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1.

In your response filed September 8, 2015, you state that while you would prefer to change your presentation of revenues when you file your December 31, 2015 Form 10-K, that you would be able and willing to make this change in your September 30, 2015 Form 10-Q. We believe that absent an inability to make the change, you should comply with Rule 5-03(b)(1) and (b)(2) of Regulation S-X in your next periodic report. However, if the cost of your service revenue is immaterial, we will not object if you indicate this in narrative form in an appropriate place within the footnotes to your financial statements rather than separately quantifying such cost of service revenue on the face of your income statement.

2.	We note your responses filed on August 28 and September 8, 2015, along with the information that you shared with us during the phone call on September 3, 2015. To assist us in better understanding your in-kind gas processing agreements, please provide us with more detailed information about how these contracts are structured and about your accounting, as requested in the following comments.

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3.

In your response to the third bullet point in comment 1 in our letter dated August 24, 2015 you state that the cost of purchased gas presented in your income statements represents the weighted average purchase cost of all consideration paid to producers for commodities purchased and that you believe commodities received as in-kind fees do not have an associated purchase cost because they are a fee for services. You did not address why fuel received in-kind effectively has no purchase cost. Please explain to us why commodities received as in-kind processing fees do not have an associated cost or value. Specifically, please tell us why you do not record service revenues and costs of goods sold (or inventory) based on the fair value of the in-kind commodities received or the associated processing services, whichever is more reliably determinable. Please also explain your accounting for commodities received in-kind for fuel and other expenses. Please refer to ASC 845-10-30.

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4.

We note that there are significant differences between your percent-of-proceeds contracts, your percent-of-liquids contracts, and your keep-whole contracts. We believe we will better understand your accounting for these contracts if you explain in more detail the terms and accounting for each type of contract. For each of the above referenced types of contracts, please separately provide the following information:

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Please provide us with a summary of the significant terms of a typical contract and a description of the economic substance of such contract. If the terms vary and there is not a “typical” contract, please provide the requested information for each major type of contract recognized under each your of percent-of-proceeds, percent-of-liquids and keep whole arrangements. In your response, please clearly distinguish between written terms of the contract and any verbal terms or unwritten customary practices. Your response should clearly delineate what portion of the hydrocarbon stream you have rights to and what portion the producer has rights to, including a discussion of the point in time at which you have rights to any NGLs received as compensation for services provided, the point in time at which you have rights to any purchased NGLs, and the point in time at which you have rights to any dry natural gas remaining after the NGLs have been extracted. Your response should clearly explain to what extent contracts specify the liquids that you will extract, how much control you have in choosing which liquids to extract, and whether you ever elect to extract different liquids than specified in a contract. Your response should also confirm our understanding from the phone call, if true, that you typically purchase from producers both the NGLs resulting from processing and the dry natural gas remaining after the NGLs have been extracted. If you do not typically purchase all of the NGLs and dry natural gas and commonly have situations where you market NGLs and dry natural gas on behalf of a producer, you should separately address contracts where you purchase all of the commodities and contracts where you do not purchase all of the commodities.

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•

Percent of Proceeds (POP): From an accounting perspective, the significant terms of a typical POP contract are the commodities acquired and the purchase price for commodities acquired. Under a typical POP, we acquire all of the unprocessed natural gas received on our system. The purchase price is calculated as illustrated in Exhibit B. In connection with POP contracts, we extract NGLs, market NGLs, and market residue gas for our own account. The price at which we sell NGLs and residue gas does not affect the price we pay our customers.

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Percent of Liquids (POL): From an accounting perspective, the significant terms of a typical POL contract are the commodities acquired, the purchase price for commodities acquired, and the return of the customers commodities to which we do not take title. Under a typical POL contract, we acquire all of the NGLs in the unprocessed natural gas when the gas is received on our system, and we return our customer’s residue gas to them immediately. The purchase price for NGLs is calculated as illustrated in Exhibit B. We extract and market NGLs for our own account under typical POL contracts. The price at which we sell NGLs does not affect the price we pay our customers. We do not purchase or otherwise take title to our customer’s residue gas under typical POL contracts, and our customers are responsible for marketing their residue gas.

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Keep Whole: From an accounting perspective, the significant terms of a typical keep whole contract are the gathering fee charged and the return to the customers of the same quantity of pipeline quality residue gas on an MMBTU basis as was delivered by the customer as unprocessed natural gas. Under a typical keep whole contract, we gather the customer’s natural gas, process the customer’s natural gas, replace the MMBTUs extracted from our customer’s natural gas as NGLs with an equivalent quantity of residue gas as measured in MMBTUs, return the customer’s residue gas to them, and charge the customer a gathering fee. Because the extraction of NGLs during processing reduces the MMBTU content of our customer’s residue gas, we purchase residue gas at market prices to replace the MMBTU content of the NGLs extracted. We take title to the NGLs and we market NGLs extracted from our customers' gas for our own account under keep whole contracts. We do not purchase or otherwise take title to our customer’s residue gas under typical keep whole contracts, and our customers are responsible for marketing their residue gas.

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Based on the above information, please explain to us in more detail how the journal entries contained in your response dated August 28, 2015 reflect the substance of your gas processing contracts. If the terms of your contracts can vary such that you may or may not purchase all NGLs and/or dry natural gas or you may purchase these commodities at different points in time, please explain in detail exactly which scenario is represented by the journal entries previously provided to us and provide us with journal entries illustrating your accounting for all other common scenarios under your contracts. Please ensure that your response to the above bullet point supports your journal entries, including if applicable the lack of revenue recognition related to processing services and the appropriateness of gross or net recognition of revenue from selling both purchased and received-in-kind NGLs and purchased and received-in-kind dry natural gas resulting from these contracts. Although we acknowledge that you provided us with some journal entries in your August 28, 2015 response, we would like you to explain in more detail why these

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Percent of Proceeds (POP): The illustrative POP journal entries reflect the substance of our typical POP contract. As described above, we acquire all of the unprocessed natural gas received on our system under our typical POP contract. Cost of goods sold-natural gas and natural gas liquids represents the cash purchase of the unprocessed natural gas. The settlement due the producer for residue gas of $378 is calculated by multiplying the 100 MMBTU of residue gas by the natural gas index price of $3.98/MMBTU times the percent of proceeds percentage of 95%. Cost of goods sold—NGLs represents the cash purchase of 75 gallons (15 MMBTU) of NGLs. The settlement due the producer for NGLs

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Percent of Liquids (POL): The illustrative POL journal entries in Exhibit C reflect the substance of a POL contract under which we acquire all of the unprocessed natural gas received. Cost of goods sold—natural gas represents the cash purchase of the residue gas. The settlement due the producer for residue gas of $398 is calculated by multiplying the 100 MMBTU of residue gas by the natural gas index price of $3.98/MMBTU. Cost of goods sold—NGLs represents the cash purchase of 75 gallons (15 MMBTU) of NGLs. The settlement due the producer for NGLs of $100 is calculated by multiplying the 75 gallons of NGLs by the NGL index price of $1.48/gallon times the percent of proceeds liquids percentage of 90%.

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Keep Whole: The illustrative keep whole journal entries in Exhibit C reflect the substance of a keep whole contract under which we purchase all of the unprocessed gas from the customer. Cost of goods sold—natural gas represents the cash purchase of the 115 MMBTU of gas. The settlement due the producer for gas of $458 is calculated by multiplying the 115 MMBTU of gas by the natural gas index price of $3.98/MMBTU. No settlement is due for NGLs under a keep whole contract because everything is settled on an equivalent basis as gas. Revenues—natural gas represents our sale of the 100 MMBTU of residue gas at a sales price of $4.00/MMBTU. Revenues—NGLs represents our sale of the 75 gallons (15 MMBTU) of NGLs at a sales price of $1.50 per gallon.

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Fixed Fee: The illustrative fixed fee journal entries in Exhibit C and Exhibit D reflect the substance of our typical fixed fee contract. Under our typical fixed fee contract, we purchase the NGLs extracted and return the residue gas to the customer. Cost of goods sold—NGLs represents the cash purchase of 75 gallons (15 MMBTU) of NGLs. The settlement due the producer for NGLs of $111 is calculated by multiplying the 75 gallons of NGLs by the NGL index price of $1.48/gallon.

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•	First, we measure the quantity of unprocessed natural gas and determine its composition when it is received on our system. (See (A) in the example purchase price calculation below.)

•	Second, we deduct a contractually agreed quantity of fuel from the quantity of unprocessed natural gas, resulting in a net quantity of unprocessed gas. (See (B) in the example purchase price calculation below.)

•	Third, we determine the total quantity of NGLs and residue gas contained in the net quantity of unprocessed gas based on the composition of the unprocessed natural gas when it is received on our system. (See (C) in the example purchase price calculation below.)

•	Fourth, we determine the recoverable quantity of NGLs and residue gas by applying a contractually agreed percentage of NGL components. (See (D) in the example purchase price calculation below.)

•	Fifth, we determine the quantity of recoverable NGLs attributable to the customer by applying a contractually agreed percent of proceeds percentage. (See (E) in the example purchase price calculation below.)

•	Sixth, we determine the MMBTU equivalent of NGL gallons removed from the net quantity of unprocessed gas to calculate residue gas. (See (F) in the example purchase price calculation.)

•	Seventh, the quantity of recoverable NGLs attributable to the customer is multiplied by the NGL index price specified in the contract, and the quantity of residue gas attributable to the producer is multiplied by the natural gas index price specified in the contract. (See (G) in the example purchase price calculation below.)

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•	First, we measure the quantity of unprocessed natural gas and determine its composition when it is received on our system. (See (A) in the example purchase price calculation below.)

•	Second, we deduct a contractually agreed quantity of fuel from the quantity of unprocessed natural gas, resulting in a net quantity of unprocessed gas. (See (B) in the example purchase price calculation below.)

•	Third, we determine the total quantity of NGLs and residue gas contained in the net quantity of unprocessed gas based on the composition of the unprocessed natural gas when it is received on our system. (See (C) in the example purchase price calculation below.)

•	Fourth, we determine the recoverable quantity of NGLs by applying a contractually agreed percentage of NGL components. (See (D) in the example purchase price calculation below.)

•	Fifth, we determine the quantity of recoverable NGLs attributable to the customer by applying a contractually agreed percent of liquids percentage. (See (E) in the example purchase price calculation below.)

•	Sixth, we determine the MMBTU equivalent of NGL gallons removed from the net quantity of unprocessed gas to calculate residue gas. (See (F) in the example purchase price calculation.)

•	Seventh, the quantity of recoverable NGLs attributable to the customer is multiplied by the NGL index price specified in the contract. (See (G) in the example purchase price calculation below.)

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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 customers 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. See Exhibit E for an analysis under the criteria specified in FASB ASC Topic 605-45-45.

4.	For financial reporting purposes, Revenues—natural gas and Revenues—NGLs are presented within the single financial statement revenue caption Product Sales. Cost of goods—natural gas and Cost of goods—NGLs are presented within the single financial statement caption Cost of natural gas and natural gas liquids.

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

a.	115 MMBTU measured (100 MMBTU of natural gas, 15 MMBTU of NGLs)

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.	Processing Fees Fixed Fees: $0.20/MMBTU

b.	Gathering Fees Keep Whole: $0.40/MMBTU

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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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 customers 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. See Exhibit E for an analysis under the criteria specified in FASB ASC Topic 605-45-45.

4.	For financial reporting purposes, Revenues—natural gas and Revenues—NGLs are presented within the single financial statement revenue caption Product Sales. Cost of goods—natural gas and Cost of goods—NGLs are presented within the single financial statement caption Cost of natural gas and natural gas liquids.

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

a.	115 MMBTU measured (100 MMBTU of natural gas, 15 MMBTU of NGLs)

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.	Processing Fees Fixed Fees: $0.20/MMBTU

b.	Gathering Fees Keep Whole: $0.40/MMBTU

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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•	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 customers for commodities that we purchase are established in our agreements with the customers, 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;

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•	We have credit risk for the amount for which the commodities are sold, because we typically must pay customers 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;

•	Our customers are not obligors under the arrangements to sell the commodities because, as noted above, we contract directly with the purchaser; and

•	Our customers do not have credit risk under the arrangements to sell the commodities because, as noted above, we typically must pay customers for commodities purchased regardless of whether we collect the amount for which the commodities are sold.