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We believe that our investors and other interested parties focus on our total revenue, net income, earnings before interest, depreciation and amortization and distributable cash flow when analyzing the results of our operations, none of which would change as a result of revenue disaggregation. To date, neither our investors nor any other interested parties have requested this type of revenue information, suggesting that it is not material to their analysis of the results of our operations.

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We do not believe that revenue disaggregation would provide investors and other interested parties with material additional information that is not otherwise captured in the form of our existing disclosures. Our presentation of revenue and cost of goods sold (in our Consolidated Statements of Income) and our discussion of our contract mix by segment (in our Management’s Discussion and Analysis) provides investors and other interested parties the ability to calculate revenue from sales of commodities as follows:

•	We note that there continues to be diversity among midstream registrants in the reporting of revenue from the sale of commodities associated with midstream services as revenue from services and from the sale of products.

•	We believe that changing our presentation on a prospective basis beginning with our Form 10-K for Fiscal Year Ending December 31, 2015 will both allow for consistency

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1.

We note your response to comment 3. In your response you indicate that your revenues from the sale of natural gas, natural gas liquids (NGLs) and condensate represents approximately 68.6% and 63.5% of total revenues for fiscal years 2014 and 2013, respectively, but that you believe your revenues from the sale of commodities is integral to your provision of services and that separate disclosure of revenue from the sales of commodities (products) could be misleading to your investors. To assist us in better understanding and evaluating your response, please provide us with the following additional information:

•	For each type of natural gas processing agreement you enter into, such as percent of proceeds, percent of liquids and keep whole agreements, please tell us whether you record revenues gross as a principal or net as an agent and provide us with your analysis of the relevant accounting literature to explain why.

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•	We are the primary obligor under the arrangements to sell the commodities because we contract directly with the purchaser, rather than contracting on behalf of the producer;

•	We have general inventory risk before the commodities are sold because we take title to the commodities before they are sold;

•	We have latitude in establishing the price at which the commodities are sold, and we bear the price risk for the sale of the commodities, because the amounts that we pay producers for commodities that we purchase are established in our agreements with the producers, rather than being contingent upon the arrangements under which we sell the commodities;

•	We change the commodities by processing the natural gas, which is required for the commodities to be sold;

•	We have discretion in selecting to whom and at what market location the commodities are sold;

•	We determine the specifications of the commodities produced by selecting the location and method of processing, including the election to either recover ethane as an NGL or reject ethane as natural gas;

•	We have physical loss inventory risk of the commodities retained and purchased during and after processing;

•	We have credit risk for the amount for which the commodities are sold, because we typically must provide producers with processing services for in-kind fees and pay producers for commodities purchased regardless of whether we collect the amount for which the commodities are sold;

•	The amount we earn for the sale of commodities is not fixed, but is dependent upon the sales prices that we negotiate;

•	The producers from whom we receive in-kind fees and purchase commodities are not obligors under the arrangements to sell the commodities because, as noted above, we contract directly with the purchaser; and

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•	The producers from whom we receive in-kind fees and purchase commodities do not have credit risk under the arrangements to sell the commodities because, as noted above, we typically must provide producers with processing services for in-kind fees and pay producers for commodities purchased regardless of whether we collect the amount for which the commodities are sold.

•	Please clarify for each of the above types of processing agreements whether you purchase, take title to or otherwise have risk of ownership for the hydrocarbons you process. If so, please tell us how you considered whether the revenue associated with those processing agreements may represent the sale of tangible products rather than services.

•	Please explain in more detail your statement that costs of goods sold does not include the purchase cost of natural gas and NGLs received as in-kind

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1.	As measurement data and posted pricing is collected on a production month basis, all margin entries are recorded in the monthly close process.

2.	Due to our limited NGL storage capacity, NGL inventories are typically less than $2 million at any given time.

3.	For natural gas and NGLs that producers take in-kind, in accordance FASB ASC Topic 605-45-45, we do not record revenues or costs of goods sold, as we do not take title to, purchase or sell these volumes.

1.	4 contracts with equal volumes and compositions as follows:

a.	115 mmbtu measured (100 mmbtu of natural gas, 15 mmbtu of NGL's)

b.	75 gallons of NGLs produced

2.	Commodity Prices:

a.	$4.00/mmbtu natural gas sales price, assumes $0.02 margin

b.	$1.50/gallon NGL sales price, assumes $0.02 margin

3.	Month end inventory:

a.	2 gallons at $1.15/gallon

b.	Assumed operating costs $0.10/gallon

c.	Weighted average purchase costs $1.05/gallon

4.	Processing fees:

a.	Fixed Fees: $0.20 per mmbtu

b.	Percent of Liquids: 10% of NGLs retained

c.	Percent of Proceeds: 5% of natural gas and NGLs retained

5.	NGL value in excess of dry gas value retained

6.	No gas imbalances or beginning of month NGL inventories assumed

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•	Lastly, please tell us how you are accounting for the condensate removed from your pipelines as a byproduct. Please explain in reasonable detail why you believe condensate may not have an associated purchase cost depending on the form in which it enters the pipelines. Also tell us what percentage of your revenue is derived from the sale of retained condensate.

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