On behalf of retail electric providers (REPs), CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts (kV) in locations throughout CenterPoint Houston'sHouston’s certificated service territory. CenterPoint Houston constructs and maintains transmission facilities and provides transmission services under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

 

In the Electric Reliability Council of Texas, Inc. (ERCOT), end users purchase their electricity directly from certificated REPs. CenterPoint Houston delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston'sHouston’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston'sHouston’s operations include construction and maintenance of distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and the Texas Utility Commission.

 

CenterPoint Houston is a member of ERCOT. Within ERCOT, prices for wholesale generation and retail electric sales are unregulated, but services provided by transmission and distribution companies, such as CenterPoint Houston, are regulated by the Texas Utility Commission. ERCOT serves as the regional reliability coordinating council for member electric power systems in most of Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers, river authorities and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Arkansas and Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85%90% of the demand for power in Texas and is one of the nation'snation’s largest power markets. The ERCOT market included available generating capacity of over 74,00077,000 megawatts (MW) atas of December 31, 2013.2015. Currently, there are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

 

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Corporation (NERC) and approved by the Federal Energy Regulatory Commission (FERC). TheseWithin ERCOT, these reliability standards are administered by the Texas RegionalReliability Entity (TRE), a functionally independent division of ERCOT.. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state'sstate’s main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

 

CenterPoint Houston'sHouston’s electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. CenterPoint Houston participates with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

 

In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law). Pursuant to that legislation, integrated electric utilities operating within ERCOT were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation provided for a transition period to move to the new market structure and provided a mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs were recoverable after approval by the Texas Utility Commission either through the issuance of securitization bonds or through the implementation of a competition transition charge as a rider to the utility'sutility’s tariff. CenterPoint Houston'sHouston’s integrated utility business was restructured in accordance with the Texas electric restructuring law and its generating stations were sold to third parties. Ultimately CenterPoint Houston was authorized to recover a total of approximately $5 billion in stranded costs, other charges and related interest.  Most of that amount was recovered through the issuance of transition bonds by special purpose subsidiaries of CenterPoint Houston.  The transition bonds

CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. At December 31, 2013,2015, CenterPoint Houston'sHouston’s customers consisted of approximately 7069 REPs, which sell electricity to over two2.3 million metered customers in CenterPoint Houston'sHouston’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside CenterPoint Houston'sHouston’s certificated service area. Each REP is licensed by, and must meet minimum creditworthiness criteria established by, the Texas Utility Commission.

 

Sales to REPs that are affiliates of NRG Energy, Inc. (NRG) represented approximately 38%35%, 39%37% and 36%38% of CenterPoint Houston'sHouston’s transmission and distribution revenues in 2013, 20122015, 2014 and 2011,2013, respectively.  Sales to REPs that are affiliates of Energy Future Holdings Corp. (Energy Future Holdings) represented approximately 10%, 10% and 11% of CenterPoint Houston'sHouston’s transmission and distribution revenues in 2013, 2012each of 2015, 2014 and 2011, respectively.2013.  CenterPoint Houston'sHouston’s aggregate billed receivables balance from REPs as of December 31, 20132015 was $172$195 million.  Approximately 38%, 8%34% and 8%11% of this amount was owed by affiliates of NRG Just Energy Group, Inc. and Energy Future Holdings, respectively. CenterPoint Houston does not have long-term contracts with any of its customers. It operates using a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day.

 

In May 2012, CenterPoint Houston substantially completed the deployment of an advanced metering system (AMS), having installed approximately 2.2 million smart meters. This technology should encourage greater energy conservation by giving Houston-area electric consumers the ability to better monitor and manage their electric use and its cost in near real time. To recover the cost of the AMS, the Texas Utility Commission approved a monthly surcharge payable by REPs, initially over 12 years. For the first 24 months, which began in February 2009, the surcharge for residential customers was $3.24 per month.  Beginning in February 2011, the surcharge wasyears and later reduced to $3.05 per month.  In September 2011, thesix years as a result of U.S. Department of Energy (DOE) grant funds. The surcharge duration was reduced from 12 years to approximately six yearsexpired in 2015 for residential customers and approximately eight yearsis set to expire in 2016 to 2017 for commercialnon-residential customers. The surcharge amounts and duration are subject to adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope. Please read “ – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Regulatory Matters – CenterPoint Houston.”

 

CenterPoint Houston is also pursuing deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” (IG) which would provide on-demand data and information about the status of facilities on its system. Although this technology is still in the developmental stage, CenterPoint Houston believes it has the potential to provide an improvement in grid planning, operations, maintenance and customer service for the CenterPoint Houston distribution system. These improvements are expected to result in fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.

 

In October 2009, the U.S. Department of Energy (DOE)DOE selected CenterPoint Houston for a $200 million grant to help fund its AMS and IG projects.  CenterPoint Houston received substantially all of the $200 million of grant funding from the DOE by 2011 and used $150 million of it to accelerate completion of its deployment of advanced meters to 2012, instead of 2014 as originally scheduled.2012. CenterPoint Houston estimates that capital expenditures of approximately $660 million for the installation of the advanced meters and corresponding communication and data management systems were incurred over the advanced meter deployment period. CenterPoint Houston is usingused the other $50 million from the grant for an initial deployment of an IG that covers approximately 12% of its service territory. This initial deployment is expected to beThe DOE-funded portion of the IG project was substantially completed in 2014.  It is expected that2015, and the capital portion of the IG project subject to partial funding by the DOE will cost approximately $140 million.

 

There are no other electric transmission and distribution utilities in CenterPoint Houston'sHouston’s service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston'sHouston’s territory, it would be required to obtain a certificate of convenience and necessity from the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston'sHouston’s service area at this time. Distributed generation (i.e., power generation located at or near the point of consumption) could result in a reduction of demand for CenterPoint Houston'sHouston’s electric distribution services but has not been a significant factor to date.

 

A significant portion of CenterPoint Houston'sHouston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it delivers on behalf of such REP. Thus, CenterPoint Houston'sHouston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues generally being higher during the warmer months.

 

All of CenterPoint Houston'sHouston’s properties are located in Texas. Its properties consist primarily of high-voltage electric transmission lines and poles, distribution lines, substations, service centers, service wires and meters. Most of CenterPoint Houston'sHouston’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets under franchise agreements and as permitted by law.

 

All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to:

 

As of December 31, 2013,2015, CenterPoint Houston had approximately $1.9$2.1 billion aggregate principal amount of general mortgage bonds outstanding under the General Mortgage, including (a) $290approximately $56 million held in trust to secure pollution control bonds that are not reflected inon our consolidated financial statements because we areCenterPoint Houston is both the obligor on the bonds and the current owner of the bonds, and (b) approximately $118 million held in trust to secure pollution control bonds for which we are obligated and (c) approximately $183 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, as of December 31, 2013,2015, CenterPoint Houston had approximately $102 million aggregate principal amount of first mortgage bonds outstanding under the Mortgage. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $3.9$4.2 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2013.2015. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

 

 

 

CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

 

CERC Corp.'s natural gas distribution business (Gas Operations)’s NGD engages in regulated intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.33.4 million residential, commercial, industrial and industrialtransportation customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by Gas OperationsNGD are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2013,2015, approximately 41%39% of Gas Operations'NGD’s total throughput was to residential customers and approximately 59%61% was to commercial and industrial and transportation customers.

 

The table below reflects the number of natural gas distribution customers by state as of December 31, 2013:2015:

Gas OperationsNGD also provides unregulated services in Minnesota consisting of residential appliance repair and maintenance services along with heating, ventilating and air conditioning (HVAC) equipment sales.

The demand for intrastate natural gas sales to residential customers and natural gas sales and transportation for commercial and industrial customers is seasonal. In 2013,2015, approximately 68% of the total throughput of Gas Operations'NGD’s business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods.the colder months.

 

Supply and Transportation.  In 2013, Gas Operations2015, NGD purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Major suppliers in 20132015 included BP Energy Company/BP Canada Energy Marketing (16.2%(18.4% of supply volumes), Cargill, Inc. (13.2%), Tenaska Marketing Ventures (10.5%(14.5%), Sequent Energy Management (9.0%), ConocoPhillips Company (7.0%), Kinder Morgan Tejas Pipeline/Kinder Morgan Texas Pipeline (8.1%(6.3%), ShellTwin Eagle Resource Management (3.4%), CenterPoint Energy North America (7.8%), Sequent Energy Management (4.5%), Conoco Inc. (4.0%Services (3.2%), Mieco Inc. (3.4%(3.1%), Renaissance (2.7%Oneok Energy Services (2.9%), and Laclede Energy Resources (2.5%Trailstone NA Logistics (2.3%). Numerous other suppliers provided the remaining 27.1%30% of Gas Operations'NGD’s natural gas supply requirements. Gas OperationsNGD transports its natural gas supplies through various intrastate and interstate pipelines including those owned by our other subsidiaries, under contracts with remaining terms, including extensions, varying from one to teneight years. Gas OperationsNGD anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.

 

Gas OperationsNGD actively engages in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of its state regulatory authorities. These price stabilization activities include use of storage gas and contractually establishing structured prices (e.g., fixed price, costless collars and caps) with our physical gas suppliers. Its gas supply plans generally call for 50-75%50–75% of winter supplies to be stabilized in some fashion.

 

The regulations of the states in which Gas OperationsNGD operates allow it to pass through changes in the cost of natural gas, including savings and costs of financial derivatives associated with the index-priced physical supply, to its customers under purchased gas adjustment provisions in its tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.

 

Gas OperationsNGD uses various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather and may also supplement contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production.

 

Gas OperationsNGD owns and operates an underground natural gas storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.0 Bcf available for use during the heating season and a maximum daily withdrawal rate of 50 million cubic feet (MMcf). It also owns eight propane-air plants with a total production rate of 180,000 Dekatherms (DTH) per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant

 

On an ongoing basis, Gas OperationsNGD enters into contracts to provide sufficient supplies and pipeline capacity to meet its customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.

 

NGD has entered into various asset management agreements (AMAs) associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas.  Generally, these asset management agreementsAMAs are contracts between Gas OperationsNGD and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas OperationsNGD agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas OperationsNGD and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas OperationsNGD. NGD is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization.  Gas OperationsNGD has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreementAMA proceeds. The agreements have varying terms, the longest of which expires in 2016.2019.

As of December 31, 2013, Gas Operations2015, NGD owned approximately 73,00074,000 linear miles of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by Gas Operations,NGD, it owns the underground gas mains and service lines, metering and regulating equipment located on customers'customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which Gas OperationsNGD receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on land owned by suppliers.

Gas OperationsNGD competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users.end users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Gas Operations'NGD’s facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.

CES offers a variety of natural gas management services to gas utilities, large industrial customers, electric generators, smaller commercial and industrial customers, municipalities, educational institutions and hospitals. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES also offers a portfolio of physical delivery services and financial products designed to meet customers'customers’ supply and price risk management needs. These customers are served directly, through interconnects with various interstate and intrastate pipeline companies, and portably, through our mobile energy solutions business.

In addition to offering natural gas management services, CES procures and optimizes transportation and storage assets. CES currently transports natural gas on 47 interstate and intrastate pipelines within states located throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas

As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers'customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers'customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers'customers’ purchase commitments. These supply imbalances arise each month as customers'customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES'CES’ processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES'CES’ exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate Value at Risk (VaR).

 

Our risk control policy, which is overseen by our Risk Oversight Committee (ROC), defines authorized and prohibited trading instruments and trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts, to support its sales. The CES business optimizes its use of these various tools to minimize its supply costs and does not engage in proprietary or speculative commodity trading. The VaR limit within which CES currently operates, a $4 million maximum set by the Board of Directors, is consistent with CES'CES’ operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply. In 2013, CES'2015, CES’ VaR averaged $0.2 million with a high of $0.7$1.0 million.

CEIP owns and operates approximately 235over 200 miles of intrastate pipeline in Louisiana and Texas and contracts out approximately 2.3 Bcf of storage at its Pierce Junction facility in Texas under long-term leases.Texas. In addition, CES leases transportation capacity on various interstate and intrastate pipelines and storage to service its shippers and end-users.end users.

CES competes with regional and national wholesale and retail gas marketers, including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.

On March 14,In May 2013, CenterPoint Energy entered into a Master Formation Agreement (MFA) withwe, OGE Energy Corp. (OGE) and affiliates of ArcLight Capital Partners, LLC (ArcLight), pursuant to which CenterPoint Energy, OGE and ArcLight agreed to formformed Enable, asinitially a private limited partnership.

On May 1, 2013, the parties closed on the formationApril 16, 2014, Enable completed its initial public offering (IPO) of Enable28,750,000 common units at a price of $20.00 per unit, which included 3,750,000 common units sold by ArcLight pursuant to whichan over-allotment option that was fully exercised by the underwriters. Enable becamereceived $464 million in net proceeds from the ownersale of substantially allthe units, after deducting underwriting fees, structuring fees and other offering costs. In connection with Enable’s IPO, a portion of CERC Corp.’s former Interstate Pipelines and Field Services businesses.

Enable is equally controlled jointly by CERC Corp. and OGE;OGE as each own 50% of the management rights in the general partner of Enable. Sale of our ownership interests in Enable’s general partner to anyone other than an affiliate prior to May 1, 2016 is prohibited by Enable’s general partner’s limited liability company agreement.  Sale of our or OGE’s ownership interests in Enable’s general partner to a third party is subject to mutual rights of first offer and first refusal, and we are not permitted to dispose of less than all of our interest in Enable’s general partner.

As of December 31, 2015, CERC Corp. and OGE also own a 40% and 60% interest, respectively, in the incentive distribution rights held by the general partner of Enable. Enable is expected to pay a minimum quarterly distribution of $0.2875 per unit on its outstanding units to the extent it has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner and its affiliates, within 45 days after the end of each quarter. If cash distributions to Enable’s unitholders exceed $0.330625 per unit in any quarter, the general partner will receive increasing percentages or incentive distributions rights, up to 50%, of the cash Enable distributes in excess of that amount. In certain circumstances the general partner of Enable will have the right to reset the minimum quarterly distribution and the target distribution levels at which the incentive distributions receive increasing percentages to higher levels based on Enable’s cash distributions at the time of the exercise of this reset election.

Our investment in Enable is accounted for on an equity basis. Equity earnings associated with CenterPoint Energy'sour interest in Enable and equity earnings associated with CenterPoint Energy’s 25.05% interest in Southeast Supply Header, LLC (SESH) are reported under the Midstream Investments segment.

Enable’s natural gas gathering and processing assets are located in four statesOklahoma,Texas, Arkansas, Louisiana and Mississippi and serve natural gas production from shale developments in the Anadarko, Arkoma and Ark-La-Tex basins. Enable also owns an emerginga crude oil gathering business located in the Bakken shale formationNorth Dakota that commenced initial operations in November 2013.2013 to serve shale development in the Bakken Shale formation of the Williston Basin. Enable’s natural gas transportation and storage assets extend from western Oklahoma and the Texas Panhandle to Alabama and from Louisiana to Illinois.

As of December 31, 2013,2015, Enable’s portfolio of energy infrastructure assets included approximately 11,00012,400 miles of gathering pipelines, 1213 major processing plants with approximately 2.1 Bcf/d2.3 Bcf per day of processing capacity and 2.3 Bcf per day of treating capacity, approximately 7,900 miles of interstate pipelines (including SESH)Southeast Supply Header, LLC (SESH)), approximately 2,3002,200 miles of intrastate pipelines and eight storage facilities comprising 86.5providing approximately 85.0 Bcf of storage capacity.

Enable’s gathering and processing systems compete with gatherers and processors of all types and sizes, including those affiliated with various producers, other major pipeline companies and various independent midstream entities. Enable’s primary competitors are master limited partnerships who are active in the regions where it operates. In the process of selling NGLs, Enable competes against other natural gas processors extracting and selling NGLs. Enable’s primary competitors are master limited partnerships who are active in the regions where it operates.

Enable’s interstate pipelines compete with other interstate and intrastate pipelines. Enable’s intrastate pipeline system competes with numerous interstate and intrastate pipelines, including several of the interconnected pipelines discussed above, as well as other natural gas storage facilities. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service.

On each of May 1, 2013 CenterPoint Energyand May 30, 2014, we contributed a 24.95% interest in SESH to Enable. CERC has certain put rights, and Enable has certain call rights, exercisable with respect to the 25.05%On June 30, 2015, we contributed our remaining 0.1% interest in SESH retainedto Enable. The remaining 50% of SESH is owned by CERC, under which CERC would contribute its retained interest in SESH, in exchange for a specified number of limited partner units in Enable and a cash payment, payable either from CERC to Enable or from Enable to CERC, for changes in the value of SESH. Affiliates of Spectra Energy Corp own the remaining 50% interest in SESH.Partners, LP.

Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations that support all of our business operations.

For financial information about our segments, see Note 17 to our consolidated financial statements, which note is incorporated herein by reference.

We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.

The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in interstate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The FERC has authority to prohibit market manipulation in connection with FERC-regulated transactions and to impose significant civil and criminal penalties for statutory violations and violations of the FERC’s rules or orders. Our Energy Services business segment markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.

CenterPoint Houston is not a “public utility” under the Federal Power Act and, therefore, is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The FERC has certain responsibilities with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by CenterPoint Houston and other utilities within ERCOT. The FERC has designated the NERC as the Electric Reliability Organization (ERO) to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to (a) impose fines and other sanctions on Electric Entities that fail to comply with approved standards and (b) audit compliance with approved standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. CenterPoint Houston does not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on its operations. To the extent that CenterPoint Houston is required to make additional expenditures to comply with these standards, it is anticipated that CenterPoint Houston will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.

As a public utility holding company, under the Public Utility Holding Company Act of 2005, we and our consolidated subsidiaries are subject to reporting and accounting requirements and are required to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances.

CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. The Texas Utility Commission and certain municipalities have the authority to set the rates and terms of service provided by CenterPoint Houston under cost-of-service rate regulation. CenterPoint Houston holds non-exclusive franchises from thecertain incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 20 to 40 years.

CenterPoint Houston’s distribution rates charged to REPs for residential customers are primarily based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are primarily based on peak demand.

For a discussion of certain of CenterPoint Houston'sHouston’s ongoing regulatory proceedings, see “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters — CenterPoint Houston” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

In almost all communities in which Gas OperationsNGD provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas are perpetual. Gas OperationsNGD expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.

Substantially all of Gas OperationsNGD is subject to cost-of-service rate regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and those municipalities served by Gas OperationsNGD that have retained original jurisdiction. In certain of its jurisdictions, Gas OperationsNGD has in effect annual rate adjustment mechanisms that provide for changes in rates dependent upon certain changes in invested capital, earned returns on equity or actual margins realized.

 

For a discussion of certain of Gas Operations'NGD’s ongoing regulatory proceedings, see “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Regulatory Matters — Gas Operations”CERC” in Item 7 of Part II of this report, which discussion is incorporated herein by reference.

In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under the Pipeline Safety Improvement Act of 2002 (2002 Act). These programs included several requirements related to ensuring pipeline safety, and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration.

Pursuant to the 2006 Act, the Pipeline and Hazardous Materials Safety Administration (PHMSA) at the Department of Transportation (DOT) issued regulations, effective February 12, 2010, requiring operators of gas distribution pipelines to develop and implement integrity management programs similar to those required for gas transmission pipelines, but tailored to reflect the differences in distribution pipelines. Operators of natural gas distribution systems were required to write and implement their integrity management programs by August 2, 2011. Our natural gas distribution systems met this deadline.

Pursuant to the 2002 Act and the 2006 Act, PHMSA has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operations and maintenance procedures and operator qualification programs. PHMSA also updated its reporting requirements for natural gas pipelines effective January 1, 2011.

In December 2011, Congress passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Act). This act increases the maximum civil penalties for pipeline safety administrative enforcement actions; requires the DOT to study and report on the expansion of integrity management requirements and the sufficiency of existing gathering line regulations to ensure safety; requires pipeline operators to verify their records on maximum allowable operating pressure; and imposes new emergency response and incident notification requirements.

We anticipate that compliance with PHMSA'sPHMSA’s regulations, performance of the remediation activities by CERC'sCERC’s natural gas distribution companies and intrastate pipelines and verification of records on maximum allowable operating pressure will require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. In particular, the cost of compliance with DOT'sDOT’s integrity management rules

Federal, state, and local regulation of pipeline gathering and transportation services may affect certain aspects of Enable’s business and the market for its products and services.

 

 

Enable’s interstate pipeline systems — EGT, MRTEnable Gas Transmission, LLC (EGT), Enable-Mississippi River Transmission, LLC (MRT) and SESH — are subject to regulation by the FERC under the Natural Gas Act of 1938 (NGA) and are considered natural gas companies. Natural gas companies may not charge rates that have been determined to be unjust or unreasonable by the FERC. In addition, the FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Under the NGA, the rates for service on Enable’s interstate facilities must be just and reasonable and not unduly discriminatory. Generally, the maximum filed recourse rates for interstate pipelines are based on the pipeline’s cost of service including recovery of and a return on the pipeline’s actual prudent investment cost. Key determinants in the ratemaking process are costs of providing service, allowed rate of return, volume throughput and contractual capacity commitment assumptions. Enable’s interstate pipelines business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions. Tariff changes can only be implemented upon approval by the FERC.

 

 

On August 8, 2005, Congress enacted the Energy Policy Act of 2005 (EPAct of 2005). Among other matters, the EPAct of 2005 amended the NGA to add an anti-manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulation to be prescribed by the FERC and, furthermore, provides the FERC with additional civil penalty authority. On January 19, 2006, the FERC issued Order No. 670, a rule implementing the anti-manipulation provisions of the EPAct of 2005. The rules make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to (1) use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The EPAct of 2005 also amends the NGA and the Natural Gas Policy Act of 1978 (NGPA) to give the FERC authority to impose civil penalties for violations of these statutes and FERC’s regulations, rules, and orders, up to $1 million per day per violation for violations occurring after August 8, 2005. Should Enable fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. In addition, the Commodity Futures Trading Commission (CFTC) is directed under the Commodities Exchange Act (CEA) to prevent price manipulations for the commodity and futures markets, including the energy futures markets. Pursuant to the Dodd-Frank Act and other authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1 million or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA.

 

Enable’s transmission lines are subject to state regulation of rates and terms of service. In Oklahoma, its intrastate pipeline system is subject to regulation by the Oklahoma Corporation Commission. Oklahoma has a non-discriminatory access requirement, which is subject to a complaint-based review. In Illinois, Enable’s intrastate pipeline system is subject to regulation by the Illinois Commerce Commission.

 

Intrastate natural gas transportation is largely regulated by the state in which the transportation takes place. An intrastate natural gas pipeline system may transport natural gas in interstate commerce provided that the rates, terms, and conditions of such transportation service comply with FERC regulation and Section 311 of the NGPA and Part 284 of the FERC’s regulations. The NGPA regulates, among other things, the provision of transportation and storage services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a LDClocal distribution company served by an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. The rates under Section 311 are maximum rates and Enable may negotiate contractual rates at

 

Failure to observe the service limitations applicable to transportation services provided under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, or failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in the assertion of federal NGA jurisdiction by

 

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC. Although the FERC has not made formal determinations with respect to all of the facilities Enable considers to be gathering facilities, it believes that its natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is 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 Enable’s 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 Enable’s results of operations and cash flows. In addition, if any of Enable’s facilities were found to have provided services or otherwise operated in violation of the NGA or the NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

 

States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, requirements prohibiting undue discrimination, and in some instances complaint-based rate regulation. Enable’s gathering operations may be subject to ratable take and common purchaser statutes in the states in which they operate. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply and have the effect of restricting Enable’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

 

Enable’s gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Enable’s gathering operations could also be subject to additional safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on Enable’s operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.  

 

Enable provides interstate transportation on its crude oil gathering system in North Dakota pursuant to a public tariff in accordance with FERC regulatory requirements. Crude oil gathering pipelines that provide interstate transportation service may be regulated as a common carrier by the FERC under the Interstate Commerce Act (ICA), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that rates for interstate service pipelines that transport crude oil and refined petroleum products (collectively referred to as “petroleum pipelines”) and certain other liquids, be just and reasonable and are to be non-discriminatory or not confer any undue preference upon any shipper. FERC regulations also require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. Under the ICA, the FERC or interested persons may challenge existing or changed rates or services. The FERC is authorized to investigate such charges and may suspend the effectiveness of a new rate for up to seven months. A successful rate challenge could result in a common carrier paying refunds together with interest for the period that the rate was in effect. The FERC may also order a pipeline to change its rates, and may require a common carrier to pay shippers reparations for damages sustained for a period up to two years prior to the filing of a complaint.  

 

For some time now, the FERC has been issuing regulatory assurances that necessarily balance the anti-discrimination and undue preference requirements of common carriage with the expectations of investors in new and expanding petroleum pipelines. There is an inherent tension between the requirements imposed upon a common carrier and the need for owners of petroleum

 

 

Certain of Enable’s facilities are subject to pipeline safety regulations. PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline facilities. All natural gas transmission facilities, such as Enable’s interstate natural gas pipelines, are subject to PHMSA’s pipeline safety regulations, but natural gas gathering pipelines are subject to the pipeline safety regulations only to the extent they are classified as regulated gathering pipelines. In addition, several NGL pipeline facilities and crude oil pipeline facilities are regulated as hazardous liquids pipelines. Pursuant to various federal statutes, including the Natural Gas Pipeline Safety Act of 1968 (NGPSA), the DOT, through PHMSA, regulates pipeline safety and integrity. NGL and crude oil pipelines are subject to regulation by PHMSA under the HLPSAHazardous Liquid Pipeline Safety Act which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. PHMSA has developed regulations that require natural gas pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high consequence areas (HCAs).areas. Although many of Enable’s pipeline facilities fall within a class that is currently not subject to these integrity management requirements, Enable may incur significant costs and liabilities associated with repair, remediation, preventive or mitigating measures associated with its non-exempt pipelines. Additionally, should Enable fail to comply with DOT or comparable state regulations, it could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that Enable expand its integrity managements program to currently unregulated pipelines, including gathering lines, its costs associated with compliance may have a material effect on its operations.

Our operations and the operations of Enable are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines, distribution systems and storage, electric transmission and distribution systems, and the facilities that support these systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to, among other activities:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been stored, disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

The recent trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment,environment. For example, the Environmental Protection Agency (EPA) has also established air emission control requirements for natural gas and thus thereNGL production, processing and transportation activities, which may affect Enable’s midstream operations. These include New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and the National Emission Standards for Hazardous Air Pollutants (NESHAPS) to address hazardous air pollutants frequently associated with natural gas production and processing activities. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain inmaintain compliance with changing environmental laws and regulations and to ensure the costs of such compliance are reasonable.

Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position, results of operations or cash flows. In addition, we believe that our current environmental remediation activities will not materially interrupt or diminish our operational ability. We cannot assure you however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material current environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify.  To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businessesbusiness could be adversely affected through lower gas sales, and Enable's businesses could experience lower revenues.sales. On the other hand, warmer temperatures in our electric service territory may increase our revenues from transmission and distribution through increased demand for electricity for cooling.  Another possible effect of climate change is more frequent and more severe weather events, such as hurricanes or tornadoes.  Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes could increase our costs to repair damaged facilities and restore service to our customers. When we cannot deliver electricity or natural gas to customers, or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs.  To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

Our operations and the operations of Enable are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions,emissions. We may be required to obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

The EPA continues to adopt amendments to its regulations regardinghas established new air emission control requirements for natural gas and natural gas liquids production, processing and transportation activities. Under the NESHAPS, the EPA established maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule), the most recent being January 14, 2013.  On August 29, 2013, the EPA announced that it was reconsidering three issues related to the RICE MACT rule, but the agency has not subsequently issued a rule proposal.. Compressors and back up electrical generators used by our Natural Gas Distribution segment, and back up electrical generators used by our Electric Transmission & Distribution segment, are generally compliant. Additional rules are expected to be proposed by the EPA this year for compliance by 2016.  We believe, however, that our operations will not be materially adversely affected by such requirements.

Our operations and the operations of Enable are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.

Our operations and the operations of Enable generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment, transport and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is excluded