assets
LIABILITIES AND EQUITY
Accounts payable and other current liabilities
Long-term debt
Other long-term liabilities
Total liabilities
Commitments and contingent liabilities
Equity:
Partners’ equity
Net equity
Accumulated other comprehensive loss
Total partners’ equity
Noncontrolling interests
Total equity
Total liabilities and equity
$
1
182
75
51
309
1,727
291
558
87
2,972
234
1,620
35
1,889
1,063
(15)
1,048
35
1,083
2,972
$
$
$
$
1
57
1
—
59
823
—
1
3
886
111
—
9
120
612
—
612
154
766
886
$
$
$
$
— $
—
—
—
—
—
—
(255)
—
(255) $
— $
—
—
—
(255)
—
(255)
—
(255)
(255) $
2
239
76
51
368
2,550
291
304
90
3,603
345
1,620
44
2,009
1,420
(15)
1,405
189
1,594
3,603
(a) Amounts as previously reported with 33.33% of the Eagle Ford system presented within investments in unconsolidated
affiliates.
106
(b) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.
(c) Adjustments to remove our 33.33% investment in unconsolidated affiliates.
The results of our 80% interest in the Eagle Ford system are included in the consolidated statements of operations for the
year ended December 31, 2013 and 2012. The following tables present the previously reported consolidated statements of
operations for the year ended December 31, 2012, adjusted for the acquisition of an 80% interest in the Eagle Ford system from
DCP Midstream, LLC:
Year Ended December 31, 2012
DCP
Midstream
Partners, LP
(As previously
reported on Form
10-K filed on
2/27/13) (a)
Consolidate
Eagle Ford
system (b)
Remove Eagle
Ford system
Equity Earnings
(c)
Consolidated
DCP
Midstream
Partners, LP
(As currently
reported)
$
1,466
185
70
1,721
1,301
123
64
46
1,534
187
(42)
29
174
(1)
173
(Millions)
$
993
47
—
1,040
876
70
25
28
999
41
—
—
41
—
41
— $
—
—
—
—
—
—
—
—
—
—
(3)
(3)
—
(3)
(5)
168
$
(8)
33
$
—
(3) $
2,459
232
70
2,761
2,177
193
89
74
2,533
228
(42)
26
212
(1)
211
(13)
198
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
$
Losses from commodity derivative activity, net
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and
NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Total operating costs and expenses
Operating income
Interest expense
Earnings from unconsolidated affiliates
Income before income taxes
Income tax expense
Net income
Net income attributable to
noncontrolling interests
Net income attributable to partners
$
(a) Amounts as previously reported with 33.33% of the Eagle Ford system presented within earnings from unconsolidated
affiliates.
(b) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.
(c) Adjustments to remove the Eagle Ford system equity earnings at 33.33% from the date of acquisition through December
31, 2012.
Year Ended December 31, 2011
The results of our 80% interest in the Eagle Ford system are included in the consolidated statements of operations for the
year ended December 31, 2011. The following tables present the previously reported consolidated statements of operations for
the year ended December 31, 2011 adjusted for the acquisition of our 80% interest in the Eagle Ford system from DCP
Midstream, LLC:
107
DCP
Midstream
Partners, LP
(As previously
reported on Form
10-K filed on
2/27/13)
Consolidate
Eagle Ford
system (a)
Condensed
Consolidated
DCP
Midstream
Partners, LP
(As currently
reported)
$
2,178
$
1,309
$
172
8
2,358
1,933
126
101
48
(1)
2,207
151
(34)
23
140
—
140
33
—
1,342
1,167
62
32
27
—
1,288
54
—
—
54
(1)
53
(19)
121
$
(11)
42
$
3,487
205
8
3,700
3,100
188
133
75
(1)
3,495
205
(34)
23
194
(1)
193
(30)
163
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
Gains from commodity derivative activity, net
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and
NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other income
Total operating costs and expenses
Operating income
Interest expense
Earnings from unconsolidated affiliates
Income before income taxes
Income tax expense
Net income
Net income attributable to
noncontrolling interests
Net income attributable to partners
$
(a) Adjustments to present the Eagle Ford system on a consolidated basis with a 20% noncontrolling interest.
On July 3, 2012, we acquired the Crossroads processing plant and associated gathering system from Penn Virginia Resource
Partners, L.P. for $63 million. The acquisition was financed at closing with borrowings under our revolving credit facility. The
Crossroads system, located in the southeastern portion of Harrison County in East Texas, includes approximately 8 miles of gas
gathering pipeline, an 80 MMcf/d cryogenic processing plant, approximately 20 miles of NGL pipeline and a 50% ownership
interest in an approximately 11-mile residue gas pipeline, or CrossPoint Pipeline, LLC, which we accounted for as an unconsolidated
affiliate using the equity method. The Crossroads system is a part of our East Texas system, which is included in our Natural Gas
Services segment.
We accounted for the Crossroads business combination based on estimates of the fair value of assets acquired and
liabilities assumed, including: property, plant and equipment; the equity investment in CrossPoint Pipeline, LLC; a liability for
a firm transportation agreement which expires in 2015; and a gas purchase agreement under which a portion of those firm
transportation payments are recoverable. Expected cash payments and receipts were recorded at their estimated fair value and
are included in other current liabilities, other long-term liabilities, and accounts receivable as of the acquisition date. The
following table summarizes the aggregate consideration and fair value of the identifiable assets acquired and liabilities assumed
in the acquisition of Crossroads as of the acquisition date:
108
July 3, 2012
(Millions)
Aggregate consideration
Accounts receivable
Property, plant and equipment
Investments in unconsolidated affiliates
Other current liabilities
Other long-term liabilities
Total
$
$
$
63
4
63
6
(4)
(6)
63
The results of operations for acquisitions accounted for as a business combination are included in our results subsequent
to the date of acquisition. Accordingly, total operating revenues of $22 million and net income of $1 million associated with
Crossroads from the acquisition date to December 31, 2012 are included in our consolidated statement of operations for the
year ended December 31, 2012.
Supplemental pro forma information is presented for comparative periods prior to the date of acquisition; however,
comparative periods in the consolidated financial statements are not adjusted to include the results of the acquisition. The
following tables present unaudited supplemental pro forma information for the consolidated statement of operations for the
years ended December 31, 2012 and 2011, as if the acquisition of Crossroads had occurred at the beginning of the earliest
period presented.
Year Ended December 31, 2012
Total operating revenues
Net income attributable to partners
Less:
Net income attributable to predecessor operations
General partner’s interest in net income
Net income allocable to limited partners
Net income per limited partner unit - basic and diluted
$
$
$
$
DCP
Midstream
Partners, LP
Acquisition of
Crossroads (a)
(Millions)
27
2
$
$
2,761
198
(32)
(41)
125
2.28
$
$
—
—
2
0.03
DCP Midstream
Partners, LP Pro
Forma
$
$
$
$
2,788
200
(32)
(41)
127
2.31
(a) The year ended December 31, 2012 includes the financial results of Crossroads for the period from January 1, 2012
through July 2, 2012.
Year Ended December 31, 2011
Total operating revenues
Net income attributable to partners
Less:
Net income attributable to predecessor operations
General partner’s interest in net income
Net income allocable to limited partners
Net income per limited partner unit - basic
Net income per limited partner unit - diluted
$
$
$
$
$
109
DCP
Midstream
Partners, LP
Acquisition of
Crossroads
(Millions)
114
4
$
$
3,700
163
(63)
(25)
75
1.73
1.72
$
$
$
—
—
4
0.09
0.09
DCP
Midstream
Partners, LP
Pro Forma
$
$
$
$
$
3,814
167
(63)
(25)
79
1.82
1.81
The supplemental pro forma total operating revenues for the year ended December 31, 2012 was adjusted to eliminate $5
million related to a contractual gas processing arrangement between us and Crossroads during the period.
The supplemental pro forma information is not intended to reflect actual results that would have occurred if the acquired
business had been combined during the periods presented, nor is it intended to be indicative of the results of operations that
may be achieved by us in the future.
4. Agreements and Transactions with Affiliates
DCP Midstream, LLC
Services Agreement and Other General and Administrative Charges
We have entered into a services agreement, as amended, or the Services Agreement, with DCP Midstream, LLC. Under
the Services Agreement, which replaced the Omnibus Agreement on February 14, 2013, we are required to reimburse DCP
Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures, maintenance and
repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP Midstream, LLC an
annual fee under the Services Agreement for centralized corporate functions performed by DCP Midstream, LLC on our behalf,
including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety
and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the
annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC under the Services Agreement for other
expenses and expenditures incurred or payments made on our behalf. Pursuant to the Services Agreement, we will reimburse
DCP Midstream, LLC for expenses and expenditures incurred or payments made on our behalf.
The Services Agreement fee is subject to adjustment based on the scope of general and administrative services performed
by DCP Midstream, LLC.
The following is a summary of the fees we incurred under the Services and Omnibus Agreements, as well as other fees
paid to DCP Midstream, LLC:
Services/Omnibus Agreement
Other fees — DCP Midstream, LLC
Total — DCP Midstream, LLC
2013
$
$
29
16
45
$
$
Year Ended
December 31,
2012
(Millions)
2011
26
31
57
$
$
10
46
56
In addition to the fees paid pursuant to the Services and Omnibus Agreements, we incurred allocated expenses, including
insurance and internal audit fees with DCP Midstream, LLC of $2 million for the year ended December 31, 2013 and $1 million
for each of the years ended December 31, 2012 and 2011, respectively. The Eagle Ford system incurred $14 million for the year
ended December 31, 2013 and $27 million for each of the years ended December 31, 2012 and 2011, respectively, in general
and administrative expenses directly from DCP Midstream, LLC. For the years ended December 31, 2012 and 2011, Southeast
Texas incurred $3 million and $10 million in general and administrative expenses directly from DCP Midstream, LLC, before
the addition of Southeast Texas to the Omnibus Agreement in March 2012. During the year ended December 31, 2011, East
Texas incurred $8 million in general and administrative expenses directly from DCP Midstream, LLC.
Competition
None of DCP Midstream, LLC, or any of its affiliates, including Phillips 66 and Spectra Energy, is restricted, under either
the partnership agreement or the Services Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates,
including Phillips 66 and Spectra Energy, may acquire, construct or dispose of additional midstream energy or other assets in
the future without any obligation to offer us the opportunity to purchase or construct those assets.
Other Agreements and Transactions with DCP Midstream, LLC
110
DCP Midstream, LLC was a significant customer during the years ended December 31, 2013, 2012 and 2011. We sell a
portion of our residue gas, NGLs and condensate to, purchase natural gas and other petroleum products from, and provide
gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase from and sell
commodities and services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC
conducts derivative activities on our behalf. We have and may continue to enter into derivative transactions directly with DCP
Midstream, LLC, whereby DCP Midstream, LLC is the counterparty.
We have a contractual arrangement with DCP Midstream, LLC, through March 2022, in which we pay DCP Midstream,
LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our
Natural Gas Services segment. In addition, we have an agreement with DCP Midstream, LLC providing for adjustments to
those fees based upon plant efficiencies related to our portion of volumes from the Southern Oklahoma system being processed
at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the
consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates. In addition, as part of this
arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with
these activities in the consolidated statements of operations as transportation, processing and other to affiliates.
DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system,
included in our Northern Louisiana system, which is part of our Natural Gas Services segment, that are periodically used for the
benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to take
natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP
Midstream, LLC upstream of Pelico and transport it to Pelico under an interruptible transportation agreement with an affiliate.
Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service
charges. Volumes that exceed our on-system demand are sold to DCP Midstream, LLC at an index-based price, less
contractually agreed upon marketing fees. Revenues associated with these activities are reported gross in our consolidated
statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.
In our Natural Gas Services segment, we sell NGLs processed at certain of our plants, and sell condensate removed from
the gas gathering systems that deliver to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal to
that subsidiary’s net weighted-average sales price, adjusted for transportation, processing and other charges from the tailgate of
the respective asset.
In conjunction with our acquisitions of our East Texas and Southeast Texas systems, which are part of our Natural Gas
Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for
certain expenditures on East Texas and Southeast Texas capital projects. These reimbursements are for specific capital projects
which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital
contributions to East Texas for capital projects of $1 million, $5 million and $18 million for the years ended December 31,
2013, 2012, and 2011 respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of
$5 million for the year ended December 31, 2012. We made a distribution to DCP Midstream, LLC related to capital projects at
Southeast Texas of $3 million for the year ended December 31, 2013.
In conjunction with our acquisition of the O'Connor plant, we entered into a 15-year fee-based processing agreement with
an affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of 75% of the
plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor plant. Under this
agreement, we received fees of $6 million during the year ended December 31, 2013, which are included in transportation,
processing and other to affiliates in the consolidated statements of operations.
As a result of a downstream outage, certain of our assets were required to curtail NGL production during 2012. DCP
Midstream, LLC has reimbursed us for the impact of the curtailment and accordingly, we recorded $3 million to sales of natural
gas, propane, NGLs and condensate to affiliates and less than $1 million to transportation, processing and other to affiliates in
the consolidated statements of operations for the year ended December 31, 2012.
During the year ended December 31, 2011, East Texas received $8 million in business interruption recoveries related to
the first quarter 2009 fire that was caused by a third party underground pipeline rupture outside of our property, or the East
Texas recovery settlement. We have allocated the recoveries based upon relative ownership percentages at the time the losses
were incurred, factoring in amounts previously reimbursed to us by DCP Midstream, LLC. For the year ended December 31,
2011, we recorded $7 million to sales of natural gas, propane, NGLs and condensate, with $5 million representing DCP
Midstream, LLC’s portion recorded in net income attributable to noncontrolling interests, in the consolidated statement of
operations.
111
In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that
provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-
based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under
the transportation agreements. We generally report revenues associated with these activities in the consolidated statements of
operations as transportation, processing and other to affiliates.
The Texas Express Pipeline has in place a long-term, fee-based, ship-or-pay transportation agreement with DCP
Midstream, LLC of 20 MBbls/d.
The Wattenberg pipeline has in place a 10-year dedication and transportation agreement with a subsidiary of DCP
Midstream, LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are
dedicated for transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff. We
generally report revenues associated with these activities in the consolidated statements of operations as transportation,
processing and other to affiliates.
We pay a fee to DCP Midstream, LLC to operate our DJ Basin NGL fractionators and receive fees for the processing of
DCP Midstream, LLC’s committed NGLs produced by them in Colorado at our DJ Basin NGL fractionators under agreements
that are effective through March 2018. We incurred fees of $1 million and less than $1 million during the years ended
December 31, 2013 and 2012, respectively, which are included in operating and maintenance expense in the consolidated
statements of operations.
Spectra Energy
We had propane supply agreements with Spectra Energy that expired in April 2012, which provided us propane supply at
our marine terminals, included in our Wholesale Propane Logistics segment, for up to approximately 185 million gallons of
propane annually.
Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates:
DCP Midstream, LLC:
Sales of natural gas, propane, NGLs and condensate
Transportation, processing and other
Purchases of natural gas, propane and NGLs
Gains from commodity derivative activity, net
Operating and maintenance expense
General and administrative expense
Phillips 66:
Sales of natural gas, propane, NGLs and condensate
ConocoPhillips (a):
Sales of natural gas, propane, NGLs and condensate
Transportation, processing and other
Purchases of natural gas, propane and NGLs
Spectra Energy:
Purchases of natural gas, propane and NGLs
Unconsolidated affiliates:
Purchases of natural gas, propane and NGLs
$
$
$
$
$
$
$
$
$
$
$
$
2013
Year Ended
December 31,
2012
(Millions)
2011
1,762
57
159
22
1
45
1
$
$
$
$
$
$
$
— $
— $
— $
63
$
— $
1,630
50
135
53
1
57
$
$
$
$
$
$
— $
9
3
67
166
2
$
$
$
$
$
2,259
27
189
1
1
56
—
57
9
139
321
6
(a) In connection with Phillips 66's separation from ConocoPhillips, ConocoPhillips is not considered to be a related party
for periods after April 30, 2012 and Phillips 66 is considered a related party for periods starting May 1, 2012.
112
We had balances with affiliates as follows:
DCP Midstream, LLC:
Accounts receivable
Accounts payable
Unrealized gains on derivative instruments — current
Unrealized gains on derivative instruments — long-term
Unrealized losses on derivative instruments — current
Unrealized losses on derivative instruments — long-term
Spectra Energy:
Accounts receivable
Accounts payable
Unconsolidated affiliates:
Accounts payable
5. Inventories
Inventories were as follows:
Natural gas
NGLs
Total inventories
$
$
$
$
$
$
$
$
$
$
$
December 31,
2013
December 31,
2012
(Millions)
211
37
79
81
18
1
1
6
$
$
$
$
$
$
$
$
— $
132
66
48
64
(11)
—
—
5
1
December 31,
2013
December 31,
2012
$
(Millions)
38
29
67
$
22
54
76
We recognize lower of cost or market adjustments when the carrying value of our inventories exceeds their estimated
market value. These non-cash charges are a component of purchases of natural gas, propane and NGLs in the consolidated
statements of operations. We recognized $4 million and $19 million in lower of cost or market adjustments during the years
ended December 31, 2013 and 2012, respectively.
6. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows:
Gathering and transmission systems
Processing, storage, and terminal facilities
Other
Construction work in progress
Property, plant and equipment
Accumulated depreciation
Property, plant and equipment, net
Depreciable
Life
December 31,
2013
December 31,
2012
20 — 50 Years
35 — 60 Years
3 — 30 Years
$
$
(Millions)
2,205
1,593
48
310
4,156
(1,151)
3,005
$
$
1,921
1,103
31
561
3,616
(1,066)
2,550
Interest capitalized on construction projects in 2013, 2012 and 2011 was $11 million, $7 million and $2 million,
respectively.
113
We revised the depreciable lives for our gathering and transmission systems, processing, storage and terminal facilities,
and other assets effective April 1, 2012. The key contributing factors to the change in depreciable lives is an increase in the
producers' estimated remaining economically recoverable reserves resulting from the widespread application of techniques,
such as hydraulic fracturing and horizontal drilling, that improve commodity production in the regions our assets serve.
Advances in extraction processes, along with better technology used to locate commodity reserves, is giving producers greater
access to unconventional commodities. Based on our property, plant and equipment as of April 1, 2012, the new remaining
depreciable lives resulted in an approximate $52 million reduction in depreciation expense for the year ended December 31,
2012. This change in our estimated depreciable lives increased net income per limited partner unit by $0.95 for the year ended
December 31, 2012.
Depreciation expense was $85 million, $81 million, and $125 million for the years ended December 31, 2013, 2012, and
2011, respectively.
During the year ended December 31, 2013, we discontinued certain construction projects and wrote off approximately $8
million in construction work in progress to other expense in the consolidated statements of operations.
Asset Retirement Obligations - As of December 31, 2013 and 2012, we had asset retirement obligations of $24 million
and $23 million, respectively, included in other long-term liabilities in the consolidated balance sheets. Accretion expense was
$1 million for each of the years ended December 31, 2013 and 2011 and accretion benefit was less than $1 million for the year
ended December 31, 2012.
We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for
future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and
processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement
obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will
operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing
asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to
take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement
obligation related to this asbestos cannot be estimated and no obligation has been recorded.
7. Goodwill and Intangible Assets
The carrying value of goodwill as of December 31, 2013 and December 31, 2012 was $154 million for each of the
periods, consisting of $82 million for our Natural Gas Services segment, $35 million for our NGL Logistics segment and $37
million for our Wholesale Propane Logistics segment.
We performed our annual goodwill assessment at the reporting unit level, which is identified by assessing whether the
components of our operating segments constitute businesses for which discrete financial information is available, whether
segment management regularly reviews the operating results of those components and whether the economic and regulatory
characteristics are similar. As a result of our assessment, we concluded that the fair value of goodwill substantially exceeded its
carrying value and that the entire amount of goodwill disclosed on the consolidated balance sheet is recoverable. We primarily
used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key
assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash
flows including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current
market information, as well as historical and other factors, into our forecasted commodity prices. If actual results are not
consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be
exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair
value.
Intangible assets consist of customer contracts, including commodity purchase, transportation and processing contracts,
and related relationships. The gross carrying amount and accumulated amortization of these intangible assets are included in the
accompanying consolidated balance sheets as intangible assets, net, and are as follows:
114
Gross carrying amount
Accumulated amortization
Intangible assets, net
$
$
December 31,
2013
2012
$
(Millions)
164
(35)
129
$
164
(27)
137
For each of the years ended December 31, 2013, 2012, and 2011, we recorded amortization expense of $8 million. As of
December 31, 2013, the remaining amortization periods ranged from approximately 8 years to 22 years, with a weighted-
average remaining period of approximately 17 years.
Estimated future amortization for these intangible assets is as follows:
Estimated Future Amortization
(Millions)
2014
2015
2016
2017
2018
Thereafter
Total
$
$
8
8
8
8
8
89
129
8. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
Percentage
Ownership
December 31,
2013
December 31,
2012
Carrying Value as of
Discovery Producer Services LLC
Front Range Pipeline LLC
Texas Express Pipeline
Mont Belvieu Enterprise Fractionator
Mont Belvieu 1 Fractionator
CrossPoint Pipeline, LLC
Other
Total investments in unconsolidated affiliates
40%
33.33%
10%
12.5%
20%
50%
Various
$
$
$
(Millions)
348
134
96
26
16
6
1
627
$
223
—
41
19
14
6
1
304
There was a deficit between the carrying amount of the investment and the underlying equity of Discovery of $28 million
and $30 million at December 31, 2013 and December 31, 2012, respectively, which is associated with, and is being amortized
over, the life of the underlying long-lived assets of Discovery.
There was an excess of the carrying amount of the investment over the underlying equity of Front Range of $4 million at
December 31, 2013, which is associated with interest capitalized during the construction of the pipeline and will be amortized
over the life of the underlying long-lived assets of Front Range pipeline.
There was an excess of the carrying amount of the investment over the underlying equity of Texas Express of $3 million
and less than $1 million at December 31, 2013 and December 31, 2012, respectively, which is associated with interest
capitalized during the construction of the pipeline and is being amortized over the life of the underlying long-lived assets of
Texas Express.
115
There was a deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu 1 of $5
million and $6 million at December 31, 2013 and December 31, 2012, respectively, which is associated with, and is being
amortized over the life of the underlying long-lived assets of Mont Belvieu 1.
Earnings from investments in unconsolidated affiliates were as follows:
Mont Belvieu 1 Fractionator
Mont Belvieu Enterprise Fractionator
Discovery Producer Services LLC
Texas Express
2013
$
Total earnings from unconsolidated affiliates
$
Year Ended December 31,
2012
(Millions)
2011
19
14
1
(1)
33
$
$
6
5
15
—
26
$
$
—
—
23
—
23
The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
Statements of operations:
Operating revenue
Operating expenses
Net income
Year Ended December 31,
2013
2012
(Millions)
2011
$
$
$
484
298
186
$
$
$
293
190
103
$
$
$
213
163
50
Balance sheets:
Current assets
Long-term assets
Current liabilities
Long-term liabilities
Net assets
9. Fair Value Measurement
Determination of Fair Value
December 31,
2013
December 31,
2012
(Millions)
182
2,678
(276)
(37)
2,547
$
$
129
1,288
(75)
(43)
1,299
$
$
Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are
measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources,
where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted
by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield
curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an
“exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values
are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in
an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect
counterparty credit quality, the effect of our own creditworthiness, the time value of money and/or the liquidity of the market.
• Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the
fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties
have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect
the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit
valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with
116
our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have
posted with us as well as any letters of credit that they have provided.
• Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net
liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as
collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The
methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into
account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement
date.
• Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial
instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange
traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no
liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the
midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such
practice results in the most reliable fair value measurement as viewed by a market participant.
We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated
on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are
benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with
how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing
these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all
valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract
volume, or the contract value, whichever is more applicable.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or
reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market
participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial
instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular
basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 11
Risk Management and Hedging Activities.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as
follows.
• Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
• Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are
observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial
instrument.
• Level 3 — inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of
judgment in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as
well as the general classification of such instruments pursuant to the hierarchy.
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include over the counter, or OTC, instruments,
such as natural gas, crude oil or NGL contracts.
Within our Natural Gas Services segment we typically use OTC derivative contracts in order to mitigate a portion of our
exposure to natural gas, NGL and condensate price changes. We also may enter into natural gas derivatives to lock in margin
around our storage and transportation assets. These instruments are generally classified as Level 2. Depending upon market
conditions and our strategy, we may enter into OTC derivative positions with a significant time horizon to maturity, and market
prices for these OTC derivatives may only be readily observable for a portion of the duration of the instrument. In order to
calculate the fair value of these instruments, readily observable market information is utilized to the extent that it is available;
117
however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon
observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the
valuation of the contract as a whole, we would classify the instrument within Level 3.
Within our Wholesale Propane Logistics segment, we may enter into a variety of financial instruments to either secure
sales or purchase prices, or capture a variety of market opportunities. Since financial instruments for NGLs tend to be
counterparty and location specific, we primarily use the OTC derivative instrument markets, which are not as active and liquid
as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six
months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time
horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts with a
longer time horizon, for which we internally generate a forward curve to value such instruments, are generally classified within
Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from
third party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of
expected supply sources coming on line, expected weather trends within certain regions of the United States, and the future
expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent
to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that
requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely
become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally
developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market
conditions and the availability of market observable data.
Interest Rate Derivative Assets and Liabilities
We use interest rate swap agreements as part of our overall capital strategy. These instruments effectively exchange a
portion of our existing floating rate debt for fixed-rate debt. Our swaps are generally priced based upon a London Interbank
Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR
instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing
similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is
also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of our interest
rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
Nonfinancial Assets and Liabilities
We utilize fair value to perform impairment tests as required on our property, plant and equipment; goodwill; and
intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the
date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow
models and would generally be classified within Level 3, in the event that we were required to measure and record such assets
at fair value within our consolidated financial statements. Additionally, we use fair value to determine the inception value of our
asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically
for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property
to the contractually stipulated condition, and would generally be classified within Level 3.
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The following table presents the financial instruments carried at fair value as of December 31, 2013 and December 31,
2012, by consolidated balance sheet caption and by valuation hierarchy, as described above:
December 31, 2013
December 31, 2012
Level 1
Level 2
Level 3
Total
Carrying
Value
Level 1
Level 2
Level 3
Total
Carrying
Value
Current assets (a):
Commodity derivatives
Short-term investments (b)
Long-term assets (c):
Commodity derivatives
Current liabilities (d):
Commodity derivatives
Interest rate derivatives
Long-term liabilities (e):
Commodity derivatives
Interest rate derivatives
$
$
$
$
$
$
$
— $
$
9
$
14
— $
$
65
— $
— $
12
$
75
$
— $
— $
— $
— $
(26) $
(2) $
(1) $
— $
— $
— $
— $
— $
(Millions)
79
9
87
$
$
$
(26) $
(2) $
(1) $
— $
— $
$
2
$
9
— $
$
40
— $
— $
5
$
65
$
— $
— $
— $
— $
(26) $
(4) $
(6) $
(2) $
(1) $
— $
— $
— $
49
2
70
(27)
(4)
(6)
(2)
(a) Included in current unrealized gains on derivative instruments in our consolidated balance sheets.
(b) Includes short-term money market securities included in cash and cash equivalents in our consolidated balance sheets.
(c) Included in long-term unrealized gains on derivative instruments in our consolidated balance sheets.
(d) Included in current unrealized losses on derivative instruments in our consolidated balance sheets.
(e) Included in long-term unrealized losses on derivative instruments in our consolidated balance sheets.
Changes in Levels 1 and 2 Fair Value Measurements
The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted
prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the
market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of
any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or
liability must have existed in the previous reporting period and moved into a different level during the current period. In the
event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer between Level 1 and
Level 2 would be reflected in a table as Transfers in/out of Level 1/Level 2. During the years ended December 31, 2013 and
2012, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.
Changes in Level 3 Fair Value Measurements
The tables below illustrate a rollforward of the amounts included in our consolidated balance sheets for derivative
financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a
combination of observable components (that is, components that are actively quoted and can be validated to external sources)
and unobservable components, the gains and losses in the table below may include changes in fair value due in part to
observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information
readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the
classification of any individual financial instrument may differ from one measurement date to the next. The significant
unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market
data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the
event that there is a movement to/from the classification of an instrument as Level 3, we have reflected such items in the table
below within the “Transfers into/out of Level 3” caption.
We manage our overall risk at the portfolio level, and in the execution of our strategy, we may use a combination of
financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not
included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management
activities.
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Commodity Derivative Instruments
Current
Assets
Long-
Term
Assets
Current
Liabilities
Long-
Term
Liabilities
(Millions)
Year ended December 31, 2013 (a):
Beginning balance
$
40
$
65
$
(1) $
Net realized and unrealized gains (losses)
included in earnings (c)
Transfers into Level 3 (b)
Transfers out of Level 3 (b)
Settlements
Purchases
Ending balance
Net unrealized gains (losses) still held included
in earnings (c)
Year ended December 31, 2012 (a):
Beginning balance
Net realized and unrealized gains included in
earnings (c)
Transfers into Level 3 (b)
Transfers out of Level 3 (b)
Settlements
Purchases
Ending balance
Net unrealized gains still held included in
earnings (c)
$
$
$
$
$
42
—
(1)
(40)
24
65
41
1
14
—
—
(2)
27
40
13
$
$
$
$
$
(50)
—
(2)
—
62
75
$
(50) $
1
2
—
—
—
62
65
2
$
$
$
—
—
1
—
—
— $
— $
(1) $
—
—
—
—
—
(1) $
— $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(a) There were no issuances or sales of derivatives for the years ended December 31, 2013 and 2012.
(b) Amounts transferred in and amounts transferred out are reflected at fair value as of the end of the period.
(c) Represents the amount of total gains or losses for the year, included in gains or losses from commodity derivative
activity, net, attributable to changes in unrealized gains or losses relating to assets and liabilities classified as Level 3.
Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs
We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs
used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are
presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair
value measurements, depending on our short or long position in contracts.
Product Group
Assets
NGLs
December 31, 2013
Fair Value
(Millions)
Forward
Curve Range
$
140
$0.27-$2.11 Per gallon
Estimated Fair Value of Financial Instruments
Valuation of a contract’s fair value is validated by an internal group independent of the marketing group. While common
industry practices are used to develop valuation techniques, changes in pricing methodologies or the underlying assumptions
could result in significantly different fair values and income recognition. When available, quoted market prices or prices
obtained through external sources are used to determine a contract’s fair value. For contracts with a delivery location or
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duration for which quoted market prices are not available, fair value is determined based on pricing models developed primarily
from historical and expected relationship with quoted market prices.
Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open
positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and
management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such
estimates may change in the near term.
The fair value of our interest rate swaps and commodity non-trading derivatives is based on prices supported by quoted
market prices and other external sources and prices based on models and other valuation methods. The “prices supported by
quoted market prices and other external sources” category includes our interest rate swaps, our NGL and crude oil swaps, and
our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our
forward price curves are obtained from a third party pricing service and then validated through an internal process which
includes the use of independent broker quotes. This category also includes our forward positions in NGLs at points for which
over-the-counter, or OTC, broker quotes for similar assets or liabilities are available for the full term of the instrument. This
category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and
then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category
includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and
are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an
internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity
of the specific market point.
We have determined fair value amounts using available market information and appropriate valuation methodologies.
However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the
estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The
use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.
The fair value of accounts receivable, accounts payable and short-term borrowings are not materially different from their
carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates.
Derivative instruments are carried at fair value.
The carrying value of outstanding balances under our Credit Agreement was $525 million as of December 31, 2012,
which approximated fair value.
The carrying and fair values of the 3.875% Senior Notes were $494 million and $461 million, respectively, as of
December 31, 2013.
The carrying and fair values of the 2.50% Senior Notes was $497 million and $500 million as of December 31, 2013. The
carrying value as of December 31, 2012 was $500 million, which approximated fair value.
The carrying and fair values of the 4.95% Senior Notes was $349 million and $354 million, respectively as of
December 31, 2013, and $350 million and $374 million, respectively, as of December 31, 2012.
The carrying and fair values of the 3.25% Senior Notes were $250 million and $258 million, respectively, as of
December 31, 2013, and $250 million and $259 million, respectively, as of December 31, 2012.
We determine the fair value of our Credit Agreement borrowings based upon the discounted present value of expected
future cash flows, taking into account the difference between the contractual borrowing spread and the spread for similar credit
facilities available in the marketplace. We determine the fair value of our fixed-rate Senior Notes based on quotes obtained from
bond dealers. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy.
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10. Debt
Commercial Paper
Short-term borrowings, weighted-average interest rate of 1.14%
Credit Agreement
Revolving credit facility, weighted-average variable interest rate of 1.47%, as of
December 31, 2012, due November 10, 2016 (a)
Debt Securities
Issued March 14, 2013, interest at 3.875% payable semi-annually, due March 15,
2023
Issued November 27, 2012, interest at 2.50% payable semi-annually, due
December 1, 2017
Issued March 13, 2012, interest at 4.95% payable semi-annually, due April 1, 2022
Issued September 30, 2010, interest at 3.25% payable semi-annually, due October 1,
2015
Unamortized discount
Total debt
Short-term borrowings
Total long-term debt
December 31,
2013
December 31,
2012
(Millions)
$
335
$
—
500
500
350
250
(10)
1,925
(335)
1,590
$
$
—
525
—
500
350
250
(5)
1,620
—
1,620
(a) $150 million was swapped to a fixed rate obligation with fixed rates ranging from 2.94% to 2.99%, for a net effective
rate of 2.25% on the $525 million of outstanding debt under our revolving credit facility as of December 31, 2012.
Commercial Paper Program
In October 2013, we entered into a commercial paper program, or the Commercial Paper Program, under which we may
issue unsecured commercial paper notes, or the Notes. The Commercial Paper Program serves as an alternative source of
funding and does not increase our current overall borrowing capacity. Amounts available under the Commercial Paper Program
may be borrowed, repaid, and re-borrowed from time to time with the maximum aggregate principal amount of Notes
outstanding, combined with the amount outstanding under our revolving credit facility, not to exceed $1 billion in the
aggregate. Amounts undrawn under our revolving credit facility are available to repay the Notes, if necessary. The maturities of
the Notes will vary, but may not exceed 397 days from the date of issue. The Notes will be sold under customary terms in the
commercial paper market and may be issued at a discount from par, or, alternatively, may be sold at par and bear varying
interest rates on a fixed or floating basis. The proceeds of the issuances of the Notes are expected to be used for capital
expenditures and other general partnership purposes. As of December 31, 2013, we had $335 million of commercial paper
outstanding which is included in short-term borrowings in our consolidated balance sheets.
Credit Agreement
We have a $1 billion revolving credit facility that matures November 10, 2016, or the Credit Agreement.
At December 31, 2013 and 2012, we had $1 million of letters of credit issued and outstanding under the Credit
Agreement. As of December 31, 2013, the unused capacity under the Credit Agreement was $664 million, net of amounts
outstanding under our Commercial Paper Program and letters of credit, which was available for general working capital
purposes.
Our borrowing capacity may be limited by the Credit Agreement’s financial covenant requirements. Except in the case of
a default, amounts borrowed under our Credit Agreement will not become due prior to the November 10, 2016 maturity date.
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We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of
prepayment of London Interbank Offered Rate, or LIBOR, borrowings. Under the Credit Agreement, indebtedness under the
revolving credit facility bears interest at either: (1) LIBOR, plus an applicable margin of 1.25% based on our current credit
rating; or (2) (a) the base rate which shall be the higher of Wells Fargo Bank N.A.’s prime rate, the Federal Funds rate plus
0.50% or the LIBOR Market Index rate plus 1%, plus (b) an applicable margin of 0.25% based on our current credit rating. The
revolving credit facility incurs an annual facility fee of 0.25% based on our current credit rating. This fee is paid on drawn and
undrawn portions of the revolving credit facility.
The Credit Agreement requires us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our
consolidated EBITDA, in each case as is defined by the Credit Agreement) of not more than 5.0 to 1.0, and following the
consummation of qualifying acquisitions, not more than 5.5 to 1.0, on a temporary basis for three consecutive quarters,
including the quarter in which such acquisition is consummated.
Debt Securities
On March 14, 2013, we issued $500 million of 3.875% 10-year Senior Notes due March 15, 2023. We received proceeds
of $490 million, net of underwriters’ fees, related expenses and unamortized discounts of $10 million, which we used to fund a
portion of the purchase price for the acquisition of an additional 46.67% interest in the Eagle Ford system. Interest on the notes
will be paid semi-annually on March 15 and September 15 of each year, commencing September 15, 2013. The notes will
mature on March 15, 2023, unless redeemed prior to maturity.
On November 27, 2012, we issued $500 million of our 2.50% 5-year Senior Notes due December 1, 2017. We received
net proceeds of $494 million, net of underwriters’ fees, related expenses and unamortized discounts of $6 million. Interest on
the notes will be paid semi-annually on June 1 and December 1 of each year, commencing June 1, 2013. The notes will mature
on December 1, 2017, unless redeemed prior to maturity.
On March 13, 2012, we issued $350 million of our 4.95% 10-year Senior Notes due April 1, 2022. We received net
proceeds of $346 million, net of underwriters’ fees, related expenses and unamortized discounts of $4 million, which we used to
fund the cash portion of the acquisition of the remaining 66.67% interest in Southeast Texas and to repay funds borrowed under
our Term Loan and Credit Agreement. Interest on the notes is paid semi-annually on April 1 and October 1 of each year. The
notes will mature on April 1, 2022, unless redeemed prior to maturity.
On September 30, 2010, we issued $250 million of our 3.25% Senior Notes due October 1, 2015. We received net
proceeds of $248 million, net of underwriters’ fees, related expense and unamortized discounts of $2 million, which we used to
repay funds borrowed under the revolver portion of our Credit Agreement. Interest on the notes is paid semi-annually on April 1
and October 1 of each year. The notes will mature on October 1, 2015, unless redeemed prior to maturity.
The notes are senior unsecured obligations, ranking equally in right of payment with other unsecured indebtedness,
including indebtedness under our Credit Agreement. We are not required to make mandatory redemption or sinking fund
payments with respect to any of these notes, and they are redeemable at a premium at our option. The underwriters’ fees and
related expenses are deferred in other long-term assets in our consolidated balance sheets and will be amortized over the term of
the notes.
The future maturities of long-term debt in the year indicated are as follows:
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2014
2015
2016
2017
2018
Thereafter
Unamortized discount
Total
Debt
Maturities
(Millions)
—
250
—
500
—
850
1,600
(10)
1,590
$
$
11. Risk Management and Hedging Activities
Our day-to-day operations expose us to a variety of risks including but not limited to changes in the prices of
commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage
certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management
policy, or Risk Management Policy, and a risk management committee, or the Risk Management Committee, to monitor and
manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed
of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in
the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and
commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.
Commodity Price Risk
Cash Flow Protection Activities — We are exposed to the impact of market fluctuations in the prices of natural gas,
NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage
services, we may receive cash or commodities as payment for these services, depending on the contract type. We enter into
derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices
associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. We have mitigated a
significant portion of our expected commodity price risk associated with our gathering, processing and sales activities through
2017 with commodity derivative instruments. Our commodity derivative instruments used for our hedging program are a
combination of direct NGL product, crude oil, and natural gas hedges. Due to the limited liquidity and tenor of the NGL
derivative market, we have used crude oil swaps and costless collars to mitigate a portion of our commodity price exposure to
NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when
NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The
relationship of NGLs to crude oil continues to be lower than historical relationships; however, a significant amount of our NGL
hedges from 2014 through 2017 are direct product hedges. When our crude oil swaps become short-term in nature, we have
periodically converted certain crude oil derivatives to NGL derivatives by entering into offsetting crude oil swaps while adding
NGL swaps. Our crude oil and NGL transactions are primarily accomplished through the use of forward contracts that
effectively exchange our floating price risk for a fixed price. We also utilize crude oil costless collars that minimize our floating
price risk by establishing a fixed price floor and a fixed price ceiling. However, the type of instrument that we use to mitigate a
portion of our risk may vary depending upon our risk management objective. These transactions are not designated as hedging
instruments for accounting purposes and the change in fair value is reflected within our consolidated statements of operations as
a gain or a loss on commodity derivative activity.
Our Wholesale Propane Logistics segment is generally designed to establish stable margins by entering into supply
arrangements that specify prices based on established floating price indices and by entering into sales agreements that provide
for floating prices that are tied to our variable supply costs plus a margin. To the extent possible, we match the pricing of our
supply portfolio to our sales portfolio in order to lock in value and reduce our overall commodity price risk. However, to the
extent that we carry propane inventories or our sales and supply arrangements are not aligned, we are exposed to market
variables and commodity price risk. We manage the commodity price risk of our supply portfolio and sales portfolio with both
physical and financial transactions, including fixed price sales. While the majority of our sales and purchases in this segment
are index-based, occasionally, we may enter into fixed price sales agreements in the event that a propane distributor desires to
purchase propane from us on a fixed price basis. In such cases, we may manage this risk with derivatives that allow us to swap
our fixed price risk to market index prices that are matched to our market index supply costs. In addition, we may use financial
124
derivatives to manage the value of our propane inventories. These transactions are not designated as hedging instruments for
accounting purposes and any change in fair value is reflected in the current period within our consolidated statements of
operations as a gain or loss on commodity derivative activity.
Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of
accounting, whereby changes in fair value are recorded directly to the consolidated statements of operations; however,
depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge
method of accounting.
Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline
assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our
natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our
natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis
spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal
short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection,
withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk
of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our
physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these
transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded
in the current period consolidated statements of operations. While gas held in our storage locations is recorded at the lower of
average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and
any changes in fair value are currently recorded in our consolidated statements of operations. Even though we may have
economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our
physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market
volatility.
Commodity Cash Flow Hedges — In order for storage facilities to remain operational, a minimum level of base gas must
be maintained in each storage cavern, which is capitalized on our consolidated balance sheets as a component of property, plant
and equipment, net. During 2011, Southeast Texas commenced an expansion project to build an additional storage cavern. To
mitigate risk associated with the forecasted purchase of natural gas, we executed a series of derivative financial instruments,
which were designated as cash flow hedges. During the second half of 2013, Southeast Texas purchased base gas to bring the
storage cavern to operation. The balance in accumulated other comprehensive income, or AOCI, of these cash flow hedges was
in a loss position of $3 million as of December 31, 2013. While the cash paid upon settlement of these hedges economically
fixed the cash required to purchase the base gas, the deferred loss will remain in AOCI until the cavern is emptied and the base
gas is sold.
Interest Rate Risk
At December 31, 2013, we had interest rate swap agreements extending through June 2014 with notional values totaling
$150 million, which are accounted for under the mark-to-market method of accounting and reprice prospectively approximately
every 30 days. Under the terms of the interest rate swap agreements, we pay fixed-rates ranging from 2.94% to 2.99%, and
receive interest payments based on the one-month LIBOR. Prior to August of 2013, these interest rate swaps were designated as
cash flow hedges whereby the effective portions of changes in fair value were recognized in AOCI in the consolidated balance
sheets. The deferred loss in AOCI of $3 million, at the time of de-designation, will be reclassified into earnings as the hedged
transactions impact earnings.
In March 2012, we settled $195 million of our forward-starting interest rate swap agreements for $7 million. The net
deferred losses in AOCI of $5 million, at the settlement date, will be amortized into interest expense associated with our long-
term debt offering through 2022.
Contingent Credit Features
Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain
of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in
certain circumstances.
125
We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements
that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard
credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.
•
•
If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA
counterparties may have the right to request early termination and net settlement of any outstanding derivative liability
positions.
In the event that we or DCP Midstream, LLC were to be downgraded below investment grade by at least one of the
major credit rating agencies, certain of our ISDA counterparties have the right to reduce our collateral threshold to
zero, potentially requiring us to fully collateralize any commodity contracts in a net liability position.
• Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk
related contingent feature. These provisions apply if we default in making timely payments under those agreements
and the amount of the default is above certain predefined thresholds, which are significantly high and are generally
consistent with the terms of our Credit Agreement. As of December 31, 2013, we are not a party to any agreements that
would be subject to these provisions other than our Credit Agreement.
Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related
contingent features.
Depending upon the movement of commodity prices and interest rates, each of our individual contracts with
counterparties to our commodity derivative instruments or to our interest rate swap instruments are in either a net asset or net
liability position. As of December 31, 2013, we had $8 million of individual commodity derivative contracts that contain credit-
risk related contingent features that were in a net liability position, and have not posted any cash collateral relative to such
positions. If a credit-risk related event were to occur and we were required to net settle our position with an individual
counterparty, our ISDA contracts permit us to net all outstanding contracts with that counterparty, whether in a net asset or net
liability position, as well as any cash collateral already posted. As of December 31, 2013, if a credit-risk related event were to
occur we may be required to post additional collateral. Additionally, although our commodity derivative contracts that contain
credit-risk related contingent features were in a net liability position as of December 31, 2013, if a credit-risk related event were
to occur, the net liability position would be partially offset by contracts in a net asset position reducing our net liability to $6
million.
As of December 31, 2013, we had $150 million of interest rate swap instruments that were in a net liability position of $2
million and were subject to credit-risk related contingent features. If we were to have a default of any of our covenants to our
Credit Agreement that occurs and is continuing, the counterparties to our swap instruments have the right to request that we net
settle the instrument in the form of cash.
Unconsolidated Affiliates
Discovery Producer Services LLC, one of our unconsolidated affiliates, entered into agreements with a pipe vendor
denominated in a foreign currency in connection with the expansion of the natural gas gathering pipeline system in the
deepwater Gulf of Mexico, the Keathley Canyon Connector. Discovery entered into certain foreign currency derivative
contracts to mitigate a portion of the foreign currency exchange risks which were designated as cash flow hedges. As these
hedges are owned by Discovery, an unconsolidated affiliate, we include the impact to AOCI on our consolidated balance sheet.
Offsetting
Certain of our derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to
settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative
instruments are presented on a gross basis on the consolidated balance sheets, regardless of our ability to net settle our
positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented
with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a
net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or
similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our
derivative instruments:
126
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments (a)
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments (a)
Net
Amount
Net
Amount
December 31, 2013
December 31, 2012
$
$
$
$
166
$
— $
(27) $
(2) $
(13) $
— $
13
$
— $
153
$
— $
(14) $
(2) $
119
$
— $
(33) $
(6) $
(10) $
— $
10
$
— $
109
—
(23)
(6)
Assets:
Commodity derivatives
Interest rate derivatives
Liabilities:
Commodity derivatives
Interest rate derivatives
(a) There is no cash collateral pledged or received against these positions.
127
Summarized Derivative Information
The fair value of our derivative instruments that are designated as hedging instruments and those that are marked-to-
market each period, as well as the location of each within our consolidated balance sheets, by major category, is summarized as
follows:
Balance Sheet Line Item
December 31,
2013
December 31,
2012
Balance Sheet Line Item
December 31,
2013
December 31,
2012
(Millions)
(Millions)
Derivative Assets Designated as Hedging Instruments:
Derivative Liabilities Designated as Hedging
Instruments:
Commodity derivatives:
Commodity derivatives:
Unrealized gains on
derivative instruments —
current
Unrealized gains on
derivative instruments —
long-term
Interest rate derivatives:
Unrealized gains on
derivative instruments —
current
Unrealized gains on
derivative instruments —
long-term
$
$
$
$
— $
—
— $
— $
—
— $
Unrealized losses on
derivative instruments —
current
Unrealized losses on
derivative instruments —
long-term
Interest rate derivatives:
Unrealized losses on
derivative instruments —
current
Unrealized losses on
derivative instruments —
long-term
—
—
—
—
—
—
$
$
$
$
— $
—
— $
— $
—
— $
(3)
—
(3)
(4)
(2)
(6)
Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging
Commodity derivatives:
Unrealized gains on
derivative instruments —
current
Unrealized gains on
derivative instruments —
long-term
Interest rate derivatives:
Unrealized gains on
derivative instruments —
current
Unrealized gains on
derivative instruments —
long-term
Instruments:
Commodity derivatives:
Unrealized losses on
derivative instruments —
current
Unrealized losses on
derivative instruments —
long-term
Interest rate derivatives:
Unrealized losses on
derivative instruments —
current
Unrealized losses on
derivative instruments —
long-term
$
$
$
$
$
$
$
$
79
$
49
87
166
$
— $
—
— $
70
119
—
—
—
(26) $
(24)
(1)
(27) $
(6)
(30)
(2) $
—
(2) $
—
—
—
128
The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign
currency cash flow hedges as of and for the year ended December 31, 2013:
Interest
Rate Cash
Flow
Hedges
Foreign
Currency
Cash Flow
Hedges (a)
Commodity
Cash Flow
Hedges
(Millions)
Total
Net deferred (losses) gains in AOCI (beginning
balance)
Losses reclassified from AOCI to earnings —
effective portion
Net deferred (losses) gains in AOCI (ending
balance)
Deferred losses in AOCI expected to be
reclassified into earnings over the next 12
months
$
$
$
(10)
4
(b)
(6)
(2)
$
$
$
(6) $
1
$
(15)
—
—
4
(6) $
1
$
(11)
— $
— $
(2)
(a) Relates to Discovery, our unconsolidated affiliate.
(b) Included in interest expense in our consolidated statements of operations.
For the year ended December 31, 2013, less than $1 million of derivative losses attributable to the ineffective portion was
recognized in gains or losses from commodity derivative activity, net and interest expense in our consolidated statements of
operations. For the year ended December 31, 2013, $1 million of derivative gains were reclassified from AOCI to earnings from
unconsolidated affiliates as a result of amounts excluded from effectiveness testing or as a result of the discontinuance of cash
flow hedges related to certain forecasted transactions that are not probable of occurring.
The following table summarizes the impact on our consolidated balance sheet and consolidated statements of operations
of our derivative instruments that are accounted for using the cash flow hedge method of accounting for the year ended
December 31, 2012:
(Losses) gains
Recognized in
AOCI on
Derivatives —
Effective Portion
Losses
Reclassified
From AOCI to
Earnings —
Effective
Portion
(Millions)
Interest rate derivatives
Commodity derivatives
Foreign currency derivatives (c)
$
$
$
(1) $
(1) $
$
1
(a) $
(10)
—
—
$
$
Losses Recognized
in Income on
Derivatives —
Ineffective Portion
and Amount
Excluded From
Effectiveness
Testing
(a) (b)
(2)
—
—
(a) Included in interest expense in our consolidated statements of operations.
(b) For the year ended December 31, 2012, less than $1 million of derivative losses were reclassified from AOCI to current
period earnings as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are
not probable of occurring.
(c) Relates to Discovery, our unconsolidated affiliate.
129
Changes in value of derivative instruments, for which the hedge method of accounting has not been elected from one
period to the next, are recorded in the consolidated statements of operations. The following summarizes these amounts and the
location within the consolidated statements of operations that such amounts are reflected:
Commodity Derivatives: Statements of Operations Line Item
Year Ended December 31,
2013
2012
(Millions)
2011
Third party:
Realized (losses) gains
Unrealized gains
(Losses) gains from commodity derivative
activity, net
Affiliates:
Realized gains
Unrealized (losses) gains
Gains from commodity derivative activity, net —
affiliates
Interest Rate Derivatives: Statements of Operations Line Item
Third party:
Realized losses
Unrealized gains
Interest expense
$
$
$
$
$
$
(19) $
14
(5) $
$
73
(51)
$
$
$
4
13
17
45
8
22
$
53
$
Year Ended December 31,
2013
2012
(Millions)
2011
(2) $
2
— $
(7) $
7
— $
(36)
43
7
2
(1)
1
(4)
5
1
We do not have any derivative financial instruments that qualify as a hedge of a net investment.
The following tables represent, by commodity type, our net long or short positions that are expected to partially or
entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar
years, the contract will appear in more than one line item in the tables below.
Year of Expiration
2014
2015
2016
Year of Expiration
2013
2014
2015
2016
December 31, 2013
Crude Oil
Natural Gas
Natural Gas
Liquids
Natural Gas
Basis Swaps
Net (Short)
Position
(Bbls)
(690,945)
(745,695)
(561,922)
Net
(Short)
Position
(MMBtu)
(21,673,620)
(9,458,975)
(1,838,564)
Net
(Short)
Position
(Bbls)
(5,171,910)
(5,691,570)
(813,267)
December 31, 2012
Crude Oil
Natural Gas
Net (Short)
Position
(Bbls)
(943,379)
(584,365)
(401,865)
(183,000)
Net (Short)
Position
(MMBtu)
(8,887,980)
(4,712,880)
(5,127,155)
—
Natural Gas
Liquids
Net (Short)
Position
(Bbls)
(2,593,955)
(2,584,930)
(2,491,250)
—
Net Long
Position
(MMbtu)
21,415,000
1,875,000
—
Natural Gas
Basis Swaps
Net Long
(Short)
Position
(Mmbtu)
9,690,000
(1,350,000)
—
—
130
We periodically enter into interest rate swap agreements to mitigate a portion of our floating rate interest exposure. As of
December 31, 2013, we have swaps with a notional value of $70 million and $80 million, which, in aggregate, exchange $150
million of our floating rate obligation to a fixed rate obligation through June 2014.
12. Partnership Equity and Distributions
General — During the year ended December 31, 2013, we issued 1,408,547 of our common units pursuant to an equity
distribution agreement entered into in August 2011, or the 2011 equity distribution agreement. We received proceeds of $67
million, net of commissions and offering costs of $2 million, which were used to finance growth opportunities and for general
partnership purposes. The 2011 equity distribution agreement provided for the offer and sale of common units having an
aggregate offering amount of up to $150 million. As of December 31, 2013, no common units remain available for sale
pursuant to this equity distribution agreement and we have deregistered the corresponding registration statement.
In August 2013, we issued 9,000,000 common units at $50.04 per unit. We received proceeds of $434 million, net of
offering costs.
In June 2013, we filed a shelf registration statement on Form S-3 with the SEC with a maximum offering price of $300
million, which became effective on June 27, 2013. The shelf registration statement allows us to issue additional common units.
In November 2013, we entered into an equity distribution agreement, or the 2013 equity distribution agreement, with a group of
financial institutions as sales agents. The agreement provides for the offer and sale from time to time, through our sales agents,
of common units having an aggregate offering amount of up to $300 million. During the year ended December 31, 2013, we
issued 1,839,430 of our common units pursuant to the 2013 equity distribution agreement and received proceeds of $87 million,
net of accrued commissions and offering costs of $1 million, which were used to finance growth opportunities and for general
partnership purposes. As of December 31, 2013, approximately $212 million of the aggregate offering amount remains
available for sale pursuant to the 2013 equity distribution agreement.
In March 2013, we issued 2,789,739 common units to DCP Midstream, LLC as partial consideration for 46.67% interest
in the Eagle Ford system.
In March 2013, we issued 12,650,000 common units at $40.63 per unit. We received proceeds of $494 million, net of
offering costs.
In November 2012, we issued 1,912,663 common units to DCP Midstream, LLC as partial consideration for our 33.33%
interest in the Eagle Ford system.
In July 2012, we issued 1,536,098 common units to DCP Midstream, LLC as partial consideration for the Mont Belvieu
fractionators.
In July 2012, we closed a private placement of equity with a group of institutional investors in which we sold 4,989,802
common units at a price of $35.55 per unit, and received proceeds of $174 million net of offering costs.
In June 2012, we filed a universal shelf registration statement on Form S-3 with the SEC with an unlimited offering
amount, to replace an existing shelf registration statement. The universal shelf registration statement allows us to issue
additional common units and debt securities. Our 9,000,000 and 12,650,000 common units issued in August 2013 and March
2013, respectively, and 2.50% 5-year Senior Notes were issued under this registration statement.
In March 2012, we issued 5,148,500 common units at $47.42 per unit. We received proceeds of $234 million, net of
offering costs.
In March 2012, we issued 1,000,417 common units to DCP Midstream, LLC as partial consideration for the remaining
66.67% interest in Southeast Texas.
In February 2012, we issued 30,701 common units under our 2005 Long-Term Incentive Plan, or 2005 LTIP, to employees
as compensation for their service.
In January 2012, we issued 727,520 common units to DCP Midstream, LLC as partial consideration for the remaining
49.9% interest in East Texas.
131
In March 2011, we issued 3,596,636 common units at $40.55 per unit. We received proceeds of $140 million, net of offering
costs.
In February 2011, we issued 8,399 common units, from our LTIP to employees as compensation for their service during
2010, 2009 and 2008.
Definition of Available Cash — Our partnership agreement requires that, within 45 days after the end of each quarter, we
distribute all of our Available Cash, as defined in the partnership agreement, to unitholders of record on the applicable record
date, as determined by our general partner. Available Cash, for any quarter, consists of all cash and cash equivalents on hand at
the end of that quarter:
•
less the amount of cash reserves established by the general partner to:
•
•
•
provide for the proper conduct of our business;
comply with applicable law, any of our debt instruments or other agreements; and
provide funds for distributions to the unitholders and to our general partner for any one or more of the next
four quarters;
•
plus, if our general partner so determines, all or a portion of cash and cash equivalents on hand on the date of
determination of Available Cash for the quarter.
General Partner Interest and Incentive Distribution Rights - The general partner is entitled to a percentage of all
quarterly distributions equal to its general partner interest of approximately 1% and limited partner interest of 1% as of
December 31, 2013. The general partner has the right, but not the obligation, to contribute a proportionate amount of capital to
us to maintain its current general partner interest.
The incentive distribution rights held by the general partner entitle it to receive an increasing share of Available Cash when
pre-defined distribution targets are achieved. Currently, our distribution to our general partner related to its incentive
distribution rights is at the highest level. The general partner’s incentive distribution rights were not reduced as a result of our
common unit issuances, and will not be reduced if we issue additional units in the future and the general partner does not
contribute a proportionate amount of capital to us to maintain its current general partner interest. Please read the Distributions
of Available Cash sections below for more details about the distribution targets and their impact on the general partner’s
incentive distribution rights.
Distributions of Available Cash - Our partnership agreement, after adjustment for the general partner’s relative ownership
level, requires that we make distributions of Available Cash from operating surplus for any quarter in the following manner:
•
•
•
•
first, to all unitholders and the general partner, in accordance with their pro rata interest, until each unitholder receives
a total of $0.4025 per unit for that quarter;
second, 13% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro
rata until each unitholder receives a total of $0.4375 per unit for that quarter;
third, 23% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders pro
rata until each unitholder receives a total of $0.525 per unit for that quarter; and
thereafter, 48% to the general partner, plus the general partner’s pro rata interest, and the remainder to all unitholders.
The following table presents our cash distributions paid in 2013, 2012 and 2011:
132
Payment Date
November 14, 2013
August 14, 2013
May 15, 2013
February 14, 2013
November 14, 2012
August 14, 2012
May 15, 2012
February 14, 2012
November 14, 2011
August 12, 2011
May 13, 2011
February 14, 2011
13. Equity-Based Compensation
Total compensation cost for equity-based arrangements was as follows:
Per Unit
Distribution
Total Cash
Distribution
(Millions)
$
$
$
$
$
$
$
$
$
$
$
$
0.7200
0.7100
0.7000
0.6900
0.6800
0.6700
0.6600
0.6500
0.6400
0.6325
0.6250
0.6175
$
$
$
$
$
$
$
$
$
$
$
$
82
72
69
54
53
49
43
37
35
34
33
30
Year Ended December 31,
2012
2013
2011
Performance Phantom Units
Phantom Units
Restricted Phantom Units
Total compensation cost
(Millions)
1
$
—
1
2
$
$
$
1
—
1
2
5
—
2
7
$
$
On November 28, 2005, the board of directors of our General Partner adopted a Long-Term Incentive Plan, or the 2005
LTIP, for employees, consultants and directors of our General Partner and its affiliates who perform services for us. The 2005
LTIP provides for the grant of limited partner units, or LPUs, phantom units, unit options and substitute awards, and, with
respect to unit options and phantom units, the grant of dividend equivalent rights, or DERs. Subject to adjustment for certain
events, an aggregate of 850,000 LPUs may be issued and delivered pursuant to awards under the 2005 LTIP. Awards that are
canceled or forfeited, or are withheld to satisfy the General Partner’s tax withholding obligations, are available for delivery
pursuant to other awards.
On February 15, 2012, the board of directors of our General Partner adopted a 2012 LTIP for employees, consultants and
directors of our General Partner and its affiliates who perform services for us. The 2012 LTIP provides for the grant of phantom
units and the grant of DERs. The phantom units consist of a notional unit based on the value of common units or shares of the
Partnership, Phillips 66 and Spectra Energy.
The LTIPs were administered by the compensation committee of the General Partner’s board of directors through 2012,
and by the General Partner’s board of directors beginning in 2013. All awards are subject to cliff vesting.
Prior to February 18, 2011, substantially all equity-based awards were accounted for as liability awards. Effective
February 18, 2011, the Modification Date, we have the intent and ability to settle certain awards within our control in units and
therefore modified the accounting for these awards. We classified them as equity awards based on their re-measured fair value.
The fair value was determined based on the closing price of our common units on the Modification Date. Such modification
resulted in a reclassification of $2 million from share-based compensation liability to additional paid-in capital on the
Modification Date. Compensation expense on unvested equity awards as of the Modification Date is recognized ratably over
each remaining vesting period.
We account for other awards, which are subject to settlement in cash, as liability awards. Compensation expense on these
awards is recognized ratably over each vesting period, and will be re-measured each reporting period for all awards outstanding
133
until the units are vested. The fair value of all liability awards is determined based on the closing price of our common units at
each measurement date.
The reclassification of the affected awards did not impact our accounting for dividend equivalent rights as these
instruments will continue to be settled in cash and therefore retain their share-based compensation liability classification.
Performance Phantom Units - We have awarded Performance Phantom Units, or PPUs, pursuant to the LTIP to certain
employees. PPUs generally vest in their entirety at the end of a three year performance period. The number of PPUs that will
ultimately vest range, in value up to 200% of the outstanding PPUs, depending on the achievement of specified performance
targets over three year performance periods. The final performance payout is determined by the board of directors of our
General Partner. The DERs are paid in cash at the end of the performance period. Of the remaining PPUs outstanding at
December 31, 2013, 2,070 units are expected to vest on December 31, 2014 and 10,890 units are expected to vest on December
31, 2015.
At December 31, 2013, there was less than $1 million of unrecognized compensation expense related to the PPUs that is
expected to be recognized over a weighted-average period of approximately 2 years. The following table presents information
related to the PPUs:
Grant Date
Weighted-
Average Price
per Unit
Measurement
Date Price
per Unit
Units
Outstanding at January 1, 2011
Granted
Vested
Forfeited
Outstanding at December 31, 2011
Granted (a)
Vested
Forfeited
Outstanding at December 31, 2012
Granted
Vested (b)
Forfeited
Outstanding at December 31, 2013
Expected to vest (c)
67,350
$
$
10,580
(50,720) $
— $
$
27,210
11,740
$
(20,100) $
(7,760) $
$
11,090
11,450
$
(3,800) $
(4,990) $
$
13,750
$
12,960
15.42
41.80
10.05
—
35.69
39.31
34.57
38.97
39.24
40.88
40.75
38.77
40.36
40.38
$
$
50.33
50.33
(a) Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation
from ConocoPhillips, granted under the 2012 LTIP.
(b) The units vested at 150%.
(c) Based on our December 31, 2013 estimated achievement of specified performance targets, the performance
estimate for units granted in both 2013 and 2012 is 100%. The estimated forfeiture rate for units granted in
both 2013 and 2012 is 10%.
The estimate of PPUs that are expected to vest is based on highly subjective assumptions that could potentially change
over time, including the expected forfeiture rate and achievement of performance targets. Therefore, the amount of
unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our
consolidated statements of operations.
The following table presents the fair value of units vested and the unit-based liabilities paid related to PPUs, including the
related DERs:
134
Fair value of units vested
Unit-based liabilities paid
less than $1
1
$
$
$
1
5
$
$
5
—
Year Ended December 31,
2012
2011
2013
(Millions)
Phantom Units - As part of their director fees, we granted 4,400 Phantom Units to directors during the year ended
December 31, 2013 and 4,000 Phantom Units to directors during each of the years ended December 31, 2012, and 2011,
respectively. All of these units vested in their respective grant years, and were settled in units. The DERs are paid in cash
quarterly in arrears. The following table presents information related to the Phantom Units:
Outstanding at January 1, 2011
Granted
Vested
Outstanding at December 31, 2011
Granted
Vested
Outstanding at December 31, 2012
Granted
Vested
Outstanding at December 31, 2013
Grant Date
Weighted-
Average Price
per Unit
Measurement
Date Price
per Unit
Units
— $
$
4,000
(4,000) $
— $
4,000
$
(4,000) $
— $
4,400
$
(4,400) $
— $
—
41.80
41.80
—
48.03
48.03
—
46.39
46.39
— $
—
The fair value of units vested related to Phantom Units was less than $1 million for each of the years ended December 31,
2013, 2012 and 2011.
Restricted Phantom Units - Our General Partner’s board of directors awarded restricted phantom LPUs, or RPUs, to key
employees under the LTIP. Of the remaining RPUs outstanding at December 31, 2013, 2,070 units are expected to vest on
December 31, 2014 and 11,281 units are expected to vest on December 31, 2015. The DERs are paid in cash quarterly in
arrears. At December 31, 2013, there was less than $1 million of unrecognized compensation expense related to the RPUs that
is expected to be recognized over a weighted-average period of approximately 2 years. The following table presents
information related to the RPUs:
135
Outstanding at January 1, 2011
Granted
Vested
Forfeited
Outstanding at December 31, 2011
Granted (a)
Vested
Forfeited
Outstanding at December 31, 2012
Granted
Vested
Forfeited
Outstanding at December 31, 2013
Expected to vest
Grant Date
Weighted-
Average Price
per Unit
Measurement
Date Price
per Unit
Units
$
67,350
10,580
$
(58,600) $
— $
$
19,330
11,740
$
(19,060) $
(7,760) $
$
4,250
$
11,590
(1,950) $
— $
$
$
13,890
13,351
15.42
41.80
12.97
—
37.27
39.31
37.31
43.27
39.63
41.94
41.80
—
41.25
41.38
$
$
50.33
50.30
(a) Includes the impact of conversion of the underlying securities, in connection with Phillip 66's separation
from ConocoPhillips, granted under the 2012 LTIP.
The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related
to Restricted Phantom Units:
Year Ended December 31,
2012
2011
2013
(Millions)
Fair value of units vested
Unit-based liabilities paid
less than $1
1
$
$
$
1
2
$
$
3
1
The estimate of RPUs that are expected to vest is based on highly subjective assumptions that could potentially change
over time, including the expected forfeiture rate, which was estimated at 10% for units granted in both 2013 and 2012.
Therefore, the amount of unrecognized compensation expense noted above does not necessarily represent the value that will
ultimately be realized in our consolidated statements of operations.
14. Net Income or Loss per Limited Partner Unit
Our net income or loss is allocated to the general partner and the limited partners in accordance with their respective
ownership percentages, after allocating Available Cash generated during the period in accordance with our partnership
agreement.
Securities that meet the definition of a participating security are required to be considered for inclusion in the computation
of basic earnings per unit using the two-class method. Under the two-class method, earnings per unit is calculated as if all of the
earnings for the period were distributed under the terms of the partnership agreement, regardless of whether the general partner
has discretion over the amount of distributions to be made in any particular period, whether those earnings would actually be
distributed during a particular period from an economic or practical perspective, or whether the general partner has other legal
or contractual limitations on its ability to pay distributions that would prevent it from distributing all of the earnings for a
particular period.
These required disclosures do not impact our overall net income or loss or other financial results; however, in periods in
which aggregate net income exceeds our Available Cash it will have the impact of reducing net income per LPU.
Basic and diluted net income or loss per LPU is calculated by dividing net income or loss allocable to limited partners, by
the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on
the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class
136
method. Dilutive potential units include outstanding Performance Units, Phantom Units and Restricted Units. The dilutive
effect of unit-based awards was 19,179, 33,043 and 64,286 equivalent units during the years ended December 31, 2013, 2012
and 2011, respectively.
15. Income Taxes
We are structured as a master limited partnership with sufficient qualifying income, which is a pass-through entity for
federal income tax purposes. Accordingly, we had no federal income tax expense for the years ended December 31, 2013 and
2012.
In December 2010, we acquired all of the interests in Marysville Hydrocarbons Holdings, LLC, an entity that owned a
taxable C-Corporation consolidated return group. We estimated $35 million of deferred tax liabilities resulting from built-in tax
gains recognized in the transaction and recorded this as part of our preliminary acquisition accounting as of December 31,
2010. In January 2011, we merged two 100% owned subsidiaries of Marysville Hydrocarbons Holding, LLC and converted the
combined entity’s organizational structure from a corporation to a limited liability company. This conversion to a limited
liability company triggered the deferred tax liabilities resulting from built-in tax gains to become currently payable.
Accordingly, the estimated $35 million of deferred tax liabilities at December 31, 2010 became currently payable on January 4,
2011. During 2011, we made federal and state tax payments of $29 million and less than $1 million, respectively, related to our
estimated $35 million tax liability that resulted from our acquisition of Marysville. In 2011, the remaining $5 million estimated
tax payable was reclassified to goodwill in our final acquisition accounting for the Marysville business combination.
The State of Texas imposes a margin tax that is assessed at 0.975% of taxable margin apportioned to Texas for the year
ended December 31, 2013 and 1% for the years ended December 31, 2012 and 2011. For the year ended December 31, 2011,
the state of Michigan imposed a business tax of 0.8% on gross receipts and 4.95% of Michigan taxable income. The sum of the
gross receipts and income tax was subject to a tax surcharge of 21.99%. The Michigan business tax was repealed beginning
with the year ended December 31, 2012.
Income tax expense consists of the following:
Current:
Federal income tax expense
State income tax expense
Deferred:
Federal income tax benefit
State income tax (expense) benefit
Total income tax expense
Year Ended December 31,
2012
2011
2013
(Millions)
$
$
— $
(3)
—
(5)
(8) $
— $
(1)
—
—
(1) $
(29)
(2)
29
1
(1)
We had net long-term deferred tax liabilities of $11 million and $6 million as of December 31, 2013 and 2012, included in
other long-term liabilities on the consolidated balance sheets. These state deferred tax liabilities relate to our Texas operations,
and are primarily associated with depreciation related to property, plant and equipment.
Our effective tax rate differs from statutory rates, primarily due to being structured as a master limited partnership, which
is a pass-through entity for federal income tax purposes, while being treated as a taxable entity in certain states.
137
16. Commitments and Contingent Liabilities
Litigation
Prospect — In 2011, we received an arbitration claim, or the Claim, filed with the American Arbitration Association by
Prospect Street Energy, LLC and Prospect Street Ventures I, LLC, or together, the Claimants, against EE Group, LLC, or EE
Group, and a number of other parties that previously owned, directly or indirectly, our Marysville NGL storage facility, or
collectively, the Respondents. EE Group is our indirect subsidiary which we acquired in connection with our acquisition
of Marysville Hydrocarbons Holdings, LLC, or Marysville, on December 30, 2010. The Claim involves actions taken and time
periods prior to our ownership of EE Group and Marysville, and includes several causes of action including claims of civil
conspiracy, breach of fiduciary duty and fraud. As of February 2014, we have entered into separate settlement agreements with
the Claimants and the other Respondents involved in the arbitration. We believe these settlement agreements substantially
mitigate our liability in this matter and therefore, we consider this matter closed.
Other — We are not a party to any other significant legal proceedings, but are a party to various administrative and
regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently
believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued,
insurance coverage or other indemnification arrangements, will not have a material adverse effect on our consolidated results of
operations, financial position, or cash flow.
Insurance - We renewed our insurance policies in May, June and July 2013 for the 2013-2014 insurance year. We contract
with third party and affiliate insurers for: (1) automobile liability insurance for all owned, non-owned and hired vehicles; (2)
general liability insurance; (3) excess liability insurance above the established primary limits for general liability and
automobile liability insurance; and (4) property insurance, which covers replacement value of real and personal property and
includes business interruption/extra expense. These renewals have not resulted in any material change to the premiums we are
contracted to pay or our limits in the 2013-2014 insurance year compared with the 2012-2013 insurance year. We are jointly
insured with DCP Midstream, LLC for a portion of the directors and officers insurance covering our directors and officers for
acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of
which are common for companies that are of similar size to us and with similar types of operations.
The insurance on Discovery, as placed by Williams Field Service Group LLC, for the 2013-2014 insurance year includes
general and excess liability, onshore property damage, including named windstorm and business interruption, and offshore non-
wind property and business interruption insurance. The availability of offshore named windstorm property and business
interruption insurance has been significantly reduced over the past few years as a result of higher industry-wide damage claims.
Additionally, the named windstorm property and business interruption insurance that is available comes at uneconomic
premium levels, higher deductibles and lower coverage limits. As such, Discovery continues to elect not to purchase offshore
named windstorm property and business interruption insurance coverage for the 2013-2014 insurance year.
Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating,
or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health,
safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and
regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and
disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and
other facilities incorporates compliance with environmental laws and regulations and safety standards. Failure to comply with
these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures,
including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information,
compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations,
financial position or cash flows.
Indemnification - DCP Midstream, LLC has indemnified us for certain potential environmental claims, losses and
expenses associated with the operation of the assets of certain of our predecessors.
138
Other Commitments and Contingencies - We utilize assets under operating leases in several areas of operation.
Consolidated rental expense, including leases with no continuing commitment, totaled $17 million, $14 million, and $15
million for the years ended December 31, 2013, 2012, and 2011, respectively. Rental expense for leases with escalation clauses
is recognized on a straight line basis over the initial lease term.
Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2013:
2014
2015
2016
2017
2018
Thereafter
Total minimum rental payments
(Millions)
16
$
14
12
10
9
33
94
$
17. Business Segments
Our operations are located in the United States and are organized into three reporting segments: Natural Gas Services;
NGL Logistics; and Wholesale Propane Logistics.
Natural Gas Services — Our Natural Gas Services segment provides services that include gathering, compressing,
treating, processing, transporting and storing natural gas, and fractionating NGLs. The segment consists of our 80% interest in
the Eagle Ford system, 100% owned Eagle Plant, East Texas system, Southeast Texas system, Michigan system, Northern
Louisiana system, Southern Oklahoma system, Wyoming system, 75% interest in the Piceance system, 40% interest in
Discovery, and the O'Connor plant.
NGL Logistics — Our NGL Logistics segment provides services that include transportation, storage and fractionation of
NGLs. The segment consists of the NGL storage facility in Michigan, our 20% interest in the Mont Belvieu 1 fractionator, our
12.5% interest in the Mont Belvieu Enterprise fractionator, the Black Lake and Wattenberg interstate NGL pipelines, the DJ
Basin NGL fractionators in Colorado, the Seabreeze and Wilbreeze intrastate NGL pipelines, our 33.33% interest in the Front
Range interstate NGL pipeline, and our 10% interest in the Texas Express intrastate NGL pipeline.
Wholesale Propane Logistics — Our Wholesale Propane Logistics segment provides services that include the receipt of
propane by pipeline, rail or ship to our terminals that store and deliver the product to distributors. The segment consists of six
owned rail terminals, one owned marine terminal, one leased marine terminal, one pipeline terminal and access to several open-
access pipeline terminals.
These segments are monitored separately by management for performance against our internal forecast and are consistent
with internal financial reporting. These segments have been identified based on the differing products and services, regulatory
environment and the expertise required for these operations. Gross margin is a performance measure utilized by management to
monitor the business of each segment.
139
Wholesale
Propane
Logistics
(Millions)
380
$
Other
Total
— $
— $
—
—
(62)
—
—
(52)
(8)
52
(15)
(2)
—
(4)
—
—
—
31
$
(122) $
—
$
31
(1) $
2
5
$
— $
— $
—
(122) $
$
1
$
— $
— $
— $
2,980
599
(211)
(93)
(62)
(8)
33
(52)
(8)
198
(17)
181
(36)
4
363
782
242
The following tables set forth our segment information:
Year Ended December 31, 2013:
Natural Gas
Services (d)
NGL
Logistics
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other expense
Earnings from unconsolidated affiliates
Interest expense
Income tax expense (b)
Net income (loss)
Net income attributable to noncontrolling
interests
Net income (loss) attributable to partners
Non-cash derivative mark-to-market (c)
Non-cash lower of cost or market adjustments
Capital expenditures
Acquisition expenditures
Investments in unconsolidated affiliates
$
$
$
$
$
$
$
$
$
$
$
2,527
475
(180)
(85)
—
(1)
1
—
—
210
$
(17)
$
193
(36) $
$
2
334
696
133
$
$
$
73
72
(16)
(6)
—
(3)
32
—
—
79
—
79
$
$
$
$
— $
— $
24
86
109
$
$
$
140
Year Ended December 31, 2012:
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Earnings from unconsolidated affiliates
Interest expense
Income tax expense (b)
Net income (loss)
Net income attributable to noncontrolling
interests
Net income (loss) attributable to partners
Non-cash derivative mark-to-market (c)
Capital expenditures
Acquisitions net of cash acquired
Investments in unconsolidated affiliates
Year Ended December 31, 2011:
Natural Gas
Services (d)
NGL
Logistics
Wholesale
Propane
Logistics
(Millions)
Other
Total
$
$
$
$
$
$
$
$
2,282
478
(162)
(81)
—
15
—
—
250
(13)
237
20
467
715
115
$
$
$
$
$
$
$
$
$
$
$
64
64
(16)
(6)
—
11
—
—
53
—
53
$
— $
12
30
43
$
$
$
415
42
(15)
(2)
—
—
—
—
25
—
25
1
4
$
$
$
$
$
$
— $
— $
— $
— $
—
—
(74)
—
(42)
(1)
(117) $
—
(117) $
— $
— $
— $
— $
2,761
584
(193)
(89)
(74)
26
(42)
(1)
211
(13)
198
21
483
745
158
Natural Gas
Services (d)
NGL
Logistics
Wholesale
Propane
Logistics
Other
Eliminations
(f)
Total
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Earnings from unconsolidated
affiliates
Other operating income
Interest expense
Income tax expense (b)
Net income (loss)
Net income attributable to
noncontrolling interests
Net income (loss) attributable to
partners
Non-cash derivative mark-to-market
(c)
Capital expenditures
Acquisitions net of cash acquired
Investments in unconsolidated
affiliates
$
$
$
$
$
$
$
$
$
3,012
497
(157)
(122)
—
23
—
—
—
241
(30)
211
42
371
122
8
$
$
$
$
$
$
$
57
52
(16)
(8)
—
—
1
—
—
29
—
(Millions)
633
$
$
51
(15)
(3)
—
—
—
—
—
33
—
— $
— $
(2) $
— $
—
—
(75)
—
—
(34)
(1)
(110)
—
—
—
—
—
—
—
—
—
—
29
$
33
$
(110) $
— $
— $
— $
(2) $
— $
9
30
$
$
— $
4
$
— $
— $
— $
— $
— $
— $
— $
— $
3,700
600
(188)
(133)
(75)
23
1
(34)
(1)
193
(30)
163
40
384
152
8
141
Segment long-term assets:
Natural Gas Services (d)
NGL Logistics
Wholesale Propane Logistics
Other (e)
Total long-term assets
Current assets (d)
Total assets
2013
December 31,
2012
(Millions)
2011
$
$
3,262
555
106
100
4,023
503
4,526
$
$
2,706
340
105
84
3,235
368
3,603
$
$
2,171
250
104
14
2,539
373
2,912
(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases of natural
gas, propane and NGLs. Gross margin is viewed as a non-GAAP measure under the rules of the SEC, but is included as
a supplemental disclosure because it is a primary performance measure used by management as it represents the results
of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be
considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with
GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities
may not calculate gross margin in the same manner.
(b) For the year ended December 31, 2011, income tax expense relates primarily to the Texas margin tax and the Michigan
business tax. The Michigan business tax was repealed in 2012; accordingly, income tax expense for the years ended
December 31, 2013 and 2012 relates primarily to the Texas margin tax.
(c) Non-cash commodity derivative mark-to-market is included in segment gross margin, along with cash settlements for
our commodity derivative contracts.
(d) The segment information as of and for the years ended December 31, 2013, 2012 and 2011, includes the results of our
80% interest in the Eagle Ford system and our 100% interest in Southeast Texas. Transfers of net assets between entities
under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are
retrospectively adjusted to furnish comparative information, similar to the pooling method.
(e) Other long-term assets not allocable to segments consist of unrealized gains on derivative instruments, corporate
leasehold improvements and other long-term assets.
(f) Represents intersegment revenues consisting of sales of NGLs by Marysville in our NGL Logistics segment to our
Wholesale Propane Logistics segment.
18. Supplemental Cash Flow Information
Cash paid for interest and income taxes:
Cash paid for interest, net of amounts capitalized
Cash paid for income taxes, net of income tax refunds
$
$
Non-cash investing and financing activities:
Property, plant and equipment acquired with accounts
payable
$
Other non-cash additions of property, plant and equipment $
Non-cash change in parent advances
$
Accounts payable related to equity issuance costs
$
Year Ended December 31,
2013
2012
(Millions)
2011
40
1
$
$
27
$
$
1
— $
1
$
23
1
$
$
47
$
8
$
(115) $
— $
17
30
34
3
5
—
19. Quarterly Financial Data (Unaudited)
142
Our consolidated results of operations by quarter for the years ended December 31, 2013 and 2012 were as follows
(millions, except per unit amounts):
2013
Total operating revenues
Operating income
Net income
Net income attributable to
noncontrolling interests
income (loss) attributable
Net
partners
to
Net income (loss) allocable to limited
partners
Basic and diluted net income (loss)
per limited partner unit
2012
Total operating revenues
Operating income
Net income
Net income attributable to
noncontrolling interests
Net income attributable to partners
Net income (loss) allocable to limited
partners
Basic and diluted net income (loss)
per limited partner unit
$
$
$
$
$
$
$
$
$
$
$
$
$
$
First
Second
Third
Fourth
Year Ended
December
31, 2013
731
60
55
$
$
$
775
112
106
$
$
$
(3) $
(4) $
52
31
0.48
$
$
$
102
86
1.11
$
$
$
672
10
2
(3)
(1)
(20)
802
43
35
(7)
28
8
(0.24)
0.09
2,980
225
198
(17)
181
105
1.34
First
Second
Third
Fourth
Year Ended
December
31, 2012
837
46
38
$
$
$
(4) $
34
12
0.26
$
$
$
668
96
87
$
$
$
(2) $
$
85
69
1.33
$
$
604
9
10
$
$
$
(2) $
$
8
652
77
76
$
$
$
(5) $
$
71
(9) $
52
(0.16) $
0.87
$
$
2,761
228
211
(13)
198
124
2.28
20. Supplementary Information — Condensed Consolidating Financial Information
The following condensed consolidating financial information presents the results of operations, financial position and
cash flows of DCP Midstream Partners, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a
100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP
Midstream Partners, LP’s results on a consolidated basis. In conjunction with the universal shelf registration statement on Form
S-3 filed with the SEC on June 14, 2012, the parent guarantor has agreed to fully and unconditionally guarantee securities of the
subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance
with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash
flows, or financial position had the subsidiaries operated as independent entities.
143
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories
Other
Total current assets
Property, plant and equipment, net
Goodwill and intangible assets, net
Advances receivable — consolidated
subsidiaries
Investments in consolidated subsidiaries
Investments in unconsolidated affiliates
Other long-term assets
Total assets
LIABILITIES AND EQUITY
Accounts payable and other current
liabilities
Advances payable — consolidated
subsidiaries
Long-term debt
Other long-term liabilities
Total liabilities
Commitments and contingent liabilities
Equity:
Partners’ equity:
Net equity
Accumulated other comprehensive loss
Total partners’ equity
Noncontrolling interests
Total equity
$
$
Condensed Consolidating Balance Sheet
December 31, 2013
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
— $
— $
12
$
— $
—
—
—
—
—
—
1,805
141
—
—
—
—
—
—
—
—
1,683
386
—
12
342
67
82
503
3,005
283
—
—
627
96
1,946
$
2,081
$
4,514
$
—
—
—
—
—
—
(3,488)
(527)
—
—
(4,015) $
12
342
67
82
503
3,005
283
—
—
627
108
4,526
1
$
350
$
371
$
— $
722
—
—
—
1
1,945
—
1,945
—
1,945
—
1,590
—
1,940
147
(6)
141
—
141
3,488
—
41
3,900
391
(5)
386
228
614
(3,488)
—
—
(3,488)
(527)
—
(527)
—
(527)
(4,015) $
—
1,590
41
2,353
1,956
(11)
1,945
228
2,173
4,526
Total liabilities and equity
$
1,946
$
2,081
$
4,514
$
144
Condensed Consolidating Balance Sheet
December 31, 2012 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
— $
12
$
336
$
(3) $
345
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net
Inventories
Other
Total current assets
Property, plant and equipment, net
Goodwill and intangible assets, net
Advances receivable — consolidated
subsidiaries
Investments in consolidated subsidiaries
Investments in unconsolidated affiliates
Other long-term assets
Total assets
LIABILITIES AND EQUITY
Accounts payable and other current
liabilities
Advances payable — consolidated
subsidiaries
Long-term debt
Other long-term liabilities
Total liabilities
Commitments and contingent liabilities
Equity:
Partners’ equity:
Predecessor equity
Net equity
Accumulated other comprehensive loss
Total partners’ equity
Noncontrolling interests
Total equity
$
$
(Millions)
$
2
$
239
76
51
368
2,550
291
—
—
304
79
3
—
—
—
3
—
—
1,424
728
—
11
$
— $
—
—
—
—
—
—
873
532
—
—
1,405
$
2,166
$
3,592
$
—
—
—
—
—
1,405
—
1,405
—
1,405
—
1,620
2
1,634
—
542
(10)
532
—
532
2,297
—
42
2,675
357
376
(5)
728
189
917
(3) $
—
—
—
(3)
—
—
(2,297)
(1,260)
—
—
(3,560) $
2
239
76
51
368
2,550
291
—
—
304
90
3,603
(2,297)
—
—
(2,300)
—
(1,260)
—
(1,260)
—
(1,260)
(3,560) $
—
1,620
44
2,009
357
1,063
(15)
1,405
189
1,594
3,603
Total liabilities and equity
$
1,405
$
2,166
$
3,592
$
(a) The financial information as of December 31, 2012 includes the results of our 80% interest in the Eagle Ford system, a
transfer of net assets between entities under common control that was accounted for as if the transfer occurred at the
beginning of the period, and prior years are retrospectively adjusted to furnish comparative information similar to the
pooling method.
145
Operating revenues:
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
Gains from commodity derivative activity, net
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other expense
Total operating costs and expenses
Operating income
Interest expense, net
Income from consolidated subsidiaries
Earnings from unconsolidated affiliates
Income before income taxes
Income tax expense
Net income
Net income attributable to noncontrolling
interests
Condensed Consolidating Statement of Operations
Year Ended December 31, 2013 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-
Guarantor
Subsidiaries
(Millions)
Consolidating
Adjustments
Consolidated
$
— $
— $
2,695
$
— $
2,695
—
—
—
—
—
—
—
—
—
—
—
181
—
181
—
181
—
—
—
—
—
—
—
—
—
—
—
(52)
233
—
181
—
181
—
268
17
2,980
2,381
211
93
62
8
2,755
225
—
—
33
258
(8)
250
—
—
—
—
—
—
—
—
—
—
—
(414)
—
(414)
—
(414)
(17)
233
$
—
(414) $
268
17
2,980
2,381
211
93
62
8
2,755
225
(52)
—
33
206
(8)
198
(17)
181
Net income attributable to partners
$
181
$
181
$
(a) The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle
Ford system, a transfer of net assets between entities under common control that was accounted for as if the transfer
occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information
similar to the pooling method.
146
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2013 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
181
$
181
$
250
$
(414) $
198
—
4
4
185
—
4
—
4
185
—
—
—
—
250
(17)
—
(4)
(4)
(418)
—
$
185
$
185
$
233
$
(418) $
4
—
4
202
(17)
185
Net income
Other comprehensive income:
Reclassification of cash flow hedge
losses into earnings
Other comprehensive income from
consolidated subsidiaries
Total other comprehensive income
Total comprehensive income
Total comprehensive income
attributable to noncontrolling interests
Total comprehensive income attributable to
partners
(a) The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle
Ford system, a transfer of net assets between entities under common control that was accounted for as if the transfer
occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information
similar to the pooling method.
147
Operating revenues:
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
Gains from commodity derivative activity,
net
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and
NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Total operating costs and expenses
Operating income
Interest expense, net
Earnings from unconsolidated affiliates
Income from consolidated subsidiaries
Income before income taxes
Income tax expense
Net income
Net income attributable to noncontrolling
interests
Condensed Consolidating Statement of Operations
Year Ended December 31, 2012 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
— $
— $
2,459
$
— $
—
—
—
—
—
—
—
—
—
—
—
198
198
—
198
—
—
—
—
—
—
—
—
—
—
(41)
—
239
198
—
198
—
232
70
2,761
2,177
193
89
74
2,533
228
(1)
26
—
253
(1)
252
—
—
—
—
—
—
—
—
—
—
—
(437)
(437)
—
(437)
(13)
239
$
—
(437) $
2,459
232
70
2,761
2,177
193
89
74
2,533
228
(42)
26
—
212
(1)
211
(13)
198
Net income attributable to partners
$
198
$
198
$
(a) The financial information for the year ended December 31, 2012 includes the results of our 80% interest in the Eagle
Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the
Southeast Texas storage business. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish
comparative information similar to the pooling method.
148
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2012 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
198
$
198
$
252
$
(437) $
211
—
—
9
9
207
—
10
(1)
—
9
207
—
—
—
—
—
252
(13)
—
—
(9)
(9)
(446)
—
$
207
$
207
$
239
$
(446) $
10
(1)
—
9
220
(13)
207
Net income
Other comprehensive loss:
Reclassification of cash flow hedge
losses into earnings
Net unrealized losses on cash flow
hedges
Other comprehensive income from
consolidated subsidiaries
Total other comprehensive income
Total comprehensive income
Total comprehensive income
attributable to noncontrolling interests
Total comprehensive income attributable to
partners
(a) The financial information for the year ended December 31, 2012 includes the results of our 80% interest in the Eagle
Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the
Southeast Texas storage business. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish
comparative information similar to the pooling method.
149
Operating revenues:
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
Gains from commodity derivative activity,
net
Total operating revenues
Operating costs and expenses:
Purchases of natural gas, propane and
NGLs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other income
Total operating costs and expenses
Operating income
Interest expense
Earnings from unconsolidated affiliates
Income from consolidated subsidiaries
Income before income taxes
Income tax expense
Net income
Net income attributable to noncontrolling
interests
Condensed Consolidating Statement of Operations
Year Ended December 31, 2011 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
— $
— $
3,487
$
— $
—
—
—
—
—
—
—
—
—
—
—
—
163
163
—
163
—
—
—
—
—
—
—
—
—
—
—
(33)
—
196
163
—
163
—
205
8
3,700
3,100
188
133
75
(1)
3,495
205
(1)
23
—
227
(1)
226
—
—
—
—
—
—
—
—
—
—
—
—
(359)
(359)
—
(359)
(30)
196
$
—
(359) $
3,487
205
8
3,700
3,100
188
133
75
(1)
3,495
205
(34)
23
—
194
(1)
193
(30)
163
Net income attributable to partners
$
163
$
163
$
(a) The financial information for the year ended December 31, 2011 includes the results of our 80% interest in the Eagle
Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the
Southeast Texas storage business. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish
comparative information similar to the pooling method.
150
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2011 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
163
$
163
$
226
$
(359) $
193
—
—
6
6
169
—
21
(12)
(3)
6
169
—
—
(3)
—
(3)
223
(30)
—
—
(3)
(3)
(362)
—
$
169
$
169
$
193
$
(362) $
21
(15)
—
6
199
(30)
169
Net income
Other comprehensive loss:
Reclassification of cash flow hedge
losses into earnings
Net unrealized losses on cash flow
hedges
Other comprehensive income from
consolidated subsidiaries
Total other comprehensive income
Total comprehensive income
Total comprehensive income
attributable to noncontrolling interests
Total comprehensive income attributable to
partners
(a) The financial information for the year ended December 31, 2011 includes the results of our 80% interest in the Eagle
Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the
Southeast Texas storage business. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish
comparative information similar to the pooling method.
151
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
INVESTING ACTIVITIES:
Capital expenditures
Acquisitions, net of cash acquired
Acquisition of unconsolidated affiliates
Investments in unconsolidated affiliates
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from long-term debt
Payments of long-term debt
Proceeds from issuance of commercial paper
Payments of deferred financing costs
Excess purchase price over acquired interests
and commodity hedges
Proceeds from issuance of common units, net
of offering costs
Net change in advances to predecessor from
DCP Midstream, LLC
Distributions to limited partners and general
partner
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Distributions to DCP Midstream, LLC
Contributions from DCP Midstream, LLC
Net cash provided by (used in) financing
activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of
period
Cash and cash equivalents, end of period
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2013 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
(806)
(303)
1,430
—
—
—
—
—
—
—
—
—
—
1,083
—
(277)
—
—
—
—
806
—
—
—
—
—
—
—
—
1,957
(1,988)
335
(4)
—
—
—
—
—
—
—
—
300
(3)
3
—
(363)
(696)
(86)
(242)
(1,387)
—
—
—
—
(85)
—
32
—
(24)
46
(3)
1
(33)
10
2
12
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3
(3)
—
324
(363)
(696)
(86)
(242)
(1,387)
1,957
(1,988)
335
(4)
(85)
1,083
32
(277)
(24)
46
(3)
1
1,073
10
2
12
(a) The financial information for the year ended December 31, 2013 includes the results of our 80% interest in the Eagle
Ford system, a transfer of net assets between entities under common control that was accounted for as if the transfer
occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information
similar to the pooling method.
152
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
INVESTING ACTIVITIES:
Capital expenditures
Acquisitions, net of cash acquired
Investments in unconsolidated affiliates
Return of investment from unconsolidated
affiliate
Proceeds from sale of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from long-term debt
Payments of long-term debt
Payment of deferred financing costs
Proceeds from issuance of common units, net
of offering costs
Excess purchase price over acquired assets
Net change in advances to predecessor from
DCP Midstream, LLC
Distributions to common unitholders and
general partner
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Contributions from DCP Midstream, LLC
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2012 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
$
(274) $
(866) $
1,223
$
(1) $
82
—
—
—
—
—
—
—
—
—
455
—
—
(181)
—
—
—
274
—
—
—
—
—
—
—
—
2,665
(1,792)
(8)
—
—
—
—
—
—
—
865
(1)
4
(483)
(745)
(158)
1
2
(1,383)
—
—
—
—
(225)
355
—
(9)
25
10
156
(4)
6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1)
(2)
(3) $
(483)
(745)
(158)
1
2
(1,383)
2,665
(1,792)
(8)
455
(225)
355
(181)
(9)
25
10
1,295
(6)
8
2
Cash and cash equivalents, end of year
$
— $
3
$
2
$
(a) The financial information during the year ended December 31, 2012 includes the results of our 80% interest in the Eagle
Ford system and our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the
Southeast Texas storage business. These transfers of net assets between entities under common control were accounted
for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish
comparative information similar to the pooling method.
153
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
$
INVESTING ACTIVITIES:
Capital expenditures
Acquisitions, net of cash acquired
Investments in unconsolidated affiliates
Return of investment from unconsolidated
affiliate
Proceeds from sale of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from debt
Payments of debt
Payment of deferred financing costs
Proceeds from issuance of common units, net
of offering costs
Excess purchase price over acquired
unconsolidated affiliates
Net change in advances to predecessor from
DCP Midstream, LLC
Distributions to common unitholders and
general partner
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Net cash provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of year
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2011 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(Millions)
(38) $
(93) $
518
$
— $
387
—
—
—
—
—
—
—
—
—
170
—
—
(132)
—
—
38
—
—
—
—
—
—
—
—
1,524
(1,425)
(4)
—
—
—
—
—
—
95
2
2
4
(384)
(152)
(8)
2
5
(537)
—
—
—
—
(36)
81
—
(45)
18
18
(1)
7
$
6
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(2)
(2) $
(384)
(152)
(8)
2
5
(537)
1,524
(1,425)
(4)
170
(36)
81
(132)
(45)
18
151
1
7
8
Cash and cash equivalents, end of year
$
— $
(a) The financial information as of December 31, 2011, includes the results of our 80% interest in the Eagle Ford system and
our 100% interest in Southeast Texas and commodity derivative hedge instruments related to the Southeast Texas storage
business. These transfers of net assets between entities under common control were accounted for as if the transfers
occurred at the beginning of the period, and prior years were retrospectively adjusted to furnish comparative information
similar to the pooling method.
154
21. Valuation and Qualifying Accounts and Reserves
Our valuation and qualifying accounts and reserves for the years ended December 31, 2013, 2012, and 2011 are as follows:
December 31, 2013
Environmental
Other (a)
December 31, 2012
Environmental
Other (a)
December 31, 2011
Environmental
Litigation
Other (a)
Balance at
Beginning
of Period
Charged to
Consolidated
Statements
of operations
Charged to
Other
Accounts
(Millions)
Deductions/
Other
Balance at
End of
Period
$
$
$
$
$
$
2
1
3
3
1
4
3
1
—
4
$
$
$
$
$
$
1
—
1
$
$
— $
—
— $
— $
—
— $
— $
—
— $
— $
— $
—
1
1
—
—
$
— $
(1) $
—
(1) $
(1) $
—
(1) $
— $
(1)
—
(1) $
2
1
3
2
1
3
3
—
1
4
(a) Principally consists of allowance for doubtful accounts, reserves against other long-term assets, which are included in
other long-term assets, and other contingency liabilities, which are included in other current liabilities.
22. Subsequent Events
On January 28, 2014, we announced that the board of directors of the General Partner declared a quarterly distribution of
$0.7325 per unit, payable on February 14, 2014 to unitholders of record on February 7, 2014.
On February 25, 2014, we entered into various transaction documents with DCP Midstream, LLC for the contribution or
acquisition of (i) the remaining 20% interest in DCP SC Texas GP; (ii) a 33.33% membership interest in each DCP Southern
Hills Pipeline, LLC, which owns the Southern Hills pipeline, and DCP Sand Hills Pipeline, LLC, which owns the Sand Hills
pipeline; (iii) a 35 MMcf/d cryogenic natural gas processing plant located in Weld County, Colorado, or the Lucerne 1 plant;
and (iv) a 200 MMcf/d cryogenic natural gas processing plant also located in Weld County, Colorado, which is currently under
construction, or the Lucerne 2 plant. Total consideration for this transaction at closing is $1,220 million, subject to certain
working capital and other customary adjustments. This transaction is expected to close in March 2014, subject to customary
closing conditions, and components of the transaction may close separately. The Southern Hills pipeline is engaged in the
business of transporting NGLs, and consists of approximately 800 miles of pipeline, with an expected capacity of 175 MBbls/d
after completion of planned pump stations. The pipeline provides NGL takeaway service from the Midcontinent to fractionation
facilities along the Texas Gulf Coast and the Mont Belvieu, Texas market hub.The Southern Hills pipeline began taking flows in
the first quarter of 2013 and was placed into service in June 2013. The Sand Hills pipeline is also engaged in the business of
transporting NGLs and consists of approximately 720 miles of pipeline, with an expected initial capacity of 200 MBbls/d after
completion of pump stations, and possible further capacity increases with the installation of additional pump stations. The
pipeline provides NGL takeaway service from the Permian and Eagle Ford basins to fractionation facilities along the Texas
Gulf Coast and the Mont Belvieu, Texas market hub. The Sand Hills pipeline began taking flows in the fourth quarter of 2012
and was placed into service in June 2013.
155
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There were no changes in or disagreements with accountants on accounting and financial disclosures during the year
ended December 31, 2013.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by
us in the reports that we file or submit to the Securities and Exchange Commission under the Securities Exchange Act of 1934,
as amended, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and
forms, and that information is accumulated and communicated to the management of our general partner, including our general
partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to
allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation
of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of December 31, 2013, pursuant to
Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as
of December 31, 2013, our disclosure controls and procedures were effective at a reasonable assurance level. There were no
changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during
the fourth quarter of 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
Management’s Annual Report On Internal Control Over Financial Reporting
Our general partner is responsible for establishing and maintaining an adequate system of internal control over financial
reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to
provide reasonable assurance to our management and board of directors of our general partner regarding the preparation and
fair presentation of published financial statements.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over
financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with
policies and procedures may deteriorate.
Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the
effectiveness of our internal control over financial reporting as of December 31, 2013 based on the 1992 framework in “Internal
Control-Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
that evaluation, management concluded that our internal control over financial reporting was effective at the reasonable
assurance level as of December 31, 2013.
Deloitte & Touche, LLP, an independent registered public accounting firm, has issued their report, included immediately
following, regarding our internal control over financial reporting.
156
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream GP, LLC
Denver, Colorado
We have audited the internal control over financial reporting of DCP Midstream Partners, LP and subsidiaries (the "Company")
as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the
Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting.
Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's
principal executive and principal financial officers, or persons performing similar functions, and effected by the company's
board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of
the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that
could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or
improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a
timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated financial statements as of and for the year ended December 31, 2013 of the Company and our report dated
February 26, 2014 expressed an unqualified opinion on those consolidated financial statements and included explanatory
paragraphs referring to (a) the retrospective adjustment for the acquisition by DCP Midstream Partners, LP of the 100%
ownership interest in DCP Southeast Texas Holdings, GP, of which 33.33% and 66.67% was acquired on January 1, 2011 and
March 30, 2012, respectively, from DCP Midstream, LLC, which was accounted for in a manner similar to a pooling of
interests, (b) the retrospective adjustment of an 80% ownership in DCP SC Texas GP, of which 33.33% and 46.67% was
acquired on November 2, 2012 and March 28, 2013, respectively, from DCP Midstream LLC, which has been accounted for in
a manner similar to a pooling of interests, (c) the preparation of the portion of the consolidated financial statements attributable
to DCP Southeast Texas Holdings, GP and DCP SC Texas GP from the separate records maintained by DCP Midstream, LLC,
and (d) the retrospective effect to new disclosure requirements regarding information related to balance sheet offsetting of
assets and liabilities as disclosed in Note 11 to the consolidated financial statements.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2014
157
Item 9B. Other Information
No information was required to be disclosed in a report on Form 8-K, but not so reported, for the quarter ended
December 31, 2013.
Item 10. Directors, Executive Officers and Corporate Governance
Management of DCP Midstream Partners, LP
PART III
We do not have directors or officers, which is commonly the case with publicly traded partnerships. Our operations and
activities are managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP
Midstream GP, LLC, which we refer to as our General Partner. Our General Partner is 100% owned by DCP Midstream, LLC.
The officers and directors of our General Partner are responsible for managing us. All of the directors of our General Partner
are elected annually by DCP Midstream, LLC and all of the officers of our General Partner serve at the discretion of the
directors. Unitholders are not entitled to participate, directly or indirectly, in our management or operations.
Board of Directors and Officers
The board of directors of our General Partner that oversees our operations currently has ten members, four of whom are
independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited
partnership like us to have a majority of independent directors on its general partner’s board of directors or to establish a
compensation committee or a nominating committee. However, the board of directors of our General Partner has established an
audit committee consisting of four independent members of the board and a special committee to address conflict situations.
Our General Partner’s board of directors annually reviews the independence of directors and affirmatively makes a
determination that each director expected to be independent has no material relationship with our General Partner, either
directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with our General Partner.
The executive officers of our General Partner are responsible for establishing and executing strategic business and
operation plans and managing the day-to-day affairs of our business. All of our executive management personnel are employees
of DCP Midstream, LLC. In 2013, Mr. Waldheim, President, and Ms. Robeson, former Senior Vice President and Chief
Financial Officer, or CFO, devoted substantially all of their time to our business and affairs. Mr. Richards, who is also Vice
President and Deputy General Counsel of DCP Midstream, LLC, devoted approximately 90% of his time to our business and
affairs. Mr. van Kempen, our Chief Executive Officer, or CEO, is also the President and CEO of DCP Midstream, LLC and
spent less than 10% of his time on our matters. We have reimbursed DCP Midstream, LLC for the allocated portion of the time
Mr. van Kempen spends on our matters in the Services Agreement, which was less than $100,000 in 2013. We also utilize
employees of DCP Midstream, LLC to operate our business and provide us with general and administrative services that are
reimbursed to DCP Midstream, LLC under the Services Agreement.
In early 2013, Thomas C. O’Connor retired as President and CEO of DCP Midstream, LLC and became a non-executive
Chairman of the board of directors of our General Partner. In connection with that change, Mr. O’Connor became a party to an
agreement with DCP Midstream, LLC pursuant to which DCP Midstream, LLC compensated Mr. O’Connor for his services to
us and DCP Midstream, LLC in an amount equal to $13,886 per month through the end of 2013, plus two bonus retention
payments of $500,000 each for his service as non-executive Chairman of the board of directors of our General Partner. On
December 31, 2013, Mr. O’Connor retired as a member and Chairman of the board of directors. Effective January 1, 2014, Mr.
van Kempen was appointed as a member and as Chairman of the board of directors of our General Partner.
In early 2014, we announced the departure of Ms. Robeson as the Senior Vice President and CFO and the appointment of
Mr. O’Brien as the Group Vice President and CFO of the General Partner. Mr. O'Brien is also the Group Vice President and
CFO of DCP Midstream, LLC, the owner of the General Partner. We anticipate that Mr. O'Brien will spend less than 25% of his
time on our matters and we will be reimburse DCP Midstream, LLC for the allocated portion of his time that he spends on our
matters in the Services Agreement, which we expect to be less than $300,000 in 2014. In 2014, Mr. van Kempen also expects to
spend less than 25% of his time on our matters and we will be reimburse DCP Midstream, LLC for the allocated portion of his
time, which we expect to be less than $400,000, under the Services Agreement.
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Meeting Attendance and Preparation
The board of directors met eight times in 2013 and members of the board of directors attended at least 75% of regular and
special meetings and meetings of the committees on which they serve, either in person or telephonically, during 2013. In
addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
Directors and Executive Officers
The following table shows information regarding the current directors and the executive officers of DCP Midstream GP,
LLC. Directors are elected for one-year terms.
Name
Age Position with DCP Midstream GP, LLC
Wouter T. van Kempen
44 Chief Executive Officer, Chairman of the Board and Director
William S. Waldheim
Sean P. O'Brien
Michael S. Richards
Paul F. Ferguson, Jr.
R. Mark Fiedorek
Alan N. Harris
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
Andy Viens
Brian R. Wenzel
57 President and Director
44 Group Vice President and Chief Financial Officer
54 Vice President, General Counsel and Secretary
64 Director
51 Director
60 Director
80 Director
73 Director
67 Director
59 Director
49 Director
Directors hold office for one year or until the earlier of their death, resignation, removal or disqualification or until their
successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family
relationships among any of the directors or executive officers.
Wouter T. van Kempen was elected Chairman and member of the Board of DCP Midstream GP, LLC on January 1, 2014 and
CEO of DCP Midstream GP, LLC on January 1, 2013. Mr. van Kempen is also the Chairman, President and Chief Executive
Officer for DCP Midstream, LLC, the owner of our General Partner, since January 1, 2013. Mr. van Kempen was previously the
President and Chief Operating Officer of DCP Midstream, LLC from September 2012 until January 1, 2013. Prior to that time,
Mr. van Kempen was President, Gathering and Processing, of DCP Midstream, LLC from January 2012 to August 2012; President,
Midcontinent & Permian Business Units, and Chief Development Officer from June 2011 to December 2011; and President,
Midcontinent, and Chief Development Officer from August 2010 to May 2011. Prior to joining DCP Midstream, LLC in 2010,
Mr. van Kempen was President of Duke Energy Generation Services from September 2006 to July 2010 and Vice President of
Mergers and Acquisitions from December 2005 to September 2006. Mr. van Kempen joined Duke Energy in 2003 and served in
a number of management positions. Prior to Duke Energy, Mr. van Kempen was employed by General Electric, where he served
in increasing roles of responsibility becoming the staff executive for corporate mergers and acquisitions in 1999. Mr. van Kempen
graduated from Erasmus University Rotterdam with a master’s degree in business economics. He has extensive business and
financial training from General Electric, Harvard Business School, Kellogg Graduate School and IMD International Switzerland.
William S. Waldheim was elected President of DCP Midstream GP, LLC in September 2012 and was elected as a director
in January 2013. Prior to that time, Mr. Waldheim was President, NGL, of DCP Midstream, LLC and served in that position
since 2011. Prior to that time, Mr. Waldheim was President of DCP Midstream, LLC’s northern business unit since 2009 where
he was responsible for executive management of commercial and operations of the assets in the Midcontinent, Rocky
Mountain, Michigan and Gulf Coast regions as well as the downstream marketing of gas, NGLs and condensate. From 1999 to
2009, Mr. Waldheim served in a variety of commercial and operational executive management positions at DCP Midstream,
LLC. Prior to joining DCP Midstream, Mr. Waldheim served in a number of executive management positions with Union
Pacific Fuels, Inc. Mr. Waldheim has over 30 years of experience in the energy industry and has previously served on the
boards of various energy industry groups including the National Propane Gas Association and the Propane Education &
Research Council. Mr. Waldheim currently serves on the board of directors of the Colorado Oil & Gas Association and the
Rocky Mountain Chapter of Junior Achievement.
Sean P. O'Brien was appointed Group Vice President and Chief Financial Officer of DCP Midstream GP, LLC in January
2014. Mr. O'Brien is also the Group Vice President and Chief Financial Officer for DCP Midstream,LLC and has served in that
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position since May 2012. Prior to that time, Mr. O’Brien was Senior Vice President and Treasurer of DCP Midstream, LLC
from May 2011 and prior to that, he served as Vice President, Financial Planning and Analysis from September 2009. Prior to
joining DCP Midstream, LLC in September 2009, Mr. O’Brien was with Duke Energy Corporation where he served as General
Manager of Financial Planning and Forecasting for Duke Energy’s Commercial Business Unit from May 2006, and prior to
that, he was Vice President and Controller of Duke Energy Generation Services from May 2005. Mr. O’Brien joined Duke
Energy in 1997. Mr. O’Brien is a certified public accountant with over 21 years of experience in the finance area and over 16
years of experience in the energy industry.
Michael S. Richards was elected Vice President, General Counsel and Secretary of DCP Midstream GP, LLC in
September 2005. Mr. Richards was previously Assistant General Counsel and Assistant Secretary of DCP Midstream, LLC
since February 2000. He was previously Assistant General Counsel and Assistant Secretary at KN Energy, Inc. from December
1997 until he joined DCP Midstream, LLC. Prior to that, he was Senior Counsel and Risk Manager at Total Petroleum (North
America) Ltd. from 1994 through 1997. Mr. Richards was previously in private practice where he focused on securities and
corporate finance. Mr. Richards has also been Vice President and Deputy General Counsel for DCP Midstream, LLC since
2013.
Paul F. Ferguson, Jr. was elected as a director of DCP Midstream GP, LLC in November 2005. Mr. Ferguson currently
serves as Chairman of the Audit Committee of the board of directors. He served as Senior Vice President and Treasurer of Duke
Energy from June 1997 to June 1998, when he retired. Mr. Ferguson served as Senior Vice President and Chief Financial
Officer of PanEnergy Corp. from September 1995 to June 1997. He held various other financial positions with PanEnergy
Corp. from 1989 to 1995 and served as Treasurer of Texas Eastern Corporation from 1988 to 1989. Mr. Ferguson was a director
of the general partner of TEPPCO Partners, L.P. where he was a member of the compensation, audit and special committees
from October 2004 until his resignation in 2005.
R. Mark Fiedorek was elected as a director of DCP Midstream GP, LLC in May 2012. Mr. Fiedorek is currently the
President of Spectra Energy Transmission's western Canadian operations, a position he has been in since January 2013. Mr.
Fiedorek joined Spectra Energy in 1988 and has served in a number of management positions primarily in the supply, planning,
operations and marketer services areas.
Alan N. Harris was elected as a director of DCP Midstream, GP, LLC in January 2014 after having previously served as
Spectra’s representative on the Board of Directors from January 1, 2009 through April 25, 2012. Mr. Harris is currently a
special advisor on project development for Spectra. From January 2007 until December 2013, Mr. Harris was Chief
Development and Operations Officer of Spectra. Prior to that, Mr. Harris served as Group Vice President and Chief Financial
Officer of Duke Energy Gas Transmission since February 2004. Mr. Harris served as Executive Vice President of Duke Energy
Gas Transmission from January 2003 until February 2004. Prior to that, Mr. Harris served as Senior Vice President, Strategic
Development & Planning from March 2002 until January 2003 and Vice President, Controller & Strategic Planning from April
1999 until March 2002. Mr. Harris has over 30 years of experience in the energy industry.
Frank A. McPherson was elected as a director of DCP Midstream GP, LLC in December 2005. Mr. McPherson retired as
Chairman and Chief Executive Officer from Kerr McGee Corporation in 1997 after a 40-year career with the company. Mr.
McPherson was Chairman and Chief Executive Officer of Kerr McGee from 1983 to 1997. Prior to that, he served in various
capacities in management of Kerr McGee. Mr. McPherson joined Kerr McGee in 1957. Mr. McPherson served on the boards of
Tri Continental Corporation, Seligman Group of Mutual Funds, ConocoPhillips, Kimberly Clark Corporation, MAPCO Inc.,
Bank of Oklahoma, the Federal Reserve Bank of Kansas City and the American Petroleum Institute. He also served on the
boards of several non-profit organizations in Oklahoma.
Thomas C. Morris was elected as a director of DCP Midstream GP, LLC in December 2005. Mr. Morris is currently
retired, having served 34 years with Phillips Petroleum Company. Mr. Morris served in various capacities with Phillips,
including Vice President and Treasurer and subsequently Senior Vice President and Chief Financial Officer from 1994 until his
retirement in 2001. Mr. Morris served as Vice Chairman of the board of OK Mozart, is a former member of the executive board
of the American Petroleum Institute finance committee and a former member of the Business Development Council of Texas
A&M University.
Stephen R. Springer was elected as a director of DCP Midstream GP, LLC in July 2007. Mr. Springer currently serves as
chairman of the Special Committee of the board of Directors which addresses conflict situations. He began his career at Texas
Gas Transmission Corporation, where he served in a variety of executive management positions within gas acquisitions and gas
marketing. After serving as President of Transco Gas Marketing Company, he served as Vice President of Business
Development at Williams Field Services Company and then Senior Vice President and General Manager of Williams
Midstream Division, the position he held until his retirement in 2002. Mr. Springer has served on the board of directors of
Atmos Energy Corporation (NYSE: ATO) since 2005.
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Andy Viens was elected as a director of DCP Midstream GP, LLC in July 2012. Mr. Viens is currently the President of
Global Marketing for Phillips 66. Prior to being named to his current role, Mr. Viens served as President of Global Marketing
for ConocoPhillips since 2010. Prior to that time, Mr. Viens served in a variety of capacities at ConocoPhillips including as
President, U.S. Marketing and General Manager, Commercial Marine. Prior to joining ConocoPhillips, he was with Tosco
where he served in various marketing roles.
Brian R. Wenzel was elected as a director of DCP Midstream GP, LLC in June 2013. Mr. Wenzel is currently the Vice
President and Treasurer for Phillips 66. Prior to being named to his current role in May 2012, Mr. Wenzel worked for
ConocoPhillips as General Manager, Corporate Planning & Strategy, since July 2010. Prior to that, Mr. Wenzel was Vice
President, Finance for ConocoPhillips Alaska, after serving as President, ANS Gas Development, until May 2009. His first
position with ConocoPhillips Alaska was in 2005 as Vice President, Finance and Administration. In 2003, Mr. Wenzel was
named Manager of Treasury Services of ConocoPhillips in Bartlesville, Oklahoma. In 2001, Mr. Wenzel became the finance
manager for Phillips Petroleum Company’s Australasia division in Perth, Australia. Mr. Wenzel joined Phillips Petroleum
Company in 1991 as a financial analyst.
Director Experience and Qualifications
Directors are appointed annually by DCP Midstream, LLC and hold office for one year or until the earlier of their death,
resignation, removal or disqualification and until their successors have been elected and qualified. DCP Midstream, LLC
evaluates and recommends candidates for membership on the board of directors based on criteria established thereby. When
evaluating director candidates, nominees and incumbent directors, DCP Midstream, LLC has informed us that it considers,
among other things, educational background, knowledge of our business and industry, professional reputation, independence,
and ability to represent the best interests of our unitholders. DCP Midstream, LLC and the board of directors believe that the
above-mentioned attributes, along with the leadership skills and experience in the midstream natural gas industry, provide the
Partnership with a capable and knowledgeable board of directors.
Wouter T. van Kempen - We believe Mr. van Kempen is a suitable member of the board of directors as he brings to the
company extensive knowledge and experience about our assets as Chairman, President and Chief Executive Officer of DCP
Midstream, LLC and he brings strong management experience serving in positions of increasing responsibility at Duke Energy
and General Electric.
Paul F. Ferguson, Jr. - We believe that Mr. Ferguson is a suitable member of the board of directors because of his
extensive industry experience. Mr. Ferguson has held various financial positions with PanEnergy Corp., and the knowledge of
industry accounting and financial practices he gained through such experience, coupled with his accounting background and his
CPA designation, make him valuable to the board of directors’ understanding of the Partnership’s financial data and its
implications to the future strategic planning of the Partnership. Mr. Ferguson also provides insight to the board of directors as to
the Partnership’s financial compliance and reporting obligations. Because Mr. Ferguson has served as a director since 2005, he
brings to the board of directors valuable historical perspective of board and company operations.
R. Mark Fiedorek - We believe that Mr. Fiedorek is a suitable member of the board of directors because of his extensive
industry experience and executive management experience including his positions with Spectra Energy in natural gas
transmission, and in the supply, operations and marketing of natural gas.
Alan N. Harris - We believe that Mr. Harris is a suitable member of the board of directors because he has over 30 years of
leadership experience in the natural gas industry. In addition, Mr. Harris’ prior experience as Chief Financial Officer of Duke
Energy Gas Transmission and his knowledge of industry accounting and financial practices are invaluable to the board of
directors’ understanding of the Partnership’s financial data and its implications to the future planning of the Partnership.
Frank A. McPherson - We believe that Mr. McPherson is a suitable member of the board of directors because of his
extensive industry and executive management experience, spanning over a period of 50 years. In addition, Mr. McPherson’s
prior public company board experience provides the board of directors with valuable insight into corporate governance and
compliance matters. Because Mr. McPherson has served as a director since 2005, he also brings to the board of directors
valuable historical perspective of board and company operations.
Thomas C. Morris - We believe that Mr. Morris is a suitable member of the board of directors because of the industry
knowledge and experience gained during his 34 years of service with Phillips Petroleum Company. In addition, Mr. Morris’
background in finance and accounting, coupled with his previous role as Chief Financial Officer of Phillips Petroleum
Company, are invaluable to the board of directors’ understanding of the Partnership’s financial data and its implications to the
future strategic planning of the Partnership. Because Mr. Morris has served as a director since 2005, he also brings to the board
of directors, valuable historical perspective of board and company operations.
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Stephen R. Springer - We believe that Mr. Springer is a suitable member of the board of directors because of his extensive
industry experience, including natural gas acquisitions, natural gas marketing, natural gas gathering and processing, NGL
transportation and business development. In addition, Mr. Springer’s prior public company board experience provides the board
of directors with valuable insight into public company operations, corporate governance and compliance matters.
Andy Viens - We believe that Mr. Viens is a suitable member of the board of directors because of his extensive industry
experience and executive management experience including his marketing positions at Phillips 66 and ConocoPhillips.
William S. Waldheim - We believe Mr. Waldheim is a suitable member of the board of directors because of his extensive
industry experience and his extensive knowledge and experience about our assets as President of DCP Midstream GP, LLC and
in his prior management experience with DCP Midstream, LLC.
Brian R. Wenzel - We believe that Mr. Wenzel is a suitable member of the board of directors because of his extensive
industry experience and his knowledge of industry financing as Vice President and Treasurer for Phillips 66 and his prior
extensive treasury and finance experience with ConocoPhillips.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires DCP Midstream GP, LLC’s directors and executive
officers, and persons who own more than 10% of any class of our equity securities, to file with the Securities and Exchange
Commission, or SEC, and the NYSE initial reports of ownership and reports of changes in ownership of our common units and
our other equity securities. Specific due dates for those reports have been established, and we are required to report herein any
failure to file reports by those due dates. Directors, executive officers and greater than 10% unitholders are also required by
SEC regulations to furnish us with copies of all Section 16(a) reports they file. To our knowledge, based solely on a review of
the copies of reports and amendments thereto, furnished to us and written representations that no other reports were required
during the fiscal year ended December 31, 2013, all Section 16(a) filing requirements applicable to such reporting persons were
complied with except that William Waldheim, an executive officer, filed a Form 4 on May 23, 2013 that reported the gift of 50
common units to his adult son that had been inadvertently omitted from his prior Form 3 and Form 4 filings.
Audit Committee
The board of directors of our General Partner has a standing audit committee. The audit committee is composed of four
non-management directors, Paul F. Ferguson, Jr. (chairman), Frank A. McPherson, Thomas C. Morris and Stephen R. Springer,
each of whom is able to understand fundamental financial statements and at least one of whom has past experience in
accounting or related financial management experience. The board has determined that each member of the audit committee is
independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Securities Exchange Act of
1934, as amended. In making the independence determination, the board considered the requirements of the NYSE and our
Code of Business Ethics. Among other factors, the board considered current or previous employment with us, our auditors or
their affiliates by the director or his immediate family members, ownership of our voting securities, and other material
relationships with us. The audit committee has adopted a charter, which has been ratified and approved by the board of
directors.
With respect to material relationships, the following relationships are not considered to be material for purposes of
assessing independence: service as an officer, director, employee or trustee of, or greater than five percent beneficial ownership
in (a) a supplier to the Partnership if the annual sales to the Partnership are less than one percent of the sales of the supplier;
(b) a lender to the Partnership if the total amount of the Partnership's indebtedness is less than one percent of the total
consolidated assets of the lender; or (c) a charitable organization if the total amount of the Partnership’s annual charitable
contributions to the organization are less than three percent of that organization’s annual charitable receipts.
Mr. Ferguson has been designated by the board as the audit committee’s financial expert meeting the requirements
promulgated by the SEC and set forth in Item 407(d) of Regulation S-K of the Securities Exchange Act of 1934, as amended,
based upon his education and employment experience as more fully detailed in Mr. Ferguson’s biography set forth above.
Special Committee
The board of directors of our General Partner has a standing special committee, which is comprised of four non-
management directors, Stephen R. Springer (chairman), Paul F. Ferguson, Jr., Frank A. McPherson and Thomas C. Morris. The
special committee will review specific matters that the board believes may involve conflicts of interest. The special committee
will determine if the resolution of the conflict of interest is fair and reasonable to us, or on grounds no less favorable to us than
generally available from unrelated third parties. The special committee meets at each quarterly meeting of the board of
directors. The members of the special committee may not be officers or employees of our General Partner or directors, officers
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or employees of its affiliates. Each of the members of the special committee meet the independence and experience standards
established by the NYSE and the Securities Exchange Act of 1934, as amended. Any matters approved by the special
committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our
General Partner of any duties it may owe us or our unitholders.
Corporate Governance Guidelines and Code of Business Ethics
Our board of directors has adopted Corporate Governance Guidelines that outline the important policies and practices
regarding our governance.
We have adopted a Code of Business Ethics applicable to the persons serving as our directors, officers (including without
limitation, the chief executive officer, chief financial officer and principal accounting officer) and employees. We intend to
disclose any amendment to or waiver of our Code of Business Ethics that applies to our executive officers or directors on our
website at www.dcppartners.com in order to satisfy disclosure requirements under Form 8-K relating to such information.
Copies of our Corporate Governance Guidelines, our Code of Business Ethics and our Audit Committee Charter are
available on our website at www.dcppartners.com. Copies of these items are also available free of charge in print to any
unitholder who sends a request to the office of the Secretary of DCP Midstream Partners, LP at 370 17th Street, Suite 2500,
Denver, Colorado 80202.
Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of the special committee, the committee, which consists of all of our independent directors,
meets in an executive session without management participation or participation by non-independent directors. The chairman of
the special committee, Stephen R. Springer, presides over these executive sessions. In addition, at each quarterly meeting of the
board of directors, the non-management members of the board meet in executive session. The chairman of the board of
directors has historically presided over these executive sessions, however, with Wouter T. van Kempen’s recent appointment as
chairman of the board, in the future Alan N. Harris will preside over these executive sessions since Mr. van Kempen is a
member of management.
Unitholders or interested parties may communicate with any and all members of our board, including our non-
management directors, or any committee of our board, by transmitting correspondence by mail or facsimile addressed to one or
more directors by name or to the chairman of the board or any committee of the board at the following address and fax number:
Name of the Director(s), c/o Secretary, DCP Midstream Partners, LP, 370 17th Street, Suite 2500, Denver, Colorado 80202, fax
number (303) 633-2921.
NYSE Annual Certification
On March 26, 2013, Wouter T. van Kempen, our Chief Executive Officer, certified to the NYSE, as required by NYSE
rules, that as of March 26, 2013, he was not aware of any violation by us of the NYSE’s Corporate Governance Listing
Standards.
Report of the Audit Committee
The audit committee oversees our financial reporting process on behalf of the board of directors. Management has the
primary responsibility for the financial statements and the reporting process including the systems of internal controls. The
audit committee operates under a written charter approved by the board of directors. The charter, among other things, provides
that the audit committee has authority to appoint, retain and oversee the independent auditor. In this context, the audit
committee:
•
•
•
reviewed and discussed the audited financial statements in this annual report on Form 10-K with management,
including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of
significant judgments and the clarity of disclosures in the financial statements;
reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion
on the conformity of those audited financial statements with generally accepted accounting principles, their
judgments as to the quality and acceptability of our accounting principles and such other matters as are required to
be discussed with the audit committee under generally accepted auditing standards;
received the written disclosures and the letter required by standard No. 1 of the independence standards board
(independence discussions with audit committees) provided to the audit committee by Deloitte & Touche, LLP;
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•
•
•
•
discussed with Deloitte & Touche, LLP its independence from management and us and considered the
compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence;
discussed with Deloitte & Touche, LLP the matters required to be discussed by statement on auditing standards
No. 16 (PCAOB Auditing Standard No. 16, Communications With Audit Committees, Related Amendments to
PCAOB Standards and Transitional Amendments to AU Section 380);
discussed with our internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective
audits. The audit committee meets with the internal auditors and Deloitte & Touche, LLP, with and without
management present, to discuss the results of their examinations, their evaluations of our internal controls and the
overall quality of our financial reporting;
based on the foregoing reviews and discussions, recommended to the board of directors that the audited financial
statements be included in the annual report on Form 10-K for the year ended December 31, 2013, for filing with
the Securities and Exchange Commission; and
•
approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors.
This report has been furnished by the members of the audit committee of the board of directors:
Audit Committee
Paul F. Ferguson, Jr. (Chairman)
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by
DCP Midstream Partners, LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to
the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such
acts.
Item 11. Executive Compensation
Compensation Discussion and Analysis
General
As a publicly traded limited partnership, we do not have directors, officers or employees. Instead, our operations are
managed by our general partner, DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream GP,
LLC, which we refer to as our General Partner. Our General Partner is a 100% owned subsidiary of DCP Midstream, LLC.
For the year ended December 31, 2013, the named executive officers, or NEOs, for our General Partner were Wouter T.
van Kempen, CEO (Principal Executive Officer), William S. Waldheim, President, Rose M. Robeson, former Senior Vice
President and CFO (former Principal Financial Officer), and Michael S. Richards, Vice President, General Counsel and
Secretary. Mr. van Kempen devoted less than 10% of his time to our operations and management in 2013 and we reimbursed
DCP Midstream, LLC less than $100,000 under our Services Agreement for these services. Mr. Waldheim and Ms. Robeson
devoted all of their time to our operations and management in 2013. Mr. Richards devoted more than 90% of his time to our
operations and management in 2013. The General Partner has not entered into employment agreements with any of the named
executive officers. The reimbursement for the compensation of executive officers devoting less than a majority of their time to
our operations and management is generally based on the percentage of time allocated to us during a period under the terms of
the Services Agreement.
We do not have a compensation committee. In 2013, the compensation committee of the board of directors of DCP
Midstream, LLC, the owner of our General Partner, reviewed all elements of compensation of our NEOs discussed below, but
the decisions with respect to determinations on payments were subject to approvals by the board of directors of our General
Partner. Unless otherwise specified, when we refer herein to the compensation committee, we are referring to the compensation
committee of DCP Midstream, LLC. When we refer herein to the board of directors, we are referring to the board of directors
of our General Partner.
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Compensation Decisions
For 2014, all compensation decisions concerning the officers and employees dedicated to our operations and management
will be made by the compensation committee except with regard to equity-based compensation, which is subject to approval by
the board of directors of our General Partner. The compensation committee’s responsibilities on compensation matters include
the following:
•
•
•
•
•
annually review the Partnership’s goals and objectives relevant to compensation of the NEOs;
annually evaluate the NEO’s performance in light of the Partnership’s goals and objectives, and approve the
compensation levels for the NEOs;
periodically evaluate the terms and administration of the Partnership’s short-term and long-term incentive plans to
assure that they are structured and administered in a manner consistent with the Partnership’s goals and objectives;
periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
retain and terminate any compensation consultant to be used to assist in the evaluation of director and NEO
compensation; and
•
periodically review the compensation of the non-employee directors.
Compensation Philosophy
Our compensation program is structured to provide the following benefits:
• attract, retain and reward talented executive officers and key management employees by providing total compensation
competitive with that of other executive officers;
• motivate executive officers and key management employees to achieve strong financial and operational performance;
• emphasize performance-based compensation, balancing short-term and long-term results; and
•
reward individual performance.
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Methodology - Advisors and Peer Companies
The board of directors, in 2013, and the compensation committee, in 2014, review data from market surveys provided by
independent consultants to assess our competitive position with respect to base salary, annual short-term incentives and long-
term incentive compensation. With respect to NEO compensation, the compensation committee also considers individual
performance, levels of responsibility, skills and experience. In 2012, we engaged the services of BDO USA, LLP, or BDO, a
compensation consultant, to conduct a study to assist us in establishing overall compensation packages for the NEOs for 2013.
We consider BDO to be independent of the Partnership and therefore, the work performed by BDO does not create a conflict of
interest. The BDO study was based on compensation as reported in the annual reports on Form 10-K for a group of peer
companies with a similar tax status, and the 2012 TowersWatson General Industry Executive Compensation Survey, or the
TowersWatson survey.
The study was comprised of the following peer companies:
Access Midstream Partners, L.P.
Atlas Pipeline Partners, L.P.
Boardwalk Pipeline Partners, L.P.
Buckeye Partners, L.P.
Copano Energy, L.L.C.
Crestwood Midstream Partners, L.P.
Crosstex Energy, L.P.
Eagle Rock Energy Partners, L.P.
Enbridge Energy Partners, L.P.
Enterprise Products Partners L.P.
Genesis Energy, L.P.
Inergy, L.P.
Kinder Morgan Energy Partners, L.P.
Magellan Midstream Partners, L.P.
MarkWest Energy Partners, L.P.
NuStar Energy L.P.
ONEOK Partners, L.P.
Penn Virginia Resource Partners, L.P.
Plains All American Pipeline, L.P.
Regency Energy Partners, L.P.
Spectra Energy Partners, L.P.
Sunoco Logistics Partners, L.P.
Targa Resources Partners, L.P.
Western Gas Partners, L.P.
Williams Partners, L.P.
Studies such as this generally include only the most highly compensated officers of each company, which correlates with
our General Partner’s NEOs. The results of this study, as well as other factors such as our targeted performance objectives and
the compensation packages of highly compensated officers of DCP Midstream, LLC, served as a benchmark for establishing
our total direct compensation packages. In order to assess the competitiveness of the total direct compensation packages for our
General Partner’s NEOs, we used the data point that represents the peer 25th percentile for peer positions from the BDO study
and the data point that represents the 50th percentile of the market in the TowersWatson survey.
Components of Compensation
The total annual direct compensation program for executives of the General Partner consists of three components: (1)
base salary; (2) an annual short-term cash incentive, or STI, which is based on a percentage of annual base salary; and (3) the
present value of an equity-based grant under our LTIP which is based on a percentage of annual base salary. Under our
compensation structure, the allocation between base salary, STI and LTIP varies depending upon job title and responsibility
levels. In 2013, this allocation for targeted compensation of our General Partner’s NEOs was as follows:
Wouter T. van Kempen, CEO (a)
William S. Waldheim, President
Rose M. Robeson, former Senior Vice President and
Chief Financial Officer, or CFO
Michael S. Richards, Vice President, General Counsel
and Secretary
Base Salary
N/A
35%
Targeted
STI Level
N/A
21%
Targeted
LTIP Level
N/A
44%
40%
44%
20%
20%
40%
36%
(a) Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the
Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement.
In allocating compensation among these components, we believe a significant portion of the compensation of the
executive officers should be performance-based since these individuals have a greater opportunity to influence our
166
performance. In making this allocation, we have relied in part on the BDO study of the companies named above. Each
component of compensation is further described below.
Base Salary - Base salaries for executives are determined based upon job responsibilities, level of experience, individual
performance, and comparisons to the salaries of executives in similar positions obtained from the BDO study. The goal of the
base salary component is to compensate executives at a level that approximates the median salaries of individuals in
comparable positions at comparably sized companies in our industry.
The base salaries for executives are generally reevaluated annually as part of our performance review process, or when
there is a change in the level of job responsibility. The board of directors annually considers and approves a merit increase in
base salary based upon the results of this performance review process. Merit increases are based on review of performance in
certain categories, including: business values, safety, health and environment, leadership, financial results, project results,
attitude, ability and knowledge. The board of directors approved increases in NEO base salaries for 2013 ranging from 3.0% to
3.9%. The base salaries earned by our NEOs, other than Mr. van Kempen, are set forth in the “Summary Compensation” table
below.
Annual Short-Term Cash Incentive - Under the STI, annual cash incentives are provided to executives to promote the
achievement of our performance objectives. Target incentive opportunities for executives under the STI are established as a
percentage of base salary. Incentive amounts are intended to provide total cash compensation at the market median for
executive officers in comparable positions when target performance is achieved, below the market median when performance is
less than target and above the market median when performance exceeds target. The BDO study was used to determine the
competitiveness of the incentive opportunity for comparable positions. STI payments are generally paid in cash in March of
each year for the prior fiscal year’s performance.
In 2013, the STI objectives were initially designed and proposed by our President, working with the Chairman of the
board of directors, with objectives that were both oriented towards the Partnership and oriented towards the DCP enterprise,
which includes both DCP Midstream, LLC, the owner of our General Partner, and the Partnership combined. These objectives
were intended to promote the achievement of performance objectives of the Partnership. Historically, the Partnership objectives
account for 75% - 80% of the award and the personal objectives account for 20% - 25% of the award. Personal objectives focus
on specific objectives to be targeted by each NEO for that particular calendar year. All proposed objectives were first reviewed
and revised by the compensation committee for the President and by the President for the other NEOs. The President’s
objectives in 2013 were subsequently reviewed and approved by the board of directors. The STI objectives approved by the
board of directors were divided as follows: (1) Partnership objectives accounted for 80% of the STI and (2) personal objectives
accounted for 20% of the STI. All STI objectives are subject to change each year. The target STI opportunities for 2013 as a
percentage of base salary were as follows:
Wouter T. van Kempen, CEO (a)
William S. Waldheim, President
Rose M. Robeson, former Senior Vice President and CFO
Michael S. Richards, Vice President, General Counsel and Secretary
2013 Targeted
STI
Opportunity
N/A
60%
50%
45%
(a) Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the
Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement. Mr. van Kempen did not
participate in the Partnership's STI for 2013.
167
For 2013, there were four stated Partnership objectives under the STI which accounted for 80% of the total STI. The
stated Partnership objectives for each NEO are described below and were weighted as indicated for each NEO.
1. Distributable Cash Flow in 2013 Budget. The achievement of our budget for distributable cash flow excluding any
one-time transactions and financing costs and results from any non-budgeted acquisitions or dropdowns. We define
distributable cash flow as net cash provided by or used in operating activities, less maintenance capital expenditures,
net of reimbursable projects, plus or minus adjustments for non-cash mark-to-market of derivative instruments,
proceeds from divestiture of assets, net income attributable to noncontrolling interest net of depreciation and income
tax, net changes in operating assets and liabilities, and other adjustments to reconcile net cash provided by or used in
operating activities. As a publicly traded limited partnership, our performance is generally judged on our ability to
pay cash distributions to our unitholders. We use distributable cash flow because we believe it permits management
to focus on the long-term sustainability and development of our assets. For this Partnership objective, the target level
of performance is distributable cash flow in the 2013 budget of $255 million; the maximum level of performance is
distributable cash flow in the 2013 budget of $300 million; and the minimum level of performance is distributable
cash flow in the 2013 budget of $210 million. This objective accounts for 40% of each NEO's total STI.
2. EBIT ROCE. An objective intended to capture the constant price EBIT (earnings before interest and taxes) ROCE
(return on capital employed) of DCP Midstream, LLC, the owner of our General Partner. For this objective, the target
level of performance is EBIT ROCE of 10.8%, the maximum level of performance is EBIT ROCE of 13.6% and the
minimum level of performance is EBIT ROCE of 8.1%. This objective accounts for 25% of each NEO's total STI.
3. Recordable Injury Rate (RIR). A safety objective covering both our assets and the assets of DCP Midstream, LLC, the
owner of our General Partner and the operator of our assets. For this objective, the target level of performance during
the year is an RIR of 0.52, the maximum level of performance is an RIR of 0.30 and a minimum level of performance
is an RIR of 0.90. This objective accounts for 10% of each NEO's total STI.
4. Title V Environmental Deviations. An environmental objective of non-routine air emissions, natural gas vented or
flared, covering both our assets and the assets of DCP Midstream, LLC, the owner of our General Partner and
operator of our assets. For this objective, we have established certain levels of emissions at the assets of DCP
Midstream, LLC and the Partnership that comprise the minimum, target and maximum level of performance for this
objective. This objective accounts for 5% of each NEO's total STI.
The payout on these Partnership objectives range from 0% if the minimum level of performance is not achieved, 50% if
the minimum level of performance is achieved, 100% if the target level of performance is achieved and 200% if the maximum
level of performance is achieved. When the performance level falls between these percentages, payout will be determined by
straight-line interpolation.
The level of performance achieved in 2013 for each of the Partnership objectives was as follows:
STI Partnership Objectives
1) Distributable Cash Flow
2) EBIT ROCE
3) Recordable Injury Rate (RIR)
4) Title V Environmental Deviations
Level of
Performance Achieved
Between Minimum and Target
Between Target and Maximum
Between Minimum and Target
Between Target and Maximum
For 2013, the NEO’s personal objectives under the STI accounted for 20% of the total STI. The personal objectives were
approved by the board of directors for the President, and by the President for the other NEOs. The personal objectives for all of
the NEOs were the same to drive consistency in partnership objectives. Each of the personal objectives for the NEOs and the
weighting of each personal objective are described below:
1) Enterprise Growth. Continue to execute on the 5-year enterprise growth plan. This objective accounts for 5% of each
NEO's total STI.
2) Capital Markets. Effectively manage and adjust financial strategies and tactics to balance growth and continued near-
term challenges in the industry fundamentals. This objective accounts for 5% of each NEO's total STI.
3) Safety & Environmental Leadership. Continue to drive the safety and environmental performance culture at the DCP
enterprise to an industry leading position. This objective accounts for 5% of each NEO's total STI.
168
4) Stakeholder Effectiveness. Ensure a seamless transition into a DCP enterprise management structure. This objective
accounts for 5% of each NEO's total STI.
The payout on the individual personal objectives ranged from 0% if the minimum level of performance is not achieved,
50% if the minimum level of performance is achieved, 100% if the target level of performance is achieved and 200% if the
maximum level of performance is achieved. When the performance level falls between these percentages, payout will be
determined by straight-line interpolation.
Early in 2014, management prepared a report on the achievement of the Partnership objectives and the personal
objectives. These results were reviewed and approved by the compensation committee in February 2014, including a
calculation of the percentage achievement of each objective for purposes of the STI program. The total payout for the executive
officers under the STI for fiscal year 2013 including both Partnership objectives and personal objectives was 120.5% of target.
Long-Term Incentive Plan - The LTIP has the objective of providing a focus on long-term value creation and enhancing
executive retention. Under our LTIP, we issued phantom limited partner units to each NEO, except Mr. van Kempen, under our
2005 Long Term Incentive Plan and our 2012 Long Term Incentive Plan. Half of such phantom units are performance phantom
units, or PPUs, and half are restricted phantom units, or RPUs. The PPUs will vest based upon the level of achievement of
certain performance objectives over a three-year performance period, or the Performance Period. The RPUs will automatically
vest if the executive officer remains employed at the end of a three-year vesting period, or the Vesting Period. We believe this
program promotes retention of the executive officers, and focuses the executive officers on the goal of long-term value creation.
For 2013, the PPUs had the following two performance measures: (1) total shareholder return, or TSR, over the
Performance Period relative to a peer group of 15 other similar publicly held master limited partnerships that we believe we
compete with in the capital markets, and (2) EBIT return on capital employed, or EBIT ROCE, over the performance period of
DCP Midstream, LLC, the owner of our General Partner. Half of the PPUs will be measured against the TSR performance
objective and half of the PPUs will be measured against the EBIT ROCE performance measure. These performance measures
were initially designed and proposed by the executive officers and presented to the Chairman of the board of directors. These
objectives were then considered and approved by the compensation committee and ultimately by the board of directors. The
board of directors believes utilizing TSR as a performance measure provides incentive for the continued growth of our
operating footprint and distributions to unitholders. The board of directors believes utilizing EBIT ROCE of DCP Midstream,
LLC aligns the performance of the executive officers with the success of the DCP enterprise. We believe these performance
measures provide management with appropriate incentives for our disciplined and steady growth.
For the 2013 TSR performance measure, the companies included in the peer group that will be compared against the
Partnership were the following:
Access Midstream Partners, L.P.
Atlas Pipeline Partners, L.P.
Copano Energy, L.L.C
Crestwood Midstream Partners, L.P.
Crosstex Energy, L.P.
Enbridge Energy Partners, L.P.
Energy Transfer Partners L.P.
Enterprise Products Partners L.P.
MarkWest Energy Partners, L.P.
ONEOK Partners, L.P.
PVR Partners, L.P.
Regency Energy Partners L.P.
Targa Resources Partners L.P.
Western Gas Partners, L.P.
Williams Partners L.P.
If our TSR ranking among the companies listed above over the Performance Period is below the 25th percentile, 0% - 50%
of the performance units will vest. If the TSR ranking over the Performance Period is greater than the 25th percentile but less
than or equal to the 50th percentile, 50% - 100% of the performance units will vest. If the TSR ranking over the Performance
Period is greater than the 50th percentile but less than or equal to the 75th percentile, 100% - 175% of the performance units will
vest. If the TSR ranking over the Performance Period is greater than the 75th percentile, 175% - 200% of the performance units
will vest. Final vesting within a performance quartile will be determined by the board of directors. TSR is computed by using
data obtained from Bloomberg for the peer group and will incorporate the average closing prices of the 20 trading days ending
on December 31, 2012 and December 31, 2015.
If one of these peer companies is not publicly traded at the end of the Performance Period it will remain a member of the
peer group for purposes of ranking the peer group total shareholder return but it will go to the bottom of the peer group ranking.
If there is a combination of any of the peer group companies during the Performance Period, the performance of the surviving
169
entity will be used. No new companies will be added to the peer group during the Performance Period (including a non-peer
company) that may acquire a member of the peer group.
For the EBIT ROCE performance measure, EBIT will be for DCP Midstream, LLC, the owner of our General Partner, as
reported in its financial statements. Capital employed will be determined each year during the annual budget process as
approved by the board of directors of DCP Midstream, LLC. The EBIT ROCE targets are reset each year and will be based on
the average of the three one-year periods running from 2013 through 2015. For this objective, the target level of performance
for 2013 was EBIT ROCE of 10.8%, the maximum level of performance is EBIT ROCE of 13.6% and the minimum level of
performance is EBIT ROCE of 8.1%.
These PPU and RPU awards were granted at the first regular meeting of the board of directors during the first quarter of
2013. The number of awards granted to our executive officers is set forth in the “Grants of Plan-Based Awards” table below.
Award recipients also received the right to receive dividend equivalent rights, or DERs, on the number of units earned during
the Vesting Period. The DERs on the PPUs will be paid in cash at the end of the Performance Period and the DERs on the RPUs
are paid quarterly in cash during the Vesting Period. The amount paid on the DERs will equal the quarterly distributions
actually paid on the underlying securities during the Performance Period and the Vesting Period on the number of PPUs earned
or RPUs granted.
Our practice is to determine the dollar amount of long-term incentive compensation that we want to provide, and to then
grant a number of PPUs and RPUs that have a fair market value equal to that amount on the date of grant, which is based on the
average closing prices of the underlying securities on the NYSE for the 20 trading days prior to the date of grant. Target long-
term incentive opportunities for executives under the plan are established as a percentage of base salary, using the BDO study
data for individuals in comparable positions.
The target 2013 long-term incentive opportunities, expressed as a percentage of base salary were as follows:
Wouter T. van Kempen, CEO (a)
William S. Waldheim, President
Rose M. Robeson, former Senior Vice President and CFO
Michael S. Richards, Vice President, General Counsel and
Secretary
Targeted
LTI
Opportunity
N/A
125%
100%
80%
(a) Mr. van Kempen worked less than 10% of his time on the operations and management of the Partnership and the
Partnership reimbursed DCP Midstream, LLC for his services under the Services Agreement. Mr. van Kempen did not
participate in the Partnership's LTIP for 2013.
In the event that any person other than DCP Midstream, LLC and/or an affiliate thereof becomes the beneficial owner of
more than 50% of the combined voting power of the General Partner’s equity interests prior to the completion of the
Performance Period, the PPUs, RPUs and related DERs will (i) be replaced with equivalent units of the new enterprise if there
is no change in the recipient’s job status for twelve months or (ii) fully vest if the recipient is severed or if the recipient’s job is
lower in status within twelve months of the change in control.
In the event an award recipient’s employment is terminated after the first anniversary of the grant date for reasons of
death, disability, early or normal retirement, or if the recipient is terminated by the General Partner for reasons other than cause,
the recipient’s (i) performance units will contingently vest on a pro rata basis for time worked over the Performance Period and
final performance, measured at the end of the Performance Period, will determine the payout and (ii) time vested units will
become fully vested and payable. Termination of employment for any other reason will result in the forfeiture of any unvested
units and unpaid DERs.
Other Compensation - In addition, executives are eligible to participate in other compensation programs, which include
but are not limited to:
Company Matching and Retirement Contributions to Defined Contribution Plans - Executives may elect to participate in
the DCP Midstream, LP 401(k) and Retirement Plan. Under the plan, executives may elect to defer up to 75% of their eligible
compensation, or up to the limits specified by the Internal Revenue Service. We match the first 6% of eligible compensation
contributed by the executive to the plan. In addition, we make retirement contributions ranging from 4% to 7% of the eligible
170
compensation of qualifying participants to the plan, based on years of service, up to the limits specified by the Internal Revenue
Service. We have no defined benefit plans.
Miscellaneous Compensation - Executive officers are eligible to participate in the DCP Midstream, LLC non-qualified
deferred compensation program. Executive officers are allowed to defer up to 75% of their base salary, up to 90% of their STI
and up to 100% of their LTIP or other compensation. Executive officers elect either to receive amounts contributed during
specific plan years as a lump sum at a specific date, subject to Internal Revenue Service rules, as an annuity (up to five years) at
a specific date, subject to Internal Revenue Service rules, or in a lump sum or annual annuity (over three to ten years) at
termination. The cost associated with executive officers' participation in the plan are reimbursed to DCP Midstream, LLC under
our Services Agreement.
Executive officers and other eligible employees may participate in a non-qualified, defined contribution retirement plan.
Benefits earned under this plan are attributable to compensation in excess of the annual compensation limits under section 401
(k) of the Internal Revenue Code. Under this plan, we make a contribution of up to 13% of eligible compensation, as defined by
the plan, to the DCP Midstream, LLC non-qualified deferred compensation program.
In addition, we provide employees, including the executive officers, with a variety of health and welfare benefit programs.
The health and welfare programs are intended to protect employees against catastrophic loss and promote well-being. These
programs include medical, pharmacy, dental, life insurance, and accidental death and disability. We also provide all employees
with a monthly parking pass or a pass to be used on available public transportation systems.
We are a partnership and not a corporation for U.S. federal income tax purposes, and therefore, are not subject to the
executive compensation tax deductible limitations of Internal Revenue Code §162(m). Accordingly, none of the compensation
paid to named executive officers is subject to the limitation.
Board of Directors Report
The board of directors of the General Partner has reviewed and discussed with management the “Compensation
Discussion and Analysis” presented above. Members of management with whom the board of directors had discussions are the
CEO and President of the General Partner and the Chief Corporate Officer of DCP Midstream, LLC. In addition, the board of
directors engaged the services of BDO USA, LLP, a compensation consultant, to conduct a study to assist us in establishing
overall compensation packages for the executives. Based on this review and discussion, we recommended that the
“Compensation Discussion and Analysis” referred to above be included in this annual report on Form 10-K for the year ended
December 31, 2013.
Board of Directors
Wouter T. van Kempen (Chairman)
Paul F. Ferguson, Jr.
R. Mark Fiedorek
Alan N. Harris
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
Andy Viens
William S. Waldheim
Brian R. Wenzel
171
Executive Compensation
The following tables disclose the compensation of the General Partner’s principal executive officers, principal financial
officer and named executive officers, or collectively, the “executive officers”, except for the CEO, Wouter van Kempen. Mr.
van Kempen devoted less than 10% of his time to our management and operations in 2013 and we reimbursed DCP Midstream
for his time under the Services Agreement. The amount of this reimbursement for 2013 was less than $100,000. Mr. van
Kempen is not included in these tables since he is reimbursed under the Services Agreement:
Name and Principal Position
William S. Waldheim (a)
President
Rose M. Robeson (b)
former Senior Vice President
and Chief Financial Officer
Michael S. Richards
Vice President, General
Counsel and Secretary
Year
2013
2012
2013
2012
2013
2012
2011
LTIP
Awards (c)
$ 492,880
$
$ 296,675
$
$
— $
$
— $
Non-Equity
Incentive Plan
Compensation
(d)
286,161
66,421
180,340
65,169
All Other
Compensation
(e)
182,839
16,543
112,398
21,736
$
$
$
$
Total
$ 1,357,841
201,425
$
888,856
$
267,241
$
Salary
$ 395,961
$ 118,461
$ 299,443
$ 180,336
$ 221,415
$ 213,074
$ 201,515
$ 176,164
$ 171,869
$ 163,020
$
$
$
120,013
79,039
116,220
$
$
$
89,291
187,639
108,672
$
$
$
606,883
651,621
589,427
(a) Mr. Waldheim’s employment with the General Partner commenced on September 1, 2012. The 2012 compensation
amounts represent the General Partner’s pro rata share of Mr. Waldheim’s salary, which was paid by DCP Midstream,
LLC, the owner of the General Partner, and participation in DCP Midstream, LLC’s STI program.
(b) Ms. Robeson’s employment with the General Partner commenced on May 11, 2012.
(c) The amounts in this column reflect the grant date fair value of LTIP awards in accordance with the provisions of the
FASB Accounting Standards Codification 718, Compensation - Stock Compensation, or ASC 718. PPU awards are
subject to performance conditions. For PPUs granted in 2013, 2012 and 2011, the performance conditions are
between 0% if the minimum level of performance is not achieved and 200% if the maximum level of performance is
achieved. The maximum value of the PPUs, based on the grant date fair value, for Mr. Waldheim was $490,097 for
units granted during 2013. The maximum value of the PPUs, based on the grant date fair value, for Ms. Robeson was
$293,892 for units granted during 2013. The maximum value of the PPUs, based on the grant date fair value, for Mr.
Richards was $175,236, $171,869 and $163,020 for units granted during 2013, 2012 and 2011, respectively.
(d) The amounts in this column were paid during the fiscal year, with the exception of $12,001 for Mr. Richards which
was payable during the year but was deferred at Mr. Richard's election.
(e) Includes DERs, company retirement and non-qualified deferred compensation program contributions by the
Partnership, the value of life insurance premiums paid by the Partnership on behalf of an executive and other
deminimus compensation, which are detailed below.
William S. Waldheim, President
The LTIP awards are comprised of PPUs and RPUs pursuant to the LTIP. Under the 2013 and 2012 STI, Mr. Waldheim’s
target opportunity was 60% of his annual base salary, with the possibility of earning from 0% to 120% of his annual base salary
in 2013 and 2012, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:
Company retirement contributions to defined contribution
plans
Non-qualified deferred compensation program contributions $
$
DERs
$
Life insurance premiums (a)
$
2013
33,150
122,812
23,081
3,796
$
$
$
$
2012
—
15,400
—
1,143
(a) Paid by the Partnership on behalf of Mr. Waldheim.
172
Rose M. Robeson, former Senior Vice President and CFO
The LTIP awards are comprised of PPUs and RPUs pursuant to the LTIP. Under the 2013 and 2012 STI, Ms. Robeson’s
target opportunity was 50% of her annual base salary, with the possibility of earning from 0% to 100% of her annual base
salary in 2013 and 2012, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:
Company retirement contributions to defined contribution
plans
Non-qualified deferred compensation program contributions $
$
DERs
$
Life insurance premiums (a)
$
28,050
68,955
13,891
1,502
$
$
$
$
2,604
18,163
—
969
2013
2012
(a) Paid by the Partnership on behalf of Ms. Robeson.
Michael S. Richards, Vice President, General Counsel and Secretary
The LTIP awards are comprised of PPUs and RPUs pursuant to the LTIP. Under the 2013, 2012 and 2011 STI, Mr.
Richards’ target opportunity was 45% of his annual base salary, with the possibility of earning from 0% to 90% of his annual
base salary in 2013, 2012 and 2011, depending on the level of performance in each of the STI objectives.
“All Other Compensation” includes the following:
Company retirement contributions to defined contribution
plans
Non-qualified deferred compensation program
contributions
DERs
Life insurance premiums (a)
$
$
$
$
(a) Paid by the Partnership on behalf of Mr. Richards.
2013
28,050
30,583
29,584
1,074
$
$
$
$
2012
27,500
2011
$ 26,950
122,933
$ 19,317
36,168
1,038
$ 61,431
974
$
Grants of Plan-Based Awards
Following are the grants of plan-based awards during the year ended December 31, 2013 for the General Partner’s
executive officers:
Estimated Future Payouts under
Non-Equity Incentive Plan Awards
(a)
Estimated Future Payouts under
Equity Incentive Plan Awards
Threshold
Target
Maximum Threshold
Target
Maximum
Grant
Date Fair
Value of
LTIP
Awards
Name
William S. Waldheim
PPUs
RPUs
Rose M. Robeson
PPUs
RPUs
Michael S. Richards
PPUs
RPUs
Grant
Date
NA
(b)
(c)
NA
(b)
(c)
NA
(b)
(c)
$
$
$
$
$
$
$
$
$
($)
($)
($)
(#)
(#)
(#)
($)
— $ 237,577
$ 475,153
— $
— $
— $
— $
—
—
— $ 149,722
$ 299,443
— $
— $
— $
— $
—
—
— $ 99,637
$ 199,274
— $
— $
—
—
— $
— $
173
—
—
5,910
—
—
3,570
—
—
2,110
—
5,850
5,910
—
3,510
3,570
—
2,090
2,110
— $
—
11,700
$ 245,048
5,910
$ 247,832
— $
—
7,020
$ 146,946
3,570
$ 149,729
— $
—
4,180
$ 87,618
2,110
$ 88,546
(a) Amounts shown represent amounts under the STI. If minimum levels of performance are not met, then the payout for
one or more of the components of the STI may be zero.
(b) The number of units shown represents units awarded under the LTIP. If minimum levels of performance are not met,
then the payout may be zero.
(c) The number of units shown represents units awarded under the LTIP and these units vest at the end of the Vesting
Period provided the individual is still employed by the Partnership.
The PPUs awarded on February 14, 2013 will vest in their entirety on December 31, 2015 if the specified performance
conditions are satisfied and the RPUs awarded on February 14, 2013 will vest in their entirety on December 31, 2015 if the
executive is still employed by the Partnership.
Outstanding Equity Awards at Fiscal Year-End
Following are the outstanding equity awards for the General Partner’s executive officers as of December 31, 2013:
Outstanding LTIP Awards
Equity Incentive
Plan Awards:
Unearned Units
That Have Not
Vested (a)
Equity Incentive
Plan Awards:
Market Value of
Unearned Units
That Have Not
Vested (b)
7,800
10,590
13,190
$
$
$
386,496
524,687
685,924
Name
William S. Waldheim
Rose M. Robeson
Michael S. Richards
(a) PPUs awarded February 14, 2013 and February 15, 2012; units vest in their entirety over a range of 0% to 200% on
December 31, 2015 and December 31, 2014, respectively, if the specified performance conditions are satisfied. RPUs
awarded February 14, 2013 and February 15, 2012, vest in their entirety on December 31, 2015 and December 31,
2014, respectively. To determine the number of unearned units and the market value, the calculation of the number of
PPU’s granted on February 14, 2013 and February 15, 2012, that are expected to vest, is based on assumed
performance of 200%, as the previous fiscal year performance has exceeded target performance.
(b) Value calculated based on the closing price at December 31, 2013 of our common units at $50.35, the closing price of
Spectra Energy’s common units at $35.62, and Phillips 66’s common units at $77.13.
Option Exercises and Units Vested
Following are the units vested for the General Partner’s executive officers for the year ended December 31, 2013:
Name
William S. Waldheim
Rose M. Robeson
Michael S. Richards
Stock Awards (a)
Number of Units
Acquired on
Vesting
Value Realized
on Vesting
5,910
$
— $
$
3,900
292,893
—
196,365
(a) Includes all awards that vested during the year, regardless of whether the awards will be settled in our common units,
Phillips 66 common units, Spectra Energy common units or cash.
Non-qualified Deferred Compensation
Following is the non-qualified deferred compensation for the General Partner’s executive officers for the year ended
December 31, 2013:
174
Name
Executive
Contributions in
Last Fiscal Year (a)
Registrant
Contributions in
Last Fiscal Year (b)
Aggregate
Earnings in Last
Fiscal Year (c)
Aggregate Balance
at December 31,
2013
William S. Waldheim $
Rose M. Robeson
Michael S. Richards
$
$
33,211
44,917
135,260
$
$
$
15,400
18,163
122,933
$
$
$
5,131
7,804
19,906
$
$
$
77,811
116,924
435,890
(a) These amounts are included in the “Summary Compensation” table for the year 2013 with the exception of $33,211
for Mr. Waldheim and $7,904 for Mr. Richards, which were included in the “Summary Compensation” table for the
year 2012 as they related to deferrals of 2012 STI, and $116,285 for Mr. Richards, which was included in the
“Summary Compensation” table for the year 2010 as it related to deferrals of 2010 PPU and RPU.
(b) These amounts are included in the “Summary Compensation” table for the year 2012.
(c) The performance of executive officers non-qualified deferred compensation is linked to certain mutual funds or to the
average rating of the BBB bond index at the election of the participant.
Potential Payments upon Termination or Change in Control
The General Partner has not entered into any employment agreements with any of the executive officers. There are no
formal severance plans in place for any employees in the event of termination of employment, or a change in control of the
Partnership. As noted above, the PPUs, RPUs and the related DERs, will become payable to executive officers under certain
circumstance related to termination or change in control. When employees terminate employment with the Partnership, they are
entitled to a cash payment for the amount of unused vacation hours at the date of their termination.
The following table presents PPUs, RPUs and DERs payable as of December 31, 2013 under certain circumstances,
following termination, or a change in control:
Triggering Event
William S. Waldheim
Change of Control (a)
Rose M. Robeson
Change of Control (a)
Michael S. Richards
Change of Control (a)
Termination (b)
PPUs
RPUs
DERs
Total
$
$
$
$
274,534
164,689
308,972
171,622
$
$
$
$
277,392
167,546
309,924
210,807
$
$
$
$
11,456
6,861
27,906
21,082
$
$
$
$
563,382
339,096
646,802
403,511
----
(a)
(b)
In the event that the recipient is severed or if the recipient’s job is lower in status within twelve months of the change
of control.
In the event of termination for reasons of death, disability, early or normal retirement, or if the recipient is terminated
by the General Partner for reasons other than cause, at least one year after the grant date.
Compensation of Directors
General - Members of the board of directors who are officers or employees of the General Partner or its affiliates do not
receive additional compensation for serving on the board. For 2013, the board approved an annual compensation package for
directors who are not officers or employees of the General Partner or its affiliates, or Non-Employee Directors, containing the
following: (1) a $40,000 retainer; (2) a board meeting fee of $1,250 for each board meeting attended; (3) a telephonic board of
$500 for each telephonic meeting attended; and (4) an annual grant of Phantom Units that approximate $50,000 of value,
awarded pursuant to the LTIP, that have a six month vesting period. The directors also receive DERs, based on the number of
units awarded, which are paid in cash on a quarterly basis. The Phantom Units will be paid in units upon vesting.
The board of directors reviews data from market surveys provided by BDO to assess the corporate position with respect the
director compensation, The BDO study was based on compensation as reported in the annual reports on Form 10-K for a group
of peer companies with a similar tax status, and the TowersWatson database.
175
The directors will also be reimbursed for out-of-pocket expenses associated with their membership on the board of
directors. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent
permitted under Delaware law.
Committees - The chairman of the audit committee of the board will receive an annual retainer of $20,000 and the members
of the audit committee will receive $1,500 for each audit committee meeting attended; telephonic or in-person. The chairman of
the special committee of the board will likewise receive an annual retainer of $20,000 and the members of the special
committee will receive $1,500 for each special committee meeting attended, telephonic or in person. Finally, the Non-
Employee Director members of the pricing committee will receive $500 for each telephonic and $1,000 for each in-person
pricing committee meeting attended.
Following is the compensation of the General Partner’s Non-Employee Directors for the year ended December 31, 2013:
Name
Paul F. Ferguson, Jr.
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
Fees Earned or
Paid in Cash
LTIP
Awards (a)
DERs
$
$
$
$
101,250
81,250
71,500
101,250
$
$
$
$
51,029
51,029
51,029
51,029
$
$
$
$
1,551
1,551
1,551
1,551
$
$
$
$
Total
153,830
133,830
124,080
153,830
a) The amounts in this column reflect the grant date fair value of LTIP awards in accordance with the provisions of ASC
718.
Mr. Ferguson is the audit committee chair and a member of the special committee.
Mr. McPherson is a member of the audit committee and the special committee.
Mr. Morris is a member of the audit committee and the special committee.
Mr. Springer is the special committee chair and a member of the audit committee.
Effective February 13, 2014, the board approved certain modifications to the annual compensation package for Non-
Employee Directors. The annual cash retainer was increased to $70,000 from the previous $40,000 and grants of the annual
equity retainer will approximate a value of $70,000 increased from the previous $50,000. Furthermore, the directors will no
longer receive additional fees for attending meetings of the board or its committees. Chairpersons of committees of the board
will continue to receive an additional annual cash retainer of $20,000.
Compensation Committee Interlocks and Insider Participation
As discussed above, our board of directors does not maintain a compensation committee. In 2013, the compensation
committee of the board of directors of DCP Midstream, LLC, the owner of our general partner, reviewed all elements of
compensation for our named executive officers, but the decisions with respect to determinations on payments thereof were
subject to approvals by our board of directors. In 2013, none of our directors, except for Mr. Waldheim, have been or are
officers or employees of us or our subsidiaries. Mr. Waldheim participates in deliberations of our board of directors with regard
to executive compensation generally, but does not participate in deliberations or board actions with respect to his own
compensation. None of our named executive officers served as a director or member of a compensation committee of another
entity that has or has had an executive officer who served as a member of our board of directors during 2013.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
176
The following table sets forth the beneficial ownership of our units and the related transactions held by:
•
•
•
•
each person who beneficially owns 5% or more of our outstanding units as of February 20, 2014;
all of the directors of DCP Midstream GP, LLC;
each Named Executive Officer of DCP Midstream GP, LLC; and
all directors and executive officers of DCP Midstream GP, LLC as a group.
Percentage of total common units beneficially owned is based on 89,045,139 common units outstanding.
Name of Beneficial Owner (a)
DCP LP Holdings, LLC (b)
Kayne Anderson Capital Advisors, L.P (c)
Tortoise Capital Advisors L.L.C. (d)
ClearBridge Investments, LLC (e)
Wouter T. van Kempen
William S. Waldheim
Sean P. O'Brien
Michael S. Richards
Paul F. Ferguson, Jr.
R. Mark Fiedorek
Alan N. Harris
Frank A. McPherson
Thomas C. Morris
Stephen R. Springer
Andy Viens
Brian R. Wenzel
All directors and executive officers as a group (12 persons)
Common
Units
Beneficially
Owned
18,824,638
10,536,793
7,146,769
6,114,059
Percentage of Common
Units
Beneficially
Owned
21.1%
11.8%
8.0%
6.9%
2,540
23,800
—
20,697
14,734
—
9,842
24,066
29,067
9,900
—
—
134,646
*
*
*
*
*
*
*
*
*
*
*
*
*
177
_____________
*Less than 1%.
(a) Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2500, Denver,
Colorado 80202.
(b) DCP Midstream, LLC is the managing member of DCP LP Holdings, LLC and may, therefore, be deemed to indirectly
beneficially own the units held by DCP LP Holdings, LLC. DCP Midstream, LLC disclaims beneficial ownership of all of
the units owned by DCP LP Holdings, LP except to the extent of its pecuniary interest therein. The address of DCP LP
Holdings, LLC and DCP Midstream, LLC is 370 17th Street, Suite 2500, Denver, Colorado 80202.
(c) As set forth in a Schedule 13G filed on February 12, 2014. The address of Kayne Anderson Capital Advisors, L.P. is 1800
Avenue of the Stars, Third Floor, Los Angeles, California 90067.
(d) As set forth in a Schedule 13G filed on February 10, 2014. The address of Tortoise Capital Advisors L.L.C. is 11550 Ash
Street, Suite 300, Leawood, Kansas 66211.
(e) As set forth in a Schedule 13G filed on February 4, 2014. The address of ClearBridge Investments, LLC is 620 8th Avenue
New York, New York 10018
Equity Compensation Plan Information
The following table summarizes information about our equity compensation plan as of December 31, 2013.
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights (1)
Weighted-
average exercise
price of
outstanding
options,
warrants and
rights
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
(a)
(b)
(c)
Equity compensation plans approved by unitholders
Equity compensation plans not approved by unitholders
Total
$
$
— $
—
— $
— $
—
— $
—
738,501
738,501
(1) The long-term incentive plan currently permits the grant of awards covering an aggregate of 850,000 units. For more
information on our long-term incentive plan, which did not require approval by our limited partners, refer to Item 11.
“Executive Compensation-Components of Compensation.”
Item 13. Certain Relationships and Related Transactions, and Director Independence
Distributions and Payments to our General Partner and its Affiliates
The following table summarizes the distributions and payments to be made by us to our General Partner and its affiliates
in connection with our formation, ongoing operation, and liquidation. These distributions and payments are determined by and
among affiliated entities and, consequently, are not the result of arm’s-length negations.
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Operational Stage:
Distributions of Available Cash to our General Partner
and its affiliates
Payments to our General Partner and
its affiliates
Withdrawal or removal of our General Partner
Liquidation Stage:
Liquidation
Services Agreement
We will generally make cash distributions to the unitholders and to our
General Partner, in accordance with their pro rata interest. In addition, if
distributions exceed the minimum quarterly distribution and other higher
target levels, our General Partner will be entitled to increasing percentages of
the distributions, up to 48% of the distributions above the highest target
level. Currently, our distribution to our general partner related to its incentive
distribution rights is at the highest level.
In 2013, we reimbursed DCP Midstream, LLC and its affiliates $29 million
under the Services Agreement. For further information regarding the
reimbursement, please see the “Services Agreement” section below. We also
reimburse DCP Midstream, LLC and its affiliates for general and
administrative expenses in connection with the Eagle Ford system. Please
see the “Other Agreements and Transactions with DCP Midstream, LLC”
section below.
If our General Partner withdraws or is removed, its general partner interest
and its incentive distribution rights will either be sold to the new general
partner for cash or converted into common units, in each case for an amount
equal to the fair market value of those interests.
Upon our liquidation, the partners, including our General Partner, will be
entitled to receive liquidating distributions according to their respective
capital account balances.
The employees supporting our operations are employees of DCP Midstream. We have entered into a services agreement,
as amended, or the Services Agreement, with DCP Midstream, LLC. Under the Services Agreement, we are required to
reimburse DCP Midstream, LLC for salaries of operating personnel and employee benefits, as well as capital expenditures,
maintenance and repair costs, taxes and other direct costs incurred by DCP Midstream, LLC on our behalf. We also pay DCP
Midstream, LLC an annual fee under the Services Agreement for centralized corporate functions performed by DCP
Midstream, LLC on our behalf, including legal, accounting, cash management, insurance administration and claims processing,
risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and
engineering. Except with respect to the annual fee, there is no limit on the reimbursements we make to DCP Midstream, LLC
under the Services Agreement for other expenses and expenditures incurred or payments made on our behalf. Pursuant to the
Services Agreement, we will reimburse DCP Midstream, LLC for expenses and expenditures incurred or payments made on our
behalf.
The Services Agreement fee is subject to adjustment based on the scope of general and administrative services performed
by DCP Midstream, LLC.
Our General Partner and its affiliates will also receive payments from us pursuant to the contractual arrangements
described below under the caption “Contracts with Affiliates.”
Any or all of the provisions of the Services Agreement, other than the indemnification provisions, will be terminable by
DCP Midstream, LLC at its option if our general partner is removed without cause and units held by our general partner and its
affiliates are not voted in favor of that removal. The Services Agreement will also terminate in the event of a change of control
of us, our general partner (DCP Midstream GP, LP) or our General Partner (DCP Midstream GP, LLC).
Competition
None of DCP Midstream, LLC or any of its affiliates, including Phillips 66 and Spectra Energy, is restricted, under either
our partnership agreement or the Services Agreement, from competing with us. DCP Midstream, LLC and any of its affiliates,
including Phillips 66 and Spectra Energy, may acquire, construct or dispose of additional midstream energy or other assets in
the future without any obligation to offer us the opportunity to purchase or construct those assets.
Contracts with Affiliates
We charge transportation fees, sell a portion of our residue gas and NGLs to, and purchase natural gas and NGLs from,
DCP Midstream, LLC, Phillips 66 and their respective affiliates. Management anticipates continuing to purchase and sell these
commodities to DCP Midstream, LLC, Phillips 66 and their respective affiliates in the ordinary course of business.
179
Natural Gas Gathering and Processing Arrangements
We sell NGLs processed at certain of our plants, and sell condensate removed from the gas gathering systems that deliver
to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal to that subsidiary’s net weighted-
average sales price, adjusted for transportation, processing and other charges from the tailgate of the respective asset.
Please read Item 1. “Business - Natural Gas Services Segment - Customers and Contracts” and Note 4 of the Notes to
Consolidated Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
Merchant Arrangements
Under our merchant arrangements, we use a subsidiary of DCP Midstream, LLC (DCP Midstream Marketing, LP) as our
agent to purchase natural gas from third parties at pipeline interconnect points, as well as residue gas from certain of our
processing plants, and then resell the aggregated natural gas primarily to third parties. DCP Midstream, LLC owns certain
assets and is party to certain contractual relationships around our Pelico system, included in our Northern Louisiana system,
that are periodically used for the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and
deliver it to us and is able to take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We
purchase natural gas from DCP Midstream, LLC upstream of Pelico and transport it to Pelico under a firm transportation
agreement with an affiliate. Our purchases from DCP Midstream, LLC are at DCP Midstream LLC’s actual acquisition cost
plus any transportation service charges. Volumes that exceed our on-system demand are sold to DCP Midstream, LLC at an
index-based price, less contractually agreed to marketing fees. Please read Note 4 of the Notes to Consolidated Financial
Statements in Item 8. “Financial Statements and Supplementary Data.”
Transportation Arrangements
We also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that provides that DCP Midstream,
LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-based rates that will be applied
to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under the transportation agreements.
The Wattenberg pipeline, which is part of our NGL Logistics segment, has in place a 10-year dedication and
transportation agreement with a subsidiary of DCP Midstream, LLC whereby certain NGL volumes produced at several of DCP
Midstream, LLC’s processing facilities are dedicated for transportation on the Wattenberg pipeline. We collect fee-based
transportation revenues under our tariff.
DCP Midstream, LLC historically is also the largest shipper on the Black Lake pipeline, primarily due to the NGLs
delivered to it from certain of our processing plants.
Derivative Arrangements
We have entered into a short term NGL swap contracts with DCP Midstream, LLC whereby we receive a fixed price for
NGLs and we pay a floating price. For more information regarding our derivative activities and credit support provided by DCP
Midstream, LLC, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations -
Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk - Commodity Cash Flow Protection
Activities” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and
Capital Resources.”
Other Agreements and Transactions with DCP Midstream, LLC
DCP Midstream, LLC was a significant customer during the years ended December 31, 2013, 2012 and 2011. We sell a
portion of our residue gas, NGLs and condensate to, purchase natural gas and other petroleum products from, and provide
gathering and transportation services for, DCP Midstream, LLC. We anticipate continuing to purchase from and sell
commodities and services to DCP Midstream, LLC in the ordinary course of business. In addition, DCP Midstream, LLC
conducts derivative activities on our behalf. We have and may continue to enter into derivative transactions directly with DCP
Midstream, LLC, whereby DCP Midstream, LLC is the counterparty.
We have a contractual arrangement with DCP Midstream, LLC, through March 2022, in which we pay DCP Midstream,
LLC a fee for processing services associated with the gas we gather on our Southern Oklahoma system, which is part of our
Natural Gas Services segment. In addition, we have an agreement with DCP Midstream, LLC providing for adjustments to
those fees based upon plant efficiencies related to our portion of volumes from the Southern Oklahoma system being processed
at DCP Midstream, LLC’s plant through March 2022. We generally report fees associated with these activities in the
consolidated statements of operations as purchases of natural gas, propane and NGLs from affiliates. In addition, as part of this
180
arrangement, DCP Midstream, LLC pays us a fee for certain gathering services. We generally report revenues associated with
these activities in the consolidated statements of operations as transportation, processing and other to affiliates.
DCP Midstream, LLC owns certain assets and is party to certain contractual relationships around our Pelico system,
included in our Northern Louisiana system, which is part of our Natural Gas Services segment, that are periodically used for
the benefit of Pelico. DCP Midstream, LLC is able to source natural gas upstream of Pelico and deliver it to us and is able to
take natural gas from the outlet of the Pelico system and market it downstream of Pelico. We purchase natural gas from DCP
Midstream, LLC upstream of Pelico and transport it to Pelico under an interruptible transportation agreement with an affiliate.
Our purchases from DCP Midstream, LLC are at DCP Midstream, LLC’s actual acquisition cost plus any transportation service
charges. Volumes that exceed our on-system demand are sold to DCP Midstream, LLC at an index-based price, less
contractually agreed upon marketing fees. Revenues associated with these activities are reported gross in our consolidated
statements of operations as sales of natural gas, propane, NGLs and condensate to affiliates.
In our Natural Gas Services segment, we sell NGLs processed at certain of our plants, and sell condensate removed from
the gas gathering systems that deliver to certain of our systems under contracts to a subsidiary of DCP Midstream, LLC equal
to that subsidiary’s net weighted-average sales price, adjusted for transportation, processing and other charges from the tailgate
of the respective asset.
In conjunction with our acquisitions of our East Texas and Southeast Texas systems, which are part of our Natural Gas
Services segment, we entered into agreements with DCP Midstream, LLC whereby DCP Midstream, LLC will reimburse us for
certain expenditures on East Texas and Southeast Texas capital projects. These reimbursements are for specific capital projects
which have commenced within three years from the respective acquisition dates. DCP Midstream, LLC made capital
contributions to East Texas for capital projects of $1 million, $5 million and $18 million for the years ended December 31,
2013, 2012, and 2011 respectively. DCP Midstream, LLC made capital contributions to Southeast Texas for capital projects of
$5 million for the year ended December 31, 2012. We made a distribution to DCP Midstream, LLC related to capital projects at
Southeast Texas of $3 million for the year ended December 31, 2013.
In conjunction with our acquisition of the O'Connor plant, we entered into a 15-year fee-based processing agreement with
an affiliate of DCP Midstream, LLC pursuant to which such affiliate agreed to pay us (i) a fixed demand charge of 75% of the
plant's capacity, and (ii) a throughput fee on all volumes processed for such affiliate at the O'Connor plant. We received fees of
$6 million during the year ended December 31, 2013, which are included in transportation, processing and other to affiliates in
the consolidated statements of operations.
As a result of a downstream outage, certain of our assets were required to curtail NGL production during 2012. DCP
Midstream, LLC has reimbursed us for the impact of the curtailment and accordingly, we recorded $3 million to sales of natural
gas, propane, NGLs and condensate to affiliates and less than $1 million to transportation, processing and other to affiliates in
the consolidated statements of operations for the year ended December 31, 2012.
During the year ended December 31, 2011, East Texas received $8 million in business interruption recoveries related to
the first quarter 2009 fire that was caused by a third party underground pipeline rupture outside of our property, or the East
Texas recovery settlement. We have allocated the recoveries based upon relative ownership percentages at the time the losses
were incurred, factoring in amounts previously reimbursed to us by DCP Midstream, LLC. For the year ended December 31,
2011, we recorded $7 million to sales of natural gas, propane, NGLs and condensate, with $5 million representing DCP
Midstream, LLC’s portion recorded in net income attributable to noncontrolling interests, in the consolidated statement of
operations.
In our NGL Logistics segment, we also have a contractual arrangement with a subsidiary of DCP Midstream, LLC that
provides that DCP Midstream, LLC will pay us to transport NGLs over our Seabreeze and Wilbreeze pipelines, pursuant to fee-
based rates that will be applied to the volumes transported. DCP Midstream, LLC is the sole shipper on these pipelines under
the transportation agreements. We generally report revenues associated with these activities in the consolidated statements of
operations as transportation, processing and other to affiliates.
The Texas Express Pipeline has in place a long-term, fee-based, ship-or-pay transportation agreement with DCP
Midstream, LLC of 20 MBbls/d.
181
The Wattenberg pipeline has in place a 10-year dedication and transportation agreement with a subsidiary of DCP
Midstream, LLC whereby certain NGL volumes produced at several of DCP Midstream, LLC’s processing facilities are
dedicated for transportation on the Wattenberg pipeline. We collect fee-based transportation revenues under our tariff. We
generally report revenues associated with these activities in the consolidated statements of operations as transportation,
processing and other to affiliates.
We pay a fee to DCP Midstream, LLC to operate our DJ Basin NGL fractionators and receive fees for the processing of
DCP Midstream, LLC’s committed NGLs produced by them in Colorado at our DJ Basin NGL fractionators under agreements
that are effective through March 2018. We incurred fees of $1 million and less than $1 million during the years ended
December 31, 2013 and 2012, respectively, which are included in operating and maintenance expense in the consolidated
statements of operations.
Review, Approval or Ratification of Transactions with Related Persons
Our partnership agreement contains specific provisions that address potential conflicts of interest between the owner of
our general partner and its affiliates, including DCP Midstream, LLC on one hand, and us and our subsidiaries, on the other
hand. Whenever such a conflict of interest arises, our general partner will resolve the conflict. Our general partner may, but is
not required to, seek the approval of such resolution from the special committee of the board of directors of our general partner,
which is comprised of independent directors and acts as our conflicts committee. The partnership agreement provides that our
general partner will not be in breach of its obligations under the partnership agreement or its duties to us or to our unitholders if
the resolution of the conflict is:
•
•
•
•
approved by the conflicts committee;
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our
general partner or any of its affiliates;
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
fair and reasonable to us, taking into account the totality of the relationships between the parties involved,
including other transactions that may be particularly favorable or advantageous to us.
If our general partner does not seek approval from the special committee and the board of directors of our general partner
determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set
forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors
acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing
or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is
specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors
it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in
good faith, it requires that person to reasonably believe that he is acting in the best interests of the Partnership, unless the
context otherwise requires.
In addition, our code of business ethics requires that all employees, including employees of affiliates of DCP Midstream,
LLC who perform services for us and our general partner, avoid or disclose any activity that may interfere, or have the
appearance of interfering, with their responsibilities to us.
Director Independence
Please see Item 10. “Directors, Executive Officers and Corporate Governance” for information about the independence of
our general partner’s board of directors and its committees, which information is incorporated herein by reference in its
entirety.
182
Item 14. Principal Accountant Fees and Services
The following table presents fees for professional services rendered by Deloitte & Touche LLP, or Deloitte, our principal
accountant, for the audit of our financial statements, and the fees billed for other services rendered by Deloitte:
Type of Fees
Audit Fees (a)
Year Ended December 31,
2013
2012
$
(Millions)
2 $
2
(a) Audit Fees are fees billed by Deloitte for professional services for the audit of our consolidated financial statements
included in our annual report on Form 10-K and review of financial statements included in our quarterly reports on
Form 10-Q, services that are normally provided by Deloitte in connection with statutory and regulatory filings or
engagements or any other service performed by Deloitte to comply with generally accepted auditing standards and
include comfort and consent letters in connection with Securities and Exchange Commission filings and financing
transactions.
For the last two fiscal years, Deloitte has not billed us for assurance and related services, unless such services were
reasonably related to the performance of the audit or review of our financial statements, and are included in the table above.
Deloitte has not provided any services to us over the last two fiscal years related to tax compliance, tax services and tax
planning.
Audit Committee Pre-Approval Policy
The audit committee pre-approves all audit and permissible non-audit services provided by the independent auditors on a
case-by-case basis. These services may include audit services, audit-related services, tax services and other services. The audit
committee does not delegate its responsibilities to pre-approve services performed by the independent auditor to management
or to an individual member of the audit committee. The audit committee has, however, pre-approved audit related services that
do not impair the independence of the independent auditors for up to $50,000 per engagement, and up to an aggregate of
$200,000 annually, provided the audit committee is notified of such audit-related services in a timely manner. The audit
committee may, however, from time to time delegate its authority to any audit committee member, who will report on the
independent auditor services that were approved at the next audit committee meeting.
Item 15. Exhibits and Financial Statement Schedules
(a) Financial Statement Schedules
PART IV
Other schedules are omitted because they are not required or because the required information is included in the
Consolidated Financial Statements or Notes.
(b) Exhibits
Exhibit
Number
1.1
*
2.1
*
2.2
*
2.3
*
Description
Equity Distribution Agreement, dated November 8, 2013, among DCP Midstream Partners, LP, DCP
Midstream GP, LP, DCP Midstream GP, LLC, and Citigroup Global Markets Inc., Merrill Lynch, Pierce,
Fenner & Smith Incorporated, and Credit Suisse Securities (USA) LLC (filed as Exhibit 1.1 to DCP
Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
November 8, 2013).
Purchase and Sale Agreement (O'Connor Plant) by and between DCP Midstream Partners, LP and DCP
Midstream, LP dated August 5, 2013 (attached as Exhibit 2.1 to DCP Midstream Partners, LP's Current
Report on Form 8-K (File No. 001-32678) filed with the SEC on August 6, 2013).
Contribution Agreement, dated October 9, 2006, between DCP LP Holdings, LP and DCP Midstream
Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on October 13, 2006).
Purchase and Sale Agreement (Front Range Pipeline) by and among DCP Midstream Partners, LP and DCP
Midstream, LP dated August 5, 2013 (attached as Exhibit 2.2 to DCP Midstream Partners, LP's Current
Report on Form 8-K (File No. 001-32678) filed with the SEC on August 6, 2013).
183
2.4
*
2.5
*
2.6
*
2.7
*
2.8
*
2.9
*
2.10
*
2.11
*
2.12
*
2.13
*
2.14
*
2.15
*
2.16
*
2.17
*
2.18
*
3.1 *
3.2 *
3.3
*
3.4 *
3.5 *
Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko
Energy Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream
Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc.,
DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream
Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP
Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
Contribution Agreement dated February 24, 2009, among DCP LP Holdings, LLC, DCP Midstream GP, LP
DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 10.16 to DCP Midstream
Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
Purchase and Sale Agreement by and Among DCP Midstream, LLC and DCP Midstream Partners, LP dated
as of November 4, 2010 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form
8-K (File No. 001-32678) filed with the SEC on November 8, 2010).
Contribution Agreement between DCP Southeast Texas, LLC and DCP Partners SE Texas LLC dated as of
November 4, 2010 (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on November 8, 2010).
Contribution Agreement, dated November 4, 2011, among DCP LP Holdings, LLC, DCP Midstream GP,
LP, DCP Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.7 to DCP Midstream,
LLC’s Schedule 13D (File No. 005-81287) dated as of January 13, 2012).
Contribution Agreement, dated February 27, 2012, among DCP LP Holdings, LLC, DCP Midstream, LLC
and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on March 1, 2012).
First Amendment to Contribution Agreement, dated March 30, 2012, among DCP LP Holdings, LLC, DCP
Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 4, 2012).
Contribution Agreement among DCP LP Holdings, LLC, DCP Midstream, LLC and DCP Midstream
Partners, LP dated June 25, 2012 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on June 29, 2012).
Contribution Agreement, dated November 2, 2012, among DCP LP Holdings, LLC, DCP Midstream GP,
LP, DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream
Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2012).
Contribution Agreement dated February 27, 2013 among DCP LP Holdings, LLC, DCP Midstream, LLC
and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on February 27, 2013).
First Amendment to Contribution Agreement, dated March 28, 2013, among DCP LP Holdings, LLC, DCP
Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 3, 2013).
Contribution Agreement, dated February 25, 2014, among DCP LP Holdings, LLC, DCP Midstream GP,
LP, DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream
Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 26, 2014).
Purchase and Sale Agreement, dated February 25, 2014, among DCP Midstream, LP, and DCP Midstream
Partners, LP (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on February 26, 2014).
Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated
December 7, 2005, as amended by Amendment No. 1 dated January 20, 2009 (attached as Exhibit 3.1 to
DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on
March 5, 2009).
Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP,
LLC dated February 14, 2013 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on February 21, 2013).
Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP,
LLC dated November 6, 2013 (attached as Exhibit 3.3 to DCP Midstream Partners, LP’s Quarterly Report
on Form 10-Q (File No. 001-32678) filed with the SEC on November 6, 2013).
First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP dated December
7, 2005 (attached as Exhibit 3.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on December 12, 2005).
Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated
November 1, 2006 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on November 7, 2006).
184
3.6 *
3.7 *
4.1
*
4.2
*
4.3
*
4.4
*
4.5
*
4.6
*
4.7
*
10.1
*
10.2
*
10.3
*
10.4
* +
10.5
* +
10.6
* +
10.7
* +
Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated April 1, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
Indenture dated as of September 30, 2010 for the issuance of debt securities between DCP Midstream
Operating, LP, as issuer, any Guarantors party thereto and The Bank of New York Mellon Trust Company,
N.A., as trustee (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on September 30, 2010).
First Supplemental Indenture dated as of September 30, 2010 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank
of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
Second Supplemental Indenture dated as of March 13, 2012 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank
of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on March 13, 2012).
Third Supplemental Indenture dated as of June 14, 2012 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank
of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June 14, 2012).
LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit
4.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC
on June 14, 2012).
Fourth Supplemental Indenture dated as of November 27, 2012 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank
of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.3 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 27, 2012).
Registration Rights Agreement by and among DCP Midstream Partners, LP and the purchasers named
therein dated July 2, 2012 (attached as Exhibit 4.1 to DCP Midstream Partners LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on July 9, 2012).
Fifth Supplemental Indenture dated as of March 14, 2013 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank
of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.3 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on March 14, 2013).
First Amendment to Services Agreement by and between DCP Midstream Partners, LP and DCP
Midstream, LP dated August 5, 2013 (attached as Exhibit 10.1 to DCP Midstream Partners, LP's Current
Report on Form 8-K (File No. 001-32678) filed with the SEC on August 6, 2013).
Omnibus Agreement, dated December 7, 2005, among Duke Energy Field Services, LLC, DCP Midstream
GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.4 to
DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
December 12, 2005).
Form of Commercial Paper Dealer Agreement among DCP Midstream Operating, LP, DCP Midstream
Partners, LP, and the Dealer party thereto (attached as Exhibit 10.1 to DCP Midstream Partners, LP's
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on October 29, 2013).
DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.2 to DCP Midstream
Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12,
2005).
Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP Long-Term
Incentive Plan (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Registration Statement on Form
S-8 (File No. 001-32678) filed with the SEC on April 20, 2007).
Form of Performance Phantom Unit Grant Agreement and DERs Grant for Officers/Employees under the
DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.1 to DCP Midstream
Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 24, 2011).
Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream Partners, LP Long-Term
Incentive Plan (attached as Exhibit 10.5 to DCP Midstream Partners, LP’s Annual Report on Form 10-K
(File No. 001-32678) filed with the SEC on March 1, 2011).
185
10.8
*
10.9
*
10.10
*
10.11
*
10.12
*
10.13
*
10.14
*
10.15
*
10.16
*
10.17
*
10.18
*
10.19
* +
+
10.20
*
10.21
10.22
* +
+
* +
+
Contribution, Conveyance and Assumption Agreement, dated December 7, 2005, among DCP Midstream
Partners, LP, DCP Midstream Operating LP, DCP Midstream GP, LLC, DCP Midstream GP, LP, Duke
Energy Field Services, LLC, DEFS Holding 1, LLC, DEFS Holding, LLC, DCP Assets Holdings, LP, DCP
Assets Holdings, GP, LLC, Duke Energy Guadalupe Pipeline Holdings, Inc., Duke Energy NGL Services,
LP, DCP LP Holdings, LP and DCP Black Lake Holdings, LLC (attached as Exhibit 10.3 to DCP
Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
December 12, 2005).
First Amendment to Omnibus Agreement, dated April 1, 2006, among Duke Energy Field Services, LLC,
DCP Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as
Exhibit 10.6 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed
with the SEC on August 11, 2006).
Second Amendment to Omnibus Agreement, dated November 1, 2006, among Duke Energy Field Services,
LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream
Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on November 7, 2006).
Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC (f/k/a Duke
Energy Field Services, LLC), DCP Midstream GP, LLC, DCP Midstream Partners, LP, DCP Midstream GP,
LP, and DCP Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s Current
Report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP,
DCP Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached
as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 10-Q (File No. 001-32678) filed
with the SEC on November 9, 2010).
Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC f/k/a/
Duke Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream
Partners, LP, and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated
July 1, 2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP
Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 2,
2007).
Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q
(File No. 001-32678) filed with the SEC on August 9, 2007).
Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on September 5, 2007).
Second Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC,
dated April 1, 2009 between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.2
to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
April 7, 2009).
Tenth Amendment to Omnibus Agreement, dated December 3, 2009, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream
Operating, LP (attached as Exhibit 10.25 to DCP Midstream Partners, LP’s Annual Report on Form 10-K
(File No. 001-32678) filed with the SEC on March 11, 2010).
Amended and Restated General Partnership Agreement of DCP Southeast Texas Holdings, GP, dated as of
January 1, 2011, by and among DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP
Partners SE Texas LLC (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form
8-K (File No. 001-32678) filed with the SEC on January 6, 2011).
Twelfth Amendment to Omnibus Agreement, dated January 1, 2011, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.19 to DCP Midstream Partners, LP’s Annual Report on Form 10-K
(File No. 001-32678) filed with the SEC on March 1, 2011).
Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective
May 1, 2008 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Periodic Report (File No.
001-32678) on Form 10-Q filed August 8, 2008.
Amendment dated June 15, 2010 to Propane Sales Contract between Spectra Energy Propane LLC and Gas
Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s
Periodic Report (File No. 001-32678) on Form 10-Q filed August 9, 2010.
186
10.23
*
10.24
*
10.25
*
10.26
* +
+
10.27
*
10.28
* +
10.29
* +
10.30
* +
10.31
* +
10.32
*
10.33
*
10.34
*
10.35
*
10.36
*
10.37
*
10.38
*
10.39
*
First Amendment to Amended and Restated General Partnership Agreement of DCP Southeast Texas, LLC,
Gas Supply Resources Holdings, Inc. and DCP Partners SE Texas, LLC (attached as
Exhibit 10.22 DCP Midstream, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 1,
2011).
Thirteenth Amendment to Omnibus Agreement, dated January 3, 2012, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on January 6, 2012).
Term Loan Agreement, dated January 3, 2012, among DCP Midstream Operating, LP, DCP Midstream
Partners, LP and Wells Fargo, National Association as Administrative Agent (attached as Exhibit 10.2 to
DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
January 6, 2012).
Gas Processing Contract between DCP Midstream, LP and DCP Midstream Partners, LP dated as of August
1, 2011 (attached as Exhibit 10.4 to DCP Midstream Partners LP’s Quarterly Report on Form 10-Q (File
No. 001-32678) filed with the SEC on November 9, 2011).
Credit Agreement, dated November 10, 2011, among DCP Midstream Operating, LP, DCP
Midstream Partners, LP and Wells Fargo, National Association as Administrative Agent (attached as Exhibit
10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the
SEC on November 14, 2011).
DCP Midstream Partners, LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.26 to DCP Midstream
Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29,
2012).
Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP 2012 Long-
Term Incentive Plan (attached as Exhibit 10.27 to DCP Midstream Partners, LP’s Annual Report on Form
10-K (File No. 001-32678) filed with the SEC on February 29, 2012).
Form of Performance Phantom Unit Grant Agreement and DERs Grant for Officers/Employees under the
DCP Midstream Partners, LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.28 to DCP Midstream
Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29,
2012).
Form of Restricted Phantom Unit Grant Agreement and DERs Grant under the DCP Midstream Partners,
LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.29 to DCP Midstream Partners, LP’s Annual
Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29, 2012).
Fourteenth Amendment to Omnibus Agreement, dated March 30, 2012, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream
Operating, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on April 5, 2012).
Fifteenth Amendment to the Omnibus Agreement by and among DCP Midstream, LLC, DCP Midstream
GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream Operating, LP dated
July 2, 2012 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on July 9, 2012).
Term Loan Agreement by and among DCP Midstream Operating, LP, DCP Midstream Partners, LP and
SunTrust Bank as Administrative Agent dated July 2, 2012 (attached as Exhibit 10.2 to DCP Midstream
Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 9, 2012).
First Amendment to Term Loan Agreement, dated November 1, 2012, among DCP Midstream Partners, LP,
DCP Midstream Operating, LP, SunTrust Bank, as administrative agent, and the lenders named therein
(attached as Exhibit 10.2 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on November 7, 2012).
Common Unit Purchase Agreement by and among DCP Midstream Partners, LP and the purchasers named
therein dated June 25, 2012 (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on June 29, 2012).
Term Loan Agreement by and among DCP Midstream Operating, LP, DCP Midstream Partners, LP and
SunTrust Bank as Administrative Agent dated November 1, 2012 (attached as Exhibit 10.3 to DCP
Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
November 7, 2012).
Amended and Restated General Partnership Agreement of DCP SC Texas GP, dated November 2, 2012, by
and among DCP LP Holdings, LLC, DCP SC Texas Holdings LLC, and DCP South Central Texas Holdings
LLC (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on November 7, 2012).
Services Agreement, dated as of February 14, 2013, among DCP Midstream Partners, LP and DCP
Midstream, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on February 21, 2013).
187
10.40
*
Employee Secondment Agreement, dated as of February 14, 2013, among DCP Midstream Partners, LP and
DCP Midstream, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-
K (File No. 001-32678) filed with the SEC on February 21, 2013).
12.1
Ratio of Earnings to Fixed Charges.
21.1
23.1
24.1
31.1
31.2
32.1
32.2
101
List of Subsidiaries of DCP Midstream Partners, LP.
Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream Partners, LP
and the effectiveness of DCP Midstream Partners, LP's internal control over financial reporting.
Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
Financial statements from the Annual Report on Form 10-K of DCP Midstream Partners, LP for the annual
period ended December 31, 2013, formatted in XBRL: (i) the Consolidated Balance Sheets, (ii) the
Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv)
the Consolidated Statements of Cash Flows, (v) the Consolidated Statements of Changes in Equity, and (vi)
the Notes to the Consolidated Financial Statements.
* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
+ Denotes management contract or compensatory plan or arrangement.
++ Confidential treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed
separately with the SEC.
188
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on
February 26, 2014.
DCP Midstream Partners, LP
By:
By:
By:
DCP Midstream GP, LP
its General Partner
DCP Midstream GP, LLC
its General Partner
/s/ Wouter T. van Kempen
Name:
Title:
Wouter T. van Kempen
Chief Executive Officer
(Principal Executive Officer)
189
Exhibit
Number
*
1.1
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12
2.13
2.14
*
*
*
*
*
*
*
*
*
*
*
*
*
*
EXHIBIT INDEX
Description
Equity Distribution Agreement, dated November 8, 2013, among DCP Midstream Partners, LP, DCP Midstream
GP, LP, DCP Midstream GP, LLC, and Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith
Incorporated, and Credit Suisse Securities (USA) LLC (filed as Exhibit 1.1 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 8, 2013).
Purchase and Sale Agreement (O'Connor Plant) by and between DCP Midstream Partners, LP and DCP
Midstream, LP dated August 5, 2013 (attached as Exhibit 2.1 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on August 6, 2013).
Contribution Agreement, dated October 9, 2006, between DCP LP Holdings, LP and DCP Midstream Partners, LP
(attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on October 13, 2006).
Purchase and Sale Agreement (Front Range Pipeline) by and among DCP Midstream Partners, LP and DCP
Midstream, LP dated August 5, 2013 (attached as Exhibit 2.2 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on August 6, 2013).
Purchase and Sale Agreement, dated March 7, 2007, between Anadarko Gathering Company, Anadarko Energy
Services Company and DCP Midstream Partners, LP (attached as Exhibit 99.1 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 14, 2007).
Contribution and Sale Agreement, dated May 21, 2007, between Gas Supply Resources Holdings, Inc., DCP
Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
Contribution Agreement, dated May 23, 2007, among DCP LP Holdings, LP, DCP Midstream, LLC, DCP
Midstream GP, LP and DCP Midstream Partners, LP (attached as Exhibit 10.1 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on May 25, 2007).
Contribution Agreement dated February 24, 2009, among DCP LP Holdings, LLC, DCP Midstream GP, LP DCP
Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 10.16 to DCP Midstream Partners, LP’s
Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
Purchase and Sale Agreement by and Among DCP Midstream, LLC and DCP Midstream Partners, LP dated as of
November 4, 2010 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on November 8, 2010).
Contribution Agreement between DCP Southeast Texas, LLC and DCP Partners SE Texas LLC dated as of
November 4, 2010 (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on November 8, 2010).
Contribution Agreement, dated November 4, 2011, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCP
Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 10.7 to DCP Midstream, LLC’s Schedule
13D (File No. 005-81287) dated as of January 13, 2012).
Contribution Agreement, dated February 27, 2012, among DCP LP Holdings, LLC, DCP Midstream, LLC and
DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form
8-K (File No. 001-32678) filed with the SEC on March 1, 2012).
First Amendment to Contribution Agreement, dated March 30, 2012, among DCP LP Holdings, LLC, DCP
Midstream, LLC and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 4, 2012).
Contribution Agreement among DCP LP Holdings, LLC, DCP Midstream, LLC and DCP Midstream Partners, LP
dated June 25, 2012 (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on June 29, 2012).
Contribution Agreement, dated November 2, 2012, among DCP LP Holdings, LLC, DCP Midstream GP, LP, DCP
Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2012).
190
2.15
2.16
2.17
2.18
3.1
3.2
3.3
3.4
3.5
3.6
3.7
4.1
4.2
4.3
4.4
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
Contribution Agreement dated February 27, 2013 among DCP LP Holdings, LLC, DCP Midstream, LLC and
DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners, LP’s Current Report on Form
8-K (File No. 001-32678) filed with the SEC on February 27, 2013).
First Amendment to Contribution Agreement, dated March 28, 2013, among DCP LP Holdings, LLC, DCP
Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 3, 2013).
Contribution Agreement, dated February 25, 2014, among DCP LP Holdings, LLC, DCP Midstream GP, LP,
DCP Midstream, LLC, and DCP Midstream Partners, LP (attached as Exhibit 2.1 to DCP Midstream
Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 26, 2014).
Purchase and Sale Agreement, dated February 25, 2014, among DCP Midstream, LP, and DCP Midstream
Partners, LP (attached as Exhibit 2.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on February 26, 2014).
Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC dated December 7,
2005, as amended by Amendment No. 1 dated January 20, 2009 (attached as Exhibit 3.1 to DCP Midstream
Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on March 5, 2009).
Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC
dated February 14, 2013 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on February 21, 2013).
Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of DCP Midstream GP, LLC
dated November 6, 2013 (attached as Exhibit 3.3 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-
Q (File No. 001-32678) filed with the SEC on November 6, 2013).
First Amended and Restated Agreement of Limited Partnership of DCP Midstream GP, LP dated December 7,
2005 (attached as Exhibit 3.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on December 12, 2005).
Second Amended and Restated Agreement of Limited Partnership of DCP Midstream Partners, LP dated
November 1, 2006 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on November 7, 2006).
Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated April 11, 2008 (attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008).
Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated April 1, 2009 (attached as Exhibit 3.1 to DCP Midstream Partners, LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
Indenture dated as of September 30, 2010 for the issuance of debt securities between DCP Midstream Operating,
LP, as issuer, any Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A., as trustee
(attached as Exhibit 4.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed
with the SEC on September 30, 2010).
First Supplemental Indenture dated as of September 30, 2010 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of
New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on September 30, 2010).
Second Supplemental Indenture dated as of March 13, 2012 to Indenture dated as of September 30, 2010 between
DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York
Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on March 13, 2012).
Third Supplemental Indenture dated as of June 14, 2012 to Indenture dated as of September 30, 2010 between
DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York
Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on June 14, 2012).
LP, as guarantor, and the Bank of New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.2 to
DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June 14,
2012).
191
4.5
4.6
4.7
10.1
10.2
10.3
*
*
*
*
*
*
10.4
* +
10.5
* +
Fourth Supplemental Indenture dated as of November 27, 2012 to Indenture dated as of September 30, 2010
between DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of
New York Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 27, 2012).
Registration Rights Agreement by and among DCP Midstream Partners, LP and the purchasers named therein
dated July 2, 2012 (attached as Exhibit 4.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on July 9, 2012).
Fifth Supplemental Indenture dated as of March 14, 2013 to Indenture dated as of September 30, 2010 between
DCP Midstream Operating, LP, as issuer, DCP Midstream Partners, LP, as guarantor, and the Bank of New York
Mellon Trust Company, N.A., as trustee (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Current Report
on Form 8-K (File No. 001-32678) filed with the SEC on March 14, 2013).
First Amendment to Services Agreement by and between DCP Midstream Partners, LP and DCP Midstream, LP
dated August 5, 2013 (attached as Exhibit 10.1 to DCP Midstream Partners, LP's Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on August 6, 2013).
Omnibus Agreement, dated December 7, 2005, among Duke Energy Field Services, LLC, DCP Midstream GP,
LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.4 to DCP
Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12,
2005).
Form of Commercial Paper Dealer Agreement among DCP Midstream Operating, LP, DCP Midstream Partners,
LP, and the Dealer party thereto (attached as Exhibit 10.1 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on October 29, 2013).
DCP Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.2 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP Long-Term
Incentive Plan (attached as Exhibit 4.3 to DCP Midstream Partners, LP’s Registration Statement on Form S-8
(File No. 001-32678) filed with the SEC on April 20, 2007).
10.6
* +
Form of Performance Phantom Unit Grant Agreement and DERs Grant for Officers/Employees under the DCP
Midstream Partners, LP Long-Term Incentive Plan (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on February 24, 2011).
10.7
* +
Form of Restricted Phantom Unit Grant Agreement under the DCP Midstream Partners, LP Long-Term Incentive
Plan (attached as Exhibit 10.5 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No.
001-32678) filed with the SEC on March 1, 2011).
10.8
*
10.9
*
10.10
*
10.11
*
10.12
*
Contribution, Conveyance and Assumption Agreement, dated December 7, 2005, among DCP Midstream
Partners, LP, DCP Midstream Operating LP, DCP Midstream GP, LLC, DCP Midstream GP, LP, Duke Energy
Field Services, LLC, DEFS Holding 1, LLC, DEFS Holding, LLC, DCP Assets Holdings, LP, DCP Assets
Holdings, GP, LLC, Duke Energy Guadalupe Pipeline Holdings, Inc., Duke Energy NGL Services, LP, DCP LP
Holdings, LP and DCP Black Lake Holdings, LLC (attached as Exhibit 10.3 to DCP Midstream Partners, LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on December 12, 2005).
First Amendment to Omnibus Agreement, dated April 1, 2006, among Duke Energy Field Services, LLC, DCP
Midstream GP, LLC, DCP Midstream Partners, LP and DCP Midstream Operating, LP (attached as Exhibit 10.6
to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with the SEC on
August 11, 2006).
Second Amendment to Omnibus Agreement, dated November 1, 2006, among Duke Energy Field Services, LLC,
DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream Operating,
LP (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on November 7, 2006).
Third Amendment to Omnibus Agreement, dated May 9, 2007, among DCP Midstream, LLC (f/k/a Duke Energy
Field Services, LLC), DCP Midstream GP, LLC, DCP Midstream Partners, LP, DCP Midstream GP, LP, and DCP
Midstream Operating, LP (attached as Exhibit 99.3 to DCP Midstream Partners LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on May 14, 2007).
Amended and Restated Credit Agreement, dated June 21, 2007, among DCP Midstream Operating, LP, DCP
Midstream Partners, LP and Wachovia Bank, National Association as Administrative Agent (attached as
Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 10-Q (File No. 001-32678) filed with the
SEC on November 9, 2010).
192
10.13
*
10.14
10.15
*
*
10.16
*
10.17
10.18
*
*
Fourth Amendment to Omnibus Agreement, dated July 1, 2007, by and among DCP Midstream, LLC f/k/a/ Duke
Energy Field Services, LLC, DCP Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP,
and DCP Midstream Operating, LP (attached as Exhibit 10.2 to DCP Midstream Partners LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated July 1,
2007, between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.3 to DCP Midstream
Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 2, 2007).
Fifth Amendment to Omnibus Agreement dated August 7, 2007, among DCP Midstream, LLC, DCP Midstream
GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP (attached as
Exhibit 10.1 to DCP Midstream Partners, LP’s Quarterly Report on Form 10-Q (File No. 001-32678) filed with
the SEC on August 9, 2007).
Sixth Amendment to Omnibus Agreement, dated August 29, 2007, among DCP Midstream, LLC, DCP Midstream
GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP (attached
as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the
SEC on September 5, 2007).
Second Amended and Restated Limited Liability Company Agreement of DCP East Texas Holdings, LLC, dated
April 1, 2009 between DCP Midstream, LLC and DCP Assets Holding, LP (attached as Exhibit 10.2 to DCP
Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 7, 2009).
Tenth Amendment to Omnibus Agreement, dated December 3, 2009, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LLC, and DCP Midstream Operating, LP
(attached as Exhibit 10.25 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678)
filed with the SEC on March 11, 2010).
10.19
* ++ Amended and Restated General Partnership Agreement of DCP Southeast Texas Holdings, GP, dated as of
January 1, 2011, by and among DCP Southeast Texas, LLC, Gas Supply Resources Holdings, Inc. and DCP
Partners SE Texas LLC (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K
(File No. 001-32678) filed with the SEC on January 6, 2011).
10.20
*
Twelfth Amendment to Omnibus Agreement, dated January 1, 2011, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP
(attached as Exhibit 10.19 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File No. 001-32678)
filed with the SEC on March 1, 2011).
10.21
* ++
Propane Sales Contract between Spectra Energy Propane LLC and Gas Supply Resources LLC effective May 1,
2008 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Periodic Report (File No. 001-32678) on Form
10-Q filed August 8, 2008.
10.22
* ++ Amendment dated June 15, 2010 to Propane Sales Contract between Spectra Energy Propane LLC and Gas
Supply Resources LLC effective May 1, 2008 (attached as Exhibit 10.2 to DCP Midstream Partners, LP’s
Periodic Report (File No. 001-32678) on Form 10-Q filed August 9, 2010.
10.23
10.24
*
*
First Amendment to Amended and Restated General Partnership Agreement of DCP Southeast Texas, LLC, Gas
Supply Resources Holdings, Inc. and DCP Partners SE Texas, LLC (attached as
Exhibit 10.22 DCP Midstream, LP’s Form 10-K (File No. 001-32678) filed with the SEC on March 1, 2011).
Thirteenth Amendment to Omnibus Agreement, dated January 3, 2012, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP
(attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on January 6, 2012).
10.25
*
Term Loan Agreement, dated January 3, 2012, among DCP Midstream Operating, LP, DCP Midstream Partners,
LP and Wells Fargo, National Association as Administrative Agent (attached as Exhibit 10.2 to DCP Midstream
Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2012).
10.26
* ++ Gas Processing Contract between DCP Midstream, LP and DCP Midstream Partners, LP dated as of August 1,
2011 (attached as Exhibit 10.4 to DCP Midstream Partners LP’s Quarterly Report on Form 10-Q (File No.
001-32678) filed with the SEC on November 9, 2011).
193
10.27
*
Credit Agreement, dated November 10, 2011, among DCP Midstream Operating, LP, DCP
Midstream Partners, LP and Wells Fargo, National Association as Administrative Agent (attached as Exhibit 10.1
to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
November 14, 2011).
10.28
* +
DCP Midstream Partners, LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.26 to DCP Midstream
Partners, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29, 2012).
10.29
* +
Form of Phantom Unit and DERs Grant for Directors under the DCP Midstream Partners, LP 2012 Long-Term
Incentive Plan (attached as Exhibit 10.27 to DCP Midstream Partners, LP’s Annual Report on Form 10-K (File
No. 001-32678) filed with the SEC on February 29, 2012).
10.30
* +
Form of Performance Phantom Unit Grant Agreement and DERs Grant for Officers/Employees under the DCP
Midstream Partners, LP 2012 Long-Term Incentive Plan (attached as Exhibit 10.28 to DCP Midstream Partners,
LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 29, 2012).
10.31
* +
Form of Restricted Phantom Unit Grant Agreement and DERs Grant under the DCP Midstream Partners, LP 2012
Long-Term Incentive Plan (attached as Exhibit 10.29 to DCP Midstream Partners, LP’s Annual Report on Form
10-K (File No. 001-32678) filed with the SEC on February 29, 2012).
10.32
*
10.33
*
Fourteenth Amendment to Omnibus Agreement, dated March 30, 2012, among DCP Midstream, LLC, DCP
Midstream GP, LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP, and DCP Midstream Operating, LP
(attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on April 5, 2012).
Fifteenth Amendment to the Omnibus Agreement by and among DCP Midstream, LLC, DCP Midstream GP,
LLC, DCP Midstream GP, LP, DCP Midstream Partners, LP and DCP Midstream Operating, LP dated July 2,
2012 (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on July 9, 2012).
10.34
10.35
10.36
10.37
10.38
10.39
10.40
12.1
21.1
23.1
*
*
*
*
*
*
*
Term Loan Agreement by and among DCP Midstream Operating, LP, DCP Midstream Partners, LP and SunTrust
Bank as Administrative Agent dated July 2, 2012 (attached as Exhibit 10.2 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on July 9, 2012).
First Amendment to Term Loan Agreement, dated November 1, 2012, among DCP Midstream Partners, LP, DCP
Midstream Operating, LP, SunTrust Bank, as administrative agent, and the lenders named therein (attached as
Exhibit 10.2 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678) filed with the
SEC on November 7, 2012).
Common Unit Purchase Agreement by and among DCP Midstream Partners, LP and the purchasers named therein
dated June 25, 2012 (attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File
No. 001-32678) filed with the SEC on June 29, 2012).
Term Loan Agreement by and among DCP Midstream Operating, LP, DCP Midstream Partners, LP and SunTrust
Bank as Administrative Agent dated November 1, 2012 (attached as Exhibit 10.3 to DCP Midstream Partners LP’s
Current Report on Form 8-K (File No. 001-32678) filed with the SEC on November 7, 2012).
Amended and Restated General Partnership Agreement of DCP SC Texas GP, dated November 2, 2012, by and
among DCP LP Holdings, LLC, DCP SC Texas Holdings LLC, and DCP South Central Texas Holdings LLC
(attached as Exhibit 10.1 to DCP Midstream Partners LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on November 7, 2012).
Services Agreement, dated as of February 14, 2013, among DCP Midstream Partners, LP and DCP Midstream, LP
(attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on February 21, 2013).
Employee Secondment Agreement, dated as of February 14, 2013, among DCP Midstream Partners, LP and DCP
Midstream, LP (attached as Exhibit 10.1 to DCP Midstream Partners, LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on February 21, 2013).
Ratio of Earnings to Fixed Charges.
List of Subsidiaries of DCP Midstream Partners, LP.
Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream Partners, LP and the
effectiveness of DCP Midstream Partners, LP's internal control over financial reporting.
194
24.1
31.1
31.2
32.1
32.2
101
Power of Attorney (incorporated by reference to the signature page of this Annual Report on Form 10-K).
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
Financial statements from the Annual Report on Form 10-K of DCP Midstream Partners, LP for the annual
period ended December 31, 2013, formatted in XBRL: (i) the Consolidated Balance Sheets, (ii) the
Consolidated Statements of Operations, (iii) the Consolidated Statements of Comprehensive Income, (iv)
the Consolidated Statements of Cash Flows, (v) the Consolidated Statements of Changes in Equity, and (vi)
the Notes to the Consolidated Financial Statements.
________
* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
+ Denotes management contract or compensatory plan or arrangement.
++ Confidential treatment has been requested with respect to portions of the exhibit. Such portions have been redacted and filed
separately with the SEC.
195
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS that each person whose signature appears below constitutes and appoints
each of Wouter T. van Kempen and Sean P. O'Brien as his/her true and lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him or in his name, place, and stead, in any and all capacities, to sign any and all
amendments (including post-effective amendments) to this annual report, and to file the same, with all exhibits thereto, and
other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact
and agent full power and authority to do and perform each and every act and thing requisite and necessary to be done in
connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all
that said attorney-in-fact and agent or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following
persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Wouter T. van Kempen
Wouter T. van Kempen
/s/ William S. Waldheim
William S. Waldheim
/s/ Sean P. O'Brien
Sean P. O'Brien
/s/ Gary D. Watkins
Gary D. Watkins
/s/ Paul F. Ferguson, Jr.
Paul F. Ferguson, Jr.
/s/ R. Mark Fiedorek
R. Mark Fiedorek
/s/ Alan N. Harris
Alan N. Harris
/s/ Frank A. McPherson
Frank A. McPherson
/s/ Thomas C. Morris
Thomas C. Morris
/s/ Stephen R. Springer
Stephen R. Springer
/s/ Andy Viens
Andy Viens
/s/ Brian R. Wenzel
Brian R. Wenzel
Chief Executive Officer,
Chairman of the Board and Director
(Principal Executive Officer)
February 26, 2014
President and Director
February 26, 2014
Group Vice President and Chief Financial Officer
(Principal Financial Officer)
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
February 26, 2014
Chief Accounting Officer
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
Director
Director
196
Forward-Looking Statements
This annual report may contain or
incorporate by reference forward-looking
statements as defined under the federal
securities laws regarding DCP Midstream
Partners, LP, including projections,
estimates, forecasts, plans, and objectives.
Although management believes that
expectations reflected in such forward-
looking statements are reasonable,
no assurance can be given that such
expectations will prove to be correct. In
addition, these statements are subject
to certain risks, uncertainties, and other
assumptions that are difficult to predict
and may be beyond our control. If one
or more of these risks or uncertainties
materialize, or if underlying assumptions
prove incorrect, the Partnership’s actual
results may vary materially from what
management anticipated, estimated,
projected, or expected.
Investors are encouraged to closely
consider the disclosures and risk factors
contained in the Partnership’s annual
and quarterly reports filed from time to
time with the Securities and Exchange
Commission. The Partnership undertakes
no obligation to update or revise any
forward-looking statements, whether as a
result of new information, future events, or
otherwise. Information contained in this
annual report is unaudited, and is subject
to change.
Publicly Traded Partnership
Attributes
DCP Midstream Partners, LP is a publicly
traded partnership, which operates in the
following distinct ways from a publicly
traded stock corporation:
Unitholders own limited partnership
(cid:2)
units instead of shares of common stock
and receive cash distributions rather than
dividends.
A partnership is generally not a taxable
(cid:2)
entity and does not pay federal and
state income tax, as does a corporation.
Partnerships flow through all of the
annual income, gains, losses, deductions,
or credits to unitholders, who are
required to show their allocated share
of these amounts on their income tax
returns, as though these items were
incurred directly.
DCP Midstream Partners provides each
(cid:2)
unitholder owning units for any portion
of the year a Schedule K-1 tax package
that includes each unitholder’s allocated
share of reportable Partnership items and
other Partnership information necessary
to be included in tax returns. This
compares with a corporate stock-holder,
who receives a Form 1099 annually
detailing required tax data.
Corporate Governance
DCP Midstream Partners, LP’s employees
and board of directors are committed
to conducting our business ethically
and in compliance with all laws and
regulations. Our Code of Business Ethics
serves as our core foundation on which
we base our decision-making. We have
established procedures for contacting
the non-management members of the
DCP Midstream Partners’ board of
directors. Any interested party may
report complaints about accounting,
auditing matters, or any other matter to
any member of our board of directors by
writing:
Name of Board Member or Committee
DCP Midstream Partners, LP
370 17th Street
Suite 2500
Denver, CO 80202
Corporate Headquarters
370 17th Street
Suite 2500
Denver, CO 80202
(303) 633-2900
Investor Relations
Andrea Attel
370 17th Street
Suite 2500
Denver, CO 80202
(303) 605-1741
arattel@dcpmidstream.com
Stock Exchange
DCP Midstream Partners, LP’s common
units are listed on the New York Stock
Exchange under the symbol DPM.
Website
www.dcppartners.com
Independent Auditors
Deloitte & Touche LLP
555 17th Street
Suite 3600
Denver, CO 80202
Transfer Agent and Registrar
For registered unitholders, communication
regarding name and address changes,
lost certificates, and other administrative
matters should be directed to:
American Stock Transfer
& Trust Company, LLC
Attn: Operations Center
6201 15th Avenue
Brooklyn, NY 11219
(800) 937-5449
Info@amstock.com
Cash Distributions
DCP Midstream Partners, LP pays a
quarterly cash distribution, which as
of the quarter ended December 31, 2013
was $0.7325 per limited partnership unit,
or $2.93 annualized. This distribution
was paid February 14, 2014. Future
2014 distributions are expected to be
paid on or about May 15, August 15,
and November 14.
Tax Information/ K-1 Inquiries:
Unitholder Schedule K-1 inquiries
should be directed to our toll-free
support line at (800) 230-7199,
or to the Partnership’s K-1 website:
www.taxpackagesupport.com/
dcpmidstream
dcppartners.com
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