ENABLE MIDSTREAM PARTNERS, LP
One Leadership Square
211 North Robinson Avenue, Suite 150
Oklahoma City, Oklahoma 73102
October 14, 2016
Via EDGAR and FedEx
Securities and Exchange Commission
Division of Corporation Finance
100 F Street NE
Washington, DC 20549-3561
Attn: Jennifer Thompson
Accounting Branch Chief
Office of Consumer Products
Re: Enable Midstream Partners, LP
Form 10-K for Fiscal Year Ended December 31, 2015
Filed February 17, 2016
Form 10-Q for Fiscal Quarter Ended June 30, 2016
Filed August 3, 2016
File No. 001-36413
Ladies and Gentlemen:
Set forth below are the responses of Enable Midstream Partners, LP, a Delaware limited partnership (“we” or the “Partnership”), 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 September 23, 2016 with respect to the Partnership’s Form 10-K for the fiscal year ended December 31, 2015 filed with the Commission on February 17, 2016 (the “Form 10-K”) and Form 10-Q for fiscal quarter ended June 30, 2016 filed with the Commission on August 3, 2016 (the “Form 10-Q”), File No. 001-36413. For your convenience, each response is prefaced by the text of the Staff’s corresponding comment in bold text.
Form 10-K For Fiscal Year Ended December 31, 2015
Management’s Discussion and Analysis of Financial Condition and Results of Operations
General Trends and Outlook, page 63
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1. | We note you have no allowance for doubtful accounts receivable at December 31, 2015. Please tell us how you monitor the credit quality of your producer customers and how you considered whether the collectability of your accounts receivable has been impacted by the decline in commodity prices. |
Response: In accordance with our risk policy, we monitor the credit quality of our producer customers on an ongoing basis to identify issues that may impact their ability to meet their obligations to us. This monitoring includes the following components:
• | Initial Credit Assessment. Prior to doing business with any producer, our credit risk team assesses that producer’s credit quality by reviewing relevant information, which may include credit ratings from ratings agencies, financial statements, payment history, bank references, trade references and public reports filed with the Commission. |
• | Ongoing Credit Monitoring. Our credit risk team monitors the payment history, accounts receivable aging and credit limits of our producer customers and reviews other relevant information regarding our producer customers, including ratings agency alerts and news releases. At least quarterly, members of our credit risk, accounting and commercial management teams meet to evaluate the accounts receivable of our producer customers. At least annually, we review and update our assessment of each producer customer’s credit quality. |
• | Credit Assurance. If, through the initial credit assessment or ongoing credit monitoring procedures described above, we determine that a producer customer poses a significant credit risk, we may request adequate assurance from that customer, which can take the form of a guaranty, a letter of credit, prepayment, cash collateral, or other arrangements. These types of adequate assurance serve as credit enhancements to a producer customers’ credit quality, and, when present, reduce the need for an allowance with respect to those accounts. |
Using this information, management applies its judgment to determine whether an allowance for doubtful accounts should be recognized in accordance with ASC 450-20.
The collectability of our accounts receivable has not been materially impacted by the decline in commodity prices. At December 31, 2015, we had $266 million of accounts receivable (including accounts receivable-affiliated companies), for which less than $1 million was reserved as an allowance for doubtful accounts, which rounded to zero for purposes of financial reporting. As of June 30, 2016, we had collected all but $3.8 million of the $266 million outstanding at December 31, 2015, of which less than $1 million was reserved as an allowance for doubtful accounts, which rounded to zero for purposes of financial reporting, and of which none was attributable to trade receivables. For each of the fiscal years ended December 31, 2013, 2014, and 2015, we had reserved as an allowance for doubtful accounts less than $1 million. For the six month period ended June 30, 2016, we reserved as an allowance for doubtful accounts an additional $1.4 million, none of which was related to our producer customers. We
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have not seen a material increase in the aging of our accounts receivable or a material increase in bad debt expense.
In light of your comment, we will revise the disclosure in our Notes to Financial Statements beginning with our Form 10-Q for the Fiscal Quarter Ended September 30, 2016 to provide additional information about how we monitor the credit quality of our customers by including the following:
Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to historical bad debt write-offs, the aging of receivables and specific customer circumstances that may impact their ability to pay the amounts due. Based on this review, management determined that a $[∙] allowance for doubtful accounts was required as of September 30, 2016, and no allowance for doubtful accounts was required as of December 31, 2015.
2. | We note that you have gathering and processing contracts with minimum volume commitments. Please confirm our assumption, if true, that you have neither renegotiated the fees or minimum volume commitments on any contracts prior to their expiration nor are currently in the process of renegotiating any contracts prior to their expiration. If our assumption is incorrect, please tell us in detail how you considered the impact of these renegotiated contracts when explaining trends and uncertainties in your results of operations. Please also tell us, and consider disclosing in future filings, the volume amount of gathering and processing contracts that expire within one year and your expectations regarding the trend of gathering and processing fees. |
Response: With respect to our gathering and processing contracts with minimum volume commitments, as of the date of this letter, we have neither renegotiated the fees nor the minimum volume commitments on any such contracts prior to their expiration nor are we in the process of renegotiating any contracts prior to their expiration. With respect to our gathering and processing contracts without minimum volume commitments, as of the date of this letter, we are in the process of renegotiating one processing arrangement prior to its expiration to be fee-based rather than percent-of-proceeds, which we believe will be on terms no less favorable to us than the current contract. Our renegotiation of this processing arrangement is consistent with our disclosure in General Trends and Outlook on page 63 of the Form 10-K that we attempt to
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mitigate the impact of commodity prices on our business by converting existing commodity-based contracts to fee-based contracts.
For the six and twelve month periods ended June 30, 2016 and December 31, 2015, none of our gathered volumes were under contracts with minimum volume commitments that expire within one year. For the six month period ended June 30, 2016, 9% of our gathered volumes were under contracts without minimum volume commitments with primary terms that expire within one year and 11% percent of our gathered volumes were under contracts without minimum volume commitments in evergreen status. For the twelve month period ended December 31, 2015, 8% of our gathered volumes were under contracts without minimum volume commitments with primary terms that expire within one year and 12% percent of our gathered volumes were under contracts without minimum volume commitments with terms in evergreen status. Evergreen provisions automatically renew the length of a contract after the primary term unless and until notice of termination is given. Our gathering and processing contracts generally contain evergreen provisions. While we may have contracts that in aggregate represent significant gathered volumes expiring within any given year, our experience is that most of our contracts are renewed, either through renegotiation or by moving into evergreen status.
For the six month period ended June 30, 2016, our top ten customers by volume accounted for 65% of our gathered volumes under contracts with a weighted average contract life of 8.0 years. For the twelve month period ended December 31, 2015, our top ten customers by volume accounted for 65% of our gathered volumes under contracts with a weighted average contract life of 8.7 years. For the six month period ended June 30, 2016, 31 customers accounted for the 9% of our gathered volumes under contracts with primary terms that expire within one year, and 166 customers accounted for the 11% of our gathered volumes under contracts with primary terms in evergreen status. For the twelve month period ended December 31, 2015, 30 customers accounted for the 8% of our gathered volumes under contracts with primary terms that expire within one year, and 175 customers accounted for the 12% of our gathered volumes under contracts with primary terms in evergreen status. Because of the large number of customers that account for the gathered volumes under contracts that expire within one year or are under evergreen status, and because of our experience that our contracts are typically renewed, we believe that disclosure of the aggregate percentage of our gathered volumes that are under contracts that expire within one year or are under evergreen status would overstate the significance of these contracts and the risk to gathering and processing revenues.
We have generally experienced stability in the gathering and processing fees in connection with the negotiation of both contract renewals and new contracts. As we have disclosed in Risks Related to Our Business on page 28 of the Form 10-K, gathering and processing fees depend on the prevailing market at the time of renewal, and to the extent we are unable to renew our existing contracts on terms that are favorable to us, our revenue, results of operations, and distributable cash flow could be adversely affected. Nevertheless, we have not experienced a trend, change or uncertainty in gathering and processing fees that would cause our reported financial information not to be necessarily indicative of future operating results or of future
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financial condition or that we would reasonably expect to have a material favorable or unfavorable impact on net sales or revenues or income from continuing operations.
With respect to both volume weighted average contract life for gathered volumes and gathering and processing fee trends, we believe that our existing approach provides the appropriate level of disclosure. However if, in either case, we later experience a trend, change or uncertainty that would cause our reported financial information not to be necessarily indicative of future operating results or that we would reasonably expect to have a material impact on our financial condition or the results of our operations, we will revise our disclosures accordingly.
3. | We note that several oil and gas producers with operations in Texas and Oklahoma have recently declared bankruptcy. Please tell us in detail how your determined there was no potential additional impairment of your Texas and Oklahoma operations’ long-lived assets or intangible assets related to financial difficulties, if any, of your oil and gas producer customers. |
Response: Consistent with ASC 360-10-35, our quarterly evaluation of potential impairment indicators includes customer-specific issues, such as bankruptcies and other financial difficulties. As of December 31, 2015, we did not identify producer customer bankruptcies as a potential indicator of impairment because no bankruptcies of our significant producer customers had occurred or were anticipated. However, as indicated in Fair Value Measurements on page 116 of the Form 10-K, we identified the decreases in crude oil and natural gas prices during 2015 as potential indicators of impairment. As a result, we performed step one of ASC 360-10-35 on all of our gathering and processing asset groups, inclusive of intangible assets, and step two of ASC 360-10-35 on two of our gathering and processing groups. As disclosed in the Form 10-K, we recognized impairments on those two asset groups.
For the twelve month period ended December 31, 2015, only two of our producer customers who together accounted for less than 0.5% of our gathered volumes had declared bankruptcy. For the six month period ended June 30, 2016, an additional eight of our producer customers who together accounted for less than 2% of our gathered volumes had declared bankruptcy. Of our overdue accounts receivable for our producer customers who had declared bankruptcy through June 30, 2016, $165,000 remained outstanding as of June 30, 2016. All of our producer customers who have declared bankruptcy have filed for reorganization under Chapter 11 of the Bankruptcy Code rather than for liquidation under Chapter 7 of the Bankruptcy Code. As of the date of this letter, three of our producer customers who declared bankruptcy have emerged from Chapter 11, and none of our contracts with our producer customers who have declared bankruptcy have been rejected in bankruptcy to date. We have not experienced a material change in our financial condition or in the results of our operations as a result of bankruptcies or the credit quality of our producer customers, and we have not experienced a trend with the bankruptcies and credit quality of our producer customers that we would reasonably expect to have a material impact on our financial condition or the results of our operations.
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Non-GAAP Financial Measures, page 70
4. | We note your disclosure that Gross margin allows you to make a meaningful comparison of the operating results between your fee-based revenues, and your commodity-based contracts which involve the purchase or sale of natural gas, NGLs, and/or crude oil, and it also allows you to make a meaningful comparison of the results of your commodity-based activities across different commodity price environments because it measures the spread between the product sales price and cost of products sold. However, we note that your Gross margin measure represents your total revenues from both product sales and service revenues less the cost of natural gas and natural gas liquids. Please explain to us in more detail why subtracting certain costs of selling your products from your aggregate revenue including both product sales and service revenue achieves your stated objectives. Given your recent disaggregation of product sales from service revenue, also tell us how you considered revising this non-GAAP measure to present product sales less the cost of natural gas and natural gas liquids in order to capture the spread between product sales price and cost of products sold. |
Response: Gross margin is a non-GAAP measure which we define as total revenues minus costs of natural gas and natural gas liquids, excluding depreciation and amortization. Total revenues consist of the fees that we charge our customers and the sales price of natural gas and natural liquids that we sell. The cost of natural gas and natural gas liquids consists of the purchase price of natural gas and natural gas liquids that we purchase.
We view gross margin as a performance measure of the core profitability of our mix of fee-based and commodity-based customer arrangements. Our arrangements with a customer may consist of fee only arrangements, commodity only arrangements or a combination of both fee and commodity arrangements. This non-GAAP measure is a key component of our internal management reporting and is used by our management to evaluate our customer arrangements in aggregate. We believe that investors and other interested parties benefit from having access to the same financial measures that our management uses to evaluate our customer arrangements.
We generate gross margin under fee-based arrangements by receiving fees from our customers for gathering, processing, transportation and storage services. In connection with commodity-based arrangements, we purchase natural gas and natural gas liquids from our customers and sell natural gas and natural gas liquids to counterparties that include marketers, utilities, and industrial users, and thereby generate gross margin based upon the difference between the sales price and the purchase price for natural gas and natural gas liquids.
The fees that we receive under fee-based arrangements reflect the core profitability of those arrangements. However, to reflect the core profitability of our commodity-based arrangements, we must deduct the purchase price of natural gas and natural gas liquids that we purchase from the sales price of natural gas and natural gas liquids that we sell. By subtracting the costs of natural gas and natural gas liquids from total revenues, gross margin allows us to measure the
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aggregate core profitability of our mix of fee-based and commodity-based customer arrangements.
We said in the Form 10-K that gross margin allows us to make a meaningful comparison of operating results between our fee-based arrangements and our commodity-based arrangements. We intended to convey that this non-GAAP measure allows us to evaluate the core profitability of our mix of fee-based and commodity-based customer arrangements. We believe that it is important to evaluate the results of our fee-based and commodity-based customer arrangements together because, as noted above, our arrangements with a customer may consist of fee only arrangements, commodity only arrangements or a combination of both fee and commodity arrangements.
We also said in the Form 10-K that gross margin allows us to make a meaningful comparison of the result of our commodity-based activities across different commodity price environments because it measures the spread between the product sales price and the cost of products sold. As noted above, by subtracting the costs of natural gas and natural gas liquids from total revenues, gross margin includes the spread between the sales price of natural gas and natural gas liquids that we sell and the purchase price of natural gas and natural gas liquids that we purchase. By comparing changes in gross margin over time, we can analyze the impact of different commodity price environments on the core profitability of our mix of fee-based and commodity-based customer arrangements.
In light of your comments, we believe that it would be beneficial to our investors and other interested parties to modify our disclosure on the use of gross margin as a non-GAAP measure beginning with our Form 10-Q for the Fiscal Quarter Ended September 30, 2016 as follows:
We define gross margin as total revenues minus costs of natural gas and natural gas liquids, excluding depreciation and amortization. Total revenues consist of the fees that we charge our customers and the sales price of natural gas and natural liquids that we sell. The cost of natural gas and natural gas liquids consists of the purchase price of natural gas and natural gas liquids that we purchase. We deduct the cost of natural gas and natural gas liquids from total revenue to arrive at a measure of the core profitability of our mix of fee-based and commodity-based customer arrangements. We use gross margin as a performance measure to analyze the aggregate core profitability of our customer arrangements. Please read “-Results of Operations” and “-Non-GAAP Financial Measures” below.
When we recently revised the presentation of our income statements to disaggregate product sales from service revenue as contemplated by Rule 5-03.2 of Regulation S-X, we did not make a similar revision to the non-GAAP measure gross margin. As noted above, because our arrangements with customers may consist of fee only arrangements, commodity only arrangements or a combination of both fee and commodity arrangements, we believe that it is important to evaluate the core profitability of our customer arrangements in aggregate. We also
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believe that investors and other interested parties benefit from having access to the same financial measures that our management uses to evaluate our business. However, in light of your comment, we will present our reconciliation of gross margin to total revenues to disaggregate total revenues between product sales and service revenue beginning with our Form 10-Q for the Fiscal Quarter Ended September 30, 2016 so that all of the components are specifically identified for investors and other interested parties. Our presentation will appear as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||||||
(In millions) | |||||||||||||||
Reconciliation of Gross Margin to Total Revenues: | |||||||||||||||
Consolidated | |||||||||||||||
Product Sales | $ | — | $ | — | $ | — | $ | — | |||||||
Service revenue | — | — | — | — | |||||||||||
Total revenues | — | — | — | — | |||||||||||
Cost of natural gas and natural gas liquids (excluding depreciation and amortization) | — | — | — | — | |||||||||||
Gross margin | $ | — | $ | — | $ | — | $ | — | |||||||
Financial Statements
(17) Equity Based Compensation, page 125
5. | Based on your disclosures, it appears that your Performance units and Phantom units are entitled to receive distributions and that payment of such distributions is accumulated and paid at vesting of the respective units. You also disclose that distributions are paid as declared on your Restricted units and such distributions are not subject to forfeiture after payment. Please clarify what you mean by your disclosure that for your Performance units and Phantom units distributions are not included in the fair value calculation while distributions for your Restricted units are included in the fair value calculation. We note that for awards for which employees are not entitled to dividends declared on the underlying shares the grant date fair value of the award would be measured using the grant-date fair value of your common shares reduced by the present value of the dividends expected to be paid on the underlying shares during the requisite service period. Conversely, for awards where dividends are either paid or accumulated prior to vesting, such dividends are accounted for under the guidance in ASC 718-10-55-44 through 55-45. Please explain your disclosure and your accounting for distributions on your non-vested Performance, Phantom and Restricted unit awards. |
Response: We confirm your understanding that our performance units, phantom units, and restricted units are entitled to receive distributions and the timing of the payment of such distributions. We also acknowledge that distributions on restricted units, performance units, and phantom units either paid or accumulated prior to vesting should be accounted for under the guidance in ASC 718-10-55-44 through 55-45, which provides that distributions paid or
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accumulated prior to vesting should be included in the fair value calculation of such unit grants. We included the distributions paid prior to vesting on the restricted units granted in 2015 and 2014 and the distributions accumulated prior to vesting on the performance units and phantom units granted in 2015 in the fair value calculation. However, with respect to the performance units and phantom units granted in 2014, we excluded the distributions accumulated prior to vesting from the fair value calculation. The exclusion of distributions accumulated prior to vesting from the fair value calculation of performance units and phantom units granted in 2014 understated the fair value of performance units by $3.49 per unit, resulting in a total accumulated unrecognized compensation expense, as of December 31, 2015, of $572,000 during the requisite service period, which is not material quantitatively or qualitatively to our financial statements or disclosures. In light of your comment, we will modify our Equity Based Compensation disclosures beginning with our Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2016 to state, consistent with the guidance in ASC 718-10-55-44 through 55-45, that distributions paid or accumulated prior to vesting are included in the fair value calculation of performance units and phantom units.
Form 10-Q for Fiscal Quarter June 30, 2016
Financial Statements
(4) Partners’ Equity, page 12
6. | We note that your Series A Preferred Units are required to be redeemed in certain circumstances if they are not eligible for trading on the New York Stock Exchange. We also note your Third Amended and Restated Agreement of Limited Partnership of Enable Midstream Partners, LP, dated as of February 18, 2016 appears to limit such circumstances to listing requirements of the New York Stock Exchange reasonably within the control of the Partnership. Please explain to us in detail whether listing requirements reasonably within control of the Partnership is defined, or if not, how you and holders of Series A Preferred Units would determine which listing requirements were deemed to be reasonably within your control. Please explain to us your understanding of which listing requirements would be deemed reasonably within your control and which listing requirements would be deemed outside your control to support your conclusion that these Series A Preferred Units should be classified within equity. |
Response: As discussed below, our Series A Preferred Units are required to be redeemed (a “Redemption Upon an NYSE Event”) in circumstances where an eligible holder of Series A Preferred Units exercises a demand right under the Registration Rights Agreement applicable to the Series A Preferred Units (the “Registration Rights Agreement”), an amendment to our Partnership Agreement, or to another agreement of the Partnership in lieu thereof, is required for the Series A Preferred Units to meet the listing requirements of the New York Stock Exchange (the “NYSE”), and a Management Member of our General Partner (a “Management Member”) who does not hold Series A Preferred Units refuses to consent to such amendment.
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A Redemption Upon an NYSE Event may exist when the exercise of a demand right is made at a time when the Series A Preferred Units would meet the holding, distribution and other requirements of the NYSE not within the reasonable control of the Partnership. The Partnership Agreement does not define which listing requirements of the NYSE are reasonably within the control of the Partnership; however, the definition of “NYSE Event” in the Partnership Agreement does provide the NYSE’s holding and public distribution requirements as examples of listing requirements that are outside the reasonable control of the Partnership. These listing requirements are outside the reasonable control of the Partnership because they cannot be satisfied by the unilateral action of the Partnership. In contrast, we believe that preparing a listing application, obtaining a CUSIP, paying the listing fee, and obtaining the necessary approvals from the Board of Directors of our General Partner and Management Members are examples of NYSE listing requirements that are within the reasonable control of the Partnership because they can be satisfied by the unilateral action of the Partnership. We and holders of Series A Preferred Units would determine which listing requirements are reasonably within the Partnership’s control by determining whether they can be satisfied by the unilateral action of the Partnership. Currently, an affiliate of CenterPoint Energy, Inc. is the only holder of our Series A Preferred Units and would likely seek listing of such units in connection with a potential sale thereof.
Whether a listing requirement is within the reasonable control of the Partnership impacts the determination of whether the Series A Preferred Units are a “mandatorily redeemable financial instrument.” ASC 480-10-20 defines a mandatorily redeemable financial instrument as:
Any of various financial instruments issued in the form of shares that embody an unconditional obligation requiring the issuer to redeem the instrument by transferring its assets at a specified or determinable date (or dates) or upon an event that is certain to occur.
ASC 480-10-25-4 provides that:
A mandatorily redeemable financial instrument shall be classified as a liability unless the redemption is required to occur only upon the liquidation or termination of the reporting entity.
ASC 480-10-25-7 goes on to provide, in pertinent part, that:
If a financial instrument will only be redeemed upon the occurrence of a conditional event, the redemption of that instrument is conditional and, therefore, the instrument does not meet the definition of mandatorily redeemable financial instrument.
In evaluating whether the Series A Preferred Units are a mandatorily redeemable financial instrument, we considered whether a Redemption Upon an NYSE Event is a mandatory
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redemption or a conditional redemption. We concluded that a Redemption Upon an NYSE Event is a conditional redemption because it is subject to circumstances that may not occur.
First, a Redemption Upon an NYSE Event may occur only when the Series A Preferred Units meet the NYSE listing requirements that are outside the reasonable control of the Partnership at the time an eligible holder of Series A Preferred Units exercises a demand right under the Registration Rights Agreement. Under the Registration Rights Agreement, an eligible holder of Series A Preferred Units has a demand right for all or any portion of such holder’s Series A Preferred Units. If, for example, an eligible holder demands the registration of a quantity of Series A Preferred Units that are insufficient to meet the NYSE’s public distribution requirements, then the Series A Preferred Units will be unable to meet an NYSE listing requirement that is outside of the Partnership’s reasonable control, a circumstance necessary for a Redemption Upon an NYSE Event would not exist.
Second, a Redemption Upon an NYSE Event may occur only when an amendment to the Partnership Agreement, or to another agreement of the Partnership in lieu thereof, is required to meet NYSE listing requirements (an “Amendment”). We are not aware of any current or pending NYSE listing requirement that would require an Amendment. Unless the NYSE changes its listing requirements, a circumstance necessary for a Redemption Upon an NYSE Event would not exist.
Third, a Redemption Upon an NYSE Event occurs only when a Management Member who does not hold Series A Preferred Units refuses to consent to an Amendment. Therefore, a holder of Series A Preferred Units cannot unilaterally trigger a Redemption Upon an NYSE Event. Whether a Management Member who does not hold Series A Preferred Units would refuse to consent to an Amendment can only be determined at the time that such consent is sought, and a Redemption Upon an NYSE Event can only be triggered by this refusal.
As required by ASC 480-10-25-7, we assess each quarter whether circumstances have changed such that Series A Preferred Units would meet the definition of a mandatorily redeemable instrument (that is, the events required for a Redemption Upon an NYSE Event are no longer contingent), at which time the Series A Preferred Units would be reclassified as a liability.
Whether a listing requirement is within the reasonable control of the Partnership impacts the determination of whether the Series A Preferred Units are “redeemable preferred stock.” ASC 480-10-S99-1.02 defines redeemable preferred stock as:
[A]ny stock which (i) the issuer undertakes to redeem at a fixed or determinable price on the fixed or determinable date or dates, whether by operation of a sinking fund or otherwise; (ii) is redeemable at the option of the holders, or (iii) has conditions for redemption which are not solely within the control of the issuer, such as stock which must be redeemed out of future earnings.
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ASC 480-10-S99-1.02 goes on to define “non-redeemable preferred stock” as:
[A]ny preferred stock which does not meet the criteria for classification as a “redeemable preferred stock.”
In evaluating whether the Series A Preferred Units are redeemable preferred stock or non-redeemable preferred stock, we considered whether a Redemption Upon an NYSE Event meets any of the criteria for redeemable preferred stock. First, we considered whether a Redemption Under an NYSE Event requires a redemption at a fixed or determinable price on the fixed or determinable date or dates. If Redemption Upon an NYSE Event occurs, each Series A Preferred Unit is redeemable for a price of $25.50 plus an amount equal to all unpaid distributions thereon to be paid on a date determined by the redeeming party. Although a Redemption Upon an NYSE Event requires a redemption at a determinable price, it does not require payment on a fixed or determinable date.
Second, we considered whether the Series A Preferred Units are redeemable at the option of the holders under a Redemption Upon an NYSE Event. As previously noted, a Redemption Under an NYSE Event can only occur if a Management Member who does not hold Series A Preferred Units refuses to consent to an Amendment. Based on this requirement, the Series A Preferred Units are not redeemable at the option of the holders.
Third, we considered whether a Redemption Upon an NYSE Event has conditions for redemption which are not solely within the control of the Partnership. A Redemption Upon an NYSE Event occurs only when a Management Member who does not hold Series A Preferred Units refuses to consent to an Amendment. Therefore, a Redemption Upon an NYSE Event is conditioned upon the exercise of governance rights. As a result, we considered the examples under ASC 480-10-S99-3 that consider the classification of preferred securities with a redemption that is conditioned upon governance rights. In these examples, a preferred security is classified as permanent equity unless a holder of the preferred security can trigger or otherwise require a redemption through its governance rights. Example 2 provides that:
[I]f the preferred security holders control a majority of the votes on the board of directors through direct representation on the board or through other rights, the preferred security is redeemable at the option of the holder and classification in temporary equity is required.
In contrast, Example 5 provides that:
[A] security would be appropriately classified in permanent equity if the preferred stockholders cannot trigger or otherwise require [a redemption] through representation on the board of directors or through other rights, because the [redemption] is solely within the issuers control.
Similarly, Example 6 provides that:
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[A]ssuming the preferred stockholders cannot control the vote of the board of directors through direct representation or through other rights, the security would be properly classified in permanent equity because the [redemption] is within the control of the issuer.
Based upon these examples, we determined that the exercise of governance rights that are not within the control of the holders of preferred securities should be considered within the control of the issuer. Since a holder of Series A Preferred Units cannot trigger a Redemption Upon an NYSE Event by refusing to consent to an Amendment as a Management Member, we concluded that the Series A Preferred Units are properly classified in permanent equity because a Redemption Upon an NYSE Event is within the control of the Partnership.
* * * * *
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If you have any questions with respect to the foregoing response or require further information, please contact J. Brent Hagy of Enable Midstream at (405) 525-7788 or Gerald M. Spedale of Baker Botts L.L.P. at (713) 229-1734.
Very truly yours, | |||
ENABLE MIDSTREAM PARTNERS, LP | |||
By: | Enable GP, LLC, | ||
its general partner | |||
By: | /s/ Tom Levescy | ||
Tom Levescy | |||
Senior Vice President, Chief Accounting Officer and Controller | |||
cc: | Sondra Snyder, Securities and Exchange Commission |
J. Brent Hagy, Enable Midstream Partners, LP | |
Gerald M. Spedale, Baker Botts L.L.P. | |