Management's Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Directors, Executive Officers and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accountant Fees and Services
PART IV
Exhibits and Financial Statement Schedules
Form 10-K Summary
Signatures
GLOSSARY OF TERMS
The following is a list of terms used in the industry and throughout this report:
ASC
accounting standards codification
ASU
accounting standards update
Bbl
barrel
Bbls/d
barrels per day
Bcf
billion cubic feet
Bcf/d
billion cubic feet per day
Btu
British thermal unit, a measurement of energy
COBRA
Consolidated Omnibus Budget Reconciliation Act
Credit Agreement
Credit Agreement governing our Credit Facility
Credit Facility
Our $1.4 billion unsecured revolving credit facility, maturing March 18, 2027
Fractionation
the process by which natural gas liquids are separated
into individual components
GAAP
generally accepted accounting principles in the United States of America
LIBOR
London Interbank Offered Rate
MBbls
thousand barrels
MBbls/d
thousand barrels per day
MMBbls
million barrels
MMBtu
million Btus
MMBtu/d
million Btus per day
MMcf
million cubic feet
MMcf/d
million cubic feet per day
NGLs
natural gas liquids
OPEC
Organization of the Petroleum Exporting Countries
OPEC+
OPEC members plus ten other oil producing countries
OPIS
Oil Price Information Service
Railroad Commission
the Railroad Commission of Texas
SEC
U.S. Securities and Exchange Commission
Securitization Facility
$350 million Accounts Receivable Securitization
Facility, maturing August 12, 2024
SOFR
Secured Overnight Financing Rate
TBtu/d
trillion Btus per day
Throughput
the volume of product transported or passing through a
pipeline or other facility
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 for the year ended December 31, 2022, including the following risks and uncertainties:
• the timing and completion of our pending merger with Phillips 66 pursuant to which Phillips 66 will acquire all of our issued and outstanding common units not already owned by DCP Midstream, LLC or its subsidiaries;
• conflicts of interest may exist between our individual unitholders and Phillips 66, which has the authority to conduct, direct and manage the activiti es of DCP Midstream, LLC associated with the Partnership and our general partner;
• risks related to the disruption of economies around the world including the oil, gas and NGL industry in which we operate and the resulting adverse impact on our business, liquidity, commodity prices, workforce, third-party and counterparty effects and resulting federal, state and local actions;
• 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;
• new, additions to, and changes in, laws and regulations, particularly with regard to taxes, safety, regulatory and protection of the environment, including, but not limited to, climate change legislation, regulation of over-the-counter derivatives markets and entities, and hydraulic fracturing regulations, or the increased regulation of our industry, including additional local control over such activities, and their impact on producers and customers served by our systems;
• other factors beyond our control including the increased cost of labor, contractors, services, supplies and materials due to persistent inflation;
• general economic, market and business conditions;
• 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, 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 or we may be required to find alternative markets and arrangements for our natural gas and NGLs;
• our ability to continue the safe and reliable operation of our assets;
• our ability to grow through organic growth projects, or acquisitions, and the successful integration and future performance of such assets;
• our ability to access the debt and equity markets and the resulting cost of capital, which will depend on general market conditions, our financial and operating results, inflation rates, interest rates, our ability to comply with the covenants in our Credit Agreement or other credit facilities, and the indentures governing our notes, as well as our ability to maintain our credit ratings;
iii
• the creditworthiness of our customers and the counterparties to our transactions, including the impact of bankruptcies;
• the amount of collateral we may be required to post from time to time in our transactions;
• industry changes, including consolidations, alternative energy sources, technological advances, infrastructure constraints and changes in competition;
• 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 hire, train, and retain qualified personnel and key management to execute our business strategy;
• our ability to successfully manage our ongoing integration with Phillips 66;
• volatility in the price of our common units and preferred units;
• 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 terrorist attacks, and cybersecurity attacks and 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 factors generally described in “Item 1A. Risk Factors” in this report.
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.
PART I
Item 1. Business
OVERVIEW
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 a joint venture between Phillips 66 and Enbridge, Inc. (“Enbridge”) that, prior to the realignment transaction in August of 2022 described below, was owned 50% by Phillips 66 and 50% by Enbridge.
Our operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate. The remainder of our business operations are presented as “Other,” and consist of unallocated corporate costs.
Realignment Transaction
On August 17, 2022, Phillips 66 and Enbridge, through their respective subsidiaries, entered into an Agreement and Plan of Merger for the purpose of realigning their respective economic and governance interests in the Partnership and Gray Oak Pipeline, LLC through the merger of DCP Midstream, LLC with another joint venture owned by Phillips 66 and Enbridge (the “Realignment Transaction”). In connection with the closing of the Realignment Transaction, Phillips Gas Company LLC, an indirect wholly owned subsidiary of Phillips 66 (“PGC”), and Spectra DEFS Holding, LLC, an indirect wholly owned subsidiary of Enbridge, as the members of DCP Midstream, LLC, entered into a Third Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (the “Third A&R LLC Agreement”), which, among other things, designated PGC as the Class A Managing Member of DCP Midstream, LLC with the power to conduct, direct and manage all activities of DCP Midstream, LLC associated with the Partnership and each of its subsidiaries, DCP Midstream GP, LP (“GP LP”), our general partner, and DCP Midstream GP, LLC, the general partner of GP LP (the “General Partner”), and, in each case, the businesses, activities and liabilities thereof. The Third A&R LLC Agreement also provided PGC with the power to exercise DCP Midstream, LLC’s rights to appoint or remove any director on the board of directors of our General Partner and vote the common units representing limited partner interests in the Partnership that are owned directly or indirectly by DCP Midstream, LLC.
The diagram below depicts our organizational structure as of December 31, 2022.
Pending Merger with Phillips 66
On August 17, 2022, the board of directors of our General Partner received a non-binding proposal from Phillips 66 to acquire all of the Partnership’s issued and outstanding publicly-held common units not already owned by DCP Midstream, LLC or its subsidiaries at a value of $34.75 per common unit (the “Proposal”). The board of directors of our General Partner appointed the special committee to review, evaluate and negotiate the Proposal.
On January 5, 2023, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Phillips 66, Phillips 66 Project Development Inc., a wholly owned subsidiary of Phillips 66 (“PDI”), Dynamo Merger Sub LLC, a wholly owned subsidiary of PDI (“Merger Sub”), GP LP and our General Partner, pursuant to which Merger Sub will merge with and into the Partnership, with the Partnership surviving as a Delaware limited partnership (the “Merger”). Under the terms of the Merger Agreement, at the effective time of the Merger, each common unit representing a limited partner interest in the Partnership (other than the common units owned by DCP Midstream, LLC and GP LP) will be converted into the right to receive $41.75 per common unit in cash, without interest. The Partnership’s Preferred Units will be unaffected by the Merger and will remain outstanding following the Merger.
The Merger Agreement and the transactions contemplated thereby, including the Merger, were unanimously approved on behalf of the Partnership by the special committee and the board of directors of our General Partner, which is the general partner of GP LP. The special committee, which is comprised of independent members of the board of directors of our general partner, retained independent legal and financial advisors to assist it in evaluating and negotiating the Merger Agreement and the Merger. Concurrently with the execution and delivery of the Merger Agreement, DCP Midstream, LLC and GP LP, which, together own greater than a majority of the common units representing limited partner interests in the Partnership, delivered a written consent to GP LP that was sufficient to approve the Merger Agreement and the Merger. The Merger is expected to close in the second quarter of 2023. Completion of the Merger is subject to certain customary conditions as set forth in the Merger Agreement. There can be no assurance that the Merger will be consummated on the terms described above or at all.
OUR BUSINESS STRATEGY
Our primary business objectives are to achieve sustained company profitability, a strong balance sheet and profitable growth. 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 logistics assets and gathering and processing systems 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 incremental revenue, 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, by establishing relationships with new customers and by strategically rationalizing assets. 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 processors 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 leveraging our diverse and strategic asset base to increase supply across our fully integrated value chain. We will also make selective and capital efficient investments in our assets and energy transition.
Strategic Acquisitions and Partnerships . We intend to pursue economically attractive and strategic acquisition and partnership 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 processors of natural gas and one of the largest producers and marketers of NGLs in the United States with a diversified portfolio of integrated assets across our value chain. In 2022, our total wellhead volume was approximately 4.4 Bcf/d of natural gas and we produced an average of approximately 421 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:
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, the Denver-Julesburg Basin (“DJ Basin”), the Midcontinent, East Texas, the Gulf Coast, South Texas, and Central Texas. Our NGL pipelines connect to various natural gas processing plants and transport the NGLs to 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.
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 including the DJ Basin, Midcontinent, Permian Basin, 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.
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. The long term 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. As of December 31, 2022, we were approximately 70% fee-based.
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.
Digital Transformation . We are driving workforce efficiencies through automation, improving safety and decreasing emissions via real-time monitoring and predictive analytics and optimizing margins while increasing cost efficiencies.
Experienced Management Team. Our senior management team and the board of directors of our General Partner have extensive experience in the midstream industry.
Affiliation with DCP Midstream, LLC and Phillips 66 . Our relationship with DCP Midstream, LLC and its Class A Managing Member, Phillips 66, should continue to provide us with significant business opportunities. Through our relationship with DCP Midstream, LLC and Phillips 66, 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, together with GP LP, of approximately 57% of our common units. Through its ownership interest in DCP Midstream, LLC, Phillips 66 holds an indirect economic interest in us of approximately 43%, and is responsible, as the Class A Managing Member of DCP Midstream, LLC, for conducting, directing and managing all activities associated with us, our subsidiaries, GP LP and our General Partner.
OUR OPERATING SEGMENTS
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 and price risk management. 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, petrochemical plants 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.
The following is operating data for our Logistics and Marketing segment:
Operating Data
Year Ended December 31, 2022
System
Approximate
System Length (Miles)
Fractionators
Approximate
Throughput Capacity
(MBbls/d) (a)
Approximate Gas Throughput Capacity
(TBtus/d) (a)
Pipeline Throughput
(MBbls/d) (a)
Pipeline Throughput
(TBtus/d) (a)(b)
Fractionator Throughput (MBbls/d) (a)
Sand Hills pipeline
Southern Hills pipeline
Front Range pipeline
Texas Express pipeline
Other NGL pipelines (a)
Gulf Coast Express pipeline
Guadalupe pipeline
Cheyenne Connector
Mont Belvieu fractionators
Total
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.
(b) Represents average throughput for full year 2022.
NGL Pipelines
DCP Sand Hills Pipeline, LLC, or the Sand Hills pipeline, an interstate NGL pipeline which is owned 66.67% by us and 33.33% by Phillips 66, is a common carrier pipeline that 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.
DCP Southern Hills Pipeline, LLC, or the Southern Hills pipeline, an interstate NGL pipeline which is owned 66.67% by us and 33.33% by Phillips 66, provides takeaway service from the North and Midcontinent regions 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 plants, 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, 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.
Natural Gas Pipelines
Gulf Coast Express LLC, or the Gulf Coast Express pipeline, an intrastate natural gas pipeline in which we own a 25% interest, originates from the Waha area in West Texas to Agua Dulce, in Nueces County, Texas. Kinder Morgan is the operator of the pipeline. The Gulf Coast Express pipeline is fully subscribed under long-term transportation contracts with us and third party shippers.
The Guadalupe pipeline is an intrastate natural gas pipeline that provides us access to market centers/hubs including Waha, Texas, Katy, Texas and the Houston Ship Channel and is used primarily in our natural gas asset based trading activities. We may transport volumes for third party shippers using our available capacity in the future.
Cheyenne Connector, LLC, or the Cheyenne Connector is an interstate natural gas pipeline in which we own a 50% interest, which provides residue gas takeaway from the DJ Basin to the Rockies Express Cheyenne Hub, just south of the Colorado-Wyoming border. Tallgrass Energy is the operator of the Cheyenne Connector. The Cheyenne Connector is fully subscribed under long-term transportation contracts with us and third party shippers.
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 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 Marysville NGL storage facility, which stores ethane, propane and butane, is located in Michigan and has strategic access to 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.
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. Our 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 assets. When this market condition exists, we may execute derivative instruments around this differential at the market price. The 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.
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.
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 the maintenance and long term growth of 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 36 active natural gas processing plants, including an interest in a 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 2022, total wellhead volume on our assets was approximately 4.4 Bcf/d, originating from a diversified mix of customers. Our systems each have significant customer acreage dedications that we expect will continue to provide opportunities for growth as those customers execute their drilling plans over time. Our gathering systems also attract new natural gas volumes through numerous smaller acreage dedications and by contracting with undedicated producers who are operating in or around our gathering footprint. During 2022, the combined NGL production from our processing facilities was approximately 421 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
Year ended December 31, 2022
Regions
Plants
Approximate
Gathering
and Transmission
Systems (Miles)
Approximate
Net Nameplate Plant
Capacity
(MMcf/d) (a)
Natural Gas
Wellhead Volume
(MMcf/d) (a)
NGL
Production
(MBbls/d) (a)
North
Midcontinent
Permian
South
Total
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.
North Region
Our North region primarily consists of our DJ Basin system. We have a broad network of gathering, compression, treating, and processing facilities in Weld County, Colorado that provide significant optionality and flexibility.
Our DJ Basin system delivers to the Mont Belvieu hub in Mont Belvieu, Texas via the Southern Hills, Front Range and Texas Express pipelines, to the Conway hub in Bushton, Kansas via our Wattenberg pipeline, and Rockies Express Cheyenne Hub via the Cheyenne Connector.
Midcontinent Region
Our Midcontinent region primarily includes our Liberal system and 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.
Our gathering system footprint in the eastern Midcontinent region, which includes our South Central Oklahoma system, serves the SCOOP and STACK plays. Existing production in the western Midcontinent region, which includes our Liberal system in the Hugoton Basin, 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 and processing assets in the Midcontinent region deliver NGLs primarily to the Gulf Coast and Mont Belvieu via our Southern Hills pipeline.
Permian Region
Our Permian region primarily includes our West Texas system in the Midland Basin, our Southeast New Mexico system in the Delaware Basin, and our James Lake System that has connectivity to both the Midland and Delaware Basins. 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, to fractionation facilities along the Gulf Coast and to the Mont Belvieu hub. The Guadalupe pipeline provides gas takeaway from Waha to Katy, Texas. Through our ownership interest in the Gulf Coast Express pipeline we provide additional gas takeaway in the region. In the third quarter of 2022 we completed the acquisition of the James Lake System and a 120MMcf/d cryogenic processing facility that provides connectivity to the Delaware and Midland Basins.
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 include 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.
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. The HLPSA and implementing regulations apply to interstate and intrastate pipeline facilities and the pipeline transportation of liquid petroleum and petroleum products, including NGLs and condensate, and require 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) reauthorized 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 promulgated by DOT’s PHMSA address many areas of this legislation, as described below. We currently estimate we will incur approximately $92 million between 2023 and 2027 to implement integrity management program testing along certain segments of our natural gas transmission and NGL pipelines under Parts 192 and 195. 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, nor is it inclusive of estimated costs to implement the Final Gathering Rule (as defined and discussed in further detail below).
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 gave PHMSA civil penalty authority up to $213,268 per day per violation, with a maximum of $2,132,679 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.
On December 21, 2020, the U.S. Congress passed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (the 2020 Act). The Act reauthorizes the federal pipeline safety program through September 30, 2023, and establishes annual funding levels through 2023. The 2020 Act also requires PHMSA to issue new rules for gas pipeline leak detection and repair programs and idle pipelines, and issue final rulemakings for gas gathering lines, class location changes, and the definition of unusually sensitive areas. The 2020 Act establishes additional due process requirements applicable to PHMSA enforcement actions, authorizes a new declaratory order proceeding, and obligates PHMSA to consider an operator’s self-report in assessing a civil penalty.
On January 11, 2021, PHMSA published a Final Rule amending certain gas pipeline safety regulations at 49 C.F.R. Parts 191 and 192 (the "Final Rule"). Although the effective date of the Final Rule is March 12, 2021, PHMSA provided a deferred compliance date of October 1, 2021. Among other changes, these Part 192 changes include provisions allowing operators to remotely monitor cathodic protection rectifier stations, provided that they perform annual testing by physical inspection of the rectifier. The Final Rule also adjusts the monetary property damage threshold in the definition of an “incident” from $50,000 to $122,000 to account for inflation, with a commitment to update the threshold annually using a defined formula. The Final Rule incorporates certain industry standards for construction of plastic pipes and changes test factors for pressure vessels.
On November 15, 2021, PHMSA published a Final Rule amending the gas pipeline safety regulations at 49 CFR Parts 191 and 192 to extend regulation over larger diameter gas gathering pipelines located in rural (Class 1) locations (the “Final Gathering Rule”). The Final Gathering Rule imposes Part 191 or Part 192 requirements on such rural gathering pipelines. All rural gathering pipelines will be subject to annual and incident reporting under Part 191, while those pipelines over 8.625 inches in diameter that are operated at a maximum allowable operating pressure ("MAOP") of more than 20% of specified minimum yield strength ("SMYS") or, where SMYS is not known, where the MAOP exceeds 125 psig, must also comply with certain Part 192 requirements. The applicable Part 192 requirements increase with increased diameter and with proximity to buildings intended for human occupancy or impacted sites. For gathering pipelines between 8.625 inches and 16 inches in diameter, the new regulations require annual and incident reporting, as well as design and construction standards, damage prevention, and emergency planning on new pipelines or those that are repaired or replaced or otherwise substantially changed. If the potential impact radius of the pipeline segment includes a building intended for human occupancy or an impacted site, corrosion control, line markers, public awareness and leakage survey and repair for pipelines of less than 12.75 inches in diameter are also added, and MAOP requirements and standards for plastic pipelines for lines are added for pipelines between 12.75 inches and 16 inches in diameter. Pipelines of more than 16 inches in diameter are subject to all of the above, whether or not the potential impact radius includes any structures intended for human occupancy or impacted sites. The Part 191 reporting requirements of the Final Gathering Rule took effect on May 16, 2022. The remaining Part 192 requirements were to take effect on November 15, 2022 or May 16, 2023, depending on the rule section. However, following GPA Midstream Association’s petition for judicial review of the new rule, PHMSA agreed to stay enforcement until May 16, 2024 with respect to smaller-diameter pipelines (8.625 to 12.75 inches). We believe that we will be to meet the requirements of the Final Gathering Rule in all material respects by the dates set forth in the Final Gathering Rule.
We are currently evaluating the impact of the Final Gathering Rule on our operations and compliance programs. We are also evaluating opportunities to reduce the number of miles of pipeline that will be subject to the Final Gathering Rule, including changes in operating pressures and system reconfiguration or optimization.
Finally, the Company is evaluating the cost impact of the Final Gathering Rule, which depends on the results of our analysis of pipeline data. We currently estimate that we will incur costs of approximately $100 million to implement the requirements of the Final Gathering Rule, and we will refine that number as we complete our analysis.
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, and to the extent we make changes to our program to reflect the 2020 Act, we expect to be in material compliance by the effective dates of the new regulations promulgated under the 2020 Act.
States are largely preempted by federal law from regulating pipeline safety, but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we or the entities in which we own an interest operate. Our natural gas transmission and regulated gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.
In addition, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management 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 that involves a chemical at or above specified thresholds, or any process that 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 at temperatures below the normal
boiling point of the liquids without the benefit of chilling or refrigeration are exempt from these standards. The EPA regulations have similar applicability thresholds. We implement these safety programs, and 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.
FERC and State Regulation of Operations
Federal Energy Regulatory Commission (“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, Cheyenne Connector, 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:
• 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, allowed rate of return and volume 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 , , discriminatory or preferential, then any rate reduction or change that it orders generally will be 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 $1.5 million per day per violation, and violators may be subject to criminal penalties of up to $1.5 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.
Under the NGA and the National Environmental Policy Act of 1969, FERC has broad authority to approve the construction of new interstate natural gas pipeline facilities, including imposing environmental conditions on certificates of public convenience and necessity. In February 2022, FERC issued new policy guidance that details what FERC will consider in evaluating new pipeline infrastructure projects. Considerations include, among general public benefit and adverse effect analyses, impacts on: greenhouse gas emissions, the environment, environmental justice communities, existing customers of pending projects, existing pipelines and their customers, and landowners. FERC subsequently amended these policies in March 2022 to make them draft policies only, which renders them inoperable unless and until final policies are issued. Since then, FERC has requested and received comments on the draft policies. Depending on the outcome of these policies and the promulgation of new policies, regulations or statutes, new pipeline infrastructure projects could face increased scrutiny and enhanced regulatory reviews by federal, state and/or environmental regulators due to an increased focus on climate change policies and the fossil fuel industry. While we do not currently have projects pending that are subject to material risk, any governmental or regulatory actions that place additional burdens and/or costs on future projects, could impact our ability to develop new infrastructure.
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 and Gulf Coast Express pipeline are intrastate pipelines regulated as a gas utility by the Railroad Commission. 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 to observe the service applicable to transportation services provided under Section 311, to comply with the rates approved by FERC for Section 311 service, and 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 . Among other matters, EPACT 2005 also amended the NGPA to give FERC authority to impose civil for of the NGPA up to $1 million for any one and may be subject to of up to $1 million per 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.
Other Laws - Texas Weather Emergencies
In 2021, in response to Winter Storm Uri in February 2021, the State of Texas implemented new laws related to preparing for, preventing and responding to weather emergencies and power outages. Under the new law, several state agencies, including the Railroad Commission, the Public Utilities Commission of Texas (“TPUC”), and the Energy Reliability Council of Texas (“ERCOT”) are required to coordinate and implement new rules and processes related to weather emergencies impacting gas-fired electric generation and the natural gas production and supply chain. The Railroad Commission and TPUC implemented rules related to the critical designation of natural gas infrastructure and electric service to such critical infrastructure during an emergency. The Railroad Commission designated natural gas processing plants, natural gas pipelines and related facilities, and natural gas storage, in addition gas production and distribution facilities, as critical. We are obligated to develop a listing of our critical natural gas facilities and update it semi-annually. Electric utilities are obligated to review our critically designated facility listings and establish priorities during load shed events. The law further requires the agencies to “map” the supply chain of natural gas to electric generation facilities; natural gas facilities that are deemed to the supply of electricity will be required to implement measures to prepare to operate during a winter weather emergency (“weatherize”). Several of our facilities in Texas, including gas processing, gas storage and gas pipeline and compression facilities have been deemed to the supply of electric generation and are subject to new weatherization rules implemented by the Railroad Commission. Such facilities are required to implement weather emergency preparation measures and attest to such measures annually. to comply with the Railroad Commission’s weatherization requirements is subject to a of up to $1 million dollars per .
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 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 2020, the indexing methodology for the five years beginning July 1, 2021 was changed to be the Producer Price Index for Finished Goods plus 0.78%; however, after considering rehearing requests, the FERC revised its decision and adjusted the five-year index to the Producer Price Index minus 0.21%. The new ceiling levels and revised tariff rates implementing the revised index were required to be filed with FERC effective March 1, 2022. The FERC’s current five-year indexing methodology is subject to review in the U.S. Court of Appeals for the District of Columbia Circuit. 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 2021 and resulted in the decrease in many of the tariff rates for such pipelines. The ceiling levels for our interstate NGL pipelines were further decreased March 1, 2022, as a result of the revised 2021 index; however, many of the tariff rates were below the ceiling level and will remain unchanged. The index July 1, 2022, was based on the Producer's Price Index for Finished Goods, resulting in an increase to tariff rates.
In December 2022, FERC issued a notice of proposed policy statement in which FERC proposes to revise its policy for evaluating whether contractual committed transportation service complies with the Interstate Commerce Act where the only shipper to obtain the contractual committed service is the pipeline’s affiliate. FERC’s proposed policy is intended to evaluate the rate and non-rate terms offered in an open season for new capacity to ensure they are not structured to favor the pipeline’s affiliate and to exclude nonaffiliates. The policy, when finalized, would apply to future interstate committed service offerings. While no final policy has been issued, FERC’s proposed policy would place additional burdens and scrutiny on such transactions. We do not anticipate any changes to existing affiliate-only contractual committed transportation service.
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 for their intrastate NGL transportation services. The intrastate tariffs for many of our intrastate NGL pipelines rely on the FERC indexing methodology for annual adjustments to rates when the index is positive and remain unchanged when the index is negative.
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:
• 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;
• requiring changes or additions to our equipment or facilities, or changes to our operations, pursuant to government-promulgated regulations to protect the environment, including air quality and reduction of greenhouse gases;
• 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 environmental regulations or 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 current or 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 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 seek 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 includes methane. 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. , NGLs or natural gas) that we process, or we may otherwise be required by regulation to take steps to reduce emissions of GHGs.
At the federal level, the EPA has taken several actions to regulate emissions of GHGs. In 2010, the EPA found that certain GHGs “endanger” public health and welfare and that GHG vehicle emissions contribute to the GHG pollution threatening public health and welfare, thus triggering regulation of 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. Most recently, in 2016, the EPA proposed PSD and Title V permitting
regulations that would address control of GHG emissions if certain thresholds are met. While the EPA has not finalized the rule, states such as Colorado have adopted similar requirements. The EPA also has issued various rules relating to the mandatory reporting of GHG emissions, including mandatory reporting requirements of GHGs from petroleum and natural gas systems, which encompasses all segments of the oil and gas sector.
The EPA has adopted federal new source performance standards (“NSPS”) for new and modified oil and gas sector sources that regulate emissions of VOCs and methane from these sources. EPA promulgated the NSPS for VOCs in 2012 and the NSPS for VOCs and methane in 2016. The regulations, contained in 40 CFR Part 60, Subpart OOOO and OOOOa, require, among other things, control of VOC and methane emissions from subject sources through ensuring adequate design, requiring installation of emission controls, and institution of leak detection and repair programs. In November 2021, the EPA proposed regulations that expand the scope and breadth of the existing regulations. The 2021 proposed rules include provisions that: 1) extend emission control and reduction requirements under this part of the Clean Air Act to existing sources, which is a first; and 2) expand and tighten the existing emission reduction requirements for new or modified sources adopted in 2012 and 2016. In December 2022, EPA issued a supplemental proposal to update, strengthen and expand the 2021 proposed rules. EPA is expected to finalize the rule in 2023.
States’ efforts to comply with the National Ambient Air Quality Standard (“NAAQS”) for ozone, which is set by the EPA, also may have an impact on our operations. States or areas of a state that are not in attainment with the ozone NAAQS are required to approve implementation plans that reduce emissions of ozone precursors in order to achieve compliance with the NAAQS, which plans can impose emissions control requirements and associated costs on us or on our customers. 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, and in December 2018 EPA published a final rule “Implementation of the 2015 National Ambient Air Quality Standards for Ozone: Nonattainment Area State Implementation Plan Requirements.” The EPA in October 2016 issued Control Techniques Guidelines (“CTGs”) 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. Under the Trump Administration, the EPA on December 31, 2020, issued a final rule retaining the 2015 standard at 70 parts per billion. However, in late 2021, the EPA communicated that it would reconsider the 2020 decision to retain the ozone NAAQS with the intention of completing the reconsideration by the end of 2023. If the ozone NAAQS is lowered, it may result in additional actions by states requiring further emission controls and associated costs.
In relation to addressing the ozone NAAQS but more specifically greenhouse gas emissions, on January 29, 2019, the New Mexico governor issued an executive order establishing an interagency Climate Change Task Force and directing the Energy, Minerals and Natural Resources Department (“EMNRD”) and the New Mexico Environment Department (“NMED”) to develop a statewide, enforceable regulatory framework to reduce methane emissions from new and existing sources in the oil and gas sector. The Oil Conservation Division ("OCD") adopted the EMNRD rules in mid-2021, which institute gas capture requirements for both upstream and midstream operators, prohibit routine flaring, and require operation plans for operators of gas gathering systems. In 2022, the NMED adopted an Ozone Precursor rule crafted with the intention of preventing the state from falling into non-attainment with the ozone NAAQS by controlling ozone precursor pollutants, including nitrogen oxides ("NOx") and volatile organic compounds (“VOCs”), from the oil and gas industry, which will also have the associated effect of controlling or reducing methane emissions. The rule establishes emission standards and emission reduction requirements for various equipment and processes as well as leak detection and repair requirements. We anticipate that the NMED rule will impose additional operational costs and potential regulatory compliance and enforcement risks.
Similarly, Colorado has undertaken various rulemakings to address compliance with and attainment of the ozone NAAQS, including regulations in 2019 and 2020 to reduce emissions of NOx and VOCs from the oil and gas sector. These regulations, as an example, impose emissions standards on our compressor engines in the Ozone Non-Attainment Area, which, in turn, requires the installation of emissions control technologies and work practice standards to manage emissions. Further, in 2019 the Colorado legislature enacted HB19-1261 establishing statewide greenhouse gas emission reduction goals and included agency authorities and mandates to promulgate regulations to achieve greenhouse gas reduction goals. In January 2021 the governor issued the “Greenhouse Gas Pollution Reduction Roadmap,” which describes state actions and the regulatory pathway to achieve the HB19-1261 greenhouse gas reduction goals. The Greenhouse Gas Reduction Roadmap specifies, among other things, intended reductions by economic sector, including the oil and gas sector as well as the “residential, commercial and industrial” sector that includes emissions from the combustion of fuels. In 2021, Governor Polis signed HB21-1266 into law, which includes environmental justice provisions and requirements for adoption of rules for reduction of greenhouse gas (“GHG”) emissions from “oil and gas exploration, production, processing, transmission, and storage operations” by at least 36% by 2025 and 60% by 2030 below a 2005 baseline. These administrative and regulatory actions have been and will be pursued by various state agencies, including the Colorado Energy Office and the Colorado Air Quality Control Commission
(“AQCC”). In December 2021, the AQCC adopted regulations to reduce GHGs from the oil and gas sector through myriad requirements to address emissions and control requirements, including emissions reduction requirements for production well sites, and capture requirements for pigging activities and capture and control requirements for equipment blowdowns. The AQCC also adopted requirements for a Steering Committee to assess methods and feasibility to reduce GHG emissions from industrial combustion of hydrocarbon fuels, specifically including oil and gas sector compression equipment to gather and transport natural gas, ultimately resulting in plans and regulations for oil and gas sector industrial combustion equipment to achieve the HB21-1266 reduction goals. Effective November 7, 2022, Colorado's front range was reclassified from a “serious” to a “severe” nonattainment area for the 2008 8-hour ozone standard. In December 2022, the AQCC approved revisions to the State’s Implementation Plan to further reduce emissions of VOCs and NOx to come into compliance with the ozone standards. Additional future rulemakings from the AQCC are expected to yet further reduce emissions of VOCs and NOx from the oil and gas sector as part of the State’s Implementation Plan to come into compliance with the ozone standards.
The regulations in New Mexico and Colorado collectively are anticipated to impose near- and longer-term obligations and costs on our producer customers as well as on our own midstream equipment and facilities. These rulemaking proceedings to reduce greenhouse gas emissions could increase costs on or inhibit or adversely influence the ability of our producer customers to develop and operate production wells. These rulemaking proceedings could increase costs for us to operate our compressor stations or gas plants in the respective states, and they could affect the types of equipment or the manner in which we operate our midstream equipment. These rulemaking proceedings, or future related rulemaking proceedings, have the potential to result in some manner of greenhouse gas emissions caps in the state, or greenhouse gas sector-specific performance standards, either of which could result in increased costs on our producer customers or increased costs on us to operate our facilities, and could affect the types of equipment that we operate or the manner in which it is operated. These rulemaking proceedings have the potential to affect the operations and production of our customers, which can in turn affect our operations, and they also have the potential to affect our costs and facility operations, either of which could adversely affect our financial results or have such an effect on our operations.
The Clean Air Act imposes substantial potential civil and criminal penalties for non-compliance with or deviations from applicable regulations or permits. State laws for the control of air pollution also provide varying administrative, civil and potentially criminal penalties and liabilities. The permitting, regulatory compliance and reporting programs, including those detailed above, taken as a whole, increase the costs and complexity of oil and gas operations with the 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, or 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 or a location 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 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, or transported 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 substances that have been released into the environment, for 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 to public health or the environment and to seek to recover from the responsible parties the costs that the agency incurs. the “petroleum exclusion” of CERCLA Section 101(14), which encompasses natural gas, we may nonetheless handle substances within the meaning of CERCLA, or similar state statutes, in the ordinary course of our 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 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 sustaining 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 contribute to or 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 financial condition or results of operations.
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 administrative, civil and potentially 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 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 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 financial condition or results of operations.
Anti-Terrorism Measures
The United States 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.
Human Capital Management
Our operations and activities are managed by our general partner, GP LP, which is managed by its general partner, the General Partner, which is 100% owned by DCP Midstream, LLC. We do not have any employees. As of December 31, 2022, 1,910 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 (the “Services Agreement”). 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.
Integration with Phillips 66
Following the completion of the Realignment Transaction in August of 2022, we began to integrate certain of our operations with Phillips 66’s midstream segment, including the integration of operational services that are currently, or were previously, provided by DCP Services, LLC. As part of these integration efforts, continuing employees will transfer employment to a Phillips 66 subsidiary, which we expect to occur beginning in the second quarter of 2023, and general and administrative services will be provided by Phillips 66 or one or more of its subsidiaries going forward. We expect these integration efforts to continue regardless of the outcome of our pending Merger with Phillips 66.
The following summary of employment related matters generally refers to plans and policies in place prior to the completion of these integration efforts. Once our integration with Phillips 66 is complete, we anticipate that employees that provide support for our operations will be subject to existing plans and policies maintained by Phillips 66.
Benefits and Compensation
Our compensation program is designed to attract and reward talented individuals who possess the skills necessary to support our business objectives, assist in the achievement of our goals and create long term value for our unitholders. We incentivize our employees by providing market competitive total compensation packages, including salaries, bonuses, opportunities for equity ownership, and benefits, including comprehensive medical plan options; dental, vision and life insurance; 401(k) savings matches and retirement contributions; vacation, sick, personal and wellness days; tuition and gym membership reimbursement, voluntary insurance, an employee-matching charitable gifts program, an employee assistance program and additional programs through DCP Perks. We use voluntary turnover as a key measure to track and reduce the turnover of key and critical employees, which was 8.6% in 2022.
Training and development
We believe that the high performance of our employees is a byproduct of our employees honing the skills and tools necessary to manage change and prepare for the future, and we are dedicated to the continual growth of our employees through training and development programs. We provide growth opportunities to all employees through programs ranging from individual development plans, rotational programs, tuition reimbursement, and a focused effort on succession planning tailored to each employee’s unique vision of success. Our performance review and talent development process is one in which managers provide regular feedback and coaching to assist with the development of our employees, including the use of individual development plans to assist with individual career development.
Safety, Health and Wellness
Safety is the first tenet of our vision to be the safest, most reliable, low-cost midstream service provider, and is our highest value. The importance of the safety of our employees and contractors is exemplified in our compensation structure, as every executive and employee has been directly incentivized to achieve industry-leading safety performance since 2007. Our Start SAFE Finish SAFE (“SSFS”) program provides a framework to ensure employees and contractors are starting and finishing each task or job safely. In conjunction with our SSFS program, we also have an environmental, health and safety management system database that is used to track and communicate safety related activities and events, such as audits, injuries, incidents, and near misses, including incident investigation observations and responsive actions. The Company uses (i) the employee Total Recordable Incident Rate (“TRIR”), which is the number of OSHA recordable injuries per 200,000 hours worked, and (ii) the Process Safety Event Rate (“PSER”), which is the number of process safety events per 1,000,000 work hours, as indicators of its performance. We are consistently a leader in the midstream industry for safety performance. In 2022 the company had a TRIR of 0.34 and a PSER of 0.65.
We provide our employees with access to a variety of innovative, flexible and convenient health and wellness programs. These programs are designed to support employees' physical and mental health through tools and resources to help them improve their health and encourage engagement in healthy behaviors.
Inclusion and Diversity
We are committed to advancing inclusion and diversity (“I&D”) in our workplace and driving accountability for progress throughout the Company. Our leadership is dedicated to maintaining an inclusive workplace that is free from harassment and discrimination and provides advancement opportunities for all employees. We support a variety of internal employee resource groups, including our six Inclusion and Diversity subcommittees and our Business Women’s Network.
The Company demonstrated corporate leadership on inclusion and diversity by setting the following forward-looking goals via our annual sustainability report. Our Inclusion and Diversity strategy consists of a 2028 goal to ensure our workforce and leadership fully represents the gender and racial demographics of the industry's available and qualified talent within the communities in which we operate. It also includes a 2031 goal to ensure that our internal leadership succession pipeline reflects the gender and racial demographics of the available and qualified talent within the communities where we operate. Additionally, we strive to ensure that representation of our veteran communities aligns with national demographics on an annual basis. Finally, over a five-year period, we have a goal to maintain employee satisfaction and belonging scores above industry benchmark.
As part of our work to meet these goals, we piloted a first of its kind, industry centric virtual reality training across our organization, in partnership with Moth+Flame and the National Urban League. This training centered on empowering our employees to create and enable psychologically safe environments, a fundamental prerequisite for Inclusion and Diversity work. Our Business Women’s Network managed the second year of a company-wide women’s mentorship program, which partners our women leaders with emerging women leaders for formal mentorship opportunities to support increasing the number of women in leadership and management positions at the Company. 25% of DCP’s female officers and employees participated in the program in 2022. Additionally, the Business Women’s Network launched their first annual Elevate Women’s Leadership conference, hosting over 60% of DCP’s female officers and employees for a two-day conference focused on connection, professional development, and leadership skills.
General
We make certain filings with the 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 on the internet at www.sec.gov or through our website, www.dcpmidstream.com , as soon as reasonably practicable after they are filed with the SEC. Our annual reports to unitholders, press releases and recent analyst presentations are also available free of charge on our website. Information regarding our ESG, corporate responsibility and sustainability initiatives is also available on our website at www.dcpmidstream.com/sustainability. We have also posted our Code of Business Ethics, board committee charters and other corporate governance documents on our website. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this report.
Item 1A. Risk Factors
Risk Factors Summary
The following is a summary of the principal risk factors that could adversely affect our business, operations and financial results. These risks include, but are not limited to, the following:
Risks Related to Our Business and Industry
Risks Related to Our Operations
• Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business.
• We face numerous risks related to the disruption of economies around the world including the oil, gas and NGL industry in which we operate and the resulting adverse impact on our business, liquidity, commodity prices, workforce, third-party and counterparty effects and resulting federal, state and local actions, which could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.
• Market conditions, including commodity prices, may impact our earnings, financial condition and cash flows.
• We could incur losses due to impairment in the carrying value of our long-lived assets.
• 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.
• We depend on certain natural gas producer customers for a significant portion of our supply of natural gas and NGLs.
• 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.
• 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 may incur significant costs and liabilities resulting from implementing and administering pipeline and asset integrity programs and related repairs.
• Our assets and operations, and related upstream and downstream operations, can be affected by weather, weather-related conditions and other natural phenomena.
• 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.
• 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 business involves many hazards and operational risks, some of which may not be fully covered by insurance.
Risks Related to the Merger
• The timing of the completion of our Merger with Phillips 66 is not certain, which affects when our common unitholders will receive the merger consideration. If the Merger is not consummated, the market price of our common units may decline.
• While the Merger is pending, we are subject to contractual restrictions which could adversely affect our business.
• We have and will continue to incur substantial transaction-related costs in connection with the Merger. If the Merger does not occur, we will not benefit from these costs.
• Securities class action and derivative litigation could result in substantial costs and may delay or prevent the closing of our Merger with Phillips 66.
Legal, Regulatory and Technology Risks
• Federal executive, legislative, and regulatory initiatives relating to oil and gas operations could adversely affect our operations and those of our third-party customers.
• 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.
• 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.
• 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.
• We may incur significant costs in the future associated with proposed climate change regulation and legislation.
• 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 and natural gas liquids that we gather, process and transport.
• Our increasing dependence on digital technology puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruption or financial loss.
• Our business could be negatively impacted by security threats, including cybersecurity threats, terrorist attacks, the threat of terrorist attacks and related disruptions.
Risks Related to Our Indebtedness
• 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.
• Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
• Restrictions in our debt agreements may limit our ability to make distributions to unitholders and may limit our ability to capitalize on acquisitions and other business opportunities.
• Our significant indebtedness and the restrictions in our debt agreements may adversely affect our future financial and operating flexibility.
Risks Inherent in an Investment in Our Units
• Conflicts of interest may exist between our individual unitholders and Phillips 66, which has the authority to conduct, direct and manage the activities of DCP Midstream, LLC associated with the Partnership and our general partner.
• 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.
• Our Partnership Agreement limits our general partner’s fiduciary duties to holders of our units (other than our general partner and its affiliates).
• Our Partnership Agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
• Holders of our units have limited voting rights and are not entitled to elect our general partner or its directors.
• Our units may experience price volatility.
• Our Partnership Agreement restricts the voting rights of our unitholders owning 20% or more of any class of our units.
• 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.
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 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.
• 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.
Additional risks and uncertainties not presently known to us or that we currently deem immaterial also may impair our business, financial condition, results of operations and cash flows.
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 for the year ended December 31, 2022 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 distributions on our units, the trading price of our units could decline and you could lose all or part of your investment.
Risks Related to Our Business and Industry
Risks Related to Our Operations
Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments required to operate our business.
The U.S. economy experienced rising inflation in 2022. A sustained increase in inflation may continue to increase our costs for labor, services, and materials. Further our producer suppliers and customers face inflationary pressures and resulting impacts, such as the tight labor market, availability of drilling and hydraulic fracturing equipment, and supply chain disruptions, which could increase the cost of production which in turn may limit the level of drilling activity in the regions in which we operate. Our throughput volumes of natural gas and NGL supply may be impacted if producers are constrained. The rate and scope of these various inflationary factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may have an adverse effect on our costs, operating margins, results of operations and financial condition.
We face numerous risks related to the disruption of economies around the world including the oil, gas and NGL industry in which we operate and the resulting adverse impact on our business, liquidity, commodity prices, workforce, third-party and counterparty effects and resulting federal, state and local actions; which could have a material adverse effect on our business, financial condition, liquidity, results of operations and prospects.
The demand for oil, gas and NGLs is generally linked closely with broad-based macroeconomic activities. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on our financial results. Other factors that affect general economic conditions such as periods of civil unrest, government regulation, security or public health issues and responses, can also impact the demand for our products. The extent to which these various factors may impact our business, financial condition, liquidity, results of operations and prospects will depend highly on future developments, which are very uncertain and cannot be predicted with confidence. Additionally, the extent and duration of any of these factors on our unit price is uncertain and may make us look less attractive to investors and, as a result, there may be a less active trading market for our units, our unit prices may be more volatile, and our ability to raise capital could be impaired.
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. The prices of natural gas, NGLs and crude oil have historically 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 volatility during 2022, as illustrated by the following table:
Year Ended December 31, 2022
December 31, 2022
Daily High
Daily Low
Commodity:
NYMEX Natural Gas ($/MMBtu)
NGLs ($/Gallon)
Crude Oil ($/Bbl)
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 or extreme winter or summer weather that cause lower or higher 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, including the ability or willingness of OPEC and OPEC+ to set and maintain pricing and production levels for oil, which, for example, had a pronounced effect on global oil prices and the volatility thereof in 2020 during the onset and spread of the COVID-19 pandemic;
• 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.
The 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.
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, 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 or we may be required to find alternative markets and arrangements for our natural gas and NGLs.
The natural gas we gather, compress, treat, process, transport, sell and store, or the NGLs we produce, fractionate, transport, sell and store, are delivered into pipelines for further delivery to end-users, including fractionation facilities. If these pipelines, storage and fractionation facilities cannot, or will not, accept delivery of the gas or NGLs due to capacity constraints or changes in interstate pipeline gas quality specifications, we may be forced to limit or stop the flow of gas or NGLs through our pipelines and processing, treating, and fractionation facilities. We have long and short-term arrangements with facilities to fractionate our NGL production; however, additional fractionation capacity may be limited to the extent current and planned fractionation facilities experience delays in construction, significant mechanical or other problems arise at existing facilities, or such facilities otherwise become unavailable to us due to unforeseen circumstances. As a result, we may be required to find alternative markets and arrangements for our production and for fractionation, and such alternative markets and arrangements may not be available on favorable terms, or at all. Additionally, capacity constraints may impact production volumes from our producer customers and/or transportation volumes from our third-party NGL customers if there is fractionation or storage capacity to handle all of their projected volumes. Any number of factors beyond our control could cause such or constraints, including fully utilized capacity, necessary and scheduled maintenance, or 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 affect our operations and cash flows available for distribution to our unitholders.
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, and reduce the amount of NGL extraction, which would decrease 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.
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 risk, we also forego the benefits we would otherwise experience if commodity prices 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 long-lived assets.
We periodically evaluate 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. 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.
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. In 2022, our two largest suppliers of natural gas accounted for 27% of our total natural gas supply. 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 , which could have a material 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. If any of these third parties do not continue operation of these facilities or they become unavailable to us, and we are not able to obtain new facilities to transport, process or produce natural gas and NGLs, it could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to make cash distributions.
We may not successfully balance our purchases and sales of natural gas.
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. 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.
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 method investments. 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:
• 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 and PHMSA has indicated that it expects to publish these final rules this year. 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 Railroad Commission.
We currently estimate that we will incur costs of approximately $92 million between 2023 and 2027 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 integrity assessment program, nor is it inclusive of estimated costs to implement the Final Gathering Rule (as defined and discussed in further detail below).
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, if at all.
Any new or expanded pipeline integrity requirements or the adoption of other asset integrity requirements could also increase our cost of operation and impair our ability to provide service during the period in which assessments and repairs take place, adversely affecting our business. Further, execution of and compliance with such integrity programs may cause us to
incur greater than expected capital and operating expenditures for repairs and upgrades that are necessary to ensure the continued safe and reliable operation of our assets.
We are exposed to the credit risks of our producer customers and counterparties, and any material nonpayment or nonperformance by our producer customers or counterparties 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 counterparties. Any material nonpayment or nonperformance by our producer customers or counterparties could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers or counterparties 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. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices, or financial difficulties that could impact their creditworthiness and ability to perform their contractual obligations, including their ability to pay us.
Our assets and operations, and related upstream and downstream 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. Extreme weather conditions and temperature changes may adversely impact the mechanical abilities of equipment and the volumes of natural gas gathered and processed and NGL volumes produced, transported, and fractionated. Any power interruptions and inaccessible well sites as a result of extreme weather or severe storms or freeze-offs, a phenomenon where produced water freezes at the wellhead or within the gathering system, may interrupt the flow of natural gas and NGLs. If we incur a significant in our operations, or there is a significant in related upstream or downstream 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 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:
• the fees we charge and the margins we realize for our services;
• the prices of, level of production of, and demand for natural gas, condensate, and NGLs;
• 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;
• the operational performance and efficiency of our assets, including our plants and equipment;
• the operational performance and efficiency of third party assets 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 and NGLs;
• 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:
• the level of capital expenditures we make;
• the cost and form of payment for acquisitions;
• our debt service requirements and other liabilities;
• fluctuations in our working capital needs;
• our ability to borrow funds and access capital markets at reasonable rates;
• restrictions contained in our 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 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 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 some of the land on which our pipelines and facilities are located, which may subject us to increased costs or disruptions to our operations.
Our pipelines and facilities are located either on land that we own in fee, or on land in which our right to use such land for our operations is derived from leases, easements, rights of way, permits, or licenses from landowners or governmental authorities either in perpetuity or for a specific period of time. We may become 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. Any loss of rights with respect to land on which we operate, could disrupt our ability to continue operations thereon and adversely affect our business, results of operations, and financial position.
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 and NGLs, including:
• 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, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage facilities, or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;
• contaminants in the pipeline system;
• fires and explosions; and
• other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks inherent to our business, including offshore wind. We insure our underground pipeline systems against property damage, although coverage on certain of our small diameter gathering pipelines is subject to usual and customary sublimits. 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 . In some instances, certain insurance could become or available only for reduced amounts of coverage, or may become prohibitively expensive, and we may elect not to carry such a policy.
We are subject to business uncertainties during our ongoing integration with Phillips 66 that may cause disruption.
Employee uncertainty about the effect of our ongoing integration with Phillips 66 may have an adverse effect on us. These uncertainties may impair our ability to attract, retain and motivate employees and could cause those that transact with us to seek to change their existing business relationships with us. Our operations require engineers, operating and field technicians and other highly skilled employees. Competition for skilled employees is intense and increases when the demand from other energy companies for such personnel is high. Current and prospective employees may experience uncertainty about their roles within the combined company, which may have an adverse effect on our current ability to attract or retain employees.
Risks Related to the Merger
The timing of the completion of our merger with Phillips 66 is not certain, which affects when our common unitholders will receive the merger consideration. If the Merger is not consummated, the market price of our common units may decline.
Completion of our merger with Phillips 66 is subject to several conditions, not all of which are controllable by us. Accordingly, the date on which our unitholders will receive the merger consideration depends on the completion date of the merger, which is uncertain. If any of the conditions to completing the merger are not satisfied or waived, the merger may not occur, even though affiliates of Phillips 66, as the holders of a majority of our outstanding common units, have already delivered a written consent approving the merger. If the merger does not occur, the market price of our common units may decline.
While the Merger is pending, we are subject to contractual restrictions which could adversely affect our business.
The Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Phillips 66, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.
We have and will continue to incur substantial transaction-related costs in connection with the Merger. If the Merger does not occur, we will not benefit from these costs.
We may incur a number of non-recurring costs associated with the completion of the Merger, which could be substantial. Nonrecurring transaction costs include, but are not limited to, fees paid to legal, financial and accounting advisors. If the Merger does not occur in a timely manner or at all, we will not benefit from these costs.
Securities class action and derivative litigation could result in substantial costs and may delay or prevent the closing of our Merger with Phillips 66.
Companies that have entered into merger agreements often become the target of securities class action lawsuits and derivative litigation that seek to enjoin the relevant merger or seek monetary relief regardless of the merits related to the underlying acquisition. While we will evaluate and defend against any litigation vigorously, an unfavorable resolution of any such litigation could delay or prevent the consummation of our Merger with Phillips 66 and the costs of the defense of such litigation and other effects of such litigation could have a material adverse effect on our financial condition, results of operations and cash flows.
Legal, Regulatory and Technology Risks
Federal executive, legislative, and regulatory initiatives relating to oil and gas operations could adversely affect our operations and those of our third-party customers.
The Biden administration has generally taken a more rigorous approach to environmental regulations and permitting reviews, particularly as they related to air quality and climate issues. In January 2021, President Biden issued Executive Order 13990, which directed executive departments and agencies at the time to review all existing regulations, orders, guidance documents, policies and any other similar action taken during the previous Administration that are inconsistent with President Biden’s plan to elevate climate issues and, as appropriate, suspend, revise, or rescind those that are inconsistent with that plan. Those initial actions included the revocation of certain prior Executive Orders concerning federal regulation executed by the previous Administration, as well as new Executive Orders directing a focused regulatory freeze and review of rulemaking actions taken by the prior Administration.
Additionally, in January 2021, President Biden issued Executive Order 14008 imposing a temporary moratorium on the issuance of new oil and gas leases on public lands and offshore waters, pending a comprehensive review and reconsideration of oil and gas permitting and leasing practices. That same Order directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by mid-century or before. That effort was designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch for example on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice.
The moratorium on new oil and gas leases was challenged in several courts, including in Louisiana federal district court in a lawsuit filed in March 2021 by officials representing 13 states and in Wyoming federal district court in a similar lawsuit by officials representing the State of Wyoming and various trade organizations, and in North Dakota federal district court in a similar lawsuit by officials representing State of North Dakota. In June 2021, the Louisiana federal judge issued a preliminary injection and in August 2022, a permanent injunction against the moratorium as it pertains to the states that are parties to the Louisiana litigation.
When on-shore lease sales resumed in 2022, the acreage was geographically limited, and the lease terms included higher federal royalty rates more in line with royalties required by many states, and the environmental review accompanying the lease sale notices generally contained more robust greenhouse gas emissions and climate change impact analyses. As of the end of the 2022 fiscal year on September 30, 2022, the Biden Administration had offered only 127,691 onshore acres for lease.
On August 16, 2022, President Biden signed the reconciliation budget bill, known as the Inflation Reduction Act of 2022 (“IRA”), which imposed an expression of interest fee for nominating federal lands for potential lease sale, increased the royalty rate, annual rental rate, and minimum bid on federal oil and gas leases issued after that date, and ended the noncompetitive oil and gas leasing process. Furthermore, royalty will now also be imposed on gas that is vented, flared, or leaked, except for safety purposes. However, as a concession to Senator Manchin, wind and solar development was tied to the reinstatement of federal oil and gas lease sales. The IRA requires Department of the Interior to offer at least two million acres a year for federal onshore oil and gas lease sales or half of all the land nominated for leasing and hold a lease sale within 120 days of issuing any wind or solar rights-of-way. The IRA also includes a new “waste emission charge” imposed for methane emissions for oil and gas production and onshore pipelines, storage, gathering, and boosting for facilities that emit more than 25,000 metric tons of carbon dioxide annually beginning in 2025. On November 3, 2022, the U.S. Environmental Protection Agency issued a Request for Information seeking comments on implementation of both the methane emissions charge and the methane emissions reduction incentives program authorized and funded by the IRA. Also in November 2022, the Department of Interior issued seven Instruction Memoranda outlining the agency’s policies for implementing the IRA.
On November 15, 2021, PHMSA published a Final Rule amending the gas pipeline safety regulations at 49 CFR Parts 191 and 192 to extend regulation over larger diameter gas gathering pipelines located in rural (Class 1) locations (the “Final Gathering Rule”). The Final Gathering Rule imposes Part 191 or Part 192 requirements on such rural gathering pipelines. All rural gathering pipelines will be subject to annual and incident reporting under Part 191, while those pipelines over 8.625 inches in diameter that are operated at a maximum allowable operating pressure ("MAOP") of more than 20% of specified minimum
yield strength ("SMYS") or, where SMYS is not known, where the MAOP exceeds 125 psig, must also comply with certain Part 192 requirements. The applicable Part 192 requirements increase with increased diameter and with proximity to buildings intended for human occupancy or impacted sites. For gathering pipelines between 8.625 inches and 16 inches in diameter, the new regulations require annual and incident reporting, as well as design and construction standards, damage prevention, and emergency planning on new pipelines or those that are repaired or replaced or otherwise substantially changed. If the potential impact radius of the pipeline segment includes a building intended for human occupancy or an impacted site, corrosion control, line markers, public awareness and leakage survey and repair for pipelines of less than 12.75 inches in diameter are also added, and MAOP requirements and standards for plastic pipelines for lines are added for pipelines between 12.75 inches and 16 inches in diameter. Pipelines of more than 16 inches in diameter are subject to all of the above, whether or not the potential impact radius includes any structures intended for human occupancy or impacted sites. The Part 191 reporting requirements of the Final Gathering Rule took effect on May 16, 2022. The remaining Part 192 requirements were to take effect on November 15, 2022, or May 16, 2023, depending on the rule section. However, following GPA Midstream Association’s petition for judicial review of the new rule, PHMSA agreed to stay enforcement until May 16, 2024, with respect to smaller-diameter pipelines (8.625 to 12.75 inches).
In November 2021, EPA proposed the expansion of the federal new source performance standards (“NSPS”) for new and modified, and existing, oil and gas sector sources that regulate emissions of VOCs and methane from these sources. EPA had promulgated enhanced NSPS regulations for VOCs in 2012 and the NSPS for VOCs and methane in 2016. The regulations, contained in 40 CFR Part 60, Subpart OOOO and OOOOa, among other things, require control of VOC and methane emissions from subject sources through ensuring adequate design, requiring installation of emission controls, and institution of leak detection and repair programs. EPA’s November 2021 proposed regulations would expand the scope and breadth of the existing regulations. The 2021 proposed rules include provisions that: 1) extend emission control and reduction requirements under this part of the Clean Air Act to existing oil and gas sources, which is a first; and 2) expand and tighten the existing emission reduction requirements for new or modified oil and gas sources adopted in 2012 and 2016. In December 2022, EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. EPA is expected to finalize the rule in 2023.
In the event federal executive or legislative initiatives result in increased federal lease costs or requirements, restrictions or prohibitions that apply to our areas of operations, our customers may incur increased 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. Any adverse impact on our customers’ activities could have a corresponding negative impact on our throughput volumes. In addition, certain administrative rules and legislative proposals specifically target existing law and direct future federal rulemaking activity that 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.
State agency rulemakings in New Mexico could increase our operational costs, and potentially impact new oil and gas development activity by our producer customers.
On January 29, 2019, the New Mexico governor issued an executive order establishing an interagency Climate Change Task Force and directing the Energy, Minerals and Natural Resources Department (“EMNRD”) and the New Mexico Environment Department (“NMED”) to develop a statewide, enforceable regulatory framework to reduce methane emissions from new and existing sources in the oil and gas sector. Following a year-long stakeholder process by both agencies, the Oil Conservation Division ("OCD") adopted the EMNRD rules in mid-2021, which institute gas capture requirements for both upstream and midstream operators, prohibit routine flaring, and require operation plans for operators of gas gathering systems.
In 2022, NMED adopted an Ozone Precursor rule to regulate and control ozone precursor pollutants, including volatile organic compounds (“VOCs”) and nitrogen oxides (“NOx”), from the oil and gas industry, which will also control or reduce methane emissions. The rule establishes emission standards and emission reduction requirements for various equipment and processes as well as leak detection and repair requirements. The EMNRD rules impose additional operational requirements and costs, and potential regulatory compliance and enforcement risk, on our facilities and operations. The NMED rule will impose additional operational costs and potential regulatory compliance and enforcement risks. Similarly, our customers are expected to incur compliance costs of their own under these rules and may, if out of compliance, experience delays or curtailment in the pursuit of their exploration, development, or production activities. Any adverse impact on our customers’ activities could have a corresponding negative impact on our throughput volumes. Accordingly, such restrictions or prohibitions could have an adverse effect on our business, prospects, results of operations, financial condition, cash flows and ability to make distributions to our unitholders.
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. Those measures could include heightened permitting requirements for upstream operations that impact the location, timing, and scope of new development activity, and may include additional drilling and operational restrictions in order to address environmental justice concerns, minimize impacts to disproportionately impacted communities, and possibly to contend with elevated ground-level ozone days. Local governments may exercise their land use authority and police powers to impose additional development restrictions and ongoing regulation of odor, traffic, noise and other community impacts. In Colorado, private organizations have sponsored and may in the future sponsor 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.
Laws and corresponding rulemakings in Colorado could have a material adverse impact on new oil and gas development in the state and could reduce the demand for our services in the state.
On April 16, 2019, Governor Polis signed into law Senate Bill 19-181 (“SB-181”), which amended existing laws and enacted new laws concerning the conduct of oil and gas operations in Colorado. The bill changed the mandate of the Colorado Oil and Gas Conservation Commission (the “COGCC”) to regulate oil and gas development in a manner that protects the public health, safety, welfare, and the environment and wildlife, from the previous mandate to foster the development and production of oil and gas. Other key elements of SB-181 include granting local governments ability to regulate facility siting and surface impacts of oil and gas operations as well as the ability to inspect and impose fines for leaks, spills, and emissions, and requiring the Colorado Department of Public Health and Environment (the “CDPHE”) to adopt additional rules that call for the minimization and continual monitoring of emissions at oil and gas facilities. SB-181 also requires the COGCC to conduct rulemakings concerning the cumulative impacts of oil and gas development, additional flowline regulations, as well as other matters.
The COGCC completed the most significant rulemaking to implement SB-181 in late 2020, with the final SB-181 rulemaking concerning financial assurance having been completed in early 2022. These rules are focused on upstream oil and gas development, and as a whole touch on nearly every aspect of oil and gas development activity. Due to the scope and complexity of the rules, the COGCC has issued guidance materials that will be central to achieving successful rule implementation. Although our customers have expressed confidence in their ability to conform to the rules and move forward with predictable development plans, the number of drilling permits issued by the COGCC slowed considerably in 2021 as staff began reviewing permit applications in accordance with the new rules. We expect the approval of well permit applications to improve as operators and COGCC staff both gain experience with the new regulatory regime, and because our customers are increasingly focused on permitting comprehensive area plans that will allow for the approval of a larger number of wells as part of larger long-term development plans.
While much of our oil and gas infrastructure in Colorado is not located near populous areas, the population in Colorado continues to grow, which may result in populated areas coming closer to existing and proposed oil and gas development. Notably, Weld County has exercised the authority granted under SB-181 to enact its own local siting and permitting regulatory framework, in a manner that is intended to and has allowed for continued oil and gas development in the jurisdiction where the majority of our assets are located. However, local regulations enacted under SB-181 do not supplant the COGCC’s authority over well permitting and approval, and thus even in Weld County our customers may experience additional costs or delays associated with obtaining those state permits. Any such impact on new oil and gas development, would, as production from existing and previously permitted wells depletes, lead to a reduction in demand for our gathering, processing, and transportation services in the state, which reduction, over time, may be material.
In addition, in 2019 the Colorado legislature enacted HB19-1261 establishing statewide greenhouse gas emission reduction goals and included agency authorities and mandates to promulgate regulations to achieve greenhouse gas reduction goals. In January 2021, Governor Polis issued the “Greenhouse Gas Pollution Reduction Roadmap,” which describes state actions and the regulatory pathway to achieve the HB19-1261 greenhouse gas reduction goals. The Greenhouse Gas Reduction Roadmap specifies, among other things, intended reductions by economic sector, including the oil and gas sector as well as the “residential, commercial and industrial” sector that includes emissions from the combustion of fuels.
In 2021, the governor signed HB21-1266 into law, which required the adoption of rules to reduce greenhouse gas (“GHG”) emissions from “oil and gas exploration, production, processing, transmission, and storage operations” by at least 36% by 2025 and 60% by 2030 below a 2005 baseline. These regulatory actions have been and will be pursued by various state agencies, including the Colorado Energy Office and the Colorado Air Quality Control Commission (“AQCC”). In December 2021, the AQCC adopted regulations to reduce GHGs from the oil and gas sector through myriad requirements to address emissions and control requirements, including emissions reduction requirements for production well sites, and capture requirements for pigging activities and capture and control requirements for equipment blowdowns. The AQCC also adopted requirements for a Steering Committee to assess methods and feasibility to reduce GHG emissions from industrial combustion of hydrocarbon fuels, specifically including oil and gas sector compression equipment to gather and transport natural gas, ultimately resulting in plans and regulations for oil and gas sector industrial combustion equipment to achieve the HB21-1266 reduction goals. These regulations collectively are anticipated to impose near- and longer-term obligations and costs on our producer customers as well as on our own midstream equipment and facilities. These rulemaking proceedings to reduce greenhouse gas emissions could increase costs on or inhibit or adversely influence the ability of our producer customers to develop and operate production wells. These rulemaking proceedings could increase costs for us to operate our compressor stations or gas plants in the state, and they could affect the types of equipment or the manner in which we operate our midstream equipment. These rulemaking proceedings, or future related rulemaking proceedings, have the potential to result in some manner of greenhouse gas emissions caps in the state, or greenhouse gas sector-specific performance standards, either of which could result in increased costs on our producer customers or increased costs on us to operate our facilities, and could affect the types of equipment that we operate or the manner in which it is operated. These rulemaking proceedings have the potential to affect the operations and production of our customers, which can in turn affect our operations, and they also have the potential to affect our costs and facility operations, either of which could affect our financial results or have such an effect on our operations.
The official title of HB21-1266 is the Environmental Justice Act and the legislation also created the Environmental Justice Action Task Force, a 22-member body charged with recommending and promoting strategies for incorporating environmental justice and equity into how state agencies discharge their responsibilities. The Task Force completed its duties with the issuance of a final report on November 14, 2022, which presented to the governor and the general assembly a set of seven recommendations including topics such as environmental justice coordination, agency consideration of cumulative impacts, data collection, and best practices for community engagement. While none of the recommendations are binding, they do represent the basis for which future legislation and agency rulemakings could impose additional legal requirements that impact our ability or that of our producer customers to obtain necessary permits, construct and expand our assets, and operate our facilities.
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: (i) the federal Clean Air Act and comparable state laws and regulations, including federal and state air permits, that impose obligations related to air emissions; (ii) RCRA, and comparable state laws that impose requirements for the management, storage and disposal of solid and hazardous waste from our facilities; (iii) CERCLA, 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; (iv) the Clean Water Act and the Oil Pollution Act, and comparable state laws and regulations 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 (v) state laws that impose requirements on the response to and remediation of hydrocarbon releases to soil or groundwater 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 , the imposition of remedial requirements, and the issuance of orders or affecting current or future operations. Certain environmental laws and 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 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 there can be no assurance that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated 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 disgorgement of profits. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose penalties of up to $1.5 million per day for each violation and possible criminal penalties of up to $1.5 million per violation and five years in prison. Under the NGPA, FERC may impose civil penalties of up to $1.5 million for any one violation and may impose criminal penalties of up to $1.5 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 change, which may give producers a basis to 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 $1.5 million per day for each violation and possible criminal penalties of up to $1.5 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 FERC’s revised income tax allowance policy for partnership pipelines and the federal law reducing the corporate income tax rate.
Effective January 1, 2018, the federal corporate tax rate was reduced to 21%, and in March 2018, FERC issued a revised policy statement disallowing an income tax allowance in the cost-of-service rates for partnership-owned pipelines. Previously, FERC’s policy generally permitted partnership pipelines to recover an income tax allowance in a cost-of-service proceeding before FERC if the pipeline’s ultimate owners had income tax liability. The maximum cost-based rates for our interstate natural gas pipelines and intrastate pipelines that provide interstate transportation services could be adversely affected in future rate proceedings as a result of the change in policy and law. For interstate oil and NGL pipelines, FERC considered the impacts of the tax policy and law changes on an industry-wide basis during the 2020 calendar year through its indexing methodology review. Additionally, any new cost-based rates for our pipelines regulated by the FERC will be affected by the new policy and tax law.
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.
EPA had promulgated enhanced New Source Performance Standards (“NSPS”) regulations for the oil and gas sector to control volatile organic compounds (“VOCs”) in 2012, and an NSPS for VOCs and methane in the oil and gas sector in 2016. The regulations, contained in 40 CFR Part 60, Subpart OOOO and OOOOa, among other things, require control of VOC and methane emissions from subject sources through ensuring adequate design, requiring installation of emission controls, and institution of leak detection and repair programs. EPA’s 2016 regulatory action imposed leak detection and repair requirements for VOCs and methane on producer well site equipment and on midstream equipment such as compressor and booster stations, imposed additional emission reduction requirements on specific pieces of oil and gas equipment, and was a regulatory pre-condition to the EPA acting to regulate existing oil and gas methane sources in the future under Section 111(d) of the Clean Air Act. In November 2021, EPA proposed revisions of the federal NSPS for oil and gas sector sources that regulate emissions of VOCs and methane. EPA’s November 2021 proposed regulations would expand the scope and breadth of the existing regulations, including: 1) the extension of emission control and reduction requirements under this part of the Clean Air Act to existing oil and gas sources, which is a first; and 2) expansion and tightening of the existing emission reduction requirements for new or modified oil and gas sources adopted in 2012 and 2016. In December 2022, EPA issued a supplemental proposal to update, , and expand the 2021 proposed rules. EPA is expected to finalize the rule in 2023.
States’ efforts to comply with the National Ambient Air Quality Standard (“NAAQS”) for ozone, which is set by the EPA, also may have an impact on our operations. States or areas of a state that are not in attainment with the ozone NAAQS are required to approve implementation plans that reduce emissions of ozone precursors in order to achieve compliance with the NAAQS, which plans can impose emissions control requirements and associated costs on us or on our customers. The EPA revised and lowered the ozone NAAQS from 75 to 70 parts per billion in 2015, and on December 31, 2020, the EPA issued a final rule retaining the 2015 standard. In late 2021, the EPA communicated that it would reconsider the 2020 decision to retain the ozone NAAQS with the intention of completing the reconsideration by the end of 2023. If the ozone NAAQS is lowered, it may result in additional actions by states requiring further emission controls and associated costs. States are required to evaluate compliance with 70 parts per billion standard and, if not met, to adopt implementation plans to reduce emissions of ozone-forming pollutants, like VOCs and nitrogen oxides (“NOx”), 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 and complex to site and permit major new or modified facilities) and additional emissions control requirements. In
October 2016, the EPA also finalized Control Techniques Guidelines (“CTGs”) for VOC emissions from existing oil and natural gas equipment and processes in moderate ozone non-attainment areas. These CTGs 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 Colorado, including Weld County, EPA has classified the Denver Metro/North Front Range as “severe” nonattainment for the 2008 ozone standard and “marginal” nonattainment for the 2015/2020 ozone standard. Effective November 7, 2022, Colorado’s front range was reclassified from a “serious” to a “severe” nonattainment area for the 2008 8-hour ozone standard. The nonattainment status of this area has resulted in reduction of the major source threshold and adoptions of regulations designed to reduce ozone precursor emissions, including regulations adopting provisions of the CTGs and other regulations focused on reducing VOC and NOx emissions from the oil and gas industry. In December 2022, the AQCC approved revisions to the State’s Implementation Plan to reduce emissions of VOCs and NOx to come into compliance with the ozone standards. Additional rulemakings from the Colorado Air Quality Control Commission are expected in the future to reduce emissions of VOCs and NOx from the oil and gas sector as part of the State’s Implementation Plan to come into compliance with the ozone standards.
In New Mexico in 2022, the NMED adopted an Ozone Precursor rule with the intention of preventing the state from falling into non-attainment with the ozone NAAQS by controlling ozone precursor pollutants, VOCs and NOx, from the oil and gas industry, which will also control or reduce methane emissions. The rule establishes emission standards and emission reduction requirements for various equipment and processes as well as leak detection and repair requirements. We anticipate that the rule will impose additional operational costs and potential regulatory compliance and enforcement risks.
States can initiate and promulgate regulations affecting oil and gas operations and associated emissions, either as a matter of their own statutory authority and programs or when implementing federal programs, such as the federal ozone ambient air quality standard or the federal Regional Haze regulation. Judicial challenges to new regulatory measures can occur, and we cannot predict the outcome of such challenges. New regulatory suspensions, revisions, or rescissions, as well as new regulations, and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. Collectively, implementation of more stringent regulations 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. These regulations could also affect the permitting of, or the emissions control requirements in permits for our customers’ facilities and equipment, or our facilities and equipment. 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 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 have or may consider legislation or regulations 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. At the United Nations Climate Change Conference in Glasgow (COP26) in 2021, the United States and the European Union announced the Global Methane Pledge that aims to limit methane emissions by 30% compared with 2020 levels. More recently, at the United Nations Climate Change Conference in Egypt (COP27) in 2022, the Biden Administration announced new initiatives to tackle climate change.
At the federal level, 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 August 2022, President Biden signed the reconciliation budget bill, known as the Inflation Reduction Act of 2022 (“IRA”), which, among other things, includes a new “waste emission charge” imposed for methane emissions for oil and gas production and onshore pipelines, storage, gathering, and boosting for facilities that emit more than 25,000 metric tons of carbon dioxide annually beginning in 2025. In 2011, EPA proposed greenhouse gas permitting requirements for 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, although that rule was challenged. Following from that challenge, in 2016 the EPA proposed PSD and Title V permitting regulations that
would address control of GHG emissions if certain thresholds are met. While EPA has not finalized the rule, states such as Colorado have adopted similar requirements. Separately, in 2011 EPA issued rules requiring reporting of greenhouse gases, on an annual basis, for certain onshore natural gas and oil production facilities, and in October 2015, EPA amended and expanded those greenhouse gas reporting requirements to all segments of the oil and gas industry effective January 1, 2016. In June 2013, President Obama announced a climate action plan that targeted methane emissions from the oil and gas industry as part of a comprehensive interagency methane reduction strategy, and in June 2016, the EPA expanded the NSPS regulations for new or modified oil and gas sources of VOCs to include methane emissions, which, among other things, 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, imposes additional emission reduction requirements on specific pieces of oil and gas equipment, and is a regulatory pre-condition to the EPA acting to regulate existing oil and gas methane sources in the future under Section 111(d) of the Clean Air Act. In November 2021, EPA proposed revisions to the federal NSPS for oil and gas sector sources that regulate emissions of VOCs and methane. EPA’s November 2021 proposed regulations would expand the scope and breadth of the existing regulations, including: 1) the extension of emission control and reduction requirements under this part of the Clean Air Act to existing oil and gas sources, which is a first; and 2) expansion and of the existing emission reduction requirements for new or modified oil and gas sources adopted in 2012 and 2016. In December 2022, EPA issued a supplemental proposal to update, , and expand the 2021 proposed rules. EPA is expected to finalize the rule in 2023.
Similarly, some states can initiate and promulgate regulations affecting oil and gas operations and associated greenhouse gas emissions as a matter of their own statutory authority and programs. For example, in 2019, the Colorado legislature passed House Bill 19-1261, the “Climate Action Plan to Reduce Pollution” that sets greenhouse gas emission reduction targets for the state, and included agency authorities and mandates to promulgate regulations to achieve greenhouse gas reduction goals. In January 2021 the governor issued the “Greenhouse Gas Pollution Reduction Roadmap,” which describes state actions and the regulatory pathway to achieve the HB19-1261 greenhouse gas reduction goals. The Greenhouse Gas Reduction Roadmap specifies, among other things, intended reductions by economic sector, including the oil and gas sector as well as the “residential, commercial and industrial” sector that includes emissions from the combustion of fuels. In 2021, Governor Polis signed HB21-1266 into law, which includes environmental justice provisions and requirements for adoption of rules for reduction of greenhouse gas (“GHG”) emissions from “oil and gas exploration, production, processing, transmission, and storage operations” by at least 36% by 2025 and 60% by 2030 below a 2005 baseline. These administrative and regulatory actions have been and will be pursued by various state agencies, including the Colorado Energy Office and the Colorado Air Quality Control Commission (“AQCC”). In December 2021, the AQCC adopted regulations to reduce GHGs from the oil and gas sector through myriad requirements to address emissions and control requirements, including emissions reduction requirements for production well sites, and capture requirements for pigging activities and capture and control requirements for equipment blowdowns. The AQCC also adopted requirements for a Steering Committee to assess methods and feasibility to reduce GHG emissions from industrial combustion of hydrocarbon fuels, specifically including oil and gas sector compression equipment to gather and transport natural gas, ultimately resulting in plans and regulations for oil and gas sector industrial combustion equipment to the HB21-1266 reduction goals.
New regulations, as well as new regulatory suspensions, revisions, or rescissions, and conflicting state and federal regulatory mandates may inhibit our ability to accurately forecast the costs associated with future regulatory compliance. 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) design, permit and construct 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 and natural gas liquids 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, hydraulic fracturing is excluded from regulation except where 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. Over the past several years, 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. States can propose or promulgate regulations or enact initiatives or legislation imposing conditions or restrictions on hydraulic fracturing practices or oil and gas well development using hydraulic fracturing or horizontal drilling techniques. 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. 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. 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.
President Biden has taken action to roll back many of the policies and regulations that the Trump administration had put in place to ease burdens on the development or use of domestically produced energy resources. President Biden issued Executive Order 13990 on January 20, 2021, directing executive departments and agencies to review all existing regulations, orders, guidance documents, policies and any other similar action taken during the Trump administration that are inconsistent with President Biden’s plan to elevate climate issues and, as appropriate, suspend, revise, or rescind those that are inconsistent with that plan. Our customers will continue to be subject to uncertainty associated with new regulatory measures as well as 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 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 because there are numerous uncertainties inherent in estimating quantities of future production. As a result, these facilities may not be to attract enough throughput to our expected investment return, which could affect our results of operations and financial condition. The construction of new systems or additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing these facilities. We may be to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other expansion . The construction of new systems or additions to our existing gathering and transportation assets may also require us to obtain various regulatory approvals. For example, under the NGA and the National Environmental Policy Act of 1969, FERC has broad authority to approve the construction of new interstate natural gas pipeline facilities, including imposing environmental conditions on certificates of public convenience and necessity. New pipeline infrastructure projects could face increased and regulatory reviews by federal, state and/or environmental regulators due to an increased focus on climate change policies and the fossil fuel industry. While we do not currently have projects pending that are subject to material risk, any governmental or regulatory actions that place additional and/or costs on future projects, could impact our ability to develop new infrastructure. The construction of new systems or additions to our existing gathering and transportation assets may require us to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas and NGLs. If such third-party facilities are not constructed or operational at the time that the addition to our facilities is completed, we may experience effects on our results of operations and financial condition. The construction of additional systems may require 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 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.
Our increasing dependence on digital technology puts us at risk for a cyber incident that could result in information theft, data corruption, operational disruption or financial loss.
We are increasingly reliant on digital technology to run our business and operate our assets. Our DCP 2.0 digital transformation includes a focus on increasing the use of digital technology in all aspects of our business. We use digital technology to conduct certain of our plant operations, to monitor pipelines, compressors, pumps, meters, and other operating assets, to record financial and operating data, and to maintain various information databases relating our business. Our service providers are also increasingly reliant on digital technology. Our and their reliance on this technology increasingly puts us at risk for technology system failures, telecommunication, data, and network disruptions, and cyberattacks and other breaches in cybersecurity, which could significantly impair our ability to conduct our business. Any such events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability. As these cyber-risks continue to evolve and our dependence on digital technology grows, we may be required to expend significant additional resources to continue to modify or enhance our protective measures and remediate cyber .
Our business could be negatively impacted by security threats, including cybersecurity threats, terrorist attacks, the threat of terrorist attacks and related disruptions.
We face a variety of security threats, including 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 or cyber incidents 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.
Risk Related to Our Indebtedness
A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.
A downgrade of our credit rating could 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 to 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 debt agreements may limit our ability to make distributions to unitholders and may limit our ability to capitalize on acquisitions and other business opportunities.
Our debt agreements contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates. Furthermore, our Credit Agreement contains covenants requiring us to maintain a certain leverage ratio and meet certain other tests. Any subsequent replacement of our debt agreements or any new indebtedness could have similar or greater restrictions. If our covenants are not met, whether as a result of reduced production levels of natural gas and NGLs as described above or otherwise, our financial condition, results of operations and ability to make distributions to our unitholders could be materially adversely affected.
Changes in interest rates may adversely impact our ability to issue additional equity or incur debt, as well as the ability of exploration and production companies to finance new drilling programs around our systems.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could impair our ability to issue additional equity or incur debt to make acquisitions, and 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.
It is unclear how the discontinuation of LIBOR and transition to SOFR may affect our financing costs in the future.
Our existing two series of preferred limited partner units (our “Preferred LP Units”) are scheduled by their terms to convert from fixed percentage distributions to distributions that accumulate an annual floating rate of the three-month London Interbank Offered Rate, or LIBOR plus a spread of 4.919% (Series B scheduled to start in June 2023) (the “Contractual Series B Floating Rate”) and 4.882% (Series C scheduled to start in October 2023) (the “Contractual Series C Floating Rate”), respectively. In May 2023, our 5.85% Fixed-to-Floating Rate Junior Subordinated Notes due 2043 (our “Subordinated Notes”) are scheduled by their terms to convert from a fixed percentage of interest to interest based on an annual floating rate of the three-month LIBOR plus a spread of 3.85% (the “Contractual Subordinated Notes Floating Rate”). On December 31, 2021, however, ICE Benchmark Administration Limited (the “IBA”), the administrator for LIBOR, permanently ceased publishing LIBOR with respect to one-week and two-month U.S. dollar LIBOR tenors, and will permanently cease publishing LIBOR with respect to all other U.S. dollar LIBOR tenors (overnight, one-month, three-month, six-month and 12-month U.S. dollar LIBOR tenors) on June 30, 2023. The phase out of LIBOR may create market disruptions or volatility, and the consequences of these market developments cannot be entirely predicted and a transition from LIBOR, could increase the cost of our variable rate indebtedness. The terms applicable to our Preferred LP Units and our Subordinated Notes do not contain any contractual fallback provision that would replace references to LIBOR (including the Contractual Series B Floating Rate, the Contractual Series C Floating Rate and the Contractual Subordinated Notes Floating Rate) with an alternative benchmark in the event that a given LIBOR rate publication, is or is found no longer to be representative.
On March 15, 2022, President Biden signed into law the federal Adjustable Interest Rate (LIBOR) Act (the “LIBOR Act”), and the Board of Governors of the Federal Reserve System (the “Board of Governors”) has promulgated its Regulation ZZ as a final rule to implement the LIBOR Act (“Regulation ZZ”). The LIBOR Act and Regulation ZZ provide a fallback mechanism on a nationwide basis to replace U.S. dollar LIBOR with a benchmark rate for certain so-called “tough legacy
contracts” (including the terms applicable to the Preferred LP Units and the Subordinated Notes) that reference the overnight and one-, three-, six- and 12-month tenors of U.S. dollar LIBOR but that contain no or insufficient fallback provisions for a replacement benchmark rate. Pursuant to the LIBOR Act and Regulation ZZ, effective on the first London banking day after June 30, 2023 (unless the Board of Governors determines that the applicable U.S. dollar LIBOR tenor will cease to be published or cease to be representative on a different date) (in either case, the “LIBOR Replacement Date”) and continuing at all times thereafter, the Series B Preferred LP Units will accumulate distributions at an annual floating rate equal to the sum of the CME Term SOFR Reference Rate published for a three-month tenor as administered by CME Group Benchmark Administration, Ltd. (or any successor administrator thereof) (“3-Month CME Term SOFR”) plus a tenor spread adjustment of 0.26161% (the 3-Month CME Term SOFR plus such tenor spread adjustment is the “Adjusted 3-Month CME Term SOFR”) plus 4.919%, in lieu of the Contractual Series B Floating Rate. Effective on the Series C Conversion Date and continuing at all times thereafter, the Series C Preferred LP Units will accumulate distributions at an annual floating rate equal to the sum of the Adjusted 3-Month CME Term SOFR plus 4.882%, in lieu of the Contractual Series C Floating Rate. on the LIBOR Replacement Date and continuing at all times thereafter, the Subordinated Notes will bear interest at an annual rate equal to the sum of the Adjusted 3-Month CME Term SOFR plus 3.85%, in lieu of the Contractual Subordinated Notes Floating Rate. The phase out of LIBOR and the transition to Adjusted 3-Month CME Term SOFR as a benchmark may create market or , and the consequences of these market developments cannot be entirely predicted and could increase the cost of our variable rate indebtedness and the accrual of distributions on our Preferred LP Units. Moreover, because the change in the benchmark rates for our Preferred LP Units and Subordinated Notes is mandated by the LIBOR Act and Regulation ZZ rather than set forth in the terms of our Preferred LP Units and Subordinated Notes, such rates may be subject to future changes by act of Congress or rulemaking by the Board of Governors.
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 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 3.875% Senior Notes due 2023, 5.375% Senior Notes due 2025, 5.625% Senior Notes due 2027, 5.125% Senior Notes due 2029, 8.125% Senior Notes due 2030, 3.25% Senior Notes due 2032, 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 of the of such creditors, there may be little or no amounts left available to make payments in respect of our notes. As of December 31, 2022, DCP Operating’s subsidiaries had no debt for borrowed money owing to any unaffiliated third parties, other than the amounts borrowed under the Securitization Facility. 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, with the exception of our Securitization Facility. Although our debt agreements place 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, 2022, our consolidated principal indebtedness was $4,865 million. Our significant indebtedness and any additional debt we may incur in the future 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 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.
Risks Inherent in an Investment in Our Common Units
Conflicts of interest may exist between our individual unitholders and Phillips 66, which has the authority to conduct, direct and manage the activities of DCP Midstream, LLC associated with the Partnership and our general partner.
DCP Midstream, LLC owns and controls our general partner, which has the sole responsibility for conducting our business and managing our operations. Phillips 66, through its wholly owned subsidiary, has the power to conduct, direct and manage all activities of DCP Midstream, LLC associated with the Partnership and its subsidiaries and our general partner, including the power to exercise DCP Midstream, LLC's rights to appoint or remove any director on the board of directors of our general partner. Some of our general partner’s directors are executive officers of Phillips 66. Therefore, conflicts of interest may arise between Phillips 66 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:
• neither our Partnership Agreement nor any other agreement requires Phillips 66 to pursue a business strategy that favors us. Phillips 66’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stakeholders of Phillips 66, which may be contrary to our interests;
• our general partner is allowed to take into account the interests of parties other than us, such as DCP Midstream, LLC and its affiliates, including Phillips 66, in resolving conflicts of interest;
• DCP Midstream, LLC and its affiliates, including Phillips 66, 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;
• 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 sustaining 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.
DCP Midstream, LLC and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.
Neither our Partnership Agreement nor the Services Agreement between us and DCP Midstream, LLC prohibits DCP Midstream, LLC and its affiliates, including Phillips 66, 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, 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. Phillips 66 is a large, established participant in the midstream energy business, and has significantly greater resources than we have, which factors may make it more difficult for us to compete with Phillips 66 with respect to commercial activities as well as for acquisition candidates. As a result, competition from Phillips 66 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, including Phillips 66, 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 units (other than our general partner and its affiliates).
Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owner, DCP Midstream, LLC. Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our Partnership Agreement permits our general partner to make a number of decisions either in its individual capacity, as opposed to in its capacity as our general partner or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:
• 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 unit, a 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 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:
• 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 or, in the case of a matter, acted with knowledge that the conduct was .
Holders of our 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 members of the board of directors of our general partner are chosen by the owner of our general partner. As a result of these limitations, the price at which the units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our units may experience price volatility.
Our unit price has experienced volatility in the past, and volatility in the price of our 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 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 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, 2022, our general partner and its affiliates owned approximately 57% 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 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:
• 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 Preferred Units are in arrears.
The holders of our 7.875% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”) and our 7.95% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (“Series C Preferred Units and together with the Series B Preferred Units, the “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 Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions to our 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 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 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.
Risks Inherent in an Investment in Our Preferred Units
Our 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 Preferred Units, and by other transactions.
The 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 Preferred Units. The issuance of additional units on parity with or senior to the Preferred Units (including additional Preferred Units) would dilute the interests of the holders of the 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 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 Preferred Units, which may limit the cash available to make distributions on the 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 in Note 17 of the Notes to Consolidated Financial Statements in Item 8. "Financial Statements and Supplementary Data.". 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 Preferred Units.
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.
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%, 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 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.
Public Law 115-97, known as the Tax Cuts and Jobs Act enacted on December 22, 2017 (the "Tax Cuts and Jobs Act") provides a deduction under Code Section 199A 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
law 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.
Changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.
If 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 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 changed. Unless we are eligible to (and choose to) elect to issue statements similar to 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.
Our unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% (or 50% for 2020, as amended by the Coronavirus Aid, Relief and Economic Security Act on March 27, 2020) of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion that is not required to be capitalized as part of cost of goods sold.
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. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) may be required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business or vice versa.
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 (or the transferee's broker, if applicable) is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Recent final Treasury regulations provide for the application of this withholding rule to open market transfers of interests in publicly traded partnerships beginning on January 1, 2023. Under these regulations, the “amount realized” for purposes of this withholding is the gross proceeds paid or credited upon the transfer.
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.
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 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. 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, 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 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 Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of Preferred Units than the holders of our common units.
The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of our Preferred Units as partners for tax purposes and will treat distributions on our Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of our Preferred Units as ordinary income and will not be eligible for the deduction provided for under Code Section 199A. Although a holder of our 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 associated with the Preferred Units. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payments attributable to the period beginning December 15 and ending December 31 will accrue as income to the holder of record of a Preferred Unit on December 31 for such period, regardless of whether such holder continues to own the Preferred Units at the time the actual distribution is made. Otherwise, the holders of our 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 Preferred Units with the benefit of the liquidation preference. We will not allocate any share of our nonrecourse liabilities to the holders of our Preferred Units. If our Preferred Units were treated as indebtedness for tax purposes, rather than as partnership interests, distributions on our Preferred Units likely would be treated as payments of interest by us to the holders of our Preferred Units, rather than as guaranteed payments for the use of capital.
A holder of our Preferred Units will be required to recognize gain or loss on a sale of its Preferred Units equal to the difference between the amount realized by such holder and tax basis in the 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 Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of 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 Preferred Unit to acquire such Preferred Unit. Gain or loss recognized by a holder of a Preferred Unit on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of our Preferred Units will generally not be 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.
General Risk Factors
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 amended and restated Partnership Agreement (the “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 financial covenants contained in the Credit Agreement.
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.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
For details on our plants, fractionation and storage facilities 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 6900 E. Layton Avenue, Suite 900, Denver, Colorado 80237, our telephone number is 303-595-3331 and our website address is www.dcpmidstream.com .
Item 3. Legal Proceedings
See Item 8 - Financial Statements - Notes to Consolidated Financial Statements - Note 22 in Part II of this Form 10-K for information about legal proceedings. For the disclosure of environmental proceedings with a governmental entity as a party pursuant to Item 103(c)(3)(iii) of Regulation S-K, the Company has elected to disclose matters where the Company reasonably believes such proceeding would result in monetary sanctions, exclusive of interest costs, of $1.0 million or more.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market for Registrant’s Common Units, Related Unitholder Matters and Issuer Purchases of Common Units
Market Information
Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “DCP”. As of February 10, 2023, there were approximately 31 unitholders of record of our common units. This number does not include unitholders whose common units are held in trust by other entities.
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. [Reserved]
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. This section of this Annual Report on Form 10-K generally discusses performance during the fiscal years ended December 31, 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 performance and year-to-year comparisons between 2021 and 2020 are not included in this Annual Report on Form 10-K, but rather can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2021.
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) Logistics and Marketing and (ii) Gathering and Processing. Our Logistics and Marketing segment includes transporting, trading, marketing and storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, and processing natural gas, producing and fractionating NGLs, and recovering condensate.
Realignment Transaction
On August 17, 2022, in connection with the closing of the Realignment Transaction between Phillips 66 and Enbridge, PGC, an indirect wholly owned subsidiary of Phillips 66, and Spectra DEFS Holding, LLC, an indirect wholly owned subsidiary of Enbridge, as the members of DCP Midstream, LLC, entered into the Third A&R LLC Agreement, which, among other things, designated PGC as the Class A Managing Member of DCP Midstream, LLC with the power to conduct, direct and manage all activities of DCP Midstream, LLC associated with the Partnership and each of its subsidiaries, GP LP and our General Partner, and, in each case, the businesses, activities and liabilities thereof. The Third A&R LLC Agreement also provided PGC with the power to exercise DCP Midstream, LLC’s rights to appoint or remove any director on the board of directors of our General Partner and vote the common units representing limited partner interests in the Partnership that are owned directly or indirectly by DCP Midstream, LLC.
Following the completion of the Realignment Transaction, we began to integrate certain of our operations with Phillips 66’s midstream segment, including the integration of operational services that are currently, or were previously, provided by DCP Services, LLC. As part of these integration efforts, continuing employees will transfer employment to a Phillips 66 subsidiary, which we expect to occur beginning in the second quarter of 2023, and general and administrative services will be provided by Phillips 66 or one or more of its subsidiaries going forward. We expect such integration efforts to continue regardless of the outcome of the pending Merger with Phillips 66 described below.
Pending Merger with Phillips 66
On August 17, 2022, the board of directors of our General Partner received a non-binding proposal from Phillips 66 to acquire all of the Partnership’s issued and outstanding publicly-held common units not already owned by DCP Midstream, LLC or its subsidiaries at a value of $34.75 per common unit (the “Proposal”). The board of directors of our General Partner appointed the special committee to review, evaluate and negotiate the Proposal.
On January 5, 2023, we entered into the Merger Agreement with Phillips 66, PDI, Merger Sub, GP LP and our General Partner, pursuant to which, at the effective time of the Merger, each common unit representing a limited partner interest in the Partnership (other than the common units owned by DCP Midstream, LLC and GP LP) will be converted into the right to receive $41.75 per common unit in cash, without interest. GP LP has agreed to declare, and cause the Partnership to pay, a cash distribution in respect of the common units in an amount equal to $0.43 per common unit for each completed quarter ending on or after December 31, 2022 and prior to the effective time of the Merger.
The Merger Agreement and the transactions contemplated thereby, including the Merger, were unanimously approved on behalf of the Partnership by the special committee and the board of directors of the General Partner, which is the general partner of GP LP. The special committee, which is comprised of independent members of the board of directors of our general partner, retained independent legal and financial advisors to assist it in evaluating and negotiating the Merger Agreement and the Merger.
The Merger is expected to close in the second quarter of 2023, subject to customary closing conditions. There can be no assurance that the Merger will be consummated on the terms described above or at all.
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 significant portion of commodity price risk on an overall Partnership basis through our fee-based assets and by executing on our hedging program. 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. Commodity prices were volatile during 2022 and are subject to global energy supply and demand fundamentals as well as geopolitical disruptions. Drilling activity levels vary by geographic area and we will continue to target our strategy in geographic areas where we expect producer drilling activity.
Our long-term view is that commodity prices will be at levels that we believe will support sustained or increasing levels of domestic production. Our business is predominantly fee-based and we have a diversified portfolio to balance the upside of our earnings potential while reducing our commodity exposure. In addition, we use our strategic hedging program to further mitigate commodity price exposure. We expect future commodity prices will be influenced by tariffs and other global economic conditions, the level of North American production and drilling activity by exploration and production companies, the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil, and the severity of winter and summer weather.
We expect to be a proactive participant in the transition to a lower carbon energy future through increased efficiency and modernization of existing operations, which we expect will reduce the greenhouse gas emissions from our base business. Going forward, we expect that our assets will be managed in a manner consistent with the emissions goals of Phillips 66.
Our business is primarily driven by the level of production of natural gas by producers and of NGLs from processing plants connected to our pipelines and fractionators. These volumes can be impacted negatively by, among other things, reduced drilling activity, depressed commodity prices, severe weather disruptions, operational outages and ethane rejection. Upstream producers response to changes in commodity prices and demand remain uncertain.
We have historically hedged commodity prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing segment.
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, 5 have investment grade credit ratings. During February 2021, Winter Storm Uri resulted in lower volumes and abnormally high gas prices in certain regions. Certain counterparty billings during this time remain under dispute and are taking longer to collect than normal.
The global economic outlook continues to be a cause for concern for U.S. financial markets and businesses and investors alike. This uncertainty may contribute to volatility in financial and commodity markets.
We believe we are positioned to withstand future commodity price volatility as a result of the following:
• Our 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 multi-year 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 including excess distribution coverage and divestitures.
During 2023, our strategic objectives are to generate Excess Free Cash Flows (a non-GAAP measure defined in “Reconciliation of Non-GAAP Measures - Excess Free Cash Flows”) and reduce leverage. We believe the key elements to generating Excess Free 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 Excess Free Cash Flows. We will continue to pursue incremental revenue, cost efficiencies and operating improvements of our assets through process and technology improvements.
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 2023 plan includes sustaining capital expenditures of approximately $150 million and expansion capital expenditures of approximately $125 million.
Recent Events
Series A Preferred Units Redemption
On December 15, 2022 we paid $500 million to redeem in full the outstanding Series A Preferred Units at a redemption price of $1,000 per unit using cash as well as borrowings under our Securitization Facility. The difference between the redemption price of the Series A Preferred Units and the carrying value on the balance sheet resulted in an approximately $13 million reduction to Net income allocable to limited partners. The carrying value represented the original issuance proceeds, net of underwriting fees and offering costs for the Series A Preferred Units.
Common and Preferred Distributions
On January 24, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.43 per common unit. The distribution was paid on February 14, 2023 to unitholders of record on February 3, 2023.
Also on January 24, 2023, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and $0.4969 per unit, respectively. The Series B distribution will be paid on March 15, 2023 to unitholders of record on March 1, 2023. The Series C distribution will be paid on April 17, 2023 to unitholders of record on April 3, 2023.
Factors That May Significantly Affect Our Results
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 below in our Gathering and Processing segment, may also impact the throughput and volume for our Logistics and Marketing segment.
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.
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 adjusted 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 and global demand. The number of active oil and gas drilling rigs in the United States increased, from 586 on December 31, 2021 to 779 on December 31, 2022. 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 2022 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 net realizable value 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.
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. Wide fluctuations in the price of natural gas caused by extreme weather events may increase our working capital requirements in order to fund settlements or margin requirements on open positions on commodities exchanges. 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 could restrict 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.
Climate change may have a long-term impact on our operations. For example, our facilities that are located in low lying areas such as the gulf coast of Texas and Louisiana may be at increased risk due to flooding, rising sea levels, or disruption to operations from more frequent and severe weather events. Changes in climate or weather patterns may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect throughput volumes entering our systems. Changes in climate or weather may also impact demand for energy products and services or alter the overall energy demand by fuel.
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
We anticipate that an increase in labor costs, along with increased supply chain costs primarily related to inflationary pressures that began in the latter half of 2021 and persisted through 2022, will continue to have an impact on our operations in 2023. However, a portion of these cost increases have been planned for in our 2023 budget process and should be partially offset by benefits to our commodity sales, transportation and processing prices. However, inflationary pressures on interest rates impact our business, as well as the broader economy and energy business. Consequently, our costs for chemicals, utilities, materials and supplies, labor and major equipment purchases may increase during periods of general business inflation or periods of relatively high energy commodity prices.
Other
The above factors, including sustained deterioration in commodity prices and volumes, other market declines or a decline in our 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 net realizable value 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) adjusted gross margin and segment adjusted gross margin; (3) operating and maintenance expense, and general and administrative expense; (4) adjusted EBITDA; (5) adjusted segment EBITDA; (6) Distributable Cash Flow; and (7) Excess Free Cash Flow. Adjusted gross margin, segment adjusted gross margin, adjusted EBITDA, adjusted segment EBITDA, Distributable Cash Flow and Excess Free Cash Flow are non-GAAP measures. 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 existing and 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 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 market demand.
Results of Operations
Consolidated Overview
The following table and discussion provides a summary of our consolidated results of operations for the years ended December 31, 2022 and 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion. Discussions for the year ended December 31, 2021 versus the year ended December 31, 2020 can be found in our Annual Report Form 10-K for the year ended December 31, 2021 and should be read in conjunction with the discussions below.
Year Ended December 31,
Variance
Increase
(Decrease)
Percent
(millions, except operating data)
Operating revenues (a):
Logistics and Marketing
Gathering and Processing
Inter-segment eliminations
Total operating revenues
Purchases and related costs
Logistics and Marketing
Gathering and Processing
Inter-segment eliminations
Total purchases
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other income, net
Gain (loss) on sale of assets, net
Restructuring costs
Earnings from unconsolidated affiliates (b)
Interest expense
Income tax expense
Net income attributable to noncontrolling interests
Net income attributable to partners
Other data:
Adjusted gross margin (c):
Logistics and Marketing
Gathering and Processing
Total adjusted gross margin
Non-cash commodity derivative mark-to-market
NGL pipelines throughput (MBbls/d) (d)
Gas pipelines throughput (TBtu/d) (d)
Natural gas wellhead (MMcf/d) (d)
NGL gross production (MBbls/d) (d)
* Percentage change is not meaningful.
(a) Operating revenues include the impact of trading and marketing gains (losses), net.
(b) Earnings for certain unconsolidated affiliates include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.
(c) Adjusted gross margin consists of total operating revenues less purchases and related costs. Segment adjusted 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, 2022 vs. Year Ended December 31, 2021
Total Operating Revenues — Total operating revenues increased $4,286 million in 2022 compared to 2021, primarily as a result of the following:
• $3,708 million increase for our Logistics and Marketing segment, primarily due to higher commodity prices, higher gas and NGL volumes, favorable commodity derivative activity, and an increase in transportation, processing and other; and
• $3,235 million increase for our Gathering and Processing segment, primarily due to higher commodity prices, higher volumes in the Permian region, DJ Basin, and Midcontinent region, an increase in transportation, processing and other, and favorable commodity derivative activity, partially offset by lower volumes in the South region.
These increases were partially offset by:
• $2,657 million change 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.
Total Purchases — Total purchases increased $3,625 million in 2022 compared to 2021, primarily as a result of the following:
• $3,679 million increase for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and
• $2,603 million increase for our Gathering and Processing segment for the commodity price and volume changes discussed above.
These increases were partially offset by:
• $2,657 million change in inter-segment eliminations, for the reasons discussed above.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2022 compared to 2021 largely due to higher base costs primarily in the Permian region and higher reliability and pipeline integrity spend.
General and Administrative Expense — General and administrative expense increased in 2022 compared to 2021, primarily due to higher employee costs and benefits.
Asset Impairments — Asset impairments in 2021 relate to long-lived assets in the Midcontinent and South regions of our Gathering and Processing segment, and long-lived assets in South Texas in our Logistics and Marketing segment.
Gain (loss) on sale of assets, net — The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region. The net loss on sale of assets in 2021 primarily represents the sale of gathering systems in the Midcontinent region.
Restructuring Costs — Restructuring costs increased in 2022 compared to 2021 primarily as a result of severance for termination benefits and other costs as a result of our ongoing integration with Phillips 66 following the Realignment Transaction.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2022 compared to 2021 primarily as a result of a contract amendment with a third party customer that modified performance obligations and conditions, resulting in higher non-recurring earnings on the Sand Hills pipeline, higher throughput volumes on the Sand Hills and Front Range pipelines, and higher NGL pipeline tariffs.
Interest Expense — Interest expense decreased in 2022 compared to 2021 primarily as a result of lower average outstanding debt balances.
Income tax expense — Income tax expense decreased in 2022 compared to 2021 based on forecasted reversals in 2021 of temporary differences using our future expected apportionment in Texas.
Net Income Attributable to Partners — Net income attributable to partners increased in 2022 compared to 2021 for all of the reasons discussed above.
Adjusted Gross Margin — Adjusted gross margin increased $661 million in 2022 compared to 2021, primarily as a result of the following:
• $632 million increase for our Gathering and Processing segment, primarily as a result of higher commodity prices, higher margins in the Permian and Midcontinent regions, higher volumes in the DJ Basin and Permian region, favorable derivative activity attributable to our corporate equity hedge program, and the negative impact of Winter Storm Uri resulting in producer shut-ins in the first quarter of 2021; and
• $29 million increase for our Logistics and Marketing segment, primarily as a result of an increase in gas pipeline and storage marketing margins due to more favorable commodity spreads in 2022, an increase in NGL pipeline margins, and the negative impact of Winter Storm Uri in the first quarter of 2021, partially offset by a contract settlement and unfavorable NGL marketing and storage activity.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2022 compared to 2021 due to increased volumes on the Sand Hills and Front Range pipelines.
Natural Gas Wellhead — Natural gas wellhead increased in 2022 compared to 2021 due to increased volumes in the Permian region, South region, and DJ Basin.
NGL Gross Production — NGL gross production increased in 2022 compared to 2021 due to increased volumes in the DJ Basin and Permian region.
Supplemental Information on Unconsolidated Affiliates
The following tables present financial information related to unconsolidated affiliates during the year ended December 31, 2022 and 2021, respectively:
Earnings from investments in unconsolidated affiliates were as follows:
Year Ended December 31,
(millions)
DCP Sand Hills Pipeline, LLC
DCP Southern Hills Pipeline, LLC
Gulf Coast Express LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu 1 Fractionator
Discovery Producer Services LLC
Cheyenne Connector, LLC
Mont Belvieu Enterprise Fractionator
Other
Total earnings from unconsolidated affiliates
Distributions received from unconsolidated affiliates were as follows:
Year Ended December 31,
(millions)
DCP Sand Hills Pipeline, LLC
DCP Southern Hills Pipeline, LLC
Gulf Coast Express LLC
Front Range Pipeline LLC
Texas Express Pipeline LLC
Mont Belvieu 1 Fractionator
Discovery Producer Services LLC
Cheyenne Connector, LLC
Mont Belvieu Enterprise Fractionator
Other
Total distributions from unconsolidated affiliates
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
Increase
(Decrease)
Percent
(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate
Transportation, processing and other
Trading and marketing losses, net
Total operating revenues
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other income, net
Earnings from unconsolidated affiliates (a)
Gain on sale of assets, net
Segment net income attributable to partners
Other data:
Segment adjusted gross margin (b)
Non-cash commodity derivative mark-to-market
NGL pipelines throughput (MBbls/d) (c)
Gas pipelines throughput (TBtu/d) (c)
* Percentage change is not meaningful.
(a) Earnings for certain unconsolidated affiliates include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.
(b) Adjusted gross margin consists of total operating revenues less purchases and related costs. Segment adjusted 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”.
(c) For entities not wholly owned by us, includes our share, based on our ownership percentage, of the throughput volumes.
Year Ended December 31, 2022 vs. Year Ended December 31, 2021
Total Operating Revenues — Total operating revenues increased $3,708 million in 2022 compared to 2021, primarily as a result of the following:
• $2,750 million increase as a result of higher commodity prices before the impact of derivative activity;
• $713 million increase attributable to higher gas and NGL volumes;
• $236 million increase as a result of commodity derivative activity attributable to a decrease in realized cash settlement losses of $242 million, partially offset by an increase in unrealized commodity derivative losses of $6 million due to movements in forward prices of commodities; and
• $9 million increase in transportation, processing and other.
Purchases and Related Costs — Purchases and related costs increased $3,679 million in 2022 compared to 2021, for the reasons discussed above.
Asset Impairments — Asset impairments in 2021 relate to long-lived assets in South Texas where we determined a triggering event occurred due to a negative outlook for long-term volume forecasts.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2022 compared to 2021 primarily as a result of a contract amendment with a third party customer that modified performance obligations and conditions, resulting in higher non-recurring earnings on the Sand Hills pipeline, higher throughput volumes on the Sand Hills and Front Range pipelines, and higher NGL pipeline tariffs.
Segment Adjusted Gross Margin — Segment adjusted gross margin increased $29 million in 2022 compared to 2021, primarily as a result of the following:
• $39 million increase as a result of increased gas pipeline and storage marketing margins due to more favorable commodity spreads in 2022;
• $6 million increase as a result of NGL pipeline margins.
• $5 million increase as a result of the negative impacts of Winter Storm Uri in the first quarter 2021; and
These increases were partially offset by:
• $16 million contract settlement; and
• $5 million decrease as a result of unfavorable NGL marketing and storage activity in 2022.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2022 compared to 2021 due to increased volumes on the Sand Hills and Front Range pipelines.
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
Increase
(Decrease)
Percent
(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate
Transportation, processing and other
Trading and marketing losses, net
Total operating revenues
Purchases and related costs
Operating and maintenance expense
Depreciation and amortization expense
General and administrative expense
Asset impairments
Other expense, net
Gain (loss) on sale of assets, net
Earnings from unconsolidated affiliates (a)
Segment net income
Segment net income attributable to noncontrolling interests
Segment net income attributable to partners
Other data:
Segment adjusted 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.
(a) Earnings for certain unconsolidated affiliates include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities.
(b) Segment adjusted 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”.
(c) For entities not wholly owned by us, includes our share, based on our ownership percentage, of the wellhead and NGL production
Year Ended December 31, 2022 vs. Year Ended December 31, 2021
Total Operating Revenues — Total operating revenues increased $3,235 million in 2022 compared to 2021, primarily as a result of the following:
• $2,472 million increase attributable to higher commodity prices, before the impact of derivative activity;
• $448 million increase as a result of higher volumes in the Permian region, DJ Basin, and Midcontinent region, partially offset by lower volumes in the South region;
• $136 million increase in transportation, processing and other; and
• $179 million increase as a result of commodity derivative activity attributable to a $224 million increase in unrealized commodity derivative gains partially offset by an increase in realized cash settlement losses of $45 million due to movements in forward prices of commodities in 2022.
Purchases and Related Costs — Purchases and related costs increased $2,603 million in 2022 compared to 2021, primarily as a result of the commodity price and volume changes discussed above.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2022 compared to 2021 largely due to higher base costs primarily in the Permian region and higher reliability and pipeline integrity spend.
Asset Impairments — Asset impairments in 2021 relate to certain long-lived assets in the Midcontinent and South regions.
Gain (loss) on Sale of Assets, net — The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region. The net loss on sale of assets in 2021 primarily represent the sale of gathering systems in the Midcontinent region.
Segment Adjusted Gross Margin — Segment adjusted gross margin increased $632 million in 2022 compared to 2021, primarily as a result of the following:
• $349 million increase as a result of higher commodity prices;
• $136 million increase due to higher gathering and processing margins primarily in the Permian and Midcontinent regions and higher volumes in the DJ Basin and Permian region;
• $112 million increase as a result of favorable commodity derivative activity attributable to our corporate equity hedge program as discussed above; and
• $35 million increase as a result of the negative impact of Winter Storm Uri in the first quarter 2021 which reflected reduced volumes due to producer shut-ins, commodity derivative activity associated with swaps, and the net impact of producer payments and marketing activity.
Natural Gas Wellhead — Natural gas wellhead increased in 2022 compared to 2021 due to increased volumes in the Permian region, South region, and DJ Basin.
NGL Gross Production — NGL gross production increased in 2022 compared to 2021 due to increased volumes in the DJ Basin and Permian region.
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 and Securitization Facility;
• proceeds from asset rationalization;
• debt offerings;
• borrowings under term loans, or other credit facilities; and
We anticipate our more significant uses of resources to include:
• quarterly distributions to our common unitholders and distributions to our preferred unitholders;
• payments to service or retire our debt or Preferred Units;
• capital expenditures;
• contributions to our unconsolidated affiliates to finance our share of their capital expenditures;
• 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 expenditures and quarterly cash distributions.
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 or acquisitions.
Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, impact our credit ratings, raise our financing costs, as well as impact our compliance with the financial covenants contained in the Credit Agreement and other debt instruments.
Series A Preferred Units Redemption — On December 15, 2022 we paid $500 million to redeem in full the outstanding Series A Preferred Units at a redemption price of $1,000 per unit using cash on hand and borrowings under our Securitization Facility. The difference between the redemption price of the Series A Preferred Units and the carrying value on the balance sheet resulted in an approximately $13 million reduction to net income allocable to limited partners. The carrying value represented the original issuance proceeds, net of underwriting fees and offering costs for the Series A Preferred Units.
Senior Notes — On January 3, 2022, we repaid, at par, prior to maturity all $350 million of aggregate principal amount outstanding of our 4.95% Senior Notes due April 1, 2022, using borrowings under our Credit Facility and Securitization Facility.
Credit Agreement —On March 18, 2022, we amended the Credit Agreement. The amendment extended the term of the Credit Agreement from December 9, 2024 to March 18, 2027. The amendment also includes sustainability linked key performance indicators that increase or decrease the applicable margin and facility fee payable thereunder based on our safety performance relative to our peers and year-over-year change in our greenhouse gas emissions intensity rate. The Credit Agreement provides up to $1.4 billion of borrowing capacity and bears interest at either the term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating.
As of December 31, 2022, we had unused borrowing capacity of $1,390 million, net of $10 million letters of credit, under the Credit Agreement, of which at least $1,390 million would have been available to borrow for working capital and other general partnership purposes based on the financial covenants set forth in the Credit Agreement. As of February 10, 2023, we had unused borrowing capacity of $1,377 million, net of $13 million of outstanding borrowings and $10 million of letters of
credit under the Credit Agreement. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid.
Accounts Receivable Securitization Facility — As of December 31, 2022, we had unused borrowing capacity of $310 million under the Securitization Facility, secured by approximately $1,104 million of our accounts receivable at DCP Receivables LLC ( “ DCP Receivables ” ).
Issuance of Securities — In October 2020, we filed a shelf registration statement with the SEC that became effective upon filing and allows us to issue an indeterminate number of common units, preferred units, debt securities, and guarantees of debt securities. During the year ended December 31, 2022, we did not issue any securities pursuant to this registration statement.
In October 2020, we also 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, 2022, we did not issue any common units pursuant to this registration statement, and $750 million remained available for future sales.
Guarantee of Registered Debt Securities — The consolidated financial statements of DCP Midstream, LP, or “parent guarantor”, include the accounts of DCP Midstream Operating LP, or “subsidiary issuer”, which is a 100% owned subsidiary, and all other subsidiaries which are all non-guarantor subsidiaries. The parent guarantor has agreed to fully and unconditionally guarantee the senior notes. The entirety of the Company’s operating assets and liabilities, operating revenues, expenses and other comprehensive income exist at its non-guarantor subsidiaries, and the parent guarantor and subsidiary issuer have no assets, liabilities or operations independent of their respective financing activities and investments in non-guarantor subsidiaries. All covenants in the indentures governing the notes limit the activities of subsidiary issuer, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to parent guarantor.
The Company qualifies for alternative disclosure under Rule 13-01 of Regulation S-X, because the combined financial information of the subsidiary issuer and parent guarantor, excluding investments in subsidiaries that are not issuers or guarantors, reflect no material assets, liabilities or results of operations apart from their respective financing activities and investments in non-guarantor subsidiaries. Summarized financial information is presented as follows. The only assets, liabilities and results of operations of the subsidiary issuer and parent guarantor on a combined basis, independent of their respective investments in non-guarantor subsidiaries are:
• Accounts payable and other current liabilities of $80 million and $81 million as of December 31, 2022 and December 31, 2021, respectively;
• Balances related to debt of $4.823 billion and $5.174 billion as of December 31, 2022 and December 31, 2021, respectively; and
• Interest expense, net of $271 million and $296 million for the year ended December 31, 2022 and 2021, respectively.
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. For additional information regarding our derivative activities, please read Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” contained herein.
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 in part 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 and the Securitization Facility, 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. During February 2021, Winter Storm Uri resulted in lower regional volumes and abnormally high gas prices for a period of days. A majority of our receivables associated with Winter Storm Uri have been collected. Certain counterparty billings during this time are under dispute and are taking longer to collect than normal, which continues to impact our working capital at December 31, 2022. We believe the amounts due to us are owed and are vigorously pursuing legal avenues to collect these receivables.
We had working capital deficits of $802 million and $261 million as of December 31, 2022 and December 31, 2021, respectively, driven by current maturities of long term debt of $506 million and $355 million, respectively. We had net derivative working capital deficits of $8 million and $59 million as of December 31, 2022 and December 31, 2021, respectively.
Cash Flow — Operating, investing and financing activities were as follows:
Year Ended December 31,
(millions)
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Year Ended December 31, 2022 vs. Year Ended December 31, 2021
Operating Activities — Net cash provided by operating activities increased $1,236 million in 2022 compared to the same period in 2021. 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. For additional information regarding fluctuations in our earnings and distributions from unconsolidated affiliates, please read “Supplemental Information on Unconsolidated Affiliates” under “Results of Operations”.
Investing Activitie s — Net cash used in investing activities increased $281 million in 2022 compared to the same period in 2021, primarily as a result of an increase in capital expenditures and the acquisition of the James Lake System, partially offset by proceeds from the sale of assets.
Financing Activitie s — Net cash used in financing activities increased $896 million in 2022 compared to the same period in 2021, primarily as a result of the redemption of the Series A Preferred Units and higher net payments of debt.
Contractual Obligation s — Material contractual obligations arising in the normal course of business primarily consist of purchase obligations, long-term debt and related interest payments, leases, asset retirement obligations, and other long-term liabilities. See Note s 10, 14, and 15 to the Consolidated Financial Statements included in Item 8 "Financial Statements" in Part II of this form 10-K for amounts outstanding on December 31, 2022, related to asset retirement obligations, leases, and debt.
Purchase Obligations are contractual obligations and include various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including gas supply, fractionation and transportation agreements in the ordinary course of business.
Management believes that our cash and investment position and operating cash flows as well as capacity under existing and available credit agreements will be sufficient to meet our liquidity and capital requirements for the foreseeable future. We believe that our current and projected asset position is sufficient to meet our liquidity requirements.
Capital Requirements — The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. In the ordinary course of our business, we purchase physical commodities and enter into arrangements related to other items, including long-term fractionation and transportation agreements, in future periods. We establish a margin for these purchases by entering into physical and financial sale and exchange transactions to maintain a balanced position between purchases and sales and future delivery obligations. We expect to fund the obligations with the corresponding sales to entities that we deem creditworthy or that have provided credit support we consider adequate. We may
enter into purchase order and non-cancelable construction agreements for capital expenditures. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of the following:
• Sustaining capital expenditures, which are cash expenditures to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Sustaining 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, or 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 2023 plan includes sustaining capital expenditures of $150 million and expansion capital expenditures of $125 million.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, Securitization Facility and the issuance of additional debt and equity securities. We funded our acquisition of the James Lake System with cash and borrowings under our Credit Facility. Future material investments 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.
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 common unitholders and general partner of $342 million and $325 million during the years ended December 31, 2022 and 2021, respectively.
On January 24, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution on our common units of $0.43 per common unit. The distribution was paid on February 14, 2023 to unitholders of record on February 3, 2023.
Also on January 24, 2023, the board of directors of the General Partner declared a quarterly distribution on our Series B and Series C Preferred Units of $0.4922 and $0.4969 per unit, respectively. The Series B distribution will be paid on March 15, 2023 to unitholders of record on March 1, 2023. The Series C distribution will be paid on April 17, 2023 to unitholders of record on April 3, 2023.
We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders. See Note 17 . “Partnership Equity and Distributions” in the Notes to the Consolidated Financial Statements in Item 8. “Financial Statements” in Part II of this 10-K.
Reconciliation of Non-GAAP Measures
Adjusted Gross Margin and Segment Adjusted Gross Margin — In addition to net income, we view our adjusted gross margin as an important performance measure of the core profitability of our operations. We review our adjusted gross margin monthly for consistency and trend analysis.
We define adjusted gross margin as total operating revenues, less purchases and related costs, and we define segment adjusted gross margin for each segment as total operating revenues for that segment less purchases and related costs for that segment. Our adjusted gross margin equals the sum of our segment adjusted gross margins. Adjusted gross margin and segment adjusted 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, adjusted gross margin and segment adjusted gross margin should not be considered an alternative to, or more meaningful than, operating revenues, gross margin, segment gross margin, net income or loss, net income or loss attributable to partners, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP.
We believe adjusted gross margin provides useful information to our investors because our management views our adjusted gross margin and segment adjusted gross margin as important performance measures that represent the results of product sales and purchases, a key component of our operations. We review our adjusted gross margin and segment adjusted gross margin monthly for consistency and trend analysis. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results.
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, net cash provided by 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 pay 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 segment 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 adjusted gross margin, segment adjusted 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 adjusted gross margin, segment adjusted 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 sustaining capital expenditures, net of reimbursable projects, less interest expense, less income attributable to preferred units, and certain other items. Sustaining capital expenditures are cash expenditures made to maintain our cash flows, operating or earnings capacity. These expenditures add on to or improve capital assets owned, including certain system integrity, compliance and safety improvements. Sustaining 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 preferred units. Cash distributions to be paid to the holders of the preferred units assuming a distribution is declared by the board of directors of the General Partner, 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. 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.
Excess Free Cash Flow — We define Excess Free Cash Flow as Distributable Cash Flow, as defined above, less distributions to limited partners, less expansion capital expenditures, net of reimbursable projects, and contributions to equity method investments and certain other items. Expansion capital expenditures are cash expenditures to increase our cash flows, or 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).
Excess Free 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, and is useful to investors and management as a measure of our ability to generate cash. Once business needs and obligations are met, including cash reserves to provide funds for distribution payments on our units and the proper conduct of our business, which includes cash reserves for future capital expenditures and anticipated credit needs, this cash can be used to reduce debt, reinvest in the company for future growth, or return to unitholders.
Our definition of Excess Free Cash Flow is limited in that it does not represent residual cash flows available for discretionary expenditures. Therefore, we believe the use of Excess Free Cash Flow for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure. Excess Free Cash Flow may not be comparable to a similarly titled measure of another company because other entities may not calculate Excess Free Cash Flow in the same manner.
The following table sets forth our reconciliation of certain non-GAAP measures:
Year Ended December 31,
Reconciliation of Non-GAAP Measures
(millions)
Reconciliation of gross margin to adjusted gross margin:
Operating revenues
Cost of revenues
Purchases and related costs
Purchases and related costs from affiliates
Transportation and related costs from affiliates
Depreciation and amortization expense
Gross margin
Depreciation and amortization expense
Adjusted gross margin
Reconciliation of segment gross margin to segment adjusted gross margin:
Logistics and Marketing segment:
Operating revenues
Cost of revenues
Purchases and related costs
Depreciation and amortization expense
Segment gross margin
Depreciation and amortization expense
Segment adjusted gross margin
Gathering and Processing segment:
Operating revenues
Cost of revenues
Purchases and related costs
Depreciation and amortization expense
Segment gross margin
Depreciation and amortization expense
Segment adjusted gross margin
Year Ended December 31,
(millions)
Reconciliation of net income attributable to partners to 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
Asset impairments
Other (income) expense
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
Distributions from unconsolidated affiliates, net of earnings
Asset impairments
Gain on sale of assets
Other expense
Adjusted segment EBITDA
(a) We recognized $17 million, zero, and $6 million of lower of cost or net realizable value adjustment for the years ending December 31, 2022, 2021, and 2020, respectively.
Operating and Maintenance and General and Administrative Expense
Pursuant to the Contribution Agreement, on January 1, 2017, the Partnership entered into 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.
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.
Critical Accounting Policies and Estimates
Our financial statements reflect the selection and application of accounting policies that require management to make estimates and assumptions. Management believes 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. Management bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities. Our significant accounting policies are described further in Note 2 of the Notes to Consolidated Financial Statements in Item 8. "Financial Statements and Supplementary Data."
Impairment of long-lived assets - We evaluate property, plant and equipment, operating lease right-of-use (“ROU”) assets and other finite-lived assets for impairment when facts and circumstances indicate that the carrying values of such assets may not be recoverable.
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.
We estimate fair value measurements to record impairment to certain long-lived assets and to determine fair value disclosures in accordance with Accounting Standards Codification ("ASC") 360 and 820. These significant estimates, judgments, inputs, and assumptions include, when applicable, the selection of an appropriate valuation method depending on the nature of the respective asset, such as the income approach, the market or sales comparison approach. The fair value of our operating asset groups is estimated using a discounted cash flow model as quoted market prices are not available. For other long-lived assets, fair value is determined using an approach that is appropriate based on the relevant facts and circumstances, which may include discounted cash flows or comparable transactions analyses.
Determining whether impairment indicators exist, estimating the undiscounted cash flows and fair value of the Company’s long lived assets for impairment testing requires significant judgment. The assumptions used to assess impairment consider historical trends, macroeconomic and industry conditions, and projections consistent with the Company’s operating strategy. Our undiscounted cash flow forecasts contain uncertainties because they require management to make assumptions and to apply judgment in estimating future cash flows including forecasting projected revenues and margins based on the future volumes of gas or other applicable throughputs, future commodity prices, operating costs, forecasting useful lives of the assets, assessing the probability of different outcomes, and with respect to asset fair values selecting an appropriate discount rate to estimate the present value of those projected cash flows. The discount rate is selected based on the return we believe a market participant would require that appropriately reflects the risks associated with the cash flows when determining a purchase price for the asset groups.
Using the impairment review methodology described herein, we recorded $1 million and $31 million of impairment charges on long-lived assets during the years ended December 31, 2022 and 2021, respectively. These estimates are sensitive to change and 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 that could be material. 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. See Note 13 of the Notes to Consolidated Financial Statements in Item 8. "Financial Statements."
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 fair value of such investment may have experienced a decline to less than its carrying value and the impairment is other than temporary.
We estimate fair value measurements to record impairment to certain unconsolidated affiliates and to determine fair value disclosures in accordance with ASC 323 and 820. These significant estimates, judgments, inputs, and assumptions include, when applicable, the selection of an appropriate valuation method depending on the nature of the respective asset, such as the income approach, the market or sales comparison approach. When determining whether a decline in value is other than
temporary, management considers factors such as the duration and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that allows for recovery. The fair value of our unconsolidated affiliates is primarily estimated using a discounted cash flow model as quoted market prices are not available.
Determining whether impairment indicators exist and estimating the fair value of the Company’s unconsolidated affiliates for impairment testing requires significant judgment. The assumptions used to assess other than temporary impairment consider historical trends, macroeconomic and industry conditions, and projections consistent with the Company’s operating strategy. Our fair value calculations contain uncertainties because they require management to make assumptions and to apply judgment in estimating future cash flows including forecasting projected revenues and margins based on the future volumes of gas or other applicable throughputs, future commodity prices, operating costs, forecasting useful lives of the assets, assessing the probability of different outcomes, and with respect to asset fair values selecting an appropriate discount rate to estimate the present value of those projected cash flows. The discount rate is selected based on the return we believe a market participant would require that appropriately reflects the risks associated with the 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, 2022. These estimates are sensitive to change and 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 that could be material. 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.
Business combinations - We account for business combinations under ASC 805 which, among other things, requires the allocation of the company’s purchase price to the various assets and liabilities of the acquired business at their respective fair values at the date of acquisition.
We estimate fair value measurements in accordance with ASC 820. These significant estimates, judgments, inputs, and assumptions include, when applicable, the selection of an appropriate valuation method depending on the nature of the respective asset, such as the income approach, the market or sales comparison approach. Determining the fair values of assets acquired generally involves assumptions regarding the amounts and timing of future revenues and expenditures, as well as discount rates.
The assumptions and inputs incorporated within the fair value estimates are subject to considerable management judgement and are based on historical trends, industry, market, and economic conditions prevalent at the time of the acquisition. Although we based these estimates on assumptions believed to be reasonable, these estimates are inherently unpredictable, uncertain and sensitive to change and the actual results could affect the accuracy or validity of our estimates.
