DCP MIDSTREAM, LP 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 endedDecember 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 endedDecember 31, 2021 . Overview We are aDelaware limited partnership formed byDCP 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
OnAugust 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, andSpectra DEFS Holding, LLC , an indirect wholly owned subsidiary of Enbridge, as the members ofDCP Midstream, LLC , entered into the Third A&R LLC Agreement, which, among other things, designated PGC as the Class A Managing Member ofDCP Midstream, LLC with the power to conduct, direct and manage all activities ofDCP Midstream, LLC associated with the Partnership and each of its subsidiaries,GP LP and ourGeneral Partner , and, in each case, the businesses, activities and liabilities thereof. The Third A&R LLC Agreement also provided PGC with the power to exerciseDCP Midstream, LLC's rights to appoint or remove any director on the board of directors of ourGeneral Partner and vote the common units representing limited partner interests in the Partnership that are owned directly or indirectly byDCP 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 byDCP 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
OnAugust 17, 2022 , the board of directors of ourGeneral 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 byDCP Midstream, LLC or its subsidiaries at a value of$34.75 per common unit (the "Proposal"). The board of directors of ourGeneral Partner appointed the special committee to review, evaluate and negotiate the Proposal. OnJanuary 5, 2023 , we entered into the Merger Agreement with Phillips 66, PDI, Merger Sub,GP LP and ourGeneral 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 byDCP Midstream, LLC andGP 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 afterDecember 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 ofGP 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. 60 --------------------------------------------------------------------------------
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. DuringFebruary 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
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
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--------------------------------------------------------------------------------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
Recent Events
Series A Preferred Units Redemption
OnDecember 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
OnJanuary 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 onFebruary 14, 2023 to unitholders of record onFebruary 3, 2023 . Also onJanuary 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 onMarch 15, 2023 to unitholders of record onMarch 1, 2023 . The Series C distribution will be paid onApril 17, 2023 to unitholders of record onApril 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
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--------------------------------------------------------------------------------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 inthe United States increased, from 586 onDecember 31, 2021 to 779 onDecember 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. 63 --------------------------------------------------------------------------------
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 ofTexas andLouisiana 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
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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 opportunities to connect new supply
to these pipelines. We also monitor our inventory in our NGL and gas storage
facilities, as well as overall demand for storage based on seasonal patterns and
other market factors such as weather and overall market demand.
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--------------------------------------------------------------------------------Results of Operations
Consolidated Overview
The following table and discussion provides a summary of our consolidated results of operations for the years endedDecember 31, 2022 and 2021. The results of operations by segment are discussed in further detail following this consolidated overview discussion. Discussions for the year endedDecember 31, 2021 versus the year endedDecember 31, 2020 can be found in our Annual Report Form 10-K for the year endedDecember 31, 2021 and should be read in conjunction with the discussions below. Year Ended Variance December 31, 2022 vs. 2021 Increase 2022 2021 (Decrease) Percent (millions, except operating data) Operating revenues (a): Logistics and Marketing$ 13,442 $ 9,734 $ 3,708 38 % Gathering and Processing 10,129 6,894 3,235 47 % Inter-segment eliminations (8,578) (5,921) 2,657 45 % Total operating revenues 14,993 10,707 4,286 40 % Purchases and related costs Logistics and Marketing (13,275) (9,596) 3,679 38 % Gathering and Processing (8,193) (5,590) 2,603 47 % Inter-segment eliminations 8,578 5,921 2,657 45 % Total purchases (12,890) (9,265) 3,625 39 % Operating and maintenance expense (729) (659) 70 11 % Depreciation and amortization expense (360) (364) (4) (1 %) General and administrative expense (286) (223) 63 28 % Asset impairments (1) (31) (30) (97 %) Other income, net 3 5 (2) (40 %) Gain (loss) on sale of assets, net 6 (5) 11 * Restructuring costs (21) - 21 * Earnings from unconsolidated affiliates (b) 620 535 85 16 % Interest expense (278) (299) (21) (7 %) Income tax expense (1) (6) (5) (83 %) Net income attributable to noncontrolling interests (4) (4) - - % Net income attributable to partners$ 1,052 $ 391 $ 661 * Other data: Adjusted gross margin (c): Logistics and Marketing$ 167 $ 138 $ 29 21 % Gathering and Processing 1,936 1,304 632 48 % Total adjusted gross margin$ 2,103 $ 1,442 $ 661 46 % Non-cash commodity derivative mark-to-market$ 93 $ (125) $ 218 * NGL pipelines throughput (MBbls/d) (d) 705 652 53 8 % Gas pipelines throughput (TBtu/d) (d) 1.09 1.0 0.09 9 % Natural gas wellhead (MMcf/d) (d) 4,353 4,196 157 4 % NGL gross production (MBbls/d) (d) 421 398 23 6 % * 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". 66 --------------------------------------------------------------------------------
(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
Total Operating Revenues - Total operating revenues increased
•$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
•$3,679 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
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 theSand Hills pipeline, higher throughput volumes on theSand Hills andFront 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
Net Income Attributable to Partners - Net income attributable to partners increased in 2022 compared to 2021 for all of the reasons discussed above.
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Adjusted Gross Margin - Adjusted gross margin increased
•$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
•$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
Natural Gas Wellhead - Natural gas wellhead increased in 2022 compared to 2021
due to increased volumes in the Permian region, South region, and
NGL Gross Production - NGL gross production increased in 2022 compared to 2021
due to increased volumes in the
Supplemental Information on Unconsolidated Affiliates
The following tables present financial information related to unconsolidated
affiliates during the year ended
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--------------------------------------------------------------------------------Earnings from investments in unconsolidated affiliates were as follows:
Year Ended December 31,
2022 2021
(millions)
DCP Sand Hills Pipeline, LLC $ 338 $ 274
DCP Southern Hills Pipeline, LLC 89 91
Gulf Coast Express LLC 67 63
Front Range Pipeline LLC 46 38
Texas Express Pipeline LLC 22 19
Mont Belvieu 1 Fractionator 15 17
Discovery Producer Services LLC 20 16
Cheyenne Connector, LLC 15 12
Mont Belvieu Enterprise Fractionator 6 3
Other 2 2 Total earnings from unconsolidated affiliates
Distributions received from unconsolidated affiliates were as follows:
Year Ended December 31,
2022 2021
(millions)
DCP Sand Hills Pipeline, LLC $ 388 $ 293
DCP Southern Hills Pipeline, LLC 105 102
Gulf Coast Express LLC 82 78
Front Range Pipeline LLC 50 42
Texas Express Pipeline LLC 24 21
Mont Belvieu 1 Fractionator 14 17
Discovery Producer Services LLC 33 29
Cheyenne Connector, LLC 19 17
Mont Belvieu Enterprise Fractionator 6 1
Other 3 4
Total distributions from unconsolidated affiliates $ 724 $ 604
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Results of Operations - Logistics and Marketing Segment
The results of operations for our Logistics and Marketing segment are as
follows:
Variance
Year Ended December 31, 2022 vs. 2021
Increase
2022 2021 (Decrease) Percent
(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate $ 13,394 $ 9,931 $ 3,463 35 %
Transportation, processing and other 74 65 9 14 %
Trading and marketing losses, net (26) (262) 236 90 %
Total operating revenues 13,442 9,734 3,708 38 %
Purchases and related costs (13,275) (9,596) 3,679 38 %
Operating and maintenance expense (36) (38) (2) (5 %)
Depreciation and amortization expense (12) (12) - - %
General and administrative expense (6) (6) - - %
Asset impairments - (13) (13) *
Other income, net 8 6 2 33 %
Earnings from unconsolidated affiliates (a) 601 519 82 16 %
Gain on sale of assets, net - 2 2 *
Segment net income attributable to partners $ 722 $ 596 $ 126 21 %
Other data:
Segment adjusted gross margin (b) $ 167 $ 138 $ 29 21 %
Non-cash commodity derivative mark-to-market $ (25) $ (19) $ (6) (32 %)
NGL pipelines throughput (MBbls/d) (c) 705 652 53 8 %
Gas pipelines throughput (TBtu/d) (c) 1.09 1.0 0.09 9 %
* 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
Total Operating Revenues - Total operating revenues increased
•$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
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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
•$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
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--------------------------------------------------------------------------------Results of Operations - Gathering and Processing Segment
The results of operations for our Gathering and Processing segment are as
follows:
Year Ended Variance
December 31, 2022 vs. 2021
Increase
2022 2021 (Decrease) Percent
(millions, except operating data)
Operating revenues:
Sales of natural gas, NGLs and condensate $ 9,696 $ 6,776 $ 2,920 43 %
Transportation, processing and other 610 474 136 29 %
Trading and marketing losses, net (177) (356) 179 50 %
Total operating revenues 10,129 6,894 3,235 47 %
Purchases and related costs (8,193) (5,590) 2,603 47 %
Operating and maintenance expense (671) (603) 68 11 %
Depreciation and amortization expense (329) (325) 4 1 %
General and administrative expense (18) (15) 3 20 %
Asset impairments (1) (18) (17) (94 %)
Other expense, net (5) (1) 4 *
Gain (loss) on sale of assets, net 6 (7) 13 *
Earnings from unconsolidated affiliates (a) 19 16 3 19 %
Segment net income 937 351 586 *
Segment net income attributable to noncontrolling interests (4) (4) - - %
Segment net income attributable to partners $ 933 $ 347 $ 586 *
Other data:
Segment adjusted gross margin (b) $ 1,936 $ 1,304 $ 632 48 %
Non-cash commodity derivative mark-to-market $ 118 $ (106) $ 224 *
Natural gas wellhead (MMcf/d) (c) 4,353 4,196 157 4 %
NGL gross production (MBbls/d) (c) 421 398 23 6 %
* 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
Total Operating Revenues - Total operating revenues increased
•$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
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•$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
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
•$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 theDJ 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
NGL Gross Production - NGL gross production increased in 2022 compared to 2021
due to increased volumes in the
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--------------------------------------------------------------------------------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 - OnDecember 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 - OnJanuary 3, 2022 , we repaid, at par, prior to maturity all$350 million of aggregate principal amount outstanding of our 4.95% Senior Notes dueApril 1, 2022 , using borrowings under our Credit Facility and Securitization Facility. Credit Agreement -OnMarch 18, 2022 , we amended the Credit Agreement. The amendment extended the term of the Credit Agreement fromDecember 9, 2024 toMarch 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 ofDecember 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 ofFebruary 10, 2023 , we had unused borrowing capacity of$1,377 million , net of$13 million of outstanding borrowings and$10 million of letters of 74 --------------------------------------------------------------------------------
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 ofDecember 31, 2022 , we had unused borrowing capacity of$310 million under the Securitization Facility, secured by approximately$1,104 million of our accounts receivable atDCP Receivables LLC ("DCP Receivables"). Issuance of Securities - InOctober 2020 , we filed a shelf registration statement with theSEC 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 endedDecember 31, 2022 , we did not issue any securities pursuant to this registration statement.
In
Guarantee ofRegistered Debt Securities - The consolidated financial statements ofDCP Midstream, LP , or "parent guarantor", include the accounts ofDCP 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 ofDecember 31, 2022 andDecember 31, 2021 , respectively; •Balances related to debt of$4.823 billion and$5.174 billion as ofDecember 31, 2022 andDecember 31, 2021 , respectively; and •Interest expense, net of$271 million and$296 million for the year endedDecember 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 75 -------------------------------------------------------------------------------- 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. DuringFebruary 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 atDecember 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 ofDecember 31, 2022 andDecember 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 ofDecember 31, 2022 andDecember 31, 2021 , respectively.
Cash Flow - Operating, investing and financing activities were as follows:
Year Ended December 31,
2022 2021 2020
(millions)
Net cash provided by operating activities $ 1,882 $ 646 $ 1,099
Net cash used in investing activities $ (391) $ (110) $ (259)
Net cash used in financing activities $ (1,487) $ (591) $ (785) Year Ended
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 Activities - 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 theJames Lake System, partially offset by proceeds from the sale of assets. Financing Activities - 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 Obligations - 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 onDecember 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
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--------------------------------------------------------------------------------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
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 JamesLake 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 endedDecember 31, 2022 and 2021, respectively. OnJanuary 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 onFebruary 14, 2023 to unitholders of record onFebruary 3, 2023 . Also onJanuary 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 onMarch 15, 2023 to unitholders of record onMarch 1, 2023 . The Series C distribution will be paid onApril 17, 2023 to unitholders of record onApril 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.
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--------------------------------------------------------------------------------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
78
--------------------------------------------------------------------------------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.
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The following table sets forth our reconciliation of certain non-GAAP measures:
Year Ended December 31,
2022 2021 2020
Reconciliation of Non-GAAP Measures (millions)
Reconciliation of gross margin to adjusted gross margin:
Operating revenues$ 14,993 $ 10,707 $ 6,302 Cost of revenues Purchases and related costs 11,476 8,093 3,627 Purchases and related costs from affiliates 307 188 166 Transportation and related costs from affiliates 1,107 984 950 Depreciation and amortization expense 360 364 376 Gross margin 1,743 1,078 1,183 Depreciation and amortization expense 360 364$ 376 Adjusted gross margin
Reconciliation of segment gross margin to segment adjusted gross margin:
Logistics and Marketing segment: Operating revenues$ 13,442 $ 9,734 $ 5,530 Cost of revenues Purchases and related costs 13,275 9,596 5,197 Depreciation and amortization expense 12 12 13 Segment gross margin 155 126$ 320 Depreciation and amortization expense 12 12$ 13 Segment adjusted gross margin
Gathering and Processing segment: Operating revenues$ 10,129 $ 6,894 $ 3,479 Cost of revenues Purchases and related costs 8,193 5,590 2,253 Depreciation and amortization expense 329 325 333 Segment gross margin 1,607 979 893 Depreciation and amortization expense 329 325 333 Segment adjusted gross margin
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Year Ended December 31,
2022 2021 2020
(millions)Reconciliation of net income attributable to partners to adjusted segment EBITDA:
Logistics and Marketing segment: Segment net income attributable to partners (a)$ 722 $ 596 $ 777 Non-cash commodity derivative mark-to-market 25 19 (78)
Depreciation and amortization expense, net of noncontrolling interest
12 12 13
Distributions from unconsolidated affiliates, net of earnings 91 56 106
Asset impairments - 13 -
Other (income) expense - (2) 2
Adjusted segment EBITDA $ 850 $ 694 $ 820
Gathering and Processing segment:
Segment net income (loss) attributable to partners $ 933 $ 347 $ (499)
Non-cash commodity derivative mark-to-market (118) 106 23
Depreciation and amortization expense, net of noncontrolling interest
328 324 332
Distributions from unconsolidated affiliates, net of earnings 13 13 78
Asset impairments 1 18 746
Gain on sale of assets (6) - -
Other expense 3 9 3
Adjusted segment EBITDA $ 1,154 $ 817 $ 683 (a) We recognized
Operating and Maintenance and General and Administrative Expense
Pursuant to the Contribution Agreement, onJanuary 1, 2017 , the Partnership entered into the Services Agreement, which replaced the services agreement between the Partnership andDCP Midstream, LLC , datedFebruary 14, 2013 , as amended. Under the Services Agreement, we are required to reimburseDCP Midstream, LLC for salaries of personnel and employee benefits, as well as capital expenditures, maintenance and repair costs, taxes and other direct costs incurred byDCP Midstream, LLC on our behalf. There is no limit on the reimbursements we make toDCP 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 byDCP 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. 81 --------------------------------------------------------------------------------
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
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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 endedDecember 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.
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