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As filed with the Securities and Exchange Commission on April 1, 2014
Registration No. 333-192542
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Amendment No. 6
to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
ENABLE MIDSTREAM PARTNERS, LP
(Exact name of registrant as specified in its charter)
| Delaware | 4922 | 72-1252419 | ||
| (State or jurisdiction of incorporation or organization) |
(Primary Standard Industrial Classification Code Number) |
(I.R.S. Employer Identification No.) |
One Leadership Square
211 North Robinson Avenue
Suite 950
Oklahoma City, Oklahoma 73102
(405) 525-7788
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
Mark C. Schroeder
General Counsel
1111 Louisiana Street
Houston, Texas 77002
(713) 207-1111
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
| Gerald M. Spedale Jason A. Rocha Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234 |
Robert J. Joseph Jones Day 77 West Wacker Drive Chicago, Illinois 60601 (312) 269-4176 |
Sean T. Wheeler Ryan J. Maierson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400 |
Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ¨
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non- accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ¨ | Accelerated filer | ¨ | |||
| Non-accelerated filer | x (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
CALCULATION OF REGISTRATION FEE
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| Title of Each Class of Securities to be Registered | Proposed Maximum Aggregate Offering Price(1)(2) |
Amount of Registration Fee(3) | ||
| Common units representing limited partner interests |
$603,750,000 | $77,763 | ||
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| (1) | Includes common units that the underwriters have the option to purchase. |
| (2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933. |
| (3) | The total registration fee includes $64,400 that was previously paid for the registration of $500,000,000 of proposed maximum aggregate offering price in the filing of the Registration Statement on November 26, 2013 and $13,363 for the registration of an additional $103,750,000 of proposed maximum aggregate offering price registered hereby. |
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to Section 8(a), may determine.
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The information in this prospectus is not complete and may be changed. We may not offer or sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
PROSPECTUS
Subject To Completion, dated April 1, 2014
25,000,000 Common Units
Representing Limited Partner Interests
This is the initial public offering of common units of Enable Midstream Partners, LP. We are selling 25,000,000 common units in this offering. We currently estimate that the initial public offering price will be between $19.00 and $21.00 per common unit. Prior to this offering, there has been no public market for our common units. We have been approved to list our common units on the New York Stock Exchange under the symbol “ENBL,” subject to official notice of issuance.
Investing in our common units involves risks. Please see “Risk Factors” beginning on page 26.
These risks include the following:
| • | We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units. |
| • | Our contracts are subject to renewal risks. |
| • | Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our results of operations and our ability to make cash distributions to unitholders. |
| • | Our general partner and its affiliates, including OGE Energy and CenterPoint Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders. |
| • | Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. |
| • | Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors. |
| • | Even if holders of our common units are dissatisfied, they will not initially be able to remove our general partner without its consent. |
| • | There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment. |
| • | Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced. |
| • | Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us. |
| Per Common Unit |
Total |
|||||||
| Initial public offering price |
$ | $ | ||||||
| Underwriting discounts and commissions(1) |
$ | $ | ||||||
| Proceeds, before expenses, to Enable Midstream Partners, LP |
$ | $ | ||||||
| (1) | Excludes a structuring fee of an aggregate of $1.5 million payable to Morgan Stanley & Co. LLC, Barclays Capital Inc. and Goldman, Sachs & Co. We refer you to “Underwriting” starting on page 244 of this prospectus for additional information regarding underwriting compensation. |
The selling unitholder named in this prospectus has granted the underwriters a 30-day option to purchase up to an additional 3,750,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 25,000,000 common units in this offering. We will not receive any proceeds from the sale of common units by the selling unitholder pursuant to any exercise of the underwriters’ option to purchase additional common units.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
The underwriters expect to deliver the common units to purchasers on or about , 2014, through the book-entry facilities of The Depository Trust Company.
| Morgan Stanley |
Barclays | Goldman, Sachs & Co. |
| Citigroup | ||||||||||
| Deutsche Bank Securities | ||||||||||
| J.P. Morgan | ||||||||||
| UBS Investment Bank | ||||||||||
| Wells Fargo Securities | ||||||||||
| BofA Merrill Lynch | Credit Suisse | RBC Capital Markets |
Prospectus dated , 2014
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You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we, the selling unitholder nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. Neither we, the selling unitholder nor the underwriters are making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
INDUSTRY AND MARKET DATA
The data included in this prospectus regarding the midstream natural gas and crude oil industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management’s knowledge and experience in the industry in which we operate. Although we have not independently verified the accuracy or completeness of the third-party information included in this prospectus, based on management’s knowledge and experience, we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.
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This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical combined and consolidated financial statements, the pro forma combined financial statements and the related notes included elsewhere herein before investing in our common units. Unless indicated otherwise, the information presented in this prospectus (1) assumes an initial public offering price of $20.00 per common unit, (2) assumes that the underwriters do not exercise their option to purchase additional common units and (3) is adjusted to reflect the 1 for 1.279082616 reverse unit split effected on March 25, 2014. You should read “Risk Factors” beginning on page 26 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.
Except as otherwise set forth in the prospectus, all references in this prospectus to “our,” “we,” the “partnership,” “us” and like terms, when used with respect to periods prior to May 1, 2013, refer to the entities comprising CenterPoint Energy’s interstate pipelines and field services reportable business segments, and when used with respect to periods on and after May 1, 2013, refer to Enable Midstream Partners, LP and its subsidiaries. For a description of the transactions entered into in connection with the formation of our partnership on May 1, 2013, please read “—Formation Transactions and Partnership Structure.” References to “Enable GP” or our “general partner” are to Enable GP, LLC, a Delaware limited liability company and our general partner; references to “CenterPoint Energy” are to CenterPoint Energy, Inc., a Texas corporation, and its subsidiaries, other than us; references to “OGE Energy” are to OGE Energy Corp., an Oklahoma corporation, and its subsidiaries, other than us; references to our “sponsors” are to CenterPoint Energy and OGE Energy; and references to “ArcLight” are to ArcLight Capital Partners, LLC, a Delaware limited liability company, its affiliated entities, ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P., Bronco Midstream Partners, L.P., Bronco Midstream Infrastructure LLC and Enogex Holdings LLC, and their respective general partners and subsidiaries.
We are a large-scale, growth-oriented limited partnership formed to own, operate and develop strategically located natural gas and crude oil infrastructure assets. We serve key current and emerging production areas in the United States, including several premier shale resource plays and local and regional end-user markets in the United States. Our assets and operations are organized into two business segments: (i) gathering and processing, which primarily provides natural gas gathering, processing and fractionation services and crude oil gathering for our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service to natural gas producers, utilities and industrial customers. In both business segments, we generate a substantial portion of our gross margin under long-term, fee-based agreements that minimize our direct exposure to commodity price fluctuations.
Our natural gas gathering and processing assets are strategically located in four states and serve natural gas production from shale developments, which we refer to as unconventional shale resource plays, in some of the most productive regions of the Anadarko, Arkoma and Ark-La-Tex basins. These basins have experienced a strong increase in investment and drilling activity by exploration and production companies in recent years. We also own an emerging crude oil gathering business in the Bakken shale formation of the Williston Basin that commenced initial operations in November 2013. We are continuing to construct additional crude oil gathering capacity in this area. Our natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.
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Upon our formation in May 2013 as a limited partnership among OGE Energy, CenterPoint Energy and ArcLight, we became one of the largest midstream partnerships in the United States based on total assets. As of December 31, 2013, our portfolio of energy infrastructure assets included approximately 11,000 miles of gathering pipelines, 12 major processing plants with approximately 2.1 Bcf/d of processing capacity, approximately 7,900 miles of interstate pipelines (including Southeast Supply Header, LLC, or SESH, in which we own a 24.95% interest), approximately 2,300 miles of intrastate pipelines and eight storage facilities comprising 86.5 Bcf of storage capacity. We believe our scale benefits our customers by providing them with fully integrated midstream services and improved access from the wellhead to the marketplace. In addition, we believe our scale and scope will position us to be more competitive in developing new energy infrastructure assets and adding complementary services and business lines.
From the year ended December 31, 2011 through the year ended December 31, 2013, on a pro forma basis, we grew the volume of gas processed on our systems by 61%. We expect to continue to grow our business by providing midstream services to our customers’ rapidly growing upstream development projects. We expect our customers’ activity in the basins in which we operate to result in higher throughput on our systems and additional organic growth opportunities to expand the capacity and utilization of our assets. We also expect to grow our business and distributable cash flow by developing new energy infrastructure projects to support new and existing customers as they expand beyond our current footprint, as well as through third-party acquisitions. For the years ended December 31, 2011, 2012 and 2013, on a pro forma basis, we invested $798 million, $912 million and $571 million, respectively, in expansion capital expenditures. We expect that our expansion capital expenditures will be $533 million for the twelve months ending March 31, 2015.
We believe that our contractual arrangements provide a strong platform to support established operations and future organic growth. For the year ended December 31, 2013, on a pro forma basis, approximately 76% of our gross margin was generated from contracts that are fee-based, and approximately 50% of our gross margin was attributable to firm contracts or contracts with minimum volume commitment features.
For the year ended December 31, 2013, on a pro forma basis, we generated $1,322 million of gross margin, $779 million of Adjusted EBITDA and $454 million of net income. Gross margin and Adjusted EBITDA are non-GAAP financial measures. For definitions of gross margin and Adjusted EBITDA and a reconciliation to their most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States, or GAAP, please read “—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”
Gathering and Processing. We provide gathering, processing, treating, compression, dehydration and natural gas liquids (NGLs) fractionation for natural gas producers. Our gathering and processing assets are strategically located in established and actively developing basins in the United States and are interconnected with our interstate and intrastate pipelines and with third-party pipelines, which provides our customers with the benefits of a flexible and efficient transportation and storage system. On a pro forma basis for the year ended December 31, 2013, our top customers by volumes gathered were affiliates of Encana Corporation (Encana), Shell Oil Corporation (Shell), Exxon Mobil Corporation (Exxon), Chesapeake Energy Corporation (Chesapeake), Apache Corporation (Apache), Continental Resources, Inc. (Continental), QEP Energy Company (QEP), Devon Energy Production Company LP (Devon), BP America Production Company (BP) and Samson Resources Company (Samson).
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The following table sets forth certain information regarding our gathering and processing assets on a pro forma basis as of or for the year ended December 31, 2013:
| Asset/Basin |
Length (miles) |
Compression (Horsepower) |
Average Gathering Volume (TBtu/d) |
Number of Processing Plants |
Processing Capacity (MMcf/d) |
NGLs Produced (Bbl/d) |
Gross Acreage Dedications (in millions) |
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| Anadarko Basin |
6,729 | 477,462 | 1.3 | 9 | 1,445 | 43,233 | 4.7 | |||||||||||||||||||||
| Arkoma Basin |
2,676 | 137,928 | 1.0 | 1 | 60 | 4,686 | 1.2 | |||||||||||||||||||||
| Ark-La-Tex Basin(1) |
1,639 | 182,892 | 1.3 | 2 | 545 | 10,814 | 0.7 | |||||||||||||||||||||
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| Total |
11,044 | 798,282 | 3.6 | 12 | 2,050 | 58,733 | 6.6 | |||||||||||||||||||||
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| (1) | Ark-La-Tex basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table. |
Six of our processing plants in the Anadarko basin are interconnected via our large-diameter, rich gas gathering system in western Oklahoma, which spans 18 counties and has approximately 1.2 Bcf/d of processing capacity. Our 4.7 million gross acres of acreage dedications in the Anadarko basin area are served by this system, which we refer to as our “super-header” system. We have configured this system to optimize the flow of natural gas and the utilization of the processing plants connected to it, which we believe provides us with strategic growth opportunities. We have made investments to expand the super-header system, including our newest plant located in Custer County, Oklahoma (the McClure Plant) that was placed in service in December 2013. The McClure Plant increased our natural gas processing capacity in the basin by over 15%, providing an additional 200 MMcf/d of natural gas processing capacity. We expect to continue to grow the capacity of the super-header system through the planned addition of another new cryogenic processing plant and related gathering pipelines. This plant, which will be located in Grady County, Oklahoma (the Bradley Plant), will provide an additional 200 MMcf/d of processing capacity and is expected to be completed in the first quarter of 2015.
We believe our contract structures provide us with stable cash flows in our major operating basins. For the year ended December 31, 2013, on a pro forma basis, we generated 61% of our gathering and processing gross margin under long-term, fee-based agreements, and of this fee-based margin, approximately 38% was attributable to gathering and processing contracts containing minimum volume commitment features. Under our minimum volume commitment contracts, our customers commit to ship a minimum annual volume of natural gas on our gathering system, or, in lieu of shipping such volumes, to pay us periodically as if that minimum amount had been shipped. As of December 31, 2013, we had minimum volume commitments in lean natural gas developments of 1.6 Bcf/d with a weighted average remaining term of over nine years. We also have an emerging crude oil gathering business in the Bakken shale formation. Our current operations in the Bakken have a similar minimum volume commitment contract structure that we believe will provide us with an additional source of stable cash flows. Under our acreage dedication contracts, our customers are generally required to deliver all of their production within the dedicated area to our gathering system over the period of the contract. As of December 31, 2013, we had acreage dedications in rich natural gas developments covering more than 5.7 million acres that generally have long lived reserves with a weighted average remaining term of approximately nine years. As of December 31, 2013, our gathering and processing contracts for our top ten natural gas producer customers, which accounted for approximately 75% of our gathered volumes for the year ended December 31, 2013, on a pro forma basis, had a volume-weighted average remaining term of approximately nine years.
For the year ended December 31, 2013, on a pro forma basis, our gathering and processing business segment generated $762 million of gross margin and $467 million of Adjusted EBITDA.
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Transportation and Storage. Our natural gas transportation and storage business segment consists of our interstate pipelines, our intrastate pipelines and our storage assets. We provide pipeline takeaway capacity for natural gas producers from supply basins to market hubs and critical natural gas supply for industrial end users and utilities, such as local distribution companies, or LDCs, and power generators. Our interstate pipeline system, including SESH, includes approximately 7,900 miles of transportation pipelines and extends from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois. Our eight storage facilities in Oklahoma, Louisiana and Illinois have 86.5 Bcf of storage capacity and strategically complement our pipeline systems.
The following table sets forth certain information regarding our transportation and storage assets as of December 31, 2013:
| Asset |
Length (miles) |
Capacity | Total Firm Contracted Capacity(Bcf/d) |
Average Throughput Volume (Tbtu/d) |
Percent of Capacity under Firm Contracts |
Weighted Average Remaining Firm Contract Life(years) |
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| Interstate Transportation(1) |
7,880 | 8.4 Bcf | /d | 8.0 | 3.5 | (2) | 95 | % | 3.9 | |||||||||||||||
| Intrastate Transportation |
2,304 | 1.9 Bcf | /d(3) | — | 1.6 | — | 4.9 | |||||||||||||||||
| Storage |
— | 86.5 Bcf | 67.9 | — | 79 | % | 4.4 | |||||||||||||||||
| (1) | Except with respect to length, this information does not include amounts for SESH. SESH is a non-consolidated entity in which we own a 24.95% ownership interest. |
| (2) | Actual volumes transported per day may be less than total firm contracted capacity based on demand. |
| (3) | This represents the maximum single day receipts on the intrastate systems. Our Oklahoma intrastate pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2013, the peak daily throughput was 1.9 TBtu or, on a volumetric basis, 1.9 Bcf/d. |
We generate revenue primarily by charging demand fees pursuant to applicable tariffs for the transportation and storage of natural gas on our system. On a pro forma basis, we generated 96% of our transportation and storage gross margin under fee-based agreements with a weighted average remaining contract life of over four years as of December 31, 2013. Demand-based margin for this period represented 89% of the fee-based margin, on a pro forma basis. We generally do not take ownership of the natural gas that we transport and store.
For the year ended December 31, 2013, on a pro forma basis, our top customers by gross margin were affiliates of CenterPoint Energy, Laclede Group (Laclede), OGE Energy, American Electric Power Company, Inc. (AEP) and Exxon. Our transportation and storage assets were designed and built to serve affiliates of CenterPoint Energy, Laclede, OGE Energy and AEP and are competitively positioned to serve other large natural gas and electric utility companies, such as Ameren Corporation (Ameren) and Entergy Corporation (Entergy).
For the year ended December 31, 2013, on a pro forma basis, our transportation and storage business segment generated $562 million of gross margin and $313 million of Adjusted EBITDA.
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Our primary business objective is to practice operational excellence and to grow our business responsibly, enabling us to increase the amount of cash distributions we make to our unitholders over time while maintaining our financial stability. We intend to accomplish this objective by executing the strategies listed below:
| • | Capitalize on Organic Growth Opportunities Associated with Our Strategically Located Assets. We own and operate assets servicing four of the largest basins in the United States, including some of the most productive shale developments in these basins. We believe current high levels of natural gas and crude oil exploration, development and production activities within our areas of operation present significant opportunities for organic growth and increasing throughput on our system. Over 200 drilling rigs were deployed in our areas of gas gathering operation as of December 31, 2013, which represents a 12% increase over December 2012. As a result of this expanding activity, we are constructing an additional processing facility in Oklahoma that is expected to provide an additional 200 MMcf/d in processing capacity. Additionally, as of December 31, 2013, there were 97 drilling rigs operating in Dunn and McKenzie counties, North Dakota, in the Williston Basin, where we are currently operating a crude oil gathering system, as well as 64 drilling rigs operating in Williams and Mountrail counties, North Dakota, in the Williston Basin, where we have entered into an agreement to construct a second crude oil gathering system. We are evaluating other expansion opportunities to further enhance our existing systems. |
| • | Continue to Minimize Direct Commodity Price Exposure Through Long-Term, Fee-Based Contracts. We continually seek ways to minimize our exposure to commodity price risk, and we believe that our focus on fee-based revenues reduces our direct commodity price exposure and is essential to maintaining stable cash flows and increasing our quarterly distributions over time. Since 2009, we have focused on increasing the percentage of long-term, fee-based contracts with our customers. For the year ended December 31, 2013, on a pro forma basis, 76% of our gross margin was generated from fee-based contracts. As we grow, we intend to maintain our focus on long-term, fee-based contracts. |
| • | Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines. We plan to grow our business through our strong relationships with existing customers. We believe that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in multiple organic growth projects in support of our existing and new customers. For example, in 2012, an existing customer invited us to participate in the construction of a gas gathering system in the Ark-La-Tex basin, and in 2013, a second customer invited us to develop a crude oil gathering system in the Williston basin. In addition, in February 2014, we executed another agreement with this second customer to gather additional crude oil production through a new crude oil gathering system in the Williston Basin that is expected to commence operations in the second quarter of 2015. We expect to maintain and build relationships with key producers and suppliers to continue to attract new volumes and expansion opportunities. |
| • | Grow Through Accretive Acquisitions and Disciplined Development. We plan to pursue accretive acquisitions of complementary assets that provide attractive potential returns in new operating regions or midstream business lines. From January 1, 2011 through December 31, 2013, on a pro forma basis, we have invested approximately $639 million in acquisitions of new assets (including our Waskom processing plant, Cordillera gathering system and Amoruso gathering system) and investments in joint ventures (including SESH), and we have invested an additional $179 million in expansion capital associated with these projects. We also have the ability to acquire CenterPoint Energy’s remaining 25.05% interest in SESH by 2015. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including a process for evaluating and managing risks to cash distributions. |
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| • | Leverage the Scale of Our Existing Assets to Realize Significant Synergies. Given the complementary features of our assets, we expect operating synergies from the interconnection and optimization of our systems to increase our cash flows over time. We expect to achieve operational and commercial synergies of $15.6 million through March 31, 2015, net of integration costs, and we expect additional synergies over time as we create a combined midstream service platform and are able to offer new and existing customers new and more efficient services. |
We believe that we are well positioned to execute our business strategies successfully because of the following competitive strengths:
| • | Significant Capability, Scale and Stability of Our Diversified Midstream Business. With over $11 billion in assets as of December 31, 2013 across ten states and multiple midstream business lines, we have an enhanced ability to provide customers with access to diverse services and end markets. We have approximately 11,000 miles of gathering pipelines and 12 major processing plants with approximately 2.1 Bcf/d of processing capacity spanning the Anadarko, Arkoma and Ark-La-Tex basins. Our natural gas processing plants produced 58.7 MBbl/d of NGLs, on a pro forma basis, for the year ended December 31, 2013, making us one of the largest producers of NGLs in the United States. Our network of interstate and intrastate pipelines covers approximately 7,900 miles (including SESH) and 2,300 miles, respectively, and is complemented by our 86.5 Bcf of storage capacity. We believe our size, scale and stability are competitive strengths and enhance our ability to provide reliable and increasing cash flows to our unitholders. |
| • | Strategically Located Assets that Provide a Strong Platform for Growth and Operational Flexibility to Our Customers. Our assets are strategically configured in and around four of the most prominent natural gas and crude oil producing basins in the country and support a diversified midstream business that we believe will deliver reliable distributions and steady growth to our unitholders. Our assets transport natural gas to delivery points across the United States through 97 interconnects as of December 31, 2013. A portion of our system also serves local natural gas demand at LDCs, natural gas-fired power plants and industrial load in the regions in which we operate. We believe that our assets provide operational flexibility and delivery options for producers transporting natural gas from a mix of rich and lean natural gas plays to multiple market hubs within our region. Our assets also provide outlets for suppliers from other regions seeking to provide natural gas to on-system markets that we serve. We believe that our competitors would require significant capital expenditures to provide comparable services to these customers, providing us with a significant competitive advantage as demand for natural gas grows over time. |
| • | Strong Relationships with a Large and Diverse Customer Base. We serve a broad range of customers across both of our business segments, and many of our customers rely on us for multiple midstream services. We believe that our track record of executing large infrastructure projects and meeting target in-service dates has allowed us to build a reputation as a reliable operator that provides high-quality services and focuses on the needs of our customers. On a pro forma basis for the year ended December 31, 2013, our top gathering and processing customers by volumes gathered were affiliates of Encana, Shell, Exxon, Chesapeake, Apache, Continental, QEP, Devon, BP and Samson and our top transportation and storage customers by gross margin were affiliates of CenterPoint Energy, Laclede, OGE Energy, AEP and Exxon. We believe that our relationships and reputation will continue to create opportunities with new and existing customers. |
| • | Stable Cash Flows as a Result of Fee-Based Revenues Under Long-Term Contracts. For the years ended December 31, 2013 and 2012, on a pro forma basis, we generated approximately 76% and 74%, respectively, of our gross margin from fee-based contracts, primarily with creditworthy counterparties. |
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| We believe that our long-term, fee-based contracts, many of which include minimum volume commitments and/or acreage dedications, minimize our commodity price exposure and enhance the predictability of our financial performance. |
| • | Strong and Flexible Capital Structure. We have a disciplined financial policy and maintain a strong and flexible capital structure to allow us to execute our identified growth projects and acquisitions even in challenging market environments. On May 1, 2013, we entered into our $1.4 billion five-year senior unsecured revolving credit facility. As of January 2014, we have the ability to issue up to $1.4 billion in commercial paper, subject to available borrowing capacity under our revolving credit facility and market conditions, to manage the timing of cash flows and fund short-term working capital deficits. We believe our strong credit profile, including our investment-grade credit ratings, and the liquidity provided by our revolving credit facility give us a significant advantage over many of our competitors that may be more limited in their access to capital to pursue organic growth and acquisition opportunities. |
| • | Experienced Management Team and Key Operational Personnel with a Proven Record of Asset Operation, Acquisition, Construction, Development and Integration Expertise. Our management team has an average of over 30 years of experience in the energy industry in operating, acquiring, constructing, developing and integrating midstream assets, and understands the service requirements of our customers. Our management team has established strong relationships with producers, marketers and other end-users of natural gas throughout the U.S. upstream and midstream industries, which we believe will be beneficial to us in pursuing acquisition and organic expansion opportunities. We also employ skilled engineering, construction and operations teams that have significant experience in designing, constructing and operating large midstream energy projects. |
Our Relationship with OGE Energy and CenterPoint Energy
OGE Energy and CenterPoint Energy are aligned with us to grow our distributions. Following the completion of this offering, OGE Energy and CenterPoint Energy will retain a significant interest in us through their approximate 26.7% and 54.7% limited partner interests in us, respectively. OGE Energy and CenterPoint Energy will each own 50% of the management rights of our general partner, which holds all of our incentive distribution rights. In addition, OGE Energy and CenterPoint Energy own 60% and 40%, respectively, of the economic rights in our general partner.
OGE Energy (NYSE: OGE) is the parent company of Oklahoma Gas and Electric Company, or OG&E, a regulated electric utility serving approximately 805,000 customers in a service territory spanning 30,000 square miles in Oklahoma and western Arkansas. OG&E furnishes retail electric service in 268 communities and their contiguous rural and suburban areas. OG&E’s service area includes Oklahoma City, Oklahoma and Fort Smith, Arkansas, the second largest city in that state. Of the 268 communities that OG&E serves, 242 are located in Oklahoma and 26 are located in Arkansas. As of December 31, 2013, OGE Energy had total assets of $9.1 billion and a market capitalization of $6.7 billion.
CenterPoint Energy (NYSE: CNP) is a public utility holding company whose indirect wholly owned subsidiaries include (i) CenterPoint Energy Houston Electric, LLC, which provides electric transmission and distribution services to retail electric providers serving over two million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately six million people and includes the city of Houston; and (ii) CenterPoint Energy Resources Corp., which owns and operates natural gas distribution systems serving more than three million customers in six states, including customers in the metropolitan areas of Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. As of December 31, 2013, CenterPoint Energy had total assets of $21.9 billion and a market capitalization of $9.9 billion.
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Our sponsors are also significant customers of our transportation and storage business segment and continue to own and operate a substantial portfolio of energy assets. For the years ended December 31, 2013 and 2012, on a pro forma basis, approximately 4% of our total gross margin was derived from contracts servicing electric power generation with OGE Energy. For the years ended December 31, 2013 and 2012, on a pro forma basis, approximately 7% of our total gross margin was derived from contracts servicing LDCs owned by CenterPoint Energy.
Our sponsors entered into a number of agreements in connection with our formation. Please read “Certain Relationships and Related Party Transactions” for a detailed description of these agreements, as well as other agreements affecting us and our sponsors. Although we believe our relationships with OGE Energy and CenterPoint Energy are positive attributes, there can be no assurance that we will benefit from these relationships.
An investment in our common units involves risks associated with our business, our regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in “Risk Factors” beginning on page 26 of this prospectus and the other information in this prospectus before deciding whether to invest in our common units.
Risks Related to Our Business
| • | We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units. |
| • | The assumptions underlying the forecast of distributable cash flow that we include under the caption “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. |
| • | Our contracts are subject to renewal risks. |
| • | We depend on a small number of customers for a significant portion of our firm transportation and storage services revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of our transportation and storage services and our consolidated financial position, results of operations and our ability to make cash distributions to our unitholders. |
| • | Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our results of operations and our ability to make cash distributions to unitholders. |
Risks Related to an Investment in Us
| • | Our general partner and its affiliates, including OGE Energy and CenterPoint Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders. |
| • | If you are not an Eligible Holder, your common units may be subject to redemption. |
| • | Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties. |
| • | Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. |
| • | Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors. |
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| • | Even if holders of our common units are dissatisfied, they will not initially be able to remove our general partner without its consent. |
| • | You will experience immediate and substantial dilution in pro forma net tangible book value of $2.77 per common unit. |
| • | There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment. |
Tax Risks to Common Unitholders
| • | Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced. |
| • | If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our distributable cash flow to our unitholders. |
| • | The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis. |
| • | Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us. |
FORMATION TRANSACTIONS AND PARTNERSHIP STRUCTURE
We were formed in May 2013 by affiliates of CenterPoint Energy, OGE Energy and ArcLight to own, operate and develop a diversified portfolio of complementary midstream businesses previously operated by OGE Energy and CenterPoint Energy. Pursuant to a master formation agreement among our sponsors and ArcLight, the following transactions, which we refer to as our formation transactions, occurred in connection with our formation:
| • | CenterPoint Energy converted CenterPoint Energy Field Services, LLC, an indirect wholly owned subsidiary, or CEFS, into a Delaware limited partnership, which subsequently changed its name to Enable Midstream Partners, LP; |
| • | CenterPoint Energy contributed certain equity interests in its subsidiaries that conduct the remaining portion of its midstream business to Enable Midstream Partners, LP; and |
| • | OGE Energy and an indirect subsidiary of ArcLight contributed 100% of the equity interests in Enogex LLC, a Delaware limited liability company (Enogex), to Enable Midstream Partners, LP. |
As consideration for the contribution of these assets and agreements, we issued 227,508,825 common units to CenterPoint Energy, 110,982,805 common units to OGE Energy and 51,527,730 common units to ArcLight after giving effect to the reverse unit split. We also issued a non-economic general partner interest and our incentive distribution rights to Enable GP. Enable GP is equally controlled by CenterPoint Energy and OGE Energy, with each owning 50% of the management rights. Enable GP holds all of our incentive distribution rights, 40% of which are allocated to CenterPoint Energy and 60% of which are allocated to OGE Energy. In connection with this offering, 139,704,916 of CenterPoint Energy’s common units and 68,150,514 of OGE Energy’s common units will be converted into subordinated units.
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We also entered into a number of agreements with our sponsors in connection with our formation. These agreements included an agreement with respect to the transfer of CenterPoint Energy’s remaining 25.05% interest in SESH to us, an omnibus agreement, certain services and employment agreements and tax sharing agreements. In addition, upon our formation, we entered into our $1.05 billion three-year term loan facility and our $1.4 billion five-year revolving credit facility.
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The diagram below depicts a simplified organization and ownership chart after giving effect to the offering. After giving effect to this offering, our units will be held as follows:
| Public Common Units (1) |
6.0 | % | ||
| Common Units Held by: |
||||
| CenterPoint Energy |
21.1 | % | ||
| OGE Energy |
10.3 | % | ||
| ArcLight |
12.4 | % | ||
| Subordinated Units Held by: |
||||
| CenterPoint Energy |
33.6 | % | ||
| OGE Energy |
16.4 | % | ||
| LTIP Common Units (2) |
0.2 | % | ||
| General Partner Interest |
0.0 | % | ||
|
|
|
|||
| Total |
100.0 | % |
| (1) | Includes up to 1,250,000 common units that may be purchased by certain of our directors, officers and related persons pursuant to a directed unit program, as described in more detail in “Underwriting—Directed Unit Program.” |
| (2) | Excludes approximately 100,000 phantom units that may be granted to certain key employees that provide services for us pursuant to our long term incentive plan. Please read “Management—2014 Executive Compensation Program—Long Term Incentive Plan.” |
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MANAGEMENT OF ENABLE MIDSTREAM PARTNERS, LP
Enable GP, LLC, our general partner, will manage our business and operations. The board of directors and executive officers of our general partner will oversee our operations and make decisions on our behalf. Certain officers and directors of OGE Energy and CenterPoint also serve as executive officers or directors of our general partner.
Unlike shareholders in a publicly traded corporation, our common unitholders will not be entitled to elect our general partner or its directors. OGE Energy and CenterPoint Energy each have the right to designate two members of the board of directors of our general partner, with any additional members of our board of directors being designated collectively by OGE Energy and CenterPoint Energy. At the closing of this offering, our general partner will have one director who is independent as defined under the independence standards established by the New York Stock Exchange, or NYSE. OGE Energy and CenterPoint Energy will appoint one additional independent director within 90 days of the date of this prospectus and a third independent director within 12 months of the date of this prospectus. For information about the executive officers and directors of our general partner, please read “Management.”
SUMMARY OF CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
Our general partner has a duty to manage our partnership in a manner it subjectively believes is in our best interests. However, the officers and directors of our general partner also have duties to manage our general partner in a manner beneficial to its owners, OGE Energy and CenterPoint Energy. Additionally, certain of our executive officers and initial directors are officers and/or directors of OGE Energy or CenterPoint Energy. As a result, conflicts of interest may arise in the future between us and our common unitholders, on the one hand, and OGE Energy and CenterPoint Energy and our general partner, on the other hand. For a more detailed description of the conflicts of interest of our general partner, please read “Risk Factors—Risks Related to an Investment in Us” and “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.”
Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Pursuant to these provisions, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and the methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement also provides that, subject to the provisions contained in the omnibus agreement, affiliates of our general partner, including OGE Energy and CenterPoint Energy and their other subsidiaries and affiliates, are permitted to compete with us. We may enter into additional agreements in the future with OGE Energy and CenterPoint Energy relating to the purchase of additional assets, the provision of certain services to us by OGE Energy or CenterPoint Energy and other matters. In the performance of their obligations under these agreements, OGE Energy and CenterPoint Energy and their subsidiaries are not held to a fiduciary duty standard of care to us, our general partner or our limited partners, but rather to the standard of care specified in these agreements. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each common unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.
For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”
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PRINCIPAL EXECUTIVE OFFICES AND INTERNET ADDRESS
Our principal executive offices are located at One Leadership Square, 211 North Robinson Avenue, Suite 950, Oklahoma City, Oklahoma 73102, and our telephone number is (405) 525-7788. Our website is located at www.enablemidstream.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, or the SEC, available, free of charge, on our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.
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| Common units offered to the public |
25,000,000 common units or 28,750,000 common units if the underwriters exercise in full their option to purchase additional common units. | |
| Units outstanding after this offering |
207,855,430 common units and 207,855,430 subordinated units, representing 50.0% and 50.0%, respectively, limited partner interests in us. | |
| As described further below, the exercise of the underwriters’ option to purchase additional common units will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all outstanding units. | ||
| In addition, our general partner will own a non-economic general partner interest in us. | ||
| Option to purchase additional units |
The selling unitholder has granted the underwriters a 30-day option to purchase up to an aggregate of 3,750,000 additional common units to the extent the underwriters sell more than 25,000,000 common units in this offering. | |
| Use of proceeds |
We expect to receive net proceeds from this offering of approximately $466 million, after deducting underwriting discounts and commissions, the structuring fee and offering expenses. We base this amount on an assumed initial public offering price of $20.00 per common unit. We intend to use approximately $453 million of the net proceeds of this offering for general partnership purposes, including the funding of expansion capital expenditures, and approximately $13 million to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. Pending application of the net proceeds as described above, we may temporarily pay down debt outstanding under our commercial paper program and revolving credit facility.
Affiliates of each of the underwriters are lenders under our revolving credit facility and will, in that capacity, receive a portion of the proceeds from this offering through any repayment of borrowings outstanding under our revolving credit facility pending the application of the net proceeds as described above. Please read “Underwriting.” | |
| We will not receive any proceeds from the sale of common units by the selling unitholder pursuant to any exercise of the underwriters’ option to purchase additional common units. The selling unitholder may be deemed under federal securities laws to be an underwriter with respect to the common units it may sell in connection with this offering. | ||
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| Cash distributions |
We intend to pay the minimum quarterly distribution of $0.2875 per unit ($1.15 per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.” | |
| We will adjust the amount of our distribution for the period from the completion of this offering through June 30, 2014, based on the actual length of that period. | ||
| Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner: | ||
| • first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $0.2875 plus any arrearages from prior quarters;
• second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $0.2875 ; and
• third, to all unitholders, pro rata, until each unit has received a distribution of $0.330625. | ||
| If cash distributions to our unitholders exceed $0.330625 per unit in any quarter, our general partner will receive increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions” because they incentivize our general partner to increase distributions to our unitholders. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages of the cash we distribute to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.” | ||
| Prior to making distributions, we will reimburse OGE Energy and CenterPoint Energy for direct or allocated costs and expenses incurred by them on our behalf pursuant to the services agreements and the employee transition agreements. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Offering Transactions.” | ||
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| Pro forma distributable cash flow generated during the year ended December 31, 2013 was approximately $541 million. The amount of cash we will need to pay the minimum quarterly distribution for four quarters on our common units and subordinated units to be outstanding immediately after this offering will be approximately $478 million (or an average of approximately $119.5 million per quarter). As a result, we would have had sufficient distributable cash flow to pay the full minimum quarterly distribution of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all of our common units and subordinated units for the year ended December 31, 2013. Please read “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013.” | ||
| We believe that, based on the financial forecasts and related assumptions included under the caption “Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending March 31, 2015,” we will have sufficient distributable cash flow to make cash distributions for the twelve months ending March 31, 2015, at the minimum quarterly distribution rate of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all common units and subordinated units outstanding immediately after completion of this offering. However, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast. | ||
| Subordinated units |
OGE Energy and CenterPoint Energy will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. If we do not pay distributions on our subordinated units, our subordinated units will not accrue arrearages for those unpaid distributions. | |
| Conversion of subordinated units |
The subordination period will end on the first business day after we have earned and paid at least (i) $1.15 (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit, for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2017, or (ii) $1.725 (150% of the annualized | |
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| minimum quarterly distribution) on each outstanding common unit and subordinated unit, in addition to any distribution made in respect of the incentive distribution rights, for any four-consecutive-quarter period ending on or after June 30, 2015, in each case provided that there are no arrearages on our common units at that time. For purposes of the foregoing test, our general partner may include as earned in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current contract year under our gathering agreements that include minimum volume commitments. In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. | ||
| When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordination Period.” | ||
| Issuance of additional units |
We can issue an unlimited number of units without the consent of our unitholders. Please see “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.” | |
| Limited voting rights |
Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will not have the right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 75% of our outstanding common and subordinated units, including any common and subordinated units owned by our general partner and its affiliates, voting together as a single class. Upon closing of this offering, OGE Energy and CenterPoint Energy will own an aggregate of approximately 81.4% of our common and subordinated units. This will give OGE Energy and CenterPoint Energy the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement—Voting Rights.” | |
| Limited call right |
If at any time our general partner and its affiliates own more than 90% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the remaining common units at a price not less than the | |
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| then-current market price of the common units, as calculated in accordance with our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding common units, the ownership threshold to exercise the call right will be permanently reduced to 80%. See “The Partnership Agreement—Limited Call Right.” | ||
| Estimated ratio of taxable income to distributions |
We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2016, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.15 per common unit, we estimate that your average allocable taxable income per year will be no more than $0.23 per common unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.” | |
| Material tax consequences |
For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Federal Income Tax Consequences.” | |
| Directed unit program |
At our request, the underwriters have reserved for sale, at the initial public offering price, up to 5% of the common units offered hereby for our directors, officers and seconded employees. If purchased by these persons, these common units will be subject to a 180-day lock-up restriction. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units which are not so purchased will be offered by the underwriters to the general public on the same terms as the other common units offered hereby. Please read “Underwriting—Directed Unit Program.” | |
| Exchange listing |
We have been approved to list the common units on the NYSE under the symbol “ENBL,” subject to official notice of issuance. | |
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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA
The following tables set forth, for the periods and as of the dates indicated, the summary historical financial and operating data of Enable Midstream Partners, LP, which is derived from the historical books and records of the partnership, the summary historical financial and operating data of Enogex, which is derived from the historical books and records of Enogex, and the pro forma financial and operating data of Enable Midstream Partners, LP. On May 1, 2013 (formation), OGE Energy and ArcLight indirectly contributed 100% of the equity interests in Enogex to the partnership in exchange for common units and, for OGE Energy only, interests in our general partner. The transaction was considered a business combination for accounting purposes, with the partnership considered the acquirer of Enogex. Subsequent to May 1, 2013, the financial and operating data of the partnership are consolidated to reflect the acquisition of Enogex and the retention of certain assets and liabilities by CenterPoint Energy. The following tables should be read together with, and are qualified in their entirety by reference to, the historical and unaudited pro forma and supplemental pro forma combined and consolidated financial statements, as applicable, and the accompanying notes included elsewhere in this prospectus.
The summary historical financial and operating data of Enable Midstream Partners, LP for the years ended December 31, 2013, 2012 and 2011 and balance sheet data as of December 31, 2013 and 2012 is derived from and should be read in conjunction with the audited historical combined and consolidated financial statements of the partnership included elsewhere in this prospectus. The operating data for all periods is unaudited. The following table should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
The summary historical financial and operating data of Enogex for the years ended December 31, 2012 and 2011 and balance sheet data as of December 31, 2012 and 2011 is derived from and should be read in conjunction with the audited historical consolidated financial statements of Enogex included elsewhere in this prospectus. The operating data for all periods is unaudited.
The summary unaudited pro forma financial and operating data is derived from and should be read in conjunction with the unaudited pro forma and supplemental pro forma combined financial statements of Enable Midstream Partners, LP included elsewhere in this prospectus. The pro forma balance sheet assumes that the offering occurred as of December 31, 2013 and the pro forma condensed combined statements of income for the years ended December 31, 2013 and 2012 assume that our formation transactions and this offering, with respect to unit and per unit information, occurred as of January 1, 2013 and 2012, respectively. These transactions include, and the pro forma financial data gives effect to, the following:
| • | The acquisition of Enogex on May 1, 2013, including (1) the incremental depreciation and amortization incurred on the fair value adjustment of Enogex’s assets, (2) adjustments to revenue and cost of sales to reflect purchase price adjustments for the recurring impact of certain loss contracts and deferred revenues and (3) a reduction to interest expense for recognition of a premium on Enogex’s fixed rate senior notes; |
| • | A reduction in the historical interest income received on the notes receivable—affiliated companies from CenterPoint Energy, which were paid off at formation, and the interest expense incurred on notes payable—affiliated companies to CenterPoint Energy and OGE Energy prior to May 1, 2013, which were repaid at formation; |
| • | The entrance into a $1.05 billion 3-year senior unsecured term loan facility by the partnership and the incremental interest expense and amortization of deferred financing costs related thereto; |
| • | The entrance into a $1.4 billion senior unsecured revolving credit facility by the partnership and the incremental interest expense and amortization of deferred financing costs related thereto; |
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| • | A reduction for the elimination of federal and state income taxes, except for Texas state margin taxes; |
| • | A reduction in the partnership’s interest in SESH from 50% to 24.95%; |
| • | The consummation of this offering and our issuance of 25,000,000 common units to the public and the conversion of 139,704,916 common units held by CenterPoint Energy and 68,150,514 common units held by OGE Energy into subordinated units; and |
| • | The application of the net proceeds of this offering as described in “Use of Proceeds.” |
The pro forma financial data does not give effect to the estimated $3 million in incremental annual operation and maintenance expense we expect to incur as a result of being a publicly traded partnership. The pro forma financial data does not give effect to any potential cost savings or other operating efficiencies from the integration of the partnership and Enogex. The pro forma financial data does not reflect adjustments for the execution of service agreements with CenterPoint Energy and OGE Energy upon formation since the costs under these service agreements were previously incurred by the partnership and Enogex on a similar basis. The pro forma financial data does not adjust for acquisition related costs since the partnership incurred no acquisition related costs in the Combined and Consolidated Statement of Income during any period presented based upon the terms in the master formation agreement. For a description of the step acquisition gain, please refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Pro Forma.”
The following tables include the financial measures of gross margin, which we use as a measure of performance, Adjusted EBITDA, which we use as a measure of performance and liquidity, and distributable cash flow, which we use as a measure of liquidity. Gross margin, Adjusted EBITDA and distributable cash flow are not calculated and presented in accordance with GAAP. We define gross margin as total revenues minus cost of goods sold, excluding depreciation and amortization. We define Adjusted EBITDA as net income from continuing operations before interest expense, income tax expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results. For a reconciliation of gross margin, Adjusted EBITDA and distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “—Non-GAAP Financial Measures.”
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| Enable Midstream Partners, LP Historical |
Enogex LLC Historical |
Enable Midstream Partners, LP Pro Forma |
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| Year Ended December 31, |
Year Ended December 31, |
YearEnded December 31, |
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| 2013 | 2012 | 2011 | 2012 | 2011 | 2013 | 2012 | ||||||||||||||||||||||
| (In millions, except per unit and operating data) |
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| Results of Operations Data: |
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| Revenues |
$ | 2,489 | $ | 952 | $ | 932 | $ | 1,609 | $ | 1,787 | $ | 3,120 | $ | 2,564 | ||||||||||||||
| Cost of goods sold, excluding depreciation and amortization |
1,313 | 129 | 101 | 1,120 | 1,346 | 1,798 | 1,238 | |||||||||||||||||||||
| Operation and maintenance |
429 | 267 | 263 | 179 | 167 | 493 | 446 | |||||||||||||||||||||
| Depreciation and amortization |
212 | 106 | 91 | 109 | 78 | 269 | 273 | |||||||||||||||||||||
| Impairments |
12 | — | — | — | 6 | 12 | — | |||||||||||||||||||||
| Gain on insurance proceeds |
— | — | — | (8 | ) | (3 | ) | — | (8 | ) | ||||||||||||||||||
| Taxes other than income |
54 | 34 | 37 | 23 | 18 | 62 | 57 | |||||||||||||||||||||
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| Operating income |
469 | 416 | 440 | 186 | 175 | 486 | 558 | |||||||||||||||||||||
| Interest expense |
(67 | ) | (85 | ) | (90 | ) | (32 | ) | (23 | ) | (49 | ) | (45 | ) | ||||||||||||||
| Equity in earnings of equity method affiliates |
15 | 31 | 31 | — | — | 12 | 18 | |||||||||||||||||||||
| Interest income—affiliated companies |
9 | 21 | 14 | — | — | — | — | |||||||||||||||||||||
| Step acquisition gain |
— | 136 | — | — | — | — | 136 | |||||||||||||||||||||
| Other, net |
— | — | — | (4 | ) | 3 | 9 | (4 | ) | |||||||||||||||||||
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|
|||||||||||||||
| Income before income taxes |
426 | 519 | 395 | 150 | 155 | 458 | 663 | |||||||||||||||||||||
| Income tax expense (benefit) |
(1,192 | ) | 203 | 163 | — | — | 4 | 3 | ||||||||||||||||||||
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|||||||||||||||
| Net income |
$ | 1,618 | $ | 316 | $ | 232 | $ | 150 | $ | 155 | $ | 454 | $ | 660 | ||||||||||||||
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|||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest |
3 | — | — | 2 | (1 | ) | 3 | 2 | ||||||||||||||||||||
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| Net income attributable to controlling interest |
$ | 1,615 | $ | 316 | $ | 232 | $ | 148 | $ | 156 | $ | 451 | $ | 658 | ||||||||||||||
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| Limited partners’ interest in net income attributable to controlling interest(1) |
$ | 289 | $ | 451 | $ |
658 |
| |||||||||||||||||||||
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| Basic and diluted earnings per common limited partner unit(1)(2) |
$ | 0.74 | $ | 1.09 | $ | 1.58 | ||||||||||||||||||||||
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| Basic and diluted earnings per subordinated limited partner unit(1) |
$ | 1.08 | $ | 1.58 | ||||||||||||||||||||||||
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| Balance Sheet Data (at period end): |
||||||||||||||||||||||||||||
| Property, plant and equipment, net |
$ | 8,990 | $ | 4,705 | $ | 4,070 | $ | 2,262 | $ | 1,889 | $ | 8,990 | ||||||||||||||||
| Total assets |
11,232 | 6,482 | 5,796 | 2,651 | 2,277 | 11,698 | ||||||||||||||||||||||
| Long-term debt, including current portion |
2,120 | 1,762 | 1,568 | 698 | 598 | 2,120 | ||||||||||||||||||||||
| Enable Midstream Partners, LP Partners’ Capital |
8,148 | 3,215 | 2,898 | 8,614 | ||||||||||||||||||||||||
| Enogex LLC Member’s Interest |
1,417 | 1,265 | ||||||||||||||||||||||||||
| Cash Flow Data: |
||||||||||||||||||||||||||||
| Net cash flows provided by (used in): |
||||||||||||||||||||||||||||
| Operating activities |
$ | 648 | $ | 451 | $ | 662 | $ | 316 | $ | 253 | ||||||||||||||||||
| Investing activities |
(140 | ) | (645 | ) | (560 | ) | (508 | ) | (576 | ) | ||||||||||||||||||
| Financing activities |
(400 | ) | 194 | (102 | ) | 189 | 325 | |||||||||||||||||||||
| Other Financial Data: |
||||||||||||||||||||||||||||
| Gross margin |
$ | 1,176 | $ | 823 | $ | 831 | $ | 489 | $ | 441 | $ | 1,322 | $ | 1,326 | ||||||||||||||
| Adjusted EBITDA |
714 | $ | 561 | $ | 570 | $ | 281 | $ | 260 | $ | 779 | $ | 837 | |||||||||||||||
| Distributable cash flow |
$ | 541 | $ | 612 | ||||||||||||||||||||||||
| (1) | Historical limited partners’ interest in net income attributable to Enable Midstream Partners, LP and basic and diluted earnings per unit reflect net income attributable to Enable Midstream Partners, LP subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date. |
| (2) | Historical basic and diluted earnings per common limited partner unit reflects the 1 for 1.279082616 reverse unit split effected on March 25, 2014. |
21
Table of Contents
| Enable Midstream Partners, LP Historical |
Enogex LLC Historical |
Enable Midstream Partners, LP Pro Forma |
||||||||||||||||||||||||||
| Year Ended December 31, |
Year Ended December 31, |
Year Ended December 31, |
||||||||||||||||||||||||||
| 2013 | 2012 | 2011 | 2012 | 2011 | 2013 | 2012 | ||||||||||||||||||||||
| (In millions, except per unit and operating data) |
||||||||||||||||||||||||||||
| Operating Data: |
||||||||||||||||||||||||||||
| Gathered volumes—TBtu |
1,113 | 874 | 794 | 517 | 497 | 1,298 | 1,391 | |||||||||||||||||||||
| Gathered volumes—TBtu/d |
3.05 | 2.39 | 2.17 | 1.41 | 1.36 | 3.56 | 3.80 | |||||||||||||||||||||
| Natural gas processed volumes—TBtu |
397 | 73 | 37 | 357 | 290 | 524 | 430 | |||||||||||||||||||||
| Natural gas processed volumes—TBtu/d |
1.09 | 0.20 | 0.10 | 0.98 | 0.79 | 1.44 | 1.17 | |||||||||||||||||||||
| Total NGLs sold—millions of gallons/d |
1.90 | 0.25 | 0.09 | 2.37 | 1.88 | 2.52 | 2.62 | |||||||||||||||||||||
| Transported volumes—TBtu |
1,608 | 1,378 | 1,596 | 585 | 595 | 1,803 | 1,962 | |||||||||||||||||||||
| Transportation volumes— TBtu/d |
4.48 | 3.76 | 4.37 | 1.60 | 1.63 | 4.94 | 5.36 | |||||||||||||||||||||
| Interstate firm contracted capacity—Bcf/d |
8.01 | 7.94 | 8.12 | — | — | 8.01 | 7.94 | |||||||||||||||||||||
| Intrastate average deliveries—TBtu/d |
1.58 | — | — | 1.60 | 1.63 | 1.59 | 1.60 | |||||||||||||||||||||
22
Table of Contents
We define gross margin as total revenues minus cost of goods sold, excluding depreciation and amortization. We define Adjusted EBITDA as net income from continuing operations before interest expense, income tax expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results. The economic substance behind the use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors. For a discussion of distributable cash flow, please see “Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013.” Gross margin, Adjusted EBITDA and distributable cash flow are supplemental financial measures that management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies may use, to assess:
| • | our operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our partners; |
| • | our ability to incur and service debt and fund capital expenditures; and |
| • | the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities. |
We believe that the presentation of gross margin, Adjusted EBITDA and distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. Gross margin, Adjusted EBITDA and distributable cash flow should not be considered as alternatives to net income, operating income, revenue, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Gross margin, Adjusted EBITDA and distributable cash flow have important limitations as an analytical tool because they exclude some but not all items that affect the most directly comparable GAAP measures. Additionally, because gross margin, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of gross margin, Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
23
Table of Contents
The following table presents a reconciliation of (i) gross margin to revenues, (ii) Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest and (iii) Adjusted EBITDA to net cash provided by operating activities, in each case, the most directly comparable GAAP financial measures, on a historical basis and pro forma basis, as applicable, for each of the periods indicated.
| Enable Midstream Partners, LP Historical |
Enogex LLC Historical |
Enable Midstream Partners, LP Pro Forma |
||||||||||||||||||||||||||
| Year Ended December 31, |
Year
Ended December 31, |
Year
Ended December 31, |
||||||||||||||||||||||||||
| 2013 | 2012 | 2011 | 2012 | 2011 | 2013 | 2012 | ||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| Reconciliation of Gross Margin to Revenues: |
||||||||||||||||||||||||||||
| Revenues |
$ | 2,489 | $ | 952 | $ | 932 | $ | 1,609 | $ | 1,787 | $ | 3,120 | $ | 2,564 | ||||||||||||||
| Cost of goods sold, excluding depreciation and amortization |
1,313 | 129 | 101 | 1,120 | 1,346 | 1,798 | 1,238 | |||||||||||||||||||||
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| Gross margin |
$ | 1,176 | $ | 823 | $ | 831 | $ | 489 | $ | 441 | $ | 1,322 | $ | 1,326 | ||||||||||||||
| Reconciliation of Adjusted EBITDA and distributable cash flow to net income attributable to controlling interest: |
||||||||||||||||||||||||||||
| Net income attributable to controlling interest |
$ | 1,615 | $ | 316 | $ | 232 | $ | 148 | $ | 156 | $ | 451 | $ | 658 | ||||||||||||||
| Add: |
||||||||||||||||||||||||||||
| Depreciation and amortization expense |
212 | 106 | 91 | 109 | 78 | 269 | 273 | |||||||||||||||||||||
| Interest expense, net of interest income |
58 | 64 | 76 | 32 | 23 | 49 | 45 | |||||||||||||||||||||
| Income tax expense (benefit) |
(1,192 | ) | 203 | 163 | — | — | 4 | 3 | ||||||||||||||||||||
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| EBITDA |
$ | 693 | $ | 689 | $ | 562 | $ | 289 | $ | 257 | $ | 773 | $ | 979 | ||||||||||||||
| Add: |
||||||||||||||||||||||||||||
| Impairment |
12 | — | — | — | 6 | 12 | — | |||||||||||||||||||||
| Distributions from equity method affiliates |
24 | 39 | 39 | — | — | 16 | 20 | |||||||||||||||||||||
| Less: |
||||||||||||||||||||||||||||
| Equity in earnings of equity method affiliates |
(15 | ) | (31 | ) | (31 | ) | — | — | (12 | ) | (18 | ) | ||||||||||||||||
| Gain on insurance proceeds |
— | — | — | (8 | ) | (3 | ) | — | (8 | ) | ||||||||||||||||||
| Gain on disposition |
— | — | — | — | — | (10 | ) | — | ||||||||||||||||||||
| Step acquisition gain |
— | (136 | ) | — | — | — | — | (136 | ) | |||||||||||||||||||
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| Adjusted EBITDA |
$ | 714 | $ | 561 | $ | 570 | $ | 281 | $ | 260 | $ | 779 | $ | 837 | ||||||||||||||
| Less: |
||||||||||||||||||||||||||||
| Adjusted interest expense, net |
(61 | ) | (55 | ) | ||||||||||||||||||||||||
| Expansion capital expenditures |
(571 | ) | (912 | ) | ||||||||||||||||||||||||
| Maintenance capital expenditures |
(174 | ) | (167 | ) | ||||||||||||||||||||||||
| Incremental operation and maintenance |
(3 | ) | (3 | ) | ||||||||||||||||||||||||
| Demand fees associated with legacy marketing business loss contracts |
(10 | ) | (10 | ) | ||||||||||||||||||||||||
| Add: |
||||||||||||||||||||||||||||
| Borrowings to fund demand fees associated with legacy marketing business loss contracts |
10 | 10 | ||||||||||||||||||||||||||
| Borrowings for expansion capital expenditures |
|
571 |
|
912 | ||||||||||||||||||||||||
|
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|
|
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| Distributable cash flow |
$ | 541 | $ | 612 | ||||||||||||||||||||||||
24
Table of Contents
| Enable Midstream Partners, LP Historical |
Enogex LLC Historical |
Enable Midstream Partners, LP Pro Forma | ||||||||||||||||||||||
| Year Ended December 31, |
Year Ended December 31, |
Year
Ended December 31, | ||||||||||||||||||||||
| 2013 | 2012 | 2011 | 2012 | 2011 | 2013 | 2012 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Reconciliation of Adjusted EBITDA to net cash provided by operating activities: |
||||||||||||||||||||||||
| Net cash provided by operating activities |
$ | 648 | $ | 451 | $ | 662 | $ | 316 | $ | 253 | ||||||||||||||
| Interest expense, net of interest income |
58 | 64 | 76 | 32 | 23 | |||||||||||||||||||
| Net (income) loss attributable to noncontrolling interest |
3 | — | — | (2 | ) | 1 | ||||||||||||||||||
| Income tax expense (benefit) |
|
(1,192 |
) |
203 | 163 | — | — | |||||||||||||||||
| Deferred income tax (expense) benefit |
1,194 | (196 | ) | (176 | ) | — | — | |||||||||||||||||
| Equity in earnings of equity method affiliates (net of distributions) |
(9 | ) | (8 | ) | (8 | ) | — | — | ||||||||||||||||
| Impairment |
12 | — | — | — | (6 | ) | ||||||||||||||||||
| Step acquisition gain |
— | 136 | — | — | — | |||||||||||||||||||
| Gain on insurance proceeds |
— | 8 | 3 | |||||||||||||||||||||
| Other non-cash items |
— | — | — | (6 | ) | (2 | ) | |||||||||||||||||
| Changes in operating working capital which (provided) used cash: |
||||||||||||||||||||||||
| Accounts receivable |
86 | 8 | (73 | ) | (6 | ) | 5 | |||||||||||||||||
| Accounts payable |
(65 | ) | 6 | (6 | ) | (40 | ) | (3 | ) | |||||||||||||||
| Other, including changes in noncurrent assets and liabilities |
(42 | ) | 25 | (76 | ) | (13 | ) | (17 | ) | |||||||||||||||
|
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| EBITDA |
$ | 693 | $ | 689 | $ | 562 | $ | 289 | $ | 257 | ||||||||||||||
| Add: |
||||||||||||||||||||||||
| Impairment |
12 | — | — | — | 6 | |||||||||||||||||||
| Distributions from equity method affiliates |
24 | 39 | 39 | — | — | |||||||||||||||||||
| Less: |
||||||||||||||||||||||||
| Equity in earnings of equity method affiliates |
(15 | ) | (31 | ) | (31 | ) | — | — | ||||||||||||||||
| Gain on insurance proceeds |
— | — | — | (8 | ) | (3 | ) | |||||||||||||||||
| Step acquisition gain |
— | (136 | ) | — | — | — | ||||||||||||||||||
|
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|
|
|
|
|
|
|
|
|
|||||||||||||||
| Adjusted EBITDA |
$ | 714 | $ | 561 | $ | 570 | $ | 281 | $ | 260 | ||||||||||||||
25
Table of Contents
Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to holders of our common and subordinated units.
In order to pay the minimum quarterly distribution of $0.2875 per unit, or $1.15 per unit on an annualized basis, we will require available cash of approximately $119.5 million per quarter, or $478 million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering and phantom units with distribution equivalent rights that may be granted in connection with this offering to certain key employees that provide services for us pursuant to our long term incentive plan. Please read “Management—2014 Executive Compensation Program—Long Term Incentive Plan.” We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
| • | the fees and gross margins we realize with respect to the volume of natural gas and crude oil that we handle; |
| • | the prices of, levels of production of, and demand for natural gas and crude oil; |
| • | the volume of natural gas and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store; |
| • | the relationship among prices for natural gas, NGLs and crude oil; |
| • | cash calls and settlements of hedging positions; |
| • | margin requirements on open price risk management assets and liabilities; |
| • | the level of competition from other midstream energy companies; |
| • | adverse effects of governmental and environmental regulation; |
| • | the level of our operation and maintenance expenses and general and administrative costs; and |
| • | prevailing economic conditions. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
| • | the level and timing of capital expenditures we make; |
| • | the cost of acquisitions; |
| • | our debt service requirements and other liabilities; |
| • | fluctuations in working capital needs; |
| • | our ability to borrow funds and access capital markets; |
26
Table of Contents
| • | restrictions contained in our debt agreements; |
| • | the amount of cash reserves established by our general partner; and |
| • | other business risks affecting our cash levels. |
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please see “Cash Distribution Policy and Restrictions on Distributions.”
The assumptions underlying the forecast of distributable cash flow that we include under the caption “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.
The forecast of distributable cash flow set forth in “Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and distributable cash flow for the twelve months ending March 31, 2015. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Cash Distribution Policy and Restrictions on Distributions.” Our financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including those discussed in this prospectus, which could cause our Adjusted EBITDA to be materially less than the amount forecasted. If we do not generate the forecasted Adjusted EBITDA, we may not be able to make the minimum quarterly distribution or pay any amount on our common units or subordinated units, and the market price of our common units may decline materially.
Our contracts are subject to renewal risks.
We generate a substantial portion of our gross margins under long-term, fee-based agreements. For the year ended December 31, 2013, on a pro forma basis, approximately 76% of our gross margin was generated from contracts that are fee-based and approximately 50% of our gross margin was attributable to firm contracts or contracts with minimum volume commitment features. As these and other contracts expire, we may have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. For example, depending on prevailing market conditions at the time of a contract renewal, gathering and processing customers with fixed-fee or fixed-margin contracts may desire to enter into contracts under different fee arrangements. To the extent we are unable to renew our existing contracts on terms that are favorable to us, if at all, or successfully manage our overall contract mix over time, our revenue, results of operations and distributable cash flow could be adversely affected.
We depend on a small number of customers for a significant portion of our firm transportation and storage services revenues. The loss of, or reduction in volumes from, these customers could result in a decline in sales of our transportation and storage services and our consolidated financial position, results of operations and our ability to make cash distributions to our unitholders.
We provide firm transportation and storage services to certain key customers on our system. Our major transportation customers are affiliates of CenterPoint Energy, Laclede, OGE Energy, AEP and Exxon. Our interstate transportation and storage assets were designed and built to serve affiliates of CenterPoint Energy, Laclede, OGE Energy and AEP.
Enable-Mississippi River Transmission, LLC’s (MRT) firm transportation and storage contracts with Laclede are scheduled to expire in 2015 and 2016. The primary terms of Enable Gas Transmission, LLC’s (EGT) firm transportation and storage contracts with CenterPoint Energy’s natural gas distribution business will expire in 2018.
27
Table of Contents
Our firm transportation contract with an affiliate of AEP expires January 1, 2015 and will remain in effect from year to year thereafter unless either party provides written notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period. The stated term of the OG&E transportation and storage contract expired April 30, 2009, but the contract remained in effect from year to year thereafter. On January 31, 2014, in anticipation of entering into a new, five-year term contract, OG&E provided written notice of termination of the contract, effective April 30, 2014. On March 17, 2014, we executed a new transportation agreement with OG&E effective May 1, 2014, with a primary term through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.
The loss of all or even a portion of the interstate or intrastate transportation and storage services for any of these customers, the failure to extend or replace these contracts or the extension or replacement of these contracts on less favorable terms, as a result of competition or otherwise, could adversely affect our combined and consolidated financial position, results of operations and our ability to make cash distributions to unitholders.
Our businesses are dependent, in part, on the drilling and production decisions of others.
Our businesses are dependent on the continued availability of natural gas and crude oil production. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, our cash flows associated with wells currently connected to our systems will decline over time. To maintain or increase throughput levels on our gathering and transportation systems and the asset utilization rates at our natural gas processing plants, our customers must continually obtain new natural gas and crude oil supplies. The primary factors affecting our ability to obtain new supplies of natural gas and crude oil and attract new customers to our assets are the level of successful drilling activity near these systems, our ability to compete for volumes from successful new wells and our ability to expand capacity as needed. If we are not able to obtain new supplies of natural gas and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering, processing, transportation and storage facilities would decline, which could have a material adverse effect on our results of operations and distributable cash flow. We have no control over producers or their drilling and production decisions, which are affected by, among other things:
| • | the availability and cost of capital; |
| • | prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil; |
| • | demand for natural gas, NGLs and crude oil; |
| • | levels of reserves; |
| • | geological considerations; |
| • | environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and |
| • | the availability of drilling rigs and other costs of production and equipment. |
Fluctuations in energy prices can also greatly affect the development of new natural gas and crude oil reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of natural gas, crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Because of these factors, even if new natural gas or crude oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Declines in natural gas or crude oil prices can have a negative impact on exploration, development and production activity and, if sustained, could lead to decreases in such activity. A sustained decline could also lead producers to shut in production from their existing wells. Sustained reductions
28
Table of Contents
in exploration or production activity in our areas of operation could lead to further reductions in the utilization of our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Should we determine that the economics of our gathering assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, we may reduce such capital expenditures, which could cause revenues associated with these assets to decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures relative to throughput over time, which will reduce our distributable cash flow.
Because of these and other factors, even if new reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Reductions in drilling activity would result in our inability to maintain the current levels of throughput on our systems and could have a material adverse effect on our results of operations and distributable cash flow.
Our industry is highly competitive, and increased competitive pressure could adversely affect our results of operations and distributable cash flow.
We compete with similar enterprises in our respective areas of operation. The principal elements of competition are rates, terms of service and flexibility and reliability of service. Our competitors include large crude oil, natural gas and petrochemical companies that have greater financial resources and access to supplies of natural gas, NGLs and crude oil than us. Some of these competitors may expand or construct gathering, processing, transportation and storage systems that would create additional competition for the services we provide to our customers. Excess pipeline capacity in the regions served by our interstate pipelines could also increase competition and adversely impact our ability to renew or enter into new contracts with respect to our available capacity when existing contracts expire. In addition, our customers that are significant producers of natural gas may develop their own gathering, processing, transportation and storage systems in lieu of using ours. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and customers. Further, natural gas utilized as a fuel competes with other forms of energy available to end-users, including electricity, coal and liquid fuels. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, processing, transportation and transportation services. All of these competitive pressures could adversely affect our results of operations and distributable cash flow.
We derive a substantial portion of our operating income and cash flow from subsidiaries through which we hold a substantial portion of our assets.
We derive a substantial portion of our operating income and cash flow from, and hold a substantial portion of our assets through, our subsidiaries. As a result, we depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.
Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.
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The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
We may not be able to recover the costs of our substantial planned investment in capital improvements and additions, and the actual cost of such improvements and additions may be significantly higher than we anticipate.
Our business plan calls for extensive investment in capital improvements and additions. We expect that our expansion capital expenditures will be $533 million for the twelve months ending March 31, 2015. For example, we are currently constructing a cryogenic processing plant in Grady County, Oklahoma (the Bradley Plant), which will provide an additional 200 MMcf/d of processing capacity and is expected to be completed in the first quarter of 2015. In addition, we expect to place additional assets in service in 2014 related to our existing crude oil gathering pipeline system, and we recently entered into an agreement to construct a new crude oil gathering system in North Dakota’s Bakken shale formation with a total capacity of up to 30,000 Bbl/d.
The construction of additions or modifications to our existing systems, and the construction of new midstream assets, involves numerous regulatory, environmental, political and legal uncertainties, many of which are beyond our control and may require the expenditure of significant amounts of capital, which may exceed our estimates. These projects may not be completed at the planned cost, on schedule or at all. The construction of new pipeline, gathering, treating, processing, compression or other facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel, labor shortages or weather or other delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner, if at all, or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. Moreover, our revenues and cash flows may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand an existing pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues or cash flows until the project is completed. In addition, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, the new facilities may not be able to achieve our expected investment return, which could adversely affect our results of operations and our ability to make cash distributions to unitholders.
In connection with our capital investments, we may engage a third party to estimate potential reserves in areas to be developed prior to constructing facilities in those areas. To the extent we rely on estimates of future production in deciding to construct additions to our systems, those estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating future production. As a result, new facilities may not be able to attract sufficient throughput to achieve expected investment return, which could adversely affect our results of operations and our ability to make cash distributions to unitholders. In addition, the construction of additions to existing gathering and transportation assets may require new rights-of-way prior to construction. Those rights-of-way to connect new natural gas supplies to existing gathering lines may be unavailable and we may not be able to capitalize on attractive expansion opportunities. Additionally, it may become more expensive to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.
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Natural gas, NGL and crude oil prices are volatile, and changes in these prices could adversely affect our results of operations and our ability to make cash distributions to unitholders.
Our results of operations and our ability to make cash distributions to unitholders could be negatively affected by adverse movements in the prices of natural gas, NGLs and crude oil depending on factors that are beyond our control. These factors include demand for these commodities, which fluctuates with changes in market and economic conditions and other factors, including the impact of seasonality and weather, general economic conditions, the level of domestic and offshore natural gas production and consumption, the availability of imported natural gas, LNG, NGLs and crude oil, actions taken by foreign natural gas and oil producing nations, the availability of local, intrastate and interstate transportation systems, the availability and marketing of competitive fuels, the impact of energy conservation efforts, technological advances affecting energy consumption and the extent of governmental regulation and taxation.
Our keep-whole natural gas processing arrangements, which accounted for 7% of our pro forma natural gas processed volumes in 2013, expose us to fluctuations in the pricing spreads between NGL prices and natural gas prices. Under these arrangements, the processor processes raw natural gas to extract NGLs and pays to the producer the natural gas equivalent Btu value of raw natural gas received from the producer in the form of either processed natural gas or its cash equivalent. The processor is generally entitled to retain the processed NGLs and to sell them for its own account. Accordingly, the processor’s margin is a function of the difference between the value of the NGLs produced and the cost of the processed natural gas used to replace the natural gas equivalent Btu value of those NGLs. Therefore, if natural gas prices increase and NGL prices do not increase by a corresponding amount, the processor has to replace the Btu of natural gas at higher prices and processing margins are negatively affected.
Our percent-of-proceeds and percent-of-liquids natural gas processing agreements accounted for 45% of our natural gas processed volumes on a pro forma basis in 2013. Under these arrangements, the processor generally gathers raw natural gas from producers at the wellhead, transports the natural gas through its gathering system, processes the natural gas and sells the processed natural gas and/or NGLs at prices based on published index prices. The price paid to producers is based on an agreed percentage of the actual proceeds of the sale of processed natural gas, NGLs or both, or the expected proceeds based on an index price. We refer to contracts in which the processor shares in specified percentages of the proceeds from the sale of natural gas and NGLs as “percent-of-proceeds” arrangements, and contracts in which the processor receives proceeds from the sale of a percentage of the NGLs or the NGLs themselves as compensation for processing services as “percent-of-liquids” arrangements. These arrangements expose us to risks associated with the price of natural gas and NGLs.
At any given time, our overall portfolio of processing contracts may reflect a net short position in natural gas (meaning that we are a net buyer of natural gas) and a net long position in NGLs (meaning that we are a net seller of NGLs). As a result, our gross margin could be adversely impacted to the extent the price of NGLs decreases in relation to the price of natural gas.
We have limited experience in the crude oil gathering business.
In November 2013, we commenced initial operations on a new crude oil gathering pipeline system in North Dakota’s Bakken shale formation, and we expect to place additional related assets in service in 2014. The gathering system, located in Dunn and McKenzie Counties in North Dakota, has a planned capacity of up to 19,500 barrels per day. These facilities are the first crude oil gathering system that we have built and operated. In addition, in February 2014, we executed an agreement to gather crude oil production through a new crude oil gathering system with a planned capacity of up to 30,000 Bbl/d in Williams and Mountrail counties in North Dakota that is expected to commence operations in the second quarter of 2015. Other operators of gathering systems in the Bakken shale formation may have more experience in the construction, operation and maintenance of crude oil gathering systems than we do. This relative lack of experience may hinder our ability to fully implement our business plan in a timely and cost efficient manner, which, in turn, may adversely affect our results of operations and our ability to make cash distributions to unitholders.
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We provide certain transportation and storage services under long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
We have been authorized by the Federal Energy Regulatory Commission, or the FERC, to provide transportation and storage services at our facilities at negotiated rates. Generally, negotiated rates are in excess of the maximum recourse rates allowed by the FERC, but it is possible that costs to perform services under “negotiated rate” contracts will exceed the revenues obtained under these agreements. If this occurs, it could decrease the cash flow realized by our systems and, therefore, decrease the cash we have available for distribution to our unitholders.
As of December 31, 2013, approximately 57% of our contracted transportation firm capacity and 43% of our contracted storage firm capacity was subscribed under such “negotiated rate” contracts. These contracts generally do not include provisions allowing for adjustment for increased costs due to inflation, pipeline safety activities or other factors that are not tied to an applicable tracking mechanism authorized by the FERC. Successful recovery of any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, is not assured under current FERC policies.
If third-party pipelines and other facilities interconnected to our gathering, processing or transportation facilities become partially or fully unavailable to us for any reason, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.
We depend upon third-party natural gas pipelines to deliver natural gas to, and take natural gas from, our transportation systems. We also depend on third-party facilities to transport and fractionate NGLs that are delivered to the third party at the tailgates of the processing plants. Fractionation is the separation of the heterogeneous mixture of extracted NGLs into individual components for end-use sale. For example, an outage or disruption on certain pipelines or fractionators operated by a third party could result in the shutdown of certain of our processing plants, and a prolonged outage or disruption could ultimately result in a reduction in the volume of NGLs we are able to produce. Additionally, we depend on third parties to provide electricity for compression at many of our facilities. Since we do not own or operate any of these third-party pipelines or other facilities, their continuing operation is not within our control. If any of these third-party pipelines or other facilities become partially or fully unavailable to us for any reason, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. A loss of these rights, through our inability to renew right-of-way contracts or otherwise, could cause us to cease operations temporarily or permanently on the affected land, increase costs related to the construction and continuing operations elsewhere, and adversely affect our results of operations and our ability to make cash distributions to unitholders.
We conduct a portion of our operations through joint ventures, which subject us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.
We conduct a portion of our operations through joint ventures with third parties, including affiliates of Spectra Energy Corp, DCP Midstream Partners, LP, Trans Louisiana Gas Pipeline, Inc. and Pablo Gathering LLC. We may also enter into other joint venture arrangements in the future. These third parties may have
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obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The performance of these third-party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.
Our joint venture arrangements may involve risks not otherwise present when operating assets directly, including, for example:
| • | our joint venture partners may share certain approval rights over major decisions; |
| • | our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities; |
| • | we may be unable to control the amount of cash we will receive from the joint venture; |
| • | we may incur liabilities as a result of an action taken by our joint venture partners; |
| • | we may be required to devote significant management time to the requirements of and matters relating to the joint ventures; |
| • | our insurance policies may not fully cover loss or damage incurred by both us and our joint venture partners in certain circumstances; |
| • | our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and |
| • | disputes between us and our joint venture partners may result in delays, litigation or operational impasses. |
The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations. The agreements under which we formed certain joint ventures may subject us to various risks, limit the actions we may take with respect to the assets subject to the joint venture and require us to grant rights to our joint venture partners that could limit our ability to benefit fully from future positive developments. Some joint ventures require us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. Certain of our joint venture partners may have substantially greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations our joint venture partners propose, thereby reducing our ability to benefit from the joint venture.
Under certain circumstances, affiliates of Spectra Energy Corp will have the right to purchase an ownership interest in SESH at fair market value.
We own a 24.95% ownership interest in SESH. The remaining 25.05% and 50.0% ownership interests are held by affiliates of CenterPoint Energy and Spectra Energy Corp, respectively. Under the master formation agreement, CenterPoint Energy has certain put rights, and we have certain call rights, exercisable with respect to the interest in SESH retained by CenterPoint Energy, under which CenterPoint Energy would contribute to us its interest in SESH at a price equal to the fair market value of the interest at the time the put right or call right is exercised. Please read “Certain Relationships and Related Party Transactions—Master Formation Agreement—Acquisition of Remaining CenterPoint Energy Interest in SESH.”
Upon completion of this offering, CenterPoint Energy will own a 54.7% limited partner interest in us. Pursuant to the terms of the limited liability company agreement of SESH, as amended (the SESH LLC Agreement), if, at any time, CenterPoint Energy owns less than a 50% economic interest in us, affiliates of
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Spectra Energy Corp will have the right to purchase our 24.95% interest in SESH at fair market value. Affiliates of Spectra Energy Corp will also have a preferential purchase right with respect to any interest in SESH transferred to us by CenterPoint Energy if, at the time such interest is transferred, we are not an “affiliate” of CenterPoint Energy, as such term is defined in the SESH LLC Agreement. Under the master formation agreement, we are entitled to receive the cash consideration related to any exercise of these rights by Spectra Energy Corp or its affiliates.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations and our ability to make cash distributions to unitholders.
Our operations are subject to all of the risks and hazards inherent in the gathering, processing, transportation and storage of natural gas and crude oil, including:
| • | damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties; |
| • | inadvertent damage from construction, vehicles, farm and utility equipment; |
| • | leaks of natural gas, crude oil and other hydrocarbons or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities; |
| • | ruptures, fires and explosions; and |
| • | other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. |
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, plant and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. Our sponsors currently have general liability and property insurance in place to cover certain of our facilities in amounts that they consider appropriate. Such policies are subject to certain limits and deductibles. We do not have business interruption insurance coverage for all of our operations. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations and our ability to make cash distributions to unitholders.
The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and our ability to make cash distributions to unitholders.
We and our subsidiaries periodically use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Failure to attract and retain an appropriately qualified workforce could adversely impact our results of operations.
As of December 31, 2013, we did not have any direct employees. All of the individuals providing services to us as of that date were doing so as seconded employees by OGE Energy and CenterPoint Energy or pursuant to
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services agreements with OGE Energy or CenterPoint Energy. On or prior to December 31, 2014, we will provide offers of employment to those seconded employees that we determine to hire. Employees of OGE Energy and CenterPoint Energy that we determine to hire are under no obligation to accept our offer of employment on the terms we provide, or at all.
Our business is dependent on our ability to recruit, retain and motivate employees. Certain circumstances, such as an aging workforce without appropriate replacements, a mismatch of existing skill sets to future needs, competition for skilled labor or the unavailability of contract resources may lead to operating challenges such as a lack of resources, loss of knowledge or a lengthy time period associated with skill development. Our costs, including costs for contractors to replace employees, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate our business.
If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.
Our ability to grow is dependent on our ability to access external financing sources.
We expect that our operating subsidiaries will distribute all of their available cash to us and that we will distribute all of our available cash to our unitholders. As a result, we expect that we and our operating subsidiaries will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As a result, to the extent we or our operating subsidiaries are unable to finance growth externally, our and our operating subsidiaries’ cash distribution policy will significantly impair our and our operating subsidiaries’ ability to grow. In addition, because we and our operating subsidiaries distribute all available cash, our and our operating subsidiaries’ growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.
To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt by us or our operating subsidiaries to finance our growth strategy would result in increased interest expense, which in turn may negatively impact the available cash that our operating subsidiaries have to distribute to us, and that we have to distribute to our unitholders.
If we do not make acquisitions or are unable to make acquisitions on economically acceptable terms, our future growth will be limited.
Our ability to grow depends, in part, on the ability to make acquisitions that result in an increase in our cash generated from operations. If we are unable to make these accretive acquisitions either because: (i) we are unable to identify attractive acquisition targets or we are unable to negotiate purchase contracts on acceptable terms, (ii) we are unable to obtain acquisition financing on economically acceptable terms, or (iii) we are outbid by competitors, then our future growth and ability to increase distributions will be limited.
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Our merger and acquisition activities may not be successful or may result in completed acquisitions that do not perform as anticipated.
From time to time, we have made, and we intend to continue to make, acquisitions of businesses and assets. Such acquisitions involve substantial risks, including the following:
| • | acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels; |
| • | acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate; |
| • | we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited; |
| • | we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and |
| • | acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures. |
Our and our operating subsidiaries’ debt levels may limit our and their flexibility in obtaining additional financing and in pursuing other business opportunities.
As of December 31, 2013, we had approximately $1.9 billion of long-term debt outstanding and $200 million of short-term debt outstanding, excluding the premiums on senior notes. We have $363 million of long-term notes payable-affiliated companies due to CenterPoint Energy. We have a $1.4 billion revolving credit facility for working capital, capital expenditures and other partnership purposes, including acquisitions, of which $1.1 billion was available as of December 31, 2013. As of January 2014, we had the ability to issue up to $1.4 billion in commercial paper, subject to available borrowing capacity under our revolving credit facility and market conditions, to manage the timing of cash flows and fund short-term working capital deficits. As of February 28, 2014, $430 million was outstanding under our commercial paper program. Following this offering, we will continue to have the ability to incur additional debt, subject to limitations in our credit facilities. The levels of our debt could have important consequences, including the following:
| • | the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all; |
| • | a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions; |
| • | our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and |
| • | our debt level may limit our flexibility in responding to changing business and economic conditions. |
Our and our operating subsidiaries’ ability to service our and their debt will depend upon, among other things, their future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our and their control. If operating results are not sufficient to service our or our operating subsidiaries’ current or future indebtedness, we and they may be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. These actions may not be effected on satisfactory terms, or at all. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
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Our credit facilities contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our control, which could adversely affect our business, financial condition, results of operations and ability to make quarterly distributions to our unitholders.
Our credit facilities contain customary covenants that, among other things, limit our ability to:
| • | permit our subsidiaries to incur or guarantee additional debt; |
| • | incur or permit to exist certain liens on assets; |
| • | dispose of assets; |
| • | merge or consolidate with another company or engage in a change of control; |
| • | enter into transactions with affiliates on non-arm’s length terms; and |
| • | change the nature of our business. |
Our credit facilities also require us to maintain certain financial ratios. Our ability to meet those financial ratios can be affected by events beyond our control, and we cannot assure you that we will meet those ratios. In addition, our credit facilities contain events of default customary for agreements of this nature.
Our ability to comply with the covenants and restrictions contained in our credit facilities may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facilities, a significant portion of our indebtedness may become immediately due and payable. In addition, our lenders’ commitments to make further loans to us under the revolving credit facility may be suspended or terminated. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Affiliates of our general partner, including OGE Energy and CenterPoint Energy, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.
Under our omnibus agreement, OGE Energy, CenterPoint Energy and their affiliates have agreed to hold or otherwise conduct all of their respective midstream operations located within the United States through us. This requirement will cease to apply to both OGE Energy and CenterPoint Energy as soon as either OGE Energy or CenterPoint Energy ceases to hold any interest in our general partner or at least 20% of our common units. In addition, if OGE Energy or CenterPoint Energy acquires any assets or equity of any person engaged in midstream operations with a value in excess of $50 million (or $100 million in the aggregate with such party’s other acquired midstream operations that have not been offered to us), the acquiring party will be required to offer to us such assets or equity for such value. If we do not purchase such assets, the acquiring party will be free to retain and operate such midstream assets, so long as the value of the assets does not reach certain thresholds.
As a result, under the circumstances described above, OGE Energy and CenterPoint Energy have the ability to construct or acquire assets that directly compete with our assets. Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and OGE Energy and CenterPoint Energy. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders. Please read “Conflicts of Interest and Fiduciary Duties.”
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If our general partner fails to develop or maintain an effective system of internal controls, then we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.
Our general partner has sole responsibility for conducting our business and for managing our operations. Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective internal controls are necessary for our general partner, on our behalf, to provide reliable financial reports, prevent fraud and operate us successfully as a public company. If our general partner’s efforts to maintain its internal controls are not successful, it is unable to maintain adequate controls over our financial processes and reporting in the future or it is unable to assist us in complying with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed or we may fail to meet our reporting obligations. Ineffective internal controls also could cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
We rely on executive officers of our general partner and employees of OGE Energy and CenterPoint Energy for the success of our and our subsidiaries’ businesses.
Certain of the executive officers of our general partner are employees of OGE Energy or CenterPoint Energy. We have entered into services agreements with OGE Energy and CenterPoint Energy pursuant to which OGE Energy and CenterPoint Energy perform administrative services for us such as legal, accounting, treasury, finance, investor relations, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, facilities, fleet management and media services. Affiliates of OGE Energy and CenterPoint Energy conduct businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of the executive officers and employees of OGE Energy and CenterPoint Energy who provide services to our general partner. If the executive officers of our general partner and the employees of OGE Energy and CenterPoint Energy do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make cash distributions may be impaired.
Cyber-attacks, acts of terrorism or other disruptions could adversely impact our results of operations and our ability to make cash distributions to unitholders.
We are subject to cyber-security risks related to breaches in the systems and technology that we use (i) to manage our operations and other business processes and (ii) to protect sensitive information maintained in the normal course of our businesses. The gathering, processing and transportation of natural gas from our gathering, processing and pipeline facilities are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities. Disruption of those communications, whether caused by physical disruption such as storms or other natural phenomena, by failure of equipment or technology, or by manmade events, such as cyber-attacks or acts of terrorism, may disrupt our ability to deliver natural gas and control these assets. Cyber-attacks could also result in the loss of confidential or proprietary data or security breaches of other information technology systems that could disrupt our operations and critical business functions, adversely affect our reputation, and subject us to possible legal claims and liability. We are not fully insured against all cyber-security risks, any of which could have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders. In addition, our natural gas pipeline systems may be targets of terrorist activities that could disrupt our ability to conduct our business and have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
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We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Performance of our operations require that we obtain and maintain a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approval limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval limit or standard. Noncompliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. A decision by a government agency to deny or delay the issuance of a new or existing material permit or other approval, or to revoke or substantially modify an existing permit or other approval, could adversely affect our ability to initiate or continue operations at the affected location or facility and on our financial condition, results of operations and cash flows.
Additionally, in order to obtain permits and renewals of permits and other approvals in the future, we may be required to prepare and present data to governmental authorities pertaining to the potential adverse impact that any proposed pipeline or processing-related activities may have on the environment, individually or in the aggregate, including on public and Indian lands. Certain approval procedures may require preparation of archaeological surveys, endangered species studies and other studies to assess the environmental impact of new sites or the expansion of existing sites. Compliance with these regulatory requirements is expensive and significantly lengthens the time required to prepare applications and to receive authorizations.
Costs of compliance with existing environmental laws and regulations are significant, and the cost of compliance with future environmental laws and regulations may adversely affect our results of operations and our ability to make cash distributions to unitholders.
We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, wildlife conservation, natural resources and health and safety that could, among other things, delay or increase our costs of construction, restrict or limit the output of certain facilities and/or require additional pollution control equipment and otherwise increase costs. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations and those costs may be even more significant in the future.
There is inherent risk of the incurrence of environmental costs and liabilities in our operations due to our handling of natural gas, NGLs and crude oil, air emissions related to our operations and historical industry operations and waste disposal practices. These activities are subject to stringent and complex federal, state and local laws and regulations governing environmental protection, including the discharge of materials into the environment and the protection of plants, wildlife, and natural and cultural resources. These laws and regulations can restrict or impact our business activities in many ways, such as restricting the way we can handle or dispose of wastes or requiring remedial action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may be unable to recover these costs from insurance. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase compliance costs and the cost of any remediation that may become necessary. Further, stricter requirements could negatively impact our customers’ production and operations, resulting in less demand for our services. Please see “Business—Environmental Matters.”
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Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely affect our results of operations and our ability to make cash distributions to unitholders.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Many of our customers commonly use hydraulic fracturing techniques in their drilling and completion programs. Hydraulic fracturing typically is regulated by state oil and natural gas commissions. In addition, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act (SDWA) and to require disclosure of the chemicals used in the hydraulic fracturing process. Some states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers operate, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, some or all of which activities could adversely affect demand for our services to those customers.
In addition, certain governmental reviews have been conducted or are underway that focus on environmental aspects of hydraulic fracturing practices. The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review by 2014. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. President Obama created the Interagency Working Group on Unconventional Natural Gas and Oil by Executive Order on April 13, 2012, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources, including hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.
Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.
Because our operations emit various types of greenhouse gases, legislation and regulations governing greenhouse gas emissions could increase our costs related to operating and maintaining our facilities, and could delay future permitting. At the federal level, the U.S. Congress has in the past and may in the future consider legislation to reduce emissions of greenhouse gases. On September 22, 2009, the EPA issued a rule requiring nation-wide reporting of greenhouse gas emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Subsequently, on November 30, 2010, the EPA issued a supplemental rulemaking that expanded the types of industrial sources that are subject to or potentially subject to EPA’s mandatory greenhouse gas emissions reporting requirements to include petroleum and natural gas systems. On May 13, 2010, the EPA issued the “tailoring rule,” which served to increase the greenhouse gas emissions threshold that triggers the permitting requirements for major new (and major modifications to existing) stationary sources. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons
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per year or more of carbon dioxide equivalent (CO2e) and existing facilities making changes that would increase greenhouse gas emissions by 75,000 CO2e. The EPA has also indicated in rulemakings that it may further reduce the current regulatory thresholds for greenhouse gas emissions, making additional sources subject to permitting. On June 26, 2012, in Coalition for Responsible Regulation v. EPA, the U.S. Circuit Court of Appeals for the District of Columbia circuit upheld the bases for the tailoring rule, and ruled that no petitioners had standing to challenge it. On October 15, 2013, the U.S. Supreme Court granted a petition for a writ of certiorari to review the appellate court’s decision.
In addition, more than one-third of the states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap-and-trade programs. Although many of the state-level initiatives have, to date, focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that in the future other sources of greenhouse gas emissions, such as our gas-fired compressors, could become subject to greenhouse gas-related state regulations. Depending on the particular program, we could in the future be required to purchase and surrender emission allowances or otherwise undertake measures to reduce greenhouse gas emissions. Any additional costs or operating restrictions associated with new legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for our services.
Increased regulatory-imposed costs may increase the cost of consuming, and thereby reduce demand for, the products that we gather, treat and transport. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this view could negatively affect our ability to access capital markets or cause us to receive less favorable terms and conditions. Consequently, legislation and regulatory initiatives aimed at reducing greenhouse gases could have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders.
Our operations are subject to extensive regulation by federal regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our results of operations and our ability to make cash distributions to unitholders.
The rates charged by several of our pipeline systems, including for interstate gas transportation service provided by our intrastate pipelines, are regulated by the FERC. The FERC and state regulatory agencies also regulate other terms and conditions of the services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose or offer, the profitability of our pipeline businesses could suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which could also limit our profitability. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders.
Our natural gas interstate pipelines are regulated by the FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or the NGPA, and the Energy Policy Act of 2005, or EPAct of 2005. Generally, the FERC’s authority over interstate natural gas transportation extends to:
| • | rates, operating terms, conditions of service and service contracts; |
| • | certification and construction of new facilities; |
| • | extension or abandonment of services and facilities or expansion of existing facilities; |
| • | maintenance of accounts and records; |
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| • | acquisition and disposition of facilities; |
| • | initiation and discontinuation of services; |
| • | depreciation and amortization policies; |
| • | conduct and relationship with certain affiliates; |
| • | market manipulation in connection with interstate sales, purchases or natural gas transportation; and |
| • | various other matters. |
The FERC’s jurisdiction extends to the certification and construction of interstate transportation and storage facilities, including, but not limited to expansions, lateral and other facilities and abandonment of facilities and services. Prior to commencing construction of significant new interstate transportation and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or an order amending its existing certificate, from the FERC. Certain minor expansions are authorized by blanket certificates that the FERC has issued by rule. Typically, a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any failure by an agency to issue sufficient authorizations or permits in a timely manner for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Our inability to obtain sufficient permits and authorizations in a timely manner could materially and negatively impact the additional revenues expected from these projects.
The FERC conducts audits to verify compliance with the FERC’s regulations and the terms of its orders, including whether the websites of interstate pipelines accurately provide information on the operations and availability of services. The FERC’s regulations require uniform terms and conditions for service, as set forth in agreements for transportation and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the standard form of service agreements set forth in the pipeline’s FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.
The rates, terms and conditions for transporting natural gas in interstate commerce on certain of our intrastate pipelines and for services offered at certain of our storage facilities are subject to the jurisdiction of the FERC under Section 311 of the NGPA. Rates to provide such interstate transportation service must be “fair and equitable” under the NGPA and are subject to review, refund with interest if found not to be fair and equitable, and approval by the FERC at least once every five years.
Our crude oil gathering pipelines are subject to common carrier regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain tariffs on file with the FERC setting forth the rates we charge for providing transportation services, as well as the rules and regulations governing such services. The ICA requires, among other things, that our rates must be “just and reasonable” and that we provide service in a manner that is nondiscriminatory.
Our operations may also be subject to regulation by state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could adversely affect our results of operations and our ability to make cash distributions to unitholders.
Our pipeline operations that are not regulated by the FERC may be subject to state and local regulation applicable to intrastate natural and transportation services. The relevant states in which we operate include North Dakota, Oklahoma, Arkansas, Louisiana, Texas, Missouri, Kansas, Mississippi, Tennessee and Illinois. State and local regulations generally focus on safety, environmental and, in some circumstances, prohibition of undue
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discrimination among shippers. Additional rules and legislation pertaining to these matters are considered and, in some instances, adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes. Other state and local regulations also may affect our business. Any such state or local regulation could have an adverse effect on our business and the results of our operations.
Our gathering lines may be subject to ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to access to oil and natural gas gathering pipelines and rate discrimination.
Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for processing, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines are currently subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the regulatory status of a line, or the rates, terms and conditions of a gathering line providing transportation service.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Our natural gas gathering and intrastate transportation operations are generally exempt from the jurisdiction of the FERC under the NGA, but FERC regulation may indirectly impact these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the intrastate natural gas transportation business. Although the FERC has not made a formal determination with respect to all of our facilities we consider to be gathering facilities, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.
Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation
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of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
We may incur significant costs and liabilities resulting from pipeline integrity and other similar programs and related repairs.
The U.S. Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas,” which are those areas where a leak or rupture could do the most harm. The regulations require operators, including us, to, among other things:
| • | develop a baseline plan to prioritize the assessment of a covered pipeline segment; |
| • | identify and characterize applicable threats that could impact a high consequence area; |
| • | improve data collection, integration, and analysis; |
| • | repair and remediate pipelines as necessary; and |
| • | implement preventive and mitigating action. |
Although many of our pipelines fall within a class that is currently not subject to these requirements, we may incur significant cost and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt pipelines. This work is part of our normal integrity management program and we do not expect to incur any extraordinary costs during 2013 or 2014 to complete the testing required by existing DOT regulations and their state counterparts. We have not estimated the costs for any repair, remediation, preventive or mitigation actions that may be determined to be necessary as a result of the testing program, which could be substantial, or any lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Should we fail to comply with DOT or comparable state regulations, we could be subject to penalties and fines. Also, as addressed in the “Business—Safety and Health Regulation,” the scope of the integrity management program and other related pipeline safety programs could be expanded in the future. We have not estimated the cost of complying with such future requirements.
The adoption of financial reform legislation by the United States Congress could adversely affect our ability to use derivative instruments to hedge risks associated with our business.
At times, we may hedge all or a portion of our commodity risk and our interest rate risk. The United States Congress adopted comprehensive financial reform legislation that changed federal oversight and regulation of the derivatives markets and entities, including businesses like ours, that participate in those markets. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the legislation. In its rulemaking under the Dodd-Frank Act, the CFTC adopted regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, but these rules were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. The CFTC appealed this ruling, but subsequently withdrew its appeal. In December 2013, the CFTC published a Notice of Proposed Rulemaking designed to implement new position limits regulation. The ultimate form and timing of the implementation of the regulatory regime affecting commodity derivatives remains uncertain. However, reporting obligations for transactions involving non-financial swap counterparties such as us began on July 1, 2013 with regard to interest rate swaps and August 19, 2013 with regard to other commodity swaps such as natural gas swap products.
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Under final rules adopted by the CFTC, we believe our hedging transactions will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing requirement, where the counterparty such as us has a required identification number, is not a financial entity as defined by the regulations, and meets a minimum asset test. The Dodd-Frank Act may also require us to comply with margin requirements in connection with our hedging activities, although the application of those provisions to us is uncertain at this time. The Dodd-Frank Act may also require the counterparties to our derivative instruments to spin off some of their hedging activities to a separate entity, which may not be as creditworthy as the current counterparty.
The Dodd-Frank Act and related regulations could significantly increase the cost of derivatives contracts for our industry (including requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties, particularly if we are unable to utilize the commercial end user exception with respect to certain of our hedging transactions. If we reduce our use of hedging as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and fund unitholder distributions. Finally, the legislation was intended, in part, to reduce the volatility of crude oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to crude oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could adversely affect our results of operations and our ability to make cash distributions to unitholders.
Risks Related to an Investment in Us
Our general partner and its affiliates, including OGE Energy and CenterPoint Energy, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our other common unitholders.
Following this offering, affiliates of OGE Energy and CenterPoint Energy will continue to own and control our general partner and will continue to appoint all of the officers and directors of our general partner. Some of the initial officers and a majority of the initial directors of our general partner are also officers and/or directors of OGE Energy or CenterPoint Energy. Although our general partner has a duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to OGE Energy and CenterPoint Energy. Conflicts of interest will arise between OGE Energy, CenterPoint Energy and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of OGE Energy and CenterPoint Energy over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
| • | Neither our partnership agreement nor any other agreement requires OGE Energy or CenterPoint Energy to pursue a business strategy that favors us. The directors and officers of OGE Energy and CenterPoint Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. OGE Energy and CenterPoint Energy may choose to shift the focus of their investment and growth to areas not served by our assets. |
| • | Our general partner is allowed to take into account the interests of parties other than us, such as OGE Energy and CenterPoint Energy, in resolving conflicts of interest. |
| • | Some of the officers and a majority of the initial directors of our general partner are also officers and/or directors of OGE Energy or CenterPoint Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of OGE Energy and CenterPoint Energy. |
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| • | Our partnership agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty. |
| • | Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval. |
| • | Disputes may arise under our commercial agreements with OGE Energy and CenterPoint Energy. |
| • | Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow. |
| • | Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units. |
| • | Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. |
| • | Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period. |
| • | Our partnership agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. |
| • | Our general partner intends to limit its liability regarding our contractual and other obligations. |
| • | Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. |
| • | Our general partner controls the enforcement of the obligations that it and its affiliates owe to us. |
| • | Our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
| • | Our general partner may transfer its incentive distribution rights without unitholder approval. |
| • | Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations. |
Please read “Conflicts of Interest and Fiduciary Duties.”
If you are not an Eligible Holder, your common units may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are limited partners whose (i) federal income tax status is not reasonably
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likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (ii) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read “The Partnership Agreement—Ineligible Holders; Redemption.”
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in our credit facilities that limit our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
The reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our distributable cash flow. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including OGE Energy and CenterPoint Energy, for costs and expenses they incur and payments they make on our behalf. Pursuant to services agreements we have entered into with each of OGE Energy and CenterPoint Energy, we will reimburse OGE Energy and CenterPoint Energy for the payment of operating expenses related to our operations and for the provision of various general and administrative services performed for our benefit. Payments for these services may be substantial and will reduce the amount of distributable cash flow. Additionally, we will reimburse OGE Energy and CenterPoint Energy for direct or allocated costs and expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. We also expect to incur approximately $3 million of incremental annual operation and maintenance expense as a result of being a publicly traded partnership. Please read “Certain Relationships and Related Party Transactions—Omnibus Agreement.” Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read “Cash Distribution Policy and Restrictions on Distributions.”
Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.
We cannot assure you that our credit ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Any future downgrade could increase the cost of short-term borrowings or prevent us from accessing the commercial paper markets. Any downgrade could also lead to higher borrowing costs and, if below
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investment grade, could require us or our subsidiaries to post cash collateral under our shipping or hedging arrangements or in order to purchase natural gas or letters of credit. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, our results of operations and our ability to make cash distributions to unitholders could be adversely affected.
The credit and business risk profiles of our general partner, OGE Energy and CenterPoint Energy could adversely affect our credit ratings and profile.
The credit and business risk profiles of our general partner, OGE Energy and CenterPoint Energy may be factors in credit evaluations of a master limited partnership because our general partner can exercise control over our business activities, including our cash distribution and acquisition strategy and business risk profile. Other factors that may be considered are the financial conditions of our general partner, OGE Energy and CenterPoint Energy, including the degree of their financial leverage and their dependence on cash flows from us to service their indebtedness.
OGE Energy and CenterPoint Energy, which indirectly own our general partner, have indebtedness outstanding and are partially dependent on the cash distributions from their general partner and limited partner interests in us to service such indebtedness and pay dividends on their common stock. Any distributions by us to such entities will be made only after satisfying our then-current obligations to our creditors. Our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of the entities that control our general partner were viewed as substantially lower or more risky than ours.
Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:
| • | how to allocate corporate opportunities among us and its other affiliates; |
| • | whether to exercise its limited call right; |
| • | whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner; |
| • | whether to elect to reset target distribution levels; |
| • | whether to transfer the incentive distribution rights to a third party; and |
| • | whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Duties of the General Partner.”
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Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
| • | whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of our partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
| • | our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith; |
| • | our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
| • | our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is: |
| • | approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; |
| • | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; |
| • | determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | determined by the board of directors of our general partner to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner or the conflicts committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the third and fourth subbullets above, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”
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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the minimum quarterly distribution and the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right, at any time when there are no subordinated units outstanding, if it has received incentive distributions at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters and the amount of each such distribution did not exceed the adjusted operating surplus for such quarter, respectively, to reset the initial minimum quarterly distribution and cash target distribution levels at higher levels based on the average cash distribution amount per common unit for the two fiscal quarters prior to the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the reset minimum quarterly distribution) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash—General Partner Interest and Incentive Distribution Rights.”
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. Because OGE Energy and CenterPoint Energy collectively indirectly own 100% of our general partner, the board of directors of our general partner has been, and, as long as OGE Energy and CenterPoint Energy own 100% of our general partner, will continue to be, chosen by OGE Energy and CenterPoint Energy. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Please see “—Even if holders of our common units are dissatisfied, they will not initially be able to remove our general partner without its consent.” As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
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Even if holders of our common units are dissatisfied, they will not initially be able to remove our general partner without its consent.
The unitholders initially will be unable to remove our general partner without its consent because affiliates of our general partner will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 75% of all outstanding units voting together as a single class is required to remove our general partner. Following the closing of this offering, affiliates of our general partner will own 81.4% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. “Cause” does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing us will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Our general partner’s interest in us and control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Although the limited liability company agreement of our general partner restricts the ability of OGE Energy and CenterPoint Energy to transfer their ownership of their respective limited liability company interest in our general partner until May 1, 2016, our partnership agreement does not restrict the ability of the owners of our general partner from transferring all or a portion of their respective limited liability company interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and executive officers.
The incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of OGE Energy or CenterPoint Energy selling or contributing additional assets to us, as they would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
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You will experience immediate and substantial dilution in pro forma net tangible book value of $2.77 per common unit.
The assumed initial public offering price of $20.00 per unit (the midpoint of the price range set forth on the cover page of this prospectus) exceeds our pro forma net tangible book value of $17.23 per unit. Based on the assumed initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $2.77 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please see “Dilution.”
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
| • | our existing unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of distributable cash flow on each unit may decrease; |
| • | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
| • | because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of the common units may decline. |
Please read “Certain Relationships and Related Party Transactions—Master Formation Agreement—Acquisition of Remaining CenterPoint Energy Interest in SESH” for a description of certain additional common units that may be issued to CenterPoint Energy in connection with our acquisition of additional interests in SESH.
Affiliates of our general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units.
Upon the completion of this offering, subsidiaries of OGE Energy and CenterPoint Energy will hold an aggregate of 130,636,200 common units and 207,855,430 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier under certain circumstances. In addition, we have agreed to provide OGE Energy, CenterPoint Energy and ArcLight with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price, as calculated pursuant to the terms of the partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax
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liability upon a sale of your units. Upon the completion of this offering, affiliates of our general partner will own approximately 62.8% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), affiliates of our general partner will own approximately 81.4% of our aggregate outstanding common units. Affiliates of our general partner may acquire additional common units from us in connection with future transactions or through open-market or negotiated purchases. For additional information about this right, please see “The Partnership Agreement—Limited Call Right.”
Your liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we may do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:
| • | we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
| • | your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business. |
For a discussion of the implications of the limitations of liability on a unitholder, please see “The Partnership Agreement—Limited Liability.”
Our partnership agreement will designate the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.
Our partnership agreement will provide, that, with certain limited exceptions, the Court of Chancery of the State of Delaware will be the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty (including a fiduciary duty) owed by any of our, or our general partner’s, directors, officers, or other employees, or owed by our general partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. Although we believe this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our general partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations and our ability to make cash distributions to our unitholders.
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The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We have been approved to list our common units on the NYSE, subject to official notice of issuance. Because we will be a publicly traded limited partnership, the NYSE does not require us to have, and we do not intend to have, a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management.”
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, which we refer to herein as the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for both the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of transfer and for unknown obligations if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are non-recourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
An increase in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.
Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price of our common units is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue additional equity to make acquisitions or for other purposes and our ability to make cash distributions at our intended levels.
There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. Following this offering, the market price of our common units may fluctuate significantly, and you could lose all or part of your investment.
Prior to this offering, there has been no public market for our common units. After this offering, there will be only 25,000,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above
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the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.
The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:
| • | the level of our quarterly distributions; |
| • | our quarterly or annual earnings or those of other companies in our industry; |
| • | the loss of a large customer or contract; |
| • | announcements by us or our competitors of significant contracts or acquisitions; |
| • | changes in accounting standards, policies, guidance, interpretations or principles; |
| • | general economic conditions; |
| • | the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts; |
| • | future sales of our common units; and |
| • | other factors described in these “Risk Factors.” |
We will incur increased costs as a result of being a publicly traded partnership.
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and possibly to result in our general partner having to accept reduced policy limits and coverage. We have included $3 million of estimated annual incremental costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus, some of which will be allocated to us by OGE Energy and CenterPoint Energy and their affiliates. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
Tax Risks to Common Unitholders
In addition to reading the following risk factors, you should read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
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Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, or IRS, on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our distributable cash flow to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of such additional tax on us by a state will reduce the distributable cash flow. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. Please read “Material Federal Income Tax Consequences—Partnership Status.” We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
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Our unitholders’ share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Because a unitholder will be treated as a partner to whom we will allocate taxable income which could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our distributable cash flow to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash flow to our unitholders.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of your common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.
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We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We will prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Our counsel has not rendered an opinion with respect to our monthly convention for allocating taxable income and losses. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.
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We will adopt certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, OGE Energy, CenterPoint and ArcLight will in the aggregate indirectly own more than 50% of the total interests in our capital and profits. Therefore, transfers and transfers deemed to occur for tax purposes by OGE Energy, CenterPoint or ArcLight or their affiliates of all or a portion of their respective interests in us could result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year if the termination occurs on a day other than December 31 and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read “Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.
As a result of investing in our common units, you will likely become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the
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various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We will initially own property or conduct business in a number of states, most of which currently impose a personal income tax on individuals, and most of which also impose an income or similar tax on corporations and certain other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose an income tax or similar tax. In certain states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent tax years. Some states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholders’ income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. It is your responsibility to file all U.S. federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.
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We expect to receive net proceeds from this offering of approximately $466 million, after deducting underwriting discounts and commissions, the structuring fee and offering expenses. We base this amount on an assumed initial public offering price of $20.00 per common unit. We intend to use:
| • | approximately $453 million of the net proceeds of this offering for general partnership purposes, including the funding of expansion capital expenditures; and |
| • | approximately $13 million of the net proceeds of this offering to pre-fund demand fees expected to be incurred over the next three years relating to certain expiring transportation and storage contracts. |
Pending application of the net proceeds as described in the bullets above, we may temporarily pay down debt outstanding under our commercial paper program and revolving credit facility. We utilize our revolving credit facility and commercial paper program to manage the timing of cash flows and fund short-term working capital deficits. As of February 28, 2014, $430 million was outstanding under our commercial paper program, with a weighted average interest rate of 0.90%, and there were no other outstanding borrowings under our revolving credit facility. Our revolving credit facility matures in May 2018.
ArcLight, the selling unitholder, has granted the underwriters a 30-day option to purchase up to an aggregate of 3,750,000 additional common units to the extent the underwriters sell more than 25,000,000 common units in this offering. We will not receive any proceeds from the sale of common units by the selling unitholder pursuant to any exercise of the underwriters’ option to purchase additional common units. The selling unitholder may be deemed under federal securities laws to be an underwriter with respect to the common units it may sell in connection with this offering. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to 28,750,000 common units, representing an aggregate 6.9% limited partner interest in us.
The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of each of the underwriters are lenders under our revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through any repayment of borrowings outstanding under our revolving credit facility pending the application of the net proceeds as described above. Please read “Underwriting.”
An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions, the structuring fee and offering expenses, to increase or decrease, respectively, by $24 million.
The number of common units offered to the public in this offering may be increased or decreased. Each increase of 1,000,000 common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $20.00 per common unit, would increase net proceeds to us from this offering by approximately $43 million. Similarly, each decrease of 1,000,000 common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $20.00 per common unit, would decrease the net proceeds to us from this offering by approximately $41 million. To the extent there is an increase or decrease in the net proceeds we receive from this offering, we will apply the net proceeds for general partnership purposes.
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The following table shows:
| • | our historical cash and cash equivalents and capitalization as of December 31, 2013 after the 1 for 1.279082616 reverse unit split effected on March 25, 2014; and |
| • | our pro forma cash and cash equivalents and capitalization as of December 31, 2013 after giving effect to this offering and the application of the net proceeds therefrom as described under “Use of Proceeds.” |
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
| As of December 31, 2013 | ||||||||
| Historical | Pro Forma(1) | |||||||
| (In millions, except unit amounts) | ||||||||
| Cash and cash equivalents |
$ | 108 | $ | 574 | ||||
|
|
|
|
|
|||||
| Total debt (including current portion and notes payable—affiliated companies) |
||||||||
| Term Loan Facility |
$ | 1,050 | $ | 1,050 | ||||
| Revolving Credit Facility(2) |
333 | 333 | ||||||
| Long-term notes payable—affiliated companies |
363 | 363 | ||||||
| Enable Oklahoma Term Loan |
250 | 250 | ||||||
| Enable Oklahoma 6.875% senior notes due 2014 |
200 | 200 | ||||||
| Enable Oklahoma 6.25% senior notes due 2020 |
250 | 250 | ||||||
| Premium on Enable Oklahoma senior notes |
37 | 37 | ||||||
|
|
|
|
|
|||||
| Total debt (including current portion and notes payable—affiliated companies) |
$ | 2,483 | $ | 2,483 | ||||
| Partners’ Capital: |
||||||||
| Enable Midstream Partners, LP Partners’ Capital: |
||||||||
| Held by public: |
||||||||
| Common (— and 25,691,500 units)(3) |
$ | — | $ | 466 | ||||
| Held by OGE Energy: |
||||||||
| Common (110,982,805 and 42,832,291 units) |
2,319 | 895 | ||||||
| Subordinated (— and 68,150,514 units) |
— | 1,424 | ||||||
| Held by CenterPoint Energy: |
||||||||
| Common (227,508,825 and 87,803,909 units) |
4,753 | 1,834 | ||||||
| Subordinated (— and 139,704,916 units) |
— | 2,919 | ||||||
| Held by ArcLight: |
||||||||
| Common (51,527,730 and 51,527,730 units) |
1,076 | 1,076 | ||||||
|
|
|
|
|
|||||
| Total Enable Midstream Partners, LP Partners’ Capital: |
$ | 8,148 | $ | 8,614 | ||||
|
|
|
|
|
|||||
| Noncontrolling interest |
33 | 33 | ||||||
|
|
|
|
|
|||||
| Total partners’ capital |
8,181 | 8,647 | ||||||
|
|
|
|
|
|||||
| Total capitalization |
$ | 10,664 | $ | 11,130 | ||||
|
|
|
|
|
|||||
| (1) | An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from this offering, after deducting underwriting discounts and commissions, the structuring fee and offering expenses, to increase or decrease by $24 million. If the proceeds increase due to a higher initial public offering price or decrease due to a lower initial public offering price, then the proceeds of this offering used for general partnership purposes will increase or decrease, as applicable, by a corresponding amount. |
| (2) | As of February 28, 2014, $430 million was outstanding under our commercial paper program, and $2 million of letters of credit were outstanding under our revolving credit facility, reducing our borrowing capacity thereunder. As of February 28, 2014, there were no other outstanding borrowings under our revolving credit facility. |
| (3) | Includes 691,500 common units and restricted units to be issued to certain directors and officers pursuant to their compensation arrangements and our long term incentive plan. |
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Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $20.00, on a pro forma basis as of December 31, 2013, our net tangible book value was $6.7 billion, or $17.17 per unit. Net tangible book value excludes $1.45 billion of net intangible assets. Purchasers of common units in this offering will experience an immediate dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table:
| Assumed initial public offering price per common unit |
$ | 20.00 | ||||||
| Pro forma net tangible book value per unit before the offering(1) |
$ | 17.17 | ||||||
| Increase in pro forma net tangible book value per unit attributable to purchasers in the offering |
0.06 | |||||||
|
|
|
|||||||
| Less: |
||||||||
| Pro forma net tangible book value per unit after the offering(2) |
17.23 | |||||||
|
|
|
|||||||
| Immediate dilution in pro forma tangible net book value per unit attributable to purchasers in the offering(3) |
$ | 2.77 | ||||||
|
|
|
| (1) | Determined by dividing the number of units (182,163,930 common units and 207,855,430 subordinated units) issued to affiliates of CenterPoint Energy, OGE Energy and ArcLight for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities (which excludes equity attributable to the noncontrolling interest). |
| (2) | Determined by dividing the total number of units to be outstanding after the offering (207,855,430 common units and 207,855,430 subordinated units) into our pro forma net tangible book value (which excludes equity attributable to the noncontrolling interest), after giving effect to the application of the expected net proceeds of the offering. |
| (3) | If the initial public offering price were to increase or decrease by $1.00 per common unit, immediate dilution in tangible net book value per common unit would equal $3.71 or $1.83, respectively. |
The following table sets forth the number of units that we will issue and the total consideration contributed to us by affiliates of OGE Energy, CenterPoint Energy and ArcLight (including our general partner), by the purchasers of our common units in this offering and by LTIP participants upon consummation of the transactions contemplated by this prospectus:
| Units Acquired | Total Consideration | |||||||||||||||
| Number | Percent | Amount | Percent | |||||||||||||
| Affiliates of OGE Energy, CenterPoint Energy and ArcLight(1)(2)(3) |
390,019,360 | 93.8 | % | $ | 8,040 | 94.0 | % | |||||||||
| Purchasers in this offering |
25,000,000 | 6.0 | % | 500 | 5.8 | % | ||||||||||
| LTIP participants |
691,500 | 0.2 | % | 14 | 0.2 | % | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
415,710,860 | 100 | % | $ | 8,554 | 100 | % | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) | Upon completion of the transactions contemplated by this prospectus, OGE Energy, CenterPoint Energy and ArcLight collectively will own 182,163,930 common units and 207,855,430 subordinated units. Although OGE Energy and CenterPoint Energy will each also own a 50% management interest in our general partner, our general partner’s general partner interest is not entitled to any distributions from available cash, and, accordingly, is not included in these calculations. OGE Energy and CenterPoint Energy are also entitled to 60% and 40%, respectively, of the incentive distribution rights owned by our general partner. |
| (2) | The assets and liabilities of CenterPoint Energy were recorded at historical cost in accordance with GAAP. The assets and liabilities contributed by OGE Energy and ArcLight were recorded at fair |
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| value in accordance with GAAP as the formation transactions were considered a business combination for accounting purposes. The net investment of OGE Energy, CenterPoint Energy and ArcLight, as of December 31, 2013, after giving effect to the application of the net proceeds of this offering, is set forth above. |
| (3) | Assumes the underwriters’ option to purchase additional common units is not exercised. |
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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Significant Forecast Assumptions” below. In addition, please read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements and related notes included elsewhere in this prospectus.
Rationale for Our Cash Distribution Policy
Our partnership agreement requires that we distribute all of our available cash quarterly. Our cash distribution policy reflects our belief that our unitholders will be better served if we distribute rather than retain available cash, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Generally, our available cash is the sum of our (a) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (b) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case if we were subject to federal income tax.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy is subject to certain restrictions and may be changed at any time. The reasons for such uncertainties in our stated cash distribution policy include the following factors:
| • | Our ability to make cash distributions may be limited by certain covenants in our revolving credit facility. Should we be unable to satisfy these covenants, we will be unable to make cash distributions notwithstanding our cash distribution policy. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility.” |
| • | Our general partner will have the authority to establish reserves for the proper conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders. Our partnership agreement provides that in order for a determination by our general partner to be considered to have been made in good faith, our general partner must subjectively believe that the determination is in our best interests. |
| • | While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders other than in certain circumstances where no unitholder approval is required. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by our general partner and its affiliates) after the subordination period has ended. At the closing of this offering, OGE Energy and CenterPoint Energy will own our general partner as well as approximately 62.8% of our outstanding common units and all of our outstanding subordinated |
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| units, representing an aggregate 81.4% limited partner interest in us. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.” |
| • | Even if our cash distribution policy is not modified or revoked, the amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. |
| • | Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. |
| • | We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors, as well as increases in our operating or operation and maintenance expense, principal and interest payments on our debt, working capital requirements and anticipated cash needs. Our distributable cash flow is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. |
| • | Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations. |
| • | If and to the extent our distributable cash flow materially declines, we may elect to reduce our quarterly cash distributions in order to service or repay our debt or fund expansion capital expenditures. |
All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $300 million cash basket, that represent non-operating sources of cash. Accordingly, it is possible that return of capital distributions could be made from operating surplus. Any cash distributed by us in excess of operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. We do not anticipate that we will make any distributions from capital surplus.
Our Ability to Grow is Dependent on Our Ability to Access External Financing Sources
Because we will distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. We do not have any commitment from our general partner or other affiliates, including OGE Energy and CenterPoint Energy, to provide any direct or indirect financial assistance to us following the closing of this offering, except for CenterPoint Energy’s guarantee of our term loan facility. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units and the incremental distributions on the incentive distribution rights may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional borrowings under our revolving credit facility or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
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Our Minimum Quarterly Distribution
Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.2875 per unit for each complete quarter, or $1.15 per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 45 days after the end of each quarter, on or about the 15th day of each February, May, August and November to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately following the indicated distribution date. We will not make distributions for the period that begins on April 1, 2014, and ends on the day prior to the closing of this offering, other than the required distributions to our sponsors and ArcLight under our partnership agreement. We will adjust the amount of our distribution for the period from the completion of this offering through June 30, 2014 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common and subordinated units to be outstanding immediately after this offering for one quarter and on an annualized basis is summarized in the table below:
| Minimum Quarterly Distribution | ||||||||||||
| Number of Units | One Quarter | Annualized | ||||||||||
| (in millions) | ||||||||||||
| Publicly held common units(1) |
25,000,000 | $ | 7.2 | $ | 29 | |||||||
| Common units held by OGE Energy |
42,832,291 | $ | 12.3 | $ | 49 | |||||||
| Subordinated units held by OGE Energy |
68,150,514 | $ | 19.6 | $ | 78 | |||||||
| LTIP participant units(2) |
691,500 | $ | 0.2 | $ | 1 | |||||||
| Common units held by CenterPoint Energy |
87,803,909 | $ | 25.2 | $ | 101 | |||||||
| Subordinated units held by CenterPoint Energy |
139,704,916 | $ | 40.2 | $ | 161 | |||||||
| Common units held by ArcLight(1) |
51,527,730 | $ | 14.8 | $ | 59 | |||||||
|
|
|
|
|
|
|
|||||||
| Total |
415,710,860 | $ | 119.5 | $ | 478 | |||||||
|
|
|
|
|
|
|
|||||||
| (1) | Assumes that the underwriters’ option to purchase additional common units is not exercised. |
| (2) | Effective as of the closing of this offering, the board of directors of our general partner will grant 691,500 common units and restricted units to certain directors and executive officers pursuant to their compensation arrangements and our long term incentive plan. In addition, the board of directors of our general partner may grant up to approximately 100,000 phantom units with distribution equivalent rights to certain key employees that provide services for us pursuant to our long term incentive plan. Please read “Management—2014 Executive Compensation Program—Long Term Incentive Plan.” |
Our general partner will hold our incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.330625 per unit per quarter.
During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter.
Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in our best interests. Please read “Conflicts of Interest and Fiduciary Duties.”
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Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of cash reserves our general partner establishes in accordance with our partnership agreement as described above.
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $0.2875 per unit for the twelve months ending March 31, 2015. In those sections, we present two tables, consisting of:
| • | “Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended December 31, 2013, derived from our unaudited pro forma financial data that are included elsewhere in this prospectus, as adjusted to give pro forma effect to our formation transactions and this offering; and |
| • | “Estimated Distributable Cash Flow for the Twelve Months Ending March 31, 2015,” in which we explain our belief that we will be able to generate sufficient distributable cash flow for us to pay the minimum quarterly distribution on all units for the twelve months ending March 31, 2015. |
Unaudited Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013
If we had completed our formation transactions and this offering on January 1, 2013, our unaudited pro forma distributable cash flow for the year ended December 31, 2013 would have been approximately $541 million. This amount would have been sufficient to pay the full minimum quarterly distribution of $0.2875 per unit per quarter ($1.15 per unit on an annualized basis) on all of our common units and subordinated units for such period.
Our unaudited pro forma available cash for the year ended December 31, 2013 includes $3 million of estimated incremental operation and maintenance expenses that we expect to incur as a result of becoming a publicly traded partnership. Incremental operation and maintenance expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. These expenses are not reflected in historical financial statements of the partnership or our unaudited pro forma financial statements included elsewhere in the prospectus.
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had our formation transactions and this offering been completed as of the dates indicated. In addition, distributable cash flow is primarily a cash accounting concept, while the historical financial statements of the partnership and our unaudited pro forma financial statements included elsewhere in the prospectus have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we completed this offering on the dates indicated. The pro forma amounts below are presented on a twelve-month basis, and there is no guarantee that we would have had available cash sufficient to pay the full minimum quarterly distribution on all of our outstanding common units and subordinated units for each quarter within the twelve-month periods presented.
We use the term “distributable cash flow,” which is not defined in our partnership agreement, to measure whether we have generated from our operations, or “earned,” a particular amount of cash sufficient to support the payment of the minimum quarterly distributions. Our partnership agreement contains the concept of “operating surplus” to determine whether our operations are generating sufficient cash to support the distributions that we are paying, as opposed to returning capital to our partners. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Operating Surplus and Capital Surplus—Operating Surplus.” Because operating
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surplus is a cumulative concept (measured from the initial public offering date, and compared to cumulative distributions from the initial public offering date), we use the term distributable cash flow to approximate operating surplus on an annual, rather than a cumulative, basis. As a result, distributable cash flow is not necessarily indicative of the actual cash we have on hand to distribute or that we are required to distribute.
The following table illustrates, on a pro forma basis, for the year ended December 31, 2013, the amount of cash that would have been available for distribution to our unitholders, assuming that our formation transactions and this offering had been completed on January 1, 2013. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.
Enable Midstream Partners, LP
Unaudited Pro Forma Distributable Cash Flow
| Year Ended December 31, 2013 |
||||
| (In millions) | ||||
| Pro Forma Net Income attributable to Enable Midstream Partners, LP |
$ | 451 | ||
| Add: |
||||
| Depreciation and amortization |
269 | |||
| Interest expense, net |
49 | |||
| Income tax expense |
4 | |||
|
|
|
|||
| Pro Forma EBITDA |
$ | 773 | ||
|
|
|
|||
| Add: |
||||
| Impairment(1) |
12 | |||
| Distributions from equity method affiliates—SESH |
16 | |||
| Less: |
||||
| Equity in earnings of equity method affiliates—SESH |
(12 | ) | ||
| Gain on disposition(2) |
(10 | ) | ||
|
|
|
|||
| Pro Forma Adjusted EBITDA(3) |
$ | 779 | ||
|
|
|
|||
| Less: |
||||
| Adjusted interest expense, net(4) |
(61 | ) | ||
| Expansion capital expenditures(5) |
(571 | ) | ||
| Maintenance capital expenditures(6) |
(174 | ) | ||
| Incremental operation and maintenance expense of being a public entity(7) |
(3 | ) | ||
| Demand fees associated with legacy marketing business loss contracts |
(10 | ) | ||
| Add: |
||||
| Borrowings to fund demand fees associated with legacy marketing business loss contracts |
10 | |||
| Borrowings to fund expansion capital expenditures |
571 | |||
|
|
|
|||
| Pro Forma Distributable Cash Flow |
$ | 541 | ||
|
|
|
|||
| Pro Forma Distributable Cash Flow |
||||
| Distribution per unit (based on a minimum quarterly distribution rate of $0.2875 per unit) |
$ | 1.15 | ||
| Annual distributions to: |
||||
| Public common unitholders |
$ | 29 | ||
| Common units held by ArcLight |
59 | |||
| LTIP participants(8) |
1 | |||
| Common units held by OGE Energy |
49 | |||
| Common units held by CenterPoint Energy |
101 | |||
| Subordinated units held by OGE Energy |
78 | |||
| Subordinated units held by CenterPoint Energy |
161 | |||
|
|
|
|||
| Total annual minimum cash distributions |
$ | 478 | ||
|
|
|
|||
| Excess |
$ | 63 | ||
|
|
|
|||
| (1) | Attributable to the assets of the Service Star business line, a component of the gathering and processing business segment that provides measurement and communication services to third parties. |
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| (2) | Attributable to the sale by Enogex of certain gas gathering assets in the Texas Panhandle to a customer for cash proceeds of approximately $35 million. |
| (3) | We define Adjusted EBITDA and provide a reconciliation to its most directly comparable financial measures calculated and presented in accordance with GAAP in “Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.” |
| (4) | Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.” |
| (5) | Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our asset base, operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of additional pipeline, storage, gathering or processing capacity, including well connections, to the extent such capital expenditures are expected to expand our asset base, operating capacity or our operating income. |
| (6) | Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our asset base, operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. |
| (7) | Reflects an adjustment for estimated cash expenses associated with being a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance expenses; and director compensation. |
| (8) | Assumes that effective as of the closing of this offering, the board of directors of our general partner will grant 691,500 common units and restricted units to certain directors and executive officers pursuant to their compensation arrangements and our long term incentive plan, as well as approximately 100,000 phantom units with distribution equivalent rights to certain key employees that provide services for us pursuant to our long term incentive plan. Please read “Management—2014 Executive Compensation Program—Long Term Incentive Plan.” |
Estimated Distributable Cash Flow for the Twelve Months Ending March 31, 2015
We forecast that our estimated distributable cash flow during the twelve months ending March 31, 2015 will be approximately $550 million. This amount would exceed by $72 million the amount needed to pay the minimum quarterly distribution of $0.2875 per unit on all of our units for the twelve months ending March 31, 2015.
We are providing the forecast of estimated distributable cash flow to supplement the historical financial statements of the partnership and our unaudited pro forma financial statements included elsewhere in the prospectus in support of our belief that we will have sufficient cash available to allow us to pay cash distributions at the minimum quarterly distribution rate on all of our units for the twelve months ending March 31, 2015. To the extent that there is a shortfall during any quarter in the forecast period, we believe we would be able to make working capital borrowings to pay distributions in such quarter and would likely be able to repay such borrowings in a subsequent quarter, because we believe the total distributable cash flow for the forecast period will be more than sufficient to pay the aggregate minimum quarterly distribution on all of our units. To the extent we have distributable cash flow in excess of our quarterly distributions in the forecast period, we expect that our general partner will reserve such excess amount. During the forecast period, we expect that our general partner will not reserve amounts that impair our ability to pay our minimum quarterly distribution. Please read “—Significant Forecast Assumptions” for further information as to the assumptions we have made for the
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forecast. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” for information as to the accounting policies we have followed for the financial forecast.
Our forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending March 31, 2015. We believe that our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. If our estimates are not achieved, we may not be able to pay the minimum quarterly distribution or any other distribution on our common units. The assumptions and estimates underlying the forecast are inherently uncertain and, though we consider them reasonable as of the date of this prospectus, are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the forecast, including, among others, risks and uncertainties contained in “Risk Factors.” Accordingly, there can be no assurance that the forecast is indicative of our future performance or that actual results will not differ materially from those presented in the forecast. Inclusion of the forecast in this prospectus should not be regarded as a representation by any person that the results contained in the forecast will be achieved.
Unaudited Prospective Financial Information
We do not as a matter of course make public projections as to future sales, earnings or other results. However, we have prepared the following prospective financial information to present the estimated distributable cash flow to our common unitholders during the forecasted period. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this forecast are cautioned not to place undue reliance on the prospective financial information.
Neither our independent auditors, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm’s report included in this prospectus relates to historical financial information. It does not extend to prospective financial information and should not be read to do so.
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast or the assumptions used to prepare the forecast to reflect events or circumstances after the completion of this offering. In light of this, the statement that we believe that we will have sufficient distributable cash flow to allow us to make the full minimum quarterly distribution on all of our outstanding units for each quarter through March 31, 2015 should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.
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Enable Midstream Partners, LP
Estimated Distributable Cash Flow
| Twelve Months Ending March 31, 2015 |
||||
| (In millions) | ||||
| Gross margin(1) |
$ | 1,404 | ||
| Operation and maintenance(2) |
503 | |||
| Depreciation and amortization |
290 | |||
| Taxes other than income(3) |
65 | |||
|
|
|
|||
| Operating Income |
546 | |||
| Interest expense, net(4) |
(89 | ) | ||
| Equity in earnings of equity method affiliates(5) |
13 | |||
|
|
|
|||
| Net income |
470 | |||
| Less: Net income attributable to noncontrolling interest |
(3 | ) | ||
|
|
|
|||
| Net Income attributable to Enable Midstream Partners, LP |
$ | 467 | ||
|
|
|
|||
| Add: |
||||
| Depreciation and amortization |
290 | |||
| Interest expense, net(4) |
89 | |||
|
|
|
|||
| Estimated EBITDA |
846 | |||
| Add: |
||||
| Estimated distributions from equity method affiliates – SESH(6) |
15 | |||
| Less: |
||||
| Equity in earnings of equity method affiliates – SESH(5) |
(13 | ) | ||
|
|
|
|||
| Estimated Adjusted EBITDA(7) |
848 | |||
| Less: |
||||
| Adjusted interest expense, net(8) |
(99 | ) | ||
| Expansion capital expenditures(9) |
(533 | ) | ||
| Maintenance capital expenditures(10) |
(199 | ) | ||
| Demand fees associated with legacy marketing business loss contracts(11) |
(10 | ) | ||
| Add: |
||||
| Offering proceeds retained to fund demand fees associated with legacy marketing business loss contracts |
10 | |||
| Offering proceeds retained/Borrowings to fund expansion capital expenditures |
533 | |||
|
|
|
|||
| Estimated distributable cash flow |
$ | 550 | ||
|
|
|
|||
| Distribution per unit (based on minimum quarterly distribution rate of $0.2875 per unit) |
1.15 | |||
| Annual distributions to public common unitholders |
29 | |||
| Annual distributions to ArcLight |
59 | |||
| Annual distributions to LTIP participants(12) |
1 | |||
| Annual distributions to: |
||||
| Common units held by OGE Energy |
49 | |||
| Common units held by CenterPoint Energy |
101 | |||
| Subordinated units held by OGE Energy |
78 | |||
| Subordinated units held by CenterPoint Energy |
161 | |||
|
|
|
|||
| Total distributions to sponsors |
389 | |||
| General partner interest |
— | |||
|
|
|
|||
| Total distributions at minimum quarterly distribution rate |
$ | 478 | ||
|
|
|
|||
| Excess of distributable cash flow over aggregate annualized minimum quarterly distribution |
$ | 72 | ||
|
|
|
|||
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| (1) | We define gross margin and provide a reconciliation to its most directly comparable financial measure calculated in accordance with GAAP in “Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.” |
| (2) | Includes approximately $3 million of estimated annual incremental operation and maintenance expenses that we expect to incur as a result of being a separate publicly traded partnership, which are not reflected in our unaudited pro forma financial statements. |
| (3) | Taxes other than income are comprised primarily of property taxes and sales and use taxes. |
| (4) | Interest expense, net reflects interest expense forecasted on the borrowings detailed under “—Significant Forecast Assumptions—Financing” on a basis consistent with historical GAAP interest expense, net of interest income. We have assumed the issuance of long-term notes in the first half of 2014 to refinance our existing term loans and a portion of our Enable Oklahoma senior notes. |
| (5) | SESH is a non-consolidated entity in which we own a 24.95% ownership interest. Our earnings from SESH are included on our pro forma consolidated statement of income included elsewhere in this prospectus. Because our earnings from SESH may not necessarily be reflective of the amount of cash we would expect to receive, those earnings are included in our net income but subtracted in connection with our calculation of Adjusted EBITDA. Our estimate of SESH’s expected cash contribution to us during the twelve months ending March 31, 2015 is included in our Adjusted EBITDA. |
| (6) | Under the terms of its limited liability company agreement, SESH must distribute 100% of its available cash within 30 days following the end of each quarter to its members. Available cash is generally defined as cash on hand at the end of the applicable quarter, less any reserves determined to be appropriate by the management committee. We expect that we will receive 24.95% of the cash available for distribution from SESH for the twelve months ending March 31, 2015. Because we control only 24.95% of the voting interest of the management committee of SESH, we will not be able to control the determination of available cash with respect to any quarter. Please see “Risk Factors—Risks Related to Our Business—We conduct a portion of our operations through joint ventures, which subject us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.” |
| (7) | We define Adjusted EBITDA and provide a reconciliation to its most directly comparable financial measures calculated and presented in accordance with GAAP in “Summary—Summary Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.” |
| (8) | Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes, which is the primary reason for the $10 million difference between Interest expense, net and Adjusted interest expense, net for the twelve months ending March 31, 2015. |
| (9) | Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our asset base, operating income or operating capacity over the long term. Examples of expansion capital expenditures include the acquisition of equipment and the construction, development or acquisition of additional pipeline, storage, gathering or processing capacity, including well connections, to the extent such capital expenditures are expected to expand our asset base, operating capacity or our operating income. |
| (10) | Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our asset base, operating capacity or operating income. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations. |
| (11) | Demand fees associated with legacy marketing business loss contracts are related to three expiring contracts that were entered into by an affiliate of Enogex prior to the formation of the partnership to ship or store gas on third-party assets. These contracts are not core to our operations and we do not expect to realize value above the demand fees. As part of the purchase accounting adjustments at the formation of the partnership, these contracts were marked to their fair value and were recorded on the balance sheet. The remaining expected demand fees associated with these contracts are approximately $10 million for |
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| the twelve month period ending March 31, 2015, and an estimated $3 million thereafter. Accordingly, we intend to retain approximately $13 million from the net proceeds of this offering, which we anticipate will fully fund the remaining demand fees associated with these contracts to be paid as they come due. |
| (12) | Assumes that effective as of the closing of this offering, the board of directors of our general partner will grant 691,500 common units and restricted units to certain directors and executive officers pursuant to their compensation arrangements and our long term incentive plan, as well as approximately 100,000 phantom units with distribution equivalent rights to certain key employees that provide services for us pursuant to our long term incentive plan. Please read “Management—2014 Executive Compensation Program—Long Term Incentive Plan.” |
Significant Forecast Assumptions
The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending March 31, 2015. While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed below are those that we believe are material to our forecasted results of operations and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and the actual results and those differences could be material. If the forecast is not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.
Segment Data
The following table compares certain financial data in our gathering and processing and transportation and storage business segments for the twelve months ending March 31, 2015 to the pro forma period for the year ended December 31, 2013.
| Pro Forma | Forecasted | |||||||
| Year Ended December 31, 2013 |
Twelve Months Ending March 31, 2015 |
|||||||
| (In millions) | ||||||||
| Gathering and Processing |
||||||||
| Segment Gross Margin |
$ | 762 | $ | 833 | ||||
| Segment Adjusted EBITDA(1) |
467 | 513 | ||||||
| Transportation and Storage |
||||||||
| Segment Gross Margin |
$ | 562 | $ | 571 | ||||
| Segment Adjusted EBITDA(1) |
313 | 338 | ||||||
| (1) | Excludes allocation of $3 million of incremental costs associated with operating as a publicly traded partnership. |
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Volume and Commodity Price Assumptions and Sensitivity Analysis
Volumes
The following table compares estimated volumes and certain operational data for our gathering and processing and transportation and storage business segments for the twelve months ending March 31, 2015 to the pro forma period for the year ended December 31, 2013:
| Pro Forma | Forecasted | |||||||
| Year Ended December 31, 2013 |
Twelve Months Ending March 31, 2015 |
|||||||
| Gathering and Processing |
||||||||
| Natural gas gathering volume (TBtu/d) |
3.6 | 4.0 | ||||||
| Plant natural gas inlet volume (TBtu/d) |
1.4 | 1.7 | ||||||
| Gross NGL production (MBbl/d)(1) |
58.7 | 77.3 | ||||||
| Gross condensate production (MBbl/d) |
3.0 | 3.2 | ||||||
| Crude oil gathered volumes (MBbl/d)(2) |
— | 9.9 | ||||||
| Transportation and Storage |
||||||||
| Interstate firm contracted capacity (Bcf/d)(3)(4) |
8.0 | 8.0 | ||||||
| Intrastate average deliveries (TBtu/d) |
1.6 | 1.6 | ||||||
| Average firm storage volumes (Bcf) . |
67.9 | 66.9 | ||||||
| (1) | Excludes condensate. Includes third party processing. |
| (2) | Initial operations began November 1, 2013. From November 1, 2013 to December 31, 2013, actual gathered volumes were 3,100 barrels. |
| (3) | Excludes SESH’s approximately 1.0 Bcf/d firm contracted capacity. |
| (4) | Actual volumes transported per day may be less than total firm contracted capacity depending on demand. |
The actual volume of natural gas that we gather in our gathering and processing business segment will influence whether the amount of distributable cash flow for the twelve months ending March 31, 2015 is above or below our forecast. For example, if the actual volume of natural gas we gather on all of our gathering systems for the twelve months ending March 31, 2015 was 10% higher or lower than our forecasted levels, that change would result in an increase or decrease to distributable cash flow of approximately $62 million, if all other assumptions are held constant.
Commodity Prices
Natural gas, crude oil and NGL prices are factors that influence whether the amount of distributable cash flow for the twelve months ending March 31, 2015 will be above or below our forecast. Approximately $346 million, or 25%, of our total forecasted gross margin for the twelve months ending March 31, 2015 is directly exposed to changes in commodity prices. This compares to approximately 24% of our total gross margin for the pro forma period for the year ended December 31, 2013. Of the amount included in our forecast period, approximately $316 million is related to the realization of our expected natural gas, NGLs and condensate positions associated with our gathering and processing operations and contractual arrangements. The remaining $30 million is associated with sales of natural gas and NGLs collected under our contractual arrangements or fuel charges net of the fuel used to run our compression facilities not subject to a fuel tracker system. Our forecast does not include any material derivative contracts for the twelve months ending March 31, 2015.
The table below sets forth our estimates for average monthly benchmark commodity prices for the twelve months ending March 31, 2015 compared to actual monthly average prices for the year ended December 31, 2013. The projected prices that we expect to realize for these commodities reflect various adjustments to the applicable transportation, quality and regional price differentials. Our forecasted commodity prices are primarily
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based on market prices for the applicable commodities, as adjusted to take into account third-party market analysis and management’s judgment. Based on the natural gas and NGL price assumptions below for the twelve months ending March 31, 2015, we expect to operate our processing assets in ethane rejection mode unless plant capabilities or plant-level economics dictate otherwise.
| Pro Forma | Forecasted | |||||||
| Year Ended December 31, 2013 |
Twelve Months Ending March 31, 2015 |
|||||||
| Natural Gas – Henry Hub ($/MMBtu) |
$ | 3.65 | $ | 4.14 | ||||
| Natural Gas Liquids Composite ($/gal)(1) |
||||||||
| Mont Belvieu, Texas |
$ | 0.85 | $ | 0.89 | ||||
| Conway, Kansas |
$ | 0.81 | $ | 0.84 | ||||
| Crude Oil - WTI ($/Bbl) |
$ | 96.81 | $ | 92.62 | ||||
| (1) | Natural gas liquids composite based on an assumed composition of 45%, 30%, 10%, 5%, and 10% for ethane, propane, normal butane, isobutane and natural gasoline, respectively. |
Holding all other assumptions constant, we estimate that (i) a 10.0% increase or decrease in the price of natural gas from forecasted levels would result in an increase or decrease of approximately $22 million in distributable cash flow for the forecast period and (ii) a 10.0% increase or decrease in the price of NGLs from forecasted levels, would result in an increase or decrease of approximately $11 million in distributable cash flow for the forecast period.
Gathering and Processing Gross Margin
We estimate that we will generate gross margin in our gathering and processing segment of $833 million for the twelve months ending March 31, 2015, compared to $762 million for the year ended December 31, 2013 on a pro forma basis. The increase of $71 million in gross margin for the forecasted period as compared to the pro forma year ended December 31, 2013 is primarily attributable to increased volumes on our Anadarko system in the Greater Granite Wash, SCOOP and Mississippi Lime plays and gathering fees associated with our Bakken crude oil gathering system and commodity price improvement.
For the twelve months ending March 31, 2015, we have estimated that approximately $517 million, or 62%, and $316 million, or 38%, of the gross margin in our gathering and processing segment will be fee-based and commodity-based, respectively. In comparison, the corresponding contribution percentages to gross margin by fee-based and commodity-based, respectively, were 61% and 39% for the year ended December 31, 2013 on a pro forma basis. The expected increase in fee-based gross margin is due to increased natural gas and crude oil gathered volumes resulting in increased gathering and compression fees and increased volumes associated with fixed-fee processing arrangements. Approximately $216 million, or 42%, of our total fee-based gathering and processing gross margin for the twelve months ending March 31, 2015 is expected to come from contracts containing minimum volume commitment features. Our commodity-based margin is related to the realization of our natural gas, NGL and condensate positions associated with our gathering and processing operations and associated contractual terms.
We estimate that the total volumes of natural gas gathered on our systems will average approximately 4 TBtu/d and the total volumes of liquids produced on our systems, including condensate, will average approximately 80.5 MBbl/d for the twelve months ending March 31, 2015. We estimate that natural gas gathered volumes will increase by approximately 11% during the twelve months ending March 31, 2015 compared with the pro forma year ended December 31, 2013 due to an increase in producer activity in our rich gas areas that will be partially offset by declining volumes in our lean gas areas.
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The following table compares forecasted volumes of natural gas and crude oil gathered and NGLs and condensate produced on our systems for the twelve months ending March 31, 2015 to actual pro forma volumes for the year ended December 31, 2013.
| Pro Forma | Forecasted | |||||||
| Year Ended December 31, 2013 |
Twelve Months Ending March 31, 2015 |
|||||||
| Natural Gas – Gathered Volumes (TBtu/d) |
||||||||
| Anadarko system |
1.3 | 1.5 | ||||||
| Ark-La-Tex system |
1.3 | 1.6 | (1) | |||||
| Arkoma system |
1.0 | 0.9 | (2) | |||||
|
|
|
|
|
|||||
| Total |
3.6 | 4.0 | ||||||
| NGLs (MBbl/d)(3) |
||||||||
| Anadarko system |
43.2 | 60.7 | ||||||
| Ark-La-Tex system |
10.8 | 11.9 | ||||||
| Arkoma system |
4.7 | 4.7 | ||||||
|
|
|
|
|
|||||
| Total |
58.7 | 77.3 | ||||||
| Condensate (MBbl/d) |
3.0 | 3.2 | ||||||
| Crude Oil — Gathered Volumes (MBbl/d) |
||||||||
| Williston system(4) |
— | 9.9 | ||||||
| (1) | Gathered volumes does not include approximately 0.6 TBtu/d not expected to be delivered but for which payments would be received in order for our customers to meet minimum volume commitments. |
| (2) | Gathered volumes does not include approximately 0.1 TBtu/d not expected to be delivered but for which payments would be received in order for our customers to meet minimum volume commitments. |
| (3) | Excludes condensate. |
| (4) | Initial operation of the system began on November 1, 2013. From November 1, 2013 to December 31, 2013, actual gathered volumes were 3,100 barrels. |
Anadarko Basin
Natural gas gathered volumes on our Anadarko system are expected to average 1.5 TBtu/d for the twelve months ending March 31, 2015, an increase of 15% as compared to the pro forma year ended December 31, 2013. The estimated increase in volumes to be gathered and processed in this basin is primarily associated with our customers’ activity in the liquids-rich Greater Granite Wash, SCOOP and Mississippi Lime plays. Since January 2010, we have secured over 3.8 million gross acres dedicated via long-term contracts in this basin. We currently serve over 200 producers in this basin with total acreage dedications of over 4.7 million gross acres. In support of these long-term dedications and continued producer activity in this liquids-rich basin, we elected to expand the processing capacity on our Anadarko super header by 800 MMcf/d since January 2010. This strategic expansion was initiated to allow us to continue to provide reliable and efficient service to our customers. To date, we have installed 600 MMcf/d of that capacity and expect that we will commence operations at our 200 MMcf/d Bradley plant in the first quarter of 2015.
Ark-La-Tex Basin
Natural gas gathered volumes on our Ark-La-Tex system are expected to average 1.6 TBtu/d for the twelve months ending March 31, 2015, an increase of 23% as compared to the pro forma year ended December 31, 2013. We are forecasting increased volume associated with the relatively rich Cotton Valley play from
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increased drilling activity around our Waskom plant, as well as increased volumes due to recent drilling activity in the Haynesville shale play. Throughput on our systems in the lean Haynesville shale play is not expected to exceed our minimum volume commitments during the forecast period; therefore, we do not expect an increase in margin commensurate with the expected increase in volume. We currently serve over 110 producers and have secured over 0.7 million gross acres dedicated via long-term contracts in this basin. We believe that we are well-positioned to benefit from future increases in drilling activity in this basin.
Arkoma Basin
Natural gas gathered volumes on our Arkoma system are expected to average 0.9 TBtu/d for the twelve months ending March 31, 2015 compared to 1.0 TBtu/d for the pro forma year ended December 31, 2013. Volumes in this basin are primarily produced from the Fayetteville and Woodford shale plays and the traditional Arkoma basin. Throughput on our systems in the Arkoma Basin is not expected to exceed our minimum volume commitments during the forecast period. We currently serve over 220 producers and have secured 1.2 million acres dedicated via long-term contracts in this basin, which we believe positions us to benefit from future increases in drilling activity in this basin.
Williston
We estimate that we will gather an average of 9,880 Bbl/d of crude oil associated with our Williston system in the Bakken for the twelve months ending March 31, 2015. Initial operation of this system began on November 1, 2013. Construction associated with this project is ongoing and we expect it to be fully operational in the third quarter of 2014. Total capacity on the system once fully in-service will be 19,500 Bbl/d, all of which is contracted through 2028. We executed an agreement in February 2014 to gather crude oil production through a second new crude oil gathering system in the Williston Basin. The new system will have a total capacity of up to 30,000 Bbl/d. We will file to seek a FERC order approving our terms of service for this project. Although we expect to receive FERC approval by the third quarter of 2014, we cannot assure you that we will be able to obtain such approval. We expect the system to commence initial operations during the second quarter of 2015. For the twelve months ending March 31, 2015, we have included $83 million of expansion capital expenditures for this project. We do not expect to receive any cash flows from this project until the second quarter of 2015. We estimate that the total expansion capital expenditures for this project will be $156 million.