See accompanying notes to condensed consolidated financial statements.
See accompanying notes to condensed consolidated financial statements.
See accompanying notes to condensed consolidated financial statements.
1. Description of Business and Basis of Presentation
Our operations and activities are managed by our general partner, DCP Midstream GP, LP (“GP LP”), which in turn is managed by its general partner, DCP Midstream GP, LLC, which we refer to as the General Partner, and which is 100% owned by DCP Midstream, LLC. Phillips 66 has the authority to conduct, direct and manage the activities of DCP Midstream, LLC associated with the Partnership and our general partner, and, therefore, effectively controls our business and affairs.
The condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could differ from those estimates. All intercompany balances and transactions have been eliminated in consolidation.
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (Millions) |
| Employee related costs charged by DCP Midstream, LLC | | | | | | | | |
| Operating and maintenance expense | | $ | 50 |
| | $ | 51 |
| | $ | 149 |
| | $ | 158 |
|
| General and administrative expense (including restructuring charges) | | $ | 46 |
| | $ | 47 |
| | $ | 116 |
| | $ | 142 |
|
Phillips 66 and its Affiliates
We sell a portion of our residue gas and NGLs to Phillips 66 and Chevron Phillips Chemical LLC, or CPChem. In addition, we purchase NGLs from CPChem. CPChem is owned 50% by Phillips 66, and is considered a related party. Approximately 22% of our NGL production was committed to Phillips 66 and CPChem as of September 30, 2017. The primary production commitment on certain contracts began a ratable wind down period in December 2014 and expires in January 2019. We anticipate continuing to purchase and sell commodities with Phillips 66 and CPChem in the ordinary course of business.
Enbridge and its Affiliates
We sell NGLs to and purchase NGLs from Enbridge and its affiliates. We anticipate continuing to sell commodities to and purchase commodities from Enbridge and its affiliates in the ordinary course of business.
Unconsolidated Affiliates
We have entered into 15-year transportation agreements, with Sand Hills Pipeline, LLC, or Sand Hills, Southern Hills Pipeline, LLC, or Southern Hills, Front Range Pipeline LLC, or Front Range, and Texas Express Pipeline LLC, or Texas Express. Under the terms of these 15-year agreements, which commenced at each of the pipelines’ respective in-service dates and expire between 2028 and 2029, we have committed to transport minimum throughput volumes at rates defined in each of the pipelines’ respective tariffs.
We also sell a portion of our residue gas and NGLs to, purchase natural gas and other NGL products from, and provide gathering and transportation services to other unconsolidated affiliates. We anticipate continuing to purchase and sell commodities and provide services to unconsolidated affiliates in the ordinary course of business.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
Under the terms of the Sand Hills LLC Agreement and the Southern Hills LLC Agreement, or the Sand Hills and Southern Hills LLC Agreements, Sand Hills and Southern Hills are required to reimburse us for any direct costs or expenses (other than general and administration services) which we incur on behalf of Sand Hills and Southern Hills. Additionally, Sand Hills and Southern Hills each pay us an annual service fee of $5 million, for centralized corporate functions provided by us as operator of Sand Hills and Southern Hills, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, taxes and engineering. Except with respect to the annual service fee, there is no limit on the reimbursements Sand Hills and Southern Hills make to us under the Sand Hills and Southern Hills LLC Agreements for other expenses and expenditures which we incur on behalf of Sand Hills or Southern Hills.
Summary of Transactions with Affiliates
The following table summarizes our transactions with affiliates: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2023 | | 2022 | | 2023 | | 2022 | | |
| | (millions) |
| Phillips 66 (including its affiliates): | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 896 | | | $ | 1,197 | | 1197 | $ | 1,600 | | | $ | 2,292 | | | |
| Purchases and related costs from affiliates | | $ | 2 | | | $ | 65 | | | $ | 77 | | | $ | 127 | | | |
| Transportation and related costs from affiliates | | $ | 46 | | | $ | 47 | | | $ | 87 | | | $ | 90 | | | |
| Operating and maintenance and general administrative expenses | | $ | 6 | | | $ | 4 | | | $ | 10 | | | $ | 7 | | | |
| Enbridge (including its affiliates): | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 1 | | | $ | (2) | | | $ | 2 | | | $ | (2) | | | |
| Purchases and related costs from affiliates | | $ | — | | | $ | — | | | $ | — | | | $ | 13 | | | |
| Transportation and related costs from affiliates | | $ | 1 | | | $ | 1 | | | $ | 1 | | | $ | 1 | | | |
| Operating and maintenance and general administrative expenses | | $ | 1 | | | $ | — | | | $ | 1 | | | $ | — | | | |
| Unconsolidated affiliates: | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 14 | | | $ | 24 | | | $ | 42 | | | $ | 56 | | | |
| Transportation, processing, and other to affiliates | | $ | 4 | | | $ | 3 | | | $ | 8 | | | $ | 7 | | | |
| Purchases and related costs from affiliates | | $ | 10 | | | $ | 35 | | | $ | 32 | | | $ | 59 | | | |
| Transportation and related costs from affiliates | | $ | 241 | | | $ | 227 | | | $ | 479 | | | $ | 441 | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (Millions) |
| Phillips 66 (including its affiliates): | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 289 |
| | $ | 237 |
| | $ | 814 |
| | $ | 633 |
|
| Purchases of natural gas and NGLs from affiliates | | $ | 7 |
| | $ | 6 |
| | $ | 22 |
| | $ | 12 |
|
| Operating and maintenance and general administrative expenses | | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
|
| Enbridge (including its affiliates): | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 14 |
| | $ | — |
| | $ | 34 |
| | $ | — |
|
| Purchases of natural gas and NGLs from affiliates | | $ | 12 |
| | $ | 7 |
| | $ | 31 |
| | $ | 25 |
|
| Operating and maintenance and general administrative expenses | | $ | 1 |
| | $ | 1 |
| | $ | 2 |
| | $ | 3 |
|
| Unconsolidated affiliates: | | | | | | | | |
| Sales of natural gas, NGLs and condensate to affiliates | | $ | 15 |
| | $ | 12 |
| | $ | 37 |
| | $ | 29 |
|
| Transportation, storage and processing to affiliates | | $ | 1 |
| | $ | — |
| | $ | 4 |
| | $ | 3 |
|
| Purchases of natural gas and NGLs from affiliates | | $ | 126 |
| | $ | 113 |
| | $ | 358 |
| | $ | 319 |
|
We had balances with affiliates as follows: | | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| | (millions) |
| Phillips 66 (including its affiliates): | | | |
| Accounts receivable | $ | 398 | | | $ | 343 | |
| Other assets | $ | 7 | | | $ | 1 | |
| Accounts payable | $ | 163 | | | $ | 167 | |
| Accrued wages and benefits | $ | 32 | | | $ | — | |
| Other liabilities | $ | 28 | | | $ | — | |
| Long-term debt | $ | 100 | | | $ | — | |
| Enbridge (including its affiliates): | | | |
| Accounts receivable | $ | — | | | $ | 1 | |
| Accounts payable | $ | — | | | $ | 1 | |
| | | |
| | | |
| Unconsolidated affiliates: | | | |
| Accounts receivable | $ | 27 | | | $ | 16 | |
| Accounts payable | $ | 90 | | | $ | 87 | |
| | | |
4. Inventories
Inventories were as follows: | | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| | (millions) |
| Natural gas | $ | 20 | | | $ | 47 | |
| NGLs | 21 | | | 36 | |
| Total inventories | $ | 41 | | | $ | 83 | |
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| | (Millions) |
| Phillips 66 (including its affiliates): | | | |
| Accounts receivable | $ | 113 |
| | $ | 115 |
|
| Accounts payable | $ | 4 |
| | $ | 4 |
|
| Other assets | $ | 1 |
| | $ | 2 |
|
| Enbridge (including its affiliates): | | | |
| Accounts receivable | $ | 7 |
| | $ | 1 |
|
| Accounts payable | $ | 7 |
| | $ | 3 |
|
| Other assets | $ | — |
| | $ | 1 |
|
| Other liabilities | $ | — |
| | $ | 1 |
|
| Unconsolidated affiliates: | | | |
| Accounts receivable | $ | 18 |
| | $ | 18 |
|
| Accounts payable | $ | 46 |
| | $ | 41 |
|
| Other assets | $ | 3 |
| | $ | 5 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
6. Inventories
Inventories were as follows:
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| | (Millions) |
| Natural gas | $ | 32 |
| | $ | 28 |
|
| NGLs | 30 |
| | 44 |
|
| Total inventories | $ | 62 |
| | $ | 72 |
|
We recognize the lower of cost or marketnet realizable value adjustments when the carrying value of our inventories exceeds their estimated marketnet realizable value. These non-cash charges are a component of purchases of natural gas and NGLsrelated costs in the condensed consolidated statements of operations. We recognized nozero and $22 million lower of cost or marketnet realizable value adjustments duringfor the three and six months ended SeptemberJune 30, 2017 or September 30, 2016.2023, respectively. We recognized no lower of cost or marketnet realizable value adjustments duringfor the ninethree and six months ended SeptemberJune 30, 2017 and $3 million during the nine months ended September 30, 2016.2022.
7.
5. Property, Plant and Equipment
A summary of property, plant and equipment by classification is as follows: | | | | | | | | | | | | | | | | | |
| Depreciable
Life | | June 30, 2023 | | December 31, 2022 |
| | | | (millions) |
| Gathering and transmission systems | 20 — 50 Years | | $ | 7,955 | | | $ | 7,865 | |
| Processing, storage and terminal facilities | 35 — 60 Years | | 5,175 | | | 5,138 | |
| Other | 3 — 30 Years | | 545 | | | 563 | |
| Finance lease assets | 5 — 35 Years | | 32 | | | 32 | |
| Construction work in progress | | | 196 | | | 183 | |
| Property, plant and equipment | | | 13,903 | | | 13,781 | |
| Accumulated depreciation | | | (6,170) | | | (6,018) | |
| Property, plant and equipment, net | | | $ | 7,733 | | | $ | 7,763 | |
|
| | | | | | | | | |
| | Depreciable Life | | September 30,
2017 | | December 31,
2016 |
| | | | (Millions) |
| Gathering and transmission systems | 20 — 50 Years | | $ | 8,447 |
| | $ | 8,560 |
|
| Processing, storage and terminal facilities | 35 — 60 Years | | 5,107 |
| | 5,134 |
|
| Other | 3 — 30 Years | | 539 |
| | 502 |
|
| Construction work in progress | | | 288 |
| | 171 |
|
| Property, plant and equipment | | | 14,381 |
| | 14,367 |
|
| Accumulated depreciation | | | (5,455 | ) | | (5,298 | ) |
| Property, plant and equipment, net | | | $ | 8,926 |
| | $ | 9,069 |
|
InterestConstruction projects with capitalized on construction projects was $2 million and less than $1 million forinterest were immaterial during the threesix months ended SeptemberJune 30, 20172023 and 2016, respectively, and $4 million and less than $1 million for the nine months ended September 30, 2017 and 2016, respectively.2022.
Depreciation expense was $90 million and $91$88 million for the three months ended SeptemberJune 30, 20172023 and 2016,2022, respectively, and $272$179 million and $275$177 million for the ninesix months ended SeptemberJune 30, 20172023 and 2016,2022, respectively.
8. Goodwill6. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates: | | | | | | | | | | | | | | | | | |
| | | | Carrying Value as of |
| | Percentage
Ownership | | June 30, 2023 | | December 31, 2022 |
| | | | (millions) |
| DCP Sand Hills Pipeline, LLC | 66.67% | | $ | 1,637 | | | $ | 1,653 | |
| DCP Southern Hills Pipeline, LLC | 66.67% | | 705 | | | 713 | |
| Gulf Coast Express LLC | 25.00% | | 392 | | | 408 | |
| Front Range Pipeline LLC | 33.33% | | 187 | | | 191 | |
| Texas Express Pipeline LLC | 10.00% | | 88 | | | 91 | |
| Mont Belvieu 1 Fractionator | 20.00% | | 9 | | | 7 | |
| Discovery Producer Services LLC | 40.00% | | 208 | | | 219 | |
| Cheyenne Connector, LLC | 50.00% | | 141 | | | 143 | |
| Mont Belvieu Enterprise Fractionator | 12.50% | | 28 | | | 28 | |
| | | | | |
| | | | | |
| Other | Various | | 21 | | | 22 | |
| Total investments in unconsolidated affiliates | | | $ | 3,416 | | | $ | 3,475 | |
We performed our annual goodwill assessment during the third quarter of 2017 at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. As a result of our assessment, we concluded that the fair value of goodwill substantially exceeded its carrying value in our North reporting unit, the only reporting unit allocated goodwill included within our Gathering and Processing reportable segment and in our Marysville reporting unit included within our Logistics and Marketing reportable segment. For our Wholesale Propane reporting unit, which is included in our Logistics and Marketing reportable segment, the fair value exceeded the carrying value (including approximately $37 million of allocated goodwill) by less than 10%. We concluded that the entire amount of goodwill disclosed on the condensed consolidated balance sheet is recoverable.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
We primarily used a discounted cash flow analysis, supplemented by a market approach analysis, to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, terminal year multiples, and estimated future cash flows, including an estimate of operating and general and administrative costs. In estimating cash flows, we incorporate current market information (including forecasted volumes and commodity prices), as well as historical and other factors. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to goodwill impairment charges, which would be recognized in the period in which the carrying value exceeds fair value.
We expect that the fair value of our Wholesale Propane reporting unit will continue to exceed carrying value so long as our estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile propane prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. Changes to any one or combination of these factors, would result in changes to the reporting unit fair values discussed above which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations.
The carrying amount of goodwill in each of our reportable segments was as follows:
|
| | | | | | | | | | | |
| | September 30, 2017 |
| | (Millions) |
| | Gathering and Processing | | Logistics and Marketing | | Total |
| Balance, January 1, 2017 | $ | 164 |
| | $ | 72 |
| | $ | 236 |
|
| Dispositions | (5 | ) | | — |
| | (5 | ) |
| Balance, September 30, 2017 | $ | 159 |
| | $ | 72 |
| | $ | 231 |
|
9. Investments in Unconsolidated Affiliates
The following table summarizes our investments in unconsolidated affiliates:
|
| | | | | | | | | |
| | | | Carrying Value as of |
| | Percentage Ownership | | September 30,
2017 | | December 31,
2016 |
| | | | (Millions) |
| DCP Sand Hills Pipeline, LLC | 66.67% | | $ | 1,563 |
| | $ | 1,507 |
|
| Discovery Producer Services LLC | 40.00% | | 376 |
| | 385 |
|
| DCP Southern Hills Pipeline, LLC | 66.67% | | 741 |
| | 754 |
|
| Front Range Pipeline LLC | 33.33% | | 165 |
| | 165 |
|
| Texas Express Pipeline LLC | 10.00% | | 90 |
| | 93 |
|
| Panola Pipeline Company, LLC | 15.00% | | 24 |
| | 25 |
|
| Mont Belvieu Enterprise Fractionator | 12.50% | | 24 |
| | 23 |
|
| Mont Belvieu 1 Fractionator | 20.00% | | 13 |
| | 10 |
|
| Other | Various | | 6 |
| | 7 |
|
| Total investments in unconsolidated affiliates | | | $ | 3,002 |
| | $ | 2,969 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Earnings from investments in unconsolidated affiliates were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 | | |
| | (millions) |
| DCP Sand Hills Pipeline, LLC | $ | 78 | | | $ | 104 | | | $ | 165 | | | $ | 175 | | | |
| DCP Southern Hills Pipeline, LLC | 27 | | | 21 | | | 52 | | | 45 | | | |
| Gulf Coast Express LLC | 18 | | | 16 | | | 35 | | | 32 | | | |
| Front Range Pipeline LLC | 11 | | | 11 | | | 22 | | | 21 | | | |
| Texas Express Pipeline LLC | 5 | | | 5 | | | 10 | | | 10 | | | |
| Mont Belvieu 1 Fractionator | 4 | | | 3 | | | 8 | | | 7 | | | |
| Discovery Producer Services LLC | 1 | | | 3 | | | 7 | | | 9 | | | |
| Cheyenne Connector, LLC | 3 | | | 3 | | | 6 | | | 7 | | | |
| Mont Belvieu Enterprise Fractionator | 1 | | | 2 | | | 2 | | | 4 | | | |
| | | | | | | | | |
| Other | — | | | — | | | 1 | | | 1 | | | |
| Total earnings from unconsolidated affiliates | $ | 148 | | | $ | 168 | | | $ | 308 | | | $ | 311 | | | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, |
| Nine Months Ended September 30, |
| | 2017 | | 2016 |
| 2017 |
| 2016 |
| | (Millions) |
| DCP Sand Hills Pipeline, LLC | $ | 37 |
| | $ | 28 |
|
| $ | 105 |
|
| $ | 84 |
|
| Discovery Producer Services LLC | 14 |
| | 20 |
|
| 59 |
|
| 52 |
|
| DCP Southern Hills Pipeline, LLC | 10 |
| | 13 |
|
| 34 |
|
| 37 |
|
| Front Range Pipeline LLC | 5 |
| | 5 |
|
| 12 |
|
| 14 |
|
| Texas Express Pipeline LLC | 4 |
| | 2 |
|
| 7 |
|
| 6 |
|
| Mont Belvieu Enterprise Fractionator | 3 |
| | 4 |
|
| 10 |
|
| 12 |
|
| Mont Belvieu 1 Fractionator | 2 |
| | 2 |
|
| 6 |
|
| 7 |
|
| Other | (1 | ) | | 1 |
|
| 1 |
|
| 2 |
|
| Total earnings from unconsolidated affiliates | $ | 74 |
| | $ | 75 |
|
| $ | 234 |
|
| $ | 214 |
|
The following tables summarize the combined financial information of our investments in unconsolidated affiliates: | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 | | |
| | (millions) | | (millions) |
| Statements of operations: | | | | | | | | | |
| Operating revenue | $ | 541 | | | $ | 626 | | | $ | 1,136 | | | $ | 1,189 | | | |
| Operating expenses | $ | 214 | | | $ | 246 | | | $ | 436 | | | $ | 463 | | | |
| Net income | $ | 328 | | | $ | 380 | | | $ | 707 | | | $ | 724 | | | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (Millions) |
| Statements of operations: | | | | | | | |
| Operating revenue | $ | 358 |
| | $ | 335 |
| | $ | 1,063 |
| | $ | 971 |
|
| Operating expenses | $ | 164 |
| | $ | 136 |
| | $ | 464 |
| | $ | 390 |
|
| Net income | $ | 194 |
| | $ | 199 |
| | $ | 598 |
| | $ | 576 |
|
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| | (Millions) |
| Balance sheets: | | | |
| Current assets | $ | 242 |
| | $ | 232 |
|
| Long-term assets | 5,253 |
| | 5,274 |
|
| Current liabilities | (165 | ) | | (156 | ) |
| Long-term liabilities | (200 | ) | | (205 | ) |
| Net assets | $ | 5,130 |
| | $ | 5,145 |
|
10.7. Fair Value Measurement
Determination of Fair Value
Below is a general description of our valuation methodologies for derivative financial assets and liabilities which are measured at fair value. Fair values are generally based upon quoted market prices or prices obtained through external sources, where available. If listed market prices or quotes are not available, we determine fair value based upon a market quote, adjusted by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. These adjustments result in a fair value for each asset or liability under an “exit price” methodology, in line with how we believe a marketplace participant would value that asset or liability. Fair values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. These adjustments may include amounts to reflect counterparty credit quality, the effect of our own creditworthiness, and/or the liquidity of the market.
Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have near zero, or low, default rates and have equal credit quality. Therefore, an adjustment may be necessary to reflect
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
the credit quality of a specific counterparty to determine the fair value of the instrument. We record counterparty credit valuation adjustments on all derivatives that are in a net asset position as of the measurement date in accordance with our established counterparty credit policy, which takes into account any collateral margin that a counterparty may have posted with us as well as any letters of credit that they have provided.
Entity valuation adjustments are necessary to reflect the effect of our own credit quality on the fair value of our net liability positions with each counterparty. This adjustment takes into account any credit enhancements, such as collateral margin we may have posted with a counterparty, as well as any letters of credit that we have provided. The methodology to determine this adjustment is consistent with how we evaluate counterparty credit risk, taking into account our own credit rating, current credit spreads, as well as any change in such spreads since the last measurement date.
Liquidity valuation adjustments are necessary when we are not able to observe a recent market price for financial instruments that trade in less active markets for the fair value to reflect the cost of exiting the position. Exchange traded contracts are valued at market value without making any additional valuation adjustments and, therefore, no liquidity reserve is applied. For contracts other than exchange traded instruments, we mark our positions to the midpoint of the bid/ask spread, and record a liquidity reserve based upon our total net position. We believe that such practice results in the most reliable fair value measurement as viewed by a market participant.
We manage our derivative instruments on a portfolio basis and the valuation adjustments described above are calculated on this basis. We believe that the portfolio level approach represents the highest and best use for these assets as there are benefits inherent in naturally offsetting positions within the portfolio at any given time, and this approach is consistent with how a market participant would view and value the assets and liabilities. Although we take a portfolio approach to managing these assets/liabilities, in order to reflect the fair value of any one individual contract within the portfolio, we allocate all valuation adjustments down to the contract level, to the extent deemed necessary, based upon either the notional contract volume, or the contract value, whichever is more applicable.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. While we believe that our valuation methods are appropriate and consistent with other market participants, we recognize that the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. We review our fair value policies on a regular basis taking into consideration changes in the marketplace and, if necessary, will adjust our policies accordingly. See Note 12 - Risk Management and Hedging Activities.
Valuation Hierarchy
Our fair value measurements are grouped into a three-level valuation hierarchy and are categorized in their entirety in the same level of the fair value hierarchy as the lowest level input that is significant to the entire measurement. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows.
•Level 1 — inputs are unadjusted quoted prices for identical assets or liabilities in active markets.
•Level 2 — inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•Level 3 — inputs are unobservable and considered significant to the fair value measurement.
A financial instrument’s categorization within the hierarchy is based upon the level of judgment involved in the most significant input in the determination of the instrument’s fair value. Following is a description of the valuation methodologies used as well as the general classification of such instruments pursuant to the hierarchy.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Commodity Derivative Assets and Liabilities
We enter into a variety of derivative financial instruments, which may include exchange traded instruments (such as New York Mercantile Exchange, or NYMEX, crude oil or natural gas futures) or over-the-counter, or OTC, instruments (such as natural gas contracts, crude oil or NGL swaps). The exchange traded instruments are generally executed with a highly rated broker dealer serving as the clearinghouse for individual transactions.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Six Months Ended June 30, 2023 and 2022
Our activities expose us to varying degrees of commodity price risk. To mitigate a portion of this risk and to manage commodity price risk related primarily to owned natural gas storage and pipeline assets, we engage in natural gas asset based trading and marketing, and we may enter into natural gas and crude oil derivatives to lock in a specific margin when market conditions are favorable. A portion of this may be accomplished through the use of exchange traded derivative contracts. Such instruments are generally classified as Level 1 since the value is equal to the quoted market price of the exchange traded instrument as of our balance sheet date, and no adjustments are required. Depending upon market conditions and our strategy we may enter into exchange traded derivative positions with a significant time horizon to maturity. Although such instruments are exchange traded, market prices may only be readily observable for a portion of the duration of the instrument. In order to calculate the fair value of these instruments, readily observable market information is utilized to the extent it is available; however, in the event that readily observable market data is not available, we may interpolate or extrapolate based upon observable data. In instances where we utilize an interpolated or extrapolated value, and it is considered significant to the valuation of the contract as a whole, we would classify the instrument within Level 3.
We also engage in the business of trading energy related products and services, which exposes us to market variables and commodity price risk. We may enter into physical contracts or financial instruments with the objective of realizing a positive margin from the purchase and sale of these commodity-based instruments. We may enter into derivative instruments for NGLs or other energy related products, primarily using the OTC derivative instrument markets, which are not as active and liquid as exchange traded instruments. Market quotes for such contracts may only be available for short dated positions (up to six months), and an active market itself may not exist beyond such time horizon. Contracts entered into with a relatively short time horizon for which prices are readily observable in the OTC market are generally classified within Level 2. Contracts entered into with a longer time horizon, for which prices are not readily observable in the OTC marketwe internally generate a forward curve to value such instruments, are generally classified within Level 3. The internally generated curve may utilize a variety of assumptions including, but not limited to, data obtained from third-party pricing services, historical and future expected relationship of NGL prices to crude oil prices, the knowledge of expected supply sources coming online, expected weather trends within certain regions of the United States, and the future expected demand for NGLs.
Each instrument is assigned to a level within the hierarchy at the end of each financial quarter depending upon the extent to which the valuation inputs are observable. Generally, an instrument will move toward a level within the hierarchy that requires a lower degree of judgment as the time to maturity approaches, and as the markets in which the asset trades will likely become more liquid and prices more readily available in the market, thus reducing the need to rely upon our internally developed assumptions. However, the level of a given instrument may change, in either direction, depending upon market conditions and the availability of market observable data.
Interest Rate Derivative Assets and Liabilities
We periodically use interest rate swap agreements as part of our overall capital strategy. TheseThe following table presents the financial instruments effectively exchange a portion of our fixed-rate debt for floating rate debt or floating rate debt for fixed-rate debt. The swaps are generally priced based upon a London Interbank Offered Rate, or LIBOR, instrument with similar duration, adjusted by the credit spread between our company and the LIBOR instrument. Given that a portion of the swap value is derived from the credit spread, which may be observed by comparing similar assets in the market, these instruments are classified within Level 2. Default risk on either side of the swap transaction is also considered in the valuation. We record counterparty credit and entity valuation adjustments in the valuation of interest rate swaps; however, these reserves are not considered to be a significant input to the overall valuation.
Nonfinancial Assets and Liabilities
We utilize fair value to perform impairment tests as required on our property, plant and equipment, goodwill, and other long-lived intangible assets. Assets and liabilities acquired in third party business combinations are recorded at their fair value as of the date of acquisition. The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified within Level 3 in the event that we were required to measure and record such assetscarried at fair value within ouron a recurring basis as of June 30, 2023 and December 31, 2022, by condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costsbalance sheet caption and by valuation hierarchy, as described above:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2023 | | December 31, 2022 |
| | Level 1 | | Level 2 | | Level 3 | | Total
Carrying
Value | | Level 1 | | Level 2 | | Level 3 | | Total
Carrying
Value |
| | (millions) |
| Current assets: | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | 1 | | | $ | 49 | | | $ | 10 | | | $ | 60 | | | $ | 2 | | | $ | 121 | | | $ | 17 | | | $ | 140 | |
| Short-term investments (a) | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 1 | | | $ | — | | | $ | 1 | |
| | | | | | | | | | | | | | | |
| Long-term assets: | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | — | | | $ | 16 | | | $ | 1 | | | $ | 17 | | | $ | — | | | $ | 23 | | | $ | 3 | | | $ | 26 | |
| Investments in marketable securities (a) | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 42 | | | $ | — | | | $ | — | | | $ | 42 | |
| Current liabilities: | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | (1) | | | $ | (31) | | | $ | (4) | | | $ | (36) | | | $ | (4) | | | $ | (142) | | | $ | (2) | | | $ | (148) | |
| | | | | | | | | | | | | | | |
| Long-term liabilities: | | | | | | | | | | | | | | | |
| Commodity derivatives | $ | — | | | $ | (12) | | | $ | (1) | | | $ | (13) | | | $ | — | | | $ | (32) | | | $ | (3) | | | $ | (35) | |
| | | | | | | | | | | | | | | |
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition,(a) zero and would generally be classified$1 million recorded within Level 3.
During the nine months ended September 30, 2017, we recognized impairments of property, plant and equipment, intangible"Other" current assets and investment in unconsolidated affiliates of $48zero and $42 million in our condensed consolidated statement of operations as summarized in the table below. Our impairment determinations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilizedrecorded within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.
The following tables present the carrying value of assets measured at fair value on a non-recurring basis, by consolidated balance sheet caption and by valuation hierarchy,"Other long-term assets" as of and for the three and nine months ended SeptemberJune 30, 2017:
|
| | | | | | | | | | | | | | | | | | | |
| | Net Carrying Value | | Fair Value Measurements Using | | Asset Impairments |
| | | Level 1 | | Level 2 | | Level 3 | |
| | (millions) |
| Three and Nine Months Ended September 30, 2017 | | | | | | | | | |
| Property, plant and equipment | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 14 |
| | $ | 26 |
|
| Intangible assets | 11 |
| | — |
| | — |
| | 11 |
| | 21 |
|
| Investment in unconsolidated affiliates | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Total non-recurring assets at fair value | $ | 26 |
| | $ | — |
| | $ | — |
| | $ | 26 |
| | $ | 48 |
|
On January 3, 2017, the Chicago Mercantile Exchange ("CME") modified its exchange rules to characterize daily variation margin amounts as "final settlement" values. The modified rule ("CME Rule 814") impacts derivative financial instruments traded on exchanges administered by the CME, including the New York Mercantile Exchange. As a result of this rule change, we are reporting the affected derivative instruments on a net basis on our balance sheet. The netting process results in the elimination of offsetting derivative assets, derivative liabilities and associated collateral cash deposits and related amounts as if the underlying derivative instruments had settled on the balance sheet date. Through December 31, 2016, we historically reported such derivatives and associated collateral balances on a gross basis. Derivative transactions and associated collateral balances cleared on exchanges other than the CME continue to be reported on a gross basis.
The following table presents the financial instruments carried at fair value as of September 30, 20172023 and December 31, 2016, by condensed consolidated balance sheet caption and by valuation hierarchy, as described above: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total Carrying Value | | Level 1 | | Level 2 | | Level 3 | | Total Carrying Value |
| | (Millions) |
| Current assets: | | | | | | | | | | | | | | | |
| Commodity derivatives (a) | $ | 9 |
| | $ | 21 |
| | $ | 2 |
| | $ | 32 |
| | $ | 5 |
| | $ | 28 |
| | $ | 9 |
| | $ | 42 |
|
| Short-term investments (b) | $ | 310 |
| | $ | — |
| | $ | — |
| | $ | 310 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Long-term assets: | | | | | | | | | | | | | | | |
| Commodity derivatives (c) | $ | 1 |
| | $ | 2 |
| | $ | 1 |
| | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 5 |
| | $ | 5 |
|
| Current liabilities: | | | | | | | | | | | | | | | |
| Commodity derivatives (d) | $ | (6 | ) | | $ | (28 | ) | | $ | (8 | ) | | $ | (42 | ) | | $ | (11 | ) | | $ | (57 | ) | | $ | (23 | ) | | $ | (91 | ) |
| Long-term liabilities: | | | | | | | | | | | | | | | |
| Commodity derivatives (e) | $ | (2 | ) | | $ | (6 | ) | | $ | (2 | ) | | $ | (10 | ) | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
| |
(a) | Included in current unrealized gains on derivative instruments in our condensed consolidated balance sheets. |
| |
(b) | Includes short-term money market securities included in cash and cash equivalents in our condensed consolidated balance sheets. |
| |
(c) | Included in long-term unrealized gains on derivative instruments in our condensed consolidated balance sheets. |
| |
(d) | Included in current unrealized losses on derivative instruments in our condensed consolidated balance sheets. |
| |
(e) | Included in long-term unrealized losses on derivative instruments in our condensed consolidated balance sheets. |
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Changes in Levels 1 and 2 Fair Value Measurements
The determination to classify a financial instrument within Level 1 or Level 2 is based upon the availability of quoted prices for identical or similar assets and liabilities in active markets. Depending upon the information readily observable in the market, and/or the use of identical or similar quoted prices, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. To qualify as a transfer, the asset or liability must have existed in the previous reporting period and moved into a different level during the current period. In the event that there is a movement between the classification of an instrument as Level 1 or 2, the transfer would be reflected in a table as Transfers into or out of Level 1 and Level 2. During the three and nine months ended September 30, 2017 and 2016, there were no transfers between Level 1 and Level 2 of the fair value hierarchy.2022, respectively.
Changes in Level 3 Fair Value Measurements
The tablestable below illustrateillustrates a rollforward of the amounts included in our condensed consolidated balance sheets for derivative financial instruments that we have classified within Level 3. Since financial instruments classified as Level 3 typically include a combination of observable components (that is, components that are actively quoted and can be validated to external sources) and unobservable components, the gains and losses in the table below may include changes in fair value due in part to observable market factors, or changes to our assumptions on the unobservable components. Depending upon the information readily observable in the market, and/or the use of unobservable inputs, which are significant to the overall valuation, the classification of any individual financial instrument may differ from one measurement date to the next. The significant unobservable inputs used in determining fair value include adjustments by other market-based or independently sourced market data such as historical commodity volatilities, crude oil future yield curves, and/or counterparty specific considerations. In the event that there is a movement to/from the classification of an instrument as Level 3, we would reflect such items in the table below within the “Transfers into/out of Level 3” captions.
We manage our overall risk at the portfolio level and in the execution of our strategy, we may use a combination of financial instruments, which may be classified within any level. Since Level 1 and Level 2 risk management instruments are not included in the rollforward below, the gains or losses in the table do not reflect the effect of our total risk management activities.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Commodity Derivative Instruments |
| | Current
Assets | | Long-Term
Assets | | Current
Liabilities | | Long-Term
Liabilities |
| | (millions) |
| Three months ended June 30, 2023 (a): | | | | | | | |
| Beginning balance | $ | 15 | | | $ | 1 | | | $ | (1) | | | $ | (1) | |
| Net unrealized gains (losses) included in earnings | 6 | | | — | | | (6) | | | (1) | |
| | | | | | | |
| Transfers out of Level 3 | (9) | | | (1) | | | 4 | | | 1 | |
| Settlements | (2) | | | 1 | | | (1) | | | — | |
| | | | | | | |
| | | | | | | |
| Ending balance | $ | 10 | | | $ | 1 | | | $ | (4) | | | $ | (1) | |
| Net unrealized gains (losses) on derivatives still held included in earnings | $ | 4 | | | $ | — | | | $ | (3) | | | $ | — | |
| Three months ended June 30, 2022 (a): | | | | | | | |
| Beginning balance | $ | 2 | | | $ | 4 | | | $ | (10) | | | $ | (5) | |
| Net unrealized gains included in earnings | 3 | | | 2 | | | 5 | | | — | |
| | | | | | | |
| Transfers out of Level 3 | (1) | | | — | | | 2 | | | 1 | |
| Settlements | (1) | | | — | | | — | | | — | |
| | | | | | | |
| | | | | | | |
| Ending balance | $ | 3 | | | $ | 6 | | | $ | (3) | | | $ | (4) | |
| Net unrealized gains (losses) on derivatives still held included in earnings | $ | 3 | | | $ | 3 | | | $ | 5 | | | $ | (6) | |
|
| | | | | | | | | | | | | | | |
| | Commodity Derivative Instruments |
| | Current Assets | | Long-Term Assets | | Current Liabilities | | Long-Term Liabilities |
| | (Millions) |
| Three months ended September 30, 2017 (a): | | | | | | | |
| Beginning balance | $ | 7 |
| | $ | 2 |
| | $ | (2 | ) | | $ | (3 | ) |
| Net unrealized gains (losses) included in earnings (b) | — |
| | 2 |
| | (26 | ) | | — |
|
| Transfers out of Level 3 (c) | — |
| | — |
| | 2 |
| | — |
|
| Settlements | — |
| | — |
| | 2 |
| | — |
|
| CME Rule 814 adjustment | (5 | ) | | (3 | ) | | 16 |
| | 1 |
|
| Ending balance | $ | 2 |
| | $ | 1 |
| | $ | (8 | ) | | $ | (2 | ) |
| Net unrealized gains (losses) on derivatives still held included in earnings (b) | $ | 3 |
| | $ | 2 |
| | $ | (22 | ) | | $ | — |
|
| Three months ended September 30, 2016 (a): | | | | | | | |
| Beginning balance | $ | 5 |
| | $ | 2 |
| | $ | (8 | ) | | $ | (2 | ) |
| Net unrealized gains included in earnings (b) | 2 |
| | — |
| | — |
| | 1 |
|
| Transfers out of Level 3 (c) | (2 | ) | | — |
| | 2 |
| | — |
|
| Settlements | (1 | ) | | — |
| | 1 |
| | — |
|
| Ending balance | $ | 4 |
| | $ | 2 |
| | $ | (5 | ) | | $ | (1 | ) |
| Net unrealized gains on derivatives still held included in earnings (b) | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| | Commodity Derivative Instruments |
| | Current
Assets | | Long-Term
Assets | | Current
Liabilities | | Long-Term
Liabilities |
| | (millions) |
| Six months ended June 30, 2023 (a): | | | | | | | |
| Beginning balance | $ | 17 | | | $ | 3 | | | $ | (2) | | | $ | (3) | |
| Net unrealized gains (losses) included in earnings | 5 | | | — | | | (2) | | | 1 | |
| | | | | | | |
| Transfers out of Level 3 | (8) | | | (2) | | | 1 | | | 1 | |
| Settlements | (4) | | | — | | | (1) | | | — | |
| | | | | | | |
| | | | | | | |
| Ending balance | $ | 10 | | | $ | 1 | | | $ | (4) | | | $ | (1) | |
| Net unrealized gains (losses) on derivatives still held included in earnings | $ | 6 | | | $ | 1 | | | $ | (3) | | | $ | (1) | |
| Six months ended June 30, 2022 (a): | | | | | | | |
| Beginning balance | $ | — | | | $ | 2 | | | $ | (3) | | | $ | (4) | |
| Net unrealized gains (losses) included in earnings | 3 | | | 6 | | | (6) | | | (6) | |
| | | | | | | |
| Transfers out of Level 3 | — | | | (2) | | | 4 | | | 6 | |
| Settlements | — | | | — | | | 2 | | | — | |
| | | | | | | |
| | | | | | | |
| Ending balance | $ | 3 | | | $ | 6 | | | $ | (3) | | | $ | (4) | |
| Net unrealized gains (losses) on derivatives still held included in earnings | $ | 3 | | | $ | 4 | | | $ | (2) | | | $ | (3) | |
|
| | | | | | | | | | | | | | | |
| | Commodity Derivative Instruments |
| | Current
Assets | | Long-Term
Assets | | Current
Liabilities | | Long-Term
Liabilities |
| | (Millions) |
| Nine months ended September 30, 2017 (a): | | | | | | | |
| Beginning balance | $ | 9 |
| | $ | 5 |
| | $ | (23 | ) | | $ | — |
|
| Net unrealized gains (losses) included in earnings (b) | 4 |
| | (1 | ) | | (20 | ) | | (3 | ) |
| Transfers out of Level 3 (c) | (4 | ) | | — |
| | 12 |
| | — |
|
| Settlements | (2 | ) | | — |
| | 7 |
| | — |
|
| CME Rule 814 adjustment | (5 | ) | | (3 | ) | | 16 |
| | 1 |
|
| Ending balance | $ | 2 |
| | $ | 1 |
| | $ | (8 | ) | | $ | (2 | ) |
| Net unrealized gains (losses) on derivatives still held included in earnings (b) | $ | 7 |
| | $ | (1 | ) | | $ | (21 | ) | | $ | (2 | ) |
| Nine months ended September 30, 2016 (a): | | | | | | | |
| Beginning balance | $ | 35 |
| | $ | 4 |
| | $ | (23 | ) | | $ | (6 | ) |
| Net unrealized (losses) gains included in earnings (b) | (3 | ) | | (2 | ) | | 12 |
| | 5 |
|
| Transfers out of Level 3 (c) | (2 | ) | | — |
| | 3 |
| | — |
|
| Settlements | (26 | ) | | — |
| | 3 |
| | — |
|
| Ending balance | $ | 4 |
| | $ | 2 |
| | $ | (5 | ) | | $ | (1 | ) |
| Net unrealized gains (losses) on derivatives still held included in earnings (b) | $ | 2 |
| | $ | 1 |
| | $ | (4 | ) | | $ | 5 |
|
| |
(a) | There were no purchases, issuances or sales of derivatives or transfers into Level 3 for the three and nine months ended September 30, 2017 and 2016.
|
| |
(b) | Represents the amount of unrealized gains or losses for the period, included in trading and marketing gains (losses), net. |
| |
(c) | Amounts transferred out of Level 3 are reflected at fair value at the end of the period. |
Quantitative Information and Fair Value Sensitivities Related to Level 3 Unobservable Inputs
We utilize the market approach to measure the fair value of our commodity contracts. The significant unobservable inputs used in this approach to fair value are longer dated price quotes. Our sensitivity to these longer dated forward curve prices are presented in the table below. Significant changes in any of those inputs in isolation would result in significantly different fair value measurements, depending on our short or long position in contracts. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2023 | | |
| Product Group | Fair Value | | Valuation Techniques | | Unobservable Input | | Forward
Curve Range | | Weighted Average (a) | | |
| | (millions) | | | | | | |
| Assets | | | | | | | | | | | |
| NGLs | $ | 10 | | | Market approach | | Longer dated forward curve prices | | $0.24-$1.29 | | $0.68 | | Per gallon |
| Natural gas | $ | 1 | | | Market approach | | Longer dated forward curve prices | | $2.73-$4.71 | | $1.96 | | Per MMBtu |
| Liabilities | | | | | | | | | | | |
| NGLs | $ | (4) | | | Market approach | | Longer dated forward curve prices | | $0.24-$1.33 | | $0.81 | | Per gallon |
| Natural gas | $ | (1) | | | Market approach | | Longer dated forward curve prices | | $2.73-$4.71 | | $3.16 | | Per MMBtu |
(a) Unobservable inputs were weighted by the instrument's notional amounts. |
| | | | | | | |
| | September 30, 2017 | | |
| Product Group | Fair Value | | Forward Curve Range | | |
| | (Millions) | | |
| Assets | | | | | |
| NGLs | $ | 3 |
| | $0.28-$1.22 | | Per gallon |
| Liabilities | | | | | |
| NGLs | $ | (10 | ) | | $0.21-$1.22 | | Per gallon |
Estimated Fair Value of Financial Instruments
Valuation of a contract’sWe utilize fair value is validated by an internal group independent of the marketing group. While common industry practices are used to develop valuation techniques, changesperform impairment tests as required on our long-lived assets and equity investments in pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. When available, quoted market prices or prices obtained through external sources areunconsolidated affiliates. The inputs used to determine a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available,such fair value is determinedare primarily based on pricing modelsupon internally developed primarily from historical and expected relationship with quoted market prices.cash flow
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
Values are adjusted to reflect the credit risk inherentmodels and would generally be classified within Level 3 in the transactionevent that we were required to measure and record such assets at fair value within our condensed consolidated financial statements. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the potential impact of liquidating open positions incontractually stipulated condition, and would generally be classified within Level 3.
During the three and six months ended June 30, 2023, we recognized a $10 million impairment associated with an orderly manner over a reasonable time period under current conditions. Changes in market pricesoffice lease that we vacated and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.
The fair valuepartially sublet as part of our interest rate swaps, if any, and commodity non-trading derivativesintegration with Phillips 66 during the three months ended June 30, 2023. This impairment is based on prices supported by quoted market pricesrecorded within restructuring costs in our condensed consolidated statements of operations and other, external sources and prices based on models and other valuation methods. The “prices supported by quoted market prices and other external sources” category includesnet within our interest rate swaps, if any, our NGL and crude oil swaps and our NYMEX positions in natural gas. In addition, this category includes our forward positions in natural gas for which our forward price curves are obtained from a third party pricing service and then validated through an internal process which includes the usecondensed consolidated statements of independent broker quotes. This category also includes our forward positions in NGLs at points for which OTC broker quotes for similar assets or liabilities are available for the full termcash flows.
Estimated Fair Value of the instrument. This category also includes “strip” transactions whose pricing inputs are directly or indirectly observable from external sources and then modeled to daily or monthly prices as appropriate. The “prices based on models and other valuation methods” category includes the value of transactions for which inputs to the fair value of the instrument are unobservable in the marketplace and are considered significant to the overall fair value of the instrument. The fair value of these instruments may be based upon an internally developed price curve, which was constructed as a result of the long dated nature of the transaction or the illiquidity of the specific market point.
We have determined fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.Financial Instruments
The fair value of accounts receivable and accounts payable and short-term borrowings are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Derivative instruments are carried at fair value.
We determine the fair value of our fixed-rate senior notes and junior subordinated notes based on quotes obtained from bond dealers. We determine the fairThe carrying value of borrowings under our revolving credit facility based upon the discounted present value of expected future cash flows, taking into account the difference between the contractual borrowing spreadCredit Agreement and the spread for similar credit facilities available in the marketplace.Securitization Facility approximate fair value as their interest rates are based on prevailing market interest rates. We classify the fair values of our outstanding debt balances within Level 2 of the valuation hierarchy. As of SeptemberJune 30, 20172023 and December 31, 2016,2022, the carrying value and fair value of our total debt, including current maturities, were as follows:
|
| | | | | | | | | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
| | | Carrying Value (a) | | Fair Value | | Carrying Value (a) | | Fair Value |
| | (Millions) |
| | | | | | | | | |
| Total debt | | $ | 5,235 |
| | $ | 5,365 |
| | $ | 5,430 |
| | $ | 5,395 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2023 | | December 31, 2022 |
| | | Carrying Value (a) | | Fair Value | | Carrying Value (a) | | Fair Value |
| | (millions) |
| | | | | | | | |
| Total debt | | $ | 5,013 | | | $ | 4,976 | | | $ | 4,874 | | | $ | 4,772 | |
(a) Excludes unamortized issuance costs.
DCP MIDSTREAM, LPcosts and finance lease liabilities.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
11.8. Debt
|
| | | | | | | |
| | September 30,
2017 | | December 31,
2016 |
| | (Millions) |
| Senior notes: | | | |
| Issued November 2012, interest at 2.500% payable semi-annually, due December 2017 | $ | 500 |
| | $ | 500 |
|
| Issued February 2009, interest at 9.750% payable semiannually, due March 2019 (a) | 450 |
| | 450 |
|
| Issued March 2014, interest at 2.700% payable semi-annually, due April 2019 | 325 |
| | 325 |
|
| Issued March 2010, interest at 5.350% payable semiannually, due March 2020 (a) | 600 |
| | 600 |
|
| Issued September 2011, interest at 4.750% payable semiannually, due September 2021 | 500 |
| | 500 |
|
| Issued March 2012, interest at 4.950% payable semi-annually, due April 2022 | 350 |
| | 350 |
|
| Issued March 2013, interest at 3.875% payable semi-annually, due March 2023 | 500 |
| | 500 |
|
| Issued August 2000, interest at 8.125% payable semi-annually, due August 2030 (a) | 300 |
| | 300 |
|
| Issued October 2006, interest at 6.450% payable semi-annually, due November 2036 | 300 |
| | 300 |
|
| Issued September 2007, interest at 6.750% payable semi-annually, due September 2037 | 450 |
| | 450 |
|
| Issued March 2014, interest at 5.600% payable semi-annually, due April 2044 | 400 |
| | 400 |
|
| Junior subordinated notes: | | | |
| Issued May 2013, interest at 5.850% payable semi-annually, due May 2043 | 550 |
| | 550 |
|
| Credit facility with financial institutions: | | | |
| Revolving credit facility, weighted-average variable interest rate of 2.010%, as of December 31, 2016, due May 2019 | — |
| | 195 |
|
| Fair value adjustments related to interest rate swap fair value hedges (a) | 23 |
| | 24 |
|
| Unamortized issuance costs | (24 | ) | | (23 | ) |
| Unamortized discount | (13 | ) | | (14 | ) |
| Total debt | 5,211 |
| | 5,407 |
|
| Current maturities of long-term debt | 500 |
| | 500 |
|
| Total long-term debt | $ | 4,711 |
| | $ | 4,907 |
|
(a) The swaps associated with this debt were previously terminated. The remaining long-term fair valueOn May 19, 2023, we redeemed, at par, prior to maturity all $550 million of approximately
$23 million related to the swaps is being amortized as a reduction to interest expense through 2019, 2020 and 2030, the original maturity datesaggregate principal amount outstanding of the debt.
our 5.850% Junior Notes due May 2043, using borrowings under our Credit Facility with Financial Institutionsand Securitization Facility.
In February 2017,Senior Notes Redemption
On March 15, 2023, we further amendedrepaid, at par, all $500 million of aggregate principal amount outstanding of our $1.25 billion senior unsecured revolving credit agreement that matures on May 1, 2019, or the3.875% Senior Notes due March 15, 2023, using borrowings under our Credit Facility and Securitization Facility.
Intercompany Credit Agreement
On June 15, 2023, we and our wholly owned subsidiary, DCP Midstream Operating, LP, entered into a new five-year revolving Intercompany Credit Agreement with Phillips 66, as lender. The Intercompany Credit Agreement provides up to $1 billion of borrowing capacity, with an option to increase the commitment by an aggregate commitments underprincipal amount of up to $500 million, subject to lender approval. At our election, the unsecured revolving credit facility to approximately $1.4 billion. TheIntercompany Credit Agreement is used for working capital requirements and other general partnership purposes including acquisitions.
The Credit Agreement allows for unrestricted cash and cash equivalents to be netted against consolidated indebtedness for purposes of calculatingbears interest at either the Partnership’s Consolidated Leverage Ratio (as definedadjusted term SOFR rate or the base rate plus, in the Credit Agreement). Additionally, under the Credit Agreement, the maximum Consolidated Leverage Ratio of the Partnership as of the end of any fiscal quarter shall not exceed: (a) 5.75 to 1.0 for the quarters ending March 31, 2017 through December 31, 2017, (b) 5.50 to 1.0 for the quarter ending March 31, 2018, (c) 5.25 to 1.0 for the quarter ending June 30, 2018, and (d) 5.00 to 1.0 for the quarters thereafter; provided that, if there is a Qualified Acquisition (as defined in the Credit Agreement) during any fiscal quarter ending June 30, 2018 or thereafter, the maximum Consolidated Leverage Ratio shall not exceed 5.50 to 1.0 at the end of such quarter and at the end of the two fiscal quarters immediately thereafter.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Oureach case, an applicable margin based on our credit rating. A ratings-based pricing grid determines our cost of borrowing under the Intercompany Credit Agreement is determined by a ratings-based pricing grid.Agreement. Indebtedness under the Intercompany Credit Agreement bears interest at either: (1) LIBOR,SOFR, plus an applicable margin of 1.45%1.075% based on our current credit rating;rating, plus an adjustment of 0.10%; or (2) (a) the base rate, which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the LIBORSOFR Market Index rate plus 1%1.00%, plus (b) an applicable margin of 0.45%0.075% based on our current credit rating. TheBased on our current credit rating, the Intercompany Credit Agreement incurs an annual facility fee of 0.3% based on our current credit rating. This fee is paid on drawn0.175%.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and undrawn portions of the approximately $1.4 billion revolving credit facility.Six Months Ended June 30, 2023 and 2022
As of SeptemberJune 30, 2017,2023, we had unused borrowing capacity of $1,373$900 million, net of $25$100 million of outstanding borrowings, under the Intercompany Credit Agreement, of which $900 million would have been available to borrow for working capital and other general partnership purposes based on the financial covenants set forth in the Intercompany Credit Agreement. Except in the case of a default, amounts borrowed under our Intercompany Credit Agreement will not become due prior to the June 15, 2028 maturity date.
Credit Agreement
We are party to a $1.4 billion unsecured revolving Credit Facility governed by the Credit Agreement that bears interest at either the term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. The Credit Agreement matures on March 18, 2027. The Credit Agreement 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.
As of June 30, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 million of letters of credit, under the Credit Agreement. Our borrowing capacity may be limited byAgreement, of which $548 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. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by $1,373 million as of September 30, 2017. Except in the case of a default, amounts borrowed under our Credit Agreement will not become due prior to the May 1, 2019March 18, 2027 maturity date.
Accounts Receivable Securitization Facility
Senior NotesThe Securitization Facility provides for up to $350 million of borrowing capacity through August 2024 at an adjusted SOFR rate and Junior Subordinated Notesincludes an uncommitted option to increase the total commitments under the Securitization Facility by up to an additional $400 million. Under this Securitization Facility, certain of the Partnership’s wholly owned subsidiaries sell or contribute receivables to another of the Partnership’s consolidated subsidiaries, DCP Receivables, a bankruptcy-remote special purpose entity created for the sole purpose of the Securitization Facility.
Our senior notes and junior subordinated notes, collectively referred to as our debt securities, mature and become payable on their respective due dates, and are not subject to any sinking fund or mandatory redemption provisions. The senior notes are senior unsecured obligations that are guaranteed by the Partnership and rank equally in a rightAs of payment with our other senior unsecured indebtedness, including indebtedness under our Credit Agreement, and the junior subordinated notes are unsecured and rank subordinate in right of payment to allJune 30, 2023, DCP Receivables had approximately $785 million of our existing and future senior indebtedness. The debt securities include an optional redemption whereby we may elect to redeemaccounts receivable securing borrowings of $280 million under the notes, in whole or in part from time-to-time for a premium. Additionally, we may defer the payment of all or part of the interest on the junior subordinated notes for one or more periods up to five consecutive years. The underwriters’ fees and related expenses are recorded in our condensed consolidated balance sheets within the carrying amount of long-term debt and will be amortized over the term of the notes.
Securitization Facility.
The maturities of our long-term debt as of June 30, 2023 are as follows:
| | | | | |
| | Debt
Maturities |
| | (millions) |
| 2023 | $ | — | |
| 2024 | 280 | |
| 2025 | 825 | |
| 2026 | — | |
| 2027 | 1,350 | |
| Thereafter | 2,550 | |
| Total debt | $ | 5,005 | |
|
| | | |
| | Debt Maturities |
| | (Millions) |
| 2018 | $ | — |
|
| 2019 | 775 |
|
| 2020 | 600 |
|
| 2021 | 500 |
|
| 2022 | 350 |
|
| Thereafter | 2,500 |
|
| Total long-term debt | $ | 4,725 |
|
12.9. Risk Management and Hedging Activities
Our operations expose us to a variety of risks including but not limited to changes in the prices of commodities that we buy or sell, changes in interest rates, and the creditworthiness of each of our counterparties. We manage certain of these exposures with either physical or financial transactions. We have established a comprehensive risk management policy and a risk management committee or the Risk(the “Risk Management Committee,Committee”), to monitor and manage market risks associated with commodity prices and counterparty credit. The Risk Management Committee is composed of senior executives who receive regular briefings on positions and exposures, credit exposures and overall risk management in the context of market activities. The Risk Management Committee is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits. The following describes each of the risks that we manage.
Commodity Price Risk
Our portfolio of commodity derivative activity is primarily accounted for using the mark-to-market method of accounting; however, depending upon our risk profile and objectives, in certain limited cases, we may execute transactions that qualify for the hedge method of accounting. The risks, strategies and instruments used to mitigate such risks, as well as the method of accounting are discussed and summarized below.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
Natural Gas Asset Based Trading and Marketing
Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-market accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.
Commodity Cash Flow Hedges
In order for our natural gas storage facility to remain operational, a minimum level of base gas must be maintained in each storage cavern, which is capitalized on our condensed consolidated balance sheets as a component of property, plant and equipment, net. During construction or expansion of our storage caverns, we may execute a series of derivative financial instruments to mitigate a portion of the risk associated with the forecasted purchase of natural gas when we bring the storage caverns into operation. These derivative financial instruments may be designated as cash flow hedges. While the cash paid upon settlement of these hedges economically fixes the cash required to purchase base gas, the deferred losses or gains would remain in accumulated other comprehensive income, or AOCI, until the cavern is emptied and the base gas is sold. The balance in AOCI of our previously settled base gas cash flow hedges was in a loss position of $6 million as of September 30, 2017.
Commodity Cash Flow Protection Activities
We are exposed to the impact of market fluctuations in the prices of natural gas, NGLs and condensate as a result of our gathering, processing, sales and storage activities. For gathering, processing and storage services, we may receive cash or commodities as payment for these services, depending on the contract type. We may enter into derivative financial instruments to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices associated with our gathering, processing and sales activities, thereby stabilizing our cash flows. Our derivative financial instruments used to mitigate a portion of the risk of weakening natural gas, NGL and condensate prices extend through the first quarter of 2019. The commodity derivative instruments used for our hedging programs are a combination of direct NGL product, crude oil and natural gas hedges. Due to the limited liquidity and tenor of the NGL derivative market, we may use crude oil swaps to mitigate a portion of the commodity price risk exposure for NGLs. Historically, prices of NGLs have generally been related to crude oil prices; however, there are periods of time when NGL pricing may be at a greater discount to crude oil, resulting in additional exposure to NGL commodity prices. The relationship of NGLs to crude oil continues to be lower than historical relationships. When our crude oil swaps become short-term in nature, certain crude oil derivatives may be converted to NGL derivatives by entering into offsetting crude oil swaps while adding NGL swaps. Crude oil and NGL transactions are primarily accomplished through the use of forward contracts that effectively exchange floating price risk for a fixed price. The type of instrument used to mitigate a portion of the risk may vary depending on our risk management objectives. These transactions are not designated as hedging instruments for accounting purposes and the change in fair value is reflected in the current period within our condensed consolidated statements of operations as trading and marketing gains and (losses), net.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
NGL Proprietary Trading
Our NGL proprietary trading activity includes trading energy related products and services. We undertake these activities through the use of fixed forward sales and purchases, basis and spread trades, storage opportunities, put/call options, term contracts and spot market trading. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and these operations may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. These physical and financial instruments are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations.
We employ established risk limits, policies and procedures to manage risks associated with our natural gas asset based trading and marketing and NGL proprietary trading.
Interest Rate Risk
We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to convert our floating rate debt to fixed-rate debt or to convert our fixed-rate debt to floating rate debt. Our primary goals include: (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates.
We previously had interest rate cash flow hedges and fair value hedges in place that were terminated. As the underlying transactions impact earnings, the remaining net loss deferred in AOCI relative to these cash flow hedges will be reclassified to interest expense, net from 2022 through 2030 and the remaining net loss included in long-term debt relative to these fair value hedges will be reclassified to interest expense, net from 2019 through 2030, the original maturity dates of the debt.
Credit Risk
Our principal customers range from large, natural gas marketers to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 22% of our NGL production was committed to Phillips 66 and CPChem as of September 30, 2017. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use various master agreements that include language giving us the right to request collateral to mitigate credit exposure. The collateral language provides for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral language also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our master agreements and our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.
Contingent Credit Features
Each of the above risks is managed through the execution of individual contracts with a variety of counterparties. Certain of our derivative contracts may contain credit-risk related contingent provisions that may require us to take certain actions in certain circumstances.
We have International Swaps and Derivatives Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions. Some of the provisions we are subject to are outlined below.
If we were to have an effective event of default under our Credit Agreement that occurs and is continuing, our ISDA counterparties may have the right to request early termination and net settlement of any outstanding derivative liability positions.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Our ISDA counterparties generally have collateral thresholds of zero, requiring us to fully collateralize any commodity contracts in a net liability position, when our credit rating is below investment grade.
Additionally, in some cases, our ISDA contracts contain cross-default provisions that could constitute a credit-risk related contingent feature. These provisions apply if we default in making timely payments under other credit arrangements and the amount of the default is above certain predefined thresholds, which are significantly high and are generally consistent with the terms of our Credit Agreement. As of September 30, 2017, we were not a party to any agreements that would trigger the cross-default provisions.
Our commodity derivative contracts that are not governed by ISDA contracts do not have any credit-risk related contingent features. Depending upon the movement of commodity prices and interest rates, each of our individual contracts with counterparties to our commodity derivative instruments or interest rate swap instruments are in either a net asset or net liability position. As of September 30, 2017, we had less than $1 million of individual commodity derivative contracts that contain credit-risk related contingent features that were in a net liability position. If we were required to net settle our position with an individual counterparty, due to a credit-risk related event, our ISDA contracts may permit us to net all outstanding contracts with that counterparty, whether in a net asset or net liability position, as well as any cash collateral already posted. As of September 30, 2017, we have not been required to post additional collateral. Although our commodity derivative contracts that contain credit-risk related contingent features were in a net liability position as of September 30, 2017, the net liability position would be offset by contracts in a net asset position.
Collateral
As of SeptemberJune 30, 2017,2023, we had cash deposits of $42$3 million, included in collateral cash deposits in our condensed consolidated balance sheets, andsheets. Additionally, as of June 30, 2023, we held letters of credit of $13 million with counterparties to secure our obligations to provide future services or to perform under financial contracts. Additionally, as of September 30, 2017, we held cash of $19 million, included in other current liabilities in our condensed consolidated balance sheet, related to cash postings by third parties and letters of credit of $36$23 million from counterparties to secure their future performance under financial or physical contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, services, trading and hedging contracts. In many cases, we and our counterparties have publicly disclosed credit ratings, which may impact the amounts of collateral requirements.
Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.
Offsetting
Certain of our financial derivative instruments are subject to a master netting or similar arrangement, whereby we may elect to settle multiple positions with an individual counterparty through a single net payment. Each of our individual derivative instruments are presented on a gross basis on the condensed consolidated balance sheets, regardless of our ability to net settle our positions. Instruments that are governed by agreements that include net settle provisions allow final settlement, when presented with a termination event, of outstanding amounts by extinguishing the mutual debts owed between the parties in exchange for a net amount due. We have trade receivables and payables associated with derivative instruments, subject to master netting or similar agreements, which are not included in the table below. The following summarizes the gross and net amounts of our derivative instruments:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| June 30, 2023 | | December 31, 2022 |
| Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet | | Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments | | | | Net
Amount | | Gross Amounts
of Assets and
(Liabilities)
Presented in the
Balance Sheet | | Amounts Not
Offset in the
Balance Sheet -
Financial
Instruments | | Net
Amount |
| (millions) |
| Assets: | | | | | | | | | | | | | |
| Commodity derivatives | $ | 77 | | | $ | (8) | | | | | $ | 69 | | | $ | 166 | | | $ | — | | | $ | 166 | |
| | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | |
| Commodity derivatives | $ | (49) | | | $ | 8 | | | | | $ | (41) | | | $ | (183) | | | $ | — | | | $ | (183) | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet | | Amounts Not Offset in the Balance Sheet - Financial Instruments | | Net Amount | | Gross Amounts of Assets and (Liabilities) Presented in the Balance Sheet | | Amounts Not Offset in the Balance Sheet - Financial Instruments | | Net Amount |
| | (Millions) |
| Assets: | | | | | | | | | | | |
| Commodity derivatives | $ | 36 |
| | $ | — |
| | $ | 36 |
| | $ | 47 |
| | $ | — |
| | $ | 47 |
|
| Liabilities: | | | | | | | | | | | |
| Commodity derivatives | $ | (52 | ) | | $ | — |
| | $ | (52 | ) | | $ | (92 | ) | | $ | — |
| | $ | (92 | ) |
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
Summarized Derivative Information
The fair value of our derivative instruments that are marked-to-market each period, as well as the location of each within our condensed consolidated balance sheets, by major category, is summarized below. We have no derivative instruments that are designated as hedging instruments for accounting purposes as of SeptemberJune 30, 20172023 and December 31, 2016.2022.
|
| | | | | | | | | | | | | | | | | |
| Balance Sheet Line Item | September 30,
2017 | | December 31,
2016 | | Balance Sheet Line Item | | September 30,
2017 | | December 31,
2016 |
| | (Millions) | | | | (Millions) |
| Derivative Assets Not Designated as Hedging Instruments: | | Derivative Liabilities Not Designated as Hedging Instruments: |
| Commodity derivatives: | | | | | Commodity derivatives: | | | | |
| Unrealized gains on derivative instruments — current | $ | 32 |
| | $ | 42 |
| | Unrealized losses on derivative instruments — current | | $ | (42 | ) | | $ | (91 | ) |
| Unrealized gains on derivative instruments — long-term | 4 |
| | 5 |
| | Unrealized losses on derivative instruments — long-term | | (10 | ) | | (1 | ) |
| Total | $ | 36 |
| | $ | 47 |
| | Total | | $ | (52 | ) | | $ | (92 | ) |
The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended September 30, 2017: |
| | | | | | | | | | | | | | | |
| | Interest
Rate Cash
Flow
Hedges | | Commodity
Cash Flow
Hedges | | Foreign
Currency
Cash Flow
Hedges (a) | | Total |
| | (Millions) |
| Net deferred (losses) gains in AOCI (beginning balance) | $ | (4 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (9 | ) |
| Net deferred (losses) gains in AOCI (ending balance) | $ | (4 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (9 | ) |
| Deferred losses in AOCI expected to be reclassified into earnings over the next 12 months | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the nine months ended September 30, 2017:
|
| | | | | | | | | | | | | | | |
| | Interest
Rate Cash
Flow
Hedges | | Commodity
Cash Flow
Hedges | | Foreign
Currency
Cash Flow
Hedges (a) | | Total |
| | (Millions) |
| Net deferred (losses) gains in AOCI (beginning balance) | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (8 | ) |
| Losses reclassified from AOCI to earnings — effective portion | 1 |
| | — |
| | — |
| | 1 |
|
| Deficit purchase price under carrying value of the Transaction | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | (2 | ) |
| Net deferred (losses) gains in AOCI (ending balance) | $ | (4 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (9 | ) |
| |
(a) | Relates to Discovery, an unconsolidated affiliate. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance Sheet Line Item | June 30,
2023 | | December 31,
2022 | | Balance Sheet Line Item | | June 30,
2023 | | December 31,
2022 |
| | (millions) | | | | (millions) |
| | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Derivative Assets Not Designated as Hedging Instruments: | | Derivative Liabilities Not Designated as Hedging Instruments: |
| Commodity derivatives: | | | | | Commodity derivatives: | | | | |
| Unrealized gains on derivative instruments — current | $ | 60 | | | $ | 140 | | | Unrealized losses on derivative instruments — current | | $ | (36) | | | $ | (148) | |
| Unrealized gains on derivative instruments — long-term | 17 | | | 26 | | | Unrealized losses on derivative instruments — long-term | | (13) | | | (35) | |
| Total | $ | 77 | | | $ | 166 | | | Total | | $ | (49) | | | $ | (183) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
For the three and ninesix months ended SeptemberJune 30, 2017, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading2023 and marketing gains, net or interest expense in our condensed consolidated statements of operations. For the three and nine months ended September 30, 2017, no derivative losses were reclassified from AOCI to trading and marketing gains, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the three months ended September 30, 2016:
|
| | | | | | | | | | | | | | | |
| | Interest
Rate Cash
Flow
Hedges | | Commodity
Cash Flow
Hedges | | Foreign
Currency
Cash Flow
Hedges (a) | | Total |
| | (Millions) |
| Net deferred (losses) gains in AOCI (beginning balance) | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (8 | ) |
| Net deferred (losses) gains in AOCI (ending balance) | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (8 | ) |
The following summarizes the balance and activity within AOCI relative to our interest rate, commodity and foreign currency cash flow hedges as of and for the nine months ended September 30, 2016: |
| | | | | | | | | | | | | | | |
| | Interest
Rate Cash
Flow
Hedges | | Commodity
Cash Flow
Hedges | | Foreign
Currency
Cash Flow
Hedges (a) | | Total |
| | (Millions) |
| Net deferred (losses) gains in AOCI (beginning balance) | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (8 | ) |
| Net deferred (losses) gains in AOCI (ending balance) | $ | (3 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (8 | ) |
| |
(a) | Relates to Discovery, an unconsolidated affiliate. |
For the three and nine months ended September 30, 2016,2022, no derivative losses attributable to the ineffective portion or to amounts excluded from effectiveness testing were recognized in trading and marketing gains or losses, net or interest expense in our condensed consolidated statements of operations. For the three
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and nine months ended SeptemberSix Months Ended June 30, 2016, no derivative losses were reclassified from AOCI to trading2023 and marketing gains or losses, net or interest expense as a result of the discontinuance of cash flow hedges related to certain forecasted transactions that are not probable of occurring.2022
Changes in the value of derivative instruments, for which the hedge method of accounting has not been elected from one period to the next, are recorded in the condensed consolidated statements of operations. The following summarizes these amounts and the location within the condensed consolidated statements of operations that such amounts are reflected:
|
| | | | | | | | | | | | | | | | |
| Commodity Derivatives: Statements of Operations Line Item | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | (Millions) |
| Realized gains | | $ | 16 |
| | $ | 6 |
| | $ | 9 |
| | $ | 90 |
|
| Unrealized (losses) gains | | (59 | ) | | 9 |
| | 1 |
| | (80 | ) |
| Trading and marketing (losses) gains, net | | $ | (43 | ) | | $ | 15 |
| | $ | 10 |
| | $ | 10 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Derivatives: Statements of Operations Line Item | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2023 | | 2022 | | 2023 | | 2022 | | |
| | | (millions) | | (millions) |
| Realized gains (losses) | | $ | 13 | | | $ | (115) | | | $ | 60 | | | $ | (174) | | | |
| Unrealized gains (losses) | | 7 | | | 101 | | | 47 | | | (75) | | | |
| Trading and marketing gains (losses), net | | $ | 20 | | | $ | (14) | | | $ | 107 | | | $ | (249) | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | |
| | | | | | | | | | |
| |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
We do not have any derivative financial instruments that qualifyare designated as a hedge of a net investment.
The following tables represent, by commodity type, our net long or short positions that are expected to partially or entirely settle in each respective year. To the extent that we have long dated derivative positions that span multiple calendar years, the contract will appear in more than one line item in the tables below.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | June 30, 2023 | |
| | Crude Oil | | Natural Gas | | Natural Gas
Liquids | | Natural Gas
Basis Swaps | |
| Year of Expiration | Net Short
Position
(Bbls) | | Net Short Position
(MMBtu) | | Net Short
Position
(Bbls) | | Net Long (Short) Position
(MMBtu) | |
| 2023 | — | | | (16,830,500) | | | (2,750,000) | | | 1,280,000 | | |
| 2024 | — | | | (15,966,800) | | | — | | | (235,000) | | |
| 2025 | — | | | (4,140,000) | | | — | | | 2,985,000 | | |
| 2026 | — | | | — | | | — | | | 535,000 | | |
| | | | | | | | |
| | | | | | | | |
| | June 30, 2022 | |
| | Crude Oil | | Natural Gas | | Natural Gas
Liquids | | Natural Gas
Basis Swaps | |
| Year of Expiration | Net Short
Position
(Bbls) | | Net Short Position
(MMBtu) | | Net Short
Position
(Bbls) | | Net (Short) Long
Position
(MMBtu) | |
| 2022 | (849,000) | | | (42,566,900) | | | (5,347,476) | | | (2,915,000) | | |
| 2023 | (1,526,000) | | | (26,655,000) | | | (4,281,200) | | | (16,572,500) | | |
| 2024 | (720,000) | | | (8,235,000) | | | (1,337,000) | | | (5,940,000) | | |
| 2025 | — | | | (7,300,000) | | | (1,441,000) | | | (980,000) | | |
| 2026 | — | | | — | | | (1,440,000) | | | 535,000 | | |
| 2027 | — | | | — | | | (600,000) | | | — | | |
10. Partnership Equity and Distributions
Common Units — Following the completion of the Merger on June 15, 2023, all of the Common Units of the Partnership are owned by DCP Midstream, LLC, DCP Midstream GP, LP and Phillips 66 Project Development Inc., an indirect wholly owned subsidiary of Phillips 66. Former holders of Public Common Units ceased to have any rights as holders of Common Units at the Effective Time, other than the right to receive the Merger Consideration in accordance with the Merger Agreement. The Common Units were delisted from the NYSE and we filed to suspend our reporting obligations with respect to the Common Units under Sections 13 and 15(d) of the Securities Exchange Act of 1934, as amended.
Preferred Units — On June 15, 2023 we paid $161 million to redeem in full the outstanding Series B Preferred Units at a redemption price of $25 per unit using cash on hand and borrowings under our Securitization Facility. The difference between the redemption price of the Series B Preferred Units and the carrying value on the balance sheet resulted in an approximately $5 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 B Preferred Units. Following the redemption, the Series B Preferred Units
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
|
| | | | | | | | | | | |
| | September 30, 2017 |
| | Crude Oil | | Natural Gas | | Natural Gas Liquids | | Natural Gas Basis Swaps |
| Year of Expiration | Net Short Position (Bbls) | | Net Short Position (MMBtu) | | Net (Short) Long Position (Bbls) | | Net Long Position (MMBtu) |
| 2017 | (81,000 | ) | | (20,888,000 | ) | | (9,288,558 | ) | | 2,680,000 |
|
| 2018 | (1,803,000 | ) | | (29,277,400 | ) | | (13,417,484 | ) | | 9,190,000 |
|
| 2019 | (367,000 | ) | | — |
| | (2,353,300 | ) | | 9,317,500 |
|
| 2020 | (50,000 | ) | | — |
| | 238,548 |
| | 3,660,000 |
|
| | | | | | | | |
| | September 30, 2016 |
| | Crude Oil | | Natural Gas | | Natural Gas Liquids | | Natural Gas Basis Swaps |
| Year of Expiration | Net Short Position (Bbls) | | Net Short Position (MMBtu) | | Net (Short) Long Position (Bbls) | | Net (Short) Long Position (MMBtu) |
| 2016 | (380,000 | ) | | (5,915,500 | ) | | (10,018,903 | ) | | (512,500 | ) |
| 2017 | (964,000 | ) | | (27,686,850 | ) | | (7,725,057 | ) | | 6,515,000 |
|
| 2018 | — |
| | — |
| | 150,216 |
| | — |
|
| 2019 | (40,000 | ) | | — |
| | (1,984 | ) | | — |
|
| 2020 | (50,000 | ) | | — |
| | 240,000 |
| | — |
|
13. Partnership Equitywere delisted from the NYSE and Distributions
As partwe filed to suspend our reporting obligations with respect to the Series B Preferred Units under Sections 13 and 15(d) of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions payable to our General Partner under our Partnership AgreementSecurities Exchange Act of up to $100 million annually through 2019 to target an approximate 1.0 times distribution coverage ratio. Under the terms of our amended partnership agreement, the amount of incentive distributions paid to our General Partner will be evaluated by our General Partner on both a quarterly and annual basis and may be reduced each quarter by an amount determined by our General Partner (the “IDR giveback”). If no determination is made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback, of up to $100 million annually, will be subject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our amended partnership agreement) less the total annual distribution payable to our unitholders, adjusted to target an approximate 1.0 times coverage ratio. Distributions paid to the holders of the Partnership's incentive distribution rights were reduced by $20 million and $40 million during the three and nine month periods ended September 30, 2017, respectively, in accordance with the Third Amendment to the Partnership Agreement.1934, as amended.
In January 2017, we issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to the General Partner in a private placement as consideration for the Transaction that closed on January 1, 2017. For additional information regarding the Transaction, see Note 3 - Acquisitions.
During the nine months ended September 30, 2017 and 2016, we issued no common units pursuant to our 2014 equity distribution agreement.
Distributions — The following table presents our cash distributions paid in 20172023: | | | | | | | | | | | |
| Payment Date | Per Unit
Distribution | | Total Cash
Distribution |
| | | (millions) |
| Distributions to common unitholders | | | |
| May 15, 2023 | $ | 0.43 | | | $ | 89 | |
| February 14, 2023 | $ | 0.43 | | | $ | 90 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Distributions to Series B Preferred unitholders | | | |
| June 15, 2023 | $ | 0.4922 | | | $ | 3 | |
| March 15, 2023 | $ | 0.4922 | | | $ | 3 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| Distributions to Series C Preferred unitholders | | | |
| April 17, 2023 | $ | 0.4969 | | | $ | 2 | |
| January 17, 2023 | $ | 0.4969 | | | $ | 2 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
11. Equity-Based Compensation
As of December 31, 2022, we had 327,190 Strategic Performance Units ("SPUs") and 2016:532,432 Phantom Units outstanding. Pursuant to the terms of the Merger Agreement, the majority of these SPUs and Phantom Units were forfeited and as of June 30, 2023, there were an immaterial number of SPUs and Phantom Units outstanding.
12. Net Income or Loss per Limited Partner Unit
Prior to June 15, 2023, we had restricted phantom units outstanding, and we had the ability to elect to settle certain of the restricted phantom units in either cash or common units at our discretion. As of June 30, 2023, there were no outstanding equity classified restricted phantom units.
Basic and diluted net income per limited partner unit was calculated as follows for the periods indicated: | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2023 | | 2022 | | 2023 | | 2022 | | |
| (millions, except per unit amounts) |
| | | | | | | | | |
| Net income allocable to limited partners | $ | 84 | | | $ | 368 | | | $ | 290 | | | $ | 434 | | | |
| Weighted average limited partner units outstanding, basic | 208,662,361 | | | 208,379,466 | | | 208,609,415 | | | 208,381,451 | | | |
| Dilutive effects of nonvested restricted phantom units | 8,327 | | | 142,150 | | | 24,353 | | | 235,749 | | | |
| Weighted average limited partner units outstanding, diluted | 208,670,688 | | | 208,521,616 | | | 208,633,768 | | | 208,617,200 | | | |
| Net income per limited partner unit, basic and diluted | $ | 0.40 | | | $ | 1.77 | | | $ | 1.39 | | | $ | 2.08 | | | |
| | | | | | | | | |
|
| | | | | | | |
| Payment Date | Per Unit Distribution | | Total Cash Distribution |
| | |
| | (Millions) |
| August 14, 2017 | $ | 0.7800 |
| | $ | 134 |
|
| May 15, 2017 | 0.7800 |
| | 135 |
|
| February 14, 2017 | 0.7800 |
| | 121 |
|
| November 14, 2016 | 0.7800 |
| | 120 |
|
| August 12, 2016 | 0.7800 |
| | 121 |
|
| May 13, 2016 | 0.7800 |
| | 121 |
|
| February 12, 2016 | 0.7800 |
| | 121 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
14. Net Income or Loss per Limited Partner Unit
Basic and diluted net income or loss per limited partner unit (or "LPU") is calculated by dividing net income or loss allocable to limited partners, by the weighted-average number of outstanding LPUs during the period. Diluted net income or loss per LPU is computed based on the weighted average number of units plus the effect of dilutive potential units outstanding during the period using the two-class method.
15.13. Commitments and Contingent Liabilities
Litigation — We are not a party to any significantmaterial legal proceedings, but are a party to various administrative and regulatory proceedings and commercial disputes that have arisen in the ordinary course of our business. Management currently believes that the ultimate resolution of the foregoing matters, taken as a whole, and after consideration of amounts accrued, insurance coverage or other indemnification arrangements, will not have a material adverse effect on our results of operations, financial position, or cash flow.
Insurance — Our insurance coverage is carried with third-party insurers and with an affiliate of Phillips 66. Our insurance coverage includes: (1)(i) general liability insurance covering third-party exposures; (2)(ii) statutory workers’ compensation insurance; (3)(iii) automobile liability insurance for all owned, non-owned and hired vehicles; (4)(iv) excess liability insurance above the established primary limits for general liability and automobile liability insurance; (5)(v) property insurance, which covers the replacement value of real and personal property and includes business interruption; and (6)(vi) insurance covering our directors and officers for acts related to our business activities. All coverage is subject to certain limits and deductibles, the terms and conditions of which are common for companies with similar types of operations.
EnvironmentalEnvironment, Health and Safety — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, fractionating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to the environment, health safety and the environment.safety. As an owner or operator of these facilities, we must comply with laws and regulations at the federal, state and, in some cases, local levels that relate to worker health and safety, public health and safety, pipeline safety, air and water quality, solid and hazardous waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities incorporates compliance with environmental laws and regulations, workerhealth and safety standards applicable to workers and the public, and safety standards applicable to our various facilities. In addition, there is increasing focus from (i) from city, stateregulatory bodies and federal regulatory officialscommunities, and through litigation, on hydraulic fracturing as well as general oil and gas production facilities and the real or perceived environmental or public health impacts of this technique,these activities, which indirectly presents some risk to our available supply of natural gas and the resulting supply of NGLs,NGLs; (ii) from federal regulatory agenciesbodies regarding pipeline system safety which could impose additional regulatory burdens and increase the cost of our operations, andoperations; (iii) from state and federal regulatory officialsagencies regarding the emission of greenhouse gases and other air emissions associated with our operations or the materials managed as part of our business, which could impose regulatory burdens and increase the cost of our operations.operations; and (iv) regulatory bodies and communities that could prevent or delay the development of fossil fuel energy infrastructure such as pipelines, plants, and other facilities used in our business. Failure to comply with these various health, safety and environmental laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these existing laws and regulations will not have a material adverse effect on our results of operations, financial position or cash flows.
The following pending proceedings involve governmental authorities as a party under federal, state, and local laws regulating the discharge of materials into the environment. We have elected to disclose matters where we reasonably believe such proceeding would result in monetary sanctions, exclusive of interest and costs, of $1 million or more. It is not possible for us to predict the final outcome of these pending proceedings; however, we do not expect the outcome of one or more of these proceedings to have a material adverse effect on our results of operations, financial position, or cash flows:
•In 2018, the Colorado Department of Public Health and Environment (“CDPHE”) issued a Compliance Advisory in relation to an improperly permitted facility flare and related air emissions from flare operations at one of our gas processing plants, which we had self-disclosed to CDPHE in December 2017. Following information exchanges and discussions with CDPHE, a resolution was proposed pursuant to which the plant's air permit would be revised to include the flare and emissions limits for such flare in addition to us paying an administrative penalty as well as an economic benefit payment generally covering the period when the flare was required to be included in the facility air permit. A revised air permit was issued in May 2019, but the parties had not yet entered into a final settlement agreement to complete the matter. Subsequently, in July 2020 CDPHE issued a Notice of Violation in relation to amine treater emissions at this gas processing plant, which we had self-disclosed to CDPHE in April 2020. We are still exchanging information and holding discussions with CDPHE as to this and the foregoing flare-related enforcement matter, including possible settlement terms, although these matters, which have since been combined, may end up in formal legal proceedings. It is possible that resolution of this matter may include an administrative penalty and economic benefit payment, further revising the facility air permit, or installation of emissions management equipment, or a combination of these, that could, in the aggregate, exceed the disclosure threshold amount described above,
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
although we do not believe that resolution of this matter would have a material adverse effect on our results of operations, financial position, or cash flows.
16.
14. Restructuring Costs
We undertook restructuring actions, as well as other transformation and integration efforts, as part of our integration with Phillips 66. During the three and six months ended June 30, 2023, we incurred $16 million and $26 million, respectively, in impairment, severance and other employee related costs.
| | | | | | |
| The following table presents a rollforward of the Company's restructuring liability as of June 30, 2023, which is primarily included in Other current liabilities in the condensed consolidated balance sheets: | |
| (millions) | |
| Balance as of January 1, 2023 | $ | 15 | | |
| Severance and employee related charges | 16 | | |
| | |
| Cash payments | (30) | | |
| Balance as of June 30, 2023 | $ | 1 | | |
| | |
| | |
| | |
15. Business Segments
Concurrent with the completion of the Transaction in the first quarter of 2017, management reevaluated our reportable segments and determined that ourOur operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing and (ii) Logistics and Marketing. Segment information for prior periods has been retrospectively adjusted to furnish comparative information similar to the pooling method to reflect these reportable segments.Processing. These segments are monitored separately by management for performance against our internal forecast and are consistent with internal financial reporting. These segments have been identified based on the differing products and services, regulatory environment and the expertise required for these operations. Our Gathering and Processing reportable segment includes operating segments that have been aggregated based on the nature of the products and services provided. GrossAdjusted gross margin is a performance measure utilized by management to monitor the operations of each segment. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies included in Note 2 of the Notes to the Consolidated Financial Statements in "Financial Statements and Supplementary Data" included as Exhibit 99.4Item 8 in our Annual Report on Form 10-K for the May 2017 8-K.year ended December 31, 2022.
Our Logistics and Marketing segment includes transporting, trading, marketing, storing natural gas and NGLs, and fractionating NGLs. Our Gathering and Processing segment consists of gathering, compressing, treating, processing natural gas, producing and fractionating NGLs, and recovering and selling condensate. Our Logistics and Marketing segment includes transporting, trading, marketing, and storing natural gas and NGLs, fractionating NGLs, and wholesale propane logistics. The remainder of our business operations is presented as “Other,” and consists of unallocated corporate costs. Elimination of inter-segment transactions are reflected in the eliminationsEliminations column. The following tables set forth our segment information:
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
The following tables set forth our segment information:
Three Months Ended SeptemberJune 30, 2017:2023
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Logistics and Marketing | | Gathering and Processing | | | | Other | | Eliminations | | Total |
| | (millions) |
| Total operating revenue | $ | 1,561 | | | $ | 1,252 | | | | | $ | — | | | $ | (972) | | | $ | 1,841 | |
| Adjusted gross margin (a) | $ | 58 | | | $ | 371 | | | | | $ | — | | | $ | — | | | $ | 429 | |
| Operating and maintenance expense | (8) | | | (216) | | | | | (5) | | | — | | | (229) | |
| General and administrative expense | (1) | | | (4) | | | | | (63) | | | — | | | (68) | |
| Depreciation and amortization expense | (4) | | | (84) | | | | | (3) | | | — | | | (91) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Loss on sale of assets, net | — | | | (3) | | | | | — | | | — | | | (3) | |
| Restructuring costs | — | | | — | | | | | (16) | | | — | | | (16) | |
| Earnings from unconsolidated affiliates | 147 | | | 1 | | | | | — | | | — | | | 148 | |
| Interest expense | — | | | — | | | | | (75) | | | — | | | (75) | |
| | | | | | | | | | | |
| Net income (loss) | $ | 192 | | | $ | 65 | | | | | $ | (162) | | | $ | — | | | $ | 95 | |
| Net income attributable to noncontrolling interests | — | | | (1) | | | | | — | | | — | | | (1) | |
| Net income (loss) attributable to partners | $ | 192 | | | $ | 64 | | | | | $ | (162) | | | $ | — | | | $ | 94 | |
| Non-cash derivative mark-to-market | $ | 17 | | | $ | (10) | | | | | $ | — | | | $ | — | | | $ | 7 | |
| | | | | | | | | | | |
| Capital expenditures | $ | 1 | | | $ | 81 | | | | | $ | — | | | $ | — | | | $ | 82 | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Gathering and Processing | | Logistics and Marketing | | Other | | Eliminations | | Total |
| | (Millions) |
| Total operating revenue | $ | 1,337 |
| | $ | 1,913 |
| | $ | — |
| | $ | (1,195 | ) | | $ | 2,055 |
|
| Gross margin (a) | $ | 303 |
| | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 360 |
|
| Operating and maintenance expense | (154 | ) | | (9 | ) | | (5 | ) | | — |
| | (168 | ) |
| Depreciation and amortization expense | (85 | ) | | (4 | ) | | (5 | ) | | — |
| | (94 | ) |
| General and administrative expense | (2 | ) | | (3 | ) | | (64 | ) | | — |
| | (69 | ) |
| Asset impairments | (48 | ) | | — |
| | — |
| | — |
| | (48 | ) |
| Other (expense) income | — |
| | (1 | ) | | 1 |
| | — |
| | — |
|
| Earnings from unconsolidated affiliates | 15 |
| | 59 |
| | — |
| | — |
| | 74 |
|
| Interest expense | — |
| | — |
| | (73 | ) | | — |
| | (73 | ) |
| Income tax expense | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Net income (loss) | $ | 29 |
| | $ | 99 |
| | $ | (148 | ) | | $ | — |
| | $ | (20 | ) |
| Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Net income (loss) attributable to partners | $ | 29 |
| | $ | 99 |
| | $ | (148 | ) | | $ | — |
| | $ | (20 | ) |
| Non-cash derivative mark-to-market (b) | $ | (51 | ) | | $ | (8 | ) | | $ | — |
| | $ | — |
| | $ | (59 | ) |
| Capital expenditures | $ | 91 |
| | $ | 1 |
| | $ | 7 |
| | $ | — |
| | $ | 99 |
|
| Investments in unconsolidated affiliates, net | $ | 1 |
| | $ | 28 |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
ThreeSix Months Ended SeptemberJune 30, 2016:2023:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Logistics and Marketing | | Gathering and Processing | | | | Other | | Eliminations | | Total |
| | (millions) |
| Total operating revenue | $ | 3,953 | | | $ | 3,018 | | | | | $ | — | | | $ | (2,404) | | | $ | 4,567 | |
| Adjusted gross margin (a) | $ | 112 | | | $ | 815 | | | | | $ | — | | | $ | — | | | $ | 927 | |
| Operating and maintenance expense | (17) | | | (398) | | | | | (11) | | | — | | | (426) | |
| General and administrative expense | (3) | | | (8) | | | | | (137) | | | — | | | (148) | |
| Depreciation and amortization expense | (6) | | | (168) | | | | | (7) | | | — | | | (181) | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Loss on sale of assets, net | — | | | (3) | | | | | — | | | — | | | (3) | |
| Restructuring costs | — | | | — | | | | | (26) | | | — | | | (26) | |
| Earnings from unconsolidated affiliates | 301 | | | 7 | | | | | — | | | — | | | 308 | |
| Interest expense | — | | | — | | | | | (143) | | | — | | | (143) | |
| Income tax expense | — | | | — | | | | | (1) | | | — | | | (1) | |
| Net income (loss) | $ | 387 | | | $ | 245 | | | | | $ | (325) | | | $ | — | | | $ | 307 | |
| Net income attributable to noncontrolling interests | — | | | (2) | | | | | — | | | — | | | (2) | |
| Net income (loss) attributable to partners | $ | 387 | | | $ | 243 | | | | | $ | (325) | | | $ | — | | | $ | 305 | |
| Non-cash derivative mark-to-market | $ | 12 | | | $ | 35 | | | | | $ | — | | | $ | — | | | $ | 47 | |
| Non-cash lower of cost or net realizable value adjustments | $ | 22 | | | $ | — | | | | | $ | — | | | $ | — | | | $ | 22 | |
| Capital expenditures | $ | 1 | | | $ | 160 | | | | | $ | 2 | | | $ | — | | | $ | 163 | |
| | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | |
| | Gathering and Processing | | Logistics and Marketing | | Other | | Eliminations | | Total |
| | (Millions) |
| Total operating revenue | $ | 1,217 |
| | $ | 1,641 |
| | $ | — |
| | $ | (1,035 | ) | | $ | 1,823 |
|
| Gross margin (a) | $ | 335 |
| | $ | 51 |
| | $ | — |
| | $ | — |
| | $ | 386 |
|
| Operating and maintenance expense | (146 | ) | | (13 | ) | | (2 | ) | | — |
| | (161 | ) |
| Depreciation and amortization expense | (85 | ) | | (4 | ) | | (5 | ) | | — |
| | (94 | ) |
| General and administrative expense | (2 | ) | | (2 | ) | | (60 | ) | | — |
| | (64 | ) |
| Other expense | (13 | ) | | — |
| | (1 | ) | | — |
| | (14 | ) |
| Gain on sale of assets, net | 25 |
| | 16 |
| | — |
| | — |
| | 41 |
|
| Restructuring costs | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Earnings from unconsolidated affiliates | 20 |
| | 55 |
| | — |
| | — |
| | 75 |
|
| Interest expense | — |
| | — |
| | (77 | ) | | — |
| | (77 | ) |
| Income tax expense | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Net income (loss) | $ | 134 |
| | $ | 103 |
| | $ | (148 | ) | | $ | — |
| | $ | 89 |
|
| Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Net income (loss) attributable to partners | $ | 134 |
| | $ | 103 |
| | $ | (148 | ) | | $ | — |
| | $ | 89 |
|
| Non-cash derivative mark-to-market (b) | $ | (5 | ) | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | 9 |
|
| Capital expenditures | $ | 18 |
| | $ | 4 |
| | $ | 8 |
| | $ | — |
| | $ | 30 |
|
| Investments in unconsolidated affiliates, net | $ | — |
| | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | 11 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
NineThree Months Ended SeptemberJune 30, 2017:2022
| | | | Logistics and Marketing | | Gathering and Processing | | | Other | | Eliminations | | Total |
| | | | (millions) |
| Total operating revenue | | Total operating revenue | $ | 3,789 | | | $ | 2,967 | | | | $ | — | | | $ | (2,487) | | | $ | 4,269 | |
| Adjusted gross margin (a) | | Adjusted gross margin (a) | $ | 40 | | | $ | 585 | | | | $ | — | | | $ | — | | | $ | 625 | |
| Operating and maintenance expense | | Operating and maintenance expense | (9) | | | (175) | | | | (5) | | | — | | | (189) | |
| General and administrative expense | | General and administrative expense | (2) | | | (5) | | | | (58) | | | — | | | (65) | |
| Depreciation and amortization expense | | Depreciation and amortization expense | (3) | | | (82) | | | | (5) | | | — | | | (90) | |
| Asset impairments | | Asset impairments | — | | | (1) | | | | — | | | — | | | (1) | |
| Other income (expense), net | | Other income (expense), net | 10 | | | (2) | | | | — | | | — | | | 8 | |
| | | | Gathering and Processing | | Logistics and Marketing | | Other | | Eliminations | | Total | |
| | (Millions) | |
| Total operating revenue | $ | 3,965 |
| | $ | 5,596 |
| | $ | — |
| | $ | (3,436 | ) | | $ | 6,125 |
| |
| Gross margin (a) | $ | 1,021 |
| | $ | 165 |
| | $ | — |
| | $ | — |
| | $ | 1,186 |
| |
| Operating and maintenance expense | (469 | ) | | (31 | ) | | (13 | ) | | — |
| | (513 | ) | |
| Depreciation and amortization expense | (256 | ) | | (11 | ) | | (15 | ) | | — |
| | (282 | ) | |
| General and administrative expense | (15 | ) | | (8 | ) | | (179 | ) | | — |
| | (202 | ) | |
| Asset impairments | (48 | ) | | — |
| | — |
| | — |
| | (48 | ) | |
| Other expense | (3 | ) | | (12 | ) | | — |
| | — |
| | (15 | ) | |
| Gain on sale of assets, net | 34 |
| | — |
| | — |
| | — |
| | 34 |
| |
| Earnings from unconsolidated affiliates | 59 |
| | 175 |
| | — |
| | — |
| | 234 |
| Earnings from unconsolidated affiliates | 165 | | | 3 | | | | — | | | — | | | 168 | |
| Interest expense | — |
| | — |
| | (219 | ) | | — |
| | (219 | ) | Interest expense | — | | | — | | | | (70) | | | — | | | (70) | |
| Income tax expense | — |
| | — |
| | (5 | ) | | — |
| | (5 | ) | Income tax expense | — | | | — | | | | (2) | | | — | | | (2) | |
| Net income (loss) | $ | 323 |
| | $ | 278 |
| | $ | (431 | ) | | $ | — |
| | $ | 170 |
| Net income (loss) | $ | 201 | | | $ | 323 | | | | $ | (140) | | | $ | — | | | $ | 384 | |
| Net income attributable to noncontrolling interests | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | Net income attributable to noncontrolling interests | — | | | (1) | | | | — | | | — | | | (1) | |
| Net income (loss) attributable to partners | $ | 322 |
| | $ | 278 |
| | $ | (431 | ) | | $ | — |
| | $ | 169 |
| Net income (loss) attributable to partners | $ | 201 | | | $ | 322 | | | | $ | (140) | | | $ | — | | | $ | 383 | |
| Non-cash derivative mark-to-market (b) | $ | (4 | ) | | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| |
| Non-cash derivative mark-to-market | | Non-cash derivative mark-to-market | $ | 26 | | | $ | 75 | | | | $ | — | | | $ | — | | | $ | 101 | |
| | Capital expenditures | $ | 237 |
| | $ | 2 |
| | $ | 19 |
| | $ | — |
| | $ | 258 |
| Capital expenditures | $ | 4 | | | $ | 31 | | | | $ | 2 | | | $ | — | | | $ | 37 | |
| Investments in unconsolidated affiliates, net | $ | 1 |
| | $ | 69 |
| | $ | — |
| | $ | — |
| | $ | 70 |
| Investments in unconsolidated affiliates, net | $ | — | | | $ | — | | | | $ | — | | | $ | — | | | $ | — | |
NineSix Months Ended SeptemberJune 30, 2016:2022: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Logistics and Marketing | | Gathering and Processing | | | | Other | | Eliminations | | Total |
| | (millions) |
| Total operating revenue | $ | 6,952 | | | $ | 5,073 | | | | | $ | — | | | $ | (4,381) | | | $ | 7,644 | |
| Adjusted gross margin (a) | $ | 56 | | | $ | 869 | | | | | $ | — | | | $ | — | | | $ | 925 | |
| Operating and maintenance expense | (17) | | | (315) | | | | | (9) | | | — | | | (341) | |
| General and administrative expense | (3) | | | (9) | | | | | (108) | | | — | | | (120) | |
| Depreciation and amortization expense | (6) | | | (163) | | | | | (11) | | | — | | | (180) | |
| Asset impairments | — | | | (1) | | | | | — | | | — | | | (1) | |
| Other income (expense), net | 10 | | | (2) | | | | | — | | | — | | | 8 | |
| | | | | | | | | | | |
| Gain on sale of assets, net | — | | | 7 | | | | | — | | | — | | | 7 | |
| | | | | | | | | | | |
| Earnings from unconsolidated affiliates | 302 | | | 9 | | | | | — | | | — | | | 311 | |
| Interest expense | — | | | — | | | | | (141) | | | — | | | (141) | |
| Income tax expense | — | | | — | | | | | (3) | | | — | | | (3) | |
| Net income (loss) | $ | 342 | | | $ | 395 | | | | | $ | (272) | | | $ | — | | | $ | 465 | |
| Net income attributable to noncontrolling interests | — | | | (2) | | | | | — | | | — | | | (2) | |
| Net income (loss) attributable to partners | $ | 342 | | | $ | 393 | | | | | $ | (272) | | | $ | — | | | $ | 463 | |
| | | | | | | | | | | |
| Non-cash derivative mark-to-market | $ | (19) | | | $ | (56) | | | | | $ | — | | | $ | — | | | $ | (75) | |
| | | | | | | | | | | |
| Capital expenditures | $ | 6 | | | $ | 51 | | | | | $ | 3 | | | $ | — | | | $ | 60 | |
| Investments in unconsolidated affiliates, net | $ | — | | | $ | 1 | | | | | $ | — | | | $ | — | | | $ | 1 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Gathering and Processing | | Logistics and Marketing | | Other | | Eliminations | | Total |
| | (Millions) |
| Total operating revenue | $ | 3,190 |
| | $ | 4,362 |
| | $ | — |
| | $ | (2,642 | ) | | $ | 4,910 |
|
| Gross margin (a) | $ | 892 |
| | $ | 152 |
| | $ | — |
| | $ | — |
| | $ | 1,044 |
|
| Operating and maintenance expense | (458 | ) | | (33 | ) | | (15 | ) | | — |
| | (506 | ) |
| Depreciation and amortization expense | (258 | ) | | (12 | ) | | (14 | ) | | — |
| | (284 | ) |
| General and administrative expense | (10 | ) | | (7 | ) | | (170 | ) | | — |
| | (187 | ) |
| Other income (expense) | 74 |
| | (5 | ) | | (1 | ) | | — |
| | 68 |
|
| Gain on sale of assets, net | 19 |
| | 16 |
| | — |
| | — |
| | 35 |
|
| Restructuring costs | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
| Earnings from unconsolidated affiliates | 52 |
| | 162 |
| | — |
| | — |
| | 214 |
|
| Interest expense | — |
| | — |
| | (235 | ) | | — |
| | (235 | ) |
| Income tax expense | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) |
| Net income (loss) | $ | 311 |
| | $ | 273 |
| | $ | (451 | ) | | $ | — |
| | $ | 133 |
|
| Net income attributable to noncontrolling interests | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
| Net income (loss) attributable to partners | $ | 310 |
| | $ | 273 |
| | $ | (451 | ) | | $ | — |
| | $ | 132 |
|
| Non-cash derivative mark-to-market (b) | $ | (73 | ) | | $ | (7 | ) | | $ | — |
| | $ | — |
| | $ | (80 | ) |
| Non-cash lower of cost or market adjustments | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
| Capital expenditures | $ | 90 |
| | $ | 7 |
| | $ | 16 |
| | $ | — |
| | $ | 113 |
|
| Investments in unconsolidated affiliates, net | $ | — |
| | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | 38 |
|
| |
(a) | Gross margin consists of total operating revenues, including trading and marketing gains and losses, less purchases of natural gas and NGLs. Gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner. |
| |
(b) | Non-cash commodity derivative mark-to-market is included in gross margin, along with cash settlements for our commodity derivative contracts. |
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and NineSix Months Ended SeptemberJune 30, 20172023 and 2016 - (Continued)2022
(Unaudited)
| | | | | | | | | | | |
| June 30, | | December 31, |
| 2023 | | 2022 |
| | (millions) |
| Segment long-term assets: | | | |
| Gathering and Processing | $ | 7,573 | | | $ | 7,594 | |
| Logistics and Marketing | 3,754 | | | 3,814 | |
| Other (b) | 163 | | | 224 | |
| Total long-term assets | 11,490 | | | 11,632 | |
| Current assets | 1,002 | | | 1,702 | |
| Total assets | $ | 12,492 | | | $ | 13,334 | |
(a) Adjusted gross margin consists of total operating revenues, including commodity derivative activity, less purchases and related costs. Adjusted gross margin is viewed as a non-GAAP financial measure under the rules of the SEC, but is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product sales versus product purchases. As an indicator of our operating performance, adjusted gross margin should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or gross margin as determined in accordance with GAAP. Our adjusted gross margin may not be comparable to similarly titled measures of other companies because other entities may not calculate adjusted gross margin in the same manner.
(b) Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets.
|
| | | | | | | |
| | September 30, | | December 31, |
| | 2017 | | 2016 |
| | (Millions) |
| Segment long-term assets: | | | |
| Gathering and Processing | $ | 8,884 |
| | $ | 9,053 |
|
| Logistics and Marketing | 3,293 |
| | 3,278 |
|
| Other (a) | 283 |
| | 286 |
|
| Total long-term assets | 12,460 |
| | 12,617 |
|
| Current assets | 1,311 |
| | 994 |
|
| Total assets | $ | 13,771 |
| | $ | 13,611 |
|
| |
(a) | Other long-term assets not allocable to segments consist of corporate leasehold improvements and other long-term assets. |
17.16. Supplemental Cash Flow Information
| | | | | | | | | | | | | |
| | Six Months Ended June 30, |
| | 2023 | | 2022 | | |
| | (millions) |
| Cash paid for interest: | | | | | |
| Cash paid for interest, net of amounts capitalized | $ | 145 | | | $ | 138 | | | |
| Cash paid for income taxes, net of income tax refunds | $ | 2 | | | $ | — | | | |
| Non-cash investing and financing activities: | | | | | |
| Property, plant and equipment acquired with accounts payable and accrued liabilities | $ | 24 | | | $ | 12 | | | |
| Other non-cash changes in property, plant and equipment | $ | — | | | $ | (2) | | | |
| Other non-cash activities: | | | | | |
| | | | | |
| Right-of-use assets obtained in exchange for operating and finance lease liabilities | $ | 22 | | | $ | 14 | | | |
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (Millions) |
| Cash paid for interest: | | | |
| Cash paid for interest, net of amounts capitalized | $ | 218 |
| | $ | 248 |
|
| Cash paid for income taxes, net of income tax refunds | $ | 2 |
| | $ | 2 |
|
| Non-cash investing and financing activities: | | | |
| Property, plant and equipment acquired with accounts payable and accrued liabilities | $ | 27 |
| | $ | 15 |
|
| Other non-cash changes in property, plant and equipment | $ | (1 | ) | | $ | 1 |
|
| Issuance of common and general partner units | $ | 1,125 |
| | $ | — |
|
| Deficit purchase price in the Transaction | $ | 3,094 |
| | $ | — |
|
18. Condensed Consolidating Financial Information
The following condensed consolidating financial information presents the results of operations, financial position and cash flows of DCP Midstream, LP, or parent guarantor, DCP Midstream Operating LP, or subsidiary issuer, which is a 100% owned subsidiary, and non-guarantor subsidiaries, as well as the consolidating adjustments necessary to present DCP Midstream, LP’s results on a consolidated basis. The parent guarantor has agreed to fully and unconditionally guarantee debt securities of the subsidiary issuer. For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities.
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Balance Sheet |
| | September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| ASSETS | | | | | | | | | |
| Current assets: | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | 310 |
| | $ | 2 |
| | $ | — |
| | $ | 312 |
|
| Accounts receivable, net | — |
| | — |
| | 846 |
| | — |
| | 846 |
|
| Inventories | — |
| | — |
| | 62 |
| | — |
| | 62 |
|
| Other | — |
| | — |
| | 91 |
| | — |
| | 91 |
|
| Total current assets | — |
| | 310 |
| | 1,001 |
| | — |
| | 1,311 |
|
| Property, plant and equipment, net | — |
| | — |
| | 8,926 |
| | — |
| | 8,926 |
|
| Goodwill and intangible assets, net | — |
| | — |
| | 340 |
| | — |
| | 340 |
|
| Advances receivable — consolidated subsidiaries | 2,563 |
| | 2,031 |
| | — |
| | (4,594 | ) | | — |
|
| Investments in consolidated subsidiaries | 4,453 |
| | 7,392 |
| | — |
| | (11,845 | ) | | — |
|
| Investments in unconsolidated affiliates | — |
| | — |
| | 3,002 |
| | — |
| | 3,002 |
|
| Other long-term assets | — |
| | — |
| | 192 |
| | — |
| | 192 |
|
| Total assets | $ | 7,016 |
| | $ | 9,733 |
| | $ | 13,461 |
| | $ | (16,439 | ) | | $ | 13,771 |
|
| LIABILITIES AND EQUITY | | | | | | | | | |
| Accounts payable and other current liabilities | $ | — |
| | $ | 69 |
| | $ | 1,215 |
| | $ | — |
| | $ | 1,284 |
|
| Current maturities of long-term debt | — |
| | 500 |
| | — |
| | — |
| | 500 |
|
| Advances payable — consolidated subsidiaries | — |
| | — |
| | 4,594 |
| | (4,594 | ) | | — |
|
| Long-term debt | — |
| | 4,711 |
| | — |
| | — |
| | 4,711 |
|
| Other long-term liabilities | — |
| | — |
| | 233 |
| | — |
| | 233 |
|
| Total liabilities | — |
| | 5,280 |
| | 6,042 |
| | (4,594 | ) | | 6,728 |
|
| Commitments and contingent liabilities |
| |
| |
| |
| |
|
| Equity: | | | | | | | | | |
| Partners’ equity: | | | | | | | | | |
| Net equity | 7,016 |
| | 4,457 |
| | 7,397 |
| | (11,845 | ) | | 7,025 |
|
| Accumulated other comprehensive loss | — |
| | (4 | ) | | (5 | ) | | — |
| | (9 | ) |
| Total partners’ equity | 7,016 |
| | 4,453 |
| | 7,392 |
| | (11,845 | ) | | 7,016 |
|
| Noncontrolling interests | — |
| | — |
| | 27 |
| | — |
| | 27 |
|
| Total equity | 7,016 |
| | 4,453 |
| | 7,419 |
| | (11,845 | ) | | 7,043 |
|
| Total liabilities and equity | $ | 7,016 |
| | $ | 9,733 |
| | $ | 13,461 |
| | $ | (16,439 | ) | | $ | 13,771 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Balance Sheet |
| | December 31, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| ASSETS | | | | | | | | | |
| Current assets: | | | | | | | | | |
| Cash and cash equivalents | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
|
| Accounts receivable, net | — |
| | — |
| | 792 |
| | — |
| | 792 |
|
| Inventories | — |
| | — |
| | 72 |
| | — |
| | 72 |
|
| Other | — |
| | — |
| | 129 |
| | — |
| | 129 |
|
| Total current assets | — |
| | — |
| | 994 |
| | — |
| | 994 |
|
| Property, plant and equipment, net | — |
| | — |
| | 9,069 |
| | — |
| | 9,069 |
|
| Goodwill and intangible assets, net | — |
| | — |
| | 373 |
| | — |
| | 373 |
|
| Advances receivable — consolidated subsidiaries | 2,953 |
| | 2,760 |
| | — |
| | (5,713 | ) | | — |
|
| Investments in consolidated subsidiaries | 3,868 |
| | 6,587 |
| | — |
| | (10,455 | ) | | — |
|
| Investments in unconsolidated affiliates | — |
| | — |
| | 2,969 |
| | — |
| | 2,969 |
|
| Other long-term assets | — |
| | — |
| | 206 |
| | — |
| | 206 |
|
| Total assets | $ | 6,821 |
| | $ | 9,347 |
| | $ | 13,611 |
| | $ | (16,168 | ) | | $ | 13,611 |
|
| LIABILITIES AND EQUITY | | | | | | | | | |
| Accounts payable and other current liabilities | $ | — |
| | $ | 72 |
| | $ | 1,051 |
| | $ | — |
| | $ | 1,123 |
|
| Current maturities of long-term debt | — |
| | 500 |
| | — |
| | — |
| | 500 |
|
| Advances payable — consolidated subsidiaries | — |
| | — |
| | 5,713 |
| | (5,713 | ) | | — |
|
| Long-term debt | — |
| | 4,907 |
| | — |
| | — |
| | 4,907 |
|
| Other long-term liabilities | — |
| | — |
| | 228 |
| | — |
| | 228 |
|
| Total liabilities | — |
| | 5,479 |
| | 6,992 |
| | (5,713 | ) | | 6,758 |
|
| Commitments and contingent liabilities |
| |
| |
| |
| |
|
| Equity: | | | | | | | | | |
| Partners’ equity: | | | | | | | | | |
| Net equity | 6,821 |
| | 3,871 |
| | 6,592 |
| | (10,455 | ) | | 6,829 |
|
| Accumulated other comprehensive loss | — |
| | (3 | ) | | (5 | ) | | — |
| | (8 | ) |
| Total partners’ equity | 6,821 |
| | 3,868 |
| | 6,587 |
| | (10,455 | ) | | 6,821 |
|
| Noncontrolling interests | — |
| | — |
| | 32 |
| | — |
| | 32 |
|
| Total equity | 6,821 |
| | 3,868 |
| | 6,619 |
| | (10,455 | ) | | 6,853 |
|
| Total liabilities and equity | $ | 6,821 |
| | $ | 9,347 |
| | $ | 13,611 |
| | $ | (16,168 | ) | | $ | 13,611 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Operations |
| | Three Months Ended September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non- Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Operating revenues: | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | $ | — |
| | $ | — |
| | $ | 1,936 |
| | $ | — |
| | $ | 1,936 |
|
| Transportation, processing and other | — |
| | — |
| | 162 |
| | — |
| | 162 |
|
| Trading and marketing losses, net | — |
| | — |
| | (43 | ) | | — |
| | (43 | ) |
| Total operating revenues | — |
| | — |
| | 2,055 |
| | — |
| | 2,055 |
|
| Operating costs and expenses: | | | | | | | | | |
| Purchases of natural gas and NGLs | — |
| | — |
| | 1,695 |
| | — |
| | 1,695 |
|
| Operating and maintenance expense | — |
| | — |
| | 168 |
| | — |
| | 168 |
|
| Depreciation and amortization expense | — |
| | — |
| | 94 |
| | — |
| | 94 |
|
| General and administrative expense | — |
| | — |
| | 69 |
| | — |
| | 69 |
|
| Asset impairments | — |
| | — |
| | 48 |
| | — |
| | 48 |
|
| Total operating costs and expenses | — |
| | — |
| | 2,074 |
| | — |
| | 2,074 |
|
| Operating loss | — |
| | — |
| | (19 | ) | | — |
| | (19 | ) |
| Interest expense | — |
| | (73 | ) | | — |
| | — |
| | (73 | ) |
| (Loss) income from consolidated subsidiaries | (20 | ) | | 53 |
| | — |
| | (33 | ) | | — |
|
| Earnings from unconsolidated affiliates | — |
| | — |
| | 74 |
| | — |
| | 74 |
|
| (Loss) income before income taxes | (20 | ) | | (20 | ) | | 55 |
| | (33 | ) | | (18 | ) |
| Income tax expense | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| Net (loss) income | (20 | ) | | (20 | ) | | 53 |
| | (33 | ) | | (20 | ) |
| Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Net (loss) income attributable to partners | $ | (20 | ) | | $ | (20 | ) | | $ | 53 |
| | $ | (33 | ) | | $ | (20 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Comprehensive (Loss) Income |
| | Three Months Ended September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Net (loss) income | $ | (20 | ) | | $ | (20 | ) | | $ | 53 |
| | $ | (33 | ) | | $ | (20 | ) |
| Total other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
|
| Total comprehensive (loss) income | (20 | ) | | (20 | ) | | 53 |
| | (33 | ) | | (20 | ) |
| Total comprehensive income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Total comprehensive (loss) income attributable to partners | $ | (20 | ) | | $ | (20 | ) | | $ | 53 |
| | $ | (33 | ) | | $ | (20 | ) |
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Operations |
| | Three Months Ended September 30, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Operating revenues: | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | $ | — |
| | $ | — |
| | $ | 1,646 |
| | $ | — |
| | $ | 1,646 |
|
| Transportation, processing and other | — |
| | — |
| | 162 |
| | — |
| | 162 |
|
| Trading and marketing gains, net | — |
| | — |
| | 15 |
| | — |
| | 15 |
|
| Total operating revenues | — |
| | — |
| | 1,823 |
| | — |
| | 1,823 |
|
| Operating costs and expenses: | | | | | | | | | |
| Purchases of natural gas and NGLs | — |
| | — |
| | 1,437 |
| | — |
| | 1,437 |
|
| Operating and maintenance expense | — |
| | — |
| | 161 |
| | — |
| | 161 |
|
| Depreciation and amortization expense | — |
| | — |
| | 94 |
| | — |
| | 94 |
|
| General and administrative expense | — |
| | — |
| | 64 |
| | — |
| | 64 |
|
| Gain on sale of assets, net | — |
| | — |
| | (41 | ) | | — |
| | (41 | ) |
| Restructuring costs | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| Other expense, net | — |
| | — |
| | 14 |
| | — |
| | 14 |
|
| Total operating costs and expenses | — |
| | — |
| | 1,731 |
| | — |
| | 1,731 |
|
| Operating income | — |
| | — |
| | 92 |
| | — |
| | 92 |
|
| Interest expense, net | — |
| | (77 | ) | | — |
| | — |
| | (77 | ) |
| Income from consolidated subsidiaries | 89 |
| | 166 |
| | — |
| | (255 | ) | | — |
|
| Earnings from unconsolidated affiliates | — |
| | — |
| | 75 |
| | — |
| | 75 |
|
| Income before income taxes | 89 |
| | 89 |
| | 167 |
| | (255 | ) | | 90 |
|
| Income tax expense | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Net income | 89 |
| | 89 |
| | 166 |
| | (255 | ) | | 89 |
|
| Net income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Net income attributable to partners | $ | 89 |
| | $ | 89 |
| | $ | 166 |
| | $ | (255 | ) | | $ | 89 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Comprehensive Income |
| | Three Months Ended September 30, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Net income | $ | 89 |
| | $ | 89 |
| | $ | 166 |
| | $ | (255 | ) | | $ | 89 |
|
| Total other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
|
| Total comprehensive income | 89 |
| | 89 |
| | 166 |
| | (255 | ) | | 89 |
|
| Total comprehensive income attributable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
|
| Total comprehensive income attributable to partners | $ | 89 |
| | $ | 89 |
| | $ | 166 |
| | $ | (255 | ) | | $ | 89 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Operations |
| | Nine Months Ended September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non- Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Operating revenues: | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | $ | — |
| | $ | — |
| | $ | 5,641 |
| | $ | — |
| | $ | 5,641 |
|
| Transportation, processing and other | — |
| | — |
| | 474 |
| | — |
| | 474 |
|
| Trading and marketing gains, net | — |
| | — |
| | 10 |
| | — |
| | 10 |
|
| Total operating revenues | — |
| | — |
| | 6,125 |
| | — |
| | 6,125 |
|
| Operating costs and expenses: | | | | | | | | | |
| Purchases of natural gas and NGLs | — |
| | — |
| | 4,939 |
| | — |
| | 4,939 |
|
| Operating and maintenance expense | — |
| | — |
| | 513 |
| | — |
| | 513 |
|
| Depreciation and amortization expense | — |
| | — |
| | 282 |
| | — |
| | 282 |
|
| General and administrative expense | — |
| | — |
| | 202 |
| | — |
| | 202 |
|
| Asset impairments | — |
| | — |
| | 48 |
| | — |
| | 48 |
|
| Gain on sale of assets, net | — |
| | — |
| | (34 | ) | | — |
| | (34 | ) |
| Other expense, net | — |
| | — |
| | 15 |
| | — |
| | 15 |
|
| Total operating costs and expenses | — |
| | — |
| | 5,965 |
| | — |
| | 5,965 |
|
| Operating income | — |
| | — |
| | 160 |
| | — |
| | 160 |
|
| Interest expense, net | — |
| | (219 | ) | | — |
| | — |
| | (219 | ) |
| Income from consolidated subsidiaries | 169 |
| | 388 |
| | — |
| | (557 | ) | | — |
|
| Earnings from unconsolidated affiliates | — |
| | — |
| | 234 |
| | — |
| | 234 |
|
| Income before income taxes | 169 |
| | 169 |
| | 394 |
| | (557 | ) | | 175 |
|
| Income tax expense | — |
| | — |
| | (5 | ) | | — |
| | (5 | ) |
| Net income | 169 |
| | 169 |
| | 389 |
| | (557 | ) | | 170 |
|
| Net income attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Net income attributable to partners | $ | 169 |
| | $ | 169 |
| | $ | 388 |
| | $ | (557 | ) | | $ | 169 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Comprehensive Income |
| | Nine Months Ended September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Net income | $ | 169 |
| | $ | 169 |
| | $ | 389 |
| | $ | (557 | ) | | $ | 170 |
|
| Other comprehensive income: | | | | | | | | | |
| Reclassification of cash flow hedge losses into earnings | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
| Other comprehensive income from consolidated subsidiaries | 1 |
| | — |
| | — |
| | (1 | ) | | — |
|
| Total other comprehensive income | 1 |
| | 1 |
| | — |
| | (1 | ) | | 1 |
|
| Total comprehensive income | 170 |
| | 170 |
| | 389 |
| | (558 | ) | | 171 |
|
| Total comprehensive income attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Total comprehensive income attributable to partners | $ | 170 |
| | $ | 170 |
| | $ | 388 |
| | $ | (558 | ) | | $ | 170 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Operations |
| | Nine Months Ended September 30, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non- Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Operating revenues: | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | $ | — |
| | $ | — |
| | $ | 4,431 |
| | $ | — |
| | $ | 4,431 |
|
| Transportation, processing and other | — |
| | — |
| | 469 |
| | — |
| | 469 |
|
| Trading and marketing gains, net | — |
| | — |
| | 10 |
| | — |
| | 10 |
|
| Total operating revenues | — |
| | — |
| | 4,910 |
| | — |
| | 4,910 |
|
| Operating costs and expenses: | | | | | | | | | |
| Purchases of natural gas and NGLs | — |
| | — |
| | 3,866 |
| | — |
| | 3,866 |
|
| Operating and maintenance expense | — |
| | — |
| | 506 |
| | — |
| | 506 |
|
| Depreciation and amortization expense | — |
| | — |
| | 284 |
| | — |
| | 284 |
|
| General and administrative expense | — |
| | — |
| | 187 |
| | — |
| | 187 |
|
| Gain on sale of assets, net | — |
| | — |
| | (35 | ) | | — |
| | (35 | ) |
| Restructuring costs | — |
| | — |
| | 10 |
| | — |
| | 10 |
|
| Other income, net | — |
| | — |
| | (68 | ) | | — |
| | (68 | ) |
| Total operating costs and expenses | — |
| | — |
| | 4,750 |
| | — |
| | 4,750 |
|
| Operating income | — |
| | — |
| | 160 |
| | — |
| | 160 |
|
| Interest expense, net | — |
| | (235 | ) | | — |
| | — |
| | (235 | ) |
| Income from consolidated subsidiaries | 132 |
| | 367 |
| | — |
| | (499 | ) | | — |
|
| Earnings from unconsolidated affiliates | — |
| | — |
| | 214 |
| | — |
| | 214 |
|
| Income before income taxes | 132 |
| | 132 |
| | 374 |
| | (499 | ) | | 139 |
|
| Income tax expense | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) |
| Net income | 132 |
| | 132 |
| | 368 |
| | (499 | ) | | 133 |
|
| Net income attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Net income attributable to partners | $ | 132 |
| | $ | 132 |
| | $ | 367 |
| | $ | (499 | ) | | $ | 132 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Comprehensive Income |
| | Nine Months Ended September 30, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| Net income | $ | 132 |
| | $ | 132 |
| | $ | 368 |
| | $ | (499 | ) | | $ | 133 |
|
| Total other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
|
| Total comprehensive income | 132 |
| | 132 |
| | 368 |
| | (499 | ) | | 133 |
|
| Total comprehensive income attributable to noncontrolling interests | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
| Total comprehensive income attributable to partners | $ | 132 |
| | $ | 132 |
| | $ | 367 |
| | $ | (499 | ) | | $ | 132 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statement of Cash Flows |
| | Nine Months Ended September 30, 2017 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net cash (used in) provided by operating activities | $ | — |
| | $ | (217 | ) | | $ | 901 |
| | $ | — |
| | $ | 684 |
|
| INVESTING ACTIVITIES: | | | | | | | | | |
| Intercompany transfers | 390 |
| | 724 |
| | — |
| | (1,114 | ) | | — |
|
| Capital expenditures | — |
| | — |
| | (258 | ) | | — |
| | (258 | ) |
| Investments in unconsolidated affiliates | — |
| | — |
| | (70 | ) | | — |
| | (70 | ) |
| Proceeds from sale of assets | — |
| | — |
| | 130 |
| | — |
| | 130 |
|
| Net cash provided by (used in) investing activities | 390 |
| | 724 |
| | (198 | ) | | (1,114 | ) | | (198 | ) |
| FINANCING ACTIVITIES: | | | | | | | | | |
| Intercompany transfers | — |
| | — |
| | (1,114 | ) | | 1,114 |
| | — |
|
| Payments of long-term debt | — |
| | (195 | ) | | — |
| | — |
| | (195 | ) |
| Net change in advances to predecessor from DCP Midstream, LLC | — |
| | — |
| | 418 |
| | — |
| | 418 |
|
| Distributions to limited partners and general partner | (390 | ) | | — |
| | — |
| | — |
| | (390 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) |
| Other | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
| Net cash used in by financing activities | (390 | ) | | (197 | ) | | (702 | ) | | 1,114 |
| | (175 | ) |
| Net change in cash and cash equivalents | — |
| | 310 |
| | 1 |
| | — |
| | 311 |
|
| Cash and cash equivalents, beginning of period | — |
| | — |
| | 1 |
| | — |
| | 1 |
|
| Cash and cash equivalents, end of period | $ | — |
| | $ | 310 |
| | $ | 2 |
| | $ | — |
| | $ | 312 |
|
DCP MIDSTREAM, LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Three and Nine Months Ended September 30, 2017 and 2016 - (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | |
| | Condensed Consolidating Statements of Cash Flows |
| | Nine Months Ended September 30, 2016 |
| | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Consolidating Adjustments | | Consolidated |
| | (Millions) |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net cash (used in) provided by operating activities | $ | — |
| | $ | (244 | ) | | $ | 765 |
| | $ | — |
| | $ | 521 |
|
| INVESTING ACTIVITIES: | | | | | | | | | |
| Intercompany transfers | 362 |
| | 559 |
| | — |
| | (921 | ) | | — |
|
| Capital expenditures | — |
| | — |
| | (113 | ) | | — |
| | (113 | ) |
| Investments in unconsolidated affiliates | — |
| | — |
| | (38 | ) | | — |
| | (38 | ) |
| Proceeds from sale of assets | — |
| | — |
| | 160 |
| | — |
| | 160 |
|
| Net cash provided by investing activities | 362 |
| | 559 |
| | 9 |
| | (921 | ) | | 9 |
|
| FINANCING ACTIVITIES: | | | | | | | | | |
| Intercompany transfers | — |
| | — |
| | (921 | ) | | 921 |
| | — |
|
| Proceeds from long-term debt | — |
| | 2,926 |
| | — |
| | — |
| | 2,926 |
|
| Payments of long-term debt | — |
| | (3,216 | ) | | — |
| | — |
| | (3,216 | ) |
| Net change in advances to predecessor from DCP Midstream, LLC | — |
| | — |
| | 150 |
| | — |
| | 150 |
|
| Distributions to limited partners and general partner | (362 | ) | | — |
| | — |
| | — |
| | (362 | ) |
| Distributions to noncontrolling interests | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) |
| Other | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) |
| Net cash used in financing activities | (362 | ) | | (300 | ) | | (777 | ) | | 921 |
| | (518 | ) |
| Net change in cash and cash equivalents | — |
| | 15 |
| | (3 | ) | | — |
| | 12 |
|
| Cash and cash equivalents, beginning of period | — |
| | — |
| | 3 |
| | — |
| | 3 |
|
| Cash and cash equivalents, end of period | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | 15 |
|
19.17. Subsequent Events
Distributions — On October 19, 2017,July 14, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution on our Common Units of $0.78$0.43 per unit.Common Unit. The distribution is payablewill be paid on November 14, 2017August 11, 2023 to unitholders of record on November 7, 2017.July 31, 2023.
Also on July 14, 2023, the board of directors of the General Partner declared a quarterly distribution on our Series C Preferred Units of $0.4969 per unit. The Series C distribution will be paid on October 16, 2023 to unitholders of record on October 2, 2023.
Item 2.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 condensed consolidated financial statements and notes included elsewhere in this Quarterly Report on Form 10-Q and the consolidated financial statements and notes thereto included as Exhibit 99.4 in our Annual Report on Form 10-K for the May 2017 8-K.year ended December 31, 2022.
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. Concurrent with the completion of the Transaction in the first quarter of 2017, management reevaluated our reportable segments and determined that ourOur operations are organized into two reportable segments: (i) Logistics and Marketing and (ii) Gathering and Processing and (ii)Processing. Our Logistics and Marketing. Segment information for earlier periods has been restated to reflect these reportable segments. Our Gathering and ProcessingMarketing segment includes operating segments that have been aggregated based on the nature of the productstransporting, trading, marketing and services provided.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.
Completion of Merger with Phillips 66
On June 15, 2023, pursuant to the terms of the previously disclosed Agreement and selling condensate. Our LogisticsPlan of Merger, dated as of January 5, 2023 (the “Merger Agreement”), by and Marketing segment includes transporting, trading, marketingamong the Partnership, DCP Midstream GP, LP, the general partner of the Partnership (the “General Partner”), DCP Midstream GP, LLC, the general partner of the General Partner, Phillips 66, Phillips 66 Project Development Inc., an indirect wholly owned subsidiary of Phillips 66 (“PDI”), and storing natural gasDynamo Merger Sub LLC, a wholly owned subsidiary of PDI (“Merger Sub”), Merger Sub merged with and NGLs, fractionating NGLsinto 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 (the “Effective Time”), each common unit representing a limited partner interest in the Partnership (each, a “Common Unit”) issued and wholesale propane logistics.outstanding as of immediately prior to the Effective Time (other than the Sponsor Owned Units, as defined below) (each, a “Public Common Unit”) was converted into the right to receive $41.75 per Public Common Unit in cash, without any interest thereon (the “Merger Consideration”). The remainderCommon Units owned by DCP Midstream, LLC and the General Partner (collectively, the “Sponsor Owned Units”) were unaffected by the Merger and remained outstanding immediately following the Merger as Common Units of the Partnership. Following the Merger, the Common Units were delisted from the New York Stock Exchange (“NYSE”) and a Form 15 has been filed to deregister the Common Units under the Securities Exchange Act of 1934, as amended.
We continue to integrate certain of our operations with Phillips 66’s midstream segment, including the integration of operational services that were previously provided by DCP Services, LLC. As part of these integration efforts, we incurred restructuring costs that primarily consisted of severance and employee related charges. Continuing employees transferred employment to a Phillips 66 subsidiary on April 1, 2023, and general and administrative services will be provided by Phillips 66 or one or more of its subsidiaries going forward. Phillips 66 is the managing member of our General Partner and, therefore, is responsible for conducting, directing, and managing our business operations is presented as "Other", and consistsaffairs.
General Trends and Outlook
We anticipate our business will continue to be affected by the key trends discussed herein. 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, unallocated corporate costs.available information prove to be incorrect, our actual results may vary materially from our expected results.
Our business is impacted by commodity prices and volumes. We mitigate a portion of commodity price risk on an overall Partnership basis by growingthrough our fee based assets and by executing on our hedging program, in which we hedge commodity prices associated with a portion of our expected natural gas, NGL and condensate equity volumes in our Gathering and Processing segment.fee-based assets. Various factors impact both commodity prices and volumes, and as indicated in Item 3. "Quantitative3. “Quantitative and Qualitative Disclosures about Market Risk,"” we have sensitivities to certain cash and non-cash changes in commodity prices. If commodityCommodity prices weaken for a sustained period, our volumes may be impacted, particularlyare volatile and are subject to global energy supply and demand fundamentals as producers are curtailing or redirecting drilling.well as geopolitical disruptions. Drilling activity levels vary by geographic area;area and we will continue to target our strategy in geographic areas where we expect producer drilling activity. Our long-term viewbusiness is thatpredominantly fee-based and we have a diversified portfolio to balance the upside of our earnings potential while reducing our commodity prices will be at levels we believe will support growth in natural gas, condensate and NGL production.exposure. We believeexpect future commodity prices will be influenced by the severity of winterglobal economic conditions and summer weather,geopolitical disruptions, the level of North American production and drilling activity by exploration and production companies, and the balance of trade between imports and exports of liquid natural gas, NGLs and crude oil.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, our assets will be managed in a manner consistent with the emissions intensity reduction goals of Phillips 66.
Our business is primarily driven by the demandlevel of production of natural gas by producers and of NGLs from petrochemicalprocessing plants connected to our pipelines and refining industries and export facilities. The petrochemical industry has been making significant investment in building and expanding facilities to convert chemical plants from a heavier oil-based feedstock to lighter NGL-based feedstocks, including ethane. This increased demand expected in the next year should provide support for the increasing supply of ethane. As these facilities commence operations, ethane prices could remain weak with supply in excess of demand. In addition, export facilities are being expanded and built, which provide support for the increasing supply of NGLs. Although therefractionators. These volumes can be impacted negatively by, among other things, reduced drilling activity, depressed commodity prices, severe weather disruptions, operational outages and has been, volatilityethane rejection. Upstream producers response to changes in NGLcommodity prices longer term we believe there will be sufficientand demand in NGLs to support increasing supply.remain uncertain.
Although we have seen a number of bankruptcies by producers in recent years, weWe believe our contract structure with our producers protectsprovides us with significant protection from a credit perspectiverisk 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, eight9 have investment grade credit ratings while the remainder do not.ratings.
In additionThe global economic outlook continues to thebe a cause for concern for U.S. financial markets manyand businesses and investors continue to monitor global economic conditions. Uncertainty abroadalike. This uncertainty may contribute to volatility in domestic financial and commodity markets.
We believe we are positioned to withstand current and future commodity price volatility as a result of the following:
•Our growing fee-based business represents a significant portion of our margins.
•We have positive operating cash flow from our well-positioned and diversified assets.
We have a well-defined and targeted hedging program.
•We manage our disciplined capital growth program with a significant focus on fee-based agreements and projects with long termlong-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.
We have engaged in a disciplined growth strategy in recent years focusing on our key areas of operations. Our targeted strategy may take numerous forms such as organic build opportunities within our footprint, joint venture opportunities,including excess distribution coverage and acquisitions. Growth opportunities will be evaluated in cooperation with producers and customers based on the expected level of drilling activity in these geographic regions and the impacts of higher costs of capital.
Some of our growth projects include the following:
Within our Gathering and Processing segment, we increased capacity in the DJ Basin by up to 40 MMcf/d starting in June 2017 by placing additional field compression and plant bypass infrastructure in service.
We are constructing a 200 MMcf/d natural gas processing plant, the Mewbourn 3 plant, and further expanding our Grand Parkway gathering system, both of which are located in the DJ Basin and expected to be in service in the fourth quarter of 2018.
Our 200 MMcf/d O'Connor 2 plant and associated gathering infrastructure, located in the DJ Basin, is also approved and expected to be in service in mid 2019.
Within our Logistics and Marketing segment, we are currently expanding the Sand Hills pipeline to 365 MBbls/d, expected to be completed late fourth quarter of 2017 or early first quarter of 2018, and have multiple Sand Hills lateral connections in flight throughout 2017.
Further Sand Hills pipeline expansion to 450 MBbls/d is progressing and includes a partial looping of the pipeline and the addition of new pump stations, and is expected to be in service in the third quarter of 2018.
We signed a letter of intent with respect to the joint development of the Gulf Coast Express pipeline project (GCX project) with Kinder Morgan Texas Pipeline LLC and Targa Resources Corp, which would provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The capacity of the GCX project is expected to be 1.92 Bcf/d. The mostly 42-inch pipeline would traverse approximately 500 miles and be in service in the second half of 2019, pending final shipper commitments and a final investment decision by all three entities. Under the terms of the letter of intent, we will own a 25 percent equity interest in the project and would commit significant volumes.
Recent Events
We are jointly developing the Cheyenne Connector pipeline (“Cheyenne Connector”) with Tallgrass Energy Partners, LP and Western Gas Partners, LP, in which we have an option to invest in at a later date. Tallgrass Energy Partners, LP has announced the launch of an open season to transport natural gas on the Cheyenne Connector from the DJ Basin to the Rockies Express Pipeline (“REX”) Cheyenne Hub just south of the Colorado-Wyoming border. Cheyenne Connector has signed long-term precedent agreements to transport at least 600 MMcf/d of natural gas with affiliates of Anadarko Petroleum Corporation and the Partnership. Cheyenne Connector will provide takeaway solutions for DJ Basin gas producers, connecting natural gas to REX’s Cheyenne Hub where it can then be delivered to numerous demand markets across the country on either REX or other interconnected pipelines.
In August 2017, we experienced business interruptions at certain of our assets as a result of Hurricane Harvey. Our logistics facilities, including Sand Hills, Southern Hills and other NGL pipelines connecting to the Gulf Coast remained operational for the duration of the storm, but volumes were impacted due to downstream constraints. Based on current assessments, no significant damage has been identified to our assets, however, final assessments are still underway.
We announced a quarterly distribution of $0.78 per unit for the third quarter of 2017. This distribution per unit remains unchanged from the previous quarter and the third quarter of 2016.
General Trends and Outlookdivestitures.
During 2017,2023, our strategic objectives will continueobjective is to focus on maintaining stable Distributablegenerate Excess Free Cash Flows from our existing assets and executing on opportunities to sustain our long-term Distributable(a non-GAAP measure defined in “Reconciliation of Non-GAAP Measures - Excess Free Cash Flows in light of the significant changes to our business resulting from the Transaction.Flows”). We believe the key elements to stable Distributablegenerating Excess Free Cash Flows are the diversity of our asset portfolio and our fee-based business which represents a significant portion of our estimated margins, plusmargins. We will continue to pursue incremental revenue, cost efficiencies and operating improvements of our hedged commodity position, the objective of which is to protect against downside risk in our Distributable Cash Flows.assets through process and technology improvements.
We incur capital expenditures for our consolidated entities and our unconsolidated affiliates. Our 20172023 plan includes maintenancesustaining capital expenditures of between $100 million and $145approximately $150 million and expansion capital expenditures between $325 millionof approximately $125 million.
Recent Events
Common and $375 million associated with approved projects. We forecast maintenance spending to be atPreferred Distributions
On July 14, 2023, we announced that the low endboard of directors of the range, and expansion spendingGeneral Partner declared a quarterly distribution on our Common Units of $0.43 per Common Unit. The distribution will be paid on August 11, 2023 to be atunitholders of record on July 31, 2023.
Also on July 14, 2023, the high endboard of directors of the range. Expansion capital expenditures include the constructionGeneral Partner declared a quarterly distribution on our Series C Preferred Units of the Mewbourn 3 plant, Grand Parkway Phase$0.4969 per unit. The Series C distribution will be paid on October 16, 2023 to unitholders of record on October 2, and O'Connor bypass in our DJ Basin system, and the capacity expansions of the Sand Hills pipeline, which are shown as an investment in unconsolidated affiliates in our condensed consolidated statements of cash flows.2023.
For an in-depth discussion of factors that may significantly affect our results, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Factors That May Significantly Affect Our Results” included as Exhibit 99.3 in our current report on the May 2017 8-K.
Results of Operations
Consolidated Overview
The following table and discussion isprovides a summary of our condensed consolidated results of operations for the three and nine months ended SeptemberJune 30, 20172023 and 2016.2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
| | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Variance Three Months 2017 vs. 2016 | | Variance Nine Months 2017 vs. 2016 | | | Three Months Ended June 30, | | Six Months Ended June 30, | | | Variance Three Months
2023 vs. 2022 | | Variance Six Months
2023 vs. 2022 |
| | | 2017 | | 2016 | | 2017 | | 2016 | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent | | | 2023 | | 2022 | | 2023 | | 2022 | | | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent |
| | (Millions, except operating data) | | (millions, except operating data) |
| Operating revenues (a): | | | | | | | | | | | | | | | | | Operating revenues (a): | | | | | |
| Logistics and Marketing | | Logistics and Marketing | | $ | 1,561 | | | $ | 3,789 | | | $ | 3,953 | | | $ | 6,952 | | | | | $ | (2,228) | | | (59 | %) | | $ | (2,999) | | | (43 | %) |
| Gathering and Processing | | $ | 1,337 |
| | $ | 1,217 |
| | $ | 3,965 |
| | $ | 3,190 |
| | $ | 120 |
| | 10 | % | | $ | 775 |
| | 24 | % | Gathering and Processing | | 1,252 | | | 2,967 | | | 3,018 | | | 5,073 | | | | | (1,715) | | | (58 | %) | | (2,055) | | | (41 | %) |
| Logistics and Marketing | | 1,913 |
| | 1,641 |
| | 5,596 |
| | 4,362 |
| | 272 |
| | 17 | % | | 1,234 |
| | 28 | % | |
| Inter-segment eliminations | | (1,195 | ) | | (1,035 | ) | | (3,436 | ) | | (2,642 | ) | | 160 |
| | 15 | % | | 794 |
| | 30 | % | Inter-segment eliminations | | (972) | | | (2,487) | | | (2,404) | | | (4,381) | | | | | (1,515) | | | (61 | %) | | (1,977) | | | (45 | %) |
| Total operating revenues | | 2,055 |
| | 1,823 |
| | 6,125 |
| | 4,910 |
| | 232 |
| | 13 | % | | 1,215 |
| | 25 | % | Total operating revenues | | 1,841 | | | 4,269 | | | 4,567 | | | 7,644 | | | | | (2,428) | | | (57 | %) | | (3,077) | | | (40 | %) |
| Purchases of natural gas and NGLs | | | | | | | | | | | | | | | | | |
| Purchases and related costs | | Purchases and related costs | | | | | | | | | | | | |
| Logistics and Marketing | | Logistics and Marketing | | (1,503) | | | (3,749) | | | (3,841) | | | (6,896) | | | | | (2,246) | | | (60 | %) | | (3,055) | | | (44 | %) |
| Gathering and Processing | | (1,034 | ) | | (882 | ) | | (2,944 | ) | | (2,298 | ) | | 152 |
| | 17 | % | | 646 |
| | 28 | % | Gathering and Processing | | (881) | | | (2,382) | | | (2,203) | | | (4,204) | | | | | (1,501) | | | (63 | %) | | (2,001) | | | (48 | %) |
| Logistics and Marketing | | (1,856 | ) | | (1,590 | ) | | (5,431 | ) | | (4,210 | ) | | 266 |
| | 17 | % | | 1,221 |
| | 29 | % | |
| Inter-segment eliminations | | 1,195 |
| | 1,035 |
| | 3,436 |
| | 2,642 |
| | 160 |
| | 15 | % | | 794 |
| | 30 | % | Inter-segment eliminations | | 972 | | | 2,487 | | | 2,404 | | | 4,381 | | | | | (1,515) | | | (61 | %) | | (1,977) | | | (45 | %) |
| Total purchases | | (1,695 | ) | | (1,437 | ) | | (4,939 | ) | | (3,866 | ) | | 258 |
| | 18 | % | | 1,073 |
| | 28 | % | Total purchases | | (1,412) | | | (3,644) | | | (3,640) | | | (6,719) | | | | | (2,232) | | | (61 | %) | | (3,079) | | | (46 | %) |
| Operating and maintenance expense | | (168 | ) | | (161 | ) | | (513 | ) | | (506 | ) | | 7 |
| | 4 | % | | 7 |
| | 1 | % | Operating and maintenance expense | | (229) | | | (189) | | | (426) | | | (341) | | | | | 40 | | | 21 | % | | 85 | | | 25 | % |
| Depreciation and amortization expense | | (94 | ) | | (94 | ) | | (282 | ) | | (284 | ) | | — |
| | — | % | | (2 | ) | | (1 | )% | Depreciation and amortization expense | | (91) | | | (90) | | | (181) | | | (180) | | | | | 1 | | | 1 | % | | 1 | | | 1 | % |
| General and administrative expense | | (69 | ) | | (64 | ) | | (202 | ) | | (187 | ) | | 5 |
| | 8 | % | | 15 |
| | 8 | % | General and administrative expense | | (68) | | | (65) | | | (148) | | | (120) | | | | | 3 | | | 5 | % | | 28 | | | 23 | % |
| Asset impairments | | (48 | ) | | — |
| | (48 | ) | | — |
| | 48 |
| | * |
| | 48 |
| | * |
| Asset impairments | | — | | | (1) | | | — | | | (1) | | | | | (1) | | | * | | (1) | | | * |
| Other (expense) income, net | | — |
| | (14 | ) | | (15 | ) | | 68 |
| | 14 |
| | * |
| | (83 | ) | | * |
| |
| Other income, net | | Other income, net | | — | | | 8 | | | — | | | 8 | | | | | (8) | | | * | | (8) | | | * |
| (Loss) gain on sale of assets, net | | (Loss) gain on sale of assets, net | | (3) | | | — | | | (3) | | | 7 | | | | | 3 | | | * | | 10 | | | * |
| Restructuring costs | | Restructuring costs | | (16) | | | — | | | (26) | | | — | | | | | 16 | | | * | | 26 | | | * |
| | Earnings from unconsolidated affiliates (b) | | 74 |
| | 75 |
| | 234 |
| | 214 |
| | (1 | ) | | (1 | )% | | 20 |
| | 9 | % | Earnings from unconsolidated affiliates (b) | | 148 | | | 168 | | | 308 | | | 311 | | | | | (20) | | | (12 | %) | | (3) | | | (1 | %) |
| Interest expense | | (73 | ) | | (77 | ) | | (219 | ) | | (235 | ) | | (4 | ) | | (5 | )% | | (16 | ) | | (7 | )% | Interest expense | | (75) | | | (70) | | | (143) | | | (141) | | | | | 5 | | | 7 | % | | 2 | | | 1 | % |
| Income tax expense | | (2 | ) | | (1 | ) | | (5 | ) | | (6 | ) | | 1 |
| | * |
| | (1 | ) | | (17 | )% | Income tax expense | | — | | | (2) | | | (1) | | | (3) | | | | | (2) | | | * | | (2) | | | (67 | %) |
| Restructuring costs | | — |
| | (2 | ) | | — |
| | (10 | ) | | (2 | ) | | * |
| | (10 | ) | | * |
| |
| Gain on sale of assets, net | | — |
| | 41 |
| | 34 |
| | 35 |
| | (41 | ) | | * |
| | (1 | ) | | * |
| |
| Net income attributable to noncontrolling interests | | — |
| | — |
| | (1 | ) | | (1 | ) | | — |
| | * |
| | — |
| | * |
| Net income attributable to noncontrolling interests | | (1) | | | (1) | | | (2) | | | (2) | | | | | — | | | — | % | | — | | | — | % |
| Net (loss) income attributable to partners | | $ | (20 | ) | | $ | 89 |
| | $ | 169 |
| | $ | 132 |
| | $ | (109 | ) | | * |
| | $ | 37 |
| | 28 | % | |
| Net income attributable to partners | | Net income attributable to partners | | $ | 94 | | | $ | 383 | | | $ | 305 | | | $ | 463 | | | | | $ | (289) | | | (75 | %) | | $ | (158) | | | (34 | %) |
| Other data: | | | | | | | | | |
| |
| |
| |
| Other data: | | | | | | | | | | | | |
| Gross margin (c): | | | | | | | | | | | | | | | | | |
| Adjusted gross margin (c): | | Adjusted gross margin (c): | | | | | |
| Logistics and Marketing | | Logistics and Marketing | | $ | 58 | | | $ | 40 | | | $ | 112 | | | $ | 56 | | | | | $ | 18 | | | 45 | % | | $ | 56 | | | * |
| Gathering and Processing | | $ | 303 |
| | $ | 335 |
| | $ | 1,021 |
| | $ | 892 |
| | $ | (32 | ) | | (10 | )% | | $ | 129 |
| | 14 | % | Gathering and Processing | | 371 | | | 585 | | | 815 | | | 869 | | | | | (214) | | | (37 | %) | | (54) | | | (6 | %) |
| Logistics and Marketing | | 57 |
| | 51 |
| | 165 |
| | 152 |
| | $ | 6 |
| | 12 | % | | $ | 13 |
| | 9 | % | |
| Total gross margin | | $ | 360 |
| | $ | 386 |
| | $ | 1,186 |
| | $ | 1,044 |
| | $ | (26 | ) | | (7 | )% | | $ | 142 |
| | 14 | % | |
| Total adjusted gross margin | | Total adjusted gross margin | | $ | 429 | | | $ | 625 | | | $ | 927 | | | $ | 925 | | | | | $ | (196) | | | (31 | %) | | $ | 2 | | | — | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-cash commodity derivative mark-to-market | | $ | (59 | ) | | $ | 9 |
| | $ | 1 |
| | $ | (80 | ) | | $ | (68 | ) | | * |
| | $ | 81 |
| | * |
| Non-cash commodity derivative mark-to-market | | $ | 7 | | | $ | 101 | | | $ | 47 | | | $ | (75) | | | | | $ | (94) | | | (93 | %) | | $ | 122 | | | * |
| NGL pipelines throughput (MBbls/d) (d) | | NGL pipelines throughput (MBbls/d) (d) | | 702 | | | 720 | | | 713 | | | 701 | | | | | (18) | | | (3 | %) | | 12 | | | 2 | % |
| Gas pipelines throughput (TBtu/d) (d) | | Gas pipelines throughput (TBtu/d) (d) | | 1.07 | | | 1.09 | | | 1.08 | | | 1.09 | | | | | (0.02) | | | (2 | %) | | (0.01) | | | (1 | %) |
| Natural gas wellhead (MMcf/d) (d) | | 4,460 |
| | 5,005 |
| | 4,508 |
| | 5,230 |
| | (545 | ) | | (11 | )% | | (722 | ) | | (14 | )% | Natural gas wellhead (MMcf/d) (d) | | 4,481 | | | 4,383 | | | 4,477 | | | 4,246 | | | | | 98 | | | 2 | % | | 231 | | | 5 | % |
| NGL gross production (MBbls/d) (d) | | 376 |
| | 392 |
| | 365 |
| | 401 |
| | (16 | ) | | (4 | )% | | (36 | ) | | (9 | )% | NGL gross production (MBbls/d) (d) | | 446 | | | 427 | | | 433 | | | 414 | | | | | 19 | | | 4 | % | | 19 | | | 5 | % |
| NGL pipelines throughput (MBbls/d) (d) | | 462 |
| | 434 |
| | 447 |
| | 421 |
| | 28 |
| | 6 | % | | 26 |
| | 6 | % | |
|
* Percentage change is not meaningful.
| |
(a) | (a) Operating revenues include the impact of trading and marketing gains (losses), net. |
| |
(b) | Earnings for Discovery, Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of the investments and the underlying equity of the entities. |
| |
(c) | Gross margin consists of total operating revenues less purchases of natural gas and NGLs. Segment gross margin for each segment consists of total operating revenues for that segment less purchases of natural gas and NGLs 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. |
(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.
Three months ended SeptemberMonths Ended June 30, 20172023 vs. Three months ended SeptemberMonths Ended June 30, 20162022
Total Operating Revenues — Total operating revenues increased $232decreased $2,428 million in 20172023 compared to 20162022, primarily as a result of the following:
•$2722,228 million increasedecrease for our Logistics and Marketing segment, primarily due to higherlower commodity prices, partially offset by higher gas and NGL volumes, and favorable commodity derivative activity, partially offset by lower gasactivity; and NGL sales volumes;
•$1201,715 million increasedecrease for our Gathering and Processing segment, primarily due to higherlower commodity prices higher gas and NGL sales volumes primarily related to our North region which impact both salesa decrease in transportation, processing and purchases. These increases wereother, partially offset by lower gashigher volumes across all regions and NGL sales volumes in the South, Midcontinent and Permian regions, unfavorablefavorable commodity derivative activity and the sale of our Douglas gathering system;activity.
These increasesdecreases were partially offset by:
•$1601,515 million increasechange 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 higherlower commodity prices, partially offset by lower gas and NGL sales volumes.prices.
Total Purchases — Total purchases increased $258decreased $2,232 million in 20172023 compared to 20162022, primarily as a result of the following:
•$2662,246 million decrease for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and
•$1,501 million decrease for our Gathering and Processing segment for the commodity price and volume changes discussed above.
These decreases was partially offset by:
•$1,515 million change in inter-segment eliminations, for the reasons discussed above.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2023 compared to 2022 largely due to a legal settlement, higher base costs primarily in the Permian region and higher pipeline integrity spend.
Other Income — Other income in 2022 was primarily a result of contractual settlements.
Restructuring Costs — Restructuring costs in 2023 was primarily a result of an impairment, severance for termination benefits and other costs as a result of our ongoing integration with Phillips 66.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2023 compared to 2022 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 in 2022.
Net Income Attributable to Partners — Net income attributable to partners decreased in 2023 compared to 2022 for all of the reasons discussed above.
Adjusted Gross Margin — Adjusted gross margin decreased $196 million in 2023 compared to 2022, primarily as a result of the following:
•$214 million decrease for our Gathering and Processing segment, primarily as a result of lower commodity prices and lower margins in the South region, partially offset by favorable derivative activity attributable to our corporate equity hedge program and higher volumes in the Permian region; partially offset by
•$18 million increase for our Logistics and Marketing segment, primarily as a result of favorable commodity derivative activity on gas pipelines, a contract settlement in 2022, and improved NGL pipeline margins, partially offset by unfavorable NGL marketing activity and lower gas storage margins.
NGL Pipelines Throughput — NGL pipelines throughput decreased in 2023 compared to 2022 due to decreased volumes on the Sand Hills and Front Range pipelines, partially offset by increased throughput on Southern Hills pipeline.
Natural Gas Wellhead — Natural gas wellhead increased in 2023 compared to 2022 due to increased volumes in the Permian region and DJ Basin, partially offset by lower volumes in the Midcontinent region.
NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian, South, and Midcontinent regions.
Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022
Total Operating Revenues — Total operating revenues decreased $3,077 million in 2023 compared to 2022, primarily as a result of the following:
•$2,999 million decrease for the reasons discussed above;our Logistics and Marketing segment, primarily due to lower commodity prices, partially offset by higher gas and NGL volumes, and favorable commodity derivative activity; and
•$1522,055 million increasedecrease for our Gathering and Processing segment, for the reasons discussed above;primarily due to lower commodity prices and a decrease in transportation, processing and other, partially offset by higher volumes across all regions and favorable commodity derivative activity.
These increasesdecreases were partially offset by:
•$1601,977 million increasechange 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 higherlower commodity prices,prices.
Total Purchases — Total purchases decreased $3,079 million in 2023 compared to 2022, primarily as a result of the following:
•$3,055 million decrease for our Logistics and Marketing segment for the commodity price and volume changes discussed above; and
•$2,001 million decrease for our Gathering and Processing segment for the commodity price and volume changes discussed above.
These decreases were partially offset by lower gas and NGL sales volumes.by:
•$1,977 million change in inter-segment eliminations, for the reasons discussed above.
Operating and Maintenance Expense — Operating and maintenance expense increased in 20172023 compared to 20162022 largely due to higher base costs primarily asin the Permian region, a result of increased asset reliabilitylegal settlement, and planned maintenance spending associated with anticipated volume growth and investment in process improvements, partially offset by other cost savings initiatives and the sale of our Douglas system in June 2017.higher pipeline integrity spend.
General and Administrative Expense— General and administrative expense increased in 20172023 compared to 20162022, primarily due to higher integration costs and employee costs.
Other Income, Net — Other income in 2022 was primarily a result of contractual settlements.
(Loss) gain on sale of assets, net — The net loss on sale of assets in 2023 represents the sale of certain non-core assets in the Midcontinent region. The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region.
Restructuring Costs — Restructuring costs in 2023 was primarily a result of severance for termination benefits, an impairment and other costs as a result of investment in process and technology improvements.our ongoing integration with Phillips 66.
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.
Other (Expense) Income — Other expense in 2016 represents the write-off of property, plant and equipment.
Interest Expense - Interest expense decreased in 2017 compared to 2016 as a result of lower average outstanding debt balances.
Restructuring Costs - Restructuring costs in 2016 related to our headcount reduction in April of 2016.
Gain on Sale of Assets, Net — The gain on sale in 2016 represents the sale of our Northern Louisiana system.
Net (Loss) Income Attributable to Partners — Net income attributable to partners decreased in 20172023 compared to 20162022 for all of the reasons discussed above.
Adjusted Gross Margin — GrossAdjusted gross margin decreased $26increased $2 million in 20172023 compared to 20162022, primarily as a result of the following:
•$3256 million increase for our Logistics and Marketing segment, primarily as a result of favorable commodity derivative activity on gas pipelines, a contract settlement, and higher NGL pipeline margins, partially offset by lower gas storage and pipeline margins, unfavorable NGL marketing activity and lower NGL storage margins; offset by
•$54 million decrease for our Gathering and Processing segment, primarily related to lower volumes across our South, Midcontinent, and Permian regions due to reduced drilling activity in prior periods, the impact of Hurricane Harvey primarily in the South and Permian regions, the sale of our Douglas gathering system and unfavorable commodity derivative activity. These decreases were partially offset by higher commodity prices, increased volume from growth projects in our North region, higher NGL recoveries in our North region and contract realignment efforts in our Permian region;
These decreases were partially offset by:
$6 million increase for our Logistics and Marketing segment primarily related to favorable commodity derivative activity and higher NGL and gas marketing margins, partially offset by a decrease in natural gas storage volumes.
Nine months ended September 30, 2017 vs. Nine months ended September 30, 2016
Total Operating Revenues — Total operating revenues increased $1,215 million in 2017 compared to 2016 primarily as a result of the following:
$1,234 million increase for our Logistics and Marketing segment primarily due to increased commodity prices and favorable commodity derivative activity, partially offset by lower gas and NGL sales volumes and the sale of our Northern Louisiana System;
$775 million increase for our Gathering and Processing segment primarily due to higher commodity prices, higher gas and NGL sales volumes primarily related to our North region which impacts both sales and purchases, and higher transportation, processing and other primarily related to fee based contract realignment efforts. These increases were partially offset by lower gas and NGL sales volumes in the South, Midcontinent and Permian regions, unfavorable commodity derivative activity and the sale of our Northern Louisiana system and Douglas gathering system;
These increases were partially offset by:
$794 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.
Total Purchases — Total purchases increased $1,073 million in 2017 compared to 2016 primarily as a result of the following:
$1,221 million increase for our Logistics and Marketing segment for the reasons discussed above;
$646 million increase for our Gathering and Processing segment for the reasons discussed above;
These increases were partially offset by:
$794 million increase in inter-segment eliminations, which relate to sales of gas and NGL volumes from our Gathering and Processing segment to our Logistics and Marketing segment, primarily due to higher commodity prices, partially offset by lower gas and NGL sales volumes.
General and Administrative Expense — General and administrative expense increased in 2017 compared to 2016 primarily as a result of investment in process and technology improvements.
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.
Other (Expense) Income — Other expense in 2017 primarily represents the write-off of property, plant and equipment associated with the expiration of a lease. Other income in 2016 primarily represents a producer settlement, net of legal fees, partially offset by the write-off of property, plant and equipment.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016 primarily as a result of the expansion and volume ramp up of the Sand Hills NGL pipeline in our Logistics and Marketing segment and an increase from Discovery in our Gathering and Processing segment primarily due to the accelerated recognition of previously deferred revenue associated with lower projections. We expect these projections to impact future earnings.
Interest Expense - Interest expense decreased in 2017 compared to 2016 as a result of lower average outstanding debt balances.
Restructuring Costs - Restructuring costscommodity prices and lower margins in 2016 related to our headcount reduction in April of 2016.
Gain on Sale of Assets, net — The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on sale in 2016 represents the sale of our Northern Louisiana system,South, DJ Basin and Midcontinent regions, partially offset by a loss on sale of non-core assets.
Net Income Attributable to Partners — Net incomefavorable derivative activity attributable to partnersour corporate equity hedge program, higher volumes in the Permian, South and DJ Basin, and improved performance in the Permian region.
NGL Pipelines Throughput — NGL pipelines throughput increased in 20172023 compared to 2016 for2022 due to increased volumes on the reasons discussed above.Sand Hills pipeline.
Gross MarginNatural Gas Wellhead — Gross marginNatural gas wellhead increased $142 million in 20172023 compared to 2016 primarily as a result of2022 due to increased volumes in the following:
$129 million increase for our Gathering and Processing segment primarily related to higher commodity prices, increased volume from growth projects, higher margins on a specific producer arrangement, higher NGL recoveries and a producer settlement in our NorthPermian region, South region, and contract realignment efforts in our Permian and Midcontinent regions. These increases wereDJ Basin, partially offset by lower volumes across our South,in the Midcontinent and Permian regionsregion.
NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to reduced drilling activity in prior periods, the impact of Hurricane Harvey primarilyincreased volumes in the Permian region, DJ Basin, and South and Permian regions, the sale of our Northern Louisiana system, the sale of our Douglas gathering system and unfavorable commodity derivative activity; and
$13 million increase for our Logistics and Marketing segment primarily related to favorable commodity derivative activity and higher NGL marketing margins, partially offset by lower margins on wholesale propane.
region.
Supplemental Information on Unconsolidated Affiliates
The following table presentstables present financial information related to unconsolidated affiliates:affiliates during the three and six months ended June 30, 2023 and 2022, respectively:
Earnings from investments in unconsolidated affiliates were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 | | |
| | (millions) |
| DCP Sand Hills Pipeline, LLC | $ | 78 | | | $ | 104 | | | $ | 165 | | | $ | 175 | | | |
| DCP Southern Hills Pipeline, LLC | 27 | | | 21 | | | 52 | | | 45 | | | |
| Gulf Coast Express LLC | 18 | | | 16 | | | 35 | | | 32 | | | |
| Front Range Pipeline LLC | 11 | | | 11 | | | 22 | | | 21 | | | |
| Texas Express Pipeline LLC | 5 | | | 5 | | | 10 | | | 10 | | | |
| Mont Belvieu 1 Fractionator | 4 | | | 3 | | | 8 | | | 7 | | | |
| Discovery Producer Services LLC | 1 | | | 3 | | | 7 | | | 9 | | | |
| Cheyenne Connector, LLC | 3 | | | 3 | | | 6 | | | 7 | | | |
| Mont Belvieu Enterprise Fractionator | 1 | | | 2 | | | 2 | | | 4 | | | |
| | | | | | | | | |
| Other | — | | | — | | | 1 | | | 1 | | | |
| Total earnings from unconsolidated affiliates | $ | 148 | | | $ | 168 | | | $ | 308 | | | $ | 311 | | | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (Millions) |
| DCP Sand Hills Pipeline, LLC | $ | 37 |
| | $ | 28 |
| | $ | 105 |
| | $ | 84 |
|
| Discovery Producer Services LLC | 14 |
| | 20 |
| | 59 |
| | 52 |
|
| DCP Southern Hills Pipeline, LLC | 10 |
| | 13 |
| | 34 |
| | 37 |
|
| Front Range Pipeline LLC | 5 |
| | 5 |
| | 12 |
| | 14 |
|
| Texas Express Pipeline LLC | 4 |
| | 2 |
| | 7 |
| | 6 |
|
| Mont Belvieu Enterprise Fractionator | 3 |
| | 4 |
| | 10 |
| | 12 |
|
| Mont Belvieu 1 Fractionator | 2 |
| | 2 |
| | 6 |
| | 7 |
|
| Other | (1 | ) | | 1 |
| | 1 |
| | 2 |
|
| Total earnings from unconsolidated affiliates | $ | 74 |
| | $ | 75 |
| | $ | 234 |
| | $ | 214 |
|
Distributions received from investments in unconsolidated affiliates were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2023 | | 2022 | | 2023 | | 2022 | | |
| | (millions) |
| DCP Sand Hills Pipeline, LLC | $ | 100 | | | $ | 117 | | | $ | 182 | | | $ | 200 | | | |
| DCP Southern Hills Pipeline, LLC | 32 | | | 28 | | | 60 | | | 56 | | | |
| Gulf Coast Express LLC | 20 | | | 20 | | | 41 | | | 40 | | | |
| Front Range Pipeline LLC | 14 | | | 12 | | | 27 | | | 24 | | | |
| Texas Express Pipeline LLC | 8 | | | 6 | | | 14 | | | 12 | | | |
| Mont Belvieu 1 Fractionator | 3 | | | 2 | | | 6 | | | 6 | | | |
| Discovery Producer Services LLC | 7 | | | 7 | | | 18 | | | 15 | | | |
| Cheyenne Connector, LLC | 5 | | | 5 | | | 9 | | | 10 | | | |
| Mont Belvieu Enterprise Fractionator | 3 | | | 3 | | | 2 | | | 4 | | | |
| | | | | | | | | |
| Other | — | | | 1 | | | 1 | | | 2 | | | |
| Total distributions from unconsolidated affiliates | $ | 192 | | | $ | 201 | | | $ | 360 | | | $ | 369 | | | |
|
| | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (Millions) |
| DCP Sand Hills Pipeline, LLC | $ | 45 |
| | $ | 39 |
| | $ | 118 |
| | $ | 107 |
|
| Discovery Producer Services LLC | 19 |
| | 24 |
| | 68 |
| | 69 |
|
| DCP Southern Hills Pipeline, LLC | 16 |
| | 15 |
| | 47 |
| | 45 |
|
| Front Range Pipeline LLC | 5 |
| | 8 |
| | 12 |
| | 18 |
|
| Texas Express Pipeline LLC | 5 |
| | 4 |
| | 10 |
| | 9 |
|
| Mont Belvieu Enterprise Fractionator | 2 |
| | 4 |
| | 8 |
| | 15 |
|
| Mont Belvieu 1 Fractionator | — |
| | 2 |
| | 4 |
| | 8 |
|
| Other | 1 |
| | 2 |
| | 3 |
| | 3 |
|
| Total distributions from unconsolidated affiliates | $ | 93 |
| | $ | 98 |
| | $ | 270 |
| | $ | 274 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating Data |
| | | | | | | | | | | | | | | | Three Months Ended June 30, 2023 | | Six Months Ended June 30, 2023 |
| 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) | | | | Pipeline Throughput
(MBbls/d) (a) | | Pipeline Throughput
(TBtus/d) (a) | | |
| Sand Hills pipeline | | | | 1,400 | | | — | | | 333 | | | — | | | | | | | | | 295 | | | — | | | | | 304 | | | — | | | |
| Southern Hills pipeline | | | | 950 | | | — | | | 128 | | | — | | | | | | | | | 126 | | | — | | | | | 121 | | | — | | | |
| Front Range pipeline | | | | 450 | | | — | | | 87 | | | — | | | | | | | | | 73 | | | — | | | | | 75 | | | — | | | |
| Texas Express pipeline | | | | 600 | | | — | | | 37 | | | — | | | | | | | | | 22 | | | — | | | | | 22 | | | — | | | |
| Other NGL pipelines (a) | | | | 1,050 | | | — | | | 310 | | | — | | | | | | | | | 186 | | | — | | | | | 191 | | | — | | | |
| Gulf Coast Express pipeline | | | | 500 | | | — | | | — | | | 0.50 | | | | | | | | | — | | | 0.51 | | | | | — | | | 0.50 | | | |
| Guadalupe pipeline | | | | 600 | | | — | | | — | | | 0.25 | | | | | | | | | — | | | 0.26 | | | | | — | | | 0.27 | | | |
| Cheyenne Connector | | | | 70 | | | — | | | — | | | 0.30 | | | | | | | | | — | | | 0.30 | | | | | — | | | 0.31 | | | |
| Mont Belvieu fractionators | | | | — | | | 2 | | | — | | | — | | | | | | | | | — | | | — | | | | | — | | | — | | | |
| Pipelines total | | | | 5,620 | | | 2 | | | 895 | | | 1.05 | | | | | | | | | 702 | | | 1.07 | | | | | 713 | | | 1.08 | | | |
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.The results of operations for our Logistics and Marketing segment are as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, | | Variance Three Months 2023 vs. 2022 | | Variance Six Months
2023 vs. 2022 | | |
| | 2023 | | 2022 | | 2023 | | 2022 | | | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent | | | | |
| | (millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | $ | 1,524 | | | $ | 3,769 | | | $ | 3,854 | | | $ | 6,954 | | | | | $ | (2,245) | | | (60 | %) | | $ | (3,100) | | | (45 | %) | | | | |
| Transportation, processing and other | 18 | | | 18 | | | 37 | | | 37 | | | | | — | | | — | % | | — | | | — | % | | | | |
| Trading and marketing gains (losses), net | 19 | | | 2 | | | 62 | | | (39) | | | | | 17 | | | * | | 101 | | | * | | | | |
| Total operating revenues | 1,561 | | | 3,789 | | | 3,953 | | | 6,952 | | | | | (2,228) | | | (59 | %) | | (2,999) | | | (43 | %) | | | | |
| Purchases and related costs | (1,503) | | | (3,749) | | | (3,841) | | | (6,896) | | | | | (2,246) | | | (60 | %) | | (3,055) | | | (44 | %) | | | | |
| Operating and maintenance expense | (8) | | | (9) | | | (17) | | | (17) | | | | | (1) | | | (11 | %) | | — | | | — | % | | | | |
| Depreciation and amortization expense | (4) | | | (3) | | | (6) | | | (6) | | | | | 1 | | | 33 | % | | — | | | — | % | | | | |
| General and administrative expense | (1) | | | (2) | | | (3) | | | (3) | | | | | (1) | | | (50 | %) | | — | | | — | % | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Other income, net | — | | | 10 | | | — | | | 10 | | | | | (10) | | | * | | (10) | | | * | | | | |
| Earnings from unconsolidated affiliates (a) | 147 | | | 165 | | | 301 | | | 302 | | | | | (18) | | | (11 | %) | | (1) | | | — | % | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Segment net income attributable to partners | $ | 192 | | | $ | 201 | | | $ | 387 | | | $ | 342 | | | | | $ | (9) | | | (4 | %) | | $ | 45 | | | 13 | % | | | | |
| Other data: | | | | | | | | | | | | | | | | | | | | | |
| Segment adjusted gross margin (b) | $ | 58 | | | $ | 40 | | | $ | 112 | | | $ | 56 | | | | | $ | 18 | | | 45 | % | | $ | 56 | | | * | | | | |
| Non-cash commodity derivative mark-to-market | $ | 17 | | | $ | 26 | | | $ | 12 | | | $ | (19) | | | | | $ | (9) | | | (35 | %) | | $ | 31 | | | * | | | | |
| NGL pipelines throughput (MBbls/d) (c) | 702 | | | 720 | | | 713 | | | 701 | | | | | (18) | | | (3 | %) | | 12 | | | 2 | % | | | | |
| Gas pipelines throughput (TBtu/d) (c) | 1.07 | | | 1.09 | | | 1.08 | | | 1.09 | | | | | (0.02) | | | (2 | %) | | (0.01) | | | (1 | %) | | | | |
* 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.
Three Months Ended June 30, 2023 vs. Three Months Ended June 30, 2022
Total Operating Revenues — Total operating revenues decreased $2,228 million in 2023 compared to 2022, primarily as a result of the following:
•$2,278 million decrease as a result of lower commodity prices before the impact of derivative activity.
This decrease was partially offset by:
•$33 million increase attributable to higher gas and NGL volumes; and
•$17 million increase as a result of commodity derivative activity attributable to a increase in realized cash settlement gains of $26 million, partially offset by an decrease in unrealized commodity derivative gains of $9 million due to movements in forward prices of commodities.
Purchases and Related Costs — Purchases and related costs decreased $2,246 million in 2023 compared to 2022, for the reasons discussed above.
Other Income — Other income in 2022 was primarily a result of contractual settlements.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2023 compared to 2022 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 in 2022.
Segment Adjusted Gross Margin — Segment adjusted gross margin increased $18 million in 2023 compared to 2022, primarily as a result of the following:
•$17 million increase as a result of commodity derivative activity discussed above;
•$16 million contract settlement in 2022; and
•$3 million increase as a result of NGL pipeline margins.
These increases were partially offset by:
•$11 million decrease as a result of unfavorable NGL marketing activity; and
•$7 million decrease as a result of lower gas storage margins.
NGL Pipelines Throughput — NGL pipelines throughput decreased in 2023 compared to 2022 due to decreased volumes on the Sand Hills and Front Range pipelines, partially offset by increased throughput on Southern Hills pipeline.
Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022
Total Operating Revenues — Total operating revenues decreased $2,999 million in 2023 compared to 2022, primarily as a result of the following:
•$3,318 million decrease as a result of lower commodity prices before the impact of derivative activity.
This decrease was partially offset by:
•$218 million increase attributable to higher gas and NGL volumes; and
•$101 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $70 million and an increase in unrealized commodity derivative gains of $31 million due to movements in forward prices of commodities.
Purchases and Related Costs — Purchases and related costs decreased $3,055 million in 2023 compared to 2022, for the reasons discussed above.
Other Income, Net — Other income in 2022 was primarily a result of contractual settlements.
Segment Adjusted Gross Margin — Segment adjusted gross margin increased $56 million in 2023 compared to 2022, primarily as a result of the following:
•$101 million increase as a result of commodity derivative activity as discussed above;
•$16 million contract settlement in 2022; and
•$5 million increase as a result of NGL pipeline margins.
These increases were partially offset by:
•$39 million decrease as a result of lower gas storage and pipeline margins;
•$23 million decrease as a result of unfavorable NGL marketing activity; and
•$4 million decrease as a result of lower NGL storage margins.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2023 compared to 2022 due to increased volumes on the Sand Hills pipeline.
Results of Operations — Gathering and Processing Segment
| | | Operating Data | Operating Data | Operating Data |
| | | | Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 | | | Three Months Ended June 30, 2023 | | Six Months Ended June 30, 2023 |
| 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) | | Natural Gas
Wellhead Volume
(MMcf/d) (a) | | NGL
Production
(MBbls/d) (a) | 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) | | Natural Gas
Wellhead Volume
(MMcf/d) (a) | | NGL
Production
(MBbls/d) (a) |
| North | | 13 |
| | 4,000 |
| | 1,260 |
| | 1,134 |
| | 87 |
| | 1,116 |
| | 86 |
| North | | 13 | | | 3,500 | | | 1,580 | | | 1,589 | | | 157 | | | 1,582 | | | 157 | |
| Midcontinent | | Midcontinent | | 6 | | | 23,000 | | | 1,110 | | | 812 | | 77 | | 808 | | | 70 | |
| Permian | | 16 |
| | 16,500 |
| | 1,460 |
| | 927 |
| | 101 |
| | 951 |
| | 102 |
| Permian | | 10 | | | 15,000 | | | 1,220 | | | 1,104 | | | 134 | | 1,097 | | | 134 | |
| Midcontinent | | 12 |
| | 29,000 |
| | 1,765 |
| | 1,206 |
| | 95 |
| | 1,199 |
| | 90 |
| |
| South | | 20 |
| | 7,500 |
| | 3,295 |
| | 1,193 |
| | 93 |
| | 1,242 |
| | 87 |
| South | | 7 | | | 6,500 | | | 1,630 | | | 976 | | | 78 | | 990 | | | 72 | |
| Total | | 61 |
| | 57,000 |
| | 7,780 |
| | 4,460 |
| | 376 |
| | 4,508 |
| | 365 |
| Total | | 36 | | | 48,000 | | | 5,540 | | | 4,481 | | | 446 | | | 4,477 | | | 433 | |
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.
The results of operations for our Gathering and Processing segment are as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Variance Three Months 2017 vs. 2016 | | Variance Nine Months
2017 vs. 2016 |
| | | 2017 | | 2016 | | 2017 | | 2016 | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | | $ | 1,249 |
| | $ | 1,066 |
| | $ | 3,562 |
| | $ | 2,781 |
| | $ | 183 |
| | 17 | % | | $ | 781 |
| | 28 | % |
| Transportation, processing and other | | 145 |
| | 146 |
| | 424 |
| | 418 |
| | (1 | ) | | (1 | )% | | 6 |
| | 1 | % |
| Trading and marketing (losses) gains, net | | (57 | ) | | 5 |
| | (21 | ) | | (9 | ) | | (62 | ) | | * |
| | (12 | ) | | * |
|
| Total operating revenues | | 1,337 |
| | 1,217 |
| | 3,965 |
| | 3,190 |
| | 120 |
| | 10 | % | | 775 |
| | 24 | % |
| Purchases of natural gas and NGLs | | (1,034 | ) | | (882 | ) | | (2,944 | ) | | (2,298 | ) | | 152 |
| | 17 | % | | 646 |
| | 28 | % |
| Operating and maintenance expense | | (154 | ) | | (146 | ) | | (469 | ) | | (458 | ) | | 8 |
| | 5 | % | | 11 |
| | 2 | % |
| General and administrative expense | | (2 | ) | | (2 | ) | | (15 | ) | | (10 | ) | | — |
| | — | % | | 5 |
| | 50 | % |
| Depreciation and amortization expense | | (85 | ) | | (85 | ) | | (256 | ) | | (258 | ) | | — |
| | — | % | | (2 | ) | | (1 | )% |
| Asset impairments | | (48 | ) | | — |
| | (48 | ) | | — |
| | (48 | ) | | * |
| | (48 | ) | | * |
|
| Other (expense) income, net | | — |
| | (13 | ) | | (3 | ) | | 74 |
| | 13 |
| | * |
| | (77 | ) | | * |
|
| Earnings from unconsolidated affiliates (a) | | 15 |
| | 20 |
| | 59 |
| | 52 |
| | (5 | ) | | (25 | )% | | 7 |
| | 13 | % |
| Gain on sale of assets, net | | — |
| | 25 |
| | 34 |
| | 19 |
| | (25 | ) | | * |
| | 15 |
| | * |
|
| Segment net income | | 29 |
| | 134 |
| | 323 |
| | 311 |
| | (105 | ) | | * |
| | 12 |
| | 4 | % |
| Segment net income attributable to noncontrolling interests | | — |
| | — |
| | (1 | ) | | (1 | ) | | — |
| | * |
| | — |
| | — | % |
| Segment net income attributable to partners | | $ | 29 |
| | $ | 134 |
| | $ | 322 |
| | $ | 310 |
| | $ | (105 | ) | | * |
| | $ | 12 |
| | 4 | % |
| Other data: | | | | | | | | | |
| |
|
| |
|
| |
|
|
| Segment gross margin (b) | | $ | 303 |
| | $ | 335 |
| | $ | 1,021 |
| | $ | 892 |
| | $ | (32 | ) | | (10 | )% | | $ | 129 |
| | 14 | % |
| Non-cash commodity derivative mark-to-market | | $ | (51 | ) | | $ | (5 | ) | | $ | (4 | ) | | $ | (73 | ) | | $ | (46 | ) | | * |
| | $ | 69 |
| | * |
|
| Natural gas wellhead (MMcf/d) (c) | | 4,460 |
| | 5,005 |
| | 4,508 |
| | 5,230 |
| | (545 | ) | | (11 | )% | | (722 | ) | | (14 | )% |
| NGL gross production (MBbls/d) (c) | | 376 |
| | 392 |
| | 365 |
| | 401 |
| | (16 | ) | | (4 | )% | | (36 | ) | | (9 | )% |
_____________ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | Six Months Ended June 30, | | Variance Three Months 2023 vs. 2022 | | Variance Six Months
2023 vs. 2022 | | |
| | | 2023 | | 2022 | | 2023 | | 2022 | | | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent | | | | |
| | (millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | | | | | | | | | |
| Sales of natural gas, NGLs and condensate | | $ | 1,121 | | | $ | 2,817 | | | $ | 2,699 | | | $ | 4,981 | | | | | $ | (1,696) | | | (60 | %) | | $ | (2,282) | | | (46 | %) | | | | |
| Transportation, processing and other | | 130 | | | 166 | | | 274 | | | 302 | | | | | (36) | | | (22 | %) | | (28) | | | (9 | %) | | | | |
| Trading and marketing gains (losses), net | | 1 | | | (16) | | | 45 | | | (210) | | | | | 17 | | | * | | 255 | | | * | | | | |
| Total operating revenues | | 1,252 | | | 2,967 | | | 3,018 | | | 5,073 | | | | | (1,715) | | | (58 | %) | | (2,055) | | | (41 | %) | | | | |
| Purchases and related costs | | (881) | | | (2,382) | | | (2,203) | | | (4,204) | | | | | (1,501) | | | (63 | %) | | (2,001) | | | (48 | %) | | | | |
| Operating and maintenance expense | | (216) | | | (175) | | | (398) | | | (315) | | | | | 41 | | | 23 | % | | 83 | | | 26 | % | | | | |
| Depreciation and amortization expense | | (84) | | | (82) | | | (168) | | | (163) | | | | | 2 | | | 2 | % | | 5 | | | 3 | % | | | | |
| General and administrative expense | | (4) | | | (5) | | | (8) | | | (9) | | | | | (1) | | | (20) | % | | (1) | | | (11 | %) | | | | |
| Asset impairments | | — | | | (1) | | | — | | | (1) | | | | | (1) | | | * | | (1) | | | * | | | | |
| Other expense, net | | — | | | (2) | | | — | | | (2) | | | | | (2) | | | * | | (2) | | | * | | | | |
| (Loss) gain on sale of assets, net | | (3) | | | — | | | (3) | | | 7 | | | | | (3) | | | * | | (10) | | | * | | | | |
| Earnings from unconsolidated affiliates (a) | | 1 | | | 3 | | | 7 | | | 9 | | | | | (2) | | | * | | (2) | | | (22 | %) | | | | |
| Segment net income | | 65 | | | 323 | | | 245 | | | 395 | | | | | (258) | | | (80 | %) | | (150) | | | (38 | %) | | | | |
| Segment net income attributable to noncontrolling interests | | (1) | | | (1) | | | (2) | | | (2) | | | | | — | | | — | % | | — | | | — | % | | | | |
| Segment net income attributable to partners | | $ | 64 | | | $ | 322 | | | $ | 243 | | | $ | 393 | | | | | $ | (258) | | | (80 | %) | | $ | (150) | | | (38 | %) | | | | |
| Other data: | | | | | | | | | | | | | | | | | | | | | | |
| Segment adjusted gross margin (b) | | $ | 371 | | | $ | 585 | | | $ | 815 | | | $ | 869 | | | | | $ | (214) | | | (37 | %) | | $ | (54) | | | (6 | %) | | | | |
| Non-cash commodity derivative mark-to-market | | $ | (10) | | | $ | 75 | | | $ | 35 | | | $ | (56) | | | | | $ | (85) | | | * | | $ | 91 | | | * | | | | |
| Natural gas wellhead (MMcf/d) (c) | | 4,481 | | | 4,383 | | | 4,477 | | | 4,246 | | | | | 98 | | | 2 | % | | 231 | | | 5 | % | | | | |
| NGL gross production (MBbls/d) (c) | | 446 | | | 427 | | | 433 | | | 414 | | | | | 19 | | | 4 | % | | 19 | | | 5 | % | | | | |
* 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.
| |
(a) | Earnings from unconsolidated affiliates includes our 40% ownership of Discovery. Earnings for Discovery include the amortization of the net difference between the carrying amount of our investment and the underlying equity of the entity. |
| |
(b) | Segment gross margin consists of total operating revenues, less purchases of natural gas and NGLs.(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 throughput volumes and NGL production. |
(c) For entities not wholly owned by us, includes our share, based on our ownership percentage, of the wellhead and NGL production
Three months ended SeptemberMonths Ended June 30, 20172023 vs. Three months ended SeptemberMonths Ended June 30, 20162022
Total Operating Revenues — Total operating revenues increased $120decreased $1,715 million in 20172023 compared to 2016,2022, primarily as a result of the following:
$251• $1,882 million increasedecrease attributable to higherlower commodity prices, which impacted both sales and purchases, before the impact of derivative activity; and
•$36 million increase attributable to higher gas and NGL sales volumes primarily related to our DJ Basin system in our North region;
These increases were partially offset by:
$104 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods;
$62 million decrease as a result of commodity derivative activity attributable to an increase in unrealized commodity derivative losses of $46 million due to movements in forward prices of commodities, and a $16 million increase in realized cash settlement losses in 2017; and
$1 million decrease in transportation, processing and other primarily related to the sale of our Douglas gathering system, partially offset by fee based contract realignment efforts in our Permian region.
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased $152 million in 2017 compared to 2016 as a result of higher commodity prices and higher gas and NGL sales volumes in our North region, partially offset by decreased volumes in our South, Midcontinent and Permian regions.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2017 compared to 2016 primarily as a result of increased reliability spending and gathering pipeline remediation spending partially offset by cost savings initiatives and the sale of our Douglas gathering system in June 2017.
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.
Other (Expense) Income — Other expense in 2016 represents the write-off of property, plant and equipment.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates decreased in 2017 compared to 2016 primarily due to lower volumes at Discovery.
Gain on Sale of Assets, net — The gain on sale in 2016 primarily represents the sale of our Northern Louisiana system in our South Region.
Segment Gross Margin — Segment gross margin decreased $32 million in 2017 compared to 2016, primarily as a result of the following:
$62 million decrease as a result of commodity derivative activity as discussed above;
$22 million decrease primarily as a result of lower volumes across our South, Permian and Midcontinent regions due to reduced drilling activity in prior periods and the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by fee based contract realignment efforts in the Permian region;other.
These decreases werewas partially offset by:
$46• $186 million increase as a result of higher commodity prices; and
$6 million increase as a result of increased volume from growth projects and higher NGL recoveries primarily related to our DJ Basin system in our North region, partially offset by the sale of our Douglas gathering system.
Total Wellhead — Natural gas wellhead decreased in 2017 compared to 2016 reflecting lower volumes primarily from (i) lower volumes associated with general declines within the South, Permian and Midcontinent regions, (ii) the sale of our Douglas gathering system within our North region, and (iii) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by general volume increases due to maximizing capacity utilization and growth projects within the North region.
NGL Gross Production — NGL production decreased in 2017 compared to 2016 primarily as a result of (i) lower volumes associated with general declines within the South, Permian and Midcontinent regions, (ii) the sale of our Douglas gathering system within our North region and (iii) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by general volume increases due to maximizing capacity utilization within the North region.
Nine Months Ended September 30, 2017 vs. Nine Months Ended September 30, 2016
Total Operating Revenues — Total operating revenues increased $775 million in 2017 compared to 2016, primarily as a result of the following:
$1,076 million increase attributable to higher commodity prices, which impacted both sales and purchases, before the impact of derivative activity;
$70 million increase attributable to higher gas and NGL sales volumes and the impact of a specific producer arrangement primarily related to our DJ Basin system in our North region;
$6 million increase in transportation, processing and other primarily related to fee based contract realignment efforts, partially offset by lower volumes in the South region and the sale of our Northern Louisiana system and Douglas gathering system;
These increases were partially offset by:
$365 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods and the impact of Hurricane Harvey primarily related to the South and Permianall regions; and
•$12 million decrease as a result of commodity derivative activity attributable to a $81 million increase in realized cash settlement losses, partially offset by a decrease in unrealized commodity derivative losses of $69 million due to movements in forward prices of commodities in 2017.
Purchases of Natural Gas and NGLs — Purchases of natural gas and NGLs increased $646 million in 2017 compared to 2016 as a result of higher commodity prices and higher gas and NGL sales volumes in our North region, partially offset by decreased volumes in our South, Midcontinent and Permian regions.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2017 compared to 2016 primarily as a result of increased reliability spending and planned maintenance spending associated with anticipated volume growth partially offset by cost savings initiatives and the sale of our Northern Louisiana system in July 2016 and Douglas gathering system in June 2017.
General and Administrative Expense — General and administrative expense increased in 2017 compared to 2016 primarily as a result of investment in process improvements.
Asset impairments — Asset impairments in 2017 represent the impairment of property, plant and equipment and intangible assets in our South region.
Other (Expense) Income — Other expense in 2017 represents the write-off of property, plant and equipment. Other income in 2016 represents a producer settlement, net of legal fees partially offset by the write-off of property, plant and equipment.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016 primarily due to the accelerated recognition of previously deferred revenue associated with lower projections at Discovery. We expect these projections to impact future earnings.
Gain on sale of assets, net - The gain on sale in 2017 represents the sale of our Douglas gathering system. The gain on sale in 2016 represents the sale of our Northern Louisiana system partially offset by a loss on sale of non-core assets.
Segment Gross Margin — Segment gross margin increased $129 million in 2017 compared to 2016, primarily as a result of the following:
$194 million increase as a result of higher commodity prices;
$31 million increase as a result of increased volume from growth projects, higher margins on a specific producer arrangement, and higher NGL recoveries primarily related to our DJ Basin system and a producer settlement in our North region;
These increases were partially offset by:
$71 million decrease primarily as a result of lower volumes across our South, Midcontinent and Permian regions due to reduced drilling activity in prior periods, partially offset by fee based contract realignment efforts in the Permian and Midcontinent region;
$13 million decrease as a result of the sale of our Northern Louisiana system in our South region and Douglas gathering system in our North region; and
$12 million decrease as a result of commodity derivative activity as discussed above.
Total Wellhead — Natural gas wellhead decreased in 2017 compared to 2016 reflecting lower volumes primarily from (i) lower volumes associated with general declines within the South, Permian and Midcontinent regions (ii) the sale of our Northern Louisiana system within our South region and (iii) the sale of our Douglas gathering system within our North region and (iv) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by (v) general volume increases due to maximizing capacity utilization and growth projects within the North region.
NGL Gross Production — NGL production decreased in 2017 compared to 2016 primarily as a result of (i) lower volumes associated with general declines within the South, Permian and Midcontinent regions, (ii) the sale of our Northern Louisiana system within our South region and (iii) the sale of our Douglas gathering system within our North region and (iv) the impact of Hurricane Harvey primarily related to the South and Permian regions, partially offset by (v) general volume increases due to maximizing capacity utilization within the North region.
Results of Operations — Logistics and Marketing Segment
|
| | | | | | | | | | | | | | | | | | | | | |
| NGL Pipeline and Fractionator Operating Data |
| | | | | | | | | Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
| System | | Approximate
System Length (Miles) | | Fractionators | | Approximate
Throughput Capacity
(MBbls/d) (a) | | Pipeline Throughput
(MBbls/d) (a) | | Fractionator Throughput
(MBbls/d) (a) | | Pipeline Throughput
(MBbls/d) (a) | | Fractionator Throughput
(MBbls/d) (a) |
| Sand Hills pipeline | | 1,300 |
| | — |
| | 190 |
| | 193 |
| | — |
| | 181 |
| | — |
|
| Southern Hills pipeline | | 950 |
| | — |
| | 117 |
| | 65 |
| | — |
| | 67 |
| | — |
|
| Front Range pipeline | | 450 |
| | — |
| | 50 |
| | 36 |
| | — |
| | 36 |
| | — |
|
| Texas Express pipeline | | 600 |
| | — |
| | 28 |
| | 16 |
| | — |
| | 15 |
| | — |
|
| Other NGL Pipelines (b) | | 1,200 |
| | — |
| | 172 |
| | 152 |
| | — |
| | 148 |
| | — |
|
| Mont Belvieu fractionators | | — |
| | 2 |
| | 60 |
| | — |
| | 49 |
| | — |
| | 48 |
|
| Total | | 4,500 |
| | 2 |
| | 617 |
| | 462 |
| | 49 |
| | 447 |
| | 48 |
|
(a) Represents total capacity or total volumes allocated to our proportionate ownership share.
(b) Excludes other natural gas pipelines within our Logistics and Marketing segment.
The results of operations for our Logistics and Marketing segment are as follows: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Variance Three Months 2017 vs. 2016 | | Variance Nine Months 2017 vs. 2016 |
| | | 2017 | | 2016 | | 2017 | | 2016 | | Increase
(Decrease) | | Percent | | Increase
(Decrease) | | Percent |
| | (Millions, except operating data) |
| Operating revenues: | | | | | | | | | | | | | | | | |
| Sales of natural gas and NGLs | | $ | 1,882 |
| | $ | 1,614 |
| | $ | 5,515 |
| | $ | 4,290 |
| | $ | 268 |
| | 17 | % | | $ | 1,225 |
| | 29 | % |
| Transportation, processing and other | | 17 |
| | 17 |
| | 50 |
| | 53 |
| | — |
| | — | % | | (3 | ) | | (6 | )% |
Trading and marketing gains, net
| | 14 |
| | 10 |
| | 31 |
| | 19 |
| | 4 |
| | 40 | % | | 12 |
| | 63 | % |
| Total operating revenues | | 1,913 |
| | 1,641 |
|
| 5,596 |
| | 4,362 |
| | 272 |
| | 17 | % | | 1,234 |
| | 28 | % |
| Purchases of natural gas and NGLs | | (1,856 | ) | | (1,590 | ) | | (5,431 | ) | | (4,210 | ) | | 266 |
| | 17 | % | | 1,221 |
| | 29 | % |
| Operating and maintenance expense | | (9 | ) | | (13 | ) | | (31 | ) | | (33 | ) | | (4 | ) | | (31 | )% | | (2 | ) | | (6 | )% |
| General and administrative expense | | (3 | ) | | (2 | ) | | (8 | ) | | (7 | ) | | 1 |
| | (50 | )% | | 1 |
| | 14 | % |
| Depreciation and amortization expense | | (4 | ) | | (4 | ) | | (11 | ) | | (12 | ) | | — |
| | — | % | | (1 | ) | | (8 | )% |
| Other expense | | (1 | ) | | — |
| | (12 | ) | | (5 | ) | | 1 |
| | * |
| | 7 |
| | * |
|
| Earnings from unconsolidated affiliates (a) | | 59 |
| | 55 |
| | 175 |
| | 162 |
| | 4 |
| | 7 | % | | 13 |
| | 8 | % |
| Gain on sale of assets, net | | — |
| | 16 |
| | — |
| | 16 |
| | (16 | ) | | * |
| | (16 | ) | | * |
|
| Segment net income attributable to partners | | $ | 99 |
| | $ | 103 |
| | $ | 278 |
| | $ | 273 |
| | $ | (4 | ) | | (4 | )% | | $ | 5 |
| | 2 | % |
| Other data: | | | | | | | | | |
| |
| |
| |
|
| Segment gross margin (b) | | $ | 57 |
| | $ | 51 |
| | $ | 165 |
| | $ | 152 |
| | $ | 6 |
| | 12 | % | | $ | 13 |
| | 9 | % |
| Non-cash commodity derivative mark-to-market | | $ | (8 | ) | | $ | 14 |
| | $ | 5 |
| | $ | (7 | ) | | (22 | ) | | * |
| | 12 |
| | * |
|
| NGL pipelines throughput (MBbls/d) (c) | | 462 |
| | 434 |
| | 447 |
| | 421 |
| | 28 |
| | 6 | % | | 26 |
| | 6 | % |
| |
(a) | Earnings from unconsolidated affiliates for Sand Hills, Southern Hills, Front Range, Mont Belvieu 1 and Texas Express include the amortization of the net difference between the carrying amount of our investments and the underlying equity of the entities. |
| |
(b) | Segment gross margin consists of total operating revenues less purchases of natural gas and NGLs. 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 throughput volumes and NGL production. |
Three months ended September 30, 2017 vs. Three months ended September 30, 2016
Total Operating Revenues — Total operating revenues increased $272 million in 2017 compared to 2016, primarily as a result of the following:
$387 million increase as a result of higher commodity prices, which impacted both sales and purchases, before the impact of derivative activity;
$4 million increase as a result of commodity derivative activity attributable to a $26 million increase in realized cash settlement gains in 2017, partially offset by an increase in unrealized commodity derivative losses of $22 million due to movements in forward prices of commodities;
These increases were partially offset by:
$119 million decrease attributable to lower gas and NGL sales volumes, which impacted both sales and purchases.
Purchases of NGLs — Purchases of NGLs increased $266 million in 2017 compared to 2016, primarily as a result of higher commodity prices, partially offset by lower gas and NGL sales volumes.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 2016 primarily as a result of timing of planned maintenance spending.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 2017 compared to 2016 primarily as a result of higher throughput volumes on Sand Hills due to the capacity expansion in 2017, partially offset by the impact of Hurricane Harvey primarily related to the Sand Hills and Southern Hills pipelines and the Mont Belvieu fractionators.
Gain on sale of assets, net — The gain on sale in 2016 primarily represents the sale of our Northern Louisiana system.
Segment Gross Margin — Segment gross margin increased $6 million in 2017 compared to 2016 primarily as a result of the following:
$4 million increase as a result of commodity derivative activity as discussed above;
$7 million increase as a result of higher NGL and gas marketing margins;
These increases are partially offset by:
$5 million decrease in natural gas storage volumes.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2017 compared to 2016 primarily as a result of higher throughput volumes on Sand Hills due to the capacity expansion in 2017, partially offset by the impact of Hurricane Harvey primarily related to the Sand Hills and Southern Hills pipelines.
Nine Months Ended September 30, 2017 vs. Nine Months Ended September 30, 2016
Total Operating Revenues — Total operating revenues increased $1,234 million in 2017 compared to 2016, primarily as a result of the following:
$1,565 million increase as a result of higher commodity prices, which impacted both sales and purchases, before the impact of derivative activity;
$1217 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $102 million, partially offset by an $85 million increase in unrealized commodity derivative losses due to movements in forward prices of commodities in 2023.
Purchases and Related Costs — Purchases and related costs decreased $1,501 million in 2023 compared to 2022, primarily as a result of the commodity price and volume changes discussed above.
Operating and Maintenance Expense — Operating and maintenance expense increased in 2023 compared to 2022 largely due to a legal settlement, higher base costs primarily in the Permian region and higher pipeline integrity spend.
Segment Adjusted Gross Margin — Segment adjusted gross margin decreased $214 million in 2023 compared to 2022, primarily as a result of the following:
•$227 million decrease as a result of lower commodity prices; and
•$4 million decrease due to lower margins in the South region, partially offset by higher volumes in the Permian region.
These decreases were partially offset by:
•$17 million increase as a result of favorable commodity derivative activity discussed above.
Natural Gas Wellhead — Natural gas wellhead increased in 2023 compared to 2022 due to increased volumes in the Permian region and DJ Basin, partially offset by lower volumes in the Midcontinent region.
NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian, South, and Midcontinent regions.
Six Months Ended June 30, 2023 vs. Six Months Ended June 30, 2022
Total Operating Revenues — Total operating revenues decreased $2,055 million in 2023 compared to 2022, primarily as a result of the following:
•$2,621 million decrease attributable to lower commodity prices, before the impact of derivative activity; and
•$28 million decrease in transportation, processing and other.
These decreases were partially offset by:
•$339 million increase as a result of higher volumes in all regions; and
•$255 million increase as a result of commodity derivative activity attributable to an increase in realized cash settlement gains of $12$164 million due to movements in forward prices of commodities in 2017;2023 and a $91 million increase in unrealized commodity derivative gains.
These increases were partially offset by:
$307 million decrease attributable to lower gasPurchases and NGL sales volumes, which impacted both sales and purchases, and;
$36 million decrease due to the sale of our Northern Louisiana system.
Purchases of NGLsRelated Costs — Purchases of NGLs increased $1,221and related costs decreased $2,001 million in 20172023 compared to 2016, primarily as a result of higher commodity prices, partially offset by lower gas and NGL sales volumes.
Operating and Maintenance Expense — Operating and maintenance expense decreased in 2017 compared to 20162022, primarily as a result of the timing of plannedcommodity price and volume changes discussed above.
Operating and Maintenance Expense — Operating and maintenance spending.
Other expense— Other expense in 2017 primarily represents the write-off of property, plant and equipment associated with the expiration of a lease while other expense in 2016 primarily represents the write-off of property, plant and equipment and other long term assets.
Earnings from Unconsolidated Affiliates — Earnings from unconsolidated affiliates increased in 20172023 compared to 2016 primarily as a result of higher throughput volumes on Sand Hills2022 largely due to the capacity expansionhigher base costs primarily in the second quarterPermian region, a legal settlement, and higher pipeline integrity spend.
(Loss) gain on Sale of 2016, partially offset by the impact of Hurricane Harvey primarily related to the Sand Hills and Southern Hills pipelines and the Mont Belvieu fractionators.
GainAssets, net — The net loss on sale of assets net — The gain on sale in 2016 primarily2023 represents the sale of our Northern Louisiana system.certain non-core assets in the Midcontinent region. The net gain on sale of assets in 2022 represents the sale of a gathering system in the Permian region.
Segment Adjusted Gross Margin — Segment adjusted gross margin increased $13decreased $54 million in 20172023 compared to 2016,2022, primarily as a result of the following:
•$12310 million decrease as a result of lower commodity prices.
These decreases were partially offset by:
•$255 million increase as a result of favorable commodity derivative activity as discussed above; and
•$91 million increase as a result of higher NGL marketing margins;
These increases are partially offset by:
$8 million of lower margins on wholesale propane.
NGL Pipelines Throughput — NGL pipelines throughput increased in 2017 compared to 2016 primarily as a result of higher throughput volumes on Sand Hills due to the capacity expansionhigher volumes in the second quarter of 2016,Permian region, South region and DJ Basin, and improved performance in the Permian region, partially offset by lower margins in the impact of Hurricane Harvey primarily relatedSouth region, DJ Basin, and Midcontinent region.
Natural Gas Wellhead — Natural gas wellhead increased in 2023 compared to 2022 due to increased volumes in the Sand HillsPermian region, South region, and Southern Hills pipelines.DJ Basin, partially offset by lower volumes in the Midcontinent region.
NGL Gross Production — NGL gross production increased in 2023 compared to 2022 due to increased volumes in the Permian region, DJ Basin, and South 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;Agreement, Intercompany Credit Agreement, and Securitization Facility;
•proceeds from asset rationalization;rationalizations;
reduction of incentive distribution right payments;
•debt offerings; and
issuances of additional common units or other securities;
•borrowings under term loans; and
letters of credit.loans, or other credit facilities.
We anticipate our more significant uses of resources to include:
•quarterly distributions to our common unitholders and General Partner;distributions to our preferred unitholders;
•payments to service or retire our debt;debt or Preferred Units;
growth •capital expenditures; and
•contributions to our unconsolidated affiliates to finance our share of their capital expenditures;
business and asset acquisitions; and
collateral with counterparties to our swap contracts to secure potential exposure under these contracts, which may, at times, be significant depending on commodity price movements.expenditures.
We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure and acquisition requirementsexpenditures and quarterly cash distributions for the next twelve months.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 andor debt instruments as vehicles for the long-term financing of our investment activities andor acquisitions.
Based on current and anticipated levels of operations, we believe we have adequate committed financial resources to conduct our ongoing business, although deterioration in our operating environment could limit our borrowing capacity, further impact our credit ratings, raise our financing costs, as well as impact our compliance with ourthe financial covenant requirements undercovenants contained in the Credit Agreement, Intercompany Credit Agreement, and other debt instruments.
Junior Notes Redemption— On May 19, 2023, we redeemed, at par, prior to maturity all $550 million of aggregate principal amount outstanding of our 5.850% Junior Notes due May 2043, using borrowings under our Credit Facility and Securitization Facility.
Series B Preferred Units Redemption —On June 15, 2023 we paid $161 million to redeem in full the outstanding Series B Preferred Units at a redemption price of $25 per unit using cash on hand and borrowings under our Securitization Facility. The difference between the redemption price of the Series B Preferred Units and the indentures governingcarrying value on the balance sheet resulted in an approximately $5 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 B Preferred Units.
Intercompany Credit Agreement — On June 15, 2023, we and our notes.
In February 2017, we further amended ourwholly owned subsidiary, DCP Midstream Operating, LP, entered into a new five-year revolving Intercompany Credit Agreement with Phillips 66, as lender. The Intercompany Credit Agreement provides up to $1 billion of borrowing capacity, with an option to increase the commitment by an aggregate commitmentsprincipal amount of up to $500 million, subject to lender approval. At our election, the Intercompany Credit Agreement bears interest at either the adjusted term SOFR rate or the base rate plus, in each case, an applicable margin based on our credit rating. A ratings-based pricing grid determines our cost of borrowing under the unsecured revolving credit facility to approximately $1.4 billion. TheIntercompany Credit Agreement. Indebtedness under the Intercompany Credit Agreement is usedbears interest at either: (1) SOFR, plus an applicable margin of 1.075% based on our current credit rating, plus an adjustment of 0.10%; or (2) (a) the base rate, which shall be the higher of the prime rate, the Federal Funds rate plus 0.50% or the SOFR Market Index rate plus 1.00%, plus (b) an applicable margin of 0.075% based on our current credit rating. Based on our current credit rating, the Intercompany Credit Agreement incurs an annual facility fee of 0.175%.
As of June 30, 2023, we had unused borrowing capacity of $900 million, net of $100 million of outstanding borrowings, under the Intercompany Credit Agreement, of which $900 million would have been available to borrow for working capital requirements and other general partnership purposes including acquisitions.
based on the financial covenants set forth in the Intercompany Credit Agreement. Except in the case of a default, amounts borrowed under our Intercompany Credit Agreement will not become due prior to the June 15, 2028 maturity date. As of September 30, 2017, there were no outstanding borrowings on the revolving credit facility under the Credit Agreement. WeJuly 28, 2023, we had unused borrowing capacity of $1,373$900 million, net of $25$100 million of outstanding borrowings.
Credit Agreement — We are party to a Credit Agreement that 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. The Credit Agreement matures on March 18, 2027.
As of June 30, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 million letters of credit, under the Credit Agreement, of which at least $548 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 July 28, 2023, we had unused borrowing capacity of $548 million, net of $850 million of outstanding borrowings and $2 million of letters of credit under the Credit Agreement. The financial covenants set forth in the Credit Agreement limit the Partnership's ability to incur incremental debt by $1,373 million as of September 30, 2017. Our cost of borrowing under the Credit Agreement is determined by a ratings-based pricing grid. In the first quarter
Accounts Receivable Securitization Facility —As of 2017, our credit rating was lowered. As a resultJune 30, 2023, we had $280 million of this action, interest rates on outstanding borrowings under the Credit Agreement increased. AsSecuritization Facility at the SOFR rate plus a margin.
Guarantee of November 2, 2017, we had no outstanding borrowings onRegistered Debt Securities — The condensed consolidated financial statements of DCP Midstream, LP, or “parent guarantor”, include the revolving credit facilityaccounts of DCP Midstream Operating LP, or “subsidiary issuer”, which is a 100% owned subsidiary, and had approximately $1,373 million, net of $26 million of letters of credit, of unused borrowing capacity underall other subsidiaries which are all non-guarantor subsidiaries. The parent guarantor has agreed to fully and unconditionally guarantee the Credit Agreement. We used a portionsenior notes. The entirety of the cash received from the Transaction to repay outstanding debt on our revolving credit facility.
On January 1, 2017, DCP Midstream, LLC contributed to us: (i) its ownership interests in all of its subsidiaries owningCompany’s operating assets and (ii) $424 millionliabilities, 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 cash. In considerationtheir 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 Partnership’s receiptsubsidiary 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 Contributions, (i)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 $73 million and $80 million as of June 30, 2023 and December 31, 2022, respectively;
•Balances related to debt of $4.728 billion and $4.823 billion as of June 30, 2023 and December 31, 2022, respectively; and
•Interest expense, net of $69 million and $69 million for the Partnership issued 28,552,480 common units to DCP Midstream, LLC and 2,550,644 general partner units to DCP Midstream GP, LP, the General Partner, in a private placement, and (ii) the Operating Partnership assumed $3,150 million of DCP Midstream, LLC’s debt. The incentive distributions payable to the holders of the Partnership’s incentive distribution rights with respect to the fiscal years 2017, 2018 and 2019, in certain circumstances, may be reduced in an amount up to $100 million per fiscal year as necessary to provide that the Distributable Cash Flow of the Partnership (as adjusted) during such year meets or exceeds the amount of distributions made by the Partnership (as adjusted) to the partners of the Partnership with respect to such year.
In April 2015, we filed a shelf registration statement with the SEC, that became effective upon filing, which allows us to issue an unlimited amount of common units and debt securities. We have issued no common units or debt securities under this registration statement.
In August 2017, we filed a shelf registration statement with the SEC which allows us to issue up to $750 million in common units pursuant to our 2014 equity distribution agreement to replace the expired shelf registration statement. During the ninethree months ended SeptemberJune 30, 2017, we issued no common units pursuant to these registration statements.2023 and 2022, respectively, and $135 million and $138 million for the six months ended June 30, 2023 and 2022, 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. We have mitigated a portion of our anticipated commodity price risk associated with the equity volumes from our gathering and processing activities through the first quarter of 2019 with fixed price commodity swaps. For additional information regarding our derivative activities, please read Item 3. "Quantitative3. “Quantitative and Qualitative Disclosures about Market Risk"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.
We had working capital deficits of $473$142 million and $629$802 million as of SeptemberJune 30, 20172023 and December 31, 2016,2022, respectively, driven by current maturities of long term debt of $7 million and $506 million, respectively. The change in working capital is primarily attributable to the cash received in the Transaction offset by the repayment of long-term debt outstanding on the revolving credit facility. We had a net derivative working capital surplus of $24 million and deficit of $10 million and $49$8 million as of SeptemberJune 30, 20172023 and December 31, 2016,2022, respectively.
As of September 30, 2017, we had $312 million in cash and cash equivalents, of which $1 million was held by consolidated subsidiaries we did not wholly own.
Cash Flow— Operating, investing and financing activities were as follows:
| | | | | | | | | | | | | |
| | Six Months Ended June 30, |
| | 2023 | | 2022 | | |
| | (millions) |
| Net cash provided by operating activities | $ | 369 | | | $ | 574 | | | |
| Net cash used in investing activities | $ | (151) | | | $ | (61) | | | |
| Net cash used in financing activities | $ | (218) | | | $ | (506) | | | |
|
| | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (Millions) |
| Net cash provided by operating activities | $ | 684 |
| | $ | 521 |
|
| Net cash (used in) provided by investing activities | $ | (198 | ) | | $ | 9 |
|
| Net cash used in financing activities | $ | (175 | ) | | $ | (518 | ) |
NineSix Months Ended SeptemberJune 30, 20172023 vs. NineSix Months Ended SeptemberJune 30, 20162022
Operating Activities — Net cash provided by operating activities decreased $205 million in 2023 compared to the same period in 2022. 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 condensed consolidated statements of cash flows.
We received cash distributions in excess of earnings from unconsolidated affiliates of $36 million and $60 million during the nine months ended September 30, 2017 and 2016, respectively. For additional information regarding fluctuations in our earnings and distributions from unconsolidated affiliates, please read "Results“Supplemental Information on Unconsolidated Affiliates” under “Results of Operations"Operations”.
Investing ActivitiesActivities — Net cash used in investing activities increased $207$90 million in 20172023 compared to the same period in 20162022, primarily as a result of the following:
Net cash usedan increase in investing activities during the nine months ended September 30, 2017 was comprised of capital expenditures, of $258 million, primarily for (1) expansion capital expenditures including construction of the Mewbourn 3 plant, and (2) investment in unconsolidated affiliates, net of $70 million for the capacity expansion of the Sand Hills pipeline, partially offset by (3)a return of capital from an investment and proceeds from the sale of our Douglas gathering system of $130 million.assets.
Net cash provided by investing activities during the nine months ended September 30, 2016 was comprised of: (1) capital expenditures of $113 million, which generally consisted of maintenance capital expenditures for our existing facilities and expansion capital expenditures for construction of additional gathering systems, processing plants, fractionators and other facilities and infrastructure and well connections; (2) investment in unconsolidated affiliates, net of $38 million, which were partially offset by (3) proceeds from the sale of our Northern Louisiana system of $160 million.
Financing ActivitiesActivities — Net cash used in financing activities decreased $343$288 million in 20172023 compared to the same period in 20162022, primarily as a result of the following:
Net cash used in financing activities during the nine months ended September 30, 2017 was primarily comprised of: (1) paymentlower net payments of debt, outstanding on the revolving credit facility of $195 million from cash received from the Transaction, (2) distributions paid to limited partners and the general partner of $390 million, (3) distributions to noncontrolling interests of $6 million, and (4) payment of deferred financing costs of $2 million; which were partially offset by (5) cash received from the Transactionredemption of $418 million.the Series B Preferred Units.
Net cash usedContractual Obligations — Material contractual obligations arising in financing activities during the nine months ended September 30, 2016 wasnormal course of business primarily comprised of: (1) paymentconsist of purchase obligations, long-term debt of $3,216 million, (2) distributions paid to limited partners and related interest payments, leases, asset retirement obligations, and other long-term liabilities. See Note 8 "Debt" in the general partner of $362 million, (3) distributions to noncontrolling interests of $6 million, and (4) payment of deferred financing costs of $10 million; which were partially offset by (5) proceeds from long-term debt of $2,926 million and (6) $150 million attributableNotes to the net changeCondensed Consolidated Financial Statements in advancesItem 1. "Financial Statements" for amounts outstanding on June 30, 2023, related to debt. Lease and asset retirement obligations are not materially different from what was disclosed in Notes 14 and 15, respectively, to the Consolidated Financial Statements included in Item 8 "Financial Statements" in Part II of form 10-K for the year ended December 31, 2022.
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 predecessor operations from DCP Midstream, LLCcash and investment position and operating cash flows as a result ofwell as capacity under existing and available credit agreements will be sufficient to meet our liquidity and capital requirements for the Transaction.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:
maintenance•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. MaintenanceSustaining capital expenditures also include certain well connects, and may include the acquisition or construction of new capital assets; and
expansion•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. We anticipate maintenanceOur 2023 plan includes sustaining capital expenditures of between $100$150 million and $145 million, and approved expansion capital expenditures of between $325 million and $375 million, for the year ending December 31, 2017. We forecast maintenance spending to be at the low end of the range, and expansion spending to approach the high end of the range. Expansion capital expenditures include the construction of the Mewbourn 3 plant, Grand Parkway Phase 2 and O'Connor bypass in our DJ Basin system, and the capacity expansions of the Sand Hills pipeline, which are shown as an investment in unconsolidated affiliates in our condensed consolidated statements of cash flows.
The following table summarizes our maintenance and expansion capital expenditures for our consolidated entities:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2017 | | Nine Months Ended September 30, 2016 |
| | Maintenance Capital Expenditures | | Expansion Capital Expenditures | | Total Consolidated Capital Expenditures | | Maintenance Capital Expenditures | | Expansion Capital Expenditures | | Total Consolidated Capital Expenditures |
| | (Millions) |
| Our portion | $ | 64 |
| | $ | 191 |
| | $ | 255 |
| | $ | 61 |
| | $ | 53 |
| | $ | 114 |
|
| Noncontrolling interest portion and reimbursable projects (a) | 1 |
| | 2 |
| | 3 |
| | 1 |
| | (2 | ) | | (1 | ) |
| Total | $ | 65 |
| | $ | 193 |
| | $ | 258 |
| | $ | 62 |
| | $ | 51 |
| | $ | 113 |
|
| |
(a) | Represents the noncontrolling interest and reimbursable portion of our capital expenditures. We have entered into agreements with third parties whereby we will be reimbursed for certain expenditures. Depending on the timing of these payments, we may be reimbursed prior to incurring the capital expenditure. |
In addition, we invested cash in unconsolidated affiliates of $70 million and $38 million during the nine months ended September 30, 2017 and 2016, respectively, to fund our share of capital expansion projects.
We intend to make cash distributions to our unitholders and our general partner. Due to our cash distribution policy, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, to fund future acquisitions and capital expenditures.$125 million.
We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Agreement, Intercompany Credit Agreement, Securitization Facility and the issuance of additional limited partnership unitsdebt and equity securities. Future material investments may require that we obtain additional capital, assume third party debt or incur other long-term obligations. We have the issuanceoption to utilize both equity and debt instruments as vehicles for the long-term financing of long-term debt.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 $390$179 million and $362$163 million during the ninesix months ended SeptemberJune 30, 20172023 and 2016,2022, respectively. We intend to continue making
On July 14, 2023, we announced that the board of directors of the General Partner declared a quarterly distribution paymentson our Common Units of $0.43 per Common Unit. The distribution will be paid on August 11, 2023 to our unitholders and general partner toof record on July 31, 2023.
Also on July 14, 2023, the extent we have sufficient cash from operations after the establishmentboard of reserves.
As partdirectors of the Transaction, Phillips 66 and Enbridge agreed, if required, to provide a reduction to incentive distributions payable to our General Partner underdeclared a quarterly distribution on our Partnership AgreementSeries C Preferred Units of up to $100 million annually through 2019 to target an approximate 1.0 times$0.4969 per unit. The Series C distribution coverage ratio. Under the terms of our amended partnership agreement, the amount of incentive distributions paid to our General Partner will be evaluated by our General Partnerpaid on both a quarterly and annual basis and may be reduced each quarter by an amount determined by our general partner (the “IDR giveback”). If no determination is made by our General Partner, the quarterly IDR giveback will be $20 million. The IDR giveback,October 16, 2023 to unitholders of up to $100 million annually, will be subject to a true-up at the end of the year by taking our total distributable cash flow (as adjusted under our amended partnership agreement) less the total annual distribution payable to our unitholders, adjusted to target an approximaterecord on October 2, 2023.
1.0 times coverage ratio. In accordance with our amended partnership agreement, distributions declared were $155 million and $424 million for the three and nine months ended September 30, 2017, respectively. Distributions declared reflected no IDR givebacks in the three months ended September 30, 2017, and reflected $40 million of IDR givebacks for the nine months ended September 30, 2017.
We expect to continue to use cash provided by operating activities for the payment of distributions to our unitholders and general partner.unitholders. See Note 13. "Partnership10 “Partnership Equity and Distributions"Distributions” in the Notes to the Condensed Consolidated Financial Statements in Item 1. “Financial Statements.”Statements”. Total Contractual Cash Obligations
A summary of our total contractual cash obligations as of September 30, 2017, was as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Payments Due by Period |
| | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | Thereafter |
| | (Millions) |
| Debt (a) | $ | 8,354 |
| | $ | 780 |
| | $ | 1,832 |
| | $ | 1,205 |
| | $ | 4,537 |
|
| Operating lease obligations | 179 |
| | 43 |
| | 66 |
| | 40 |
| | 30 |
|
| Purchase obligations (b) | 2,782 |
| | 750 |
| | 758 |
| | 659 |
| | 615 |
|
| Other long-term liabilities (c) | 141 |
| | — |
| | 16 |
| | 15 |
| | 110 |
|
| Total | $ | 11,456 |
| | $ | 1,573 |
| | $ | 2,672 |
| | $ | 1,919 |
| | $ | 5,292 |
|
| |
(a) | Includes interest payments on debt securities that have been issued. These interest payments are $280 million, $457 million, $355 million, and $2,037 million for less than one year, one to three years, three to five years, and thereafter, respectively. |
| |
(b) | Our purchase obligations are contractual obligations and include purchase orders and non-cancelable construction agreements for capital expenditures, various non-cancelable commitments to purchase physical quantities of commodities in future periods and other items, including long-term fractionation agreements. For contracts where the price paid is based on an index or other market-based rates, the amount is based on the forward market prices or current market rates as of September 30, 2017. Purchase obligations exclude accounts payable, accrued taxes and other current |
liabilities recognized in the condensed consolidated balance sheets. Purchase obligations also exclude current and long-term unrealized losses on derivative instruments included in the condensed consolidated balance sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts may be settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity. In addition, many of our gas purchase contracts include short and long-term commitments to purchase produced gas at market prices. These contracts, which have no minimum quantities, are excluded from
the table.
| |
(c) | Other long-term liabilities include asset retirement obligations, long-term environmental remediation liabilities, gas purchase liabilities, and other miscellaneous liabilities recognized in the September 30, 2017 condensed consolidated balance sheet. The table above excludes non-cash obligations as well as $28 million of Executive Deferred Compensation Plan contributions and $11 million of long-term incentive plans as the amount and timing of any payments are not subject to reasonable estimation. |
Off-Balance Sheet Obligations
As of September 30, 2017, we had no items that were classified as off-balance sheet obligations.
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 of natural gas and NGLs,related costs, and we define segment adjusted gross margin for each segment as total operating revenues for that segment less commodity purchases and related costs for that segment. Our adjusted gross margin equals the sum of our segment adjusted gross margins. GrossAdjusted 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 flows fromprovided by operating activities or any other measure of financial performance presented in accordance with accounting principles generally acceptedGAAP.
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 the United States of America, or GAAP.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 flows fromprovided 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 general partner, and finance maintenancepay 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 maintenancesustaining capital expenditures, net of reimbursable projects, less interest expense, less income attributable to preferred units, and certain other items. MaintenanceSustaining 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. MaintenanceSustaining 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. We compare the Distributable Cash Flow we generate to the cash distributions we expect to pay our partners. Using this metric, we compute our distribution coverage ratio. Distributable Cash Flow is used as a supplemental liquidity and performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess our ability to make cash distributions to our unitholders and our general partner.
Our Distributable Cash Flow may not be comparable to a similarly titled measuremeasures of another companyother companies 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 similarly titled measures of other companies 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: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2023 | | 2022 | | 2023 | | 2022 | | |
| Reconciliation of Non-GAAP Measures | | (millions) |
| | | | | | | | | | |
| Reconciliation of gross margin to adjusted gross margin: | | | | | | | | | | |
| | | | | | | | | | |
| Operating revenues | | $ | 1,841 | | | $ | 4,269 | | | $ | 4,567 | | | $ | 7,644 | | | |
| Cost of revenues | | | | | | | | | | |
| Purchases and related costs | | 1,112 | | | 3,269 | | | 2,964 | | | 5,988 | | | |
| Purchases and related costs from affiliates | | 12 | | | 100 | | | 109 | | | 199 | | | |
| Transportation and related costs from affiliates | | 288 | | | 275 | | | 567 | | | 532 | | | |
| Depreciation and amortization expense | | 91 | | | 90 | | | 181 | | | 180 | | | |
| Gross margin | | 338 | | | 535 | | | 746 | | | 745 | | | |
| Depreciation and amortization expense | | 91 | | | 90 | | | 181 | | | 180 | | | |
| Adjusted gross margin | | $ | 429 | | | $ | 625 | | | $ | 927 | | | $ | 925 | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Reconciliation of segment gross margin to segment adjusted gross margin: | | | | | | | | | | |
| | | | | | | | | | |
| Logistics and Marketing segment: | | | | | | | | | | |
| Operating revenues | | $ | 1,561 | | | $ | 3,789 | | | $ | 3,953 | | | $ | 6,952 | | | |
| Cost of revenues | | | | | | | | | | |
| Purchases and related costs | | 1,503 | | | 3,749 | | | 3,841 | | | 6,896 | | | |
| Depreciation and amortization expense | | 4 | | | 3 | | | 6 | | | 6 | | | |
| Segment gross margin | | 54 | | | 37 | | | 106 | | | 50 | | | |
| Depreciation and amortization expense | | 4 | | | 3 | | | 6 | | | 6 | | | |
| Segment adjusted gross margin | | $ | 58 | | | $ | 40 | | | $ | 112 | | | $ | 56 | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Gathering and Processing segment: | | | | | | | | | | |
| Operating revenues | | $ | 1,252 | | | $ | 2,967 | | | $ | 3,018 | | | $ | 5,073 | | | |
| Cost of revenues | | | | | | | | | | |
| Purchases and related costs | | 881 | | | 2,382 | | | 2,203 | | | 4,204 | | | |
| Depreciation and amortization expense | | 84 | | | 82 | | | 168 | | | 163 | | | |
| Segment gross margin | | 287 | | | 503 | | | 647 | | | 706 | | | |
| Depreciation and amortization expense | | 84 | | | 82 | | | 168 | | | 163 | | | |
| Segment adjusted gross margin | | $ | 371 | | | $ | 585 | | | $ | 815 | | | $ | 869 | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Reconciliation of Non-GAAP Measures | | (Millions) |
| | | | | | | | | |
| Reconciliation of net (loss) income attributable to partners to gross margin: | | | | | | | | |
| | | | | | | | | |
| Net (loss) income attributable to partners | | $ | (20 | ) | | $ | 89 |
| | $ | 169 |
| | $ | 132 |
|
| Interest expense | | 73 |
| | 77 |
| | 219 |
| | 235 |
|
| Income tax expense | | 2 |
| | 1 |
| | 5 |
| | 6 |
|
| Operating and maintenance expense | | 168 |
| | 161 |
| | 513 |
| | 506 |
|
| Depreciation and amortization expense | | 94 |
| | 94 |
| | 282 |
| | 284 |
|
| General and administrative expense | | 69 |
| | 64 |
| | 202 |
| | 187 |
|
| Asset impairments | | 48 |
| | — |
| | 48 |
| | — |
|
| Other expense (income), net | | — |
| | 14 |
| | 15 |
| | (68 | ) |
| Restructuring costs | | — |
| | 2 |
| | — |
| | 10 |
|
| Earnings from unconsolidated affiliates | | (74 | ) | | (75 | ) | | (234 | ) | | (214 | ) |
| Gain on sale of assets, net | | — |
| | (41 | ) | | (34 | ) | | (35 | ) |
| Net income attributable to noncontrolling interests | | — |
| | — |
| | 1 |
| | 1 |
|
| Gross margin | | $ | 360 |
| | $ | 386 |
| | $ | 1,186 |
| | $ | 1,044 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (59 | ) | | $ | 9 |
| | $ | 1 |
| | $ | (80 | ) |
| | | | | | | | | |
| Reconciliation of segment net income attributable to partners to segment gross margin: | | | | | | | | |
| | | | | | | | | |
| Gathering and Processing segment: | | | | | | | | |
| Segment net income attributable to partners | | $ | 29 |
| | $ | 134 |
| | $ | 322 |
| | $ | 310 |
|
| Operating and maintenance expense | | 154 |
| | 146 |
| | 469 |
| | 458 |
|
| Depreciation and amortization expense | | 85 |
| | 85 |
| | 256 |
| | 258 |
|
| General and administrative expense | | 2 |
| | 2 |
| | 15 |
| | 10 |
|
| Asset impairments | | 48 |
| | — |
| | 48 |
| | — |
|
| Other expense (income), net | | — |
| | 13 |
| | 3 |
| | (74 | ) |
| Earnings from unconsolidated affiliates | | (15 | ) | | (20 | ) | | (59 | ) | | (52 | ) |
| Gain on sale of assets, net | | — |
| | (25 | ) | | (34 | ) | | (19 | ) |
| Net income attributable to noncontrolling interests | | — |
| | — |
| | 1 |
| | 1 |
|
| Segment gross margin | | $ | 303 |
| | $ | 335 |
| | $ | 1,021 |
| | $ | 892 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (51 | ) | | $ | (5 | ) | | $ | (4 | ) | | $ | (73 | ) |
| | | | | | | | | |
| Logistics and Marketing segment: | | | | | | | | |
| Segment net income attributable to partners | | $ | 99 |
| | $ | 103 |
| | $ | 278 |
| | $ | 273 |
|
| Operating and maintenance expense | | 9 |
| | 13 |
| | 31 |
| | 33 |
|
| Depreciation and amortization expense | | 4 |
| | 4 |
| | 11 |
| | 12 |
|
| Other expense, net | | 1 |
| | — |
| | 12 |
| | 5 |
|
| General and administrative expense | | 3 |
| | 2 |
| | 8 |
| | 7 |
|
| Earnings from unconsolidated affiliates | | (59 | ) | | (55 | ) | | (175 | ) | | (162 | ) |
| Gain on sale of assets, net | | — |
| | (16 | ) | | — |
| | (16 | ) |
| Segment gross margin | | $ | 57 |
| | $ | 51 |
| | $ | 165 |
| | $ | 152 |
|
| Non-cash commodity derivative mark-to-market (a) | | $ | (8 | ) | | $ | 14 |
| | $ | 5 |
| | $ | (7 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | | 2023 | | 2022 | | 2023 | | 2022 | | |
| | | (millions) |
| Reconciliation of net income attributable to partners to adjusted segment EBITDA: | | | | | | | | | | |
| | | | | | | | | | |
| Logistics and Marketing segment: | | | | | | | | | | |
| Segment net income attributable to partners (a) | | $ | 192 | | | $ | 201 | | | $ | 387 | | | $ | 342 | | | |
| Non-cash commodity derivative mark-to-market | | (17) | | | (26) | | | (12) | | | 19 | | | |
| Depreciation and amortization expense, net of noncontrolling interest | | 4 | | | 3 | | | 6 | | | 6 | | | |
| Distributions from unconsolidated affiliates, net of earnings | | 38 | | | 29 | | | 41 | | | 52 | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Other (income) expense | | — | | | (2) | | | — | | | (2) | | | |
| Adjusted segment EBITDA | | $ | 217 | | | $ | 205 | | | $ | 422 | | | $ | 417 | | | |
| | | | | | | | | | |
| Gathering and Processing segment: | | | | | | | | | | |
| Segment net income attributable to partners | | $ | 64 | | | $ | 322 | | | $ | 243 | | | $ | 393 | | | |
| Non-cash commodity derivative mark-to-market | | 10 | | | (75) | | | (35) | | | 56 | | | |
| Depreciation and amortization expense, net of noncontrolling interest | | 84 | | | 81 | | | 168 | | | 162 | | | |
| Distributions from unconsolidated affiliates, net of earnings | | 6 | | | 4 | | | 11 | | | 6 | | | |
| Asset impairments | | — | | | 1 | | | — | | | 1 | | | |
| | | | | | | | | | |
| Loss (gain) on sale of assets | | 3 | | | — | | | 3 | | | (7) | | | |
| | | | | | | | | | |
| Other expenses | | — | | | 2 | | | — | | | 2 | | | |
| Adjusted segment EBITDA | | $ | 167 | | | $ | 335 | | | $ | 390 | | | $ | 613 | | | |
(a) We recognized zero and $22 million of lower of cost or net realizable value adjustment for the three and six months ended June 30, 2023, respectively. We recognized no lower of cost or net realizable value adjustment for the three and six months ended June 30, 2022.
| |
(a) | Non-cash commodity derivative mark-to-market is included in gross margin and segment gross margin, along with cash settlements for our commodity derivative contracts. |
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | (Millions) |
| Reconciliation of net income attributable to partners to adjusted segment EBITDA: | | | | | | | | |
| Gathering and Processing segment: | | | | | | | | |
| Segment net income attributable to partners (a) | | $ | 29 |
| | $ | 134 |
| | $ | 322 |
| | $ | 310 |
|
| Non-cash commodity derivative mark-to-market | | 51 |
| | 5 |
| | 4 |
| | 73 |
|
| Depreciation and amortization expense, net of noncontrolling interest | | 85 |
| | 85 |
| | 256 |
| | 258 |
|
| Asset impairments | | 48 |
| | — |
| | 48 |
| | — |
|
| Gain on sale of assets, net | | — |
| | (25 | ) | | (34 | ) | | (19 | ) |
Distributions from unconsolidated affiliates, net of earnings
| | 6 |
| | 5 |
| | 10 |
| | 18 |
|
| Other expense | | 1 |
| | 13 |
| | 4 |
| | 13 |
|
| Adjusted segment EBITDA | | $ | 220 |
| | $ | 217 |
| | $ | 610 |
| | $ | 653 |
|
| Logistics and Marketing segment: | | | | | | | | |
| Segment net income attributable to partners | | $ | 99 |
| | $ | 103 |
| | $ | 278 |
| | $ | 273 |
|
Non-cash commodity derivative mark-to-market
| | 8 |
| | (14 | ) | | (5 | ) | | 7 |
|
| Depreciation and amortization expense, net of noncontrolling interest | | 4 |
| | 4 |
| | 11 |
| | 12 |
|
Distributions from unconsolidated affiliates, net of earnings
| | 13 |
| | 18 |
| | 26 |
| | 42 |
|
| Gain on sale of assets, net | | — |
| | (16 | ) | | — |
| | (16 | ) |
| Other expense | | — |
| | — |
| | 9 |
| | — |
|
| Adjusted segment EBITDA | | $ | 124 |
| | $ | 95 |
| | $ | 319 |
| | $ | 318 |
|
| |
(a) | There were no lower of cost or market adjustments for the three and nine months ended September 30, 2017. There were no lower of cost or market adjustments for the three months ended September 30, 2016 and $3 million for the nine months ended September 30, 2016. |
Critical Accounting Policies and Estimates
Our critical accounting policies and estimates are described in Critical"Critical Accounting Policies and EstimatesEstimates" within exhibit 99.3Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" toincluded in our Annual Report on Form 10-K for the May 2017 8-Kyear ended December 31, 2022 and Note 2 of the Notes to Consolidated Financial Statements in Exhibit 99.4 “Financial"Financial Statements and Supplementary Data”Data" included as Exhibit 99.4Item 8 in our Annual Report on Form 10-K for the May 2017 8-K.year ended December 31, 2022. The accounting policies and estimates used in preparing our interim condensed consolidated financial statements for the ninethree and six months ended SeptemberJune 30, 20172023 are the same as those described in our Annual Report on Form 10-K for the May 2017 8-K.year ended December 31, 2022. Certain information and note disclosures normally included in our annual financial statements prepared in accordance with GAAP have been condensed or omitted from the interim financial statements included in this Quarterly Report on Form 10-Q pursuant to the rules and regulations of the SEC, although we believe that the disclosures made are adequate to make the information not misleading. The unaudited condensed consolidated financial statements and other information included in this Quarterly Report on Form 10-Q should be read in conjunction with the audited consolidated financial statements and notes thereto in our Annual Report on Form 10-K for the May 2017 8-K.year ended December 31, 2022.
Item 3.Quantitative and Qualitative Disclosures about Market Risk
For an in-depth discussion of our market risks, see "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" in our Annual Report on Form 10-K for the year ended December 31, 2016.
The following tables set forth additional information about our fixed price swaps used to mitigate a portion of our natural gas and NGL price risk associated with our percent-of-proceeds arrangements and our condensate price risk associated with our gathering and processing operations. Our positions as of November 2, 2017 were as follows:
Commodity Swaps
|
| | | | | | | | |
Period | | Commodity | | Notional
Volume
- Short
Positions
| | Reference Price | | Price Range |
October 2017 — December 2017 | | Natural Gas | | (60,000) MMBtu/d | | NYMEX Final Settlement Price (b) | | $3.28-$4.27/MMBtu |
January 2018 — March 2018 | | Natural Gas | | (27,500) MMBtu/d | | NYMEX Final Settlement Price (b) | | $3.54-$3.68/MMBtu |
October 2017 — December 2017 | | NGLs | | (29,355) Bbls/d (d) | | Mt.Belvieu (c) | | $.28-$1.22/Gal |
January 2018 — December 2018 | | NGLs | | (15,591) Bbls/d (d) | | Mt.Belvieu (c) | | $.29-$.96/Gal |
October 2017 — December 2017 | | Crude Oil | | (3,001) Bbls/d (d) | | NYMEX crude oil futures (a) | | $53.54-$56.76/Bbl |
January 2018 — December 2018 | | Crude Oil | | (4,282) Bbls/d (d) | | NYMEX crude oil futures (a) | | $51.20-$56.61/Bbl |
January 2019 — February 2019 | | Crude Oil | | (2,560) Bbls/d (d) | | NYMEX crude oil futures (a) | | $51.26-$51.29/Bbl |
| |
(a) | Monthly average of the daily close prices for the prompt month NYMEX light, sweet crude oil futures contract. |
| |
(b) | NYMEX final settlement price for natural gas futures contracts. |
| |
(c) | The average monthly OPIS price for Mt. Belvieu TET/Non-TET. |
| |
(d) | Average Bbls/d per time period. |
Our sensitivities for 20172023 as shown in the table below are estimated based on our average estimated commodity price exposure and commodity cash flow protection activities for the calendar year 2017, and exclude the impact of non-cash mark-to-market changes on our commodity derivatives. We utilize direct product crude oil, natural gas and NGL derivatives to mitigate a portion of our condensate, natural gas and NGL commodity price exposure. These sensitivities are associated with our condensate, natural gas and NGL volumes that are currently unhedged.
Commodity Sensitivities Net of Cash Flow Protection Activities |
| | | | | | | | | |
| | Per Unit Decrease | | Unit of Measurement | | Estimated Decrease in Annual Net Income Attributable to Partners |
| | | | | | (Millions) |
| Natural gas prices | $ | 0.10 |
| | MMBtu | | $ | 7 |
|
| Crude oil prices | $ | 1.00 |
| | Barrel | | $ | 4 |
|
| NGL prices | $ | 0.01 |
| | Gallon | | $ | 5 |
|
| | | | | | | | | | | | | | | | | |
| Per Unit Decrease | | Unit of
Measurement | | Estimated
Decrease in
Annual Net
Income
Attributable to
Partners |
| | | | | | (millions) |
| NGL prices | $ | 0.01 | | | Gallon | | $ | 10 | |
| Natural gas prices | $ | 0.10 | | | MMBtu | | $ | 6 | |
| Crude oil prices | $ | 1.00 | | | Barrel | | $ | 5 | |
In addition to the linear relationships in our commodity sensitivities above, additional factors may cause us to be less sensitive to commodity price declines. A portion of our net income is derived from fee-based contracts and a portion from percentage-of-proceeds and percentage-of-liquids processing arrangements that contain minimum fee clauses in which our processing margins convert to fee-based arrangements as commodity prices decline.
The above sensitivities exclude the impact from arrangements where producers on a monthly basis may elect to not process their natural gas in which case we retain a portion of the customers’ natural gas in lieu of NGLs as a fee. The above sensitivities also exclude certain related processing arrangements where we control the processing or by-pass of the production based upon individual economic processing conditions. Under each of these types of arrangements, our processing of the natural gas would yield favorable processing margins.
We estimate the following sensitivities related to the non-cash mark-to-market on our commodity derivatives associated with our open position on our commodity cash flow protection activities:
Non-Cash Mark-To-Market Commodity Sensitivities
|
| | | | | | | | | |
| | Per Unit Increase | | Unit of Measurement | | Estimated Mark-to- Market Impact (Decrease in Net Income Attributable to Partners) |
| | | | | | (Millions) |
| Natural gas prices | $ | 0.10 |
| | MMBtu | | $ | 2 |
|
| Crude oil prices | $ | 1.00 |
| | Barrel | | $ | 1 |
|
| NGL prices | $ | 0.01 |
| | Gallon | | $ | 3 |
|
While the above commodity price sensitivities are indicative of the impact that changes in commodity prices may have on our annualized net income, changes during certain periods of extreme price volatility and market conditions or changes in the relationship of the price of NGLs and crude oil may cause our commodity price sensitivities to vary significantly from these estimates.
The midstream natural gas industry is cyclical, with the operating results of companies in the industry significantly affected by the prevailing price of NGLs, which in turn has been generally related to the price of crude oil. Although the prevailing price of residue natural gas has less short-term significance to our operating results than the price of NGLs, in the long-term the growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production. To minimize potential future commodity-based pricing and cash flow volatility, we have entered into a series of derivative financial instruments. As a result of these transactions, we have mitigated a portion of our expected commodity price risk relating to the equity volumes associated with our gathering and processing activities through the first quarter of 2018.
Based on historical trends, we generally expect NGL prices to directionally follow changes in crude oil prices over the long-term. However, the pricing relationship between NGLs and crude oil may vary, as we believe crude oil prices will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy, whereas NGL prices are more correlated to supply and U.S. petrochemical demand. However,Additionally, the level of
NGL exports has increased in recent years.export demand may also have an impact on prices. We believe that future natural gas prices will be influenced by the severity of winter and summer weather, the level of North American production and drilling activity of exploration and production companies, and the balance of trade between imports and exports of liquid natural gas and NGLs.NGLs and the severity of winter and summer weather. Drilling activity can be adversely affected as natural gas prices decrease. Energy market uncertainty could also reduce North American drilling activity.
Limited access to capital could also decrease drilling. Lower drilling levels over a sustained period would reduce natural gas volumes gathered and processed, but could increase commodity prices, if supply were to fall relative to demand levels.
Natural Gas Storage and Pipeline Asset Based Commodity Derivative Program — Our natural gas storage and pipeline assets are exposed to certain risks including changes in commodity prices. We manage commodity price risk related to our natural gas storage and pipeline assets through our commodity derivative program. The commercial activities related to our natural gas storage and pipeline assets primarily consist of the purchase and sale of gas and associated time spreads and basis spreads.
A time spread transaction is executed by establishing a long gas position at one point in time and establishing an equal short gas position at a different point in time. Time spread transactions allow us to lock in a margin supported by the injection, withdrawal, and storage capacity of our natural gas storage assets. We may execute basis spread transactions to mitigate the risk of sale and purchase price differentials across our system. A basis spread transaction allows us to lock in a margin on our physical purchases and sales of gas, including injections and withdrawals from storage. We typically use swaps to execute these transactions, which are not designated as hedging instruments and are recorded at fair value with changes in fair value recorded in the current period condensed consolidated statements of operations. While gas held in our storage locations is recorded at the lower of average cost or market,net realizable value, the derivative instruments that are used to manage our storage facilities are recorded at fair value and any changes in fair value are currently recorded in our condensed consolidated statements of operations. Even though we may have economically hedged our exposure and locked in a future margin, the use of lower-of-cost-or-marketlower-of-cost-or-net realizable value accounting for our physical inventory and the use of mark-to-market accounting for our derivative instruments may subject our earnings to market volatility.
The following tables set forth additional information about our derivative instruments, used to mitigate a portion of our natural gas price risk associated with our inventory within our natural gas storage operations as of SeptemberJune 30, 2017:2023:
Inventory | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period ended | | Commodity | | Notional Volume - Long
Positions | | Fair Value
(millions) | | Weighted
Average Price |
| | | | | | | | | | |
| June 30, 2023 | | Natural Gas | | 11,550,402 | | | MMBtu | | $ | 20 | | | $1.76/MMBtu |
Commodity Swaps | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Commodity | | Notional Volume - (Short)/Long
Positions | | Fair Value
(millions) | | Price Range |
| | | | | | | | | | | |
| July 2023 — January 2025 | | Natural Gas | | (26,215,000) | | | MMBtu | | $ | 1 | | | $2.18-$5.98/MMBtu |
| July 2023 — December 2024 | | Natural Gas | | 15,192,500 | | | MMBtu | | $ | (2) | | | $2.16-$5.20/MMBtu |
Natural Gas Asset Based Trading and Marketing - Our trading and marketing activities are subject to commodity price fluctuations in response to changes in supply and demand, market conditions and other factors.
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. The following table sets forth our commodity derivative instruments as of June 30, 2023:
Commodity Swaps
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Period | | Commodity | | Notional Volume - (Short)/Long Positions | | Fair Value (millions) | | Price Range (a) |
| | July 2023 — December 2026 | | Natural Gas | | (46,517,500) | | | MMBtu | | $ | 5 | | | $0.02-$0.14/MMBtu |
| | July 2023 — December 2026 | | Natural Gas | | 44,555,000 | | | MMBtu | | $ | (10) | | | $0.09-$0.71/MMBtu |
(a) Represents the basis differential from NYMEX final settlement price for natural gas futures contracts for stated time period
|
| | | | | | | | | | | | | |
| Period ended | | Commodity | | Notional Volume - Long Positions | | Fair Value (millions) | | Weighted Average Price |
| | | | | | | | | | | |
| September 30 2017 | | Natural Gas | | 11,055,842 |
| | MMBtu | | $ | 32 |
| | $2.88/MMBtu |
Commodity Swaps
|
| | | | | | | | | | | | | |
| Period | | Commodity | | Notional Volume - (Short)/Long Positions | | Fair Value (millions) | | Price Range |
| | | | | | | | | | | |
| October 2017-April 2018 | | Natural Gas | | (25,937,500 | ) | | MMBtu | | $ | 2 |
| | $2.86-$3.58/MMBtu |
| October 2017-October 2018 | | Natural Gas | | 14,585,000 |
| | MMBtu | | $ | 1 |
| | $2.69-$3.00/MMBtu |
Item 4.Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the SEC under the Securities Exchange Act of 1934, as amended or the Exchange Act,(the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to the management of our General Partner,general partner, including our General Partner’sgeneral partner’s interim principal executive and interim principal financial officers (whom we refer to as the "Certifying Officers"“Certifying Officers”), as appropriate to allow timely decisions regarding required disclosure. The management of our general partner evaluated, with the participation of the Certifying Officers, the effectiveness of our disclosure controls and procedures as of SeptemberJune 30, 2017,2023, pursuant to Rule 13a-15(b) under the Exchange Act. Based upon that evaluation, the Certifying Officers concluded that, as of SeptemberJune 30, 2017,2023, our disclosure controls and procedures were effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There were no changes in internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended SeptemberJune 30, 20172023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATIONII
Item 1.Legal Proceedings
The information provided in “Commitments and Contingent Liabilities,”Liabilities” included in (a) Note 1922 of the Notes to Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K for the 2016 audited consolidated financial statementsyear ended December 31, 2022 and notes thereto(b) Note 13 of the Notes to Condensed Consolidated Financial Statements included as Exhibit 99.4 in the May 2017 8-K and in Note 15Item 1 of Part I of this Quarterly Report on Form 10-Q isare incorporated herein by reference. 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 million or more.
Item 1A. Risk Factors
In addition to the other information set forthAn investment in this report,our securities involves various risks. When considering an investment in us, careful consideration should be given to the risk factors discussed in Part I, “Item 1A.1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016. An investment in our securities involves various risks. When considering an investment in us, you should consider carefully all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2016.2022. There are no material changes to the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2016.2022.
Item 5. Other Information
None.
Item 6. Exhibits
|
| | | | | | | | | | | | | | |
| Exhibit Number | | | | Description | |
|
| *#+ |
| Contribution Agreement and Plan of Merger, dated December 30, 2016,January 5, 2023, by and among DCP Midstream,Phillips 66, Phillips 66 Project Development Inc., Dynamo Merger Sub LLC, DCP Midstream, Partners,LP, DCP Midstream GP, LP and DCP Midstream Operating, LPGP, LLC (attached as Exhibit 2.1 to DCP Midstream Partners, LP’sLP's Current Report on Form 8-K (File No. 001-32678) filed with the SEC on January 6, 2017)2023). | |
|
| * |
| | |
|
| * |
| | |
| | * | | | |
| | | | | |
| | | | | |
| | * | | | |
| | + | | | |
| | * | | Credit Agreement, dated April 11, 2008as of June 15, 2023, by and among DCP Midstream, LP, as guarantor, DCP Midstream Operating, LP, as borrower, and Phillips 66 Company, as lender (attached as Exhibit 4.110.1 to DCP Midstream, Partners, LP’s Current Report on Form 8-K (File No. 001-32678) filed with the SEC on April 14, 2008)June 15, 2023). | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| | * | | | |
| | | | | |
| | | | | |
| | | | | |
|
| * |
| |
|
| * |
| |
| | * | | |
| |
| | |
| |
| | | |
| |
| | | |
| |
| | | |
| |
| | | |
| 101 | |
| | Financial statements from the Quarterly Report on Form 10-Q of DCP Midstream, LP for the three and ninesix months ended SeptemberJune 30, 2017,2023, formatted in XBRL: (i) the Condensed Consolidated Balance Sheets, (ii) the Condensed Consolidated Statements of Operations, (iii) the Condensed Consolidated Statements of Comprehensive Income, (iv) the Condensed Consolidated Statements of Cash Flows, (v) the Condensed Consolidated Statements of Changes in Equity, and (vi) the Notes to the Condensed Consolidated Financial Statements. | |
| 104 | | | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |
* Such exhibit has heretofore been filed with the SEC as part of the filing indicated and is incorporated herein by reference.
+ Denotes management contract or compensatory plan or arrangement.
# Pursuant to Item 601(b)(2)(10)(iv) of Regulation S-K, the Partnership agrees to furnish supplementally aan unredacted copy of any omitted
schedulethis exhibit to the Securities and Exchange Commission upon request.request.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | | | | | | | | | | | | |
| DCP Midstream, LP |
| | |
| By: | DCP Midstream GP, LP its General Partner |
| | |
| By: | DCP Midstream GP, LLC its General Partner |
| | |
Date: November 7, 2017August 3, 2023 | By: | /s/ Wouter T. van KempenDonald A. Baldridge |
| | Name: | Wouter T. van KempenDonald A. Baldridge |
| | Title: | President andInterim Chief Executive Officer |
| | | (Principal Executive Officer) |
| | | | |
Date: November 7, 2017August 3, 2023 | By: | /s/ Sean P. O'BrienScott R. Delmoro |
| | Name: | Sean P. O'BrienScott R. Delmoro |
| | Title: | Group Vice President andInterim Chief Financial Officer |
| | | (Principal Financial Officer) |