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, 2017
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, 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) 595-3331
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class:
Common Units Representing Limited Partner Interests
Name of Each Exchange on Which Registered:
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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the
Exchange Act. (Check one):
Large accelerated filer
Non-accelerated filer
Emerging Growth Company
(Do not check if a smaller reporting company)
Accelerated filer
Smaller reporting company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
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, 2017, was approximately $3,060,364,000. 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 30, 2017.
As of February 22, 2018, there were 143,309,828 common units representing limited partner interests outstanding.
DOCUMENTS INCORPORATED BY REFERENCE:
None.
DCP MIDSTREAM, LP
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2017
TABLE OF CONTENTS
Item
1. Business
1A. Risk Factors
1B. Unresolved Staff Comments
2. Properties
3. Legal Proceedings
4. Mine Safety Disclosures
PART I
PART II
5. Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
6. Selected Financial Data
7. Management's Discussion and Analysis of Financial Condition and Results of Operations
7A. Quantitative and Qualitative Disclosures about Market Risk
8. Financial Statements and Supplementary Data
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
9A. Controls and Procedures
9B. Other Information
10. Directors, Executive Officers and Corporate Governance
11. 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
PART IV
15. Exhibits and Financial Statement Schedules
16. Form 10-K Summary
Signatures
Page
1
19
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50
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86
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168
200
201
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, but not limited to, 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 commodity prices through derivative financial instruments, and the
potential impact of price, and of producers’ access to capital on natural gas drilling, demand for our services, and the volume
of NGLs and condensate extracted;
the demand for crude oil, residue gas and NGL products;
the level and success of drilling and quality of production volumes around our assets and our ability to connect supplies to
our gathering and processing systems, as well as our residue gas and NGL infrastructure;
volatility in the price of our common units;
general economic, market and business conditions;
our ability to continue the safe and reliable operation of our assets;
our ability to construct and start up 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;
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
credit agreement and the indentures governing our notes, as well as our ability to maintain our credit ratings;
the creditworthiness of our customers and the counterparties to our transactions;
the amount of collateral we may be required to post from time to time in our transactions;
industry changes, including the impact of bankruptcies, consolidations, alternative energy sources, technological advances
and changes in competition;
our ability to grow through organic growth projects, or acquisitions, and the successful integration and future performance
of such assets;
our ability to hire, train, and retain qualified personnel and key management to execute our business strategy;
new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety and protection of the
environment, including, but not limited to, 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;
• weather, weather-related conditions and other natural phenomena, including, but not limited to, 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;
our ability to obtain insurance on commercially reasonable terms, if at all, as well as the adequacy of insurance to cover our
losses; and
the amount of natural gas we gather, compress, treat, process, transport, store and sell, or the NGLs we produce, fractionate,
transport, store and sell, 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 natural gas or NGLs.
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, except as required by applicable securities laws.
iii
Item 1. Business
OVERVIEW
PART I
DCP Midstream, LP (together with its consolidated subsidiaries, “we”, “our”, “us”, the “registrant”, or the “Partnership”)
is a Delaware limited Partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified
portfolio of complementary midstream energy assets. DCP Midstream, LLC and its subsidiaries and affiliates, collectively
referred to as DCP Midstream, LLC is owned 50% by Phillips 66 and 50% by Enbridge Inc. and its affiliates, or Enbridge.
The diagram below depicts our organizational structure as of December 31, 2017.
Our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing.
Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and
fractionating NGLs, and recovering condensate. Our Logistics and Marketing segment includes transporting, trading,
marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our
business operations are presented as “Other,” and consist of unallocated corporate costs.
1
OUR BUSINESS STRATEGY
Our primary business objectives are to achieve sustained company profitability, a strong balance sheet and profitable
growth, thereby sustaining and ultimately growing our cash distribution per unit. We intend to accomplish these objectives by
prudently executing the following business strategies:
Operational Performance. We believe our operating efficiency and reliability enhance our ability to attract new
natural gas supplies by enabling us to offer more competitive terms, services and service flexibility to producers. Our gathering
and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient
operations. Our goal is to establish a reputation in the midstream industry as a reliable, safe and low cost supplier of services to
our customers. We will continue to pursue new contracts, cost efficiencies and operating improvements of our assets through
process and technology improvements. We seek to increase the utilization of our existing facilities by providing additional
services to our existing customers and by establishing relationships with new customers. In addition, we maximize efficiency
by coordinating the completion of new facilities in a manner that is consistent with the expected production that supports them.
Organic Growth. We intend to use our strategic asset base in the United States and our position as one of the largest
gatherers of natural gas, and as one of the largest producers and marketers of NGLs in the United States, as a platform for future
growth. We plan to grow our business by constructing new NGL and natural gas pipeline infrastructure, expanding existing
infrastructure, and constructing new gathering lines and processing facilities.
Strategic Partnerships and Acquisitions. We intend to pursue economically attractive and strategic partnership and
acquisition opportunities within the midstream energy industry, both in new and existing lines of business, and areas of
operation.
OUR COMPETITIVE STRENGTHS
We are one of the largest gatherers of natural gas and one of the largest producers and marketers of NGLs in the United
States. In 2017, our total wellhead volume was approximately 4.5 Bcf/d of natural gas and we produced an average of
approximately 375 MBbls/d of NGLs. We provide natural gas gathering services to the wellhead, and leverage our strategic
footprint to extend the value chain through our integrated NGL and natural gas pipelines and marketing infrastructure. 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 to move natural gas and NGLs from wellhead to market and creates value for our
customers. We believe that we are well positioned to execute our business strategies and achieve one of our primary business
objectives of sustaining our cash distribution per unit because of the following competitive strengths:
Strategically Located Gas Gathering and Processing Operations. Our assets are strategically located in areas with the
potential for increasing our wellhead volumes and cash flow generation. We have operations in some of the largest producing
regions in the United States: Denver-Julesburg Basin (“DJ Basin”), Permian Basin, Midcontinent, and Eagle Ford. In addition,
we operate one of the largest portfolios of natural gas processing plants in the United States. Our gathering systems and
processing plants are connected to numerous key natural gas pipeline systems that provide producers with access to a variety of
natural gas market hubs.
Integrated Logistics and Marketing Operations. We believe the strategic location of our assets coupled with their
geographic diversity and our reputation for running our business reliably and effectively, presents us with continuing
opportunities to provide competitive services to our customers and attract new natural gas production to our gathering and
processing operations. We have connected our gathering and processing operations to key markets with NGL pipelines that we
own or operate to offer our customers a competitive, integrated midstream service. We have strategically located NGL
transportation pipelines that provide takeaway capabilities for our gathering and processing operations in the Permian Basin, DJ
Basin, Midcontinent, East Texas, Gulf Coast, South Texas, and Central Texas. 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 Logistics and Marketing operations also consists of multiple
downstream assets including NGL fractionation facilities, an NGL storage facility and a residue gas storage facility.
Stable Cash Flows. Our operations consist of a mix of fee-based and commodity-based services, which together with our
commodity hedging program, are intended to generate relatively stable cash flows. Growth in our fee-based earnings will
reduce the impact of unhedged margins. Additionally, while certain of our gathering and processing contracts subject us to
commodity price risk, we have mitigated a portion of our currently anticipated commodity price risk associated with the equity
volumes from our gathering and processing operations with fixed price commodity swaps, settling through the first quarter of
2019.
Established Relationships with Oil, Natural Gas and Petrochemical Companies. We have long-term relationships with
many of our suppliers and customers, and we expect that we will continue to benefit from these relationships.
2
Experienced Management Team. Our senior management team and board of directors have extensive experience in the
midstream industry. We believe our management team has a proven track record of enhancing value through organic growth
and the acquisition, optimization and integration of midstream assets.
Affiliation with DCP Midstream, LLC and its owners. Our relationship with DCP Midstream, LLC and its owners,
Phillips 66 and Enbridge, should continue to provide us with significant business opportunities. Through our relationship with
DCP Midstream, LLC and its owners, we believe our strong commercial 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.
DCP Midstream, LLC has a significant interest in us through its ownership of an approximately 2% general partner
interest, an approximately 36% limited partner interest and all of our incentive distribution rights.
OUR OPERATING SEGMENTS
Gathering and Processing Segment
General
Our Gathering and Processing 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 in Alabama, Colorado, Kansas, Louisiana,
Michigan, New Mexico, Oklahoma, Texas and Wyoming. These services include gathering, compressing, treating, and
processing natural gas, producing and fractionating NGLs, and recovering condensate. Our Gathering and Processing segment’s
operations are organized into four regions: North, Permian, Midcontinent and South. Our 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 is an important factor for maintaining and growing overall volumes and cash flow for this segment.
Our assets are positioned in certain areas with active drilling programs and opportunities for organic growth.
We provide our producer customers with gathering and processing services that allow them to move their raw
(unprocessed) natural gas to market. Raw natural gas is gathered, compressed and transported through pipelines to our
processing facilities. In order for the raw natural gas to be accepted by the downstream market, we remove water, nitrogen and
carbon dioxide and separate NGLs for further processing. Processed natural gas, usually referred to as residue natural gas, is
then recompressed and delivered to natural gas pipelines and end users. The separated NGLs are in a mixed, unfractionated
form and are sold and delivered through natural gas liquids pipelines to fractionation facilities for further separation.
We own or operate 61 natural gas processing plants and an interest in one additional plant through our 40% equity
interest in Discovery Producer Services, LLC, or Discovery. At some of these facilities, we fractionate NGLs into individual
components (ethane, propane, butane and natural gasoline).
We receive natural gas from a diverse group of producers under contracts with varying durations, and we receive fees or
commodities from the producers to transport the natural gas from the wellhead to the processing plant. We receive fees or
commodities as payment for our natural gas processing services, depending on the types of contracts we enter into with each
supplier. We purchase or take custody of substantially all of our natural gas from producers, principally under fee-based or
percent-of-proceeds/index processing contracts.
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 Gathering and Processing segment are a mix of non-commodity
sensitive fee-based contracts and commodity sensitive percent-of-proceeds and percent-of-liquids contracts. Percent-of-
proceeds contracts are directly related to the price of natural gas, NGLs and condensate and percent-of-liquids contracts are
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 three to five years and in some cases, the life of the lease. As we
negotiate new agreements and renegotiate existing agreements, this may result in a change in contract mix period over period.
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.
During 2017, total wellhead volume on our assets was approximately 4.5 Bcf/d, originating from a diversified mix of
customers. Our systems each have significant customer acreage dedications that we expect will continue to provide
3
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 2017, the combined NGL production from our processing facilities was
approximately 375 MBbls/d and was delivered and sold into various NGL takeaway pipelines.
The following is operating data for our Gathering and Processing segment by region:
Operating Data
Approximate
Gathering
and Transmission
Systems (Miles)
Approximate
Net Nameplate Plant
Capacity
(MMcf/d) (a)
Plants
Natural Gas
Wellhead Volume
(MMcf/d) (a)
NGL
Production
(MBbls/d) (a)
Year Ended December 31, 2017
13
16
12
20
61
4,000
16,500
29,000
7,500
57,000
1,260
1,460
1,765
3,295
7,780
1,121
941
1,229
1,240
4,531
86
103
94
92
375
Regions
North
Permian
Midcontinent
South
Total
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.
4
North Region
Our North region primarily consists of our DJ Basin system. We have a broad network of gathering and processing
facilities in Weld County, Colorado that provide significant optionality and flexibility.
We are constructing a new 200 MMcf/d cryogenic natural gas processing plant, Mewbourn 3, and further expanding our
Grand Parkway gathering system, both of which are expected to be placed in service in the third quarter of 2018. Our
Mewbourn 3 plant will increase capacity to support the growing processing needs of producers in the DJ Basin. Our
200 MMcf/d O'Connor 2 plant and associated gathering infrastructure is progressing and expected to be in service in 2019.
Our DJ Basin system delivers to the Mont Belvieu hub in Mont Belvieu, Texas via the Front Range and Texas Express
pipelines, owned 33.33% and 10% by us, respectively, and to the Conway hub in Bushton, Kansas via our Wattenberg pipeline
in our Logistics and Marketing segment.
5
Permian Region
Our Permian region primarily includes our West Texas system in the Midland Basin and our Southeast New Mexico
system in the Delaware Basin. Producers continue to focus drilling activity on the most attractive acreage in the Midland and
Delaware Basins. Our gathering and processing assets in the Permian region provide NGL takeaway service via our Sand Hills
pipeline, which is owned 66.67% by us and 33.33% by Phillips 66, to fractionation facilities along the Gulf Coast and to the
Mont Belvieu hub.
6
Midcontinent Region
Our Midcontinent region primarily includes our Liberal system, Panhandle system, and our South Central Oklahoma
system. We gather and process raw natural gas primarily from the Ardmore and Anadarko Basins, including the South Central
Oklahoma Oil Province (“SCOOP”) play and the Sooner Trend Anadarko Basin Canadian and Kingfisher (“STACK”) play.
Existing production in the western Midcontinent region, which includes our Liberal and Panhandle systems, is typically
from mature fields with shallow decline profiles that we expect will provide our plants with a dependable source of raw natural
gas over a long term. We believe the infrastructure of our plants and gathering facilities is uniquely positioned to pursue our
consolidation strategy in the western Midcontinent region. Our gathering system footprint in the eastern Midcontinent region,
which includes our South Central Oklahoma system, serves the SCOOP and STACK plays.
Our gathering and processing assets in the Midcontinent region deliver NGLs primarily to the Gulf Coast and Mont
Belvieu via our Southern Hills pipeline, owned 66.67% by us and 33.33% by Phillips 66.
7
South Region
Our South region primarily includes our Eagle Ford system, East Texas system, and our 40% interest in the Discovery
system. We are pursuing cost efficiencies and increasing the utilization of our existing assets.
Our Eagle Ford system delivers NGLs to the Gulf Coast petrochemical markets and to Mont Belvieu through our Sand Hills
pipeline and other third party NGL pipelines. Our East Texas system provides NGL takeaway service through the Panola pipeline,
owned 15% by us, and delivers gas primarily through its Carthage Hub which delivers residue gas to multiple interstate and
intrastate pipelines.
The Discovery system is operated by Williams Partners L.P., which owns a 60% interest, 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 Louisiana, and have access to downstream pipelines and markets.
Competition
We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies and
in gathering and processing raw natural gas 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.
8
Logistics and Marketing Segment
General
We market our NGLs, residue gas and condensate and provide logistics and marketing services to third-party NGL
producers and sales customers in significant NGL production and market centers in the United States. This includes purchasing
NGLs on behalf of third-party NGL producers for shipment on our NGL pipelines and resale in key markets.
Our NGL services include plant tailgate purchases, transportation, fractionation, flexible pricing options, price risk
management and product-in-kind agreements. Our primary NGL operations are located in close proximity to our Gathering and
Processing assets in each of the operating regions.
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 natural gas systems have the ability to deliver gas into numerous downstream transportation pipelines and markets.
We sell residue gas on behalf of our producer customers and residue gas which we earn under our gas supply agreements,
supplying the residue gas demands of end-use customers physically attached to our pipeline systems and managing excess
capacity of our owned storage and transportation assets. End-users include large industrial companies, natural gas distribution
companies and electric utilities. We are focused on extracting the highest possible value for the residue gas that results from our
processing and transportation operations. We sell the residue gas at market-based prices.
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Our ownership in various intrastate natural gas pipelines give us access to market centers/hubs such as Waha, Texas; Katy,
Texas and the Houston Ship Channel and are used in our natural gas asset based trading activities.
The following is operating data for our Logistics and Marketing segment:
Operating Data
Year Ended December 31, 2017
System
Approximate
System
Length
(Miles)
Approximate
Throughput
Capacity
(MBbls/d) (a)
Approximate
NGL Storage
Capacity
(MMBbls)
Approximate
Natural Gas
Storage
Capacity (Bcf)
Pipeline
Throughput
(MBbls/d) (a)
Fractionator
Throughput
(MBbls/d) (a)
Fractionators
Sand Hills pipeline
1,300
Southern Hills
pipeline
Front Range pipeline
Texas Express
pipeline
Other pipelines
Mont Belvieu
fractionators
Storage facilities
Total
950
455
595
1,200
—
—
4,500
—
—
—
—
—
2
—
2
227
117
50
28
241
60
—
722
—
—
—
—
—
—
8
8
—
—
—
—
—
—
12
12
192
69
36
15
148
—
—
460
—
—
—
—
—
48
—
48
(a) Represents total NGL capacity or throughput allocated to our proportionate ownership share for 2017 divided by 365
days.
NGL Pipelines
DCP Sand Hills Pipeline, LLC, or the Sand Hills pipeline, an interstate NGL pipeline in which we own a 66.67% interest,
is a common carrier pipeline which provides takeaway service from plants in the Permian and the Eagle Ford basins to
fractionation facilities along the Texas Gulf Coast and at the Mont Belvieu, Texas market hub. We have completed the
expansion of the Sand Hills pipeline to 365 MBbls/d in the first quarter of 2018. Further Sand Hills pipeline expansion to 450
MBbls/d is progressing and includes a partial looping of the pipeline and the addition of new pump stations, and is expected to
be in service in the second half of 2018.
DCP Southern Hills Pipeline, LLC, or the Southern Hills pipeline, an interstate NGL pipeline in which we own a 66.67%
interest, provides takeaway service from the Midcontinent to fractionation facilities at the Mont Belvieu, Texas market hub.
Front Range Pipeline LLC, or the Front Range pipeline, an interstate NGL pipeline in which we own a 33.33% interest,
originates in the DJ Basin and extends to Skellytown, Texas. The Front Range pipeline connects to our O'Connor, Lucerne 1,
Lucerne 2, and Mewbourn plants as well as third party plants in the DJ Basin. Enterprise Products Partners L.P., or Enterprise,
is the operator of the pipeline.
Texas Express Pipeline LLC, or the Texas Express pipeline, an intrastate NGL pipeline in which we own a 10% interest,
originates near Skellytown in Carson County, Texas, and extends to Enterprise's natural gas liquids fractionation and storage
complex at Mont Belvieu, Texas. The pipeline also provides access to other third party facilities in the area. Enterprise is the
operator of the pipeline.
The Southern Hills, Sand Hills, Texas Express, and Front Range pipelines have in place long-term, fee-based
transportation agreements, a portion of which are ship-or-pay, with us as well as third party shippers. These NGL pipelines
collect fee-based transportation revenue under regulated tariffs.
NGL Fractionation Facilities
We own a 12.5% interest in the Enterprise fractionator operated by Enterprise and a 20% interest in the Mont Belvieu 1
fractionator operated by ONEOK Partners, both located in Mont Belvieu, Texas. The fractionation facilities separate NGLs
received from processing plants into their individual components. These fractionation services are provided on a fee basis. The
10
results of operations for this business are generally dependent upon the volume of NGLs fractionated and the level of fees
charged to customers.
Storage Facilities
Our NGL storage facility, which stores ethane, propane and butane, is located in Marysville, Michigan and has strategic
access to the Marcellus, Utica and Canadian NGLs. Our facility includes 11 underground salt caverns with approximately 8
MMBbls of storage capacity. 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 under multi-year storage agreements. The results of operations for this business
are generally dependent upon the volume stored and the level of fees charged to customers.
Our Spindletop natural gas storage facility is located in Texas and plays an important role in our ability to act as a full-
service natural gas marketer. The facility has capacity for residue gas of approximately 12 Bcf. We may lease a portion of the
facility’s capacity to third-party customers, and use the balance to manage relatively constant natural gas supply volumes with
uneven demand levels, provide “backup” service to our customers and support our asset based trading activities. Our asset
based trading activities are designed to realize margins related to fluctuations in commodity prices, time spreads and basis
differentials and to maximize the value of our storage facility.
Wholesale Propane
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 fractionation facilities and crude oil refineries, primarily located in the
Marcellus/Utica area, Canada and other international sources, and transport these volumes of propane supply by pipeline, rail or
ship to our terminals and storage facilities. We primarily sell propane on a wholesale basis to propane distributors under annual
sales agreements who in turn resell propane to their customers. Our operations include one owned marine terminal, five owned
propane rail terminals and one joint venture rail terminal, with access to several open access pipeline terminals.
The wholesale propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly
in the winter, which can impact the price and volume of propane sold in the markets we serve.
Trading and Marketing
Our energy trading operations are exposed to market variables and commodity price risk. We manage commodity price
risk related to our natural gas storage and pipeline assets by engaging in natural gas asset based trading and marketing. We may
enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and
sale of commodity-based instruments.
Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities
through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term
contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk
with respect to these products and services, and these operations may enter into physical contracts and financial instruments
with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.
We may execute a time spread transaction when the difference between the current price of natural gas (cash or futures)
and the futures market price for natural gas exceeds our cost of storing physical gas in our owned and/or leased storage
facilities. The time spread transaction allows us to lock in a margin when this market condition exists. 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.
We may execute basis spread transactions when the market price differential between locations on a pipeline asset
exceeds our cost of transporting physical gas through our owned and/or leased pipeline asset. When this market condition
exists, we may execute derivative instruments around this differential at the market price. This basis spread transaction allows
us to lock in a margin on our physical purchases and sales of gas.
Customers and Contracts
We sell our commodities to a variety of customers ranging from large, multi-national petrochemical and refining
companies to small regional retail propane distributors. Substantially all of our NGL sales are made at market-based prices,
including approximately 22% of our NGL production which was committed to Phillips 66 and Chevron Phillips Chemical, or
CPChem as of December 31, 2017. The primary production commitment on certain contracts began a ratable wind down period
in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and
CPChem in the ordinary course of business.
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Competition
The Logistics and Marketing 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 natural gas and 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.
Competition in the NGLs marketing area comes from other midstream NGL marketing companies, international
producers/traders, chemical companies, refineries and other asset owners. Along with numerous marketing competitors, we
offer price risk management and other services. We believe it is important that we tailor our services to the end-use customer to
remain competitive.
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 21 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 applies to interstate and intrastate pipeline
facilities and the pipeline transportation of liquid 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
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 per violation, with
a maximum of $2 million for any related series of violations. Any material penalties or fines under these or other statutes, 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 approximately $47 million between 2018 and 2022 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.
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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 and EPA Risk Management Program regulations, which are
designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
The OSHA 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 holding or handling these materials in quantities 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. The EPA regulations have similar applicability
thresholds. 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.
The transportation of propane by rail is regulated by the Federal Railroad Administration. 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.
FERC and State Regulation of Operations
FERC regulation of interstate natural gas pipelines, the marketing and sale of natural gas in interstate commerce and the
transportation of NGLs in interstate commerce may affect certain aspects of our business and the market for our products and
services. Regulation of gathering systems and intrastate transportation of natural gas and NGLs by state agencies may also
affect our business.
Interstate Natural Gas Pipeline Regulation
Our Cimarron River, Discovery, and Dauphin Island Gathering Partners systems, or portions thereof, are some of our
natural gas pipeline assets that are subject to regulation by FERC, under the Natural Gas Act of 1938, as amended, or NGA.
Natural gas companies subject to the NGA may only charge rates that have been determined to be just and reasonable. In
addition, FERC authority over natural gas companies that provide natural gas pipeline transportation services in interstate
commerce includes:
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certification and construction of new facilities;
abandonment of services and facilities;
maintenance of accounts and records;
acquisition and disposition of facilities;
initiation and discontinuation of transportation services;
terms and conditions of transportation 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 an interstate natural gas pipeline's transportation services are based on the
pipeline's 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, including an income tax allowance, allowed rate of return and volume
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throughput and contractual capacity commitment assumptions. The allocation of costs to various pipeline services and the
manner in which rates are designed also can impact a pipeline's profitability. The maximum applicable recourse rates and terms
and conditions for service are set forth in each pipeline’s FERC-approved gas tariff. 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 to compel the company to change or justify 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 the 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 companies engaged in interstate commerce. In the Energy Policy Act of 2005, or EPACT 2005, Congress amended
the NGA and Federal Power Act to add anti-fraud and anti-manipulation requirements. 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. FERC adopted market manipulation and 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. 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 may investigate energy markets to determine if behavior unduly impacted
or "manipulated" energy prices.
In addition, EPACT 2005 gave FERC increased penalty authority for violations of the NGA and FERC's rules and
regulations thereunder. FERC may issue civil penalties of up to $1 million per day per violation, and violators may be subject to
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 relies on its enforcement authority in issuing a number of natural gas enforcement
actions. Failure to comply with the NGA and FERC's rules and regulations thereunder could result in the imposition of civil
penalties and disgorgement of profits.
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 provide service that is not unduly discriminatory and to file and/
or seek approval of their rates with the agencies and permit shippers to challenge existing rates or proposed rate increases. For
example, our Guadalupe system is an intrastate pipeline regulated as a gas utility by the Railroad Commission of Texas. To the
extent that an intrastate pipeline system transports natural gas in interstate commerce, the rates and terms and conditions of such
interstate transportation service are subject to FERC rules and regulations under Section 311 of the Natural Gas Policy Act, or
NGPA. Certain of our systems are subject to FERC jurisdiction under Section 311 of the NGPA for their interstate
transportation services. 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. Additionally, the terms and conditions of service set forth in the intrastate pipeline’s
Statement of Operating Conditions are subject to FERC approval. Non-compliance with FERC's rules and regulations
established under Section 311 of the NGPA, including 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 imposition of civil and criminal penalties. Among other matters, EPACT 2005 also amended the
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NGPA to give FERC authority to impose civil penalties for violations of the NGPA up to $1 million for any one violation and
violators may be subject to criminal penalties of up to $1 million per violation and five years in prison.
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 many circumstances, nondiscriminatory take
requirements and 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
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 interstate purchases and sales of natural gas, 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, in additional to civil and criminal penalties, 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
Certain of our pipelines, including Sand Hills and Southern Hills, are common carriers that provide interstate NGL
transportation services subject to FERC regulation. FERC regulates interstate common carriers 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 common carriers file tariffs containing all the rates, charges and other terms for services provided by such
pipelines. The ICA requires that tariffs apply to the interstate movement of NGLs, as is the case with the Sand Hills, Southern
Hills, Black Lake, Wattenberg and Front Range pipelines. Pursuant to the ICA, rates must be just, reasonable, and
nondiscriminatory, and 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
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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 that enables common carrier pipelines to charge
rates up to their ceiling levels, which are adjusted annually based on an inflation index. Specifically, the indexing methodology
requires a pipeline to adjust the ceiling level for its rates annually by the inflation index established by the FERC. FERC
reviews the indexing methodology every five years, and in 2015, the indexing methodology for the five years beginning July 1,
2016 was changed to be the Producer Price Index for Finished Goods plus 1.23 percent. 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 from the previous year. If the indexing
methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, the pipeline is required to reduce its rate
to comply with the lower ceiling unless doing so would reduce a rate “grandfathered” under EPACT 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. The ceiling levels calculated for our interstate NGL pipelines are typically increased each
year pursuant to the indexing methodology, but may be subject to decrease, which occurred in 2016 and resulted in the decrease
in the tariff rates for many such pipelines.
On October 20, 2016, FERC issued an Advance Notice of Proposed Rulemaking, which presented significant changes to
the indexing mechanism and reporting requirements of common carriers subject to FERC’s jurisdiction under the ICA. The
proposed changes to the indexing methodology, would prohibit an increase in a common carrier’s ceiling level and rates if a
complaint was filed and the return as reported by the common carrier in two previous annual reports exceeded a predetermined
threshold. Additionally, the FERC proposed multiple changes to its annual reporting requirements. We cannot predict the
outcome of the proceeding, but the proposal, if implemented, could adversely impact future rate increases of our common
carriers and place additional administration and reporting burdens on our business.
Intrastate NGL Pipeline Regulation
NGL and other common carrier petroleum pipelines that provide intrastate transportation services 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 tariffs and their rates with the agencies and permit shippers to
challenge existing rates or proposed rate increases. For example, certain of our pipelines have tariffs filed with the Railroad
Commission of Texas for their intrastate NGL transportation services.
Environmental Matters
General
Our operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, transporting,
fractionating, storing or selling 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 or authorizations to conduct regulated activities and imposing obligations in
those permits, potentially including capital expenditures or operational requirements, that reduce or limit impacts to
the environment;
restricting the ways that we can handle or dispose of our wastes;
limiting or prohibiting construction or operational activities in sensitive areas such as wetlands, coastal regions or
areas inhabited by threatened and 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, or potentially criminal
enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, potential
citizen lawsuits, and the issuance of orders enjoining or affecting future operations. Certain environmental statutes impose strict
liability or joint and several liability for costs required to clean up and restore sites where hazardous substances, or in some
cases hydrocarbons, have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and
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other third parties to file claims for property damage or personal injury allegedly caused by the release of substances or other
waste products into the environment.
The overall trend in federal and state environmental programs is to expand regulatory requirements, placing 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. 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 Air Quality Standards and Climate Change
A number of states have adopted or considered programs to reduce “greenhouse gases,” or GHGs, which can include
methane, 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 downstream combustion of fuels (e.g.,
oil or natural gas) that we process, or we may otherwise be required by regulation to take steps to reduce emissions of GHGs.
Also, the EPA has declared that GHGs “endanger” public health and welfare, and is regulating GHG emissions from mobile
sources such as cars and trucks. The EPA's 2010 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, including the Prevention of Significant Deterioration (“PSD”) program and Title V permitting. In 2016 EPA proposed a
rule to revise the PSD and Title V permitting regulations applicable to GHGs in response to a 2014 U.S. Supreme Court
decision and subsequent D.C. Circuit decision striking down its 2011 rules. The proposed revisions required that major sources
of non-GHG air pollutants, such as volatile organic compounds or nitrogen oxides, which also emit 100,000 tons per year or
more of CO2 equivalent (or modifications of these sources that result in an emissions increase of 75,000 tons per year or more
of CO2 equivalent), obtain permits addressing emissions of greenhouse gases. The EPA has not acted to finalize this proposed
rule. The EPA also has published various rules relating to the mandatory reporting of GHG emissions, including mandatory
reporting requirements of GHGs from petroleum and natural gas systems. In October 2015, the EPA amended and expanded
greenhouse gas reporting requirements to all segments of the oil and gas sector starting with the 2016 reporting year. In June
2016, the EPA published final new source performance standards (“NSPS”) for methane (a greenhouse gas) from new and
modified oil and gas sector sources. These regulations expand upon the 2012 EPA rulemaking for oil and gas equipment-
specific emissions controls, for example, regulating well head production emissions with leak detection and repair
requirements, pneumatic controllers and pumps requirements, compressor requirements, and instituting leak detection and
repair requirements for natural gas compressor and booster stations for the first time. In June 2017, EPA published a proposed
rule to stay certain requirements of the 2016 NSPS rule for two years while it completes reconsideration of certain aspects of
the rule and reviews the entire rule. In October 2015, the EPA finalized a reduction of the ambient ozone standard from 75
parts per billion to 70 parts per billion under the Clean Air Act. At EPA’s request, the judicial challenge to the ozone standard in
the D.C. Circuit was put in abeyance while EPA reviews the standard. The EPA has also indicated that it will request comments
on entirely withdrawing the October 2016 Control Techniques Guidelines for emissions of volatile organic compounds from oil
and gas sector sources that were to be implemented or utilized by states in ozone nonattainment areas, with an expected co-
benefit of reduced methane emissions. The permitting, regulatory compliance and reporting programs, taken as a whole,
increase the costs and complexity of oil and gas operations with potential to adversely affect the cost of doing business for our
customers resulting in reduced demand for our gas processing and transportation services, and which may also require us to
incur certain capital and operating expenditures in the future to meet regulatory requirements or for air pollution control
equipment, for example, in connection with obtaining and maintaining operating permits and approvals for air emissions
associated with our facilities and operations.
Hazardous Substances and Waste
Our operations are subject to environmental laws and regulations relating to the management and release of hazardous
substances, or solid or hazardous wastes, including petroleum hydrocarbons. These laws generally regulate the generation,
storage, treatment, transportation and disposal of solid and hazardous waste, and may impose strict liability or joint and several
liability for the investigation and remediation of areas at a facility where hazardous substances, or in some cases hydrocarbons,
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
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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 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 parties the costs that the agency incurs. Despite the “petroleum exclusion” of CERCLA
Section 101(14), which 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 and natural gas 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, may in the future be
designated by the EPA 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 may 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 or released thereon
may be subject to CERCLA, RCRA and analogous state laws, or separate state laws that address hydrocarbon releases. Under
these laws, we could be required to remove or remediate releases of hydrocarbon materials, or previously disposed wastes
(including wastes disposed of or released by prior owners or operators), or 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 or certain other materials. 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. The EPA has also 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, or OPA, which is part of the Clean Water Act, addresses prevention, containment and
cleanup, and liability associated with oil pollution. OPA applies to vessels, offshore platforms, and onshore facilities, including
natural gas gathering and processing facilities, 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. 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.
18
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
We do not have any employees. Our operations and activities are managed by our general partner, DCP Midstream GP, LP,
which 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, 2017, approximately 2,650 employees of DCP Services, LLC, a wholly-owned
subsidiary of DCP Midstream, LLC, provided support for our operations pursuant to the Services and Employee Secondment
Agreement between DCP Services, LLC and us. For additional information, refer to Item 10. "Directors, Executive Officers and
Corporate Governance” and Item 13. "Certain Relationships and Related Transactions, and Director Independence" in this
Annual Report on Form 10-K.
General
We make certain filings with the Securities and Exchange Commission ("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.dcpmidstream.com, as soon as reasonably practicable after they are filed with
the SEC. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into
this report. 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 on Form
10-K 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
Our cash flow is affected by natural gas, NGL and crude oil prices.
Our business is affected by natural gas, NGL and crude oil prices. In the past, the prices of natural gas, NGLs and crude oil
have been volatile, and we expect this volatility to continue.
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 crude oil and the general condition of the financial markets. Commodity
prices experienced significant volatility during 2017, as illustrated by the following table:
Commodity:
NYMEX Natural Gas
($/MMBtu)
NGLs ($/Gallon)
Crude Oil ($/Bbl)
Year Ended
December 31, 2017
Daily High
Daily Low
December 31,
2017
$
$
$
3.42
0.76
60.42
$
$
$
2.56
0.50
42.53
$
$
$
2.95
0.76
60.42
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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 further. 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 crude oil and 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 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 make cash distributions.
Market conditions, including commodity prices, may impact our earnings, financial condition and cash flows.
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 domestic and export markets and economic conditions and other factors, including:
•
•
•
•
•
•
•
•
the level of domestic and offshore production;
the availability of natural gas, NGLs and crude oil and the demand in the U.S. and globally for these commodities;
a general downturn in economic conditions;
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;
actions taken by foreign oil and gas producing and importing nations;
the availability of local, intrastate and interstate transportation systems and condensate and NGL export facilities;
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
increase or decrease, whichever is applicable, as the price of natural gas and NGLs fluctuate.
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.
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 natural gas and NGLs, we have
entered into derivative financial instruments relating to the future price of natural gas and NGLs, as well as crude oil.
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 portion not covered by derivative transactions. 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.
20
We record all of our derivative financial instruments at fair value on our balance sheet 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. Additionally, 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.
Our derivative instruments may require us to post collateral based on predetermined collateral thresholds. Depending on
the movement in commodity prices, the amount of posted collateral required may increase, reducing our liquidity.
Our hedging activities may not be as effective as we intend and 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.
We could incur losses due to impairment in the carrying value of our goodwill or long-lived assets.
We periodically evaluate goodwill and long-lived assets for impairment. Our impairment analyses for long-lived assets
require management to apply judgment in evaluating whether events and circumstances are present that indicate an impairment
may have occurred. If we believe an impairment may have occurred judgments are then applied 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. To perform the impairment assessment for
goodwill, we primarily use a discounted cash flow analysis, supplemented by a market approach analysis. 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 (including forecasted volumes and commodity prices), as well as historical and other factors. 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 impairment charges. Adverse changes in our business or the overall operating environment, such as lower
commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the
potential impact on our operations and cash flows.
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.
Volumes of natural gas dedicated to our systems in the future may be less than we anticipate.
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.
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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
and NGLs supply. We have no natural gas supplier representing 10% or more of our total natural gas supply during the year
ended December 31, 2017. 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.
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 and crude 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, crude oil and NGLs,
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
make cash distributions.
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.
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 ability to manage and grow our business effectively could be adversely affected if we or DCP Midstream, LLC and its
subsidiaries 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. This executive management team has significant experience in the midstream energy
industry. The loss of any of our executives or the 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
adversely impacted if we or DCP Midstream, LLC and its subsidiaries 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.
22
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.
In January 2017, our credit rating was lowered and the cost of borrowing under our Credit Agreement increased. The further
lowering of our credit rating could further increase our cost of borrowing under our Credit Agreement and could require us to post
collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase
our cost of debt.
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.
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:
•
•
•
•
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 Credit Agreement and the indentures governing our notes may limit our ability to make distributions to
unitholders and may limit our ability to capitalize on acquisitions and other business opportunities.
Our Credit Agreement and the indentures governing our notes 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 Credit Agreement contains covenants requiring us to maintain a certain leverage ratio and certain other tests.
Any subsequent replacement of our Credit Agreement 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.
23
The outstanding senior notes and junior subordinated notes, or notes, are 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.
The 2.70% Senior Notes due 2019, 9.75% Senior Notes due 2019, 5.35% Senior Notes due 2020, 4.75% Senior Notes due
2021, 4.95% Senior Notes due 2022, 3.875% Senior Notes due 2023, 8.125% Senior Notes due 2030, 6.450% Senior Notes due
2036, 6.750% Senior Notes due 2037, and 5.60% Senior Notes due 2044, or the Senior Notes, are senior unsecured obligations
of DCP Operating and rank equally in right of payment with all of its other existing and future senior unsecured debt and
effectively junior to any of its future secured indebtedness to the extent of the collateral securing such indebtedness. The 5.85%
Fixed-to-Floating Rate Junior Subordinated Notes due 2043 are junior subordinated obligations of DCP Operating and rank
junior 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, 2017, DCP Operating’s subsidiaries had no debt for borrowed money owing to any unaffiliated third
parties. However, such subsidiaries are not prohibited under the indentures governing the notes from incurring indebtedness in
the future.
In addition, because our notes and our guarantees 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 indentures 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, 2017, our consolidated principal indebtedness was $4,725 million. 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 and distributions on our units.
Debt service obligations and restrictive covenants in our Credit Agreement, and the indentures 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.
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. In its rulemaking under the Dodd-Frank Wall Street
Reform and Consumer Protection Act, or the Act, the Commodities Futures Trading Commission, or CFTC, adopted regulations
24
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 vacated by the court. In December 2016, the
CFTC reproposed rules that place limits on speculative positions in certain physical commodity futures and options contracts and
their "economically equivalent" swaps, including NYMEX Henry Hub Natural Gas and NYMEX Light Sweet Crude Oil contracts,
subject to exceptions for certain bona fide hedging transactions. The CFTC has sought comment on the position limits rules as
reproposed, but since these rules are not yet final, the impact of those provisions on us is uncertain at this time. Under the reproposed
rules, 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, and as a result, we do
not expect our hedging activity to be subject to mandatory clearing. 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.
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 ("Partnership Agreement"), to
our common 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.
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 covenants.
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.
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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.
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, PHMSA 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 threats to pipeline segments that could impact a high consequence area and assess the risks that such
threats pose to pipeline integrity;
collect, integrate, and analyze data regarding threats and risks posed to the pipeline;
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 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 currently are not subject to pipeline integrity requirements, we may incur
significant costs and liabilities associated with repair, remediation, preventative or mitigation measures 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 approximately $47 million between 2018 and 2022 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 programs 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
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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.
State and local legislative and regulatory initiatives relating to oil and gas operations could adversely affect our third-party
customers’ production and, therefore, adversely impact our midstream operations.
Certain states in which we operate have adopted or are considering adopting measures that could impose new or more
stringent requirements on oil and gas exploration and production activities. For example, the potential for adverse impacts to
our business is present where local governments have enacted ordinances directly regulating pipeline assets and operations, and
and private individuals have sponsored citizen initiatives to limit hydraulic fracturing, increase mandatory setbacks of oil and
gas operations from occupied structures, and achieve more restrictive state or local control over such activities.
In the event state or local restrictions or prohibitions are adopted in our areas of operations, our customers may incur
significant compliance costs or may experience delays or curtailment in the pursuit of their exploration, development, or
production activities, and possibly be limited or precluded in the drilling of certain wells altogether. Any adverse impact on our
customers’ activities would have a corresponding negative impact on our throughput volumes. In addition, while the general
focus of debate is on upstream development activities, certain proposals may, if adopted, directly impact our ability to
competitively locate, construct, maintain, and operate our own assets. Accordingly, such restrictions or prohibitions could have
a material adverse effect on our business, prospects, results of operations, financial condition, cash flows and ability to make
distributions to our unitholders.
We may incur significant costs and liabilities in the future resulting from a failure to comply with existing or new
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, including federal and state air
permits, that impose obligations related to air emissions; (2) the federal Resource Conservation and Recovery Act, as amended,
or RCRA, and comparable state laws that impose requirements for the management, storage and disposal of solid and
hazardous 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; (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 and
regulated state waters; and (5) state laws that impose requirements on the response to and remediation of hydrocarbon releases
to soil and managing related wastes. Failure to comply with these laws and regulations or newly adopted laws or regulations
may trigger a variety of administrative, civil and potentially criminal enforcement measures, including the assessment of
monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining or affecting future operations.
Certain environmental regulations, including CERCLA and analogous state laws and regulations, impose strict liability and
joint and several liability for costs required to clean up and restore sites where hazardous substances, and in some cases
hydrocarbons, have been disposed or otherwise released.
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, governmental claims for natural resource damages or imposing fines or
penalties for related violations of environmental laws, permits 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 third-party indemnification.
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
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may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated
transportation 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 certain of our pipeline
systems 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.
Several of our pipelines are interstate transporters of NGLs and are subject to FERC jurisdiction under the Interstate
Commerce Act and the Elkins Act. The base interstate tariff rates for our NGL pipelines are determined either by a FERC cost-
of-service proceeding or by agreement with an unaffiliated party, and adjusted annually through the FERC’s indexing
methodology. The NGL pipelines may also provide incentive rates, which offer tariff rates below the base tariff rates for high
volume shipments.
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 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. Under the NGPA, FERC may impose civil penalties of up to $1 million for any one violation and may impose
criminal penalties of up to $1 million and five years in prison.
Other state and local regulations also affect our business. Our non-proprietary gathering lines are subject to ratable take and
common purchaser statutes. 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.
The interstate tariff rates of certain of our pipelines are subject to review and possible adjustment by federal regulators.
FERC, pursuant to the NGA, regulates many aspects of our interstate natural gas pipeline transportation service, including
the rates our pipelines are 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 our requested tariff rate increases, or if FERC lowers the
tariff rates we are permitted to charge, on its own initiative, or as a result of challenges raised by customers or third parties, our
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.
Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be
subject to substantial penalties and the disgorgement of profits. 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.
The transportation rates for our NGL pipelines that provide interstate transportation services, our interstate natural gas
pipelines, and our intrastate pipelines that provide interstate services under Section 311 of the NGPA could be adversely
impacted by potential changes to FERC’s income tax allowance policy for partnership pipelines.
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. Under current policy, whether a pipeline’s owners have such actual or potential
income tax liability is reviewed by FERC on a case-by-case basis, and our pipelines’ ability to recover an income tax allowance
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in a cost-of-service proceeding before FERC is subject to this review and potentially impacted by ultimate partnership
ownership. On December 15, 2016, FERC issued a Notice of Inquiry (NOI) regarding its income tax recovery policy following
a decision by the U.S. Court of Appeals for the D.C. Circuit, issued in July 2016, that found FERC did not demonstrate there is
no double recovery of income taxes for a partnership owned pipeline as a result of the income tax allowance and return on
equity policies in a cost-of-service proceeding for an oil pipeline. While the Court of Appeals remand to FERC focused on a
specific case, FERC’s issuance of an NOI seeks comments on how to address any double-recovery of income taxes and also
broader industry comments related to the impact on all regulated industries, including natural gas pipelines, oil pipelines and
electric utilities. We cannot predict the outcome of this proceeding, but any shift in policy could impact future rate proceedings
for our pipelines organized as partnerships and could adversely affect our revenues for our rates calculated using a cost-of-
service methodology.
Moreover, in the NOI proceeding, parties have requested that FERC adjust the rates for interstate pipeline services based
on the reduction in the federal income tax rates for corporations, as well as partners and other owners of pass-through entities,
in the recently enacted Law to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the
Budget for Fiscal Year 2018. While we believe there is considerable regulatory precedent and laws that afford pipelines due
process rights if their rates are contested, FERC has not yet responded to the motions and we cannot predict the outcome. Any
action by FERC could impact the rates for our regulated interstate pipeline services. Additionally, the reduction in the federal
income tax rates for corporations and individuals could impact the income tax allowance included in the cost-of-service
calculations in future rate proceedings for our regulated interstate pipeline services.
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
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 VOC leaks exceeding 500 parts
per million in concentration at new or modified natural gas processing plants. The EPA made certain revisions to the regulation
from 2013 to 2015, and the regulation is also the subject of Petitions for Review before the U.S. Circuit Court of Appeals for
the District of Columbia. In addition, in June 2016, the EPA expanded the NSPS regulations for new or modified sources of
VOCs to include methane emissions. Among other things, this regulation imposes leak detection and repair requirements for
VOCs and methane on producer well site equipment and on midstream equipment such as compressor and booster stations,
impose additional emission reduction requirements on specific pieces of oil and gas equipment, and is a regulatory pre-
condition to EPA acting to regulate existing oil and gas methane sources in the future under Section 111(d) of the Clean Air Act.
This regulation is the subject of a Petition for Review before the U.S. Circuit Court of Appeals for the District of Columbia.
This regulation is also the subject of review pursuant to the March 28, 2017, Presidential Executive Order on Promoting Energy
Independence and Economic Growth, which ordered the EPA Administrator to review this regulation for consistency with the
Executive Order’s policy to review existing regulations impacting natural gas development and, if appropriate, “suspend,
revise, or rescind the guidance or publish for notice and comment proposed rules suspending, revising or rescinding those
rules.” In response to the Executive Order, in June 2017, EPA published a proposed rule to stay the compliance requirements of
the regulation while it reviews the rule. The EPA separately withdrew the information request that it had issued in November
2016 as part of an effort to develop standards for methane and other emissions from existing sources in the oil and natural gas
industry. The EPA, in October 2015, revised and lowered the ambient air quality standard for ozone in the U.S. under the Clean
Air Act, from 75 parts per billion to 70 parts per billion, which is likely to result in more, and expanded, ozone non-attainment
areas, which in turn will require states to adopt implementation plans to reduce emissions of ozone-forming pollutants, like
VOCs and nitrogen oxides, that are emitted from, among others, the oil and gas industry. Persistent non-attainment status, such
as for ozone, can result in lower major source permitting thresholds (making it more costly and complex to site and permit
major new or modified facilities) and additional control requirements. In October 2016, the EPA also finalized Control
Techniques Guidelines for VOC emissions from existing oil and natural gas equipment and processes in moderate ozone non-
attainment areas. These Control Techniques Guidelines provide recommendations for states and local air agencies to consider
when determining what emissions control requirements apply to sources in the non-attainment areas. In late 2017, however,
EPA indicated that it will request comments on withdrawing the guidelines in their entirety. Collectively, these regulations
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could require modifications to the operations of our 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
also 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 in the future associated with proposed climate change regulation and legislation.
The United States Congress and some states where we have operations may consider legislation related to greenhouse gas
emissions, including methane emissions, which may compel reductions of such emissions. In addition, there have been
international conventions and efforts to establish standards for the reduction of greenhouse gases globally, including the Paris
accords in December 2015. The conditions for entry into force of the Paris accords were met on October 5, 2016 and the
Agreement went into force 30 days later on November 4, 2016. In August 2017, however, the U.S. notified the United Nations
Secretary-General that it intends to withdraw from the agreement as soon as it is able to do so, or November 2019. Legislative
proposals have included or could include limitations, or caps, on the amount of greenhouse gas that can be emitted, as well as a
system of emissions allowances. For example, legislation passed by the U.S. 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, President Obama announced a climate action plan that targets
methane emissions from the oil and gas industry as part of a comprehensive interagency methane reduction strategy. Many of
the actions taken under the Obama Administration have been targeted by the Trump Administration. For instance, in June 2017
EPA proposed a two-year stay of the compliance requirements for the new source performance standards for methane emissions
(a greenhouse gas) from new and modified oil and gas industry sources that EPA has finalized in 2016. The EPA also indicated
that it will request comments on entirely withdrawing the October 2016 Control Techniques Guidelines for emissions of VOCs
from existing oil and gas industry sources in ozone nonattainment areas, which had an expected co-benefit of reduced methane
emissions. Relatedly, the D.C. Circuit Court challenge to the October 2015 EPA regulation reducing the ambient ozone
standard from 75 parts per billion to 70 parts per billion under the Clean Air Act was put in abeyance while the EPA reviews the
regulation. Separately, the EPA in 2011 issued permitting rules for sources of greenhouse gases; however, in June 2014, the
U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision upholding these rules and struck down the EPA’s
greenhouse gas permitting rules to the extent they impose a requirement to obtain a permit based solely on emissions of
greenhouse gases. Under the Court ruling and the EPA's subsequent proposed rules, major sources of other air pollutants, such
as VOCs or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding
emissions of greenhouse gases. These proposed rules have not been finalized. The EPA has issued rules requiring reporting of
greenhouse gas, on an annual basis, for certain onshore natural gas and oil production facilities, and in October 2015, the EPA
amended and expanded those greenhouse gas reporting requirements to all segments of the oil and gas industry effective
January 1, 2016. To the extent legislation is enacted or additional regulations 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 or institute emission reduction measures; and (v) manage a greenhouse
gas emissions program. If such legislation becomes law or additional rules are promulgated in the United States or 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 EPA under the Safe Drinking
Water Act, or SDWA, fracturing is excluded from regulation unless the injection fluid is diesel fuel. The EPA has published an
interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority. The
EPA has finalized various regulatory programs directed at hydraulic fracturing. For example, in June 2016, the EPA issued
regulations under the federal Clean Water Act to further regulate wastewater discharges from hydraulic fracturing and other
natural gas production to publicly-owned treatment works. The EPA also expanded, as discussed herein, existing Clean Air Act
new source performance standards for new and modified air emissions sources, and finalized Control Techniques Guidelines
for existing sources in ozone non-attainment areas, to reduce emissions of methane or VOCs from oil and gas sources,
including drilling and production processes. The adoption of new 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 EPA has studied the potential
adverse impact that each stage of hydraulic fracturing may have on the environment; the EPA released a final assessment report
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of the potential impacts of hydraulic fracturing on drinking water resources in December 2016. 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 Oklahoma, induced seismicity from injection of fluids in wastewater disposal wells has resulted in
regulatory limitations on wastewater disposal into such wells. Under a recent settlement agreement, the EPA will decide by
March 2019 whether to initiate rulemaking governing the disposal of wastewater from oil and gas development. The
implementation of rules relating to hydraulic fracturing could result in increased expenditures for our exploration and
production customers, which could cause them to reduce their production and thereby result in reduced demand for our services
by these customers.
On March 28, 2017, President Trump issued Executive Order 13783 entitled “Promoting Energy Independence and
Economic Growth.” Executive Order 13783 directed executive departments and agencies to review regulations that potentially
burden the development or use of domestically produced energy resources and, as appropriate, suspend, revise, or rescind those
that unduly burden domestic energy resources development. On March 26, 2015, the federal Bureau of Land Management
(“BLM”) finalized regulations requiring disclosure of chemicals used in hydraulic fracturing activities upon Native American
Indian and other federal lands, and added requirements on the use of hydraulic fracturing techniques and management of
produced water on these lands. The rule was never implemented due to court challenges. On December 29, 2017, the BLM
rescinded the rule. On November 18, 2016, the BLM finalized regulations to, among other things, curtail the flaring during the
production of natural gas and oil on Native American Indian and other federal lands, which affects how hydraulically fractured
wells are developed and operated. The U.S. District Court denied a preliminary injunction sought by industry groups and the
regulation went into effect on January 17, 2017; however, on December 8, 2017, the BLM finalized a rule suspending or
delaying many of the provisions of the regulation while it reviews the regulation. Our customers will continue to be subject to
uncertainty associated with new regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory
mandates, which could adversely affect their production and thereby result in reduced demand for our services by these
customers.
Construction of new assets is subject to regulatory, environmental, political, legal, economic, civil protest, 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, legal, and economic uncertainties beyond our control
and may require the expenditure of significant amounts of capital. For example, public participation in review and permitting
processes can introduce uncertainty and additional costs associated with project timing and completion. Relatedly, civil protests
regarding environmental and social issues, including construction of infrastructure associated with fossil fuels, may lead to
increased legislative and regulatory initiatives and review at federal, state, and local levels of government that could prevent or
delay the construction of such infrastructure and realization of associated revenues. 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.
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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. Additionally, a decline in the availability of credit to producers in and surrounding
our geographic footprint could decrease the level of capital investment and growth that would otherwise bring new volumes to
our existing assets and facilities.
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
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 may not be able to grow or effectively manage our growth.
Historically, a principal focus of our strategy was to continue to grow the per unit distribution on our units by expanding
our business. The Transaction resulted in significant growth of the Partnership, but also in the loss of certain future drop down
opportunities from DCP Midstream, LLC. 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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complete construction projects and consummate accretive acquisitions or joint ventures;
identify businesses engaged in managing, operating or owning pipelines, processing and storage assets or other
midstream assets for acquisitions, joint ventures and 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.
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A deficiency in any of these factors could adversely affect our ability to sustain 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, in recent years we have grown through organic
projects, dropdowns and acquisitions. If we fail to properly integrate these assets successfully with our existing operations, if
the future performance of these assets does not meet our expectations, if we did not properly value the assets, or we did not
identify significant liabilities associated with acquired assets, the anticipated benefits from these transactions may not be fully
realized.
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.
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.
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.
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 our
unitholders.
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, 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;
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 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 Credit Agreement and the indentures governing our notes;
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 various joint ventures, 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 ventures in which we have a partial
ownership interest may mean that we will not receive the amount of cash we expect to be distributed to us. In addition, for joint
ventures 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 joint ventures, including
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decisions with respect to incurrence of expenses and distributions to us;
these joint ventures may establish reserves for working capital, capital projects, environmental matters and legal
proceedings which would otherwise reduce cash available for distribution to us;
these joint ventures may incur additional indebtedness, and principal and interest made on such indebtedness may
reduce cash otherwise available for distribution to us; and
these joint ventures 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 our unitholders 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.
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 to 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;
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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.
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorist attacks, the threat of
terrorist attacks, sustained military campaigns 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.
We face the threat of future terrorist attacks on both our industry in general and on us, including the possibility that
infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. The increased security measures we
have taken as a precaution against possible terrorist attacks have resulted in increased costs to our business. Any physical
damage to facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to
expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect our business and
cash flows. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult
for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing
insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise
capital.
The amount of natural 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 natural 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.
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 all of its
executive officers are directors or executive 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;
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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;
• DCP Midstream, LLC and its affiliates, including Phillips 66 and Enbridge, 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;
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;
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.
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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 and Employee Secondment Agreement, or the Services Agreement,
between us and DCP Midstream, LLC prohibits DCP Midstream, LLC and its affiliates, including Phillips 66 and Enbridge,
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 Enbridge, 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 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, DCP Midstream, LLC and its affiliates 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
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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
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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
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 our unitholders 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
common units is required to remove the general partner. As of December 31, 2017, our general partner and its affiliates owned
approximately 36% of our outstanding common units.
Our Partnership Agreement restricts the voting rights of our unitholders owning 20% or more of any class of our 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 certain equity investments, such as minority ownership interests in joint ventures, which may be deemed
to be “investment securities” within the meaning of the Investment Company Act of 1940, as amended (the "Investment
Company Act"). 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
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income tax at the corporate tax rate, which could significantly reduce 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 forgo 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, under our Partnership Agreement the owners of our general
partner may pledge, impose a lien or transfer all or a portion of their respective ownership interest in our general partner to a
third party. Any 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 generally issue additional units, including units that are senior to our common units, without our unitholders’
approval, which would dilute our unitholders’ existing ownership interests.
Our Partnership Agreement does not limit the number of additional common units that we may issue at any time without
the approval of our unitholders. The issuance by us of additional common units, preferred units, or other equity securities of
equal or senior rank will have the following effects:
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our unitholders’ proportionate ownership interest in us will decrease, including a relative dilution of any voting
rights;
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.
We are prohibited from paying distributions on our common units if distributions on our Series A Preferred Units are in
arrears.
The holders of our Series A Preferred Units are entitled to certain rights that are senior to the rights of holders of common
units, such as rights to distributions and rights upon liquidation of the Partnership. If we do not pay the required distributions on
our Series A Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions to
our Series A Preferred Unitholders are cumulative, we will have to pay all unpaid accumulated preferred distributions before we
can pay any distributions to our common unitholders. Also, because distributions to our common unitholders are not
cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be
entitled to receive distributions covering any prior periods if we later commence paying distributions on our common units. The
preferences and privileges of the Series A Preferred Units could adversely affect the market price for our common units, or
could make it more difficult for us to sell our common units in the future.
Our Series A Preferred Units are subordinated to our existing and future debt obligations, and your interests could be
diluted by the issuance of additional units, including additional Series A Preferred Units, and by other transactions.
The Series A Preferred Units are subordinated to all of our existing and future indebtedness. The payment of principal and
interest on our debt reduces cash available for distribution to our limited partners, including the holders of Series A Preferred
Units. The issuance of additional units on parity with or senior to the Series A Preferred Units (including additional Series A
Preferred Units) would dilute the interests of the holders of the Series A Preferred Units, and any issuance of equal or senior
ranking securities or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation
preference on the Series A Preferred Units.
We distribute all of our available cash to our common unitholders and are not required to accumulate cash for the purpose
of meeting our future obligations to holders of the Series A Preferred Units, which may limit the cash available to make
distributions on the Series A Preferred Units.
Our Partnership Agreement requires us to distribute all of our “available cash” each quarter to our common unitholders.
“Available cash” is defined in our Partnership Agreement and described below under “Item 5. Market for Registrant’s Common
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Equity, Related Unitholder Matters and Issuer Purchases of Common Units—Distributions of Available Cash—Definition of
Available Cash.” As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount
of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make
payments on the Series A Preferred Units.
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 common 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 common
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 common unitholders may also incur a tax liability upon a sale of their common 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 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.
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.
40
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 21% for taxable years beginning after December 31, 2017, 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 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 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 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 that allows publicly traded partnerships that generate qualifying income to
be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business
activities, or affect the tax consequences of an investment in our units. The U.S. Treasury Department issued final regulations
interpreting the scope of activities that generate qualifying income under Section 7704 of the Internal Revenue Code of 1986,
as amended, or the Code. We believe that the income we currently treat as qualifying income satisfies the requirements for
qualifying income under the final regulations.
Recently enacted legislation provides a deduction to a non-corporate common unitholder, for taxable years beginning after
December 31, 2017 and ending on or before December 31, 2025, equal to 20% of his or her allocable share of our “qualified
business income.” For purposes of this deduction, our “qualified business income” is equal to the sum of the net amount of our
items of income, gain, deduction and loss to the extent such items are included or allowed in the determination of taxable
income for the year, excluding, however, certain specified types of passive investment income (such as capital gains and
dividends); and any gain recognized upon a disposition of our units to the extent such gain is attributable to certain assets, such
as depreciation recapture and our “inventory items,” and is thus treated as ordinary income under Section 751 of the Code. This
legislation also includes certain new limitations on the use of losses and other deductions to offset taxable income. Various
aspects of this deduction and these limitations may be modified by administrative, legislative or judicial interpretations at any
time, which may or may not be applied retroactively.
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, which would reduce the cash
available for distribution to our unitholders. For example, we are required to pay the State of Texas a margin tax that is assessed
at 0.75% of taxable margin apportioned to Texas. 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.
41
If tax authorities contest the tax positions we take, the market for our units may be adversely impacted, and the cost of any
contest with a tax authority would 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.
Tax authorities may adopt positions that differ from the conclusions of our counsel or from the positions we take, and the tax
authority'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 positions we take. Any contest with a tax authority, and the outcome of any such contest, may increase a
unitholder’s tax liability and result in adjustment to items unrelated to us and could materially and adversely impact the market
for our units and the price at which they trade. In addition, our costs of any contest with any tax authority will be borne
indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.
For taxable years beginning after December 31, 2017, the procedures for auditing large partnerships and the procedures for
assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit have changed. Unless we
are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted
return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in
which the audit is completed under the new procedures. If we are required to pay taxes, penalties and interest as the result of
audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment
would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense
of the adjustment even if they were not unitholders during the audited taxable year.
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.
Certain actions that we may take, such as issuing additional units, may increase the federal income tax liability of
unitholders.
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 our assets.
Tax gain or loss on disposition of common units could be more or less than expected.
If a unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the
amount realized and the unitholder's tax basis in those common units. Because distributions to a unitholder in excess of the total
net taxable income allocated to it for a common unit decreases its tax basis in that common unit, the amount, if any, of such
prior excess distributions with respect to the units sold will, in effect, become taxable income to the unitholder 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.
42
Tax-exempt entities and non-U.S. persons face unique tax issues from owning units that may result in adverse tax
consequences to them.
Investment in 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 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. Gain
recognized from a sale or other disposition of our units by a non-U.S. person will be subject to federal income tax as income
effectively connected with a U.S. trade or business. Moreover, the transferee of our units is generally required to withhold 10%
of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to
deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld.
Because the “amount realized” includes a partner's share of the partnership's liabilities, 10% of the amount realized could
exceed the total cash purchase price for the units. However, the IRS has suspended the application of this withholding rule to
open market transfers of interest in publicly traded partnerships, pending promulgation of regulations or other guidance that
address the amount to be withheld, the reporting necessary to determine such amount and the appropriate party to withhold
such amounts. It is not clear if or when such regulations or other guidance will be issued.
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 units.
We 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 have adopted
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
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 U.S. Treasury Department has adopted final 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. These regulations do not specifically authorize the proration method we have previously used. 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.
43
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 be required to 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 be required to 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 and lending 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
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 our units may have a greater portion of their adjustment under Section 743(b) of the Code 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 our units and could have
a negative impact on the value of our units or result in audit adjustments to our unitholders’ tax returns without the benefit of
additional deductions.
Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different
tax treatment for the holders of Series A Preferred Units than the holders of our common units.
The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of our Series A
Preferred Units as partners for tax purposes and will treat distributions on our Series A Preferred Units as guaranteed payments
for the use of capital that will generally be taxable to the holders of our Series A Preferred Units as ordinary income and will
not be eligible for the deduction provided for under Code Section 199A. Although a holder of our Series A Preferred Units
could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous
distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually through and including
December 15, 2022 and quarterly thereafter. Because the guaranteed payment for each unit must accrue as income to a holder
during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15 and ending
December 31 will accrue as income to the holder of record of a Series A Preferred Unit on December 31 for such period,
regardless of whether such holder continues to own the Series A Preferred Unit at the time the actual distribution is made.
Otherwise, the holders of our Series A Preferred Units are generally not anticipated to share in our items of income, gain, loss
or deduction, except to the extent necessary to provide, to the extent possible, the Series A Preferred Units with the benefit of
the liquidation preference. We will not allocate any share of our nonrecourse liabilities to the holders of our Series A Preferred
Units. If our Series A Preferred Units were treated as indebtedness for tax purposes, rather than as partnership interests,
distributions on our Series A Preferred Units likely would be treated as payments of interest by us to the holders of our Series A
Preferred Units, rather than as guaranteed payments for the use of capital.
A holder of our Series A Preferred Units will be required to recognize gain or loss on a sale of its Series A Preferred Units
equal to the difference between the amount realized by such holder and tax basis in the Series A Preferred Units sold. The
amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in
exchange for such Series A Preferred Units. Subject to general rules requiring a blended basis among multiple partnership
interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of
other property paid by the holder of the Series A Preferred Unit to acquire such Series A Preferred Unit. Gain or loss recognized
by a holder of a Series A Preferred Unit on the sale or exchange of a Series A Preferred Unit held for more than one year
generally will be taxable as long-term capital gain or loss. Because holders of our Series A Preferred Units will generally not be
44
allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be
required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.
Unitholders may be subject to state and local taxes and return filing requirements in states where they do not live 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 do 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. Our counsel has not
rendered an opinion on the foreign, state or local tax consequences of an investment in our units.
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 Item 1.
"Business - Our Operating Segments”. 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 303-595-3331 and our website address is www.dcpmidstream.com.
Item 3. Legal Proceedings
We are not a party to any 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 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.”
Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating,
fractionating, 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 laws and
regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and
hazardous 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, worker safety
standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) city, state and
federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of
this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii)
from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and
increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse
gases which could impose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and
communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other
45
facilities used in our business. Failure to comply with these various health, safety and environmental 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 existing
laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
PART II
Market Information
Our common units are listed on the New York Stock Exchange ("NYSE") under the symbol "DCP". 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 2017 and 2016.
Quarter Ended
High
Low
Distribution
Per Common
Unit
December 31, 2017
September 30, 2017
June 30, 2017
March 31, 2017
December 31, 2016
September 30, 2016
June 30, 2016
March 31, 2016
38.03
36.10
40.29
42.45
39.43
36.21
38.15
28.53
32.08
29.95
29.70
35.64
31.03
31.23
24.70
15.09
0.78
0.78
0.78
0.78
0.78
0.78
0.78
0.78
As of February 22, 2018, there were approximately 40 unitholders of record of our common units. This number does not
include unitholders whose common units are held in trust by other entities.
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 the date of
determination of available cash for that quarter:
•
less the amount of cash reserves established by our general partner to:
•
•
•
•
provide for the proper conduct of our business, including reserves for future capital expenditures and
anticipated credit needs;
comply with applicable law or any debt instrument or other agreement or obligation;
provide funds to make payments on the 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units; or
provide funds for distributions to our common 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 $0.78 per unit, or $3.12 per unit
46
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 - Liquidity and Capital Resources” 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, 2017, the General Partner was entitled
to a percentage of all quarterly distributions equal to its General Partner interest of approximately 2% and limited partner
interest of 36%. 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 have not been reduced as a result of
our 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.
As part of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions
payable to our General Partner under our Partnership Agreement of up to $100 million annually through 2019 to target an
approximate 1.0 times distribution coverage ratio. Under the terms of our amended Partnership Agreement, the amount of
incentive distributions paid to our General Partner will be evaluated by our General Partner on both a quarterly and annual basis
and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If no determination is
made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback, of up to $100 million
annually, will be subject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our
amended Partnership Agreement) less the total annual distribution payable to our unitholders, adjusted to target an approximate
1.0 times coverage ratio.
Please read the Distributions of Available Cash section in Note 14 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 23, 2018, we announced that the board of directors of DCP Midstream GP, LLC declared a quarterly
distribution of $0.78 per unit, which was paid on February 14, 2018, to unitholders of record on February 7, 2018.
Preferred Unit Distributions - On November 20, 2017, we issued 500,000 of our Series A Preferred Units ("Series A
Preferred Units"), representing limited partnership interests at a price of $1,000 per unit. We used the net proceeds of $487
million from the issuance of the Series A Preferred Units to partially repay the $500 million 2.50% Senior Notes which were
due on December 1, 2017.
Distributions of the Series A Preferred Units are payable out of available cash, accrue and are cumulative from the date of
original issuance of the Series A Preferred Units and are payable in arrears on June 15th and December 15th through and
including December 15, 2022, and, after December 15, 2022, quarterly in arrears on March 15th, June 15th, September 15th,
and December 15th of each year to holders of record as of the close of business on the first business day of the month. The
initial distribution rate will be 7.375% per year of the $1,000 liquidation preference per unit (equal to $73.75 per unit). On and
after December 15, 2022, distributions will accumulate at a percentage of the $1,000 liquidation preference equal to an annual
floating rate of the three-month LIBOR plus a spread of 5.148%. The Series A Preferred Units rank senior to our common units
with respect to distribution rights and rights upon liquidation.
At any time prior to December 15, 2022, within 120 days of a ratings event (as described in our Partnership Agreement),
we may, at our option, redeem the Series A Preferred Units in whole, but not in part, at a redemption price per unit equal to
$1,020 (102% of the liquidation preference), plus an amount equal to all accumulated and unpaid distributions. At any time on
or after December 15, 2022, we may redeem, in whole or in part, the units at a redemption price of $1,000 per unit, plus an
amount equal to all accumulated and unpaid distributions. Upon occurrence of a change in control triggering event (as
described in our Partnership Agreement), we may, at our option, (i) redeem the Series A Preferred Units, in whole or in part,
within 120 days, by paying $1,000 per unit, plus all accumulated and unpaid distributions, and (ii) each holder of Series A
Preferred Units will have the right (unless the Partnership provided notice of its election to redeem such holder’s Series A
47
Preferred Units) to convert some or all of the Series A Preferred Units held by such holder on the change of control conversion
date into a number of the Partnership’s common units per Series A Preferred Unit as defined in our Partnership Agreement.
Holders of the Series A Preferred Units have no voting rights except for limited protective voting rights set forth in our
Partnership Agreement.
Securities Authorized for Issuance Under 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
our consolidated financial statements. The information contained 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. The table should also be read
together with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The following table shows our selected financial and operating data for the periods and as of the dates indicated, which is
derived from our consolidated financial statements.
48
Statements of Operations Data:
Sales of natural gas, NGLs and condensate
$
7,850
$
6,269
$
6,779
$
13,420
$
11,539
Year Ended December 31,
2017
2016
2015
2014
2013
(millions, except per unit amounts)
Transportation, processing and other
Trading and marketing (losses) gains, net
Total operating revenues
Operating costs and expenses:
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense (income), net
(Gain) loss on sale of assets, net
Restructuring costs
Total operating costs and expenses
Operating income (loss)
Interest expense
Earnings from unconsolidated affiliates (a)
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Net income attributable to noncontrolling interests
Net income (loss) attributable to partners
Net loss (income) attributable to predecessor operations (b)
General partner interest in net income
Series A preferred limited partners' interest in net income
Net income allocable to limited partners
Net income per limited partner unit-basic and diluted
$
$
661
379
290
48
11
(34)
—
8,240
222
(289)
303
236
(2)
234
(5)
229
—
(164)
(4)
61
0.43
$
$
652
647
(40)
8,462
(23)
6,893
532
119
7,430
517
88
463
36
14,025
12,038
6,885
5,461
5,981
11,828
9,967
670
378
292
—
(65)
(35)
13
732
377
281
912
10
(42)
11
773
348
277
18
7
7
—
691
314
280
—
—
(22)
—
6,714
8,262
13,258
11,230
179
(321)
282
140
(46)
94
(6)
88
224
(124)
—
188
1.64
$
$
(832)
(320)
184
(968)
102
(866)
(5)
(871)
1,099
(124)
—
104
0.91
$
$
767
(287)
82
562
(11)
551
(4)
547
(130)
(114)
—
303
2.84
Balance Sheet Data (at period end):
Property, plant and equipment, net
Total assets
Accounts payable
Long-term debt
Partners’ equity
Predecessor equity
Noncontrolling interests
Total equity
Other Information:
Cash distributions declared per unit
Cash distributions paid per unit
Year Ended December 31,
2017
2014
2015
2016
(millions, except per unit amounts)
$
$
$
$
$
$
$
$
$
$
8,983
13,878
1,076
4,707
7,408
$
$
$
$
$
— $
$
30
$
7,438
9,069
13,611
735
4,907
2,601
4,220
32
6,853
3.1200
3.1200
$
$
3.1200
3.1200
$
$
$
$
$
$
$
$
$
$
9,428
13,885
545
5,669
2,772
4,287
33
7,092
3.1200
3.1200
$
$
$
$
$
$
$
$
$
$
9,537
13,628
977
5,191
2,993
2,189
33
5,215
3.0525
3.0050
(a) 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.
49
808
(249)
35
594
(10)
584
(5)
579
(404)
(70)
—
105
1.34
2013
8,420
12,684
1,413
4,925
1,945
2,410
34
4,389
2.8630
2.8200
$
$
$
$
$
$
$
$
$
$
$
$
(b) Includes net (loss) income attributable to the DCP Midstream Business prior to the date of our acquisition from DCP
Midstream, LLC. For additional details, please read Footnote 1 in Item 8. "Financial Statements" in this Annual
Report on Form 10-K.
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 on Form 10-K.
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 two reportable segments: (i)
Gathering and Processing and (ii) Logistics and Marketing. Our Gathering and Processing segment consists of gathering,
compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate. Our Logistics
and Marketing segment includes transporting, trading, marketing and storing natural gas and NGLs, fractionating NGLs and
wholesale propane logistics.
50
General Trends and Outlook
We anticipate our business will 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.
Our business is impacted by commodity prices and volumes. We mitigate a portion of commodity price risk on an overall
Partnership basis by growing our fee based assets and by executing on our hedging program, in which we hedge commodity
prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and
Processing segment. Various factors impact both commodity prices and volumes, and as indicated in Item 7A. "Quantitative and
Qualitative Disclosures about Market Risk," we have sensitivities to certain cash and non-cash changes in commodity prices.
Drilling activity levels vary by geographic area; we will continue to target our strategy in geographic areas where we expect
producer drilling activity.
In the long-term, our belief is that commodity prices will be at levels we believe will support growth in natural gas,
condensate and NGL production. We expect future commodity prices will be influenced by the severity of winter and summer
weather, the level of North American production and drilling activity by exploration and production companies and the balance
of trade between imports and exports of liquid natural gas, NGLs and crude oil.
NGL prices are impacted by the demand from petrochemical and refining industries and export facilities. The
petrochemical industry has been making significant investment in building and expanding facilities to convert chemical plants
from a heavier oil-based feedstock to lighter NGL-based feedstocks, including ethane. We believe this will cause increased
demand in the next year, which should provide support for the increasing supply of ethane. As these facilities commence
operations, ethane prices could remain weak with supply in excess of demand. In addition, export facilities are being expanded
and built, which provide support for the increasing supply of NGLs. Although there can be, and has been, volatility in NGL
prices, longer term we believe there will be sufficient demand in NGLs to support increasing supply.
We believe our contract structure with our producers provides us with significant protection from credit risk since we
generally hold the product, sell it and withhold our fees prior to remittance of payments to the producer. Currently, our top 20
producers account for a majority of the total natural gas that we gather and process and of these top 20 producers, eight have
investment grade credit ratings while the remainder do not.
In addition to the U.S. financial markets, many businesses and investors continue to monitor global economic conditions.
Uncertainty abroad may contribute to volatility in domestic financial and commodity markets.
We believe we are positioned to withstand current and future commodity price volatility as a result of the following:
• Our growing fee-based business represents a significant portion of our margins.
• We have positive operating cash flow from our well-positioned and diversified assets.
• We have a well-defined and targeted hedging program.
• We manage our disciplined capital growth program with a significant focus on fee-based agreements and projects
with long term volume outlooks.
• We believe we have a solid capital structure and balance sheet.
• We believe we have access to sufficient capital to fund our growth.
During 2018, our strategic objectives will continue to focus on maintaining stable Distributable Cash Flows from our
existing assets and executing on opportunities to sustain and ultimately grow 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 hedged commodity position, the objective of which is
to protect against downside risk in our Distributable Cash Flows.
We have engaged in a disciplined growth strategy in recent years focusing on our key areas of operations. Our targeted
strategy may take numerous forms such as organic build opportunities within our footprint, joint venture opportunities, and
acquisitions. Growth opportunities will be evaluated in cooperation with producers and customers based on the expected level
of drilling activity in these geographic regions and the impacts of higher costs of capital.
51
Some of our growth projects include the following:
• Within our Gathering and Processing segment, we increased capacity in the DJ Basin by up to 40 MMcf/d starting
in June 2017 by placing additional field compression and plant bypass infrastructure in service.
• We are constructing a 200 MMcf/d natural gas processing plant, the Mewbourn 3 plant, and further expanding our
Grand Parkway gathering system, both of which are located in the DJ Basin and expected to be in service in the
third quarter of 2018.
• Our 200 MMcf/d O'Connor 2 plant and associated gathering infrastructure, located in the DJ Basin, is also
approved and expected to be in service in 2019. Engineering and permitting are underway, and we have begun
purchasing equipment for the construction of the plant.
• Within our Logistics and Marketing segment, we have completed the expansion of the Sand Hills pipeline to 365
MBbls/d.
•
Further Sand Hills pipeline expansion to 450 MBbls/d is progressing and includes a partial looping of the pipeline
and the addition of new pump stations, and is expected to be in service in the second half of 2018.
• We executed definitive joint venture agreements on our 25% interest in the joint development of the Gulf Coast
Express pipeline project, or the "GCX project". The approximately $1.75 billion GCX project is designed to
transport up to 1.98 Bcf/d of natural gas. The gas takeaway pipeline is expected to be in service in 2019, pending
regulatory approvals.
• We are jointly developing the Cheyenne Connector pipeline (“Cheyenne Connector”) with Tallgrass Energy
Partners, LP (operator), and Western Gas Partners, LP and hold an option to invest in this project at a later date.
Cheyenne Connector will provide gas takeaway for the DJ Basin, connecting to the Rockies Express Pipeline's
Cheyenne Hub where it can then be delivered to numerous demand markets across the country. It will have an
initial capacity of at least 600 MMcf/day and is expected to be in service in the second half of 2019, subject to
certain conditions, including required approvals from the Federal Energy Regulatory Commission.
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2018 plan includes
maintenance capital expenditures of between $100 million and $120 million, and expansion capital expenditures between $650
million and $750 million associated with approved projects. Expansion capital expenditures include the construction of the
Mewbourn 3 plant, Grand Parkway Phase 2 and O'Connor bypass in our DJ Basin system, and the capacity expansions of the
Sand Hills pipeline, which are shown as an investment in unconsolidated affiliates in our consolidated statements of cash flows.
Our 2018 earnings from unconsolidated affiliates and distributions from unconsolidated affiliates from our investment in
Discovery in our Gathering and Processing segment are forecasted to be lower than 2017 by approximately $60 million to $70
million. Approximately $30 million to $40 million of this decrease is associated with significant volume declines from two
offshore wells and an additional $30 million is associated with a contractual dispute with certain producers regarding demand
charges, which is being challenged by Discovery.
Recent Events
On November 20, 2017, we issued 500,000 of our Series A Preferred Units representing limited partnership interests at a
price of $1,000 per unit. We used the net proceeds of $487 million from the issuance of the Series A Preferred Units to partially
repay the $500 million 2.50% Senior Notes which were due on December 1, 2017.
We announced a quarterly distribution of $0.78 per unit for the fourth quarter of 2017. This distribution per common unit
remains unchanged from the previous quarter and the fourth quarter of 2016.
On February 14, 2018, the Partnership distributed $40 million of IDR givebacks to our owners, in conjunction with the
quarterly distribution, that were previously withheld under the amended Partnership agreement.
52
Factors That May Significantly Affect Our Results
Gathering and Processing Segment
Our results of operations for our Gathering and Processing segment are impacted by (1) the prices of and relationship
between commodities such as NGLs, crude oil and natural gas, (2) increases and decreases in the wellhead volume and quality
of natural gas that we gather, (3) the associated Btu content of our system throughput and our related processing volumes, (4)
the operating efficiency and reliability of our processing facilities, (5) potential limitations on throughput volumes arising from
downstream and infrastructure capacity constraints, and (6) the terms of our processing contract arrangements with producers.
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.
Volume 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.
Volume 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 the commodity pricing environment at the time the contract is executed,
natural gas quality, geographic location, 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. We generate our revenues and our gross margin for our Gathering and Processing segment
principally from contracts that contain a combination of fee based arrangements and percent-of-proceeds/liquids arrangements.
Our Gathering and Processing 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 drilling activity, which may be impacted by prevailing commodity prices. The number of
active oil and gas drilling rigs in the United States has increased, from 563 on December 31, 2016 to 882 on December 31,
2017 (Source: IHS). 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 for 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 Item 7A in this
2017 Form 10-K, “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.
We face strong competition in acquiring raw natural gas supplies. Our competitors in obtaining additional gas supplies
and in gathering and processing raw natural gas 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.
Logistics and Marketing Segment
Our Logistics and Marketing 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 Gathering and Processing segment, may also impact the
throughput and volume for our Logistics and Marketing segment.
53
These contractual arrangements may require our customers to commit a minimum level of volumes to our pipelines and
facilities, thereby mitigating our exposure to volume risk. However, 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. 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.
Our results of operations for our Logistics and Marketing segment are also impacted by 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. 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 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.
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. 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.
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 operations and limiting our ability to support or fund our operations and growth. 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.
54
Other
The above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline
in our common 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.
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 wellhead, throughput and storage volumes 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.
55
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the years ended
December 31, 2017, 2016 and 2015. The results of operations by segment are discussed in further detail following this
consolidated overview discussion.
Year Ended December 31,
Variance 2017 vs. 2016
Variance 2016 vs. 2015
2017
2016
2015
Increase
(Decrease)
Percent
Increase
(Decrease)
Percent
(millions, except operating data)
Operating revenues (a):
Gathering and Processing
$
5,467
$ 4,490
$
4,910
$
Logistics and Marketing
Inter-segment eliminations
Total operating revenues
Purchases and related costs
Gathering and Processing
Logistics and Marketing
Inter-segment eliminations
Total purchases
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other (expense) income, net
Gain on sale of assets, net
Restructuring costs
Earnings from unconsolidated
affiliates (b)
Interest expense
Income tax (expense) benefit
Net income attributable to
noncontrolling interests
Net income (loss) attributable to
partners
Other data:
Gross margin (c):
Gathering and Processing
Logistics and Marketing
Total gross margin
Non-cash commodity derivative
mark-to-market
Natural gas wellhead (MMcf/d)
(d)
NGL gross production (MBbls/d)
(d)
NGL pipelines throughput
(MBbls/d) (d)
* Percentage change is not meaningful.
$
$
$
$
7,757
6,186
(4,762)
(3,783)
8,462
6,893
(4,090)
(3,263)
(7,557)
(5,981)
4,762
3,783
(6,885)
(5,461)
(661)
(379)
(290)
(48)
(11)
34
—
303
(289)
(2)
(5)
(670)
(378)
(292)
—
65
35
(13)
282
(321)
(46)
(6)
6,487
(3,967)
7,430
(3,697)
(6,251)
3,967
(5,981)
(732)
(377)
(281)
(912)
(10)
42
(11)
184
(320)
102
977
1,571
(979)
1,569
827
1,576
(979)
1,424
(9)
1
(2)
48
(76)
(1)
(13)
21
(32)
(44)
22 % $
25 %
(26)%
23 %
25 %
26 %
(26)%
26 %
(1)%
— %
(1)%
*
*
(3)%
*
7 %
(10)%
(96)%
(420)
(301)
184
(537)
(434)
(270)
184
(520)
(62)
1
11
(912)
75
(7)
2
98
1
(148)
(9)%
(5)%
5 %
(7)%
(12)%
(4)%
5 %
(9)%
(8)%
— %
4 %
*
*
(17)%
18 %
53 %
— %
*
20 %
(5)
(1)
(17)%
1
229
$
88
$
(871) $
141
*
$
959
*
1,377
$ 1,227
200
205
1,577
$ 1,432
$
$
1,213
236
1,449
$
$
150
(5)
145
12 % $
(2)%
10 % $
14
(31)
(17)
1 %
(13)%
(1)%
(28) $ (139) $
46
$
111
*
$
(185)
*
4,531
5,124
5,604
(593)
(12)%
(480)
(9)%
(4)%
(18)
(5)%
(15)
40
10 %
122
41 %
375
460
393
420
408
298
56
(a) Operating revenues include the impact of trading and marketing gains (losses), net.
(b) Earnings for Discovery, Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the
amortization of the net difference between the carrying amount of the investments and the underlying equity of the
entities.
(c) Gross margin consists of total operating revenues less purchases and related costs. Segment gross margin for each
segment consists of total operating revenues for that segment less purchases and related costs for that segment. Please
read “Reconciliation of Non-GAAP Measures”.
(d) For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead and
throughput volumes and NGL production.
Year ended December 31, 2017 vs. Year ended December 31, 2016
Total Operating Revenues — Total operating revenues increased $1,569 million in 2017 compared to 2016 primarily as a
result of the following:
•
•
$1,571 million increase for our Logistics and Marketing segment primarily due to increased commodity prices and
favorable commodity derivative activity, partially offset by lower gas and NGL sales volumes and the sale of our
Northern Louisiana System;
$977 million increase for our Gathering and Processing segment primarily due to higher commodity prices, higher
gas and NGL sales volumes primarily related to our North region which impacts both sales and purchases, and
higher transportation, processing and other, primarily related to fee based contract realignment efforts. These
increases were partially offset by lower gas and NGL sales volumes in the South, Midcontinent and Permian
regions, unfavorable commodity derivative activity and the sale of our Northern Louisiana system and Douglas
gathering system;
These increases were partially offset by:
•
$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our
Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity
prices, partially offset by lower gas and NGL sales volumes.
Total Purchases — Total purchases increased $1,424 million in 2017 compared to 2016 primarily as a result of the
following:
•
•
•
$1,576 million increase for our Logistics and Marketing segment for the reasons discussed above;
$827 million increase for our Gathering and Processing segment for the reasons discussed above;
These increases were partially offset by:
$979 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our
Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity
prices, partially offset by lower gas and NGL sales volumes.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 2016
primarily as a result of the sale of our Northern Louisiana system in July 2016 and Douglas gathering system in June 2017,
decreased base operating costs resulting from cost savings initiatives, partially offset by increased gathering pipeline
remediation spending, planned maintenance spending associated with anticipated volume growth and additional expenses
related to Hurricane Harvey.
General and Administrative Expense - General and administrative expense increased in 2017 compared to 2016, primarily
due to investment in digital transformation, offset by nonrecurring costs in 2016 driven by the closing of the Transaction as
described in Item 8. "Financial Statements."
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and
intangible assets in our South region.
Other (Expense) Income — Other expense in 2017 primarily represents the write-off of property, plant and equipment
associated with the expiration of a lease. Other income in 2016 primarily represents a producer settlement, net of legal fees,
partially offset by the write-off of property, plant and equipment and other long-term assets.
57
Gain on Sale of Assets, net — The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on
sale in 2016 represents the sale of our Northern Louisiana system, partially offset by a loss on sale of non-core assets.
Restructuring Costs - Restructuring costs in 2016 related to our headcount reduction in April of 2016.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016
primarily as a result of the expansion and volume ramp up of the Sand Hills NGL pipeline in our Logistics and Marketing
segment partially offset by a decrease from Discovery in our Gathering and Processing segment primarily due to lower
production volumes from two offshore wells at Discovery. We expect continued volume declines from these wells to impact
future earnings.
Interest Expense - Interest expense decreased in 2017 compared to 2016 as a result of lower average outstanding debt
balances.
Income Tax (Expense) Benefit — Income tax expense decreased in 2017 compared to 2016 primarily due to the
conversion of a subsidiary from a corporation to a limited liability company for federal income tax purposes in 2016.
Net Income Attributable to Partners — Net income attributable to partners increased in 2017 compared to 2016 for the
reasons discussed above.
Gross Margin — Gross margin increased $145 million in 2017 compared to 2016 primarily as a result of the following:
•
•
$150 million increase for our Gathering and Processing segment primarily related to higher commodity prices,
increased volume from growth projects, higher margins associated with a specific producer arrangement, higher
NGL recoveries and a producer settlement in our North region, and contract realignment efforts in our Permian
and Midcontinent regions. These increases were partially offset by lower volumes across our South,
Midcontinent, and Permian regions due to reduced drilling activity in prior periods, the impact of Hurricane
Harvey primarily in the South and Permian regions, the sale of our Northern Louisiana system, the sale of our
Douglas gathering system and unfavorable commodity derivative activity.
These increases were partially offset by:
$5 million decrease for our Logistics and Marketing segment primarily related to lower margins on wholesale
propane and the expiration of a contract, the sale of our Northern Louisiana system, lower gas storage margins
and lower transportation volumes on certain of our NGL pipelines, partially offset by higher NGL marketing
margins, higher gas marketing margins and favorable commodity derivative activity.
Year ended December 31, 2016 vs. Year ended December 31, 2015
Total Operating Revenues — Total operating revenues decreased $537 million in 2016 compared to 2015 primarily as a
result of the following:
•
•
$420 million decrease for our Gathering and Processing segment primarily due to lower commodity prices, lower
gas and NGL volumes in the South, Midcontinent and Permian regions which impacted both sales and purchases,
and unfavorable commodity derivative activity, which was partially offset by higher gas and NGL volumes in our
North region and fee based contract realignment efforts; and improved operational efficiencies in the Permian and
Midcontinent regions; and
$301 million decrease for our Logistics and Marketing segment primarily due to lower commodity prices, lower
gas and NGL sales volumes, unfavorable commodity derivative activity and lower wholesale propane fees partially
offset by new connections on certain of our NGL pipelines.
These decreases were partially offset by:
•
$184 million decrease in inter-segment eliminations, which related to sales of gas and NGL volumes from our
Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity
prices and lower gas and NGL sales volumes.
Total Purchases — Total purchases decreased $520 million in 2016 compared to 2015 primarily as a result of the
following:
•
$434 million decrease for our Gathering and Processing segment for the reasons discussed above; and
58
•
$270 million decrease for our Logistics and Marketing segment for the reasons discussed above.
These decreases were partially offset by:
•
$184 million decrease in inter-segment eliminations, which related to sales of gas and NGL volumes from our
Gathering and Processing segment to our Logistics and Marketing segment, primarily due to lower commodity
prices and lower gas and NGL sales volumes.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015
primarily as a result of our headcount reduction in April 2016, plant consolidations and other cost savings initiatives, the
disposition of our Northern Louisiana system in July 2016, the sale of certain gas processing plants and gathering systems in the
Permian region in 2015, partially offset by the completion of our Lucerne 2 plant in the DJ Basin system in July 2015 and the
completion of our Zia II plant in the Southeast New Mexico system in August 2015.
General and Administrative Expense — General and administrative expense increased in 2016, compared to 2015,
primarily due to nonrecurring costs driven by the closing of the Transaction as described in Item 8. "Financial Statements,"
partially offset by our headcount reduction in April 2016 and other cost savings initiatives.
Asset Impairments - Asset impairments in 2015 represented impairments of goodwill, property, plant and equipment and
intangible assets.
Other Income (Expense), net — Other income, net in 2016 represented a producer settlement net of legal fees, partially
offset by charges for discontinued construction projects. Other expense, net in 2015 primarily represented charges for
discontinued construction projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015,
primarily as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher
pipeline throughput volumes on Southern Hills, Sand Hills and Front Range due to growth in NGL production from new plants
placed into service in 2015 and as a result of the ramp-up of the Keathley Canyon volumes at Discovery.
Income Tax (Expense) Benefit — Income tax benefit decreased in 2016 compared to 2015 primarily due to impairments of
property, plant and equipment and intangible assets recorded in the fourth quarter of 2015.
Gain (loss) on Sale of Assets, Net — Gain on sale of assets during 2016 primarily related to the sale of our Northern
Louisiana system. During 2015, we recognized gains related to the sale of certain gas processing plants and gathering systems.
Net Income Attributable to Partners — Net income attributable to partners increased in 2016 compared to 2015 for the
reasons discussed above.
Gross Margin — Gross margin decreased $17 million in 2016 compared to 2015 primarily as a result of the following:
•
•
$31 million decrease for our Logistics and Marketing segment primarily related to unfavorable commodity
derivative activity, the sale of our Northern Louisiana system in July 2016 and lower wholesale propane fees,
partially offset by new connections on certain of our NGL pipelines.
These decreases were partially offset by:
$14 million increase for our Gathering and Processing segment primarily due to the ramp-up of the Lucerne 2 plant
in June 2015, completion of the Grand Parkway gathering system in January 2016, higher margins on a specific
producer arrangement, higher NGL recoveries in our North region, completion of the Zia II plant in August 2015 in
our Permian region, ramp-up of the National Helium plant in September 2015 in our Midcontinent region, fee
based contract realignment efforts and improved operational efficiencies in our Permian and Midcontinent regions,
partially offset by lower commodity prices, lower volumes across our South, Midcontinent and Permian regions
due to reduced drilling activity in prior periods, unfavorable derivative activity and the sale of our Northern
Louisiana system.
59
Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Earnings from investments in unconsolidated affiliates were as follows:
DCP Sand Hills Pipeline, LLC
Discovery Producer Services LLC
DCP Southern Hills Pipeline, LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu Enterprise Fractionator
Mont Belvieu 1 Fractionator
Other
Total earnings from unconsolidated affiliates
Year Ended December 31,
2017
2016
(Millions)
2015
$
$
148
61
47
17
9
13
6
2
303
$
$
110
73
44
19
9
16
9
2
282
$
63
54
18
17
8
15
9
—
$
184
Distributions received from unconsolidated affiliates were as follows:
2017
$
DCP Sand Hills Pipeline, LLC
Discovery Producer Services LLC
DCP Southern Hills Pipeline, LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu Enterprise Fractionator
Mont Belvieu 1 Fractionator
Other
Total distributions from unconsolidated affiliates
$
Year Ended December 31,
2016
(Millions)
2015
169
85
62
17
12
13
6
3
367
$
$
139
94
56
24
11
18
11
3
356
$
71
69
24
17
11
13
12
—
$
217
60
Results of Operations — Gathering and Processing Segment
The results of operations for our Gathering and Processing segment are as follows:
Year Ended December 31,
Variance
2017 vs. 2016
Variance
2016 vs. 2015
2017
2016
2015
Increase
(Decrease)
Percent
Increase
(Decrease)
Percent
(millions, except operating data)
$
4,943
$
3,955
$
4,377
$
988
25 % $
(422)
(10)%
Operating revenues:
Sales of natural gas, NGLs and
condensate
Transportation, processing and
other
Trading and marketing (losses)
gains, net
Total operating revenues
590
580
465
(66)
5,467
(45)
4,490
68
4,910
Purchases and related costs
(4,090)
(3,263)
(3,697)
Operating and maintenance expense
(602)
(611)
(668)
Depreciation and amortization
expense
(343)
(344)
(343)
(14)
—
73
19
73
423
(22)
(876)
(1)
42
54
(601)
(6)
(5)
417
$
(606) $
1,227
$
1,213
(24) $
(119) $
47
$
$
(19)
(48)
—
34
60
459
(5)
454
1,377
$
$
General and administrative expense
Asset impairments
Other income (expense), net
Gain on sale of assets, net
Earnings from unconsolidated
affiliates (a)
Segment net income (loss)
Segment net income attributable
to noncontrolling interests
Segment net income (loss) attributable
to partners
Other data:
Segment gross margin (b)
Non-cash commodity derivative
mark-to-market
Natural gas wellhead (MMcf/d)
(c)
NGL gross production (MBbls/d)
(c)
$
$
$
_____________
* Percentage change is not meaningful.
10
(21)
977
827
(9)
(1)
5
(48)
(73)
15
(13)
36
(1)
37
150
95
2 %
*
22 %
25 %
(1)%
— %
36 %
*
*
79 %
(18)%
9 %
(17)%
115
25 %
(113)
(420)
(434)
(57)
*
(9)%
(12)%
(9)%
1
— %
(8)
(876)
74
(36)%
*
*
(23)
(55)%
19
1,024
35 %
*
1
20 %
9 % $
1,023
*
12 % $
14
1 %
(80)% $
(166)
*
4,531
5,124
5,604
(593)
(12)%
(480)
(9)%
375
393
408
(18)
(5)%
(15)
(4)%
(a) Earnings from unconsolidated affiliates includes 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.
(b) Segment gross margin consists of total operating revenues, less purchases and related costs. Please read “Reconciliation
of Non-GAAP Measures”.
(c) For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the wellhead volume
and NGL production.
61
Year Ended December 31, 2017 vs. Year Ended December 31, 2016
Total Operating Revenues — Total operating revenues increased $977 million in 2017 compared to 2016, primarily as a
result of the following:
•
•
•
•
•
$1,280 million increase attributable to higher commodity prices, which impacted both sales and purchases, before
the impact of derivative activity;
$100 million increase attributable to higher gas and NGL sales volumes due to the impact of a specific producer
arrangement and growth projects primarily related to our DJ Basin system in our North region;
$10 million increase in transportation, processing and other primarily related to fee based contract realignment
efforts, partially offset by lower volumes in the South region and the sale of our Northern Louisiana system and
Douglas gathering system;
These increases were partially offset by:
$392 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions
due to reduced drilling activity in prior periods and the impact of Hurricane Harvey primarily related to the South
and Permian regions; and
$21 million decrease as a result of commodity derivative activity attributable to a $116 million increase in realized
cash settlement losses, partially offset by a decrease in unrealized commodity derivative losses of $95 million due
to movements in forward prices of commodities in 2017.
Purchases and Related Costs — Purchases and related costs increased $827 million in 2017 compared to 2016 as a result
of higher commodity prices and higher gas and NGL sales volumes in our North region, partially offset by decreased volumes
in our South, Midcontinent and Permian regions.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 2016
primarily as a result of the sale of our Northern Louisiana system in July 2016 and Douglas gathering system in June 2017,
decreased base operating costs resulting from cost savings initiatives, partially offset by increased gathering pipeline
remediation spending, planned maintenance spending associated with anticipated volume growth and additional expenses
related to Hurricane Harvey.
General and Administrative Expense — General and administrative expense increased in 2017 compared to 2016
primarily as a result higher sales tax refunds in 2016 from cost savings initiatives.
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and
intangible assets in our South region.
Other Income (Expense) — Other income in 2016 represents a producer settlement, net of legal fees partially offset by the
write-off of property, plant and equipment.
Gain on sale of assets, net - The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on
sale in 2016 represents the sale of our Northern Louisiana system partially offset by a loss on sale of non-core assets.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2017 compared to 2016
primarily due to lower production volumes from two offshore wells at Discovery. We expect continued volume declines from
these wells to impact future earnings.
Segment Gross Margin — Segment gross margin increased $150 million in 2017 compared to 2016, primarily as a result
of the following:
•
•
$231 million increase as a result of higher commodity prices;
$35 million increase as a result of increased volume from growth projects, higher margins associated with a
specific producer arrangement, and higher NGL recoveries primarily related to our DJ Basin system and a producer
settlement in our North region;
These increases were partially offset by:
•
$79 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions
due to reduced drilling activity in prior periods and the impact of Hurricane Harvey, partially offset by fee based
62
contract realignment efforts in the Permian and Midcontinent regions and operational efficiencies associated with
our investment in digital transformation;
•
$16 million decrease as a result of the sale of our Northern Louisiana system in our South region and Douglas
gathering system in our North region; and
•
$21 million decrease as a result of commodity derivative activity as discussed above.
Total Wellhead — Natural gas wellhead decreased in 2017 compared to 2016 reflecting lower volumes primarily from (i)
lower volumes associated with general declines within the South, Permian and Midcontinent regions (ii) the sale of our
Northern Louisiana system within our South region and (iii) the sale of our Douglas gathering system within our North region
and (iv) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by (v) general
volume increases due to maximizing capacity utilization and growth projects within the North region.
NGL Gross Production — NGL production decreased in 2017 compared to 2016 primarily as a result of (i) lower
volumes associated with general declines within the South, Permian and Midcontinent regions, (ii) the sale of our Northern
Louisiana system within our South region and (iii) the sale of our Douglas gathering system within our North region and (iv)
the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by (v) general volume
increases due to maximizing capacity utilization within the North region and (vi) intermittent higher ethane recoveries across all
regions.
Year Ended December 31, 2016 vs. Year Ended December 31, 2015
Total Operating Revenues — Total operating revenues decreased $420 million in 2016 compared to 2015, primarily as a
result of the following:
•
•
•
•
•
$163 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the
impact of derivative activity;
$444 million decrease attributable to lower volumes across our South, Midcontinent and Permian regions due to
reduced drilling activity in prior periods, partially offset by improved operational efficiencies in the Permian and
Midcontinent regions; and
$113 million decrease as a result of commodity derivative activity attributable to an increase in unrealized
commodity derivative losses of $166 million in 2016 which were partially offset by a $53 million increase in
realized cash settlement gains due to movements in forward prices of commodities.
These decreases were partially offset by:
$185 million increase attributable to higher gas and NGL sales volumes and the impact of a specific producer
arrangement primarily related to our DJ Basin system in our North region;
$115 million increase in transportation, processing and other primarily related to fee based contract realignment
efforts, partially offset by lower volumes in the South region and the sale of our Northern Louisiana System.
Purchases and Related Costs — Purchases and related costs decreased $434 million in 2016 compared to 2015 as a result
of decreased commodity prices and lower gas and NGL sales volumes in our South, Midcontinent and Permian regions,
partially offset by increased volumes in our North region.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015
primarily as a result of our headcount reduction in April 2016, plant consolidations and other cost savings initiatives, the
disposition of our Northern Louisiana system in July 2016 and the sale of certain gas processing plants and gathering systems in
the Permian region in 2015, partially offset by the completion of our Lucerne 2 plant in the DJ Basin system in July 2015 and
the completion of our Zia II plant in the Southeast New Mexico system in August 2015.
General and Administrative Expense — General and administrative expense decreased in 2016 compared to 2015
primarily as a result of our headcount reduction in April 2016 and other cost savings initiatives.
63
Asset Impairments — Asset impairments in 2015 represented impairments of goodwill, property, plant and equipment and
intangible assets.
Other Income (Expense), net — Other income, net in 2016 represented a producer settlement net of legal fees, partially
offset by charges from discontinued construction projects.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015
primarily as a result of the ramp-up of the Keathley Canyon volumes at Discovery.
Gain on Sale of Assets, net — Gain on sale of assets during 2016 primarily related to the sale of our Northern Louisiana
system in our South region. During 2015, we recognized gains related to the sale of certain gas processing plants and gathering
systems in our Midcontinent and Permian regions.
Segment Gross Margin — Segment gross margin increased $14 million in 2016 compared to 2015, primarily as a result of
the following:
•
•
•
•
•
•
$76 million increase primarily as a result of higher volumes following the ramp-up of the Lucerne 2 plant,
completion of the Grand Parkway gathering system in January 2016, higher margins on specific producer
arrangements and higher NGL recoveries primarily related to our DJ Basin system in our North region;
$77 million increase primarily as a result of the completion of the Zia II plant in the Southeast New Mexico system
in our Permian region in August 2015, ramp-up of the National Helium plant in the Liberal system in our
Midcontinent region in September 2015 and improved operational efficiencies in the Permian and Midcontinent
regions; and
$12 million increase primarily as a result of fee based contract realignment efforts in the Permian and Midcontinent
regions, partially offset by lower volumes across our South, Midcontinent and Permian regions due to reduced
drilling activity in prior periods.
These increases were partially offset by:
$113 million decrease as a result of commodity derivative activity as discussed above;
$30 million decrease as a result of lower commodity prices; and
$8 million decrease as a result of the sale of our Northern Louisiana system in our South Region.
Total Wellhead Volumes - Natural gas wellhead throughput decreased in 2016 compared to 2015 reflecting lower volumes
primarily from (i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the
general declines within the Permian and Midcontinent regions (iii) the disposition of our Northern Louisiana system within our
South region and (iv) disposition of certain gas processing plants and gathering systems in the Midcontinent and Permian
regions, which were partially offset by (iv) the ramp-up of the Lucerne 2 plant in our North region which commenced
operations in June 2015 (v) completion of the Zia II plant in August 2015 and (vi) ramp-up of the National Helium plant in
September 2015.
NGL Gross Production - NGL production decreased in 2016 compared to 2015 reflecting lower volumes primarily from
(i) our Eagle Ford and East Texas systems within our South region (ii) lower volumes associated with the general declines
within the Permian and Midcontinent regions (iii) the disposition of our Northern Louisiana system within our South region (iv)
disposition of certain gas processing plants in the Midcontinent and Permian regions and (v) higher ethane rejection, which
were partially offset by (vi) the ramp-up of the Lucerne 2 plant in our North region which commenced operations in June 2015
(vii) completion of the Zia II plant in August 2015 and (viii) ramp-up of the National Helium plant in September 2015.
64
Results of Operations — Logistics and Marketing Segment
The results of operations for our Logistics and Marketing segment are as follows:
Year Ended December 31,
Variance 2017 vs. 2016 Variance 2016 vs. 2015
2017
2016
2015
Increase
(Decrease)
Percent
Increase
(Decrease)
Percent
(millions, except operating data)
Operating revenues:
Sales of natural gas and NGLs
$ 7,667
$ 6,094
$
6,364
$
1,573
26 % $
(270)
(4)%
72
(6)
(9)%
(2)
(3)%
Transportation, processing and other
Trading and marketing gains, net
64
26
70
22
Total operating revenues
7,757
6,186
51
6,487
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense
Earnings from unconsolidated affiliates (a)
Gain on sale of assets, net
Segment net income attributable to partners
Other data:
Segment gross margin (b)
Non-cash commodity derivative mark-to-market
(7,557)
(5,981)
(6,251)
(41)
(14)
(11)
—
(11)
243
—
366
200
$
$
(43)
(15)
(9)
—
(5)
209
16
358
205
$
$
(49)
(16)
(11)
(9)
(8)
130
—
273
236
$
$
(4) $
(20) $
(1) $
$
$
$
NGL pipelines throughput (MBbls/d) (c)
460
420
298
4
1,571
1,576
(2)
(1)
2
—
6
34
(16)
18 %
25 %
26 %
(5)%
(7)%
22 %
*
*
16 %
*
8
2 % $
(29)
(301)
(270)
(6)
(1)
(2)
(9)
(3)
79
16
85
(57)%
(5)%
(4)%
(12)%
(6)%
(18)%
*
(38)%
61 %
*
31 %
(5)
16
40
(2)% $
(80)% $
(31)
(19)
(13)%
*
10 %
122
41 %
(a) Earnings from unconsolidated affiliates for Sand Hills, Southern Hills, Front Range, 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.
(b) Segment gross margin consists of total operating revenues less purchases and related costs. Please read “Reconciliation
of Non-GAAP Measures”.
(c) For entities not wholly-owned by us, includes our share, based on our ownership percentage, of the throughput volume.
65
Year Ended December 31, 2017 vs. Year Ended December 31, 2016
Total Operating Revenues — Total operating revenues increased $1,571 million in 2017 compared to 2016, primarily as a
result of the following:
•
•
•
•
•
$1,934 million increase as a result of higher commodity prices, which impacted both sales and purchases, before
the impact of derivative activity;
$4 million increase as a result of commodity derivative activity attributable to an decrease in unrealized
commodity derivative losses of $16 million partially offset by a $12 million decrease in realized cash settlement
gains due to movements in forward prices of commodities in 2017;
These increases were partially offset by:
$325 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases;
$36 million decrease due to the sale of our Northern Louisiana system, and;
$6 million decrease in transportation, processing and other primarily related to lower gas storage margins and
lower transportation volumes on certain of our NGL pipelines.
Purchases and related costs — Purchases and related costs increased $1,576 million in 2017 compared to 2016, primarily
as a result of higher commodity prices, partially offset by lower gas and NGL sales volumes.
Other expense — Other expense in 2017 primarily represents the write-off of property, plant and equipment associated
with the expiration of a lease while other expense in 2016 primarily represents the write-off of property, plant and equipment
and other long term assets.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016
primarily as a result of higher throughput volumes on Sand Hills due to continued NGL production growth from the Permian
basin and ongoing capacity expansions, partially offset by lower volumes and planned maintenance on the Mont Belvieu
fractionators.
Gain on sale of assets, net — The gain on sale in 2016 primarily represents the sale of our Northern Louisiana system.
Segment Gross Margin — Segment gross margin decreased $5 million in 2017 compared to 2016, primarily as a result of
the following:
•
•
$11 million decrease as a result of lower margins and the expiration of a contract in our wholesale propane
business;
$8 million decrease as a result of lower gas storage margins and lower transportation volumes on certain of our
NGL pipelines; and
•
$7 million decrease as a result of the sale of our Northern Louisiana system;
These decreases are partially offset by;
$9 million increase as a result of higher NGL marketing margins;
$8 million increase as a result of higher gas marketing margins; and
$4 million increase as a result of commodity derivative activity discussed above.
•
•
•
NGL Pipelines Throughput — NGL pipelines throughput increased in 2017 compared to 2016 primarily as a result of
higher throughput volumes on Sand Hills due to continued NGL production growth from the Permian basin and ongoing
capacity expansions on the Sand Hills pipeline.
66
Year Ended December 31, 2016 vs. Year Ended December 31, 2015
Total Operating Revenues — Total operating revenues decreased $301 million in 2016 compared to 2015, primarily as a
result of the following:
•
•
•
•
$250 million decrease attributable to lower commodity prices, which impacted both sales and purchases, before the
impact of derivative activity;
$20 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases
$29 million decrease as a result of commodity derivative activity attributable to a $10 million decrease in realized
cash settlement gains in 2016 and an increase in unrealized commodity derivative losses of $19 million due to
movements in forward prices of commodities; and
$2 million decrease primarily due to the sale of our Northern Louisiana system in July 2016 and lower wholesale
propane fees partially offset by new connections on certain of our NGL pipelines.
Purchases and Related Costs — Purchases and related costs decreased $270 million in 2016 compared to 2015 as a result
of lower commodity prices and lower gas and NGL sales volumes.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2016 compared to 2015
primarily as a result of our headcount reduction in April 2016, other cost savings initiatives and the sale of our Northern
Louisiana system in July 2016.
General and Administrative Expense — General and administrative expense decreased in 2016 compared to 2015
primarily as a result of our headcount reduction in April 2016 and other cost savings initiatives.
Asset Impairments — Asset impairments for the year ended December 31, 2015 primarily related to impairments of
property, plant and equipment and intangible assets.
Other Expense, net — Other expense, net in 2016 and 2015 primarily represents charges for discontinued construction
projects.
Gain on Sale of Assets, net — Gain on sale of assets for the year ended December 31, 2016 primarily related to the sale of
our Northern Louisiana system.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2016 compared to 2015
primarily as a result of Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher
pipeline throughput volumes on Southern Hills, Sand Hills and Front Range due to growth in NGL production from new plants
placed into service in 2015 and earnings on the Panola pipeline beginning in February 2016.
Segment Gross Margin — Segment gross margin decreased $31 million in 2016 compared to 2015, primarily as a result of
the following:
•
•
$29 million decrease as a result of commodity derivative activity attributable to a $10 million decrease in realized
cash settlement gains in 2016 and an increase in unrealized commodity derivative losses of $19 million due to
movements in forward prices of commodities;
$2 million decrease primarily due to the sale of our Northern Louisiana system in July 2016 and lower wholesale
propane fees, partially offset by new connections on certain of our NGL pipeline.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2016 compared to 2015 primarily as a result of
Enbridge’s contribution of its interests in Sand Hills and Southern Hills in November 2015, higher throughput volumes on Sand
Hills, Southern Hills and Front Range due to growth in NGL production from new plants placed into service in 2015 and the
throughput volumes on Panola commencing February 2016.
67
Liquidity and Capital Resources
We expect our sources of liquidity to include:
•
•
•
•
•
•
•
•
•
cash generated from operations;
cash distributions from our unconsolidated affiliates;
borrowings under our Credit Agreement;
proceeds from asset rationalization;
reduction of incentive distribution right payments during 2018 and 2019;
debt offerings;
issuances of additional common units, preferred units or other securities;
borrowings under term loans; and
letters of credit.
We anticipate our more significant uses of resources to include:
•
•
•
•
•
•
quarterly distributions to our common unitholders and General Partner, and semi annual distributions to our
preferred unitholders;
payments to service our debt;
growth capital expenditures;
contributions to our unconsolidated affiliates to finance our share of their capital expenditures;
business and asset acquisitions; 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.
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.
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, further
impact our credit ratings, raise our financing costs, as well as impact our compliance with our financial covenant requirements
under the Credit Agreement and the indentures governing our notes.
Credit Agreement — In December 2017, we amended our $1.4 billion Credit Agreement (the "Credit Agreement"), to
extend the maturity date to December 6, 2022. The Credit Agreement is used for working capital requirements and other
general partnership purposes including acquisitions.
As of December 31, 2017, there were no outstanding borrowings on the revolving credit facility under the Credit
Agreement. We had unused borrowing capacity of $1,375 million, net of $25 million of letters of credit, under the Credit
Agreement and the financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt
by this amount as of December 31, 2017. Our cost of borrowing under the Credit Agreement is determined by a ratings-based
pricing grid. In the first quarter of 2017, our credit rating was lowered. As a result of this action, interest rates on outstanding
borrowings under the Credit Agreement increased. As of February 22, 2018, we had no outstanding borrowings on the
revolving credit facility and had approximately $1,375 million, net of $25 million of letters of credit, of unused borrowing
capacity under the Credit Agreement.
68
Issuance of Units — In November 2017, we issued 500,000 of our 7.375% Series A Preferred Units representing limited
partner interests at a price of $1,000 per unit. We used the net proceeds of $487 million from this issuance for general
partnership purposes, including the partial repayment of the $500 million 2.50% Senior Notes which were due on December 1,
2017.
In November 2017, we filed a shelf registration statement with the SEC that became effective upon filing and allows us to
issue an indeterminate amount of common units, preferred units, and debt securities. During the year ended December 31,
2017, we issued $500 million of our Series A Preferred Units under this shelf registration statement and no other securities.
This shelf registration statement replaced the shelf registration statement that we filed in April 2015 pursuant to which we
issued no securities.
In August 2017, we filed a shelf registration statement with the SEC which allows us to issue up to $750 million in
common units pursuant to our at-the-market program. During the year ended December 31, 2017, we issued no common units
pursuant to this registration statement.
Commodity Swaps and Collateral — 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 portion of our anticipated commodity price risk associated
with the equity volumes from our gathering and processing activities through the first quarter of 2019 with fixed price
commodity swaps. For additional information regarding our derivative activities, please read Item 7A. "Quantitative and
Qualitative Disclosures about Market Risk."
When we enter into commodity swap 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.
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, cash collateral we may be required
to post with counterparties to our commodity derivative instruments, borrowings of and payments on debt, capital expenditures,
and increases or decreases in other long-term assets. We expect that our future working capital requirements will be impacted
by these same recurring factors.
We had working capital deficits of $166 million and $629 million as of December 31, 2017 and December 31, 2016,
respectively. The change in working capital is primarily attributable to the cash received in the Transaction and from the
issuance of the Series A Preferred Units offset by the repayment of the 2.50% Senior Notes and long-term debt outstanding on
the revolving credit facility. We had a net derivative working capital deficit of $46 million and $49 million as of December 31,
2017 and December 31, 2016, respectively.
As of December 31, 2017, we had $156 million in cash and cash equivalents, of which $1 million was held by
consolidated subsidiaries we did not wholly own.
69
Cash Flow — Operating, investing and financing activities were as follows:
Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in) provided by financing activities
Year Ended December 31, 2017 vs. Year Ended December 31, 2016
Year Ended December 31,
2017
2016
(millions)
2015
$
$
$
$
896
(391) $
(350) $
$
645
(34) $
(613) $
442
(711)
245
Operating Activities - Net cash provided by operating activities increased $251 million in 2017 compared to the same
period in 2016. The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash
charges and changes in working capital as presented in the consolidated statements of cash flows. In addition, we received $10
million less of cash distributions in excess of earnings from unconsolidated affiliates during the year ended December 31, 2017.
For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read "Results of
Operations".
Investing Activities - Net cash used in investing activities increased $357 million in 2017 compared to the same period in
2016 primarily as a result of higher capital expenditures used for construction of the Mewbourn 3 plant, Grand Parkway Phase
2 and O'Connor bypass projects and higher investments in unconsolidated affiliates for the capacity expansion of the Sand Hills
pipeline. In addition, less proceeds were received in 2017 from the sale of Douglas gathering system compared to proceeds
received from the sale of our Northern Louisiana system in 2016.
Financing Activities - Net cash used in financing activities decreased $263 million in 2017 compared to the same period in
2016 primarily as a result of cash received from the the issuance of Series A preferred limited partner units and from the
Transaction in 2017 partially offset by higher net payments of long-term debt and higher distributions paid to limited partners
and the general partner due to a higher number of outstanding common units and general partner units following the
Transaction.
Year Ended December 31, 2016 vs. Year Ended December 31, 2015
Operating Activities - Net cash provided by operating activities increased $203 million in 2016 compared to the same
period in 2015. The changes in net cash provided by operating activities are attributable to our net income adjusted for non-cash
charges and changes in working capital as presented in the consolidated statements of cash flows. In addition, we received $41
million more of cash distributions in excess of earnings from unconsolidated affiliates during the year ended December 31,
2016. For additional information regarding fluctuations in our earnings from unconsolidated affiliates, please read "Results of
Operations".
Investing Activities - Net cash used in investing activities decreased $677 million in 2016 compared to the same period in
2015 primarily as a result of higher capital expenditures in 2015 attributable to the Lucerne 2 plant, the Zia II plant, the
National Helium plant expansion and the Grand Parkway gathering projects, as well as decreases in cash contributions to our
unconsolidated affiliates and lower proceeds received from sale of assets in 2016.
Financing Activities - Net cash used in financing activities increased $858 million in 2016 compared to the same period in
2015 primarily as a result of the decrease in advances from DCP Midstream, LLC attributable to the $1,500 contribution
received from Phillips 66 in 2015, and the decrease in proceeds from issuance of common units to the public, partially offset by
the decrease in net debt payments primarily attributable to the repayment of outstanding commercial paper in 2015.
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,
70
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. Our 2018 plan includes
maintenance capital expenditures of between $100 million and $120 million, and expansion capital expenditures between $650
million and $750 million associated with approved projects. Expansion capital expenditures include the construction of the
Mewbourn 3 plant, Grand Parkway Phase 2 and O'Connor bypass in our DJ Basin system, and the capacity expansions of the
Sand Hills pipeline, which are shown as an investment in unconsolidated affiliates in our consolidated statements of cash flows.
The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities for the
years ended December 31, 2017, 2016 and 2015:
Year Ended December 31, 2017
Year Ended December 31, 2016
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
$
$
90
$
279
$
(millions)
369
$
86
$
57
$
2
92
4
6
$
283
$
375
$
3
89
$
(2)
55
$
143
1
144
Year Ended December 31, 2015
Maintenance
Capital
Expenditures
Expansion
Capital
Expenditures
Total
Consolidated
Capital
Expenditures
Our portion
Noncontrolling interest portion and
reimbursable projects (a)
Total
$
$
181
$
633
$
814
(3)
—
178
$
633
$
(3)
811
(a) Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into
agreements with third parties whereby we will be reimbursed for certain expenditures. Depending on the timing of these
payments, we may be reimbursed prior to incurring the capital expenditure.
In addition, we invested cash in unconsolidated affiliates of $148 million and $53 million during the years ended
December 31, 2017 and 2016, 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, to fund future acquisitions and capital expenditures.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit
Agreement, the issuance of additional equity securities and the issuance of long-term debt.
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 $545 million and $483 million during the years ended December 31, 2017 and 2016,
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.
71
In accordance with our amended Partnership Agreement, distributions declared were $618 million for the year ended
December 31, 2017. Distributions declared reflect the distribution of $40 million of IDR givebacks to our owners, in
conjunction with the quarterly distribution, that were previously withheld under the amended Partnership agreement.
We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and
general partner. See Note 14. "Partnership Equity and Distributions" in the Notes to the Consolidated Financial Statements in
Item 8. “Financial Statements.”
Total Contractual Cash Obligations
A summary of our total contractual cash obligations as of December 31, 2017, was as follows:
Debt (a)
Operating lease obligations
Purchase obligations (b)
Other long-term liabilities (c)
Total
Payments Due by Period
Total
Less than
1 year
1-3 years
(millions)
3-5 years
Thereafter
$
$
7,837
164
4,485
144
12,630
$
$
274
37
828
—
1,139
$
$
1,828
64
1,325
17
3,234
$
$
1,196
35
1,093
15
2,339
$
$
4,539
28
1,239
112
5,918
(a) Includes interest payments on debt securities that have been issued. These interest payments are $274 million, $453
million, $346 million, and $2,039 million for less than one year, one to three years, three to five years, and thereafter,
respectively.
(b) Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction
agreements for capital expenditures, various non-cancelable commitments to purchase physical quantities of
commodities in future periods and other items, including long-term fractionation agreements. For contracts where the
price paid is based on an index or other market-based rates, the amount is based on the forward market prices or current
market rates as of December 31, 2017. Purchase obligations exclude accounts payable, accrued taxes 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 sheets, 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.
(c) Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas
purchase liabilities, and other miscellaneous liabilities recognized in the December 31, 2017 consolidated balance sheet.
The table above excludes non-cash obligations as well as $29 million of Executive Deferred Compensation Plan
contributions and $14 million of long-term incentive plans as the amount and timing of any payments are not subject to
reasonable estimation.
Off-Balance Sheet Obligations
As of December 31, 2017, we had no items that were classified as off-balance sheet obligations.
72
Reconciliation of Non-GAAP Measures
Gross Margin and Segment Gross Margin — In addition to net income, 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.
We define gross margin as total operating revenues, less purchases and related costs, and we define segment gross margin
for each segment as total operating revenues 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 GAAP.
Adjusted EBITDA — We define adjusted EBITDA as net income or loss attributable to partners adjusted for (i)
distributions from unconsolidated affiliates, net of earnings (ii) depreciation and amortization expense, (iii) net interest expense,
(iv) noncontrolling interest in depreciation and income tax expense, (v) unrealized gains and losses from commodity derivatives
(vi) income tax expense or benefit, (vii) impairment expense and (viii) certain other non-cash items. Adjusted EBITDA further
excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Management believes
these measures provide investors meaningful insight into results from ongoing operations.
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 adjusted for (i) distributions from unconsolidated affiliates, net of earnings (ii) depreciation and
amortization expense, (iii) net interest expense, (iv) noncontrolling interest in depreciation and income tax expense, (v)
unrealized gains and losses from commodity derivatives (vi) income tax expense or benefit, (vii) impairment expense and (viii)
certain other non-cash items. Adjusted EBITDA further excludes items of income or loss that we characterize as
unrepresentative of our ongoing operations 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.
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
accompanying schedules provide reconciliations of gross margin, segment gross margin and adjusted segment EBITDA to their
most directly comparable GAAP financial measures.
Distributable Cash Flow — We define Distributable Cash Flow as adjusted EBITDA, as defined above, less maintenance
capital expenditures, net of reimbursable projects, less interest expense, less income attributable to preferred units, and certain
other items. Maintenance capital expenditures are cash expenditures made to maintain our cash flows, operating or earnings
73
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. Income attributable to preferred units represent cash distributions earned by the Series A
Preferred Units. Cash distributions to be paid to the holders of the Series A Preferred units, assuming a distribution is declared
by our board of directors, are not available to common unit holders. 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. We compare the Distributable Cash
Flow we generate to the cash distributions we expect to pay our partners. Using this metric, we compute our distribution
coverage ratio. Distributable Cash Flow is used as a supplemental liquidity and 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.
74
The following table sets forth our reconciliation of certain non-GAAP measures:
Reconciliation of Non-GAAP Measures
Reconciliation of net income (loss) attributable to
partners to gross margin:
Net income (loss) attributable to partners
Interest expense
Income tax expense
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense (income), net
Restructuring costs
Earnings from unconsolidated affiliates
Gain on sale of assets, net
Net income attributable to noncontrolling interests
Gross margin
Non-cash commodity derivative mark-to-market (a)
Reconciliation of segment net income (loss) attributable
to partners to segment gross margin:
Gathering and Processing segment:
Segment net income (loss) attributable to partners
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense (income), net
Earnings from unconsolidated affiliates
Gain on sale of assets, net
Net income attributable to noncontrolling interests
Segment gross margin
Non-cash commodity derivative mark-to-market (a)
Logistics and Marketing segment:
Segment net income attributable to partners
Operating and maintenance expense
Depreciation and amortization expense
Other expense, net
General and administrative expense
Earnings from unconsolidated affiliates
Gain on sale of assets, net
Asset impairments
Segment gross margin
Non-cash commodity derivative mark-to-market (a)
75
$
$
$
$
$
$
$
$
$
2017
Year Ended December 31,
2016
(Millions)
2015
$
(28) $
229
289
2
661
379
290
48
11
—
(303)
(34)
5
1,577
454
602
343
19
48
—
(60)
(34)
5
1,377
$
$
$
$
(24) $
366
41
14
11
11
(243)
—
—
200
$
(4) $
$
88
321
46
670
378
292
—
(65)
13
(282)
(35)
6
1,432
$
(139) $
$
417
611
344
14
—
(73)
(73)
(19)
6
1,227
$
(119) $
$
358
43
15
5
9
(209)
(16)
—
205
$
(20) $
(871)
320
(102)
732
377
281
912
10
11
(184)
(42)
5
1,449
46
(606)
668
343
22
876
1
(54)
(42)
5
1,213
47
273
49
16
8
11
(130)
—
9
236
(1)
(a) Non-cash commodity derivative mark-to-market is included in gross margin and segment gross margin, along with cash
settlements for our commodity derivative contracts.
Reconciliation of net income (loss) attributable to
partners to adjusted segment EBITDA:
Gathering and Processing segment:
Segment net income (loss) attributable to partners
Non-cash commodity derivative mark-to-market
Depreciation and amortization expense, net of
noncontrolling interest
Asset impairments
Gain on sale of assets, net
Distributions from unconsolidated affiliates, net of
earnings
Other expense
Adjusted segment EBITDA
Logistics and Marketing segment:
Segment net income attributable to partners (a)
Non-cash commodity derivative mark-to-market
Depreciation and amortization expense, net of
noncontrolling interest
Distributions from unconsolidated affiliates, net of
earnings
$
$
$
Gain on sale of assets, net
Asset impairments
Other expense
Adjusted segment EBITDA
Year Ended December 31,
2017
2016
2015
(Millions)
454
$
24
$
$
342
48
(34)
24
4
862
366
4
14
40
—
—
9
$
$
$
417
119
343
—
(19)
21
14
895
358
20
15
53
(16)
—
—
(606)
(47)
342
876
(42)
15
2
540
273
1
16
18
—
9
—
$
433
$
430
$
317
(a) There were lower of cost or market adjustments of $2 million, $3 million and $8 million for the years ended
December 31, 2017, 2016 and 2015, respectively.
Operating and Maintenance and General and Administrative Expense
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee
Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP
Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP
Midstream, LLC for salaries of 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. 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.
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.
76
General and administrative expense represents costs incurred to manage the business. This expense includes cost of
centralized corporate functions performed by DCP Midstream, LLC, including legal, accounting, cash management, insurance
administration and claims processing, risk management, health, safety and environmental, information technology, human
resources, credit, payroll and engineering and all other expenses necessary or appropriate to the conduct of the business.
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.
77
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
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.
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 (including
forecasted commodity prices and
volumes), as well as historical and
other factors. 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. Two of the three
reporting units that contain goodwill
are not significantly impacted by the
prices of commodities. Rather, they
are volume based businesses that have
the potential to be impacted by
commodity prices should such prices
remain depressed for a period of such
duration that NGLs cease to be
produced at levels requiring storage
and distribution to end users. The fair
value of goodwill substantially
exceeded its carrying value in our
North reporting unit, the only
reporting unit allocated goodwill
included within our Gathering and
Processing reportable segment and in
our Marysville reporting unit included
within our Logistics and Marketing
reportable segment. For our
Wholesale Propane reporting unit,
which is included in our Logistics and
Marketing reportable segment, the
fair value exceeded the carrying value
(including approximately $37 million
of allocated goodwill) by
approximately 5%. We did not record
any goodwill impairment during the
year ended December 31, 2017.
78
Description
Judgments and Uncertainties
Effect if Actual Results Differ from
Assumptions
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,
future commodity prices, volumes,
and operating costs, 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.
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. For purposes of this
evaluation, long-lived assets with
recovery periods in excess of the
weighted average remaining useful
life of our fixed assets are further
analyzed to determine if a triggering
event occurred. If it is determined that
a triggering event has occurred, we
prepare a quantitative evaluation
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.
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. We would then evaluate
if the impairment is other than
temporary.
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 an other than temporary
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
recorded a $47 million impairment
charge on long-lived assets during the
year ended December 31, 2017 when
it was determined that the carrying
value of an asset group was not
recoverable. 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
additional impairment charges. If our
forecast indicates lower commodity
prices in future periods at a level and
duration that results in producers
curtailing or redirecting drilling in
areas where we operate this may
adversely affect our estimate of future
operating results, which could result
in future impairment due to the
potential impact on our operations
and cash flows.
Using the impairment review
methodology described herein, we
have not recorded any significant
impairment charges on investments in
unconsolidated affiliates during the
year ended December 31, 2017. 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 only if the loss is
other than temporary. A period of
lower commodity prices may
adversely affect our estimate of future
operating results, which could result
in future impairment due to the
potential impact on the investee's
operations and cash flows.
79
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 end of the contractual
settlement period. 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.
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,
2017 would have affected net income
by approximately $1 million based on
our net derivative position for the year
ended December 31, 2017.
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 commodity price risk and counterparty credit risk,
including monitoring exposure limits.
See Note 13, 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.
80
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 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 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.
Commodity prices experienced significant volatility during 2017, as illustrated in Item 1A. Risk Factors - “Our cash flow
is affected by natural gas, NGL and condensate prices.” A decline in commodity prices has resulted in a decrease in exploration
and development activities in certain fields served by our gas gathering and residue gas and NGL pipeline transportation
systems, and our natural gas processing and treating plants, which could lead to further reduced utilization of these assets.
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 and processing operations. Our positions as of February 22, 2018 were as follows:
Commodity Swaps
Period
Commodity
Notional
Volume
- Short
Positions
Reference Price
Price Range
January 2018 — March 2018
Natural Gas
(37,500) MMBtu/d
NYMEX Final Settlement Price (b)
$3.30-$3.68/MMBtu
January 2018 — December 2018
NGLs
(16,080) Bbls/d (d)
Mt.Belvieu (c)
January 2018 — December 2018
Crude Oil
(7,751) Bbls/d (d)
NYMEX crude oil futures (a)
January 2019 — February 2019
Crude Oil
(6,249) Bbls/d (d)
NYMEX crude oil futures (a)
$.29-$.96/Gal
$51.20-$66.00/Bbl
$51.26-$61.51/Bbl
(a) Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract.
(b) NYMEX final settlement price for natural gas futures contracts.
(c) The average monthly OPIS price for Mt. Belvieu TET/Non-TET.
(d) Average Bbls/d per time period.
Our sensitivities for 2018 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 2018, and exclude the impact of non-cash mark-
to-market changes on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to
mitigate a portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with
our condensate, natural gas and NGL volumes that are currently unhedged.
81
Commodity Sensitivities Net of Cash Flow Protection Activities
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
$
$
$
8
2
4
In addition to the linear relationships in our commodity sensitivities above, additional factors may 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-proceeds and percentage-of-liquids processing arrangements that contain minimum fee clauses in which our
processing margins convert to fee-based arrangements as commodity 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.
We estimate the following sensitivities related to the non-cash mark-to-market on our commodity derivatives associated
with our open position on 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
$
$
$
—
3
3
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
of these transactions, we have mitigated a portion of our expected commodity price risk relating to the equity volumes
associated with our gathering and processing activities through the first quarter of 2019.
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
82
NGL exports has increased in recent years. We believe that future natural gas prices will be influenced by 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 trade between imports and exports of liquid natural gas and NGLs. 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 inventory within our natural gas storage operations as of December 31, 2017:
Inventory
Period ended
Commodity
Notional Volume - Long
Positions
Fair Value
(millions)
Weighted
Average Price
December 31, 2017
Natural Gas
11,163,515 MMBtu
$
30
$2.66/MMBtu
Commodity Swaps
Period
January 2018-December 2018
January 2018-December 2018
Commodity
Natural Gas
Natural Gas
Notional Volume - (Short)/Long
Positions
Fair Value
(millions)
Price Range
(28,427,500) MMBtu
17,605,000 MMBtu
$
$
5
$2.64-$3.58/MMBtu
— $2.63-$3.22/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
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
83
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 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.
Fair Value of Contracts as of December 31, 2017
Sources of Fair Value
Total
Maturity in 2018
Prices supported by quoted market
prices and other external sources
Prices based on models or other
valuation techniques
Total
$
$
(millions)
(48) $
(10)
(58) $
(36)
(11)
(47)
The “prices supported by quoted market prices and other external sources” category includes our commodity 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 techniques” 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.
Credit Risk
Our customers include large multi-national petrochemical and refining companies, natural gas marketers, as well as
commodity producers. 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. Our
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 our 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.
84
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, 2017, the effective weighted-average interest rate on our outstanding debt was 5.80%.
85
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS
DCP MIDSTREAM, LP CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2017 and 2016
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Changes in Equity for the years ended December 31, 2017, 2016 and 2015
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015
Notes to Consolidated Financial Statements
87
88
89
90
91
93
94
86
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream GP, LLC
Denver, Colorado
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of DCP Midstream, LP and subsidiaries (the "Partnership") as
of December 31, 2017 and 2016, 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, 2017, and the related notes (collectively
referred to as the financial statements). In our opinion, based on our audits and the report of the other auditors, the financial
statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016,
and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in
conformity with accounting principles generally accepted in the United States of America.
We did not audit the financial statements of Discovery Producer Services, LLC (Discovery), the Partnership’s investment which
is accounted for by the use of the equity method. The accompanying consolidated financial statements of the Partnership
include its equity investment in Discovery of $362 million and $385 million as of December 31, 2017 and 2016, respectively,
and its equity earnings in Discovery of $61 million, $73 million and $54 million for the years ended December 31, 2017, 2016,
and 2015, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion,
insofar as it relates to the amounts included for Discovery, is based solely on the report of the other auditors.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on the criteria established
in the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 26, 2018, expressed an unqualified opinion on the Partnership’s internal control
over financial reporting based on our audit.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion
on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and
are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement, whether due to error of
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence
regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles
used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2018
We have served as the Partnership’s auditor since 2004.
87
DCP MIDSTREAM, LP
CONSOLIDATED BALANCE SHEETS
Current assets:
Cash and cash equivalents
Accounts receivable:
ASSETS
Trade, net of allowance for doubtful accounts of $8 and $4 million, respectively
Affiliates
Other
Inventories
Unrealized gains on derivative instruments
Collateral cash deposits
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
Other
Current maturities of long-term debt
Unrealized losses on derivative instruments
Accrued interest
Accrued taxes
Accrued wages and benefits
Capital spending accrual
Other
Total current liabilities
Long-term debt
Unrealized losses on derivative instruments
Deferred income taxes
Other long-term liabilities
Total liabilities
Commitments and contingent liabilities
Equity:
Predecessor equity
Limited partners (143,309,828 and 114,749,848 common units authorized, issued and
outstanding, respectively)
Series A preferred limited partners (500,000 preferred units authorized, 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.
88
December 31,
2017
December 31,
2016
(millions)
$
156
$
1
$
$
773
191
17
68
30
75
12
1,322
8,983
231
106
3,050
3
183
13,878
989
68
19
—
76
71
58
65
39
103
1,488
4,707
15
29
201
6,440
—
6,772
652
134
6
72
42
71
16
994
9,069
236
137
2,969
5
201
13,611
677
48
10
500
91
72
49
72
20
84
1,623
4,907
1
28
199
6,758
4,220
2,591
491
154
(9)
7,408
30
7,438
13,878
$
—
18
(8)
6,821
32
6,853
13,611
$
$
$
DCP MIDSTREAM, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
Operating revenues:
Sales of natural gas, NGLs and condensate
Sales of natural gas, NGLs and condensate to affiliates
Transportation, processing and other
Trading and marketing (losses) gains, net
Total operating revenues
Operating costs and expenses:
Purchases and related costs
Purchases and related costs from affiliates
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense (income), net
Gain on sale of assets, net
Restructuring costs
Total operating costs and expenses
Operating income (loss)
Earnings from unconsolidated affiliates
Interest expense, net
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Net income attributable to noncontrolling interests
Net income (loss) attributable to partners
Net loss attributable to predecessor operations
General partner’s interest in net income
Series A preferred limited partners' interest in net income
Net income allocable to limited partners
Net income per limited partner unit — basic and diluted
Weighted-average limited partner units outstanding — basic and diluted
Year Ended December 31,
2017
2016
2015
(millions, except per unit amounts)
$
$ 6,576
1,274
652
(40)
8,462
6,308
577
661
379
290
48
11
(34)
—
8,240
222
303
(289)
236
(2)
234
(5)
229
—
(164)
(4)
61
0.43
143.3
$
$
$
$
$
$
$
5,317
952
647
(23)
6,893
4,978
483
670
378
292
—
(65)
(35)
13
6,714
179
282
(321)
140
(46)
94
(6)
88
224
(124)
—
188
1.64
114.7
6,014
765
532
119
7,430
5,563
418
732
377
281
912
10
(42)
11
8,262
(832)
184
(320)
(968)
102
(866)
(5)
(871)
1,099
(124)
—
104
0.91
114.6
See accompanying notes to consolidated financial statements.
89
DCP MIDSTREAM, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)
Other comprehensive income:
Reclassification of cash flow hedge losses into earnings
Total other comprehensive income
Total comprehensive income (loss)
Total comprehensive income attributable to noncontrolling interests
Total comprehensive income (loss) attributable to partners
$
Year Ended
December 31,
2017
2016
2015
(millions)
$
234
$
94
$
(866)
1
1
235
(5)
230
$
—
—
94
(6)
88
$
1
1
(865)
(5)
(870)
See accompanying notes to consolidated financial statements.
90
DCP MIDSTREAM, LP
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Predecessor
Equity
Limited
Partners
Partners’ Equity
Series A
Preferred
Limited
Partners
$
4,220
$
2,591
$
— $
—
—
—
(4,220)
61
—
418
—
—
3,094
—
—
—
—
1,033
—
(425)
—
4
—
—
—
—
—
487
—
—
General
Partner
Accumulated Other
Comprehensive
(Loss) Income
Noncontrolling
Interests
Total
Equity
(millions)
18
$
164
—
—
—
—
92
—
(120)
—
(8) $
32
$ 6,853
—
1
—
—
5
—
—
234
1
418
— (4,220)
(2)
—
3,092
—
—
—
—
—
1,125
—
—
487
(545)
(7)
(7)
$
— $
6,772
$
491
$
154
$
(9) $
30
$ 7,438
See accompanying notes to consolidated financial statements.
Balance, January 1,
2017
Net income
Other comprehensive
income
Net change in parent
advances
Acquisition of the
DCP Midstream
Business
Deficit purchase price
under carrying value
of the Transaction
Issuance of
28,552,480 common
units and 2,550,644
general partner units
to DCP Midstream,
LLC and affiliates
Issuance of 500,000
Series A Preferred
Units
Distributions to
limited partners and
general partner
Distributions to
noncontrolling
interests
Balance, December
31, 2017
91
DCP MIDSTREAM, LP
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Partners’ Equity
Predecessor
Equity
Limited
Partners
General
Partner
Accumulated
Other
Comprehensive
Loss
(millions)
Noncontrolling
Interests
Total
Equity
Balance, January 1, 2016
$
4,287
$
2,762
$
18
$
$
7,092
Net (loss) income
Net change in parent advances
Distributions to limited partners
and general partner
Distributions to noncontrolling
interests
Balance, December 31, 2016
188
—
124
—
(359)
(124)
$
4,220
$
2,591
$
—
—
18
$
(8) $
—
—
—
—
(8) $
33
6
—
—
(7)
32
$
94
157
(483)
(7)
6,853
Partners’ Equity
Predecessor
Equity
Limited
Partners
General
Partner
Accumulated
Other
Comprehensive
(Loss) Income
(millions)
Noncontrolling
Interests
Total
Equity
Balance, January 1, 2015
$
2,189
$
2,984
$
18
$
Net (loss) income
Other comprehensive income
Net change in parent advances
Issuance of 793,080 common units
to the public
Distributions to limited partners
and general partner
Distributions to noncontrolling
interests
Contributions from DCP
Midstream, LLC
Balance, December 31, 2015
104
—
—
31
124
—
—
—
(358)
(124)
—
1
—
—
18
$
(9) $
—
1
—
—
—
—
—
(8) $
33
5
—
—
—
—
(5)
—
33
$
5,215
(866)
1
3,197
31
(482)
(5)
1
$
7,092
(224)
157
—
—
(1,099)
—
3,197
—
—
—
—
$
4,287
$
2,762
$
See accompanying notes to consolidated financial statements.
92
DCP MIDSTREAM, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
OPERATING ACTIVITIES:
Net income (loss)
Adjustments to reconcile net income (loss) 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
Gain on sale of assets, net
Asset impairments
Other, net
Change in operating assets and liabilities, which provided (used) cash, net of effects of
acquisitions:
Accounts receivable
Inventories
Accounts payable
Other assets and liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES:
Capital expenditures
Investments in unconsolidated affiliates, net
Proceeds from sale of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from long-term debt
Payments of long-term debt
Payments of commercial paper, net
Proceeds from issuance of common units, net of offering costs
Proceeds from issuance of Series A preferred limited partner 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
Other
Net cash (used in) provided by financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Year Ended December 31,
2017
2016
2015
(millions)
$
234
$
94
$
(866)
379
(303)
367
28
(34)
48
32
(194)
4
328
7
896
(375)
(148)
132
(391)
116
(811)
—
—
487
418
(545)
(7)
(8)
(350)
155
1
156
378
(282)
356
139
(35)
—
68
(247)
(21)
199
(4)
645
(144)
(53)
163
(34)
377
(184)
217
(46)
(42)
912
(68)
479
29
(381)
15
442
(811)
(64)
164
(711)
3,353
(3,628)
—
—
—
157
(483)
(7)
(5)
(613)
(2)
3
1
$
7,216
(7,196)
(1,012)
31
—
1,697
(482)
(5)
(4)
245
(24)
27
3
$
$
See accompanying notes to consolidated financial statements.
93
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015
1. Description of Business and Basis of Presentation
DCP Midstream, LP, with its consolidated subsidiaries, or "us", "we", "our" or the "Partnership" is a Delaware limited
partnership formed in 2005 by DCP Midstream, LLC to own, operate, acquire and develop a diversified portfolio of
complementary midstream energy assets.
Our Partnership includes our Gathering and Processing and Logistics and Marketing segments. For additional information
regarding these segments, see Note 21 - Business Segments.
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 Enbridge Inc. and its affiliates, or Enbridge. Spectra Energy Corp owned 50% of DCP Midstream,
LLC prior to the completion of its merger with Enbridge in the first quarter of 2017. DCP Midstream, LLC directs our business
operations through its ownership and control of the General Partner. As of December 31, 2017, DCP Midstream, LLC owned
approximately 38.1% of us, including limited partner and general partner interests.
On December 30, 2016, we entered into a Contribution Agreement (the “Contribution Agreement”) with DCP Midstream,
LLC and DCP Midstream Operating, LP (the “Operating Partnership”), a 100% owned subsidiary of the Partnership, which
closed effective January 1, 2017. The transactions and documents contemplated by the Contribution Agreement are collectively
referred to hereafter as the “Transaction.” Our predecessor results consist of all of the ownership interests of DCP Midstream,
LLC in all of its subsidiaries that owned operating assets ("The DCP Midstream Business"), which we acquired from DCP
Midstream, LLC on January 1, 2017. This transfer of net assets between entities under common control was 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
The DCP Midstream Business for all periods presented. For additional information regarding the Transaction, see Note 4 -
Acquisitions.
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.
The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in
the United States of America, or GAAP. All intercompany balances and transactions have been eliminated in consolidation.
94
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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.
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.
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.
Accounting for Risk Management Activities and Financial Instruments - Non-trading energy commodity derivatives are
designated as 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
Trading Derivatives
Non-Trading Derivatives:
Accounting Method
Mark-to-market
method (a)
Presentation of Gains & Losses or Revenue & Expense
Net basis in trading and marketing gains and losses
Cash Flow Hedge
Hedge method (b)
Fair Value Hedge
Hedge method (b)
Normal Purchases or Normal Sales
Accrual method (c)
Other Non-Trading Derivative Activity
Mark-to-market
method (a)
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
Net basis in trading and marketing gains and losses, net
(a) 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 trading and marketing gains and losses, net during the
current period.
(b) 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 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.
(c) 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 impacts earnings.
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
95
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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.
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.
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.
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.
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.
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
96
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
commodity prices. A period of lower commodity prices may adversely affect our estimate of future operating results, which
could result in future goodwill and intangible assets impairment due to the potential impact on our operations and cash flows.
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.
Investments in Unconsolidated Affiliates - We use the equity method to account for investments in greater than 20%
owned affiliates.
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 that is other than temporary, 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 less than the carrying value, the excess of the carrying
value over the estimated fair value is recognized as an impairment loss.
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. A period of lower
commodity prices may adversely affect our estimate of future operating results, which could result in future impairment due to
the potential impact on our operations and cash flows.
Unamortized Debt Discount and Expense - Discounts and expenses incurred with the issuance of long-term debt are
amortized over the term of the debt using the effective interest method. The discounts and unamortized expenses are recorded
on the consolidated balance sheets within the carrying amount of long-term debt.
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.
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
97
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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. 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/index 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 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/index 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.
• Keep-whole and wellhead purchase 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 British thermal unit, or 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 the
terms of a wellhead purchase contract, we purchase natural gas from the producer at the wellhead or defined
receipt point for processing and then market the resulting NGLs and residue gas at market prices. Under these
types of contracts, we are exposed to the difference between the value of the NGLs extracted from processing and
the value of the Btu equivalent of residue natural gas, or frac spread. We benefit in periods when NGL prices are
higher relative to natural gas prices when that frac spread exceeds our operating costs.
Our trading and marketing of natural gas and NGLs consists of physical purchases and sales, as well as financial
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
98
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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. New or amended contracts for
certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are
reported net as one transaction. We recognize revenues for commodity derivative activity net in the consolidated statements of
operations as trading and marketing gains and losses. 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.
Purchases and related costs - Purchases and related costs primarily includes (i) the cost of purchased commodities,
including NGLs, natural gas and condensate, and (ii) fees incurred for transportation and fractionation of commodities.
Significant Customers - There were no third party customers that accounted for more than 10% of total operating
revenues for the years ended December 31, 2017, 2016 and 2015. We had significant transactions with affiliates for the years
ended December 31, 2017, 2016 and 2015. See Note 6, Agreements and Transactions with Related Parties and 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.
Equity-Based Compensation — Liability classified equity-based compensation cost is remeasured at each reporting date
at fair value, based on the closing security 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.
Income Taxes - We are structured as a master limited partnership which is a pass-through entity for federal income tax
purposes. We owned a corporation that filed its own federal and state corporate income tax returns, which we elected to convert
to a limited liability company in 2016. 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 income tax 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
limited partner units, plus the effect of dilutive potential units outstanding during the period using the two-class method.
3. New Accounting Pronouncements
Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash
Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the
FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. We adopted this ASU for
interim and annual reporting periods beginning after December 15, 2017. The adoption of this ASU will have no impact on our
consolidated cash flows.
FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which
requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the
commencement date for all leases. This ASU is effective for interim and annual reporting periods beginning after December 15,
99
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
2018, with the option to early adopt for financial statements that have not been issued. We are currently evaluating the potential
impact this standard will have on our consolidated financial statements and related disclosures.
FASB ASU 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations
and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of
Accounting Standards Codification Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting periods
beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after December 15,
2016. Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an
amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Although the new
revenue recognition model is based on control, which differs from the previous model which was based a transfer of risks and
rewards, we expect to identify similar performance obligations under Topic 606 as compared with deliverables and units of
account previously identified under Topic 605. As a result, we expect the timing of our revenue to remain the same with respect
to the majority of our contracts. There are certain contracts within our Gathering and Processing reportable segment where we
previously recognized revenue for services provided to producers whereby under Topic 606 we have concluded that those
contracts are not within the scope of Topic 606 and thus such amounts which were previously presented gross will now be
presented net within ‘Purchases and related costs’. However, this change will not have any impact on our net income (loss),
operating income (loss), cash flows, or the amount we present as gross margin in our Business Segments footnote. We also have
certain contracts with customers whereby the customer reimburses us for costs to construct certain logistical connections to our
operating assets which we own and operate. We previously accounted for these arrangements as a reduction to the cost basis of
our long-lived assets which were amortized as a reduction to depreciation expense over the estimated useful life of the related
assets. Under Topic 606 we will record these payments as deferred revenue which will be amortized into revenue over the
contract term. Accordingly, we anticipate an increase to the amounts we present as gross margin within our Business Segment
footnote, but do not anticipate a material impact to net income (loss), operating income (loss), or cash flows because the
increase to depreciation expense will be offset by the increase to revenues.
In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows
arising from contracts with customers. The FASB issued several amendments to the standard which provided additional
implementation guidance and deferred the effective date of the standard. We adopted the guidance using the modified
retrospective method on the effective date of January 1, 2018. Based on these assessments we do not believe these changes will
have a significant impact on the information presented to the users of our financial statements.
4. Acquisitions
On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning
operating assets, and (ii) $424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the
Contributions, (i) the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units
to the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream,
LLC’s debt.
Pursuant to the Contribution Agreement, DCP Midstream, LLC agreed to cause the General Partner to enter into
Amendment No. 3 (the “Third Amendment to the Partnership Agreement”) to the Second Amended and Restated Agreement of
Limited Partnership of the Partnership, dated November 1, 2006, as amended (the “Partnership Agreement”). The Third
Amendment to the Partnership Agreement includes terms that amend the Partnership Agreement to cause the incentive
distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018
and 2019 to, in certain circumstances, be reduced in an amount up to $100 million per fiscal year as necessary to provide that
the distributable cash flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made
by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.
5. Dispositions
In June 2017, we closed a transaction with Tallgrass Midstream, LLC to sell our 100% interest in our Douglas gathering
system, which primarily consisted of approximately 1,500 miles of gathering lines within our Gathering and Processing
segment, for approximately $129 million, subject to customary purchase price adjustments. As a result of this transaction, we
recognized a gain of approximately $34 million, net of goodwill allocation, in the second quarter of 2017.
100
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
6. Agreements and Transactions with Affiliates
DCP Midstream, LLC
Services Agreement and Other General and Administrative Charges
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee
Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP
Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP
Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative
functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing,
risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and
administration, credit, payroll, internal audit, taxes and engineering, as well as salaries and benefits of seconded employees,
insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the
reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred
or payments made on our behalf. The following table summarizes employee related costs that were charged by DCP Midstream,
LLC to the Partnership that are included in the consolidated statements of operations:
Employee related costs charged by DCP Midstream, LLC
Operating and maintenance expense
General and administrative expense (including restructuring charges)
Phillips 66 and its Affiliates
Year Ended December 31,
2017
2016
2015
(millions)
$
$
197
182
$
$
206
197
$
$
224
194
We sell a portion of our residue gas and NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition,
we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Approximately
22% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2017. The primary production
commitment on certain contracts began a ratable wind down period in December 2014 and expires in January 2019. We
anticipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business.
Enbridge and its Affiliates
We sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and
purchase commodities from Enbridge and its affiliates in the ordinary course of business.
Unconsolidated Affiliates
We have entered into 10 to 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills
Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, Texas Express Pipeline LLC, or Texas Express
and Gulf Coast Express Pipeline, LLC, or Gulf Coast. Under the terms of these agreements, which commenced at each of the
pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput
volumes at rates defined in each of the pipelines’ respective tariffs.
We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide
gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell
commodities and provide services to unconsolidated affiliates in the ordinary course of business.
101
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern
Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than
general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and
Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of
Sand Hills and Southern Hills, 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 service fee, there is no limit on the reimbursements Sand Hills and Southern
Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur
on behalf of Sand Hills or Southern Hills.
Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates:
Phillips 66 (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates
Purchases and related costs from affiliates
Operating and maintenance and general administrative expenses
Enbridge (including its affiliates):
Sales of natural gas, NGLs and condensate to affiliates
Purchases and related costs from affiliates
Operating and maintenance and general administrative expenses
Unconsolidated affiliates:
Sales of natural gas, NGLs and condensate to affiliates
Transportation, processing, and other to affiliates
Purchases and related costs from affiliates
We had balances with affiliates as follows:
Phillips 66 (including its affiliates):
Accounts receivable
Accounts payable
Other assets
Enbridge (including its affiliates):
Accounts receivable
Accounts payable
Other assets
Other liabilities
Unconsolidated affiliates:
Accounts receivable
Accounts payable
Other assets
102
Year Ended December 31,
2017
2016
2015
(millions)
1,172
30
2
48
43
2
54
5
504
$
$
$
$
$
$
$
$
$
909
18
2
$
$
$
— $
33
4
43
5
432
$
$
$
$
$
695
—
4
—
50
6
70
3
368
December 31,
2017
December 31,
2016
(millions)
$
156
6
$
— $
$
11
9
$
— $
— $
24
53
4
$
$
$
115
4
2
1
3
1
1
18
41
5
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
7. Inventories
Inventories were as follows:
Natural gas
NGLs
Total inventories
$
$
December 31,
2017
December 31,
2016
$
(millions)
30
38
68
$
28
44
72
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 and related costs in the consolidated statements of
operations. We recognized lower of cost or market adjustments of $2 million, $3 million and $8 million during the years ended
December 31, 2017, 2016 and 2015, respectively.
8. 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,
2017
December 31,
2016
20 — 50 Years
35 — 60 Years
3 — 30 Years
$
$
(millions)
8,473
5,128
557
374
14,532
(5,549)
8,983
$
$
8,560
5,134
502
171
14,367
(5,298)
9,069
Interest capitalized on construction projects was $7 million, less than $1 million and $32 million for the years ended
December 31, 2017, 2016 and 2015, respectively.
Depreciation expense was $367 million, $366 million and $358 million for the years ended December 31, 2017, 2016 and
2015, respectively.
Asset Retirement Obligations
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.
The following table summarizes changes in the asset retirement obligations included in our balance sheets:
103
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Balance, beginning of period
Accretion expense
Change in ARO Estimate
Balance, end of period
$
$
December 31,
2017 (a)
2016 (a)
(millions)
124
$
8
(6)
126
$
120
7
(3)
124
(a) Asset retirement obligations are included in other long-term liabilities in the consolidated balance sheets. Accretion expense
is recorded within operating and maintenance expense in our consolidated statement of operations. Accretion expense for the
year ended December 31, 2015 was $7 million.
9. Goodwill
We performed our annual goodwill assessment during the third quarter of 2017 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 in our North reporting unit, the only reporting unit allocated goodwill
included within our Gathering and Processing reportable segment and in our Marysville reporting unit included within our
Logistics and Marketing reportable segment. For our Wholesale Propane reporting unit, which is included in our Logistics and
Marketing reportable segment, the fair value exceeded the carrying value (including approximately $37 million of allocated
goodwill) by approximately 5%. We concluded 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 (including forecasted volumes and commodity prices), as well as historical and other
factors. 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.
We expect that the fair value of our Wholesale Propane reporting unit will continue to exceed carrying value so long as our
estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile
propane prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average
costs of capital, and our cash flow estimates. Changes to any one or combination of these factors, would result in changes to the
reporting unit fair values discussed above which could lead to future impairment charges. Such potential impairment could
impact our results of operations.
The change in carrying amount of goodwill in each of our reportable segments was as follows:
Year Ended December 31
2017
2016
(millions)
Gathering
and
Processing
Logistics and
Marketing
Total
Gathering
and
Processing
Logistics and
Marketing
Total
Balance, beginning of period
Dispositions
Balance, end of period
$
$
164
(5)
159
$
$
236
(5)
231
$
$
170
(6)
164
$
$
72
—
72
$
$
242
(6)
236
72
—
72
$
$
104
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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:
December 31,
2017
2016
Gross carrying amount
Accumulated amortization
Accumulated impairment
Intangible assets, net
$
$
(millions)
$
410
(161)
(143)
106
$
410
(151)
(122)
137
We recorded amortization expense of $10 million, $12 million and $19 million for the years ended December 31,
2017, 2016 and 2015, respectively. As of December 31, 2017, the remaining amortization periods ranged from approximately
less than 1 year to 18 years, with a weighted-average remaining period of approximately 13 years.
Estimated future amortization for these intangible assets is as follows:
Estimated Future Amortization
(millions)
2018
2019
2020
2021
2022
Thereafter
Total
$
10
9
9
9
9
60
106
$
10. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
DCP Sand Hills Pipeline, LLC
Discovery Producer Services LLC
DCP Southern Hills Pipeline, LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Panola Pipeline Company, LLC
Mont Belvieu Enterprise Fractionator
Mont Belvieu 1 Fractionator
Other
Total investments in unconsolidated affiliates
Percentage
Ownership
December 31,
2017
December 31,
2016
Carrying Value as of
66.67%
40.00%
66.67%
33.33%
10.00%
15.00%
12.50%
20.00%
Various
$
$
(millions)
1,633
362
739
165
90
24
23
10
4
3,050
$
$
1,507
385
754
165
93
25
23
10
7
2,969
The following table represents the excess (deficit) of the carrying amount of the investment over (under) the underlying
equity of our investments in unconsolidated affiliates as of December 31, 2017 and 2016:
105
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
DCP Sand Hills Pipeline, LLC
Discovery Producer Services LLC
DCP Southern Hills Pipeline, LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu 1 Fractionator
Excess (deficit) of Carrying Value over (under)
Underlying Equity in Unconsolidated Affiliates
December 31,
2017
December 31,
2016
$
(millions)
$
648
(18)
145
4
3
(1)
662
(20)
148
5
3
(2)
Carrying amounts in excess or deficit of the underlying equity of our unconsolidated affiliates are amortized over the life
of the underlying long-lived assets of the affiliate.
Earnings from investments in unconsolidated affiliates were as follows:
DCP Sand Hills Pipeline, LLC
Discovery Producer Services LLC
DCP Southern Hills Pipeline, LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu Enterprise Fractionator
Mont Belvieu 1 Fractionator
Other
Total earnings from unconsolidated affiliates
Year Ended December 31,
2017
2016
(millions)
2015
$
$
148
61
47
17
9
13
6
2
303
$
$
110
73
44
19
9
16
9
2
282
63
54
18
17
8
15
9
—
$
184
The following tables summarize the combined financial information of our investments in unconsolidated affiliates:
Statements of operations:
Operating revenue
Operating expenses
Net income
Balance sheets:
Current assets
Long-term assets
Current liabilities
Long-term liabilities
Net assets
Year Ended December 31,
2017
2016
(millions)
2015
$
$
$
1,397
647
747
$
$
$
1,311
539
768
$
$
$
1,142
541
600
December 31,
2017
December 31,
2016
(millions)
$
$
244
5,319
(196)
(200)
5,167
$
$
232
5,274
(156)
(205)
5,145
106
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
11. Fair Value Measurement
Determination of Fair Value
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, 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
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 13 -
Risk Management and Hedging Activities.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the
same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. 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.
107
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
• 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 level of judgment involved in the most
significant input 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 exchange traded instruments (such as New
York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as
natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated
broker dealer serving as the clearinghouse for individual transactions.
Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage
commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based
trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market
conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such
instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded
instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy
we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments
are exchange traded, market prices 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 it is available;
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.
We also engage in the business of trading energy related products and services, which exposes us to market variables and
commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive
margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs
or other energy related products, primarily using 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.
Benefits
We offer certain eligible DCP Midstream, LLC executives the opportunity to participate in our DCP Midstream LP’s
Non-Qualified Executive Deferred Compensation Plan, or the EDC Plan. All amounts contributed to and earned by the EDC
Plan’s investments are held in a trust account, which is managed by a third-party service provider. The trust account is invested
in short-term money market securities and mutual funds. These investments are recorded at fair value, with any changes in fair
value being recorded as a gain or loss in our consolidated statements of operations. Given that the value of the short-term
108
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
money market securities and mutual funds are publicly traded and for which market prices are readily available, these
investments are classified within Level 1.
Interest Rate Derivative Assets and Liabilities
We periodically use interest rate swap agreements as part of our overall capital strategy. These instruments effectively
exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally
priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread
between the Partnership 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 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 other
long-lived 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.
During the year ended December 31, 2017, we recognized impairments of property, plant and equipment, intangible assets
and investment in unconsolidated affiliates of $48 million in our consolidated statement of operations as summarized in the
table below. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding
any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized
within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not
observable from objective sources.
Property, plant and equipment
Intangible assets
Investment in unconsolidated affiliates
Total impairments
Asset
Impairments
(millions)
$
$
26
21
1
48
On January 3, 2017, the Chicago Mercantile Exchange ("CME") modified its exchange rules to characterize daily
variation margin amounts as "final settlement" values. The modified rule ("CME Rule 814") impacts derivative financial
instruments traded on exchanges administered by the CME, including the New York Mercantile Exchange. As a result of this
rule change, we are reporting the affected derivative instruments on a net basis on our balance sheet. The netting process
results in the elimination of offsetting derivative assets, derivative liabilities and associated collateral cash deposits as if the
underlying derivative instruments had settled on the balance sheet date. Through December 31, 2016, we historically reported
such derivatives and associated collateral balances on a gross basis. Derivative transactions and associated collateral balances
cleared on exchanges other than the CME continue to be reported on a gross basis.
109
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
The following table presents the financial instruments carried at fair value as of December 31, 2017 and 2016, by
consolidated balance sheet caption and by valuation hierarchy, as described above:
December 31, 2017
December 31, 2016
Level 1
Level 2
Level 3
Total
Carrying
Value
Level 1
Level 2
Level 3
Total
Carrying
Value
(millions)
Current assets:
Commodity derivatives (a)
Short-term investments (b)
Long-term assets:
Commodity derivatives (c)
Current liabilities:
Commodity derivatives (d)
Long-term liabilities:
Commodity derivatives (e)
$
10
$
17
$
3
$
30
$
5
$
28
$
9
$
$ 156
$ — $ — $
156
$ — $ — $ — $
1
$
1
$
1
$
3
$ — $ — $
5
$
42
—
5
(29) $
(34) $
(13) $
(76) $
(11) $
(57) $
(23) $
(91)
(3) $
(11) $
(1) $
(15) $
(1) $ — $ — $
(1)
$
$
$
(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 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 would be reflected in a
table as Transfers into or out of Level 1 and Level 2. During the years ended December 31, 2017 and 2016, 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 would reflect such items in the table
below within the “Transfers into/out of Level 3” captions.
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.
110
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Commodity Derivative Instruments
Current
Assets
Long-Term
Assets
Current
Liabilities
Long-Term
Liabilities
Year ended December 31, 2017 (a):
Beginning balance
Net unrealized gains (losses) included in
earnings (b)
Transfers out of Level 3 (c)
Settlements
CME Rule 814 adjustment
Ending balance
Net unrealized gains (losses) on derivatives
still held included in earnings (b)
Year ended December 31, 2016 (a):
Beginning balance
Net unrealized gains (losses) included in
earnings (b)
Settlements
Ending balance
Net unrealized gains (losses) on derivatives
still held included in earnings (b)
$
$
$
$
$
$
9
$
14
—
(13)
(7)
3
3
35
3
(29)
9
9
$
$
$
$
$
(millions)
5
1
—
—
(5)
1
$
$
(4) $
4
1
—
5
3
$
$
$
(23) $
(44)
—
36
18
(13) $
(13) $
(23) $
(15)
15
(23) $
(23) $
—
(3)
2
—
—
(1)
(1)
(6)
6
—
—
6
(a) There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the years ended December 31,
2017 and 2016.
(b) Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net.
(c) Amounts transferred out of Level 3 are reflected at fair value at the end of the period.
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
Liabilities
NGLs
December 31, 2017
Fair Value
(millions)
Forward
Curve Range
$
$
4
$0.28-$0.82 Per gallon
(14)
$0.20-$1.08 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
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.
111
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
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, if any, 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, if any, 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 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.
We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from
bond dealers. We determine the fair value of borrowings under our Credit Agreement 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 classify the fair values of our outstanding debt balances within Level 2
of the valuation hierarchy. As of December 31, 2017 and December 31, 2016, the carrying value and fair value of our total debt,
including current maturities, were as follows:
Total debt
(a) Excludes unamortized issuance costs.
December 31, 2017
December 31, 2016
Carrying
Value (a)
Fair Value
Carrying
Value (a)
Fair Value
(millions)
$
4,736
$
4,885
$
5,430
$
5,395
112
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
12. Debt
Senior notes:
December 31,
2017
December 31,
2016
(millions)
Issued November 2012, interest at 2.500% payable semi-annually, due December 2017
$
— $
Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a)
Issued March 2014, interest at 2.700% payable semi-annually, due April 2019
Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a)
Issued September 2011, interest at 4.750% payable semiannually, due September 2021
Issued March 2012, interest at 4.950% payable semi-annually, due April 2022
Issued March 2013, interest at 3.875% payable semi-annually, due March 2023
Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a)
Issued October 2006, interest at 6.450% payable semi-annually, due November 2036
Issued September 2007, interest at 6.750% payable semi-annually, due September 2037
Issued March 2014, interest at 5.600% payable semi-annually, due April 2044
Junior subordinated notes:
Issued May 2013, interest at 5.850% payable semi-annually, due May 2043
Credit agreement:
Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December
31, 2016, due December 2022
Fair value adjustments related to interest rate swap fair value hedges (a)
Unamortized issuance costs
Unamortized discount
Total debt
Current maturities of long-term debt
Total long-term debt
450
325
600
500
350
500
300
300
450
400
550
—
23
(29)
(12)
4,707
—
$
4,707
$
500
450
325
600
500
350
500
300
300
450
400
550
195
24
(23)
(14)
5,407
500
4,907
(a) The swaps associated with this debt were previously terminated. The remaining long-term fair value of approximately
$23 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity
dates of the debt.
Credit Agreement
We are a party to a $1.4 billion unsecured revolving Credit Agreement which matures on December 6, 2022. The Credit
Agreement also grants us the option to increase the revolving loan commitment by an aggregate principal amount of up to $500
million, subject to requisite lender approval. The Credit Agreement may be extended for up to two additional one-year periods
subject to requisite lender approval. Loans under the Credit Agreement may be used for working capital and other general
partnership purposes including acquisitions.
The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for
purposes of calculating the Partnership’s Consolidated Leverage Ratio (as defined in the Credit Agreement). Additionally, under
the Credit Agreement, the Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed:
(a) 5.75 to 1.0 for the fiscal quarter ended December 31, 2017 (b) 5.50 to 1.0 for the fiscal quarter ending March 31, 2018, (c)
5.25 to 1.0 for the fiscal quarter ending June 30, 2018, and (d) 5.00 to 1.0 for each fiscal quarter ending thereafter; provided
that, if there is a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending June 30, 2018 or
thereafter, the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of the three consecutive fiscal
quarters, including the fiscal quarter in which the Qualified Acquisition occurs.
113
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. Indebtedness under the
Credit Agreement bears interest at either: (1) LIBOR, plus an applicable margin of 1.45% based on our current credit rating; or
(2) (a) the base rate which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBOR Market Index
rate plus 1%, plus (b) an applicable margin of 0.45% based on our current credit rating. The Credit Agreement incurs an annual
facility fee of 0.30% based on our current credit rating. This fee is paid on drawn and undrawn portions of the approximately
$1.4 billion revolving credit facility.
As of December 31, 2017, we had unused borrowing capacity of $1,375 million, net of $25 million of letters of credit,
under the Credit Agreement. Our borrowing capacity may be limited by financial covenants set forth in the Credit Agreement.
The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by the unused
borrowing capacity of $1,375 million as of December 31, 2017. Except in the case of a default, amounts borrowed under our
Credit Agreement will not become due prior to the December 6, 2022 maturity date.
Senior Notes and Junior Subordinated Notes
Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable
on their respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are
senior unsecured obligations that are guaranteed by the Partnership and rank equally in a right of payment with our other senior
unsecured indebtedness, including indebtedness under our Credit Agreement, and the junior subordinated notes are unsecured
and rank subordinate in right of payment to all of our existing and future senior indebtedness. The debt securities include an
optional redemption whereby we may elect to redeem the notes, in whole or in part from time-to-time for a premium.
Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up
to five consecutive years. The underwriters’ fees and related expenses are recorded in our consolidated balance sheets within
the carrying amount of long-term debt and will be amortized over the term of the notes.
The maturities of our long-term debt are as follows:
2018
2019
2020
2021
2022
Thereafter
Total long-term debt
Debt
Maturities
(millions)
—
775
600
500
350
2,500
4,725
$
$
13. Risk Management and Hedging Activities
Our 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 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
Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting;
however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for
the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of
accounting are discussed and summarized below.
114
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Natural Gas Asset Based Trading and Marketing
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 our natural gas storage facility 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 construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to
mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into
operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement
of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in
accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI
of our previously settled base gas cash flow hedges was in a loss position of $6 million as of December 31, 2017.
Commodity 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 may 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 derivative financial instruments used to mitigate a portion of the risk
of weakening natural gas, NGL and condensate prices extend through the first quarter of 2019. The commodity derivative
instruments used for our hedging programs are a combination of direct NGL product, crude oil and natural gas hedges. Crude
oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating
price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk
management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change
in fair value is reflected in the current period within our consolidated statements of operations as trading and marketing gains
and (losses), net.
NGL Proprietary Trading
Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities
through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term
contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk
with respect to these products and services, and these operations may enter into physical contracts and financial instruments
with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical
and financial instruments 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.
115
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based
trading and marketing and NGL proprietary trading.
Interest Rate Risk
We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to
changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert
our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to
floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive
interest rates.
We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying
transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to
interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value
hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt.
Credit Risk
Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and
services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our
NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately
22% of our NGL production was committed to Phillips 66 and CPChem as of December 31, 2017. This concentration of credit
risk may affect our overall credit risk, in that 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 may use various
master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral
language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The
threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also
provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our
master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to
suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a
satisfactory form.
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.
We have International Swaps and Derivatives 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.
• Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity
contracts in a net liability position, when our credit rating is below investment grade.
• 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 other credit
arrangements 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, 2017, we were not a party to any
agreements that would trigger the cross-default provisions.
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
116
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
with counterparties to our commodity derivative instruments or interest rate swap instruments are in either a net asset or net
liability position. As of December 31, 2017, we had less than $1 million of individual commodity derivative contracts that
contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position
with an individual counterparty, due to a credit-risk related event, our ISDA contracts may 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, 2017, we have not been required to post additional collateral. Although our commodity derivative contracts
that contain credit-risk related contingent features were in a net liability position as of December 31, 2017, the net liability
position would be offset by contracts in a net asset position.
Collateral
As of December 31, 2017, we had cash deposits of $75 million, included in collateral cash deposits in our consolidated
balance sheets, and letters of credit of $13 million with counterparties to secure our obligations to provide future services or to
perform under financial contracts. Additionally, as of December 31, 2017, we held cash of $18 million, included in other
current liabilities in our consolidated balance sheet, related to cash postings by third parties and letters of credit of $53 million
from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted
may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales,
services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which
may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These
transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion,
to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment
satisfactory to the seller.
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:
December 31, 2017
December 31, 2016
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments
Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet
Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments
Net
Amount
Net
Amount
(millions)
Assets:
Commodity derivatives
Liabilities:
Commodity derivatives
$
$
33
$
— $
33
$
47
$
— $
47
(91) $
— $
(91) $
(92) $
— $
(92)
117
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Summarized Derivative Information
The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within
our consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are
designated as hedging instruments for accounting purposes as of December 31, 2017 and December 31, 2016.
Balance Sheet Line Item
December 31,
2017
December 31,
2016
Balance Sheet Line Item
December 31,
2017
December 31,
2016
Derivative Assets Not Designated as Hedging Instruments: Derivative Liabilities Not Designated as Hedging
(millions)
(millions)
Commodity derivatives:
Unrealized gains on
derivative instruments —
current
Unrealized gains on
derivative instruments —
long-term
Total
$
$
Instruments:
Commodity derivatives:
Unrealized losses on
derivative instruments —
current
30
$
42
3
33
$
Unrealized losses on
derivative instruments —
long-term
5
47 Total
$
$
(76) $
(91)
(15)
(91) $
(1)
(92)
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, 2017:
Interest
Rate Cash
Flow
Hedges
Commodity
Cash Flow
Hedges
Foreign
Currency
Cash Flow
Hedges (a)
Total
Net deferred (losses) gains in AOCI (beginning balance)
Losses reclassified from AOCI to earnings — effective portion
Deficit purchase price under carrying value of the Transaction
Net deferred (losses) gains in AOCI (ending balance)
$
$
$
(3) $
1
(2) $
(4) $
(millions)
(6) $
—
— $
(6) $
$
1
—
— $
1
$
(8)
1
(2)
(9)
(a) Relates to Discovery, an unconsolidated affiliate
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, 2016:
Interest
Rate Cash
Flow
Hedges
Commodity
Cash Flow
Hedges
Foreign
Currency
Cash Flow
Hedges (a)
Total
Net deferred (losses) gains in AOCI (beginning balance)
Net deferred (losses) gains in AOCI (ending balance)
$
$
(3) $
(3) $
(millions)
(6) $
(6) $
1
1
$
$
(8)
(8)
(a) Relates to Discovery, an unconsolidated affiliate.
For the years ended December 31, 2017 and 2016, no derivative losses attributable to the ineffective portion or to
amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense
in our consolidated statements of operations. For the years ended December 31, 2017 and 2016, no derivative losses were
reclassified from AOCI to trading and marketing gains or losses, net or interest expense as a result of the discontinuance of cash
flow hedges related to certain forecasted transactions that are not probable of occurring.
118
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Changes in the 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
Realized (losses) gains
Unrealized (losses) gains
Trading and marketing (losses) gains, net
Year Ended December 31,
2017
2016
(millions)
2015
$
$
(12) $
(28)
(40) $
$
116
(139)
(23) $
73
46
119
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
2018
2019
2020
Year of Expiration
2017
2018
2019
2020
December 31, 2017
Crude Oil
Natural Gas
Net Short
Position
(Bbls)
(2,701,000)
(631,000)
(50,000)
Net Short
Position
(MMBtu)
(35,977,400)
—
—
Natural Gas
Liquids
Net (Short) Long
Position
(Bbls)
Natural Gas
Basis Swaps
Net Long
Position
(MMBtu)
(19,656,392)
(2,357,156)
238,548
3,202,500
7,177,500
3,660,000
December 31, 2016
Crude Oil
Natural Gas
Net Short
Position
(Bbls)
(1,470,000)
(251,000)
(40,000)
(50,000)
Net Short
Position
(MMBtu)
(44,981,850)
—
—
—
Natural Gas
Liquids
Natural Gas
Basis Swaps
Net (Short) Long
Position
(Bbls)
Net (Short) Long
Position
(MMBtu)
(22,225,821)
144,805
(2,203)
240,000
6,510,000
912,500
—
—
14. Partnership Equity and Distributions
Preferred Units — On November 20, 2017, we issued 500,000 of our Series A Preferred Units representing limited
partnership interests at a price of $1,000 per unit. We used the net proceeds of $487 million from the issuance of the Series A
Preferred Units to partially repay the $500 million 2.50% Senior Notes which were due on December 1, 2017.
Distributions of the Series A Preferred Units are payable out of available cash, accrue and are cumulative from the date of
original issuance of the Series A Preferred Units and are payable in arrears on June 15th and December 15th through and
including December 15, 2022, and, after December 15, 2022, quarterly in arrears on March 15th, June 15th, September 15th,
and December 15th of each year to holders of record as of the close of business on the first business day of the month. The
initial distribution rate will be 7.375% per year of the $1,000 liquidation preference per unit (equal to $73.75 per unit). On and
after December 15, 2022, distributions will accumulate at a percentage of the $1,000 liquidation preference equal to an annual
floating rate of the three-month LIBOR plus a spread of 5.148%. The Series A Preferred Units rank senior to our common units
with respect to distribution rights and rights upon liquidation.
At any time prior to December 15, 2022, within 120 days of a ratings event, we may, at our option, redeem the Series A
Preferred Units in whole, but not in part, at a redemption price per unit equal to $1,020 (102% of the liquidation preference),
plus an amount equal to all accumulated and unpaid distributions. At any time on or after December 15, 2022, we may redeem,
in whole or in part, the units at a redemption price of $1,000 per unit, plus an amount equal to all accumulated and unpaid
119
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
distributions. Upon occurrence of a change in control triggering event, we may, at our option, (i) redeem the Series A Preferred
Units, in whole or in part, within 120 days, by paying $1,000 per unit, plus all accumulated and unpaid distributions, and (ii)
each holder of Series A Preferred Units will have the right (unless the Partnership provided notice of its election to redeem such
holder’s Series A Preferred Units) to convert some or all of the Series A Preferred Units held by such holder on the change of
control conversion date into a number of the Partnership’s common units per Series A Preferred Unit as defined in our
Partnership Agreement. Holders of the Series A Preferred Units have no voting rights except for certain limited protective
voting rights set forth in our Partnership Agreement.
Common Units — In January 2017, we issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general
partner units to the General Partner in a private placement as consideration for the Transaction that closed on January 1, 2017.
For additional information regarding the Transaction, see Note 4 - Acquisitions.
During the years ended December 31, 2017 and 2016, we issued no common units pursuant to our 2014 equity
distribution agreement. As of December 31, 2017, approximately $750 million of common units remained available for sale
pursuant to our at-the-market program. During the year ended December 31, 2015, we issued 788,033 common units pursuant
to our 2014 equity distribution agreement and received proceeds of $31 million, net of commissions and offering costs of less
than $1 million.
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 our general partner to:
•
•
•
•
provide for the proper conduct of our business, including reserves for future capital expenditures and
anticipated credit needs;
comply with applicable law or any debt instrument or other agreement or obligation;
provide funds to make payments on the 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units; or
provide funds for distributions to our common 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 2% and limited partner interest of approximately
36% as of December 31, 2017. 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 or limited 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.
As part of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions
payable to our General Partner under our Partnership Agreement of up to $100 million annually through 2019 to target an
approximate 1.0 times distribution coverage ratio. Under the terms of our amended Partnership Agreement, the amount of
incentive distributions paid to our General Partner will be evaluated by our General Partner on both a quarterly and annual basis
and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If no determination is
made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback, of up to $100 million
annually, will be subject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our
120
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
amended Partnership Agreement) less the total annual distribution payable to our unitholders, adjusted to target an approximate
1.0 times coverage ratio. Distributions paid to the holders of the Partnership's incentive distribution rights were reduced by $40
million during the year ended December 31, 2017, in accordance with the Third Amendment to the Partnership Agreement.
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 2017, 2016 and 2015:
Payment Date
November 14, 2017
August 14, 2017
May 15, 2017
February 14, 2017
November 14, 2016
August 12, 2016
May 13, 2016
February 12, 2016
November 13, 2015
August 14, 2015
May 15, 2015
February 13, 2015
Per Unit
Distribution
Total Cash
Distribution
(millions)
$
$
$
$
$
$
$
$
$
$
$
$
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
0.7800
$
$
$
$
$
$
$
$
$
$
$
$
155
134
135
121
120
121
121
121
120
121
121
120
15. Equity-Based Compensation
On April 28, 2016, the unitholders of the Partnership approved the 2016 Long-Term Incentive Plan (the “2016 LTIP”),
which replaced the 2005 Long-Term Incentive Plan that expired pursuant to its terms at the end of 2015 (the “2005 LTIP” and,
together with the 2012 LTIP and the 2016 LTIP, the “LTIP”). Any outstanding awards under the 2005 LTIP will remain
outstanding and settle according to the terms of such grant. The 2016 plan authorizes up to 900,000 common units to be
available for issuance under awards to employees, officers, and non-employee directors of the General Partner and its
affiliates. Awards under the 2016 LTIP may include unit options, phantom units, restricted units, distribution equivalent rights,
unit bonuses, common unit awards, and performance awards. The 2016 LTIP will expire on the earlier of the date it is
terminated by the board of directors of the General Partner or the date that all common units available under the plan have been
paid or issued.
On November 28, 2005, the board of directors of the General Partner adopted 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. The 2005 LTIP phantom units consist of a notional unit based on the
value of the Partnership's common units. 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 the 2012 LTIP (the "2012 LTIP") for employees, consultants and directors of
our General Partner and its affiliates who perform services for us. The 2012 LTIP provided for the grant of phantom units and
121
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
DERs. The 2012 LTIP phantom units consist of a notional unit based on the value of common units or shares of 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 under the LTIPs are subject to cliff
vesting.
Since we have the intent and ability to settle certain awards within our control in units, we classify them as equity awards
based on their fair value. The fair value of our equity awards is determined based on the closing price of our common units on
the grant date. Compensation expense on equity awards is recognized ratably over each vesting period. We account for other
awards which are subject to settlement in cash, including DERs, 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 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.
Under DCP Midstream, LLC's Long-Term Incentive Plan ("DCP Midstream LTIP"), awards may be granted to key
employees. The DCP Midstream LTIP provides for the grant of Strategic Performance Units ("SPUs") and Phantom Units. The
SPUs and Phantom Units consist of a notional unit based on the weighted average value of common shares of Phillips 66 and
Enbridge as of the grant date. Each award provides for the grant of dividend or distribution equivalent rights, or DERs. The
DCP Midstream LTIP is administered by the compensation committee of DCP Midstream, LLC's board of directors. All awards
are subject to cliff vesting.
Liability classified equity-based compensation expense was $23 million, $18 million and $8 million for the years ended
December 31, 2017, 2016 and 2015, respectively.
122
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
The following table presents the fair value of unvested unit-based awards related to the strategic performance units and
phantom units:
DCP Midstream LTIP:
SPUs
Phantom Units
Unrecognized
Compensation
Expense at
December 31,
2017
(millions)
Vesting
Period
(years)
Estimated
Forfeiture
Rate
Weighted-
Average
Remaining
Vesting
(years)
3
1-3
$
$
7
4
0%-11%
0%-11%
2
2
Strategic Performance Units - The number of SPUs that will ultimately vest range in value of up to 200% of the
outstanding SPUs, depending on the achievement of specified performance targets over a three year period. The final
performance payout is determined by the compensation committee of our General Partner. The DERs are paid in cash at the end
of the performance period. The following table presents information related to SPUs:
Grant Date
Weighted-Average
Price Per Unit
Measurement Date
Weighted-Average
Price Per Unit
Units
Outstanding at January 1, 2015
Granted
Forfeited
Vested (a)
Outstanding at December 31, 2015
Granted
Forfeited
Vested (b)
Outstanding at December 31, 2016
Granted
Forfeited
Vested (c)
Outstanding at December 31, 2017
Expected to vest
(a) The 2013 grants vested at 115%.
(b) The 2014 grants vested at 130%.
(c) The 2015 grants vested at 180%.
219,363
111,930
(29,283)
(93,551)
208,459
131,610
(8,463)
(98,295)
233,311
98,628
(18,577)
(98,627)
214,735
161,909
$
$
$
$
$
$
$
$
$
$
$
$
$
$
47.89
43.25
48.02
41.02
48.46
45.31
46.27
54.05
44.41
76.38
50.31
58.80
51.98
54.52
$
$
55.61
59.37
The estimate of SPUs that are expected to vest is based on highly subjective assumptions that could change over time,
including the expected forfeiture rate and achievement of performance targets.
The following table presents the fair value of units vested and the unit-based liabilities paid for unit-based awards related
to the strategic performance units:
Units
Fair Value of Units
Vested
Unit-Based
Liabilities Paid
Vested or paid in cash in 2015
Vested or paid in cash in 2016
Vested or paid in cash in 2017
93,551
98,295
98,627
$
$
$
(millions)
4
7
11
$
$
$
7
4
7
123
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Phantom Units - The DERs are paid quarterly in arrears. The following table presents information related to Phantom
Units:
Units
Grant Date
Weighted-Average
Price Per Unit
Measurement Date
Weighted-Average
Price Per Unit
Outstanding at January 1, 2015
Granted
Forfeited
Vested
Outstanding at December 31, 2015
Granted
Forfeited
Vested
Outstanding at December 31, 2016
Granted
Forfeited
Vested
Outstanding at December 31, 2017
Expected to vest
171,202
147,540
(17,400)
(96,974)
204,368
132,870
(3,240)
(126,681)
207,317
180,337
(16,677)
(169,896)
201,081
188,605
$
$
$
$
$
$
$
$
$
$
$
$
$
$
48.11
47.84
48.40
44.00
49.85
45.33
48.62
50.13
46.80
59.43
51.73
53.35
52.18
52.13
$
$
62.56
62.99
The following table presents the fair value of units vested and the unit-based liabilities paid for unit based awards related to
the phantom units:
Units
Fair Value of
Units Vested
Unit-Based
Liabilities Paid
Vested or paid in cash in 2015
Vested or paid in cash in 2016
Vested or paid in cash in 2017
96,974
126,681
169,896
$
$
$
(millions)
3
4
7
$
$
$
5
5
4
16. Benefits
We do not have our own employees. The employees supporting our operations are employees of DCP Services, LLC, for
which we incur charges under the Services Agreement. All DCP Services, LLC employees who have reached the age of 18 and
work at least 20 hours per week are eligible for participation in the 401(k) and retirement plan, to which a range of 4% to 7% of
each eligible employee’s qualified earnings is contributed to the retirement plan, based on years of service. All new employees
are automatically enrolled in the 401(k) plan at a 6% contribution level. Employees can opt out of these contribution level or
change it at any time. Additionally, DCP Services, LLC matches employees’ contributions in the 401(k) plan up to 6% of
qualified earnings. During the years ended December 31, 2017, 2016 and 2015, we expensed plan contributions of $29 million,
$29 million and $32 million, respectively.
DCP Services, LLC offers certain eligible executives the opportunity to participate in the EDC Plan. The EDC Plan allows
participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The
EDC Plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can
contribute to the 401(k) plan on the participant’s behalf.
124
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
17. 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
method. Dilutive potential units include outstanding awards under the LTIP.
18. 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. We owned a corporation that filed its own federal, foreign and state corporate income tax returns.
During the year ended December 31, 2016, we elected to convert the corporation to a limited liability company for federal
income tax purposes. The income tax (expense) benefit related to this corporation is included in our income tax (expense)
benefit, along with state and local taxes of the limited liability entities.
Income tax (expense) benefit consists of the following:
Current:
Federal income tax expense
State income tax expense
Deferred:
Federal income tax (expense) benefit
State income tax (expense) benefit
Total income tax (expense) benefit
Year Ended December 31,
2016
2015
2017
(millions)
$
$
— $
(1)
—
(1)
(2) $
(19) $
(2)
(22)
(3)
(46) $
—
—
97
5
102
As of December 31, 2017 and 2016, we had state deferred tax liabilities of $29 million and $28 million, respectively. The
state deferred tax liabilities are primarily associated with Texas franchise taxes. During the year ended December 31, 2016, we
recorded a reduction to our net federal deferred tax asset of $58 million resulting from the conversion of our corporation to a
limited liability company.
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, primarily
Texas. The State of Texas imposes a margin tax that is assessed at 0.75%, of taxable margin apportioned to Texas for each year
ended December 31, 2017, 2016 and 2015.
125
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
19. Commitments and Contingent Liabilities
Litigation — We are not a party to any 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 results of operations,
financial position, or cash flow.
Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our
insurance coverage includes: (1) general liability insurance covering third-party exposures; (2) statutory workers’ compensation
insurance; (3) automobile liability insurance for all owned, non-owned and hired vehicles; (4) excess liability insurance above
the established primary limits for general liability and automobile liability insurance; (5) property insurance, which covers the
replacement value of real and personal property and includes business interruption; and (6) 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 with similar types of operations.
Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating,
fractionating, 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 laws and
regulations at the federal, state and, in some cases, local levels that relate to worker safety, air and water quality, solid and
hazardous 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, worker safety
standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) city, state and
federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental impacts of
this technique, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs, (ii)
from federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens and
increase the cost of our operations, and (iii) from state and federal regulatory officials regarding the emission of greenhouse
gases which could impose regulatory burdens and increase the cost of our operations, and (iv) regulatory bodies and
communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other
facilities used in our business. Failure to comply with these various health, safety and environmental 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 existing
laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.
126
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
We make expenditures in connection with environmental matters as part of our normal operations. As of December 31,
2017 and 2016, environmental liabilities included in our consolidated balance sheets as other current liabilities were $4 million
and $4 million, respectively. As of December 31, 2017 and 2016, environmental liabilities included in our consolidated balance
sheets as other long-term liabilities were $8 million and $9 million, respectively.
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 $33 million, $37 million and $34 million
for the years ended December 31, 2017, 2016, and 2015, 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, 2017:
2018
2019
2020
2021
2022
Thereafter
Total minimum rental payments
Future Minimum
Rental Payments as of
December 31, 2017
(millions)
$
$
37
34
30
20
15
28
164
127
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
20. Restructuring Costs
In April 2016, we announced an approximate 10 percent headcount reduction, which involved the elimination of certain
operational and corporate positions, as part of ongoing effort to create efficiencies, reduce costs and transform our business. As
a result of this headcount reduction, we recorded one-time employee termination costs of approximately $13 million, which are
included in restructuring costs in our consolidated statements of operations for the year ended December 31, 2016.
In January 2015, we announced the initial phase of this cost reduction plan, which involved the elimination of certain
corporate employee positions. As a result, we recorded employee termination costs of approximately $11 million, all of which
were paid during the year ended December 31, 2015, and are included in restructuring costs in the consolidated statement of
operations for the year ended December 31, 2015.
21. Business Segments
Our operations are organized into two reportable segments: (i) Gathering and Processing and (ii) Logistics and Marketing.
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. Our Gathering and Processing reportable segment includes
operating segments that have been aggregated based on the nature of the products and services provided. Gross margin is a
performance measure utilized by management to monitor the operations of each segment. The accounting policies of the
reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 -
Summary of Significant Accounting Policies.
Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing
and fractionating NGLs, and recovering condensate. Our Logistics and Marketing segment includes transporting, trading,
marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our
business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment
transactions are reflected in the eliminations column.
The following tables set forth our segment information:
Year Ended December 31, 2017:
Gathering and
Processing
Logistics and
Marketing
Other
(millions)
Eliminations
Total
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense
Gain on sale of assets, net
Earnings from unconsolidated affiliates
Interest expense
Income tax expense
Net income (loss)
Net income attributable to noncontrolling
interests
Net income (loss) attributable to partners
Non-cash derivative mark-to-market (b)
Non-cash lower of cost or market adjustments
Capital expenditures
Investments in unconsolidated affiliates, net
$
$
$
$
$
$
$
$
7,757
200
(41)
(14)
(11)
—
(11)
—
243
—
—
366
$
$
$
—
366
$
(4) $
$
2
$
3
$
147
— $
— $
(18)
(22)
(260)
—
—
—
—
(289)
(2)
(591) $
—
(591) $
— $
— $
22
$
— $
(4,762) $
— $
—
—
—
—
—
—
—
—
—
— $
—
— $
— $
— $
— $
— $
8,462
1,577
(661)
(379)
(290)
(48)
(11)
34
303
(289)
(2)
234
(5)
229
(28)
2
375
148
5,467
1,377
(602)
(343)
(19)
(48)
—
34
60
—
—
459
$
$
$
(5)
454
$
(24) $
— $
$
350
$
1
128
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Year Ended December 31, 2016:
Gathering and
Processing
Logistics and
Marketing
Other
Eliminations
Total
(millions)
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Other income (expense), net
Gain on sale of assets, net
Restructuring costs
Earnings from unconsolidated affiliates
Interest expense
Income tax expense
Net income (loss)
Net income attributable to noncontrolling
interests
Net income (loss) attributable to partners
Non-cash derivative mark-to-market (b)
Non-cash lower of cost or market adjustments
Capital expenditures
Investments in unconsolidated affiliates, net
$
$
$
$
$
$
$
$
4,490
1,227
(611)
(344)
(14)
73
19
—
73
—
—
423
$
$
$
(6)
417
$
(119) $
— $
$
107
$
1
6,186
205
(43)
(15)
(9)
(5)
16
—
209
—
—
358
$
$
$
—
358
$
(20) $
$
3
$
10
$
52
— $
— $
(16)
(19)
(269)
(3)
—
(13)
—
(321)
(46)
(687) $
—
(687) $
— $
— $
$
27
— $
(3,783) $
— $
—
—
—
—
—
—
—
—
—
— $
—
— $
— $
— $
— $
— $
6,893
1,432
(670)
(378)
(292)
65
35
(13)
282
(321)
(46)
94
(6)
88
(139)
3
144
53
Year Ended December 31, 2015:
Gathering and
Processing
Logistics and
Marketing
Other
Eliminations
Total
(millions)
Total operating revenue
Gross margin (a)
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairment
Other expense
Gain on sale of assets, net
Restructuring costs
Earnings from unconsolidated affiliates
Interest expense
Income tax benefit
Net (loss) income
Net income attributable to noncontrolling
interests
Net (loss) income attributable to partners
Non-cash derivative mark-to-market (b)
Non-cash lower of cost or market adjustments
Capital expenditures
Investments in unconsolidated affiliates, net
$
$
$
$
$
$
$
$
6,487
236
(49)
(16)
(11)
(9)
(8)
—
—
130
—
—
273
$
$
$
—
273
$
(1) $
$
8
$
52
$
49
— $
— $
(15)
(18)
(248)
(27)
(1)
—
(11)
—
(320)
102
(538) $
—
(538) $
— $
— $
30
$
— $
(3,967) $
— $
—
—
—
—
—
—
—
—
—
—
— $
—
— $
— $
— $
— $
— $
7,430
1,449
(732)
(377)
(281)
(912)
(10)
42
(11)
184
(320)
102
(866)
(5)
(871)
46
8
811
64
$
$
4,910
1,213
(668)
(343)
(22)
(876)
(1)
42
—
54
—
—
(601) $
(5)
(606) $
$
47
— $
$
729
$
15
129
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Segment long-term assets:
Gathering and Processing
Logistics and Marketing
Other (c)
Total long-term assets
Current assets
Total assets
December 31,
December 31,
2017
2016
(millions)
$
$
8,943
3,348
265
12,556
1,322
13,878
$
$
9,053
3,278
286
12,617
994
13,611
(a) Gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Gross
margin is viewed as a non-GAAP financial 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) Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity
derivative contracts.
(c) Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.
22. Supplemental Cash Flow Information
Cash paid for interest:
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 and accrued
liabilities
Other non-cash changes in property, plant and equipment
Contribution of assets from our predecessor
Year Ended December 31,
2017
2016
(millions)
2015
$
$
$
$
$
290
2
58
5
$
$
$
$
— $
306
2
$
$
293
3
$
27
(3) $
— $
35
(19)
1,500
130
23. Quarterly Financial Data (Unaudited)
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Our consolidated results of operations by quarter for the years ended December 31, 2017 and 2016 were as follows
(millions, except per unit amounts):
2017
Total operating revenues
Operating income (loss)
Net income (loss)
Net income attributable to noncontrolling interests
Net income (loss) attributable to partners
Net income (loss) allocable to limited partners
Basic and diluted net income (loss) per limited partner unit
2016
Total operating revenues
Operating income (loss)
Net income (loss)
Net income attributable to noncontrolling interests
Net income (loss) attributable to partners
Net loss attributable to predecessor operations
Net income allocable to limited partners
Basic and diluted net income per limited partner unit
First
Second
Third
Fourth
Year Ended
December
31, 2017
2,121
101
101
$
$
$
1,949
78
89
$
$
$
2,055
$
(19) $
(20) $
2,337
62
64
$
$
$
8,462
222
234
— $
101
59
0.41
First
1,464
80
65
$
$
$
$
$
$
(1) $
$
88
— $
(20) $
(4) $
$
60
47
0.33
$
$
(59) $
14
(0.41) $
0.10
$
$
(5)
229
61
0.43
Second
Third
Fourth
Year Ended
December
31, 2016
1,623
$
(12) $
(21) $
1,823
92
89
$
$
$
$
1,983
19
$
(39) $
6,893
179
94
— $
(1) $
— $
(5) $
65
$
(22) $
89
$
(44) $
(6)
88
(7) $
(67) $
(31) $
(119) $
(224)
41
0.36
$
$
14
0.12
$
$
89
0.78
$
$
44
0.38
$
$
188
1.64
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
24. 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, 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, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt
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.
131
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Condensed Consolidating Balance Sheet
December 31, 2017
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
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
$
$
$
— $
155
$
1
$
— $
—
—
—
—
—
—
2,895
4,513
—
—
—
—
—
155
—
—
1,614
7,522
—
—
981
68
117
1,167
8,983
337
—
—
3,050
186
7,408
$
9,291
$
13,723
$
—
—
—
—
—
—
(4,509)
(12,035)
—
—
(16,544) $
156
981
68
117
1,322
8,983
337
—
—
3,050
186
13,878
— $
71
$
1,417
$
— $
1,488
—
—
—
—
7,408
—
7,408
—
7,408
—
4,707
—
4,778
4,517
(4)
4,513
—
4,513
4,509
—
245
6,171
7,527
(5)
7,522
30
7,552
(4,509)
—
—
(4,509)
(12,035)
—
(12,035)
—
(12,035)
(16,544) $
—
4,707
245
6,440
7,417
(9)
7,408
30
7,438
13,878
Total liabilities and equity
$
7,408
$
9,291
$
13,723
$
132
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Condensed Consolidating Balance Sheet
December 31, 2016
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
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
Current maturities of long-term debt
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
$
$
$
— $
— $
1
$
— $
—
—
—
—
—
—
2,953
3,868
—
—
—
—
—
—
—
—
2,760
6,587
—
—
792
72
129
994
9,069
373
—
—
2,969
206
6,821
$
9,347
$
13,611
$
—
—
—
—
—
—
(5,713)
(10,455)
—
—
(16,168) $
1
792
72
129
994
9,069
373
—
—
2,969
206
13,611
— $
72
$
1,051
$
— $
1,123
—
—
—
—
—
6,821
—
6,821
—
6,821
500
—
4,907
—
5,479
3,871
(3)
3,868
—
3,868
—
5,713
—
228
6,992
6,592
(5)
6,587
32
6,619
—
(5,713)
—
—
(5,713)
500
—
4,907
228
6,758
(10,455)
—
(10,455)
—
(10,455)
(16,168) $
6,829
(8)
6,821
32
6,853
13,611
Total liabilities and equity
$
6,821
$
9,347
$
13,611
$
133
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2017
Parent
Guarantor
Subsidiary
Issuer
Non-
Guarantor
Subsidiaries
(millions)
Consolidating
Adjustments
Consolidated
Operating revenues:
Sales of natural gas, NGLs and condensate
$
— $
— $
7,850
$
— $
Transportation, processing and other
Trading and marketing losses, net
Total operating revenues
Operating costs and expenses:
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Gain on sale of assets, net
Other expense, net
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
—
—
—
—
—
—
—
—
—
—
—
—
—
229
—
229
—
229
—
—
—
—
—
—
—
—
—
—
—
—
—
(289)
518
—
229
—
229
—
Net income attributable to partners
$
229
$
229
$
652
(40)
8,462
6,885
661
379
290
48
(34)
11
8,240
222
—
—
303
525
(2)
523
—
—
—
—
—
—
—
—
—
—
—
—
—
(747)
—
(747)
—
(747)
(5)
518
$
—
(747) $
7,850
652
(40)
8,462
6,885
661
379
290
48
(34)
11
8,240
222
(289)
—
303
236
(2)
234
(5)
229
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
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2017
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
$
229
$
229
$
523
$
(747) $
234
—
1
1
230
—
1
—
1
230
—
—
—
—
523
(5)
—
(1)
(1)
(748)
—
1
—
1
235
(5)
$
230
$
230
$
518
$
(748) $
230
134
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Condensed Consolidating Statement of Operations
Year Ended December 31, 2016
Parent
Guarantor
Subsidiary
Issuer
Non-
Guarantor
Subsidiaries
(millions)
Consolidating
Adjustments
Consolidated
Operating revenues:
Sales of natural gas, NGLs and condensate
$
— $
— $
6,269
$
— $
Transportation, processing and other
Trading and marketing losses, net
Total operating revenues
Operating costs and expenses:
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Gain on sale of assets, net
Restructuring costs
Other income, net
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
Net income attributable to partners
$
—
—
—
—
—
—
—
—
—
—
—
—
—
88
—
88
—
88
—
88
$
—
—
—
—
—
—
—
—
—
—
—
—
(321)
409
—
88
—
88
—
88
647
(23)
6,893
5,461
670
378
292
(35)
13
(65)
6,714
179
—
—
282
461
(46)
415
—
—
—
—
—
—
—
—
—
—
—
—
—
(497)
—
(497)
—
(497)
(6)
409
$
—
(497) $
$
6,269
647
(23)
6,893
5,461
670
378
292
(35)
13
(65)
6,714
179
(321)
—
282
140
(46)
94
(6)
88
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
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2016
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
$
88
$
88
$
415
$
(497) $
(millions)
—
—
—
88
—
—
—
—
88
—
—
—
—
415
(6)
—
—
—
(497)
—
$
88
$
88
$
409
$
(497) $
135
94
—
—
—
94
(6)
88
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Operating revenues:
Sales of natural gas, propane, NGLs and
condensate
Transportation, processing and other
Trading and marketing gains, net
Total operating revenues
Operating costs and expenses:
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Gain on sale of assets, net
Restructuring costs
Other expense, net
Total operating costs and expenses
Operating loss
Interest expense, net
Income from consolidated subsidiaries
Earnings from unconsolidated affiliates
Loss before income taxes
Income tax benefit
Net loss
Net income attributable to noncontrolling
interests
Condensed Consolidating Statement of Operations
Year Ended December 31, 2015
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
$
— $
— $
6,779
$
— $
6,779
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(871)
—
(871)
—
(871)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(320)
(551)
—
(871)
—
(871)
532
119
7,430
5,981
732
377
281
912
(42)
11
10
8,262
(832)
—
—
184
(648)
102
(546)
—
(871) $
(5)
(551) $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,422
—
1,422
—
1,422
—
1,422
$
532
119
7,430
5,981
732
377
281
912
(42)
11
10
8,262
(832)
(320)
—
184
(968)
102
(866)
(5)
(871)
Net loss attributable to partners
$
(871) $
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 loss
Total comprehensive income
attributable to noncontrolling interests
Total comprehensive loss attributable to
partners
Condensed Consolidating Statement of Comprehensive Income
Year Ended December 31, 2015
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
$
(871) $
(871) $
(546) $
1,422
$
(866)
—
1
1
(870)
—
1
—
1
(870)
—
—
—
—
(546)
(5)
—
(1)
(1)
1,421
—
1
—
1
(865)
(5)
$
(870) $
(870) $
(551) $
1,421
$
(870)
136
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
INVESTING ACTIVITIES:
Intercompany transfers
Capital expenditures
Investments in unconsolidated affiliates
Proceeds from sale of assets
Net cash provided by (used in) investing
activities
FINANCING ACTIVITIES:
Intercompany transfers
Proceeds from long-term debt
Payments of long-term debt
Proceeds from issuance of preferred Series A
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
Other
Net cash used in financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of
period
Condensed Consolidating Statement of Cash Flows
Year Ended December 31, 2017
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
$
— $
(283) $
1,179
$
— $
896
58
—
—
—
58
—
—
—
487
—
(545)
—
—
(58)
—
—
1,141
—
—
—
1,141
—
116
(811)
—
—
—
—
(8)
(703)
155
—
—
(375)
(148)
132
(391)
(1,199)
—
—
—
418
—
(7)
—
(788)
—
1
1
$
(1,199)
—
—
—
(1,199)
1,199
—
—
—
—
—
—
—
1,199
—
—
— $
—
(375)
(148)
132
(391)
—
116
(811)
487
418
(545)
(7)
(8)
(350)
155
1
156
Cash and cash equivalents, end of period
$
— $
155
$
137
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
$
INVESTING ACTIVITIES:
Intercompany transfers
Capital expenditures
Investments in unconsolidated affiliates, net
Proceeds from sale of assets
Net cash provided by (used in) investing
activities
FINANCING ACTIVITIES:
Intercompany transfers
Proceeds from long-term debt
Payments of long-term debt
Net change in advances to predecessor from
DCP Midstream, LLC
Distributions to limited partners and general
partner
Distributions to noncontrolling interests
Other
Net cash used in financing activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of
period
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2016
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
— $
(305) $
950
$
— $
645
585
—
—
—
585
—
3,353
(3,628)
—
—
—
(5)
(280)
—
483
—
—
—
483
—
—
—
—
(483)
—
—
(483)
—
—
—
(144)
(53)
163
(1,068)
—
—
—
(34)
(1,068)
(1,068)
—
—
157
—
(7)
—
(918)
(2)
1,068
—
—
—
—
—
—
1,068
—
—
— $
—
(144)
(53)
163
(34)
—
3,353
(3,628)
157
(483)
(7)
(5)
(613)
(2)
3
1
—
— $
3
1
$
Cash and cash equivalents, end of period
$
— $
138
DCP MIDSTREAM, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016 and 2015 - (Continued)
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2015 (a)
Parent
Guarantor
Subsidiary
Issuer
Non-Guarantor
Subsidiaries
Consolidating
Adjustments
Consolidated
(millions)
— $
(311) $
753
$
— $
442
OPERATING ACTIVITIES
Net cash (used in) provided by operating
activities
$
INVESTING ACTIVITIES:
Intercompany transfers
Capital expenditures
Investments in unconsolidated affiliates, net
Proceeds from sale of assets
Net cash (used in) provided by investing
activities
FINANCING ACTIVITIES:
Intercompany transfers
Proceeds from long-term debt
Payments of long-term debt
Payments of commercial paper, net
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
Other
Net cash provided by (used in) financing
activities
Net change in cash and cash equivalents
Cash and cash equivalents, beginning of year
(1,049)
1,283
—
—
—
—
—
—
(1,049)
1,283
—
—
—
—
31
1,500
(482)
—
—
1,049
—
—
—
7,216
(7,196)
(1,012)
—
—
—
—
(4)
(996)
(24)
24
—
(811)
(64)
164
(711)
(234)
—
—
—
—
197
—
(5)
—
(42)
—
3
3
$
(234)
—
—
—
(234)
234
—
—
—
—
—
—
—
—
234
—
—
— $
—
(811)
(64)
164
(711)
—
7,216
(7,196)
(1,012)
31
1,697
(482)
(5)
(4)
245
(24)
27
3
Cash and cash equivalents, end of year
$
— $
— $
25. Subsequent Events
On January 23, 2018, we announced that the board of directors of the General Partner declared a quarterly distribution of
$0.78 per unit. The distribution was paid on February 14, 2018 to unitholders of record on February 7, 2018.
On February 14, 2018, the Partnership distributed $40 million of IDR givebacks to our owners, in conjunction with the
quarterly distribution, that were previously withheld under the amended Partnership agreement.
139
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, 2017.
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 SEC under the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), is recorded, processed, summarized and reported within the time periods specified by the SEC’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, 2017, pursuant to
Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of December 31,
2017, our disclosure controls and procedures were effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
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 quarter ended December 31, 2017 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, 2017 based on the "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, 2017.
Deloitte & Touche, LLP, an independent registered public accounting firm, has issued their report, included immediately
following, regarding our internal control over financial reporting.
140
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
DCP Midstream GP, LLC
Denver, Colorado
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of DCP Midstream, LP and subsidiaries (the "Partnership") as of
December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal
Control - Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), consolidated balance sheets of the Partnership as of December 31, 2017, the related consolidated statements of
operations, comprehensive income (loss), changes in equity, and cash flows for the year then ended, and the related notes
(collectively referred to as the financial statements) and our report dated February 26, 2018, expressed an unqualified opinion
on those consolidated financial statements.
Basis for Opinion
The Partnership'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 Partnership's
internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed 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 its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
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 the policies or procedures may deteriorate.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 26, 2018
141
Item 9B. Other Information
2018 Compensatory Arrangements
On February 23, 2018, the Compensation Committee of the Board of Directors of DCP Midstream, LLC, the owner of the
general partner (the “General Partner”) of the general partner of DCP Midstream, LP (the “Partnership”), established
compensation levels for named executive officers of the General Partner (the “Officers”) for the 2018 fiscal year as shown
below:
Name
Wouter T. Van Kempen
Sean P. O'Brien
Brent L. Backes
Don A. Baldridge
Brian S. Frederick
Base Salary
Short-Term
Incentive Target
Long-Term
Incentive Target
$682,900
$437,850
$423,840
$390,000
$402,220
100%
75%
65%
75%
75%
275%
200%
140%
175%
175%
Total
$3,243,775
$1,641,938
$1,292,712
$1,365,000
$1,407,770
The Compensation Committee also established the performance criteria for certain compensation arrangements for the
Officers for the 2018 fiscal year. The performance criteria relate to grants to the Officers under the DCP Services, LLC 2008
Long-Term Incentive Plan (the “LTI Plan”) and awards to the Officers under the short term cash incentive program (“STI”).
The LTI Plan provides for the grant of cash-settled phantom units and cash-settled dividend equivalent rights. The phantom
units consist of a notional unit based on the fair market value of a common unit of the Partnership. The phantom units will be
granted equally in restricted phantom units (“RPUs”) and strategic performance units (“SPUs”). RPUs will vest at the end of a
three-year vesting period. SPUs will vest at a range of 0% to 200% depending on the level of achievement, as determined by
the Compensation Committee of DCP Midstream, LLC, during a three-year performance period measured equally by (i)
distributable cash flow per common unit of the Partnership and (ii) relative total shareholder return of the Partnership as
compared to the following peer group:
Boardwalk Pipeline Partners, LP Magellan Midstream Partners, L.P. Tallgrass Energy GP, LP
Crestwood Equity Partners LP
Enable Midstream Partners, LP ONEOK, Inc.
EnLink Midstream Partners, LP Summit Midstream Partners, LP Williams Partners L.P.
Enterprise Products Partners L.P.
Targa Resources Corp.
Western Gas Partners, LP
NuStar Energy L.P.
The foregoing description of the SPU and RPU grants is qualified in its entirety by reference to the terms of the grant
agreements, the forms of which are filed herewith as Exhibits 10.12 and 10.13, respectively.
The 2018 payout opportunity for STI awards will be based on the level of performance achieved by the Partnership in
objectives that are substantially the same as those used for the prior fiscal year.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Management of DCP Midstream, LP
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
appointed 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 elect the directors of our General Partner or participate, directly or indirectly, in our
management or operations.
142
Board of Directors and Executive Officers of DCP Midstream GP, LLC
The board of directors of our General Partner currently has eight members, three of whom are independent as defined
under the independence standards established by the NYSE. Because we are a listed limited partnership and a controlled
company, we are not required by the NYSE rules to have a majority of independent directors on the board of directors of our
General Partner or to establish a compensation committee or a nominating/corporate governance committee. However, the
board of directors of our General Partner has established an audit committee consisting of three 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. Our
General Partner’s board of directors has affirmatively determined that Messrs. Fowler, Kimble, and Waycaster satisfy the SEC
and NYSE independence standards.
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 officers are also executive officers of
DCP Midstream, LLC. We utilize employees of DCP Midstream, LLC, including the executive officers, to operate our business
and provide us with general and administrative services that are reimbursed to DCP Midstream, LLC pursuant to the terms of
the Services and Employee Secondment Agreement (the “Services and Employee Secondment Agreement”).
The following table shows information regarding the current directors and executive officers of our General Partner, DCP
Midstream GP, LLC. Directors are appointed annually by DCP Midstream, LLC and hold office for one year or until their
successors have been elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers
serve at the discretion of the board of directors of our general partner. There are no family relationships among any of the
directors or executive officers.
Name
Age
Position with DCP Midstream GP, LLC
Wouter T. van Kempen
Sean P. O'Brien
Brent L. Backes
Don Baldridge
Brian S. Frederick
Allen C. Capps
Fred J. Fowler
William F. Kimble
Brian Mandell
Bill W. Waycaster
Vern Yu
John Zuklic
48
48
58
48
52
47
71
58
54
79
51
50
Chairman of the Board, President, Chief Executive Officer, and Director
Group Vice President and Chief Financial Officer
Group Vice President and General Counsel
President, Commercial
President, Asset Operations
Director
Director
Director
Director
Director
Director
Director
Wouter T. van Kempen was appointed as DCP Midstream GP, LLC’s Chief Executive Officer ("CEO") in January 2013,
Chairman of the Board in January 2014, and President in February 2016. Mr. van Kempen is also the Chairman of the Board,
President and Chief Executive Officer for DCP Midstream, LLC, which is the owner of DCP Midstream GP, LLC, since January
2013. Mr. van Kempen was previously DCP Midstream, LLC’s President and Chief Operating Officer from September 2012 until
January 2013, where he led the gathering and processing and the marketing and logistics business units and oversaw all corporate
functions of the organization; President, Gathering and Processing, from January 2012 to August 2012; President, Midcontinent
Business Unit, and Chief Development Officer, from August 2010 to December 2011. Prior to joining DCP Midstream, LLC in
August 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.
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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
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 25 years of experience in the finance area and over 20
years of experience in the energy industry.
Brent L. Backes was appointed Group Vice President and General Counsel of DCP Midstream GP, LLC in February 2017.
Mr. Backes has also served as the Group Vice President and General Counsel of DCP Midstream, LLC since February 2002.
Prior to joining DCP Midstream, LLC in 1998, Mr. Backes was an attorney in private practice focusing on mergers and
acquisitions and regulatory matters in the energy industry since 1987.
Don Baldridge was appointed President, Commercial of DCP Midstream GP, LLC in February 2017. Mr. Baldridge has
also been a President of DCP Midstream, LLC overseeing the commercial, marketing, and logistics businesses since March
2013 and before that was Vice President, Natural Gas and NGL Marketing since February 2011. Mr. Baldridge previously
served as our Vice President, Business Development from January 2009 until February 2011. Mr. Baldridge joined DCP
Midstream, LLC in March 2005. Mr. Baldridge brings more than 25 years of experience in the energy industry, including
commercial, trading and business development activities.
Brian S. Frederick was appointed President, Asset Operations of DCP Midstream GP, LLC in February 2017. Mr.
Frederick has also been President, Asset Operations of DCP Midstream, LLC since February 2014 and prior to that was
President of the Southern and Midcontinent business units of DCP Midstream, LLC since March 2013. Mr. Frederick joined
DCP Midstream, LLC in 1999 and previously served as Vice President of Corporate Development and Vice President of Gas
Marketing. Mr. Frederick has more than 25 years of experience in the energy industry leading operations, commercial, trading
and business development teams.
Allen C. Capps was appointed a director of DCP Midstream GP, LLC in August 2016. Mr. Capps is currently the Vice
President and Chief Accounting Officer of Enbridge. Prior to assuming his current role in February 2017, Mr. Capps served in a
similar capacity as vice president and controller of Spectra Energy since January 2012. From April 2010 until January 2012,
Mr. Capps served as Vice President, Business Development, Storage and Transmission, for Union Gas Limited, Spectra
Energy’s Canadian natural gas utility, and as Vice President and Treasurer of Spectra Energy from December 2007 to April
2010. Mr. Capps has broad experience in the energy industry having served in various senior level finance and accounting roles
since 2003.
Fred J. Fowler was appointed a director of DCP Midstream GP, LLC in March 2015. Mr. Fowler is the former president
and chief executive officer of Spectra Energy, retiring from that position in December 2008. Prior to Spectra Energy’s
separation from Duke Energy Corporation in December 2006, Mr. Fowler served as group president for Duke Energy’s gas
transmission business since April 2006. Prior to that, Mr. Fowler served as president and chief operating officer of Duke Energy
Corporation since November 2002. Mr. Fowler began his career in the energy industry in 1968. Mr. Fowler served as vice
chairman of the board of directors of TEPPCO Partners, L.P. from March 1998 to February 2003 and as chairman of the board
of directors of our General Partner from April 2007 to January 2009. Mr. Fowler currently serves on the boards of directors of
Encana Corp. and PG&E Corporation.
William F. Kimble was appointed a director of DCP Midstream GP, LLC in June 2015. Mr. Kimble retired in February
2015 from KPMG LLP (“KPMG”), one of the largest audit, tax and advisory services firms in the world. Mr. Kimble served as
KPMG’s Office Managing Partner for the Atlanta office and Managing Partner - Southeastern United States, where he was
responsible for the firm’s audit, advisory and tax operations from 2009 until his retirement. Mr. Kimble was also responsible for
moderating KPMG’s Audit Committee Institute and Audit Committee Chair Sessions. Until his retirement, Mr. Kimble had
been with KPMG or its predecessor firm since 1986. During his tenure with KPMG, Mr. Kimble held numerous senior
leadership positions, including Global Chairman of Industrial Markets. Mr. Kimble also served as KPMG’s Energy Sector
Leader for approximately 10 years and was the executive director of KPMG’s Global Energy Institute. Mr. Kimble currently
serves on the board of directors of PRGX Global, Inc. and its audit committee and Liberty Oilfield Services Inc. and its audit
committee.
Brian Mandell was appointed a director of DCP Midstream GP, LLC in May 2015. Mr. Mandell has 27 years of oil and
gas industry experience serving in various marketing, commercial, and midstream roles. He is currently Senior Vice President,
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Commercial, for Phillips 66. He previously served as Phillips 66's President, Global Marketing, and prior to that, Global
Trading Lead, Clean Products, Commercial. Prior to joining Phillips 66 in May 2012, he worked for ConocoPhillips as
Manager, U.S. Gasoline Trading since 2011. Previously, Mr. Mandell served in the Commercial NGL group and was named
Manager of NGL Trading after working as Manager of Processing Assets and Business Development in 2006. Mr. Mandell
began his career with Conoco in 1991 working in various marketing roles.
Bill W. Waycaster was appointed a director of DCP Midstream GP, LLC in June 2015. Mr. Waycaster retired in April 2003
from Texas Petrochemicals LLC (“Texas Petrochemicals”) after working in the hydrocarbon process industries for over 45
years. Mr. Waycaster was President and Chief Executive Officer of Texas Petrochemicals from April 1992 until his retirement.
Prior to that, Mr. Waycaster spent 27 years at The Dow Chemical Company (“Dow”) serving as Vice President and General
Manager of Hydrocarbons and Energy Resources when he left to join Texas Petrochemicals. Mr. Waycaster held positions at
Dow ranging from Project Engineer to Vice President of Business and Asset Management. Mr. Waycaster previously served on
the board of directors of the National Petrochemical and Refiners Association, where he served as Chairman of the
Petrochemicals Committee and Executive Committee, and also served on the board of directors of the American Chemistry
Council. Mr. Waycaster has previously served on the board of directors of each of Destec Energy, Inc. and Enterprise Products
GP, LLC.
Vern Yu was appointed a director of DCP Midstream, GP, LLC in March 2017. Mr. Yu is currently Executive Vice
President and Chief Development Officer of Enbridge. From July 2014 until assuming his current role in May 2016, Mr. Yu
served as Senior Vice President, Corporate Planning, and Chief Development Officer and prior to that served as Senior Vice
President of Business and Market Development for Enbridge’s Liquids Pipelines division where he was responsible for all
business and market development activities for Enbridge’s crude oil infrastructure business. Since joining Enbridge in 1993,
Mr. Yu has held a series of roles with increasing responsibility in the corporate and financial areas. Mr. Yu currently serves on
the board of directors of Spectra Energy Partners, LP, the general partner of which is controlled by Enbridge, which is an owner
of DCP Midstream, LLC, the owner of our General Partner.
John Zuklic was appointed a director of DCP Midstream GP, LLC in May 2015. Mr. Zuklic has more than 20 years of oil
and gas industry experience serving in various finance and commercial roles. He is currently Vice President and Treasurer of
Phillips 66 and prior to assuming that role in May 2015 was General Manager, Global Commercial Risk and Compliance.
Before joining Phillips 66 and assuming the role of Assistant Treasurer in May 2012, Mr. Zuklic worked for ConocoPhillips as
Manager, Treasury Services, since 2008. In 2004, he was named Principal Consultant, Treasury, and prior to that he was
Director, Midstream Finance, from 2000 to 2004. Prior to joining ConocoPhillips in 2000, Mr. Zuklic worked at BP p.l.c. for
five years in various treasury, finance, and commercial positions.
Director Experience and Qualifications
DCP Midstream, LLC evaluates and recommends candidates for membership on the board of directors of our General
Partner based on established criteria. 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 of our General Partner 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 - Mr. van Kempen was appointed a director because of his extensive knowledge of and experience
with our assets as Chairman, President, and Chief Executive Officer of DCP Midstream GP, LLC and as Chairman, President
and Chief Executive Officer of DCP Midstream, LLC. Mr. van Kempen brings strong management experience having served in
positions of increasing responsibility at Duke Energy and General Electric.
Allen C. Capps - Mr. Capps was appointed a director because of his strong background in the energy industry including
his leadership roles in accounting, finance, and business development with Enbridge and Spectra Energy.
Fred J. Fowler - Mr. Fowler was appointed a director because of his extensive knowledge and experience of the energy
industry, including a strong understanding of our assets, customers, regulatory environment, and competitive landscape. Mr.
Fowler brings leadership, management, and business skills developed as an executive and a director at public and privately held
companies.
William F. Kimble - Mr. Kimble was appointed a director because of his extensive accounting background and experience
as a director of other public companies. Mr. Kimble brings significant knowledge of the most current and pressing audit and
financial compliance matters and reporting obligations faced by public companies.
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Brian Mandell - Mr. Mandell was appointed a director because of his strong background and knowledge with over two
decades of senior leadership experience in a variety of roles including commercial and marketing within the industry.
Bill W. Waycaster - Mr. Waycaster was appointed a director because of his lengthy tenure in the energy industry and
executive management experience, spanning over a period of 50 years. Mr. Waycaster contributes valuable insight into
strategic, corporate governance, and compliance matters with his prior public company leadership and board experience.
Vern Yu - Mr. Yu was appointed a director because of his valuable industry and executive management experience with
corporate and financial matters including mergers and acquisitions, corporate planning and development, and business and
market development.
John Zuklic - Mr. Zuklic was appointed a director because of his strong knowledge and extensive experience in the energy
industry gained through his current and past roles in treasury, finance, commercial, and risk management.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires DCP Midstream GP, LLC’s directors and executive officers, and persons who
own more than 10% of a registered class of our equity securities to file with the SEC and the NYSE initial reports of ownership
and reports of changes in ownership of our common units and our other equity securities and to furnish us with copies of such
reports. 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, all Section 16(a) filing requirements applicable to such reporting
persons were complied with on a timely basis during the fiscal year ended December 31, 2017.
Audit Committee
The board of directors of our General Partner has a standing audit committee. The audit committee is composed of three
independent directors, William F. Kimble (chairman), Fred J. Fowler, and Bill W. Waycaster, 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. Mr. Kimble has been designated by the board as the audit committee’s financial expert meeting the
requirements promulgated by the SEC as set forth in Item 407(d) of Regulation S-K of the Exchange Act based upon his
education and employment experience as more fully detailed in Mr. Kimble’s biography set forth above.
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 Exchange Act. In making the independence determination, the board considered
the requirements of the NYSE and our Corporate Governance Guidelines. 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. The primary
purpose of the audit committee is to assist the board of directors in its oversight of (1) the integrity of the financial statements of
the Partnership, (2) the compliance by the General Partner and the Partnership with legal and regulatory requirements, and the
General Partner’s and the Partnership’s Code of Business Ethics, (3) the independent auditor’s qualifications and independence
and (4) the performance of the Partnership’s internal audit function and independent auditors.
Special Committee
The board of directors of our General Partner has a standing special committee, which is comprised of two independent
directors, Bill W. Waycaster (chairman) and William F. Kimble. The special committee will review specific matters that the
board believes may involve conflicts of interest, including transactions between us and DCP Midstream, LLC or its affiliates.
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 as requested by the board
of directors. The members of the special committee may not be officers or employees of our General Partner or directors,
officers 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 Exchange Act. 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.
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Corporate Governance Guidelines, Code of Business Ethics, and Audit Committee Charter
The board of directors of our general partner adopted Corporate Governance Guidelines that outline the important policies
and practices regarding our governance.
We have adopted a Code of Business Ethics applicable to all persons serving as our directors, officers (including without
limitation, our principal executive officer, principal 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.dcpmidstream.com in order to satisfy disclosure requirements under SEC and NYSE rules relating to such
information.
Copies of our Corporate Governance Guidelines, Code of Business Ethics and Audit Committee Charter are available on
our website at www.dcpmidstream.com. Copies of these items are also available free of charge in print to any person who sends
a request to the office of the Secretary of DCP Midstream, LP at 370 17th Street, Suite 2500, Denver, Colorado 80202. The
information contained on, or connected to, our website is not incorporated by reference into this annual report on Form 10-K
and should not be considered part of this or any other report that we file with or furnish to the SEC.
Meeting of Non-Management Directors and Communications with Directors
At each quarterly meeting of the board of directors of our general partner, the independent directors meet in an executive
session, which executive sessions are presided over by William F. Kimble. In addition, at each quarterly meeting of the board of
directors, the non-management members of the board meet in executive session, which executive sessions are presided over by
Fred J. Fowler.
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 Corporate Secretary, DCP Midstream, LP, 370 17th Street, Suite 2500, Denver, Colorado 80202,
fax number 303-605-2226.
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 over
financial reporting. The audit committee operates under a written charter approved by the board of directors. The charter,
among other things, provides that the audit committee is responsible for the appointment, compensation, oversight, retention,
and termination of the independent auditor. In this context, the audit committee:
•
•
•
•
•
•
reviewed and discussed quarterly and annual earnings press releases, quarterly unaudited financial statements, and
the annual audited financial statements included in this Annual Report on Form 10-K with management and
Deloitte & Touche LLP, our independent auditors, 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, who are responsible for expressing an opinion on the conformity of the
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;
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;
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•
•
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, 2017, for filing with
the SEC; and
approved the reappointment of Deloitte & Touche LLP to serve as our independent auditors based on an annual
consideration of, among other factors, the following: their historical and recent performance on our audit, the
quality and candor of their communications with the audit committee and management, the depth of expertise of
their audit team and the value provided by their national office, the appropriateness of their fees, how effectively
they maintained their independence, their tenure as our independent auditors, their knowledge of our operations,
accounting policies and practices, and internal control over financial reporting, and external data relating to audit
quality and performance by them and their peer firms.
This report has been furnished by the members of the audit committee of the board of directors:
Audit Committee
William F. Kimble (Chairman)
Fred J. Fowler
Bill W. Waycaster
The report of the audit committee in this report shall not be deemed incorporated by reference into any other filing by
DCP Midstream, LP under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we
specifically incorporate this information by reference, and shall not otherwise be deemed filed under such laws.
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Item 11. Executive Compensation
Compensation Discussion and Analysis
General
We were formed in 2005. Similar to other publicly traded partnerships, our operations are managed by our general partner,
DCP Midstream GP, LP, which in turn is managed by its general partner, DCP Midstream LLC, which we refer to as our
General Partner. Our General Partner is 100% owned by DCP Midstream, GP, LLC. When we refer herein to the board of
directors, we are referring to the board of directors of our General Partner. Additionally, when we refer herein to the
compensation committee, we are referring to the compensation committee of the board of directors of DCP Midstream, LLC,
comprised of Chairman Greg C. Garland, Chairman and CEO of Phillips 66 and Al Monaco, President and CEO of Enbridge
Inc.
We have entered into the Services Agreement with DCP Midstream, LLC pursuant to which, among other matters, DCP
Services, LLC makes available its employees who manage and operate our assets and serve as the executive officers, including
the named executive officers, or NEOs, of our General Partner. For the year ended December 31, 2017, the NEOs of our
General Partner were Wouter T. van Kempen, Chairman of the Board, President, and Chief Executive Officer (Principal
Executive Officer); Sean P. O’Brien, Group Vice President and Chief Financial Officer (Principal Financial Officer); Brent L.
Backes, Group Vice President and General Counsel, Don A. Baldridge, President, Commercial and Brian S. Frederick,
President, Asset Operations.
The NEOs prior to the Transaction allocated their time between managing our business and the business of DCP
Midstream, LLC. Following the closing of the Transaction, each of the current NEOs devotes all of their time to our business.
The General Partner has not entered into employment agreements with any of the NEOs. The NEOs do not receive any
separate compensation from us for their services to our business or as executive officers of our General Partner. We pay DCP
Midstream, LLC the full cost for the compensation of our NEOs. The compensation committee has the ultimate decision-
making authority with respect to the total compensation that DCP Midstream, LLC pays to the NEOs.
Compensation Decisions
All compensation decisions concerning the officers and employees dedicated to our operations and management are made
by the compensation committee. The compensation committee’s responsibilities on compensation matters include the
following:
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•
•
•
•
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 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 assist in the evaluation of compensation for directors who are not
officers or employees of the General Partner or its affiliates, or our non-employee directors, and NEOs; and
•
periodically review the compensation of the non-employee directors.
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Compensation Philosophy
The Partnership’s 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 in our industry;
• 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.
Methodology - Advisors and Peer Companies
The compensation committee reviews 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 for our
NEOs as well as the compensation package for our non-employee directors. With respect to NEO compensation, the
compensation committee also considers individual performance, levels of responsibility, skills and experience. In 2016,
management, on behalf of the compensation committee, engaged the services of Mercer, a compensation consultant, to conduct
a study to assist us in establishing overall compensation packages for the NEOs for 2017. We consider Mercer to be
independent of the Partnership and therefore, the work performed by Mercer does not create a conflict of interest. The Mercer
study was based on compensation for a group of peer companies with similar operations obtained from public documents as
well as multiple survey sources, including the 2016 Mercer Benchmark Database and the 2016 Mercer Total Compensation
Survey for the Energy Sector.
The Mercer study was comprised of the following peer companies:
Boardwalk Pipeline Partners, LP Magellan Midstream Partners, LP
Buckeye Partners, LP
Crestwood Equity Partners, LP
Enable Midstream Partners, LP
EnLink Midstream Partners, LP
Genesis Energy, LP
MPLX, LP
NuStar Energy, LP
ONEOK Partners, LP
Targa Resources Corp.
Western Gas Partners, LP
Studies such as this generally include only the most highly compensated officers of each company, which correlates with
most of the NEOs. The results of this study as well as other factors such as targeted performance objectives served as a
benchmark for establishing total annual direct compensation packages for the NEOs. Peer data from the Mercer study and the
data point that represents the 50th percentile of the market in the surveys were used to assess the competitiveness of the total
annual direct compensation packages for the NEOs.
Components of Compensation
The total annual direct compensation program for the NEOs consists of three components: (1) base salary; (2) a short-
term cash incentive, or STI, which is based on a percentage of annual base salary; and (3) the present value of a grant of
phantom units payable in cash upon vesting under the DCP Services, LLC 2008 Long-Term Incentive Plan, or LTIP, which is
based on a percentage of annual base salary. Effective March 27, 2017, the base salary, short-term incentive targets, and long-
term incentive targets for our NEOs were as follows:
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Name and Principal Position
Base Salary
Short-Term
Incentive
Target
Long-Term
Incentive
Target
Wouter T. Van Kempen, CEO, President & Chairman
Sean P. O'Brien, Group Vice President & Chief Financial Officer
Brent L. Backes, Group Vice President & General Counsel
Don A. Baldridge, President, Commercial
Brian S. Frederick, President, Asset Operations
$669,500
$401,700
$411,500
$376,400
$390,500
100%
70%
65%
65%
65%
225%
165%
140%
125%
125%
Total
$2,845,375
$1,345,695
$1,255,075
$1,091,560
$1,132,450
In allocating compensation among these components, we believe a significant portion of the compensation of the NEOs
should be performance-based since these individuals have a greater opportunity to influence our performance. In making this
allocation, we have relied in part on the Mercer study and considered each component of compensation as described below.
Base Salary - Base salaries for NEOs are determined based upon job responsibilities, level of experience, individual
performance, and comparisons to the salaries of individuals in similar positions obtained from the Mercer study. The goal of the
base salary component is to compensate NEOs at a level that approximates the median salaries of individuals in comparable
positions at comparably sized companies in our industry.
The base salaries for NEOs are generally reevaluated annually as part of our performance review process, or when there is
a change in the level of job responsibility. The compensation committee annually considers and approves a merit increase in
base salary based upon the results of this performance review process. Merit increases are based on industry trends and a review
of individual performance in certain categories, such as business values, environmental, health & safety performance,
leadership, financial results, project results, attitude, ability and knowledge.
Annual Short-Term Cash Incentive - Under the STI plan, 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 Mercer 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.
The 2017 STI objectives were initially designed and proposed by our CEO and Chairman of the Board and subsequently
approved by the compensation committee. All STI objectives are tied to the performance of the Partnership and are subject to
change each year based on annual strategic priorities and goals. The 2017 objectives comprising the total STI opportunity for
the NEOs are described below.
Financial objectives (65% of total STI):
1. Distributable Cash Flow. An objective intended to capture the annual amount of cash that is available for the quarterly
distributions to our unitholders. For this objective, the level of performance is based on our annual budget.
2. Constant Price Cash Generation. An objective intended to capture the cash generated from operations for the
Partnership excluding the effect of commodity prices. For this objective, we established a range of performance from a
minimum of $805 million to a maximum of $875 million.
3. Cost. An objective intended to capture the ongoing operating and general and administrative costs of the Partnership.
For this objective, we established a range of performance from a minimum of $940 million to a maximum of $890
million.
Operational objectives (20% of total STI):
1. Capacity Utilization. An objective intended to drive asset efficiency by measuring gas volume per compressor.
2. Customer Gas Curtailed. An objective to measure the impact of reliability on customer volume with the intent to
maximize our customers’ productivity.
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3. DCP 2.0 EBITDA Contribution. An objective intended to capture the additional EBITDA from the DCP 2.0 innovation
strategies.
Safety & Environmental Objectives (15% of total STI):
1. Total Recordable Injury Rate (TRIR). An objective of both employee and contractor injury rates covering the assets of
the Partnership. For this objective, the maximum level of performance is a TRIR of 0.35 and the minimum level of
performance is a TRIR of 0.75.
2. Process Safety Event Ratio (PSE Ratio). An objective using a broad definition of process safety events covering the
assets of the Partnership. For this objective, the maximum level of performance is a PSE Ratio of 3.0 and a minimum
level of performance is a PSE Ratio of 5.64.
3. Total Emissions. An objective of air emissions, natural gas vented or flared, covering the assets of the Partnership. For
this objective, we have established certain levels of emissions at such assets.
The payout on the 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 evaluated using
straight-line interpolation with the final percentages determined by the compensation committee.
Early in 2018, management prepared a report on the achievement of the Partnership objectives during 2017. These results
were then reviewed and approved by the compensation committee. The level of performance achieved in 2017 for each of the
STI objectives was as follows:
STI Objectives
Level of Performance Achieved
Distributable Cash Flow
Constant Price Cash Generation
Cost
Capacity Utilization
Customer Gas Curtailed
DCP 2.0 EBITDA Contribution
Total Recordable Injury Rate (TRIR)
Process Safety Event Ratio (PSE Ratio)
Total Emissions
Between Target & Maximum
At Maximum
Between Target & Maximum
Between Target & Maximum
Between Target & Maximum
Between Target & Maximum
At Target
Between Target & Maximum
At Maximum
Long-Term Incentive Plan - The LTIP has the objective of providing a focus on long-term value creation and enhancing
executive retention. Under the LTIP, phantom units are issued where half of such phantom units are strategic performance units,
or SPUs, and half are restricted phantom units, or RPUs. The SPUs 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 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 2017, the SPUs had the following three performance measures: (1) constant price earnings before interest and taxes
return on capital employed, or EBIT ROCE, by the Partnership over the Performance Period; (2) total shareholder return, or
TSR, over the Performance Period of DCP Midstream, LLC’s owner, Phillips 66, relative to their peer group; and (3) risk-
adjusted total shareholder return or R-TSR, defined as total shareholder return divided by volatility, over the Performance
Period of DCP Midstream, LLC’s owner, Enbridge Inc. relative to their peer group. Half of the SPUs will be measured against
the EBIT ROCE performance measure, one quarter of the SPUs will be measured against the TSR performance objective, and
one quarter of the SPUs will be measured against the R-TSR performance objective. The compensation committee believes
utilizing EBIT ROCE of the Partnership, which is a financial performance measure of the Partnership that measures
management’s effectiveness, directly aligns the performance of the NEOs with the success of the Partnership. We believe these
performance measures provide management with appropriate incentives for our disciplined and steady growth.
For the EBIT ROCE performance measure, EBIT for the Partnership will be as calculated from its financial statements.
Capital employed will be determined each year during the annual budget process as approved by our board of directors. The
152
EBIT ROCE targets are reset each year, based on our annual budget, and the final result will be based on the average of the
three one-year periods running from 2017 through 2019.
The TSR result for the LTIP will equal the TSR results paid by Phillips 66 under their long-term incentive plan. For 2017,
the companies included in the Phillips 66 peer group that will be compared against Phillips 66 are as follows:
Phillips 66 peer group:
Andeavor
Celanese Corporation
Delek US Holdings, Inc
DowDuPont Inc
Enterprise Products Partners, LP
S&P 100
HollyFrontier Corporation
Targa Resources Corp
Huntsman Corporation
Valero Energy Corporation
Marathon Petroleum Corporation
Westlake Chemical Corporation
Eastman Chemical Company
Energy Transfer Equity, LP
ONEOK, Inc
PBF Energy, Inc
The R-TSR result for the LTIP will equal the R-TSR results paid by Enbridge under their long-term incentive plan. For
2017, the companies included in the Enbridge peer group that will be compared against Enbridge are as follows:
Enbridge peer group:
Canadian Utilities:
Fortis Inc
Inter Pipeline Ltd
Dominion Resources
DTE Energy Company
US Peers:
ONEOK, Inc
PG&E Corporation
Pembina Pipeline Corporation
Energy Transfer Equity, LP
Plains All American Pipeline, LP
TransCanada Corporation
Enterprise Products Partners, LP
Sempra Energy
Kinder Morgan, Inc
Williams Companies, Inc
Magellan Midstream Partners, LP
These SPU and RPU awards are granted as of January 1st each year. Award recipients also receive the right to receive
dividend equivalent rights, or DERs, on the number of common units earned during the Vesting Period. The DERs on the SPUs
are 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 is equal to the quarterly distributions actually paid on the underlying securities during the
Performance Period and the Vesting Period on the number of SPUs earned or RPUs granted, respectively.
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 SPUs 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 Enbridge and Phillips 66 common stock on the NYSE for the 20 trading days prior to the date of grant
under the LTIP. Target long-term incentive opportunities for executives under the plan are established as a percentage of base
salary, using the Mercer study data for individuals in comparable positions.
In the event an award recipient’s employment is terminated after the first anniversary of the grant date for reasons of
death, disability, retirement, or layoff, the recipient’s: (i) SPUs 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) RPUs 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.
On February 23, 2018 the compensation committee determined that the RPUs and SPUs issued in 2018 will be based on
the value of DCP units and will be paid in cash. The compensation committee also approved a change in the LTI performance
criteria for the 2018 SPU grants. The performance criteria for 2018 SPUs will be as follows: (1) 50% distributable cash flow
per unit of the Partnership and (2) 50% relative total shareholder return of the Partnership. See Item 9b for a complete
description of the changes approved by the compensation committee.
Other Compensation - In addition, executives are eligible to participate in other compensation programs, which include
but are not limited to:
153
Company Matching and Retirement Contributions to Defined Contribution Plans - Executives may elect to participate in a
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 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 a 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.
Within the non-qualified deferred compensation program is a non-qualified, defined contribution retirement plan in which
benefits earned under the plan are attributable to compensation in excess of the annual compensation limits under Section
401(k) of the Code. Under this part of the plan, we make a contribution of up to 13% of compensation, as defined by the plan,
to the non-qualified deferred compensation program.
Benefit Programs - 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 public transportation systems.
We do not provide any material perquisites or any other personal benefits to our executives.
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 Section 162(m) of the Code. Accordingly, none of the compensation paid
to NEOs is subject to the limitation.
154
Board of Directors Report on Compensation
Our General Partner’s board of directors does not have a compensation committee. 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 Chairman, Chief Executive Officer, and President of
the General Partner and the Group Vice President and Chief Human Resources Officer of DCP Midstream, LLC. In addition,
we engaged the services of Mercer, a compensation consultant, to conduct a study to assist us in establishing overall
compensation packages for the executives. Based on this review and discussion, the board of directors of the General Partner
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, 2017.
The information contained in this Board of Directors Report on Compensation shall not be deemed to be “soliciting
material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any filing with the SEC, or
subject to the liabilities of Section 18 of the Exchange Act, except to the extent that we specifically incorporate it by reference
into a document filed under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
Board of Directors
Wouter T. van Kempen (Chairman)
Allen C. Capps
Fred J. Fowler
William F. Kimble
Brian Mandell
Bill W. Waycaster
Vern Yu
John Zuklic
155
Executive Compensation Tables
The following tables and accompanying narrative disclosures provide information regarding compensation of our named
executive officers, or NEOs, as of December 31, 2017.
Summary Compensation Table
The following table summarizes the compensation awarded to, earned by or paid to the named executive officers of our
General Partner for the services they provided to our business:
Name and Principal Position Year Salary
LTI
Awards
(c)
Non-Equity
Incentive Plan
Compensation
(d)
All Other
Compensation
(e)
Total
Wouter T. van Kempen, Chairman of the Board, President and Chief Executive Officer
2017 $ 664,250 $
1,506,735 $
1,074,511 $
442,250 $ 3,687,746
2016 $
2015 $
— $
— $
— $
— $
— $
— $
— $ 1,303,012
(a)
— $ 1,000,000
(a)
Sean P. O’Brien, Group Vice President and Chief Financial Officer
2017 $ 398,550 $
662,999 $
451,295 $
204,895 $ 1,717,739
2016 $
2015 $
— $
— $
— $
— $
— $
— $
— $
545,503
(a)
— $
400,000
(a)
Brent L. Backes, Group Vice President and General Counsel (b)
2017 $ 408,538 $
576,480 $
429,562 $
215,903 $ 1,630,483
Don A. Baldridge, President, Commercial (b)
2017 $ 373,438
$
469,399
$
392,655
$
175,427
$ 1,410,919
Brian S. Frederick, President, Operations (b)
2017
$ 387,673 $
489,116 $
407,623 $
172,112 $ 1,456,524
(a) Prior to the Transaction, this NEO allocated 40% of his time between managing our business and the business of DCP Midstream, LLC
where the time devoted to our business was driven by the needs and demands of our ongoing business and business development efforts.
This amount represents the portion of the fixed general and administrative fee we paid to DCP Midstream, LLC under the Services
Agreement as reimbursement for the time this NEO allocated to our business.
(b) This individual was first appointed an executive officer of our General Partner on February 9, 2017.
(c) The amounts in this column reflect the grant date fair value of strategic performance units, or SPUs, and restricted phantom units, or RPUs
granted under the LTIP, and are computed in accordance with the provisions of the FASB Accounting Standards Codification, or ASC,
718 “Compensation-Stock Compensation”, or ASC 718. SPU awards are subject to performance conditions and the amounts shown are
for target performance because target is the probable outcome. For SPUs granted in 2017, the performance conditions are between 0% if
the minimum level of performance is not achieved to 200% if the maximum level of performance is achieved. The maximum value payable
on the SPUs based on the 2017 grant date fair value, assuming the SPUs vested at the highest level of performance conditions, would be
$1,506,735 for Wouter T. van Kempen, $662,999 for Sean P. O’Brien, $576,480 for Brent L. Backes, $469,399 for Don A. Baldridge, and
$489,116 for Brian S. Frederick.
(d) Includes amounts payable under the STI Plan, including any amounts voluntarily deferred. These amounts are expected to be paid in March
2018.
(e) Includes DERs, Partnership contributions to the defined contribution plan and Partnership contributions to the nonqualified deferred
compensation plan, as described in more detail below.
156
All Other Compensation
“All Other Compensation” in the summary compensation table includes the following for 2017:
Company
retirement
contributions to
defined
contribution
plans
Nonqualified
deferred
compensation
program
contributions
DERs
Total
Wouter T. van Kempen
Sean P. O’Brien
Brent L. Backes
Don A. Baldridge
Brian S. Frederick
$
$
$
$
$
27,000
27,000
32,400
29,700
35,100
$
$
$
$
$
191,499
71,004
96,878
61,319
73,344
$
$
$
$
$
223,751
106,891
86,625
84,408
63,668
$
$
$
$
$
442,250
204,895
215,903
175,427
172,112
157
Grants of Plan-Based Awards
Following are the grants of plan-based awards to the NEOs during the year ended December 31, 2017:
Estimated Future Payouts under
Non-Equity Incentive Plan Awards (a)
Estimated Future Payouts under
Equity Incentive Plan Awards
Grant
Date
Minimum
($)
Target
($)
Maximum
($)
Minimum
(#)
Target
(#)
Maximum
(#)
Grant
Date
Fair Value
of LTIP
Awards ($)
NA
(b)
(c)
NA
(b)
(c)
NA
(b)
(c)
NA
(b)
(c)
NA
(b)
(c)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
— $ 664,250 $ 1,328,500
— $
— $
— $
— $
—
—
—
—
13,250
—
— $
—
13,250
13,250
26,500 $ 753,367
13,250 $ 753,367
— $ 278,985
$
557,970
— $
— $
— $
— $
—
—
— $ 265,550
$
531,100
— $
— $
— $
— $
—
—
— $ 242,735
$
485,470
— $
— $
— $
— $
—
—
— $ 251,988 $
503,975
— $
— $
— $
— $
—
—
—
—
5,830
—
—
5,070
—
—
4,130
—
—
4,300
—
— $
—
5,830
5,830
11,660 $ 331,499
5,830 $ 331,499
—
— $
—
5,070
5,070
10,140 $ 288,240
5,070 $ 288,240
—
— $
—
4,130
4,130
8,260 $ 234,700
4,130 $ 234,700
—
— $
—
4,300
4,300
8,600 $ 244,558
4,300 $ 244,558
Name
Wouter T. van
Kempen
SPUs
RPUs
Sean P.
O’Brien
SPUs
RPUs
Brent L.
Backes
SPUs
RPUs
Don A.
Baldridge
SPUs
RPUs
Brian S.
Frederick
SPUs
RPUs
(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 as of January 1, 2017. 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 as of January 1, 2017 and these units vest at the end of the
Vesting Period provided the individual is still employed by the Partnership.
The SPUs awarded on January 1, 2017 will vest in their entirety on December 31, 2019 if the specified performance
conditions are satisfied and the RPUs awarded on January 1, 2017 will vest in their entirety on December 31, 2019 if the NEO
is still employed by the Partnership, or earlier in the case of death, disability, retirement or layoff.
158
Outstanding Equity Awards at Fiscal Year-End
Following are the outstanding equity awards for the NEOs as of December 31, 2017:
Name
Wouter T. van Kempen
Sean P. O’Brien
Brent L. Backes
Don A. Baldridge
Brian S. Frederick
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)
104,297 $
51,407 $
25,326 $
38,960 $
29,904
$
5,801,286
2,861,717
1,403,686
2,170,182
1,664,625
(a) SPUs awarded in 2016 and 2017 vest in their entirety over a range of 0% to 200% on December 31, 2018 and 2019, respectively, if
the specified performance conditions are satisfied. RPUs awarded in 2015, 2016 and 2017 vest in their entirety on October 21, 2018,
December 31, 2018 and 2019, respectively. To determine the outstanding awards, the calculation of the number of SPUs 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 on the NYSE on December 29, 2017 of Enbridge’s common stock of $39.11 and Phillips
66’s common stock of $101.15.
Stock Awards Vested
Following are the stock awards vested for the NEOs for the year ended December 31, 2017:
Name
Wouter T. van Kempen
Sean P. O’Brien
Brent L. Backes (b)
Don A. Baldridge
Brian S. Frederick
Stock Awards
Number of Units
Acquired on
Vesting
Value Realized
on Vesting (a)
32,896 $
12,705 $
15,112 $
10,285 $
10,285
$
1,957,834
756,200
898,711
612,322
612,322
(a) Value calculated based on the average closing prices on the NYSE for the last 20 trading days in 2017 of Enbridge’s common stock
of $38.63 and Phillips 66’s common stock of $99.71.
(b) Includes 5,070 units that vested on December 31, 2017 due to his retirement eligibility, the value of which is based on the closing
price on the NYSE on December 29, 2017 of Enbridge’s common stock of $39.11 and Phillips 66’s common stock of $101.15.
159
Nonqualified Deferred Compensation
Following is the nonqualified deferred compensation for the NEOs for the year ended December 31, 2017:
Name
Wouter T. van Kempen
Sean P. O’Brien
Brent L. Backes
Don A. Baldridge
Brian S. Frederick
Executive
Contributions
in Last Fiscal
Year(a)
Registrant
Contributions
in Last Fiscal
Year(a)
Aggregate
Earnings in
Last Fiscal
Year(b)
Aggregate
Withdrawal/
Distributions
Aggregate
Balance at
December 31,
2017
$
$
$
$
$
381,654 $
191,499 $
85,894 $
176,187 $
71,004 $
18,849 $
61,281 $
96,878 $
125,326 $
— $
(111,214) $
— $
1,915,776
435,622
2,718,510
111,673
$
61,319
$
36,984
$
(20,739)
$
685,328
37,849 $
73,344 $
234,701 $
— $
2,212,728
(a) These amounts are included in the Summary Compensation Table for the year 2017.
(b) At the election of each executive officer, the performance of non-qualified deferred compensation is linked to certain mutual funds
or to the US High Yield BB rated Bond Index specific to the Energy sector.
160
Potential Payments upon Termination or Change in Control
The General Partner has not entered into any employment agreements with any of our executive officers. The NEOs participate
in executive severance arrangements maintained by DCP Services, LLC in the event of termination of employment that is
involuntary or not for cause. Mr. Backes is retirement eligible and any voluntary termination would be treated as a retirement.
As noted above, the SPUs, RPUs and the related dividend equivalent rights, or DERs, will become payable to executive officers
under certain circumstance related to termination. When an employee terminates employment with the Partnership, they are
entitled to a cash payment for the amount of unused vacation hours at the date of their termination.
In the event of a change in control, the disposition of SPUs, RPUs and the related DERs will be determined by the board of
directors of DCP Midstream, LLC. There are no formal plans for severance in the event of a change in control.
The following table presents payments in the event of termination for reasons of death, disability, or if the recipient is
terminated by the General Partner for reasons other than cause as of the last business day of 2017:
Wouter T. van Kempen
Sean P. O’Brien
Brent L. Backes (a)
Don A. Baldridge
Brian S. Frederick
2017 STI
Severance
2015 LTI
$
$
$
$
$
1,074,511
451,295
429,562
392,655
407,623
$
$
$
$
$
1,004,250 $
2,079,394
401,700 $
411,500 $
376,400 $
390,500
$
803,155
997,125
650,332
650,332
Accelerated
LTIP
$
$
$
$
$
3,262,105
1,763,801
1,078,503
1,410,409
846,301
$
$
$
$
$
Total
7,420,260
3,419,951
2,916,690
2,829,796
2,294,756
(a) Also applicable for retirement
CEO Pay Ratio
We are providing the following information about the relationship of the annual total compensation of our employees and the
annual total compensation of Wouter T. van Kempen, the Chairman of the Board, President, and Chief Executive Officer of our
General Partner (our “CEO”):
For 2017, our last completed fiscal year, the median of the annual total compensation of all employees of our company (other
than our CEO) was $106,213, and the annual total compensation of our CEO, as reported in the Summary Compensation Table
above, was $3,687,746. Based on this information, for 2017, Mr. van Kempen’s total annual compensation was 35 times that of
the median of the annual total compensation of all employees.
To identify the median of the annual total compensation of all our employees (other than our CEO), as well as to determine the
annual total compensation of our median employee and our CEO, we took the following steps:
1. We determined that, as of December 31, 2017, our employee population consisted of approximately 2,650
individuals with all of these individuals located in the United States (as reported in Item 1, Business, in this
Annual Report on Form 10-K). This population consisted of our full-time, part-time, and temporary employees.
2. To identify the “median employee” from our employee population, we compared the 2017 earnings eligible in the
short-term incentive plan plus the 2016 actual incentive paid in 2017 of our employees as reflected in our payroll
records for 2017.
3. We identified our median employee using this compensation measure, which was consistently applied to all our
employees included in the calculation. Since all our employees are located in the United States, as is our CEO, we
did not make any cost-of-living adjustments in identifying the “median employee.”
4. Once we identified our median employee, we combined all of the elements of such employee’s total compensation
for 2017.
5. With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of
our 2017 Summary Compensation Table above.
161
The pay ratio disclosed above is a reasonable estimate calculated in accordance with SEC rules, based on our records and the
methodologies described above. The SEC rules for identifying the median compensated employee and calculating the pay ratio
allow companies to use a variety of methodologies and apply various assumptions. The application of various methodologies
may result in significant differences in the results reported by other SEC reporting companies. As a result the pay ratio reported
by other SEC reporting companies may differ substantially from, and may not be comparable to, the pay ratio we disclose
above.
Director Compensation
General - Members of the board of directors who are officers or employees of the General Partner or its affiliates do not
receive compensation for serving as directors.
For 2017, the board approved an annual compensation package for non-employee directors, consisting of an annual
$70,000 cash retainer and an annual grant of common units that approximate $80,000 of value on the date of grant.
Chairpersons of committees of the board received an additional annual cash retainer of $20,000. All cash retainers were paid on
a quarterly basis in arrears. Directors did not receive additional fees for attending meetings of the board or its committees. The
directors were reimbursed for out-of-pocket expenses associated with their membership on the board of directors.
Following is the compensation of the General Partner’s non-employee directors for the year ended December 31, 2017:
Name
Fred J. Fowler
William F. Kimble (b)
Bill W. Waycaster (c)
Fees Earned or
Paid in Cash
Unit
Awards (a)
$
$
$
70,000
90,000
90,000
$
$
$
79,600
79,600
79,600
$
$
$
Total
149,600
169,600
169,600
(a) The amounts in this column reflect the grant date fair value of common unit awards computed in accordance with ASC 718.
(b) Mr. Kimble received an additional $20,000 annually as the audit committee chair.
(c) Mr. Waycaster received an additional $20,000 annually as the special committee chair.
Each director is entitled to be fully indemnified by us for his actions associated with being a director to the fullest extent
permitted under Delaware law.
Compensation Committee Interlocks and Insider Participation
As discussed above, our General Partner’s board of directors does not maintain a compensation committee. In 2017, the
compensation committee of the board of directors of DCP Midstream, LLC, the owner of our General Partner, determined all
elements of compensation for our NEOs. Only Mr. van Kempen was a director and a NEO of our General Partner. Further Mr.
van Kempen is a non-voting member of the board of directors of DCP Midstream, LLC; however, he is not a member of the
compensation committee thereof, nor did he participate in deliberations of such board with regard to his own compensation.
During 2017, none of our NEOs 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, the board of directors of DCP Midstream, LLC, or
the compensation committee of the board of directors of DCP Midstream, LLC.
162
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table sets forth the beneficial ownership of our common units as of February 22, 2018 for:
•
•
•
•
each person known by us to be the beneficial owner of more than 5% of our common units;
each director of DCP Midstream GP, LLC;
each NEO 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 143,309,828 common units outstanding.
Name of Beneficial Owner (a)
DCP Midstream, LLC (b)
Advisory Research, Inc. (c)
ALPS Advisors, Inc. (d)
Alerian MLP ETF (d)
Wouter T. van Kempen
Sean P. O'Brien
Brent L. Backes
Don Baldridge
Brian Frederick
Allen C. Capps
Fred J. Fowler
William F. Kimble
Brian Mandell
Bill W. Waycaster
Vern Yu
John Zuklic
All directors and executive officers as a group (10 persons)
_____________
* Less than 1%.
Common Units Beneficially
Owned
Percentage of Common Units
Beneficially Owned
52,762,526
8,985,266
7,510,182
7,484,706
2,540
—
10,406
10,689
5,500
—
21,800
6,200
—
6,200
—
—
63,335
36.8%
6.3%
5.2%
5.2%
*
—
*
*
*
—
*
*
—
*
—
—
*
(a) Unless otherwise indicated, the address for all beneficial owners in this table is 370 17th Street, Suite 2500, Denver,
Colorado 80202.
(b) Includes 1,887,618 common units held by DCP Midstream GP, LP. DCP Midstream, LLC is the sole member of the general
partner of DCP Midstream GP, LP and may be deemed to indirectly beneficially own such securities, but disclaims
beneficial ownership except to the extent of its pecuniary interest therein.
(c) As reported on Schedule 13G/A filed with the SEC on February 13, 2017 by Advisory Research, Inc. with an address of
180 North Stetson Avenue, Suite 5500, Chicago, Illinois 60601 and Piper Jaffray Companies with an address of 800
Nicollet Mall, Suite 800, Minneapolis, Minnesota 55402. The Schedule 13G/A reports that Advisory Research, Inc. has
sole voting power over 8,922,931 of the reported units and sole dispositive power over all of the reported units and Piper
Jaffray Companies has shared voting power over 8,922,931 of the reported units and shared dispositive power over all of
the reported units.
(d) As reported on Schedule 13G/A filed with the SEC on February 6, 2018 by ALPS Advisors, Inc. and Alerian MLP ETF
each with an address of 1290 Broadway, Suite 1100, Denver, Colorado 80203. The Schedule 13G/A reports that ALPS
Advisors, Inc. (“AAI”), an investment adviser registered under the Investment Advisors Act of 1940, furnishes investment
advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the
“Funds”). In its role as investment advisor, AAI has voting and/or investment power over the registrant's common units that
are owned by the Funds, and may be deemed to be the beneficial owner of such common units held by the Funds. The
Funds have the right to receive or the power to direct the receipt of dividends from, or the proceeds from the sale of the
common units held in their respective accounts. Alerian MLP ETF is an investment company registered under the
Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. The common units
reported herein are owned by the Funds and AAI disclaims beneficial ownership of such common units.
163
Equity Compensation Plan Information
The following table sets forth information about our equity compensation plans as of December 31, 2017.
Plan Category
Number of
securities to be
issued upon
exercise of
outstanding
options, warrants
and rights
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 (1)
Equity compensation plans not approved by unitholders (2)
Total
— $
—
— $
—
—
—
885,600
—
885,600
(1) This information relates to our 2016 LTIP, which was approved by unitholders at a special meeting on April 28, 2016.
For more information on our 2016 LTIP, refer to Note 15. "Equity-Based Compensation" in the Notes to Consolidated
Financial Statements in Item 8. “Financial Statements and Supplementary Data.”
(2) This information relates to our 2005 LTIP, which expired pursuant to its terms at the end of 2015, and therefore no
equity securities remain available for issuance thereunder. For more information on our 2005 LTIP, refer to Note 15.
"Equity-Based Compensation" in the Notes to Consolidated Financial Statements in Item 8. “Financial Statements and
Supplementary Data.
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 negotiations.
Operational Stage:
Distributions of Available Cash to our General
Partner and its affiliates
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.
Payments to our General Partner and
its affiliates
For further information regarding payments to our General Partner, please
see the “Services Agreement” section below.
Withdrawal or removal of our General Partner
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.
Liquidation Stage:
Liquidation
Contribution Agreement
Upon our liquidation, the partners, including our General Partner, will be
entitled to receive liquidating distributions according to their respective
capital account balances.
On December 30, 2016, the Partnership entered into a Contribution Agreement with DCP Midstream, LLC and DCP
Midstream Operating, LP (the “Operating Partnership”), a wholly owned subsidiary of the Partnership. On January 1, 2017,
DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owning operating assets, and (ii)
$424 million of cash (together the “Contributions”). In consideration of the Partnership’s receipt of the Contributions, (i) the
Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to DCP Midstream
GP, LP, the General Partner in a private placement and (ii) the Operating Partnership assumed $3,150 million of DCP
Midstream, LLC’s debt.
164
Services Agreement
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into the Services and Employee
Secondment Agreement (the “Services Agreement”), which replaced the services agreement between the Partnership and DCP
Midstream, LLC, dated February 14, 2013, as amended. Under the Services Agreement, we are required to reimburse DCP
Midstream, LLC for costs, expenses, and expenditures incurred or payments made on our behalf for general and administrative
functions including, but not limited to, legal, accounting, compliance, treasury, insurance administration and claims processing,
risk management, health, safety and environmental, information technology, human resources, benefit plan maintenance and
administration, credit, payroll, internal audit, taxes and engineering, as well as salaries of and benefits of seconded employees,
insurance coverage and claims, capital expenditures, maintenance and repair costs and taxes. There is no limit on the
reimbursements we make to DCP Midstream, LLC under the Services Agreement for costs, expenses and expenditures incurred
or payments made on our behalf.
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.”
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
or DCP Midstream, LLC.
Competition
None of DCP Midstream, LLC, or any of its affiliates, including Phillips 66 and Enbridge, 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 Enbridge, 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 sell NGLs and a portion of our residue gas to and purchase NGLs from Phillips 66 and its respective affiliates. We
anticipate continuing to purchase and sell these commodities to Phillips 66 and its respective affiliates in the ordinary course of
business.
We sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and
purchase commodities from Enbridge and its affiliates in the ordinary course of business.
Unconsolidated Affiliates
Under the terms of their respective operating agreements, Sand Hills and Southern Hills are required to reimburse us for any
direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern
Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions
provided by us as operator of Sand Hills and Southern Hills, 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 service fee, there is no limit on the reimbursements Sand Hills
and Southern Hills make to us under the respective operating agreements for other expenses and expenditures which we incur on
behalf of Sand Hills or Southern Hills.
Transportation Arrangements
The Texas Express, Front Range, Sand Hills, Southern Hills and Gulf Coast Express pipelines have in place 10 to 15-year
transportation agreements, commencing at the pipelines' respective in-service dates, with us pursuant to which we have
committed to transport minimum throughput volumes at rates defined in each respective pipeline’s tariffs.
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 committee is comprised of independent directors and acts as our conflicts committee. The Partnership Agreement
165
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” in this Annual Report on Form 10-K for
information about the independence of our general partner’s board of directors and its committees.
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,
2017
2016
$
(millions)
4
$
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 SEC 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, which 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
$100,000 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.
166
PART IV
167
Item 15. Exhibits, Financial Statement Schedules
(a) Financial Statement Schedules
Consolidated Financial Statements and Financial Statement Schedules included in this Item 15:
Consolidated Financial Statements of Discovery Producer Services LLC
Consolidated Financial Statements of DCP Sand Hills Pipeline, LLC
168
FINANCIAL STATEMENTS
Discovery Producer Services LLC
Years Ended December 31, 2017, 2016 and 2015
169
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Management Committee of
Discovery Producer Services LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Discovery Producer Services LLC (the
“Company”) as of December 31, 2017 and 2016, the related consolidated statements of operations and
comprehensive income, members’ capital, and cash flows for each of the three years in the period ended December
31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion,
the consolidated financial statements present fairly, in all material respects, the financial position of the Company
at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express
an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent
with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB and in accordance with auditing standards
generally accepted in the United States of America. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due
to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. As part of our audits we are required to obtain an understanding of internal control
over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s
internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.
Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a
reasonable basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2002
Tulsa, Oklahoma
February 22, 2018
170
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED BALANCE SHEETS
ASSETS
Current assets:
Cash and cash equivalents
Trade accounts receivable:
Affiliate
Other
Prepaid insurance
Inventory
Total current assets
Property, plant and equipment, net
Intangible assets, net
Total assets
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable:
Affiliate
Other
Asset retirement obligations
Deferred revenue
Other current liabilities
Total current liabilities
Non Current liabilities
Asset retirement obligations
Deferred revenue
Customer deposits
Commitments and contingent liabilities (Note 6)
Members' capital
Members' capital accounts
Other comprehensive income
Total members’ capital
Total liabilities and members’ capital
See accompanying notes to the financial statements.
December 31,
2017
2016
(In thousands)
$
22,827
$
11,124
13,339
3,911
2,886
2,923
45,886
1,124,864
13,084
$ 1,183,834
14,234
28,742
2,923
2,723
59,746
1,196,537
15,108
$ 1,271,391
$
$
1,110
16,602
24,184
19,784
209
61,889
97,896
71,135
3,491
1,357
9,222
3,398
41,436
259
55,672
120,042
74,634
3,345
948,030
1,393
949,423
$ 1,183,834
1,016,242
1,456
1,017,698
$ 1,271,391
171
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
2017
Year Ended December 31,
2016
(In thousands)
2015
Revenues:
Product sales:
Affiliate
Third-party
Transportation services
Gathering and processing services:
Affiliate
Third-party
Other revenues
Total revenues
Costs and expenses:
Product cost and shrink replacement:
Affiliate
Third-party
Operating and maintenance expenses:
Affiliate
Third-party
Depreciation, amortization and accretion
Taxes other than income
General and administrative expenses- affiliate
Other (income) expense, net
Total costs and expenses
Operating income
Interest income (expense)
Foreign currency loss
Net income
Net loss from derivative instruments, including amounts reclassified into
earnings
Comprehensive income
$
$
165,525
93
46,395
$
129,609
120
60,112
687
191,351
8,793
412,844
8,750
126,610
9,510
28,719
93,110
2,913
7,454
(6,553)
270,513
142,331
177
—
142,508
330
200,723
9,012
399,906
6,168
95,364
8,679
23,479
76,110
2,702
7,219
129
219,850
180,056
(46)
—
180,010
143,483
243
53,770
423
160,150
10,344
368,413
8,356
109,782
9,196
24,378
75,333
2,869
7,320
3
237,237
131,176
37
(62)
131,151
(63)
142,445
$
(63)
179,947
$
(57)
131,094
$
See accompanying notes to the financial statements.
172
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENT OF MEMBERS' CAPITAL
Williams Field
Services
Group, LLC
DCP Assets
Holding, LP
Accumulated
Other
Comprehensive
Income
Total
(In thousands)
Balance December 31, 2014
$
645,961
$
430,138
$
1,576
$
1,077,675
Non-cash contributions *
Contributions
Distributions
Net income
Other comprehensive loss
Balance December 31, 2015
Distributions
Net income
Other comprehensive loss
Balance December 31, 2016
Contributions
Distributions
Net income
Other comprehensive loss
Balance December 31, 2017
787
32,999
(115,542)
78,691
—
$
642,896
$
(140,540)
108,006
—
—
22,000
(77,028)
52,460
—
427,570
(93,694)
72,004
—
$
$
610,362
$
405,880
$
834
(127,266)
85,504
—
556
(84,844)
57,004
—
$
569,434
$
378,596
$
—
—
—
—
(57)
1,519
—
—
(63)
1,456
—
—
—
(63)
1,393
$
$
$
787
54,999
(192,570)
131,151
(57)
1,071,985
(234,234)
180,010
(63)
1,017,698
1,390
(212,110)
142,508
(63)
949,423
* Non-cash contributions disclosed in Note 5
See accompanying notes to financial statements.
173
DISCOVERY PRODUCER SERVICES LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
2017
Year Ended December 31,
2016
(In thousands)
2015
$ 142,508
$ 180,010
$ 131,151
93,110
—
(6,556)
25,726
37
(199)
6,221
(679)
147
(50)
(30,452)
229,813
(7,390)
—
(7,390)
76,109
140
—
75,333
28
—
(1,136)
440
(10)
2,369
—
2,683
(94)
(15,908)
244,603
(28,209)
(757)
230
(8,637)
(789)
363
159
(6,221)
162,651
(8,594)
—
(8,594)
(34,121)
(23,500)
(57,621)
(212,110)
1,390
(210,720)
11,703
11,124
22,827
(234,234)
—
(234,234)
1,775
9,349
11,124
(192,570)
54,999
(137,571)
(32,541)
41,890
9,349
$
$
5,300
$
— $
—
(8,300) $
(8,756) $ (15,965)
910
(7,390) $
162
(18,156)
(8,594) $ (34,121)
$
$
$
$
OPERATING ACTIVITIES:
Net income
Adjustments to reconcile cash provided by operations:
Depreciation, amortization, and accretion
Net loss on retirement of equipment
Other non-cash item
Cash provided (used) by changes in assets and liabilities:
Trade accounts receivable
Prepaid insurance
Inventory
Accounts payable
Asset retirement obligation
Customer deposits
Other current liabilities
Deferred revenue
Net cash provided by operating activities
INVESTING ACTIVITIES:
Property, plant and equipment - capital expenditures *
Purchase of business (Note 9)
Net cash used by investing activities
FINANCING ACTIVITIES:
Distributions to members
Capital contributions
Net cash used by financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents beginning of period
Cash and cash equivalents end of period
Supplemental Disclosures
Non cash additions to PP&E
* Increase to property, plant and equipment
Changes in related accounts payable - affiliate, accounts payable, and construction
retainage payable
Capital expenditures
See accompanying notes to financial statements.
174
DISCOVERY PRODUCER SERVICES LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Description of Business
Unless the context clearly indicates otherwise, references in this report to “we”, “our”, “us” or similar language refers to
Discovery Producer Services LLC and its wholly-owned subsidiary, Discovery Gas Transmission LLC (DGT). We are a
Delaware limited liability company formed on June 24, 1996 for the purpose of constructing and operating a cryogenic
natural gas processing plant near Larose, Louisiana and a natural gas liquids fractionator near Paradis, Louisiana. DGT is a
Delaware Limited Liability Company formed on June 24, 1996 for the purpose of constructing and operating an offshore
natural gas deep water pipeline in the Gulf of Mexico which connects to our gas processing plant in Larose, Louisiana. We
have since connected several laterals to the DGT pipeline to expand our presence in the Gulf of Mexico.
We are owned 60% by Williams Field Services Group, LLC (WFS) (a wholly-owned subsidiary of Williams Partners
L.P. (WPZ)) and 40% by DCP Assets Holding, LP (a wholly-owned subsidiary of DCP Midstream Partners, LP (DCP)).
WFS is our operator. Herein, The Williams Companies, Inc., who controls WPZ through its general partner interest, WPZ
and WFS are collectively referred to as “Williams.”
We evaluated our disclosure of subsequent events through the date, February 15, 2018, the date our financial statements
were issued.
Note 2. Summary of Significant Accounting Policies
Basis of Presentation. The consolidated financial statements have been prepared based upon accounting principles generally
accepted in the United States and include the accounts of the parent and our wholly-owned subsidiary, DGT. Intercompany
accounts and transactions have been eliminated.
New Accounting Standards Issued Not yet Adopted. In May 2014, the FASB issued ASU 2014-09 establishing Accounting
Standards Codification (ASC) Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a
comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount
that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires
significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with
Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim
and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified
retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We are adopting
the new revenue recognition standard utilizing the modified retrospective transition approach, effective January 1, 2018, by
recognizing the cumulative effect of initially applying the new standard for periods prior to January 1, 2018, to the opening
balance of Members’ capital.
We are in the final stages of evaluating the impact the new revenue standard will have on our financial statements. For each
revenue contract type, we have conducted a formal contract review process to evaluate the impact of the new revenue standard.
We have substantially completed our evaluation. Under the new standard, our revenues will increase in situations where we
receive noncash consideration, which exists primarily in certain of our gas processing contracts where we receive commodities
as full or partial consideration for services provided. This increase in revenues will be offset by a similar increase in costs and
expenses when the commodities received are subsequently sold. We continue to evaluate the treatment of Hurricane Mitigation
Reliability Enhancement (HMRE) surcharges (See Note 8) on our revenue recognition. Financial systems and internal controls
necessary for adoption have been implemented effective as of January 1, 2018.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a
comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease
classification similar to current lease accounting, and causes lessees to recognize leases on the balance sheet as a lease liability
measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases
with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of
cash flows arising from leases. In November 2017, the FASB approved, pending the final drafting and issuance, a proposed
accounting standard update titled “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842”. Per
the proposed accounting standard update, land easements and rights-of-way are required to be assessed under ASU 2016-02
to determine whether the arrangements are or contain a lease and permits an entity to elect a transition practical expedient to
175
not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not
previously assessed under the previous lease guidance in Accounting Standards Codification Topic 840 “Leases”. ASU 2016-02
is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02
currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the
beginning of the earliest comparative period presented in the financial statements. In January 2018, the FASB proposed an
accounting standard update titled “Leases (Topic 842): Targeted Improvements”, which is an update to ASU 2016-02 allowing
entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU
2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption
without adjustment to the financial statements for periods prior to adoption.
We expect to adopt ASU 2016-02 effective January 1, 2019. We are in the process of reviewing contracts to identify leases
based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control
changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of
completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes relate to the
recognition of a lease liability and offsetting right-of-use asset in our consolidated balance sheet for operating leases. We are
also evaluating ASU 2016-02’s currently available and proposed practical expedients on adoption.
In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit
Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and
certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities
will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of
allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods
beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the
different categories of amendments. We are evaluating the impact of ASU 2016-13 on our consolidated financial statements.
Although we do not expect ASU 2016-13 to have a significant impact, it will impact our trade receivables as the related
allowance for credit losses will be recognized earlier under the expected loss model than under our current policy.
Use of Estimates. The preparation of consolidated financial statements in conformity with accounting principles generally
accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the
consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Significant estimates and assumptions include:
• Asset retirement obligations
• Depreciable asset lives
Cash and Cash Equivalents. The cash and cash equivalents balance includes cash equivalents which are invested in funds
with high-quality, short-term securities and instruments that are issued or guaranteed by the U.S. government. These securities
have maturities of three months or less when acquired.
Trade Accounts Receivable. Trade accounts receivable are carried on a gross basis, with no discounting, less an allowance
for doubtful accounts. We do not recognize an allowance for doubtful accounts at the time the revenue that generates the
accounts receivable is recognized. We estimate the allowance for doubtful accounts based on existing economic conditions,
the financial condition of the customers and the amount and age of past due accounts. Receivables are considered past due if
full payment is not received by the contractual due date. Past due accounts are generally written off against the allowance for
doubtful accounts only after all collection attempts have been exhausted. There is no allowance for doubtful accounts as of
December 31, 2017 and 2016.
Prepaid Insurance. Prepaid insurance represents the unamortized balance of insurance premiums. These payments are
amortized on a straight-line basis over the policy term.
Gas Imbalances. In the course of providing transportation services to customers, we may receive different quantities of gas
from shippers than the quantities delivered on behalf of those shippers. This results in gas transportation imbalance receivables
and payables. The imbalance is recovered or repaid in cash, based on market-based prices, or through the receipt or delivery
of gas in the future. Imbalance receivables are valued based on the lower of the current market prices; or the weighted average
cost of natural gas in the system. Imbalance payables are valued at current market prices. Settlement of imbalances requires
an agreement between the pipelines and shippers as to the allocations of volumes to specific transportation contracts, and the
timing of delivery of gas based on operational conditions. Pursuant to a settlement with our shippers issued by the Federal
Energy Regulatory Commission (FERC) on February 5, 2008, if a cash-out refund is due and payable to a shipper during any
176
year pursuant to our FERC Gas Tariff, the shipper will be deemed to have immediately assigned its right to the refund amount
to us.
Inventory. Inventories in the Consolidated Balance Sheet primarily consist of natural gas liquids and materials and supplies,
and are stated at the lower of cost or net realized value. The cost of inventories is primarily determined using the average-cost
method.
Property, Plant and Equipment. Property, plant and equipment is recorded at cost. We base the carrying value of these assets
on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. The natural gas and
natural gas liquids maintained in the pipeline facilities necessary for their operation (line fill) are included in property, plant
and equipment. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful
lives of 25 to 35 years. Expenditures for maintenance and repairs are expensed as incurred. Expenditures that extend the useful
lives of the assets or increase their functionality are capitalized. The cost of property, plant and equipment sold or retired and
the related accumulated depreciation is removed from the accounts in the period of sale or disposition. Gains and losses on the
disposal of property, plant and equipment are recorded in operating income.
We record an asset and a liability equal to the present value of each expected future asset retirement obligation (ARO). The
ARO asset increases the carrying value of the underlying physical asset and is depreciated with the underlying physical asset.
We measure changes in the liability due to passage of time by applying an interest method of allocation. This amount is
recognized as an increase in the carrying amount of the liability and as corresponding accretion expense included in operating
income.
Intangible Assets. Our intangible assets are primarily related to our Raceland lateral project as further described in Note 5.
Our intangible assets are amortized on a straight-line basis over the period in which these assets contribute to our cash flows.
We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through
amortization over the revised remaining useful life.
Impairment of Long-Lived Assets. We evaluate long-lived assets for impairment when events or changes in circumstances
indicate that, in our management’s judgment, the carrying value of such assets may not be recoverable. When such a
determination has been made, we compare our estimate of undiscounted future cash flows attributable to the assets to the
carrying value of the assets to determine whether the carrying value is recoverable. If the carrying value is not recoverable, we
determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and
recording a loss for the amount by which the carrying value exceeds the estimated fair value. There were no impairments
recorded during 2017, 2016 and 2015.
Customer Deposits. We extend credit to customers in the normal course of business and perform ongoing credit evaluations
of our customers. We may require cash deposit from our customers based on their overall creditworthiness. The dollars are
recorded as a non -current liability on the consolidated balance sheet.
Revenue Recognition. Revenue for sales of products is recognized in the period of delivery, and revenues from the gathering,
transportation, and processing of gas are recognized in the period the service is provided based on contractual terms and the
related natural gas and liquid volumes. DGT is subject to FERC regulations, and accordingly, certain revenues collected may
be subject to possible refunds upon final orders in pending cases. DGT records rate refund liabilities considering its and other
third parties’ regulatory proceedings, advice of counsel, estimated total exposure as discounted and risk weighted, and collection
and other risks. There was no rate refund liability accrued at December 31, 2017 or 2016.
Deferred Revenues Our deferred revenues represent up-front payments from customers associated with gas gathering and
fractionation and are recognized as we provide the service to which the payments relate.
Income Taxes. For federal tax purposes, we have elected to be treated as a partnership with each member being separately
taxed on its ratable share of our taxable income. This election, to be treated as a pass-through entity, also applies to our wholly-
owned subsidiary, DGT. Therefore, no income taxes or deferred income taxes are reflected in the consolidated financial
statements.
Foreign Currency Transactions. Transactions denominated in currencies other than the functional currency are recorded
based on exchange rates at the time such transactions arise. Subsequent changes in exchange rates result in transaction gains
or losses which are reflected in net income.
177
Other Comprehensive loss. Amounts recorded in other comprehensive loss relate to cash flow hedges we entered into to
hedge forecasted foreign currency-denominated payments for pipeline construction. We recorded the effective portion of
changes in the fair value of those hedges in other comprehensive loss, and reclassify such amounts into income on a straight-
line basis over the period that we are depreciating the assets to which the hedges related.
Note 3. Related Party Transactions
We have various business transactions with our members and subsidiaries and affiliates of our members. Revenues include
sales to Williams of natural gas liquids (NGLs) to which we take title and excess natural gas. The related-party revenues
associated with Williams in 2017, 2016, and 2015 were $166.1 million, $129.9 million, and $143.9 million, respectively.
Revenues from Phillips 66 (an affiliate of DCP) in 2017 amounted to $0.1 million.
Product cost and shrink replacement- affiliate includes natural gas purchases from Williams for fuel and shrink requirements.
We have no employees. Pipeline and plant operations are performed under operation and maintenance agreements with
Williams. Most costs for materials, services and other charges are third-party charges and are invoiced directly to us. Operating
and maintenance expenses- affiliate includes the following:
• Direct payroll and employee benefit costs incurred on our behalf by Williams;
• Transportation expense under a 10-year transportation agreement for pipeline capacity through 2020 from Texas Eastern
Transmission, LP (an affiliate of DCP); and
•
Storage expense under a 20-year agreement to store parts, tools and equipment in a warehouse owned by Williams
PERK, LLC (an affiliate of WFS) through 2033.
General and administrative expenses - affiliate includes a monthly operation and management fee paid to Williams to cover
the cost of accounting services, computer systems and management services provided to us.
We also pay Williams a project management fee to cover the cost of managing capital projects. This fee is determined on a
project by project basis and is capitalized as part of the construction costs. A summary of the payroll costs and project fees
charged to us by Williams and capitalized are as follows:
Capitalized labor
Capitalized project fee
Total
2017
Years Ended December 31,
2016
(In thousands)
754
$
249
1,003
$
$
$
464
179
643
2015
1,224
213
1,437
$
$
178
Note 4. Property, Plant, and Equipment
Property, plant, and equipment consisted of the following at December 31, 2017 and 2016:
Property, plant, and equipment:
Pipelines
Plant and other equipment
Buildings
Land and land rights
Construction work in progress
Total property, plant, and equipment
Less accumulated depreciation
Net property, plant, and equipment
Estimated
Depreciable
Lives
25 - 35 years
25 - 35 years
25 - 35 years
0 - 35 years
Years Ended December 31,
2017
2016
(In thousands)
$
$
1,108,031
532,502
31,521
8,544
4,012
1,684,610
559,746
1,124,864
$
$
1,108,062
522,297
31,521
8,035
5,465
1,675,380
478,843
1,196,537
Depreciation expense in 2017, 2016 and 2015 was $83.5 million, $66.8 million and $66.1 million, respectively, depreciable
lives of specific assets were accelerated during 2017 due to the expectation that they would no longer be used in operations.
Commitments for construction and acquisition of property, plant and equipment totaled $2.6 million at December 31, 2017.
Our asset retirement obligations relate primarily to our offshore platforms and pipelines and our onshore processing and
fractionation facilities. At the end of the useful life of each respective asset, we are legally or contractually obligated to dismantle
the offshore platforms, properly abandon the offshore pipelines, remove the onshore facilities and related surface equipment
and restore the surface of the property.
A rollforward of our asset retirement obligation for 2017 and 2016 is presented below:
Balance at January 1
Accretion expense
Estimate revisions*
New obligation incurred
Settlements
Balance at December 31
Years Ended December 31,
2016
2017
(In thousands)
$
$
123,440
7,553
(10,909)
2,675
(679)
122,080
$
$
116,933
7,296
(1,225)
436
—
123,440
*Includes a $12.3 million reduction related to assets determined not to have a retirement obligation.
Note 5. Intangible Assets
We have two intangible assets, first is Raceland valued at $20 million with useful life of ten years and second is ST 311 with
value of $.5 million with useful life of 20 years. The amortization expense for 2017, 2016 and 2015 were $2.0 million each
year, Accumulated amortization at December 31 2017 and 2016 was $7.6 million and $5.6 million, respectively. The intangible
assets are being amortized on a straight-line basis.
Below is estimated amortization expense for the next five years:
179
2018
2019
2020
2021
2022
Total
(In thousands)
2,024
$
2,024
2,024
2,024
2,024
10,120
$
Note 6. Commitments and Contingent Liabilities
We lease the land on which the Paradis fractionator and the Larose processing plant are located. The term for the leases
were renewed for an additional 10 years beginning in 2017. The future minimum annual rentals under this non-cancelable
lease as of December 31, 2017 are payable as follows:
2018
2019
2020
2021
2022
Thereafter
Total
$
$
(In thousands)
115
115
115
115
115
598
1,173
Total rent and lease expense for 2017, 2016, and 2015, including a cancelable platform space lease and miscellaneous month-
to-month leases, was $2.8 million, $2.5 million, and $2.4 million, respectively.
Environmental Matters. We are subject to extensive federal, state, and local environmental laws and regulations which
affect our operations related to the construction and operation of our facilities. Appropriate governmental authorities may
enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties,
assessment and remediation requirements and injunctions as to future compliance. We have not been notified and are not
currently aware of any material noncompliance under the various environmental laws and regulations.
Other. We are party to various other claims, legal actions and complaints arising in the ordinary course of business. We
estimate that, for all matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible
losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of
operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery
from third parties. There are no significant matters for which we are unable to reasonably estimate a range of possible loss.
Note 7. Financial Instruments, Concentrations of Credit Risk and Major Customers
Fair Value of Financial Instruments
Fair value is defined as the price which would be received to sell an asset or paid to transfer a liability in an orderly transaction
between market participants at the measurement date. Assets and liabilities recorded or disclosed at fair value are categorized
based upon the level of judgment associated with the inputs used to measure their fair values. These categories include (in
descending order of priority): Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined
as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as
unobservable inputs in which little or no market data exists, therefore requiring an entity to develop its own assumptions.
The carrying value of cash and cash equivalents (classified as Level 1), accounts receivable, accounts payable, other current
assets and other current liabilities approximate their fair value because of their short term nature.
Concentrations of Credit Risk
180
Our cash equivalents balance is primarily invested in funds with high-quality, short-term securities and instruments that are
issued or guaranteed by the U.S. government.
At December 31, 2017, substantially all of customer accounts receivable result from product sales and gathering from our
largest customers. This concentration may impact our overall credit risk either positively or negatively, in that the entity may
be similarly affected by industry-wide changes in economic or other conditions. As a general policy, collateral is not required
for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. Our credit policy and the
relatively short duration of receivables mitigate the risk of uncollected receivables. We incurred no gain/loss on receivables
in 2017, 2016 or 2015.
Major Customers
Williams accounted for $166.1 million (40%), $129.9 million (32%), and $143.9 million (39%) respectively, of our total
revenues in 2017, 2016, and 2015. These revenues were for the sale of NGLs purchased from or received as compensation
under processing contracts with third-party producers.
During 2017, ExxonMobil Corporation accounted for $68.6 million (16.6%), and Anadarko accounted for $53.7 million
(13.0%), of our total revenues. These revenues were for gathering, processing, transportation and other services.
During 2016, ExxonMobil Corporation accounted for $81.9 million (20.5%), and ENI Petroleum accounted for $50.5 million
(12.6%), of our total revenues. These revenues were for gathering, processing, transportation and other services.
Note 8. Rate and Regulatory Matters
Rate and Regulatory Matters. Pursuant to the terms of its FERC Gas Tariff, DGT has the right to file, on an annual basis,
a request with the FERC for a fuel lost-and-unaccounted-for gas (FL&U) percentage to be assessed shippers for the upcoming
fiscal year beginning July 1. On May 31, 2016, DGT filed to reduce the FL&U retention rate from 0.3 percent to 0.0 (zero)
percent per dekatherm (Dt) of gas received based upon the actual fuel use, system loss and gas retained experienced in 2015.
On June 17, 2016, the FERC issued a letter order approving the requested retention rate revision. The actual system gain for
2016 was $1.1 million with FL&U recovered of $0.6 million. On May 31, 2017, a report was filed with the FERC stating that
DGT was not revising its currently effective FL&U retention rate of 0.0 percent at this time based upon the actual fuel use,
system loss and gas retained experienced in 2016. On December 21, 2017, the FERC issued a letter order accepting the May
31, 2017 report. The actual system loss for 2017 was $2.3 million. The above amounts were recognized in each year’s respective
operating income.
On November 15, 2016, DGT filed its annual HMRE surcharge adjustment to maintain the $0.0500 per Dt surcharge effective
January 1, 2017. The HMRE surcharge allows for the recovery of certain capital and operating costs associated with DGT’s
efforts to maintain and enhance system reliability and repair and remediate facilities damaged by hurricanes. The filing reflected
an additional $0.2 million of qualifying HMRE costs to be recovered by the surcharge. As reflected in the application, the total
HMRE amount to be recovered over future periods was $24.4 million as of September 30, 2016. The Commission approved
the requested surcharge by letter order dated December 7, 2016.
On November 15, 2017, DGT filed its annual HMRE surcharge adjustment to maintain the $0.0500 per Dt surcharge effective
January 1, 2018. The filing reflected an additional $0.1 million of qualifying HMRE costs to be recovered by the surcharge.
As reflected in the application, the total HMRE amount to be recovered over future periods was $14.5 million as of September
30, 2017. The Commission approved the requested surcharge by letter order dated December 22, 2017.
Note 9. Business Combination
On July 2, 2015, we completed the acquisition of the ST 311 pipeline from Walter Oil and Gas Corporation, Castex Offshore
Inc., Fieldwood Energy LLC, and Apache Shelf Exploration LLC. The pipeline acquired is a 25 mile 14” gathering lateral
starting from the ST 311 block to the ST 200 block connection to our 18” regulated lateral line that connects to DGT’s 30”
regulated mainline. We paid $23.5 million for the pipeline, net of refunds for a pre-closing settlement. No material liabilities
were assumed besides the initial recording of an asset retirement obligation.
181
The following table presents the allocation of the acquisition-date fair value of the major classes of the net assets:
Property, plant and equipment
Intangible asset
Asset retirement obligation
Total cash
Note 10. Subsequent Events
(In thousands)
$
$
25,900
470
(2,870)
23,500
During February 2018, we made distributions to our partners totaling $10.7 million and received $1.9 million for capital
funding.
182
DCP SAND HILLS PIPELINE, LLC
Consolidated Financial Statements for the
Years Ended December 31, 2017, 2016 and 2015
183
INDEPENDENT AUDITORS' REPORT
To the Members of
DCP Sand Hills Pipeline, LLC
Denver, Colorado
We have audited the accompanying consolidated financial statements of DCP Sand Hills Pipeline, LLC and subsidiary (the
"Company"), which comprise the consolidated balance sheets as of December 31, 2017 and 2016, and the related
consolidated statements of operations, changes in members’ equity, and cash flows for each of the three years in the period
ended December 31, 2017, and the related notes to the consolidated financial statements.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance
with accounting principles generally accepted in the United States of America; this includes the design, implementation, and
maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are
free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our
audits in accordance with auditing standards generally accepted in the United States of America. Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are
free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated
financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of
material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk
assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the
consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for
the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no
such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of
significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated
financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial
position of DCP Sand Hills Pipeline, LLC and its subsidiary as of December 31, 2017 and 2016, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2017 in accordance with
accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Denver, Colorado
February 9, 2018
184
DCP SAND HILLS PIPELINE, LLC
CONSOLIDATED BALANCE SHEETS
(millions)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable:
Affiliates
Trade and other
Other
Total current assets
Property, plant and equipment, net
Other long-term assets
Total assets
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Affiliates
Trade and other
Deferred revenues:
Affiliates
Third party
Accrued taxes
Accrued capital expenditures
Accrued liabilities and other
Total current liabilities
Other long-term liabilities
Total liabilities
Total members’ equity
Total liabilities and members’ equity
December 31,
2017
2016
$
17.5
$
8.0
25.0
9.2
0.2
51.9
1,547.0
3.5
1,602.4
4.5
14.4
3.5
—
8.4
12.9
8.6
52.3
4.5
56.8
1,545.6
1,602.4
$
$
$
14.8
6.1
0.2
29.1
1,355.1
3.9
1,388.1
2.7
10.5
4.7
10.0
8.2
10.2
2.6
48.9
3.8
52.7
1,335.4
1,388.1
$
$
$
See Notes to Consolidated Financial Statements.
185
DCP SAND HILLS PIPELINE, LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(millions)
Operating revenues:
Transportation - affiliates
Transportation
Other revenues
Total operating revenues
Operating costs and expenses:
Cost of transportation - affiliates
Cost of transportation
Operating and maintenance expense
Depreciation expense
General and administrative expense - affiliates
General and administrative expense
Total operating costs and expenses
Operating income
Interest income
Income tax expense
Net income
Year Ended December 31,
2016
2015
2017
$
$
246.4
85.6
—
332.0
3.6
3.0
42.9
30.1
5.2
2.5
87.3
244.7
0.4
(1.7)
243.4
$
$
182.5
86.3
0.2
269
6.8
3.8
35.9
28.9
5.2
2.5
83.1
185.9
0.1
(1.6)
184.4
$
$
157.3
81.2
—
238.5
4.2
3.4
27.5
27.3
5.4
2.6
70.4
168.1
—
(1.4)
166.7
See Notes to Consolidated Financial Statements.
186
DCP SAND HILLS PIPELINE, LLC
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBERS’ EQUITY
(millions)
DCP Sand
Holding,
LLC
DCP
Pipeline
Holding
LLC
Phillips 66
Sand Hills
LLC
Spectra
Energy Sand
Hills
Holding,
LLC
Total
Members’
Equity
Balance, January 1, 2015
$
— $
403.6
$
403.7
$
403.7
$
1,211.0
Contributions from members
Distributions to members
Transfer of interest in DCP Sand Hills
Pipeline, LLC
Net income
Balance, December 31, 2015
Contributions from members
Distributions to members
Net income
Balance, December 31, 2016
Contributions from members
Distributions to members
Net income
Balance, December 31, 2017
2.7
(12.8)
431.3
10.1
431.3
22.0
(69.6)
61.5
445.2
73.3
(84.3)
81.1
28.7
(56.5)
—
55.6
431.4
21.8
(69.6)
61.4
445.0
73.2
(84.4)
81.2
28.6
(56.5)
—
55.6
431.4
21.9
(69.6)
61.5
445.2
73.3
(84.3)
81.1
26.0
(43.8)
(431.3)
45.4
—
—
—
—
—
—
—
—
86.0
(169.6)
—
166.7
1,294.1
65.7
(208.8)
184.4
1,335.4
219.8
(253.0)
243.4
$
515.3
$
515.0
$
515.3
$
— $
1,545.6
See Notes to Consolidated Financial Statements.
187
DCP SAND HILLS PIPELINE, LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(millions)
OPERATING ACTIVITIES:
Net income
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation expense
Other, net
Change in operating assets and liabilities:
Accounts receivable
Accounts payable
Deferred revenues
Other current assets
Other long-term assets
Other current liabilities
Other long-term liabilities
Net cash provided by operating activities
INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of assets
Net cash used in investing activities
FINANCING ACTIVITIES:
Contributions from members
Distributions to members
Net cash 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
Year Ended December 31,
2016
2017
2015
$
243.4
$
184.4
$
166.7
30.1
0.7
(13.3)
2.9
(11.2)
—
0.4
1
(0.1)
253.9
(211.2)
—
(211.2)
219.8
(253)
(33.2)
9.5
8
17.5
$
28.9
1.0
(0.9)
(1.7)
(19)
0.1
(2.7)
5.9
(0.6)
195.4
(57.3)
0.1
(57.2)
65.7
(208.8)
(143.1)
(4.9)
12.9
8.0
$
$
27.3
2.7
(6.5)
4.6
(1.7)
—
0.2
(0.3)
(0.6)
192.4
(110.6)
1.2
(109.4)
86.0
(169.6)
(83.6)
(0.6)
13.5
12.9
See Notes to Consolidated Financial Statements.
188
DCP SAND HILLS PIPELINE, LLC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended December 31, 2017, 2016, and 2015
1.
Description of Business and Basis of Presentation
DCP Sand Hills Pipeline, LLC, with its consolidated subsidiary, or Sand Hills, we, our, the Company, or us, is engaged in
the business of transporting natural gas liquids, or NGLs. The Sand Hills pipeline is a common carrier pipeline which provides
takeaway service from plants in the Permian and the Eagle Ford basins to fractionation facilities along the Texas Gulf Coast
and the Mont Belvieu, Texas market hub. The Sand Hills pipeline was placed into service in June 2013.
We are a limited liability company owned 33.330% by DCP Pipeline Holding LLC, and 33.335% by DCP Sand Holding,
LLC, both 100% owned subsidiaries of DCP Midstream, LP, or DCP Midstream, and 33.335% by Phillips 66 Sand Hills LLC,
a 100% owned subsidiary of Phillips 66 Partners LP, or Phillips 66 Partners. Throughout these consolidated financial statements,
DCP Midstream and Phillips 66 Partners will together be referenced as the members. DCP Midstream is a joint venture owned
50% by Phillips 66 and 50% by Enbridge, Inc., and is the operator of the Sand Hills pipeline.
Prior to October 2015, we were owned 33.335% by Spectra Energy Sand Hills Holding, LLC, a 100% owned subsidiary
of Spectra Energy Partners, LP, or Spectra Energy Partners. In October 2015, Spectra Energy entered into an agreement with
Spectra Energy Partners to acquire its ownership interest of 33.335% in the Company. On October 30, 2015, Spectra Energy
contributed its ownership of 33.335% interest in the Company to DCP Midstream.
The Company allocates revenues, costs, and expenses in accordance with the terms of the Second Amended and
Restated LLC Agreement, which became effective on September 3, 2013, or the LLC Agreement, to each of the three
members based on each member’s ownership interest. Under terms of the LLC Agreement, the members are required to
fund capital calls necessary to fund the capital requirements of the Company, including capital expansion and working
capital requirements. Under the terms of the LLC Agreement, cash calls and cash distributions from operations are
allocated to the members based upon each member’s respective ownership interest.
The consolidated financial statements include the accounts of Sand Hills and its 100% owned subsidiary and have been
prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Intercompany
balances and transactions have been eliminated. Transactions between us and the members have been identified in the
consolidated financial statements as transactions between affiliates.
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 - Cash and cash equivalents include all cash balances and 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.
Distributions - Under the terms of the LLC Agreement, we are required to make quarterly distributions to the members
based on Available Cash, as the term is defined in the LLC Agreement. Available Cash distributions are paid pursuant to the
members’ respective ownership percentages at the date the distributions are due.
Estimated Fair Value of Financial Instruments - The fair value of cash and cash equivalents, accounts receivable and
accounts payable included in the consolidated balance sheets are not materially different from their carrying amounts because
of the short-term nature of these instruments. We may invest available cash balances in short-term money market securities.
As of December 31, 2017 and 2016, we invested $17.5 million and $8.0 million, respectively, in short-term money market
securities which are included in cash and cash equivalents in our consolidated balance sheets. Given that the value of the short-
term money market securities is publicly traded and market prices are readily available, these investments are considered Level
1 fair value measurements.
Concentration of Credit Risk - Financial instruments that potentially subject us to concentrations of credit risk consist
principally of cash and accounts receivable. We extend credit to customers and other parties in the normal course of business
189
and have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and
rights of offset.
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.
Asset Retirement Obligations - Our asset retirement obligations, or AROs, relate primarily to the contractual
obligations relating to the retirement or abandonment of our transportation pipelines, obligations related to right-of-way
easement agreements, and contractual leases for land use. We adjust our AROs each quarter for any liabilities incurred or settled
during the period, accretion expense and any revisions made to the estimated cash flows. 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. None of our assets are legally restricted
for purposes of settling AROs.
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. 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:
•
•
•
•
•
•
a 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.
Revenue Recognition - We generate the majority of our revenues from fee-based arrangements. The revenues we earn are
from long-term contracts relating to the transportation of NGLs and generally are not dependent on commodity prices. Certain
demand contracts state that we will collect our monthly fee based on committed volumes, regardless of the actual volumes
transported. In some instances, revenue is deferred for any payments received in excess of actual volumes transported and
revenue is recognized once the committed volumes are transported, or certain contractual provisions have expired, and all other
revenue recognition criteria are met.
We recognize revenues 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 when the services are rendered.
•
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.
190
• 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.
Revenue for services provided, but not invoiced, is estimated each month. These estimates are generally based on
preliminary throughput measurements and contract data.
Significant Customers - There was one third party customer that accounted for more than 10% of total operating revenue
for the years ended December 31, 2017 and 2016. There was no third party customers that accounted for more than 10% of
total operating revenue for the year ended December 31, 2015. There were significant transactions with affiliates for each of
the years ended December 31, 2017, 2016 and 2015. See Note 4, Agreements and 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.
Income Taxes - We are structured as a limited liability company, which is a pass-through entity for federal income tax
purposes. As a limited liability company, we do not pay federal income taxes. Instead, our income or loss for tax purposes is
allocated to each of the members for inclusion in their respective tax returns. Consequently, no provision for federal income
taxes has been reflected in these consolidated financial statements. We are subject to the Texas margin tax, which is treated as
a state income tax. We follow the asset and liability method of accounting for state income taxes. Under this method, deferred
income taxes are recognized for the tax consequences of temporary differences between the consolidated financial statement
carrying amounts and the tax basis of the assets and liabilities. For the years ended December 31, 2017, 2016 and 2015, deferred
state income tax expense totaled $0.5 million, $0.7 million and $0.7 million, respectively. For the years ended December 31,
2017, 2016 and 2015, current state income tax expense totaled $1.2 million, $0.9 million and $0.7 million, respectively.
3. Recent Accounting Pronouncements
Financial Accounting Standards Board, or FASB, Accounting Standards Update, or ASU, 2016-15 “Statement of Cash
Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” or ASU 2016-15 - In August 2016, the
FASB issued ASU 2016-15, which amends certain cash flow statement classification guidance. We intend to adopt this ASU
when it is effective for public entities, which is for interim and annual reporting periods beginning after December 15, 2017.
The adoption of this ASU will have no impact on our consolidated cash flows.
FASB ASU, 2016-02 “Leases (Topic 842),” or ASU 2016-02 - In February 2016, the FASB issued ASU 2016-02, which
requires lessees to recognize a lease liability on a discounted basis and the right of use of a specified asset at the commencement
date for all leases. We intend to adopt this ASU when it is effective for public entities, which is for annual reporting periods
beginning after December 15, 2018, and we are currently assessing the impact of adoption on our consolidated results of
operations, cash flows and financial position.
FASB ASU, 2014-09 “Revenue from Contracts with Customers (Topic 606),” or ASU 2014-09 and related interpretations
and amendments - In May 2014, the FASB issued ASU 2014-09, which supersedes the revenue recognition requirements of
Accounting Standards Codification, or ASC, Topic 605 “Revenue Recognition.” This ASU is effective for annual reporting
periods beginning after December 15, 2017, with the option to adopt as early as annual reporting periods beginning after
December 15, 2016. Under the new standard, revenue is recognized when a customer obtains control of promised goods or
services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.
Although the new revenue recognition model is based on control, which differs from the previous model which was based a
transfer of risks and rewards, we expect to identify similar performance obligations under Topic 606 as compared with
deliverables and units of account previously identified under Topic 605. As a result, we expect the timing of our revenue to
remain the same with respect to the majority of our contracts. We also have certain contracts with customers whereby the
customer reimburses us for costs to construct certain logistical connections to our operating assets which we own and operate.
We previously accounted for these arrangements as a reduction to the cost basis of our long-lived assets which were amortized
as a reduction to depreciation expense over the estimated useful life of the related assets. Under Topic 606 we will record these
payments as deferred revenue which will be amortized into revenue over the contract term. We do not anticipate a material
impact to net income, operating income, or cash flows because the increase to depreciation expense will be offset by the increase
to revenues.
191
In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows
arising from contracts with customers. We adopted the guidance using the modified retrospective method on the effective date
of January 1, 2018.
4. Agreements and Transactions with Affiliates
DCP Midstream
Under the LLC Agreement, we are required to reimburse DCP Midstream for any direct costs or expenses (other than general
and administration services) incurred by DCP Midstream on our behalf. Additionally, we pay DCP Midstream an annual service
fee of $5.0 million, for centralized corporate functions provided by DCP Midstream 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. These expenses are included in general and
administrative expense - affiliates in the consolidated statements of operations. Except with respect to the annual service fee,
there is no limit on the reimbursements we make to DCP Midstream under the LLC Agreement for other expenses and
expenditures incurred or payments made on our behalf.
We have entered into transportation agreements with DCP Midstream, which include a commitment to transport volumes
at rates defined in our tariffs. These 15-year transportation agreements became effective in June 2013. We currently, and
anticipate to continue to, transact with DCP Midstream in the ordinary course of business. DCP Midstream was a significant
customer during the years ended December 31, 2017, 2016 and 2015.
DCP Southern Hills Pipeline, LLC
We have a long-term capacity lease with DCP Southern Hills Pipeline, LLC, or Southern Hills, which expires in March
2023. Under the terms of this agreement, Southern Hills has the right to transport minimum throughput volumes on the Sand
Hills pipeline at rates defined in the transportation agreement.
Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates:
DCP Midstream, LLC and its affiliates:
Transportation - affiliates
Cost of transportation - affiliates
General and administrative expense - affiliates
Southern Hills:
Transportation - affiliates
Phillips 66:
Transportation - affiliates
General and administrative expense - affiliates
Enbridge:
General and administrative expense - affiliates
2017
Year Ended December 31,
2016
(millions)
2015
$
$
$
$
$
$
$
236.7
3.6
5.0
3.2
6.5
0.2
$
$
$
$
$
$
169.8
6.8
5.0
3.2
9.5
0.2
$
$
$
$
$
$
— $
— $
150.6
4.2
5.0
3.2
3.5
0.2
0.2
192
We had balances with affiliates as follows:
DCP Midstream, LLC and its affiliates:
Accounts receivable
Accounts payable
Deferred revenue
Southern Hills:
Accounts receivable
Phillips 66:
Accounts receivable
Accounts payable
$
$
$
$
$
$
December 31,
2017
2016
(millions)
23.8
$
(4.5) $
(3.5) $
14.0
(2.5)
(4.7)
0.3
$
0.2
0.9
$
— $
0.6
(0.2)
5.
Property, Plant and Equipment
Property, plant and equipment by classification is as follows:
Transmission systems
Processing Facilities
Other
Land
Construction work in progress
Property, plant and equipment
Accumulated depreciation
Property, plant and equipment, net
Depreciable
Life
20 - 50 Years
35 - 60 Years
3 - 30 Years
December 31,
2017
2016
(millions)
$
$
1,530.3
0.3
3.2
0.2
140.9
1,674.9
(127.9)
1,547.0
$
$
1,399.1
—
3.3
0.2
50.4
1,453.0
(97.9)
1,355.1
Asset Retirement Obligations - As of December 31, 2017 and 2016, we had AROs of $1.7 million and $1.4 million,
respectively, included in other long-term liabilities in our consolidated balance sheets. For each of the years ended December
31, 2017, 2016 and 2015 accretion expense was less than $0.1 million. Accretion expense is recorded within operating and
maintenance expense in our consolidated statements of operations.
6.
Commitments and Contingent Liabilities
Regulatory Compliance - In the ordinary course of business, we are subject to various laws and regulations. In the opinion
of our management, compliance with existing laws and regulations will not materially affect our consolidated results of
operations, financial position, or cash flows.
Litigation - We are not party to any significant legal proceedings, but are a party to various administrative and regulatory
proceedings and various commercial disputes that arose during the development of the Sand Hills pipeline and 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 and other indemnification arrangements, will not have a material
adverse effect on our consolidated results of operations, financial position, or cash flows.
General Insurance - Insurance for Sand Hills is written in the commercial markets and through affiliate companies, which
management believes is consistent with companies engaged in similar commercial operations with similar assets. Our insurance
coverage includes general liability and excess liability insurance above the established primary limits for general liability. All
coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar
types of operations.
193
Environmental - The operation of pipelines for transporting NGLs 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, in some cases, local levels that relate to worker safety, air and water quality,
solid and hazardous waste storage, management, transportation and disposal, and other environmental matters. The cost of
planning, designing, constructing, and operating pipelines incorporates compliance with environmental laws and regulations,
worker safety standards, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i)
city, state and federal regulatory officials and through litigation, on hydraulic fracturing and the real or perceived environmental
impacts of this technique, which indirectly presents some risk to the available supply of natural gas and the resulting supply
of NGLs, (ii) federal regulatory agencies regarding pipeline system safety which could impose additional regulatory burdens
and increase the cost of our operations, and (iii) regulatory bodies and communities that could prevent or delay the development
of fossil fuel energy infrastructure such as pipeline and associated facilities used in our business. Failure to comply with various
health, safety and environmental 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 existing laws and regulations will not have a material adverse effect on our
consolidated results of operations, financial position, or cash flows.
Operating Leases - Consolidated rental expense, including leases with no continuing commitment, was $3.9 million, $3.5
million, and $4.1 million, respectively, for the years ended December 31, 2017, 2016 and 2015. 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:
Minimum Rental Payments
(millions)
$
$
3.6
3.7
3.7
3.8
2.0
16.8
2018
2019
2020
2021
2022
Total
7.
Supplemental Cash Flow Information
Non-cash investing and financing activities:
Property, plant and equipment acquired with accrued liabilities
Other non-cash changes in property, plant and equipment, net
$
$
20.6
0.1
$
$
15.1
$
(0.3) $
2.6
(1.4)
2017
Year Ended December 31,
2016
(millions)
2015
8.
Subsequent Events
We have evaluated subsequent events occurring through February 9, 2018, the date the consolidated financial statements
were available to be issued.
194
(b) Exhibits
Exhibit
Number
2.1
Description
*# 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).
2.2
*# 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).
2.3
*# 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).
2.4
*# 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).
2.5
2.6
2.7
2.8
2.9
*# 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).
2.10
*# 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).
2.11
*
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 5, 2012).
2.12
*# 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).
2.13
2.14
*# 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).
2.15
*
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).
2.16
*# 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).
195
Exhibit
Number
2.17
*# 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).
Description
2.18
*# Purchase and Sale Agreement, dated February 25, 2014, by and between DCP Midstream, LP, as seller, and
DCP Midstream Partners, LP, as buyer (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).
2.19
*# 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).
*
*
First Amendment to Contribution Agreement, dated February 27, 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
28, 2014).
Second Amendment to Contribution Agreement, dated March 28, 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 April 2,
2014).
*# Contribution Agreement, dated December 30, 2016, by and among DCP Midstream, LLC, DCP Midstream
Partners, LP and DCP Midstream Operating, 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 January 6, 2017).
Certificate of Limited Partnership of DCP Midstream Partners, LP dated August 5, 2005 (attached as Exhibit
3.1 to DCP Midstream Partners, LP's Registration Statement on Form S-1 (File No. 333-128378) filed with
the SEC on September 16, 2005).
Certificate of Amendment to Certificate of Limited Partnership of DCP Midstream Partners, LP dated
January 11, 2017 (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 January 17, 2017).
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).
Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated January 1, 2017 (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 January 6, 2017).
Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated January 11, 2017 (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 January 17, 2017).
Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of DCP Midstream
Partners, LP dated November 20, 2017 (attached as Exhibit 3.1 to DCP Midstream, LP’s Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on November 20, 2017).
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).
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 4.1 to DCP Midstream Partners,
LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on June 14, 2012).
196
2.20
2.21
2.22
3.1
3.2
*
*
3.3
*
3.4
*
3.5
*
3.6
3.7
3.8
4.1
4.2
4.3
*
*
*
*
*
*
Exhibit
Number
4.4
4.5
4.6
4.7
4.8
4.9
4.10
*
*
*
*
*
*
*
4.11
*
4.12
*
4.13
*
4.14
*
4.15
4.16
*
*
Description
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).
Sixth Supplemental Indenture dated as of March 13, 2014 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 13, 2014).
Indenture, dated as of August 16, 2000, by and between Duke Energy Field Services, LLC and The Chase
Manhattan Bank (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 January 6, 2017).
First Supplemental Indenture, dated August 16, 2000, by and between Duke Energy Field Services, LLC and
The Chase Manhattan Bank (attached as Exhibit 4.1 to DCP Midstream, LLC’s Current Report on Form 8-
K (File No. 000-31095) filed with the SEC on August 16, 2000).
Fifth Supplemental Indenture, dated as of October 27, 2006, by and between Duke Energy Field Services,
LLC and The Bank of New York (as successor to JPMorgan Chase Bank, N.A., formerly known as The
Chase Manhattan Bank) (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 January 6, 2017).
Sixth Supplemental Indenture, dated September 17, 2007, by and between DCP Midstream, LLC (formerly
known as Duke Energy Field Services, LLC) and The Bank of New York (as successor to JPMorgan Chase
Bank, N.A., formerly known as The Chase Manhattan Bank) (attached as Exhibit 4.4 to DCP Midstream
Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).
Eighth Supplemental Indenture, dated February 24, 2009, by and between DCP Midstream, LLC (formerly
known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as
successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as
The Chase Manhattan Bank) (attached as Exhibit 4.5 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).
Ninth Supplemental Indenture, dated March 11, 2010, by and between DCP Midstream, LLC (formerly
known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as
successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as
The Chase Manhattan Bank) (attached as Exhibit 4.6 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).
Tenth Supplemental Indenture, dated September 19, 2011, by and between DCP Midstream, LLC (formerly
known as Duke Energy Field Services, LLC) and The Bank of New York Mellon Trust Company, N.A. (as
successor to The Bank of New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as
The Chase Manhattan Bank) (attached as Exhibit 4.7 to DCP Midstream Partners, LP's Current Report on
Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).
Eleventh Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP,
DCP Midstream, LLC and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of
New York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan
Bank) (attached as Exhibit 4.8 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No.
001-32678) filed with the SEC on January 6, 2017).
Twelfth Supplemental Indenture, dated January 1, 2017, by and among DCP Midstream Operating, LP (as
successor to DCP Midstream, LLC (formerly known as Duke Energy Field Services, LLC)), DCP Midstream
Partners, LP and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New
York Mellon, as successor to JPMorgan Chase Bank, N.A., formerly known as The Chase Manhattan Bank)
(attached as Exhibit 4.9 to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678)
filed with the SEC on January 6, 2017).
Indenture, dated as of May 21, 2013, by and between DCP Midstream Operating, LP (as issuer and successor
to DCP Midstream, LLC) and the Bank of New York Mellon Trust Company, N.A (attached as Exhibit 4.10
to DCP Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on
January 6, 2017).
First Supplemental Indenture, dated May 21, 2013, by and between DCP Midstream, LLC and the Bank of
New York Mellon Trust Company, N.A (attached as Exhibit 4.11 to DCP Midstream Partners, LP's Current
Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017).
197
Exhibit
Number
4.17
4.18
10.1
*
*
*
10.2
*
10.3
10.4
*
*
10.5
*
Description
Second Supplemental Indenture, dated January 1, 2017, by and between DCP Midstream Operating, LP, DCP
Midstream, LLC and The Bank of New York Mellon Trust Company, N.A (attached as Exhibit 4.12 to DCP
Midstream Partners, LP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6,
2017).
Form of Unit Certificate for 7.375% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual
Preferred Units (attached as Exhibit 4.1 to DCP Midstream, LP’s Current Report on Form 8-K (File No.
001-32678) filed with the SEC on November 20, 2017).
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).
Amendment No. 4 to Amended and Restated Limited Liability Company Agreement of DCP Midstream
GP,LLC dated December 30, 2016 (attached as Exhibit 10.4 to DCP Midstream, LP’s Annual Report onForm
10-K (File No. 001-32678) filed with the SEC on February 15, 2017).
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).
10.6
*+ 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).
10.7
*+ 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).
10.8
*+ 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).
10.9
10.10
*+ 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).
*+ DCP Midstream Partners, LP 2016 Long-Term Incentive Plan (attached as Exhibit A to DCP Midstream
Partners, LP's Definitive Proxy Statement on Schedule 14A (File No. 001-32678) filed with the SEC on
March 15, 2016).
10.11
*+ DCP Services, LLC 2008 Long-Term Incentive Plan, as amended and restated effective March 1, 2017
(attached as Exhibit 10.3 to DCP Midstream, LP’s Quarterly Report on Form 10-Q (File No. 001-32678)
filed with the SEC on May 10, 2017).
10.12
10.13
+
+
Form of Strategic Performance Unit Grant Agreement under the DCP Services, LLC 2008 Long-Term
Incentive Plan.
Form of Restricted Phantom Unit Grant Agreement under the DCP Services, LLC 2008 Long-Term Incentive
Plan.
10.14
*+ DCP Midstream, LP Executive Deferred Compensation Plan (attached as Exhibit 10.18 to DCP Midstream,
LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February 15, 2017).
10.15
10.16
10.17
10.18
*+ DCP Midstream, LP Executive Deferred Compensation Plan Adoption Agreement (attached as Exhibit 10.19
to DCP Midstream, LP’s Annual Report on Form 10-K (File No. 001-32678) filed with the SEC on February
15, 2017).
+
+
*
DCP Services, LLC Executive Severance Plan.
Amendment to the DCP Services, LLC Executive Severance Plan.
Services and Employee Secondment Agreement, dated January 1, 2017, by and between DCP Services, 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 January 6, 2017).
198
Exhibit
Number
10.19
*
12.1
21.1
23.1
23.2
23.3
24.1
31.1
31.2
32.1
32.2
101
Description
Second Amended and Restated Credit Agreement, dated as of December 6, 2017, by and among DCP
Midstream Operating, LP, DCP Midstream, LP, Mizuho Bank, Ltd., as administrative agent, and the lenders
party thereto (attached as Exhibit 10.1 to DCP Midstream, LP's Current Report on Form 8-K (File No.
001-32678) filed with the SEC on December 8, 2017).
Computation of Ratio of Earnings to Fixed Charges.
List of Subsidiaries of DCP Midstream, LP.
Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Midstream, LP and the
effectiveness of DCP Midstream, LP's internal control over financial reporting.
Consent of Deloitte & Touche LLP on Consolidated Financial Statements of DCP Sand Hills Pipeline, LLC.
Consent of Ernst & Young LLP on Consolidated Financial Statements of Discovery Producer Services LLC.
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, LP for the year ended
December 31, 2017, 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.
Pursuant to Item 601(b)(2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted
schedule to the Securities and Exchange Commission upon request.
199
Item 16. Form 10-K Summary
None.
200
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.
SIGNATURES
Date: February 26, 2018
DCP Midstream, LP
By: DCP Midstream GP, LP
its General Partner
By: DCP Midstream GP, LLC
its General Partner
By:
/s/ Wouter T. van Kempen
Name: Wouter T. van Kempen
Title:
President and Chief Executive Officer
(Principal Executive Officer)
201
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 true and lawful attorney-in-fact and agent with full power of
substitution and resubstitution, for him and in his name, place, and stead, in any and all capacities, to sign any and all
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 attorneys-in-fact and agents, and each of them, 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 attorneys-in-fact
and agents, and each of them, 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 (Position with DCP Midstream GP, LLC)
Date
/s/ Wouter T. van Kempen
Wouter T. van Kempen
Chief Executive Officer, President,
Chairman of the Board and Director
(Principal Executive Officer)
February 26, 2018
/s/ Sean P. O'Brien
Sean P. O'Brien
/s/ Richard A. Loving
Richard A. Loving
/s/ Allen C. Capps
Allen C. Capps
/s/ Fred J. Fowler
Fred J. Fowler
/s/ William F. Kimble
William F. Kimble
/s/ Brian Mandell
Brian Mandell
/s/ Bill Waycaster
Bill Waycaster
/s/ Vern Yu
Vern Yu
/s/ John Zuklic
John Zuklic
Group Vice President and Chief Financial Officer
February 26, 2018
(Principal Financial Officer)
Chief Accounting Officer
February 26, 2018
(Principal Accounting Officer)
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
Director
Director
Director
Director
Director
Director
Director
202