SEC Filing | DCP Midstream, LP

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June 27, 2017

VIA EDGAR

Jennifer Thompson
Accounting Branch Chief
Office of Consumer Products

United States Securities and Exchange Commission
100 F. Street, N.E.
Washington, D.C. 20549


Re:	DCP Midstream, LP Form 10-K for the Fiscal Year Ended December 31, 2016 Filed February 15, 2017

Form 10-Q for the Quarterly Period Ended March 31, 2017

Filed May 10, 2017
File No. 001-32678

Dear Ms. Thompson:

Set forth below are the responses of DCP Midstream, LP, a Delaware limited partnership (the “Partnership,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated June 13, 2017, with respect to the review of the Partnership’s (a) Form 10-K for the year ended December 31, 2016 (File No. 001-32678) filed with the Commission on February 15, 2017 (the “Form 10-K”) and (b) Form 10-Q for the quarter ended March 31, 2017 (File No. 001-32678) filed with the Commission on May 10, 2017 (the “Form 10-Q”). For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold text.

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Form 10-K for the Fiscal Year Ended December 31, 2016

Item 9A. Controls and Procedures

Management’s Annual Report On Internal Control Over Financial Reporting, page 146

Comment: We note that management has conducted an evaluation of the effectiveness of your internal control over financial reporting as of December 31, 2016 based on the "Internal Control-Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Please tell us and revise future filings to disclose whether you applied the 1992 or 2013 COSO framework in your assessment. Reference is made to Item 308(a)(2) of Regulation S-K.

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 2

Response: In evaluating the effectiveness of our internal control over financial reporting for the year ended December 31, 2016, management applied the 2013 COSO framework to perform the assessment. In future filings, we will disclose the version of the framework on which management’s evaluation is based. An example revised disclosure is provided below:

Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2016 based on the framework in "Internal Control-Integrated Framework" (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2016.

Form 10-Q for the Quarterly Period Ended March 31, 2017

Item 1. Financial Statements

6. Property, Plant and Equipment, page 11

Comment: Based on your disclosures on page 55 it appears volumes in the Eagle Ford and East Texas systems have declined in the first quarter of fiscal 2017. Further, we note from the March 31, 2017 earnings call that you have idled an underutilized plant in the Eagle Ford system to help offset volume declines with cost savings. In light of these developments, please tell us if you performed an impairment analysis of the Eagle Ford Asset Group during the first quarter of fiscal 2017, and if so, please tell us the results of the analysis. If you did not perform an impairment analysis, please explain to us why you do not believe such an analysis was necessary given these developments. Refer to ASC 360-10-35-21-b. We may have further comment.

Response: The Partnership did not perform an undiscounted cash flow impairment test for the Eagle Ford asset group during the first quarter of fiscal 2017. It is the Partnership’s practice to perform an analysis for the identification of impairment indicators on a quarterly basis considering many factors that could indicate an asset group’s carrying value may not be recoverable. As part of our assessments for potential impairment of our long-lived assets, we evaluate the qualitative factors within ASC 360-10-35-21 as well as other qualitative and quantitative factors not listed under ASC 360-10-35-21 that are unique to our business. These other factors unique to our business include current volumes being processed in relation to our forecast and historical results, knowledge of the producers’ current and future operations that our systems serve, industry information regarding drilling in the areas where our assets are located, the existence of reserves that are currently economically recoverable and based on forecasted conditions, our ability to utilize the components of our physical assets to generate efficiencies which may include strategic sales of certain components, operating cost savings measures and contract adjustments with producers when warranted, along with our expectation of future pricing and its impact on producers in our operating

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 3

areas. In evaluating these factors we consider both internal and external information such as publicly available information related to producers, rig counts and drilling information, industry publications, media reports, detailed discussions with producers, and internally developed models and reports, among others. We incorporate both negative and positive evidence into our assessment. These factors are consistent with other forward-looking information prepared by the Partnership, such as forward-looking information used for internal budgets, discussions with lenders or third parties, and reporting to management. Therefore, the mix of quantitative and qualitative information that we evaluate includes both current operating data as well as our projections of future results.

One of the factors that we utilize as part of our assessment is the quantitative metric of years-to-recover (the “YTR”). We use the YTR metric as a guide for where our attention should be focused for further evaluation that may identify those asset groups that have a lower level of current and projected future cash flows in relation to the remaining carrying value of the respective asset group. However, the YTR is not the only determining factor as there could be circumstances where (for example) an asset group may have a low YTR but there are other factors present that would warrant further consideration as to whether a triggering event has occurred for purposes of impairment analysis. Though we also look at other metrics, we have found that the YTR provides a reasonable guide for where our attention should be focused for further evaluation using facts and circumstances specific to the applicable asset group. We calculate the YTR metric as the carrying value of the respective asset group divided by that asset group’s EBITDA (as a proxy for cash flows), based on the actual EBITDA as of the date of our review plus the forecast for the remainder of the year. To provide an example for the Staff, for the first quarter we calculate EBITDA for the YTR metric as two months of EBITDA actuals¹ plus ten months of forecasted EBITDA. Specific to our YTR calculation at year end, we compare current year actual results to the forecast for the following year. Asset groups with a recovery period in excess of 25 years are further analyzed to determine if a triggering event occurred to suggest possible risk of impairment. 25 years is the threshold used by the Partnership as the weighted average remaining useful life for its fixed assets is approximately 25 years.

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¹The midstream industry generally operates on a one-month lag with respect to when information is available for the production and processing of natural gas. This lag does not impact our external reporting process, as updated production and processing numbers (“actuals”) are known in advance of our financial statement issuance and reflected therein. However, as of the date of our assessment for triggers suggesting potential impairment of our long-lived assets, the latest information available are actuals from the previous month. Accordingly, our first quarter assessment (the example provided to the Staff) would include actual EBITDA for the months of January and February.

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 4

Regarding the frequency of management’s evaluation of current and forward-looking assumptions within our assessment of potential impairment triggers, management evaluates the effectiveness of cost saving measures and price and volume assumptions, amongst other assumptions as noted above, on a regular basis when evaluating the results of the business in order to prepare these forecasts and other forward-looking information. The frequency will vary based on the volatility that management observes in the market. Therefore, as a result of the volatile commodity environment, management has been evaluating the assumptions in our forecasts with increased frequency.

At the Partnership an asset group is generally a grouping of physical assets (such as gas processing plants) that are interconnected such that production from producers can be strategically routed to each physical structure in the system so as to achieve the highest level of processing efficiency, allow for routine maintenance without stopping production, and provide for scalability in terms of production flow into the system. In other cases the asset system may be a single pipeline, or a storage facility. Accordingly, the idling of one of the plants within the asset group was not considered to be a significant adverse change in the extent or manner in which we are operating the asset group. Additionally, for the Eagle Ford asset group, the YTR did not exceed the 25 year threshold. We also observed that the YTR of the asset group improved during the first quarter of 2017 from the analyses performed in the fourth and third quarters of 2016 (13.5 years as of Q1 2017, 16.8 years as of Q4 2016, and 20.9 years as of Q1 2016) primarily as a result of increasing commodity prices, which offset overall lower sales volumes and decreased throughput. In addition, increased rig count² activity in the region suggests that volumes could increase in future periods. The Eagle Ford asset group was still showing substantially positive EBITDA for the first quarter of 2017 and forecasted future periods following the anticipated cost savings of the idled plant. Volumes previously processed by the idled plant have been directed to other plants within the asset group, thus, creating operating expense savings without decreasing EBITDA, total wellhead volumes or NGL gross production volumes. As a result of the further analysis we performed, we determined that lower sales volumes and decreased throughput are not expected to continue for the long-term and have stabilized. As such, we determined that these factors were not triggering events that would otherwise require an impairment test to be performed.

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²Source: IHS

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 5

18. Business Segments, page 31

Comment: We note that you reevaluated your reportable segments concurrent with the completion of the “Transaction” in the first quarter of 2017. Please tell us what your operating segments are as of March 31, 2017. In this regard, we note you disclose you have aggregated operating segments based on the nature of the products and services provided. Please provide us with your analysis of why such aggregation is appropriate under ASC 280-10-50-11.

Response: In accordance with ASC 280-10-50-1, we identified our operating segments as those components of the Partnership that engage in business activities from which we earn revenues and incur expenses, for which operating results are regularly reviewed by our chief operating decision maker (“CODM”), and for which discrete financial information is available. As a result, we identified a total of five operating segments: four operating segments (North Region, Midcontinent Region, Permian Region, and South Region) have been aggregated into our Gathering and Processing reportable segment and one operating segment encompasses our Logistics and Marketing reportable segment. Per ASC 280-10-50-10(a), reportable segments are the operating segments that have been identified or that result from aggregating two or more of those segments in accordance with ASC 280-10-50-11. We applied the guidance in ASC 280-10-50-11, in which we evaluated the similarities of our operating segments with respect to economic characteristics, nature of products and services, nature of processes, types of customers, methods used to provide services, and regulatory environments. Based on our analysis, as summarized below, we determined that our four Gathering and Processing operating segments are similar under the criteria of ASC 280-10-50-11, and therefore, should be aggregated and disclosed as a single reportable segment.

Gathering and Processing Segment Aggregation

ASC 280-10-50-11 permits operating segments to be aggregated if the following criteria are met:

(1) Aggregation is consistent with the objective and basic principles of ASC 280,

(2) The operating segments have similar economic characteristics, and

(3) The operating segments are similar in all of the following areas:

•The nature of the products or services

•The nature of the production processes

•The type or class of customer for their products or services

•The methods used to distribute their products or provide their services

•If applicable, the nature of the regulatory environment

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 6

Each of the operating segments included in our Gathering and Processing reportable segment provide a mix of the following services related to the production of natural gas, natural gas liquids (“NGLs”) and condensate:

•Gathering

•Compression

•Treating

•Processing

•Fractionating NGLs

The nature of the production processes at each of the processing plants is similar. The gas gathering systems collect raw natural gas and deliver the gas to their respective owned or third-party processing plants to process the natural gas into residue gas, NGLs, and stabilized condensate. The processing plants have the ability to deliver gas into numerous downstream intrastate and interstate transportation pipelines and markets. Therefore the distribution methods are similar.

In addition, each of the Gathering and Processing operating segments has the following similarities:


•	Revenue is earned in a consistent manner through contractual arrangements that are similar in structure (i.e., fee-based arrangements, percent-of-proceeds, and percent-of-liquids).


•	Financial performance is driven by a combination of fees, commodity prices, components of the hydrocarbons gathered, and volume.


•	The assets in use across the North, South, Permian and Midcontinent geographic areas (gathering, processing, compression and treating) are similar and consistent.


•	The regulatory environment is considered “light hand”, and evidenced by the imposition of tariffs on certain pipelines. The regulatory environment does not have a significant impact on the economics of any of the operating segments.


•	The operating and competitive risks associated with the underlying assets and operations are similar: the nature of the products and services are similar; the production, gathering and processing are similar (refrigeration, cryogenic, amine treatment, etc.); the types of customers are the same; and the primary business activities are the same.

The monthly performance review packages, which are reviewed regularly by the CODM, for each of the Gathering and Processing geographic areas (North, South, Midcontinent and Permian) focus on margins (as influenced by price), volumes, and lost profit opportunities. Margin can vary depending on the level of activity in an area, the hydrocarbon profile of

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 7

the gas being processed, contractual terms in the region, commodity prices, and fractionation spread, but generally, the margins are within certain ranges for each of the areas as evidenced on the monthly performance review packages.

Contract types are the same across each of the Gathering and Processing components. Contracts contain one or more of the following arrangements:


•	Percent-of-proceeds / index arrangements / percent-of-liquids where the Partnership purchases natural gas from producers, gathers natural gas through our gathering systems, treats and processes the natural gas and then sells the resulting residue natural gas, NGLs and condensate.


•	Fee-based arrangements where the Partnership receives a fee for gathering, compressing, treating, and processing.

Also, the customer base within Gathering and Processing is the same across the operating segments. Each geographic area serves the same general mix of large natural gas exploration and production companies as well as smaller producers.

Operating segment margin for a given period primarily depends on the volumes generated by the producers, commodity prices of natural gas, NGLs and crude oil, contracts with the producers, and the profile of the hydrocarbons gathered in that operating segment’s region. As noted above, the Gathering and Processing operating segments operate under a variety of contractual arrangements based on customer preference and industry practices. As a result of recent contract restructuring, our contract mixes have changed over time so that more of our operating margin is earned under fee-based arrangements that have less commodity price exposure and that trend is expected to continue into the future. In addition, our focus is achieving certain levels of return, regardless of contract type – fee, percent-of-proceeds or a combination of both. We use commodity hedges when appropriate as a component of our strategy to achieve our return levels by mitigating our exposure to commodity price risk and its impact on returns. The hedging program is based on our total portfolio exposure and not based on an asset, region or operating segment. Based on the analysis of economic similarity and management’s judgment of the specific facts and circumstances surrounding the Gathering and Processing operating segment business, management has determined that the Gathering and Processing operating segments have similar economic characteristics.

Based on the analysis performed, as described above, management determined that our Gathering and Processing operating segments are similar under the criteria of ASC 280-10-50-11, and therefore, may be aggregated and disclosed as a single reportable segment – Gathering and Processing.

***

Jennifer Thompson
Accounting Branch Chief
United States Securities and Exchange Commission
June 27, 2017

Page 8

Please feel free to contact Mr. Michael S. Richards, Vice President and Deputy General Counsel, who can be reached at (303) 633-2912 or Mr. Richard Loving, Vice President and Controller, who can be reached at (303) 605-1684, if you should have any questions regarding the responses contained herein.

Very truly yours,

DCP Midstream, LP

By: DCP Midstream GP, LP

its general partner

By: DCP Midstream GP, LLC

its general partner

By: /s/ Sean P. O’Brien

Name: Sean P. O’Brien

Title: Group Vice President and Chief Financial Officer



cc:	Robert Babula, Staff Accountant, Commission
	Elizabeth Sellars, Staff Accountant, Commission
	Michael S. Richards, DCP Midstream, LP
	Lucy Stark, Holland & Hart LLP