Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein.

OVERVIEW

Background

We are a public utility holding company. Our operating subsidiaries own and operate electric transmission and distribution facilities and natural gas distribution facilities and own interests in Enable Midstream Partners, LP (Enable) as described below. Our indirect wholly-owned subsidiaries include:


•	CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in the Texas Gulf Coast area that includes the city of Houston; and


•	CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems. A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of December 31, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

•

CenterPoint Energy Resources Corp. (CERC Corp. and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems. A wholly-owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities. As of December 31, 2015, CERC Corp. also owned approximately 55.4% of the limited partner interests in Enable, which owns, operates and develops natural gas and crude oil infrastructure assets.

Business Segments

In this Management’s Discussion and Analysis, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on these segments of the energy business. The results of our business operations are significantly impacted by weather, customer growth, economic conditions, cost management, competition, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to whose jurisdiction we are subject. Our electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. Our natural gas distribution services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. The results of our Midstream Investments segment are dependent upon the results of Enable, which are driven primarily by the volume of natural gas, natural gas liquids (NGLs) and crude oil that Enable gathers, processes and transports across its systems and other factors as discussed below under “— Factors Influencing Our Midstream Investments Segment.” A summary of our reportable business segments as of December 31, 2015 is set forth below:

Electric Transmission & Distribution

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving over 2.3 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.

On behalf of REPs, CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout CenterPoint Houston’s certificated service territory. The Electric Reliability Council of Texas, Inc. (ERCOT) serves as the regional reliability coordinating council for member electric power systems in 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 represents approximately 90% of the

demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

Natural Gas Distribution

CERC owns and operates our regulated natural gas distribution business (NGD), which engages in intrastate natural gas sales to, and natural gas transportation and storage for, approximately 3.4 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.

Energy Services

CERC’s operations also include non-rate regulated natural gas sales to, and transportation and storage services for, commercial and industrial customers in 23 states in the central United States.

Midstream Investments

We have a significant equity investment in Enable, an unconsolidated subsidiary that owns, operates and develops natural gas and crude oil assets. Our Midstream Investments segment includes equity earnings associated with the operations of Enable.

Other Operations

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

EXECUTIVE SUMMARY

Factors Influencing Our Businesses and Industry Trends

We expect our and Enable’s businesses to continue to be affected by the key factors and trends discussed below. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

We are an energy delivery company. The majority of our revenues are generated from the sale of natural gas and the transmission and delivery of electricity by our subsidiaries. We do not own or operate electric generating facilities or make retail sales to end-use electric customers. To assess our financial performance, our management primarily monitors operating income and cash flows from our business segments. Within these broader financial measures, we monitor margins, operation and maintenance expense, interest expense, capital spending and working capital requirements. In addition to these financial measures we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. For example, our business is largely concentrated in Houston, Texas, where a higher percentage of employment is tied to the energy sector relative to other regions of the country. Although Houston, Texas has a diverse economy, employment in the energy industry remains important. Reduced demand and lower energy prices could lead to financial pressure on some of our customers who operate within the energy industry and impact the growth rate of our customer base. Given the significant decline in energy and commodity prices in 2015, the rate of growth in employment in Houston, which had been greater than the national average, has declined and is now more in line with the national average. We expect this trend to continue in the foreseeable future. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results on a weather adjusted basis. In 2015, our Houston service area experienced some of the mildest temperatures on record during November and December. Every state in which we distribute natural gas had a warmer than normal winter in 2015. Historically, NGD has utilized weather hedges to help reduce the impact of mild weather on its financial results. However, NGD did not enter a weather hedge for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. We also have various rate mechanisms in place that help to mitigate the impact of abnormal weather on our financial results. In 2014, we experienced a colder than normal January and February and milder

temperatures for the rest of the year, including the summer months, in the Houston area. In 2013, we experienced a colder than normal spring and very cold weather in November and December in Houston and all of the states in which we have gas customers. Our long-term national trends indicate customers have reduced their energy consumption, and reduced consumption can adversely affect our results. However, due to more affordable energy prices and continued economic improvement in the areas we serve, the trend toward lower usage has slowed in some of the areas we serve. In addition, in many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from a growth in the number of customers that also tends to mitigate the effects of reduced consumption. We anticipate that this trend will continue as the regions’ economies continue to grow. The profitability of our businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and gas distribution rates.

Our Energy Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis. Its operations serve customers in the central United States. The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While this business utilizes financial derivatives to hedge its exposure to price movements, it does not engage in speculative or proprietary trading and maintains a low value at risk level, or VaR, to avoid significant financial exposures. In 2015 and 2014, Energy Services exhibited strong commercial and industrial customer results while capitalizing on asset optimization opportunities created by basis volatility. Extreme cold weather in 2014 also increased throughput and margin from our weather sensitive customers.

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities, proceeds from commercial paper and issuances of debt and equity in the capital markets to satisfy these capital needs. We strive to maintain investment grade ratings for our securities in order to access the capital markets on terms we consider reasonable. A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities, and may prevent us from accessing the commercial paper markets. Disruptions in the financial markets can also affect the availability of new capital on terms we consider attractive. In those circumstances, companies like us may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt.

The regulation of natural gas pipelines and related facilities by federal and state regulatory agencies affects our business. In accordance with natural gas pipeline safety and integrity regulations, we are making, and will continue to make, significant capital investments in our service territories, which are necessary to help operate and maintain a safe, reliable and growing natural gas system. Our compliance expenses may also increase as a result of preventative measures required under these regulations. Consequently, new rates in the areas we serve are necessary to recover these increasing costs.

We expect to make contributions to our pension plans aggregating approximately $8 million in 2016 but may need to make larger contributions in subsequent years. Consistent with the regulatory treatment of such costs, we can defer the amount of pension expense that differs from the level of pension expense included in our base rates for our Electric Transmission & Distribution business segment and Natural Gas Distribution business segment in Texas.

Factors Influencing Our Midstream Investments Segment

The results of our Midstream Investments segment are primarily dependent upon the results of Enable, which are driven primarily by the volume of natural gas, NGLs and crude oil that Enable gathers, processes and transports across its systems, which depends significantly on the level of production from natural gas wells connected to its systems across a number of U.S. mid-continent markets. Aggregate production volumes are affected by the overall amount of oil and gas drilling and completion activities, as production must be maintained or increased by new drilling or other activity, because the production rate of oil and gas wells declines over time.

Oil and gas producers’ willingness to engage in new drilling is determined by a number of factors, the most important of which are the prevailing and projected prices of natural gas, NGLs and crude oil, the cost to drill and operate a well, the availability and cost of capital and environmental and government regulations. Commodity price changes impact the commodity-based portion of Enable’s gross margin, its producer customers’ decisions to drill and complete wells and its transportation and storage customers decisions to contract capacity on Enable’s system. Prices of natural gas, crude oil, and NGLs have historically experienced periods of significant volatility. Enable’s results are also impacted by the price differentials between receipt and delivery points on its systems. Enable has attempted to mitigate the impact of commodity prices on its business by entering into hedges, focusing on contracting fee-based business, and converting existing commodity-based contracts to fee-based contracts. The prices of crude oil, NGLs and natural gas have continued to decline significantly. Over the course of 2015 and continuing into 2016, natural gas and crude oil prices have dropped to their lowest levels in over 10 years from a high of $13.31 per MMBtu in July 2008 to $1.63 per MMBtu at December 23, 2015 and $145.31 per barrel in July 2008 to $26.19 per barrel at February 11, 2016, respectively.

Should lower commodity prices persist, or should commodity prices decline further, Enable’s future volumes and cash flows may be negatively impacted. The level of drilling is expected to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.

Over the past several years, there has been a fundamental shift in U.S. natural gas and crude oil production towards tight gas formations and shale plays. The emergence of these plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas and crude oil. Recently, declining crude oil, natural gas and NGL prices have resulted in decreases in current and anticipated crude oil and natural gas drilling activity. Should lower prices and producer activity persist for a sustained period or should prices and producer activity decline further, Enable’s future volumes and cash flows may be negatively impacted. To maintain and increase throughput volumes on its systems, Enable must continue to contract its capacity to shippers, including producers and marketers. Enable’s transportation and storage systems compete for customers based on the type of service a customer needs, operating flexibility, receipt and delivery points and geographic flexibility and available capacity and price. To maintain and increase Enable’s transportation and storage volumes, it must continue to contract its capacity to shippers, including producers, marketers, local distribution companies, power generators and industrial end users.

Natural gas continues to be a critical component of energy supply and demand in the United States. Over the long term, Enable’s management believes that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. According to the U.S. Energy Information Administration (EIA), demand for natural gas in the electric power sector is projected to increase from approximately 8.2 Tcf in 2013 to approximately 9.4 Tcf in 2040, with a portion of the growth attributable to the retirement of 37 gigawatts of coal-fired capacity by 2020. The EIA also predicts that low natural gas prices will lead to the increase of natural gas consumption in the industrial sector and to the United States becoming a new exporter of natural gas by mid-2017. However, the EIA expects growth in natural gas consumption for power generation, exploration and in the industrial sector to be partially offset by decreased usage in the residential sector. Enable’s management believes that increasing consumption of natural gas over the long term will continue to drive demand for Enable’s natural gas gathering, processing, transportation and storage services.

Enable may access the capital markets to fund expansion capital expenditures. Historically, unit prices of midstream master limited partnerships have experienced periods of volatility. In addition, because Enable’s common units are yield-based securities, rising market interest rates could impact the relative attractiveness of Enable’s common units to investors. Further, fluctuations in energy and commodity prices can create volatility in Enable’s common unit prices, which could impact investor appetite for its common units. Volatility in energy and commodity prices, as well as other macro economic factors could impact the relative attractiveness of Enable’s debt securities to investors. As a result of capital market volatility, Enable may be unable to issue equity or debt on satisfactory terms, or at all, which may limit its ability to expand its operations or make future acquisitions.

The regulation of gathering and transmission pipelines, storage and related facilities by the FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on Enable’s business. For example, PHMSA has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase compliance costs and increase the time it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on Enable’s gathering systems.

Significant Events

Impairment of Equity Investment. We recognized a loss of $1,633 million from our investment in Enable for the year ended December 31, 2015. This loss included impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 9 to our consolidated financial statements.

Brazos Valley Connection Project. In April 2015, CenterPoint Houston filed a Certificate of Convenience and Necessity (CCN) application with the Texas Utility Commission seeking approval to construct the Brazos Valley Connection (CenterPoint Houston’s portion of the Houston region transmission project). CenterPoint Houston proposed 32 alternative routes for the project in the application, including one route (the Recommended Route) that CenterPoint Houston identified in the application as best meeting the routing criteria used by the Texas Utility Commission in the route selection portion of CCN proceedings. The hearing on CenterPoint Houston’s CCN application was divided into two phases, a route-selection phase and a need phase. The route selection hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On January 15, 2016, the Texas Utility Commission issued an order finding that the evidence presented by CenterPoint Houston, ERCOT, and others established the need for the project and approving a CCN for CenterPoint Houston to construct the Brazos

Valley Connection using a modified version of the Recommended Route. A request for rehearing was filed with respect to the Texas Utility Commission’s route selection decision. That request for rehearing will be automatically deemed denied by operation of law on March 10, 2016, unless the Texas Utility Commission acts on the request before that date. The Texas Utility Commission’s order provided an estimated range of approximately $270–$310 million for the capital costs for the Brazos Valley Connection. The actual cost will depend on factors including land acquisition costs, material and construction costs and landowner elections permitted under the Texas Utility Commission’s order. CenterPoint Houston expects to complete construction of the Brazos Valley Connection by mid-2018.

Transmission Cost of Service (TCOS). On June 26, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $87.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the third quarter of 2015, and rates became effective August 17, 2015, resulting in an increase of $13.7 million in annual transmission revenues.

On October 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $107.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the fourth quarter of 2015, and rates became effective November 23, 2015, resulting in an increase of $16.8 million in annual transmission revenue.

Distribution Cost Recovery Factor (DCRF). On April 6, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for a DCRF interim rate adjustment to account for changes in certain distribution-invested capital since its 2010 rate case. The application requested (i) an increase in annual distribution revenue of $16.7 million based on an increase in rate base from January 1, 2010 through December 31, 2014 of $417 million; and (ii) that rates become effective September 1, 2015.

On June 19, 2015, an unopposed settlement agreement was filed providing for an increase in annual distribution revenue of $13.0 million, subject to final Texas Utility Commission approval. The Texas Utility Commission approved the settlement agreement on July 30, 2015. Rates became effective September 1, 2015.

Texas Coast Rate Case. On March 27, 2015, NGD filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and a return on equity (ROE) of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remand at the Railroad Commission of Texas (Railroad Commission) and five cost of service adjustment (COSA) appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.

Arkansas Formula Rate Review Plan (FRP) Legislation. On March 30, 2015, HB 1655 was signed by Governor Hutchinson and became Act 725 (the Act). This legislation introduces a FRP mechanism for utilities and requires that the Arkansas Public Service Commission (APSC) approve a FRP if requested by a utility and allows a utility to use a projected test year. The Act establishes certain parameters, including the use of an earnings band 50 basis points above and below the allowed return on equity and annual rate changes not to exceed 4% of prior year revenues per rate class. The details of a FRP that were not established by the Act are being defined during the rate proceeding currently in process.

Arkansas Rate Case. On August 17, 2015, NGD filed a Notice of Intent to File a general rate case with the APSC. The rate case was filed on November 10, 2015 seeking a $35.6 million increase in revenue requirement and a 10.3% ROE. A procedural schedule has been established with a hearing scheduled for July 12, 2016. A final determination by the APSC is expected in the third quarter of 2016.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the Minnesota Public Utilities Commission (MPUC) requesting an annual increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

Tender Offer for AOL Inc. Common Stock. On May 26, 2015, Verizon Communications, Inc. (Verizon) initiated a tender offer to purchase all outstanding shares of AOL Inc. common stock (AOL Common) for $50 per share, in which we tendered all of our shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS), we remitted $32 million to ZENS holders in July 2015, which reduced contingent principal. As a result, we recorded a reduction in

the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million. As of December 31, 2015, the reference shares for each ZENS note consisted of 0.5 share of Time Warner Inc. common stock (TW Common), 0.125505 share of Time Warner Cable Inc. (TWC) common stock (TWC Common) and 0.0625 share of Time Inc. common stock (Time Common).

Exercise of Put Right. On June 30, 2015, we closed our put right with respect to our remaining interest in Southeast Supply Header, LLC (SESH) and contributed to Enable our remaining 0.1% interest in SESH in exchange for 25,341 limited partner units of Enable. No cash payment was required to be made pursuant to the Enable formation agreements in connection with our exercise.

Debt Repayments. In June 2015, we repaid our $200 million 6.85% Senior Notes using proceeds from our commercial paper program. In October 2015, we repaid our $69 million 4.9% pollution control bonds using proceeds from our commercial paper program.

Retirement of Bonds. In November 2015, we retired $740 million of tax-exempt municipal bonds that had been held for remarketing.

Private Placement. On January 28, 2016, we entered into a purchase agreement with Enable pursuant to which we agreed to purchase in a private placement (Private Placement) an aggregate of 14,520,000 10% Series A Fixed-to-Floating Non-Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in Enable (Series A Preferred Units) for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used the proceeds from this redemption for our investment in the Series A Preferred Units.

Continuum Acquisition. On January 29, 2016, CenterPoint Energy Services (CES), our indirect, wholly-owned subsidiary, announced an agreement to acquire the retail commercial and industrial businesses of Continuum Energy Services (Continuum), a Tulsa and Houston-based company, for $77.5 million plus working capital. The transaction is conditioned upon the receipt of certain third party consents and approvals. We expect the transaction to close by the end of the first quarter of 2016.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our and Enable’s future earnings and results of our and Enable’s operations will depend on or be affected by numerous factors including:


•	the performance of Enable, the amount of cash distributions we receive from Enable, and the value of our interest in Enable, and factors that may have a material impact on such performance, cash distributions and value, including factors such as:


◦	competitive conditions in the midstream industry, and actions taken by Enable’s customers and competitors, including the extent and timing of the entry of additional competition in the markets served by Enable;


◦	the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;

◦

the timing and extent of changes in the supply of natural gas and associated commodity prices, particularly prices of natural gas and NGLs, the competitive effects of the available pipeline capacity in the regions served by Enable, and the effects of geographic and seasonal commodity price differentials, including the effects of these circumstances on re-contracting available capacity on Enable’s interstate pipelines;


◦	the demand for crude oil, natural gas, NGLs and transportation and storage services;


◦	environmental and other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing;


◦	recording of non-cash goodwill, long-lived asset or other than temporary impairment charges by or related to Enable;


◦	changes in tax status;


◦	access to debt and growth capital; and


◦	the availability and prices of raw materials and services for current and future construction projects;


•	state and federal legislative and regulatory actions or developments affecting various aspects of our businesses (including the businesses of Enable), including, among others, energy deregulation or re-regulation, pipeline integrity and safety, health care reform, financial reform, tax legislation and actions regarding the rates charged by our regulated businesses;


•	timely and appropriate rate actions that allow recovery of costs and a reasonable return on investment;


•	industrial, commercial and residential growth in our service territories and changes in market demand, including the effects of energy efficiency measures and demographic patterns;


•	future economic conditions in regional and national markets and their effect on sales, prices and costs;


•	weather variations and other natural phenomena, including the impact of severe weather events on operations and capital;


•	our ability to mitigate weather impacts through normalization or rate mechanisms, and the effectiveness of such mechanisms;


•	the timing and extent of changes in commodity prices, particularly natural gas, and the effects of geographic and seasonal commodity price differentials;


•	problems with regulatory approval, construction, implementation of necessary technology or other issues with respect to major capital projects that result in delays or in cost overruns that cannot be recouped in rates;


•	local, state and federal legislative and regulatory actions or developments relating to the environment, including those related to global climate change;


•	the impact of unplanned facility outages;


•	any direct or indirect effects on our facilities, operations and financial condition resulting from terrorism, cyber-attacks, data security breaches or other attempts to disrupt our businesses or the businesses of third parties, or other catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, hurricanes, pandemic health events or other occurrences;


•	our ability to invest planned capital and the timely recovery of our investment in capital;


•	our ability to control operation and maintenance costs;


•	actions by credit rating agencies;


•	the sufficiency of our insurance coverage, including availability, cost, coverage and terms;


•	the investment performance of our pension and postretirement benefit plans;


•	commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;


•	changes in interest rates or rates of inflation;


•	inability of various counterparties to meet their obligations to us;


•	non-payment for our services due to financial distress of our customers;


•	effectiveness of our risk management activities;


•	timely and appropriate regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;


•	our potential business strategies, including restructurings, joint ventures and acquisitions or dispositions of assets or businesses, which we cannot assure you will be completed or will have the anticipated benefits to us;


•	acquisition and merger activities involving us or our competitors;


•	our or Enable’s ability to recruit, effectively transition and retain management and key employees and maintain good labor relations;


•	the ability of GenOn Energy, Inc. (formerly known as RRI Energy, Inc., Reliant Energy, Inc. and Reliant Resources, Inc.), a wholly-owned subsidiary of NRG Energy, Inc. (NRG), and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or obligations in connection with the contractual arrangements pursuant to which we are their guarantor;


•	the outcome of litigation;


•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings Corp., to satisfy their obligations to us and our subsidiaries;


•	changes in technology, particularly with respect to efficient battery storage or the emergence or growth of new, developing or alternative sources of generation;


•	the timing and outcome of any audits, disputes and other proceedings related to taxes;


•	the effective tax rates;


•	the effect of changes in and application of accounting standards and pronouncements; and


•	other factors we discuss under “Risk Factors” in Item 1A of this report and in other reports we file from time to time with the Securities and Exchange Commission.

CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.



	Year Ended December 31,
	2015			2014			2013
Revenues	$	7,386		$	9,226		$	8,106
Expenses	6,453			8,291			7,096
Operating Income	933			935			1,010
Gain (Loss) on Marketable Securities	(93		)	163			236
Gain (Loss) on Indexed Debt Securities	74			(86		)	(193		)
Interest and Other Finance Charges	(352		)	(353		)	(351		)
Interest on Transition and System Restoration Bonds	(105		)	(118		)	(133		)
Equity in Earnings (Losses) of Unconsolidated Affiliates	(1,633		)	308			188
Other Income, net	46			36			24
Income (Loss) Before Income Taxes	(1,130		)	885			781
Income Tax Expense (Benefit)	(438		)	274			470
Net Income (Loss)	$	(692	)	$	611		$	311

Basic Earnings (Loss) Per Share	$	(1.61	)	$	1.42		$	0.73

Diluted Earnings (Loss) Per Share	$	(1.61	)	$	1.42		$	0.72

2015 Compared to 2014

Net Income. We reported a net loss of $692 million ($(1.61) per diluted share) for 2015 compared to net income of $611 million ($1.42 per diluted share) for the same period in 2014.

The decrease in net income of $1,303 million was due to the following key factors:


•	a $1,941 million decrease in equity earnings of unconsolidated affiliates, which included impairment charges of $1,846 million, discussed further in Note 9 to our consolidated financial statements; and


•	a $256 million increase in the loss on our marketable securities.

These decreases were partially offset by:


•	a $712 million decrease in income tax expense;


•	a $160 million increase in the gain on our indexed debt securities;


•	a $13 million decrease in interest expense related to our transition and system restoration bonds; and


•	an $10 million increase in other income.

Income Tax Expense. We reported an effective tax rate of 38.8% and 31.0% for the years ended December 31, 2015 and 2014, respectively. The higher effective tax rate of 38.8% is primarily due to lower earnings from the impairment of our investment in Enable. The impairment loss reduced the deferred tax liability on our investment in Enable. The effective tax rate of 31.0% for 2014 is primarily due to a $29 million tax benefit recognized upon completion of a tax basis balance sheet review and a $13 million reversal of previously accrued taxes as a result of final positions taken in the 2013 tax returns. We determined the impact of the $29 million adjustment was not material to any prior period or the year ended December 31, 2014.

2014 Compared to 2013

Net Income. We reported net income of $611 million ($1.42 per diluted share) for 2014 compared to $311 million ($0.72 per diluted share) for the same period in 2013.

The increase in net income of $300 million was due to the following key factors:


•	a $196 million decrease in income tax expense discussed below;


•	a $120 million increase in equity earnings of unconsolidated affiliates;


•	a $107 million decrease in the loss on our indexed debt securities;


•	a $13 million decrease in interest expense; and


•	a $12 million increase in other income.

These increases were partially offset by:


•	a $75 million decrease in operating income (discussed below by segment); and


•	a $73 million decrease in the gain on our marketable securities.

Income Tax Expense. We reported an effective tax rate of 31.0% and 60.2% for the years ended December 31, 2014 and 2013, respectively. The effective tax rate of 31.0% for 2014 is primarily due to a $29 million tax benefit recognized upon completion of a tax basis balance sheet review and a $13 million reversal of previously accrued taxes as a result of final positions taken in the 2013 tax returns. We determined the impact of the $29 million adjustment was not material to any prior period or the year ended December 31, 2014. The effective tax rate of 60.2% for 2013 is primarily attributable to a net $196 million charge to deferred tax expense due to the formation of Enable. For more information, see Note 13 to our consolidated financial statements.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our business segments for 2015, 2014 and 2013. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.

Operating Income (Loss) by Business Segment



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Electric Transmission & Distribution	$	607	$	595	$	607
Natural Gas Distribution	273		287		263
Energy Services	42		52		13
Interstate Pipelines	—		—		72
Field Services	—		—		73
Other Operations	11		1		(18		)
Total Consolidated Operating Income	$	933	$	935	$	1,010

Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Revenues:	(in millions, except throughput and customer data)
Electric transmission and distribution utility	$	2,364	$	2,279	$	2,063
Transition and system restoration bond companies	481		566		507
Total revenues	2,845		2,845		2,570
Expenses:
Operation and maintenance, excluding transition and system restoration bond companies	1,300		1,251		1,045
Depreciation and amortization, excluding transition and system restoration bond companies	340		327		319
Taxes other than income taxes	222		224		225
Transition and system restoration bond companies	376		448		374
Total expenses	2,238		2,250		1,963
Operating Income	$	607	$	595	$	607
Operating Income:
Electric transmission and distribution operations	$	502	$	477	$	474
Transition and system restoration bond companies (1)	105		118		133
Total segment operating income	$	607	$	595	$	607
Throughput (in gigawatt-hours (GWh)):
Residential	28,995		27,498		27,485
Total	84,191		81,839		79,985
Number of metered customers at end of period:
Residential	2,079,899		2,033,027		1,982,699
Total	2,348,517		2,299,247		2,244,289


(1)	Represents the amount necessary to pay interest on the transition and system restoration bonds.

2015 Compared to 2014. Our Electric Transmission & Distribution business segment reported operating income of $607 million for 2015, consisting of $502 million from our regulated electric transmission and distribution utility operations (TDU) and $105 million related to transition and system restoration bond companies (Bond Companies). For 2014, operating income totaled $595 million, consisting of $477 million from the TDU and $118 million related to Bond Companies.

TDU operating income increased $25 million due to the following key factors:


•	higher transmission-related revenues of $81 million, which were partially offset by increased transmission costs billed by transmission providers of $47 million;

customer growth of $25 million from the addition of nearly 50,000 new customers;
higher usage of $17 million, primarily due to a return to normal weather; and
rate relief associated with distribution capital investments of $5 million.

These increases to operating income were partially offset by the following:

lower equity return of $20 million, primarily related to true-up proceeds;


•	lower revenues from energy efficiency bonuses of $15 million, including a one-time energy efficiency remand bonus in 2014 of $8 million;

higher depreciation of $13 million; and
lower right-of-way revenues of $7 million.

2014 Compared to 2013. Our Electric Transmission & Distribution business segment reported operating income of $595 million for 2014, consisting of $477 million from the TDU and $118 million related to Bond Companies. For 2013, operating income totaled $607 million, consisting of $474 million from the TDU and $133 million related to Bond Companies.

TDU operating income increased $3 million due to the following key factors:

customer growth of $33 million from the addition of almost 55,000 new customers;
higher equity return of $23 million, primarily related to true-up proceeds; and


•	higher energy efficiency performance bonus of $15 million.

These increases to operating income were partially offset by the following:


•	increased labor and support services costs of $21 million;


•	increased contracts and services of $19 million;


•	lower right-of-way revenues of $8 million;


•	increased depreciation of $8 million;


•	an adjustment to our claims liability reserve of $6 million;


•	decreased usage of $5 million, primarily due to milder weather; and


•	increased transmission costs billed by transmission providers of $168 million, which were largely offset by increased transmission-related revenues of $164 million.

Natural Gas Distribution

The following table provides summary data of our Natural Gas Distribution business segment for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions, except throughput and customer data)
Revenues	$	2,632	$	3,301	$	2,863
Expenses:
Natural gas	1,297		1,961		1,607
Operation and maintenance	697		700		667
Depreciation and amortization	222		201		185
Taxes other than income taxes	143		152		141
Total expenses	2,359		3,014		2,600
Operating Income	$	273	$	287	$	263
Throughput (in Bcf):
Residential	171		197		182
Commercial and industrial	262		270		265
Total Throughput	433		467		447
Number of customers at end of period:
Residential	3,149,845		3,124,542		3,090,966
Commercial and industrial	253,921		249,272		247,100
Total	3,403,766		3,373,814		3,338,066

2015 Compared to 2014. Our Natural Gas Distribution business segment reported operating income of $273 million for 2015 compared to $287 million for 2014.

Operating income decreased $14 million primarily as a result of the following key factors:


•	decreased usage of $25 million as a result of warmer weather compared to the prior year, partially mitigated by weather hedges and weather normalization adjustments;


•	higher depreciation and amortization of $22 million; and


•	increase in taxes of $2 million.

These decreases were partially offset by:


•	rate increases of $23 million;


•	increased economic activity across our footprint of $7 million, including the addition of approximately 30,000 customers; and


•	increased other revenue of $5 million.

Decreased expense related to energy efficiency programs of $4 million and decreased expense related to higher gross receipt taxes of $10 million were offset by a corresponding decrease in the related revenues.

2014 Compared to 2013. Our Natural Gas Distribution business segment reported operating income of $287 million for 2014 compared to $263 million for 2013.

Operating income increased $24 million as a result of the following key factors:


•	increased usage of $16 million as a result of colder weather compared to the prior year, partially mitigated by weather hedges and weather normalization adjustments;


•	rate increases of $37 million; and


•	increased economic activity across our footprint of $10 million, including the addition of approximately 36,000 customers.

These increases were partially offset by:


•	increased contractor expense of $10 million, including pipeline integrity work;


•	higher depreciation and amortization of $16 million;


•	increase in taxes of $7 million; and


•	increased other operating expenses of $6 million.

Increased expense related to energy efficiency programs of $8 million and increased expense related to higher gross receipt taxes of $4 million were offset by a corresponding increase in the related revenues.

Energy Services

The following table provides summary data of our Energy Services business segment for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions, except throughput and customer data)
Revenues	$	1,957	$	3,179	$	2,401
Expenses:
Natural gas	1,867		3,073		2,336
Operation and maintenance	42		47		46
Depreciation and amortization	5		5		5
Taxes other than income taxes	1		2		1
Total expenses	1,915		3,127		2,388
Operating Income	$	42	$	52	$	13

Mark-to-market gain (loss)	$	4	$	29	$	(2	)

Throughput (in Bcf)	618		631		600

Number of customers at end of period (1)	18,099		17,964		17,510


(1)	These numbers do not include approximately 9,700 and 8,800 natural gas customers as of December 31, 2014 and 2013, respectively, that are under residential and small commercial choice programs invoiced by their host utility.

2015 Compared to 2014. Our Energy Services business segment reported operating income of $42 million for 2015 compared to $52 million for 2014. The decrease in operating income of $10 million was due to a $25 million decrease from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. In 2015, a $4 million mark-to-market benefit was recorded as compared to a benefit of $29 million in 2014. Offsetting this decrease was a $5 million reduction in operation and maintenance expenses and a $4 million benefit related to a lower inventory write down in 2015. The remaining increase in operating income was primarily due to improved margins resulting from reduced fixed costs.

2014 Compared to 2013. Our Energy Services business segment reported operating income of $52 million for 2014 compared to $13 million for 2013. The increase in operating income of $39 million was primarily due to a $31 million increase from mark-to-market accounting for derivatives associated with certain natural gas purchases and sales used to lock in economic margins. A $29 million mark-to-market gain was incurred in 2014 compared to a charge of $2 million in 2013. The remaining increase in operating income was primarily due to improved margins resulting from weather-related optimization of existing gas transportation assets, reduced fixed costs and increased throughput and price volatility.

Interstate Pipelines

Substantially all of our Interstate Pipelines business segment was contributed to Enable on May 1, 2013. As a result, this segment did not report operating results for 2014 or 2015. Our equity method investment and related equity income in Enable are included in our Midstream Investments segment. The following table provides summary data of our Interstate Pipelines business segment for 2013:



	Year Ended
	December 31, 2013 (1)
	(in millions, except throughput data)
Revenues	$	186
Expenses:
Natural gas	35
Operation and maintenance	51
Depreciation and amortization	20
Taxes other than income taxes	8
Total expenses	114
Operating Income	$	72

Equity in earnings of unconsolidated affiliates	$	7

Transportation throughput (in Bcf)	482

(1) Represents January 2013 through April 2013 results only.

Equity Earnings. This business segment recorded equity income of $7 million for the year ended December 31, 2013 from its interest in Southeast Supply Header, LLC (SESH), a jointly-owned pipeline. Beginning May 1, 2013, equity earnings related to our interest in SESH and Enable are reported as components of equity income in our Midstream Investments segment.

Field Services

Substantially all of our Field Services business segment was contributed to Enable on May 1, 2013. As a result, this segment did not report operating results for 2014 or 2015. Our equity method investment and related equity income in Enable are included in our Midstream Investments segment. The following table provides summary data of our Field Services business segment for 2013:



	Year Ended
	December 31, 2013 (1)
	(in millions, except throughput data)
Revenues	$	196
Expenses:
Natural gas	54
Operation and maintenance	45
Depreciation and amortization	20
Taxes other than income taxes	4
Total expenses	123
Operating Income	$	73

Gathering throughput (in Bcf)	252

(1) Represents January 2013 through April 2013 results only.

Midstream Investments

The following table summarizes the equity earnings (losses) of our Midstream Investments business segment for 2015, 2014 and 2013:



	Year Ended December 31,
	2015 (2)			2014 (3)		2013 (4)
	(in millions)
Enable (1)	$	(1,633	)	$	303	$	173
SESH	—			5		8
Total	$	(1,633	)	$	308	$	181


(1)	These amounts include our share of Enable’s impairment of goodwill and long-lived assets and the impairment of our equity method investment in Enable totaling $1,846 million during the year ended December 31, 2015. This impairment is offset by $213 million of earnings for the year ended December 31, 2015.


(2)	We contributed our remaining 0.1% interest in SESH to Enable on June 30, 2015.


(3)	On April 16, 2014, Enable completed its initial public offering and, as a result, our limited partner interest in Enable was reduced from approximately 58.3% to approximately 54.7%. On May 30, 2014, we contributed to Enable our 24.95% interest in SESH, which increased our limited partner interest in Enable from approximately 54.7% to approximately 55.4% and reduced our interest in SESH to 0.1%.


(4)	Represents our 58.3% limited partner interest in Enable and our 25.05% interest in SESH for the eight months ended December 31, 2013.

Other Operations

The following table provides summary data for our Other Operations business segment for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Revenues	$	14	$	15	$	14
Expenses	3		14		32
Operating Income (Loss)	$	11	$	1	$	(18	)

2015 Compared to 2014. Our Other Operations business segment reported operating income of $11 million for 2015 compared to $1 million for 2014. The increase in operating income of $10 million is primarily related to decreased administrative and benefits costs ($8 million), decreased depreciation and amortization ($1 million) and decreased property taxes ($1 million).

2014 Compared to 2013. Our Other Operations business segment reported operating income of $1 million for 2014 compared to an operating loss of $18 million for 2013. The increase in operating income of $19 million is primarily related to the costs associated with the formation of Enable in 2013 ($13 million) and decreased benefits costs ($8 million), which were partially offset by higher property taxes ($2 million).

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2015, 2014 and 2013 is as follows:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Cash provided by (used in):
Operating activities	$	1,865		$	1,397		$	1,613
Investing activities	(1,387		)	(1,384		)	(1,300		)
Financing activities	(512		)	77			(751		)

Cash Provided by Operating Activities

Net cash provided by operating activities increased $468 million in 2015 compared to 2014 primarily due to decreased net tax payments ($237 million), increased cash related to a decrease in gas storage inventory ($113 million), increased cash provided by net accounts receivable/payable ($85 million), increased cash provided by fuel cost recovery ($84 million), decreased net margin deposits ($75 million), increased cash provided by net regulatory assets and liabilities ($41 million) and increased cash from non-trading derivatives ($27 million), which were partially offset by decreased distributions from equity method investments ($159 million).

Net cash provided by operating activities decreased $216 million in 2014 compared to 2013 primarily due to increased net tax payments ($157 million), decreased cash provided by fuel cost recovery ($149 million), increased net margin deposits ($95 million), decreased cash related to gas storage inventory ($69 million), decreased cash from non-trading derivatives ($38 million) and decreased cash provided by net regulatory assets and liabilities ($39 million), which was partially offset by increased distributions from equity method investments ($176 million) and increased cash provided by net accounts receivable/payable ($140 million).

Cash Used in Investing Activities

Net cash used in investing activities increased $3 million in 2015 compared to 2014 primarily due to increased capital expenditures ($212 million), which were partially offset by a return of capital from unconsolidated affiliates ($148 million), increased proceeds from sale of marketable securities ($32 million) and decreased restricted cash ($19 million).

Net cash used in investing activities increased $84 million in 2014 compared to 2013 primarily due to increased capital expenditures ($86 million), increased restricted cash ($24 million) and decreased proceeds from sale of marketable securities ($9 million), which were partially offset by decreased cash contributed to Enable ($38 million).

Cash Provided by (Used in) Financing Activities

Net cash used in financing activities increased $589 million in 2015 compared to 2014 primarily due to decreased proceeds from long-term debt ($600 million), increased payments of long-term debt ($107 million), increased distributions to ZENS holders ($32 million), decreased short-term borrowings ($23 million), increased payments of common stock dividends ($18 million) and decreased proceeds from commercial paper ($11 million), which were partially offset by increased borrowings under our revolving credit facility ($200 million).

Net cash provided by financing activities increased $828 million in 2014 compared to 2013 primarily due to decreased payments of long-term debt ($1,036 million) and increased proceeds from commercial paper ($296 million), which were partially offset by decreased proceeds from long-term debt ($450 million) and increased payments of common stock dividends ($53 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs and various regulatory actions. Our principal anticipated cash requirements for 2016 include the following:


•	capital expenditures of approximately $1.4 billion;


•	scheduled principal payments on transition and system restoration bonds of $391 million;


•	investment in Enable’s Series A Preferred Units of $363 million;


•	maturing senior notes of $325 million;


•	acquisition of the retail commercial and industrial businesses of Continuum for $77.5 million plus working capital;and


•	dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that anticipated 2016 cash needs will be met with borrowings under our credit facilities, proceeds from commercial paper, proceeds from the issuance of general mortgage bonds, anticipated cash flows from operations and distributions from Enable and Enable’s redemption of $363 million of notes owed to a wholly-owned subsidiary of CERC Corp. Discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets, funds raised in the commercial paper markets and additional credit facilities may not, however, be available to us on acceptable terms.

The following table sets forth our capital expenditures for 2015 and estimates of our capital expenditures for currently identified or planned projects for 2016 through 2020:



	2015		2016		2017		2018		2019		2020
	(in millions)
Electric Transmission & Distribution	$	934	$	833	$	786	$	735	$	685	$	686
Natural Gas Distribution	601		485		470		435		430		430
Energy Services	5		5		26		—		1		—
Other Operations	35		39		33		28		25		26
Total	$	1,575	$	1,362	$	1,315	$	1,198	$	1,141	$	1,142

Our capital expenditures are expected to be used for investment in infrastructure for our electric transmission and distribution operations and our natural gas distribution operations. These capital expenditures are anticipated to maintain reliability and safety as well as expand our systems through value-added projects.

The following table sets forth estimates of our contractual obligations, including payments due by period:



Contractual Obligations	Total		2016		2017-2018		2019-2020		2021 and thereafter
	(in millions)
Transition and system restoration bond debt	$	2,674	$	391	$	845	$	689	$	749
Other long-term debt (1)	6,648		325		1,150		1,135		4,038
Interest payments — transition and system restoration bond debt (2)	367		95		146		76		50
Interest payments — other long-term debt (2)	3,639		290		504		406		2,439
Short-term borrowings	40		40		—		—		—
Capital leases	3		3		—		—		—
Operating leases (3)	24		5		7		5		7
Benefit obligations (4)	—		—		—		—		—
Non-trading derivative liabilities	16		11		5		—		—
Other commodity commitments (5)	1,685		478		862		307		38
Total contractual cash obligations (6)	$	15,096	$	1,638	$	3,519	$	2,618	$	7,321

(1)

2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) obligations are included in the 2021 and thereafter column at their contingent principal amount as of December 31, 2015 of $705 million. These obligations are exchangeable for cash at any time at the option of the holders for 95% of the current value of the reference shares attributable to each ZENS ($805 million as of December 31, 2015), as discussed in Note 10 to our consolidated financial statements.


(2)	We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2015. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.


(3)	For a discussion of operating leases, please read Note 14(c) to our consolidated financial statements.


(4)	In 2016, we are not required to make contributions to our qualified pension plan. We expect to contribute approximately $8 million and $16 million, respectively, to our non-qualified pension and postretirement benefits plans in 2016.


(5)	For a discussion of other commodity commitments, please read Note 14(a) to our consolidated financial statements.


(6)	This table does not include estimated future payments for expected future asset retirement obligations. These payments are primarily estimated to be incurred after 2021. We record a separate liability for the fair value of these asset retirement obligations which totaled $195 million as of December 31, 2015. See Note 3(c) to our consolidated financial statements.

Off-Balance Sheet Arrangements

Prior to the distribution of our ownership in Reliant Resources, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. When the companies separated, RRI agreed to secure CERC against obligations under the guarantees RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI (now GenOn Energy, Inc. (GenOn)) agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guarantees for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guarantees based on an annual calculation, with any required collateral to be posted each December. The undiscounted maximum potential payout of the demand charges under these transportation contracts, which will be in effect until 2018, was approximately $27 million as of December 31, 2015. Based on market conditions in the fourth quarter of 2015 at the time the most recent annual calculation was made under the agreement, GenOn was not obligated to post any security. If GenOn should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, any collateral provided as security may be insufficient to satisfy CERC’s obligations.

CenterPoint Energy has provided guarantees (CenterPoint Midstream Guarantees) with respect to the performance of certain obligations of Enable under long-term gas gathering and treating agreements with an indirect, wholly-owned subsidiary of Encana Corporation (Encana) and an indirect, wholly-owned subsidiary of Royal Dutch Shell plc (Shell). Under the terms of the omnibus agreement entered into in connection with the closing of the formation of Enable, Enable and CenterPoint Energy have agreed to use commercially reasonable efforts and cooperate with each other to terminate the CenterPoint Midstream Guarantees and to release CenterPoint Energy from such guarantees by causing Enable or one of its subsidiaries to enter into substitute guarantees or to assume the CenterPoint Midstream Guarantees as applicable. The guarantee in favor of the indirect, wholly-owned subsidiary of Encana was released on August 24, 2015. As of December 31, 2015, CenterPoint Energy had guaranteed Enable’s obligations up to an aggregate amount of $50 million under the guarantee in favor of the indirect, wholly-owned subsidiary of Shell.

CERC Corp. has also provided a guarantee of collection of $1.1 billion of Enable’s senior notes due 2019 and 2024. This guarantee is subordinated to all senior debt of CERC Corp. and is subject to automatic release on May 1, 2016.

The fair value of these guarantees is not material. Other than the guarantees described above and operating leases, we have no off-balance sheet arrangements.

Regulatory Matters

CenterPoint Houston

Brazos Valley Connection Project. In July 2013, CenterPoint Houston and other transmission service providers submitted analyses and transmission proposals to ERCOT for an additional transmission path into the Houston region. In April 2014, ERCOT’s Board of Directors voted to endorse a Houston region transmission project and deemed its completion before June 2018 critical for reliability. The project will consist of (i) construction of a new double-circuit 345 kilovolt (kV) line spanning approximately 130 miles, (ii) upgrades to three substations to accommodate new connections and additional capacity, and (iii) improvements to approximately 11 miles of an existing 345 kV TH Wharton-Addicks transmission line to increase its rating. Also in April 2014, ERCOT staff determined that CenterPoint Houston would be the designated transmission service provider for the portion of the project between our Zenith substation and the Gibbons Creek substation owned by the Texas Municipal Power Agency, consisting of approximately 60–78 miles (depending on the route approved by the Texas Utility Commission) of 345 kV transmission line, upgrades to the Limestone and Zenith substations and upgrades to 11 miles of the 345 kV TH Wharton-Addicks transmission line (this portion of the Houston region transmission project is referred to by CenterPoint Houston as the Brazos Valley Connection). Other transmission service providers were designated by ERCOT for the portion of the project from the Gibbons Creek Substation to the Limestone Substation as well as the upgrades to the Gibbons Creek Substation. In April 2015, CenterPoint Houston filed a CCN application with the Texas Utility Commission seeking approval to construct the Brazos Valley Connection. CenterPoint Houston proposed 32 alternative routes for the project in the application, including the Recommended Route that CenterPoint Houston identified in the application as best meeting the routing criteria used by the Texas Utility Commission in the route selection portion of CCN proceedings. The hearing on CenterPoint Houston’s CCN application was divided into two phases, a route-selection phase and a need phase. The route selection hearing was held on August 17 and 18, 2015. The hearing on the need for the line was held on September 2 and 3, 2015. On January 15, 2016, the Texas Utility Commission issued an order finding that the evidence presented by CenterPoint Houston, ERCOT, and others established the need for the project and approving a CCN for CenterPoint Houston to construct the Brazos Valley Connection using a modified version of the Recommended Route. A request for rehearing was filed with respect to the Texas Utility Commission’s route selection decision. That request for rehearing will automatically be deemed denied by operation of law on March 10, 2016, unless the Texas Utility Commission acts on the request before that date. No party filed a request for rehearing on the order’s need decision before the deadline expired and, therefore, that decision is final and not appealable. The Texas Utility Commission’s order provided an estimated range of approximately $270–$310 million for the capital costs for the Brazos Valley Connection. The actual cost will depend on factors including land acquisition costs, material and construction costs and landowner elections permitted under the Texas Utility Commission’s order. CenterPoint Houston expects to complete construction of the Brazos Valley Connection by mid-2018.

In May 2014, several electric generators appealed the ERCOT Board of Directors’ April 2014 approval of the Houston region transmission project and the determination that the project was critical for reliability in the Houston region to the Texas Utility Commission. That appeal was denied by the Texas Utility Commission in December 2014. In March 2015, the electric generators petitioned the Texas District Court of Travis County for judicial review of the Texas Utility Commission’s denial of their appeal. That case is currently pending before that court.

Transmission Cost of Service. On November 21, 2014, CenterPoint Houston filed an application, as amended, with the Texas Utility Commission seeking an increase in annual transmission revenues based on an incremental increase in total rate base of

$113.2 million. CenterPoint Houston received approval from the Texas Utility Commission during the first quarter of 2015, and rates became effective February 25, 2015, resulting in an increase of $23.5 million in annual transmission revenues.

On June 26, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an interim update of its TCOS seeking an increase in annual transmission revenues based on an incremental increase of $87.6 million in total rate base. The Texas Utility Commission approved CenterPoint Houston’s application in the third quarter of 2015, and rates became effective August 17, 2015, resulting in an increase of $13.7 million in annual transmission revenues.

Distribution Cost Recovery Factor. On April 6, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for a DCRF interim rate adjustment to account for changes in certain distribution-invested capital since its 2010 rate case. The application requested (i) an increase in annual distribution revenue of $16.7 million based on an increase in rate base from January 1, 2010 through December 31, 2014 of $417 million; and (ii) that rates become effective September 1, 2015.

The DCRF application must be filed between April 1 and April 8 of any given year. The application includes recovery of specific incremental distribution-related invested capital, including poles, transformers, conductors, meters and telecommunication equipment from the previous rate case to the end of the DCRF update period, less an adjustment for the related accumulated deferred income taxes. The application includes recovery of return on investment, depreciation expense, federal income tax, and other associated taxes less an adjustment for changes in customer count and weather normalized usage during the update period. The allocation to customer classes is conducted in the same manner as current rates. Any authorized rate change is applied to all retail customers on an energy or demand charge basis, effective September 1, 2015, through a separate DCRF charge. Only four DCRF changes may be implemented between rate cases. The utility must file an earnings monitoring report (EMR) annually with the DCRF application. By law, a DCRF application will be denied if the EMR shows the utility is earning more than its authorized rate of return using 10-year weather normalized data.

Energy Efficiency Cost Recovery Factor (EECRF). On June 1, 2015, CenterPoint Houston filed an application with the Texas Utility Commission for an adjustment to its EECRF to recover $37.7 million in 2016, including an incentive of $6.6 million based on 2014 program performance. In October 2015, the Texas Utility Commission approved the application to recover $37.6 million. The effective date of the rate adjustment will be March 1, 2016.

CERC

Texas Coast Rate Case. On March 27, 2015, NGD filed a Statement of Intent with each of the 49 cities and unincorporated areas within its Texas Coast service territory for a $6.8 million annual revenue increase. This increase was based on a rate base of $132.3 million and an ROE of 10.25%. On July 6, 2015, the parties agreed to a settlement providing for a $4.9 million annual increase to rates, an ROE of 10.0%, 54.5% equity and authorized overall rate of return of 8.23%. This settlement resolved six outstanding cases on appeal: one on remand at the Railroad Commission and five COSA appeals at the district court. The Railroad Commission unanimously approved the settlement on August 25, 2015. Rates were implemented in September 2015.

Houston, South Texas and Beaumont/East Texas GRIP. NGD’s Houston, South Texas and Beaumont/East Texas Divisions each submitted annual GRIP filings on March 31, 2015. For the Houston Division, NGD asked that its GRIP filing to recover costs related to $46.4 million in incremental capital expenditures that were incurred in 2014 be operationally suspended for one year so as to ensure that earnings are more consistent with those currently approved. For the South Texas Division, the revised filing requested recovery of costs related to $22.2 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filing period is $4.0 million annually based on an authorized overall rate of return of 8.75%. For the Beaumont/East Texas Division, the GRIP filing requested recovery of costs related to $34.3 million in incremental capital expenditures that were incurred in 2014. The increase in revenue requirements for this filing period is $5.9 million annually based on an authorized overall rate of return of 8.51%. For the South Texas and Beaumont/East Texas Divisions, rates were implemented for certain customers in May 2015. For those areas in which the jurisdictional deadline was extended by regulatory action, the rates were implemented in July 2015 following approval by the Railroad Commission.

Oklahoma Performance Based Rate Change (PBRC). In March 2015, NGD made a PBRC filing for the 2014 calendar year proposing to increase revenues by $0.9 million. On November 4, 2015, the Oklahoma Corporation Commission approved the request.

Arkansas Energy Efficiency Cost Recovery (EECR). On March 31, 2015, NGD made an EECR filing with the APSC to recover $5.9 million for the 2015 program year. The purpose of the EECR is to recover NGD’s estimated expenses and lost contributions to fixed cost for the energy efficiency programs approved by the APSC and administered either jointly or individually by NGD, plus a utility incentive earned for 2014, with adjustments for any over- or under-recovery from the prior period. The impact to customer bills is expected to be a small reduction due to actual program costs being less than estimated and a colder than normal year causing more EECR revenues than anticipated. New rates went into effect in July 2015.

Louisiana Rate Stabilization Plan (RSP). NGD made its 2015 Louisiana RSP filings with the Louisiana Public Service Commission (LPSC) on October 1, 2015. The North Louisiana Rider RSP filing shows a revenue deficiency of $1.0 million, and the South Louisiana Rider RSP filing shows a revenue deficiency of $1.5 million. Both 2015 RSP filings utilized the capital structure and ROE factors approved by the LPSC on September 23, 2015 discussed below. NGD began billing in December 2015 subject to a refund. NGD made its 2014 Louisiana RSP filings with the LPSC on October 1, 2014. The North Louisiana Rider RSP filing shows a revenue deficiency of $4.0 million, compared to the authorized ROE of 10.25%. The South Louisiana Rider RSP filing shows a revenue deficiency of $2.3 million, compared to the authorized ROE of 10.5%. NGD began billing the revised rates in December 2014, subject to refund. On November 19, 2014, NGD sought permission to amend the 2013 South Louisiana RSP filing to use a more representative capital structure and to adjust the filing’s equity banding mechanism. On December 2, 2014, NGD sought permission for similar amendments to the 2013 North Louisiana RSP filing. On September 3, 2015, Uncontested Stipulated Settlement Agreements (Stipulations) between NGD and the LPSC Staff were filed in the 2013 Louisiana RSP dockets recommending a capital structure of 48% debt and 52% equity and ROE of 9.95%. On September 23, 2015, the LPSC issued orders approving the Stipulations and ordered refunds of the 2013 RSP over-collections plus 5% annual interest. Refunds for the 2013 North and South Louisiana RSP filings in the amount of approximately $0.9 million and $0.6 million, respectively, became effective in September 2015. The 2014 and 2015 Louisiana RSP filings are still awaiting final approval from the LPSC.

On February 20, 2015, the LPSC issued orders reducing rates and requiring refunds of over-collections plus 5% interest based on disallowance of certain costs included in the 2012 RSP filings. North Louisiana was required to adjust its 2012 RSP increase from $36,400 to $2,600. South Louisiana’s 2012 RSP was further reduced by $0.1 million. New rates went into effect on February 23, 2015.

Mississippi Rate Regulation Adjustment (RRA). On May 1, 2015, NGD filed for a $2.5 million RRA with an adjusted ROE of 9.534% with the Mississippi Public Service Commission (MPSC). Additional filings were made under the Supplemental Growth Rider (SGR) of approximately $0.1 million with an ROE of 12% and the EECR rider of approximately $0.6 million. The MPSC approved the EECR and new rates were implemented on September 2, 2015. NGD and the Mississippi Commission Staff filed a Stipulation on December 1, 2015 in the RRA, which was approved by the MPSC on December 3, 2015. The stipulated revenue adjustment is $1.9 million with an ROE of 9.534%. The SGR was approved, as filed, on December 3, 2015. New rates for the RRA and the SGR were implemented in December of 2015.

Minnesota Conservation Cost Recovery Adjustment (CCRA) and CIP. On May 1, 2015, NGD filed applications with the MPUC for a CCRA and a Demand-Side Management Financial Incentive. NGD sought approval for a $2.3 million balance in its CIP Tracker, an $11.6 million financial incentive based on 2014 program performance, and an updated CCRA, to be effective on January 1, 2016. On August 11, 2015, the MPUC issued its order approving these requests.

Minnesota Rate Case. In August 2015, NGD filed a general rate case with the MPUC requesting an annual increase of $54.1 million. On September 10, 2015, the MPUC approved an interim increase of $47.8 million in revenues effective October 2, 2015, subject to a refund. The MPUC is expected to issue a final decision in mid-2016 with final rates effective by the end of 2016.

Other Matters

Credit Facilities

As of February 12, 2016, we had the following facilities:



Execution Date	Company	Size of Facility		Amount Utilized at February 12, 2016 (1)			Termination Date
		(in millions)
September 9, 2011	CenterPoint Energy	$	1,200	$	826	(2)	September 9, 2019
September 9, 2011	CenterPoint Houston	300		204		(3)	September 9, 2019
September 9, 2011	CERC Corp.	600		18		(4)	September 9, 2019


(1)	Based on the consolidated debt to capitalization covenant in our revolving credit facility and the revolving credit facility of each of CenterPoint Houston and CERC Corp., we would have been permitted to utilize the full capacity of such revolving credit facilities, which aggregated $2.1 billion at December 31, 2015.


(2)	Represents outstanding commercial paper of $820 million and outstanding letters of credit of $6 million.


(3)	Represents outstanding letters of credit of $4 million and outstanding bank loans of $200 million.


(4)	Represents outstanding commercial paper of $16 million and outstanding letters of credit of $2 million.

Our $1.2 billion revolving credit facility can be drawn at the London Interbank Offered Rate (LIBOR) plus 1.25% based on our current credit ratings. The revolving credit facility contains a financial covenant which limits our consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of our consolidated capitalization. As of December 31, 2015, our debt (excluding transition and system restoration bonds) to capital ratio, as defined in our credit facility agreement, was 55.1%. The financial covenant limit will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory and we certify to the administrative agent that CenterPoint Houston has incurred system restoration costs reasonably likely to exceed $100 million in a consecutive twelve-month period, all or part of which CenterPoint Houston intends to seek to recover through securitization financing. Such temporary increase in the financial covenant would be in effect from the date we deliver our certification until the earliest to occur of (i) the completion of the securitization financing, (ii) the first anniversary of our certification or (iii) the revocation of such certification.

CenterPoint Houston’s $300 million revolving credit facility can be drawn at LIBOR plus 1.125% based on CenterPoint Houston’s current credit ratings. The revolving credit facility contains a financial covenant which limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of CenterPoint Houston’s consolidated capitalization. As of December 31, 2015, CenterPoint Houston’s debt (excluding transition and system restoration bonds) to capital ratio, as defined in its credit facility agreement, was 51.7%.

CERC Corp.’s $600 million revolving credit facility can be drawn at LIBOR plus 1.5% based on CERC Corp.’s current credit ratings. The revolving credit facility contains a financial covenant which limits CERC’s consolidated debt to an amount not to exceed 65% of CERC’s consolidated capitalization. As of December 31, 2015, CERC’s debt to capital ratio, as defined in its credit facility agreement, was 33.9%.

Borrowings under each of the three revolving credit facilities are subject to customary terms and conditions. However, there is no requirement that the borrower make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the revolving credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. The revolving credit facilities also provide for customary fees, including commitment fees, administrative agent fees, fees in respect of letters of credit and other fees. In each of the three revolving credit facilities, the spread to LIBOR and the commitment fees fluctuate based on the borrower’s credit rating. The borrowers are currently in compliance with the various business and financial covenants in the three revolving credit facilities.

Our $1.2 billion revolving credit facility backstops our $1.0 billion commercial paper program. As of December 31, 2015, we had $716 million of outstanding commercial paper with a weighted average interest rate of 0.79%. CERC Corp.’s $600 million

revolving credit facility backstops its $600 million commercial paper program. As of December 31, 2015, CERC Corp. had $219 million of outstanding commercial paper with a weighted average interest rate of 0.81%.

In November 2015, we retired $740 million of tax-exempt municipal bonds that had been held for remarketing.

Securities Registered with the SEC

CenterPoint Energy, CenterPoint Houston and CERC Corp. have filed a joint shelf registration statement with the SEC registering indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds, CERC Corp.’s senior debt securities and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units.

Temporary Investments

As of February 12, 2016, we had no temporary investments.

Money Pool

We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under our revolving credit facility or the sale of our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings

The interest on borrowings under our credit facilities is based on our credit rating. As of February 12, 2016, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, and Fitch, Inc. (Fitch) had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:



	Moody’s		S&P		Fitch
Company/Instrument	Rating	Outlook (1)	Rating	Outlook (2)	Rating	Outlook (3)
CenterPoint Energy Senior Unsecured Debt	Baa1	Stable	BBB+	Negative	BBB	Stable
CenterPoint Houston Senior Secured Debt	A1	Stable	A	Negative	A	Stable
CERC Corp. Senior Unsecured Debt	Baa2	Stable	A-	Negative	BBB	Stable


(1)	A Moody’s rating outlook is an opinion regarding the likely direction of an issuer’s rating over the medium term.


(2)	An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.


(3)	A Fitch rating outlook indicates the direction a rating is likely to move over a one- to two-year period.

We cannot assure that the ratings set forth above will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are included for informational purposes and are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.

A decline in credit ratings could increase borrowing costs under our $1.2 billion revolving credit facility, CenterPoint Houston’s $300 million revolving credit facility and CERC Corp.’s $600 million revolving credit facility. If our credit ratings or those of CenterPoint Houston or CERC Corp. had been downgraded one notch by each of the three principal credit rating agencies from the ratings that existed at December 31, 2015, the impact on the borrowing costs under the three revolving credit facilities would have been immaterial. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions and to access the commercial paper market.

Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Energy Services Business Segments.

CERC Corp. and its subsidiaries purchase natural gas from one of their suppliers under supply agreements that contain an aggregate credit threshold of $140 million based on CERC Corp.’s S&P senior unsecured long-term debt rating of A-. Under these agreements, CERC may need to provide collateral if the aggregate threshold is exceeded or if the credit threshold is decreased due to a credit rating downgrade.

CES, a wholly-owned subsidiary of CERC Corp. operating in our Energy Services business segment, provides natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of December 31, 2015, the amount posted as collateral aggregated approximately $87 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral up to the amount of its previously unsecured credit limit. We estimate that as of December 31, 2015, unsecured credit limits extended to CES by counterparties aggregated $308 million, and $3 million of such amount was utilized.

Pipeline tariffs and contracts typically provide that if the credit ratings of a shipper or the shipper’s guarantor drop below a threshold level, which is generally investment grade ratings from both Moody’s and S&P, cash or other collateral may be demanded from the shipper in an amount equal to the sum of three months’ charges for pipeline services plus the unrecouped cost of any lateral built for such shipper. If the credit ratings of CERC Corp. decline below the applicable threshold levels, CERC Corp. might need to provide cash or other collateral of as much as $152 million as of December 31, 2015. The amount of collateral will depend on seasonal variations in transportation levels.

In September 1999, we issued ZENS having an original principal amount of $1.0 billion of which $828 million remains outstanding at December 31, 2015. Each ZENS note was originally exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of TW Common attributable to such note. The number and identity of the reference shares attributable to each ZENS note are adjusted for certain corporate events. Prior to the closing of the merger discussed below, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common, 0.045455 share of AOL Common and 0.0625 share of Time Common.

On May 26, 2015, Verizon initiated a tender offer to purchase all outstanding shares of AOL Common for $50 per share, in which we tendered all of our shares of AOL Common for $32 million. Verizon acquired the remaining eligible shares through a merger, which closed on June 23, 2015. In accordance with the terms of the ZENS, we remitted $32 million to ZENS holders in July 2015, which reduced contingent principal. As a result, we recorded a reduction in the indexed debt securities derivative liability of $18 million, a reduction in the indexed debt balance of $7 million and a loss of $7 million, which is included in Gain (loss) on indexed debt securities on the Statements of Consolidated Income. As of December 31, 2015, the reference shares for each ZENS note consisted of 0.5 share of TW Common, 0.125505 share of TWC Common and 0.0625 share of Time Common, and the contingent principal balance was $705 million.

On May 26, 2015, Charter Communications, Inc. (Charter) announced that it had entered into a definitive merger agreement with TWC. On September 21, 2015, Charter shareholders approved the announced transaction with TWC. Pursuant to the merger agreement, upon closing of the merger, TWC Common shares would be exchanged for cash and Charter stock and as a result, reference shares would consist of Charter stock, TW Common and Time Common. The merger is expected to close by June of 2016.

If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common, TWC Common and Time Common that we own or from other sources. We own shares of TW Common, TWC Common and Time Common equal to approximately 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because tax deferrals related to the ZENS notes and TW Common, TWC Common and Time Common shares would typically cease when ZENS notes are exchanged or otherwise retired and TW Common, TWC Common and Time Common shares are sold. The ultimate tax liability related to the ZENS notes continues to increase by the amount of the tax benefit realized each year, and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS

notes. If all ZENS notes had been exchanged for cash on December 31, 2015, deferred taxes of approximately $450 million would have been payable in 2015. If all the TW Common, TWC Common and Time Common had been sold on December 31, 2015, capital gains taxes of approximately $236 million would have been payable in 2015.

Cross Defaults

Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness for borrowed money and certain other specified types of obligations (including guarantees) exceeding $75 million by us or any of our significant subsidiaries will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or revolving credit facilities.

Possible Acquisitions, Divestitures and Joint Ventures

From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures or other joint ownership arrangements with respect to assets or businesses. Any determination to take action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

On February 1, 2016, we announced that we are evaluating strategic alternatives for our investment in Enable, including a sale or spin-off qualifying under Section 355 of the U.S. Internal Revenue Code, and exploring the use of the real estate investment trust business model for all or part of our utility businesses. There can be no assurances that this evaluation will result in any specific action, and we do not intend to disclose further developments on these initiatives unless and until our Board of Directors approves a specific action or as otherwise required.

Enable Midstream Partners

As of December 31, 2015, certain of the entities contributed to Enable by CERC Corp. were obligated on approximately $363 million of indebtedness owed to a wholly-owned subsidiary of CERC Corp.

On January 28, 2016, we entered into a purchase agreement with Enable pursuant to which we agreed to purchase in a Private Placement an aggregate of 14,520,000 10% Series A Preferred Units for a cash purchase price of $25.00 per Series A Preferred Unit. The Private Placement closed on February 18, 2016. In connection with the Private Placement, Enable redeemed approximately $363 million of notes scheduled to mature in 2017 payable to a wholly-owned subsidiary of CERC Corp. We used the proceeds from this redemption for our investment in the Series A Preferred Units.

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 (referred to as “available cash”) within 45 days after the end of each quarter. On January 22, 2016, Enable declared a quarterly cash distribution of $0.318 per unit on all of its outstanding common and subordinated units for the quarter ended December 31, 2015. Accordingly, CERC Corp. expects to receive a cash distribution of approximately $74 million from Enable in the first quarter of 2016 to be made with respect to CERC Corp.’s limited partner interest in Enable for the fourth quarter of 2015.

We recognized a loss of $1,633 million from our investment in Enable for the year ended December 31, 2015. This loss included impairment charges totaling $1,846 million composed of the impairment of our investment in Enable of $1,225 million and our share, $621 million, of impairment charges Enable recorded for goodwill and long-lived assets. For further discussion of the impairment, see Note 9 to our consolidated financial statements.

Dodd-Frank Swaps Regulation

We use derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices and weather on our operating results and cash flows. Following enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement Dodd-Frank’s changes to the Commodity Exchange Act, including the definition of commodity-based swaps subject to those regulations. The CFTC regulations are intended to implement new reporting and record keeping requirements related to their swap transactions and a mandatory clearing and exchange-execution regime for various types, categories or classes of swaps, subject to certain exemptions, including the trade-option and end-user exemptions. Although we anticipate that most, if not all, of our swap transactions should qualify for an exemption to the clearing and exchange-execution requirements, we will still be subject to record keeping and reporting requirements. Other changes to the Commodity Exchange Act made as a result of Dodd-Frank and the CFTC’s implementing regulations could increase the cost of entering into new swaps.

Weather Hedge

We have weather normalization or other rate mechanisms that mitigate the impact of weather on NGD in Arkansas, Louisiana, Mississippi, Minnesota and Oklahoma. NGD and electric operations in Texas do not have such mechanisms, although fixed customer charges are historically higher in Texas for NGD compared to our other jurisdictions. As a result, fluctuations from normal weather may have a positive or negative effect on NGD’s results in Texas and on CenterPoint Houston’s results in its service territory. We have historically entered into heating-degree day swaps for certain NGD jurisdictions to mitigate the effect of fluctuations from normal weather on its results of operations and cash flows for the winter heating season. However, NGD did not enter into heating-degree day swaps for the 2015–2016 winter season as a result of NGD’s Minnesota division implementing a full decoupling pilot in July 2015. We entered into a weather hedge for CenterPoint Houston’s service territory for the 2015–2016 winter season.

Collection of Receivables from REPs

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these REPs to remit payments on a timely basis, and any delay or default in payment by REPs could adversely affect CenterPoint Houston’s cash flows. In the event of a REP’s default, CenterPoint Houston’s tariff provides a number of remedies, including the option for CenterPoint Houston to request that the Texas Utility Commission suspend or revoke the certification of the REP. Applicable regulatory provisions require that customers be shifted to another REP or a provider of last resort if a REP cannot make timely payments. However, CenterPoint Houston remains at risk for payments related to services provided prior to the shift to the replacement REP or the provider of last resort. If a REP were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event such REP might seek to avoid honoring its obligations, and claims might be made against CenterPoint Houston involving payments it had received from such REP. If a REP were to file for bankruptcy, CenterPoint Houston may not be successful in recovering accrued receivables owed by such REP that are unpaid as of the date the REP filed for bankruptcy. However, Texas Utility Commission regulations authorize utilities, such as CEHE, to defer bad debts resulting from defaults by REPs for recovery in future rate cases, subject to a review of reasonableness and necessity.

Other Factors that Could Affect Cash Requirements

In addition to the above factors, our liquidity and capital resources could be affected by:


•	cash collateral requirements that could exist in connection with certain contracts, including our weather hedging arrangements, and gas purchases, gas price and gas storage activities of our Natural Gas Distribution and Energy Services business segments;


•	acceleration of payment dates on certain gas supply contracts, under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;


•	increased costs related to the acquisition of natural gas;


•	increases in interest expense in connection with debt refinancings and borrowings under credit facilities;


•	various legislative or regulatory actions;


•	incremental collateral, if any, that may be required due to regulation of derivatives;


•	the ability of GenOn and its subsidiaries to satisfy their obligations in respect of GenOn’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which our subsidiary is their guarantor;


•	the ability of REPs, including REP affiliates of NRG and Energy Future Holdings Corp., to satisfy their obligations to us and our subsidiaries;


•	slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;


•	the outcome of litigation brought by and against us;


•	contributions to pension and postretirement benefit plans;


•	restoration costs and revenue losses resulting from future natural disasters such as hurricanes and the timing of recovery of such restoration costs; and


•	various other risks identified in “Risk Factors” in Item 1A of Part I of this report.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money

CenterPoint Houston’s revolving credit facility limits CenterPoint Houston’s consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of its consolidated capitalization. CERC Corp.’s revolving credit facility limits CERC’s consolidated debt to an amount not to exceed 65% of its consolidated capitalization. Our revolving credit facility limits our consolidated debt (excluding transition and system restoration bonds) to an amount not to exceed 65% of our consolidated capitalization. The financial covenant limit in our revolving credit facility will temporarily increase from 65% to 70% if CenterPoint Houston experiences damage from a natural disaster in its service territory that meets certain criteria. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition, results of operations or cash flows. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Our Electric Transmission & Distribution business segment and our Natural Gas Distribution business segment apply this accounting guidance. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred

on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, we would be required to write off or write down these regulatory assets and liabilities. As of December 31, 2015, we had recorded regulatory assets of $3.1 billion and regulatory liabilities of $1.3 billion.

Impairment of Long-Lived Assets, Including Identifiable Intangibles, Goodwill and Equity Method Investments

We review the carrying value of our long-lived assets, including identifiable intangibles, goodwill and equity method investments whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by accounting guidance for goodwill and other intangible assets. Unforeseen events and changes in market conditions could have a material effect on the value of long-lived assets, including intangibles, goodwill and equity method investments due to changes in estimates of future cash flows, interest rate and regulatory matters and could result in an impairment charge. A loss in value of an equity method investment is recognized when the decline is deemed to be other than temporary. We recorded no goodwill impairments during 2015, 2014 and 2013. We did not record material impairments to long-lived assets, including intangibles during 2015, 2014, and 2013. We recorded impairments totaling $1,225 million to our equity method investments during 2015 and no impairment during 2014 and 2013. See Notes 8 and 9 to our consolidated financial statements for further discussion of the impairments recorded to our equity method investment in 2015.

We performed our annual goodwill impairment test in the third quarter of 2015 and determined, based on the results of the first step, using the income approach, no impairment charge was required for any reporting unit. Our reporting units approximate our reportable segments.

Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

The determination of fair value requires significant assumptions by management which are subjective and forward-looking in nature. To assist in making these assumptions, we utilized a third-party valuation specialist in both determining and testing key assumptions used in the valuation of each of our reporting units. We based our assumptions on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. These projected cash flows factor in planned growth initiatives, and for our Natural Gas Distribution reporting unit, the regulatory environment. The fair value of our Natural Gas Distribution reporting unit significantly exceeded the carrying value. The fair value of our Energy Services reporting unit exceeded the carrying value by approximately $150 million or approximately 50% excess fair value over the carrying value.

A key assumption in the income approach was the weighted average cost of capital of 5.6% and 5.9% applied in the valuation for Natural Gas Distributions and Energy Services, respectively. An increase in the discount rate to greater than 7.2%, a decline in long-term growth rate from 3% to 1.7%, or a decrease in the aggregate cash flows of greater than 33% could have individually triggered a step-two goodwill impairment evaluation for our Energy Services reporting unit in 2015.

Although there was not a goodwill asset impairment in our 2015 annual test, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, or if our market capitalization falls below book value for an extended period of time. No impairment triggers were identified subsequent to our 2015 annual test.

We determined in connection with our preparation of financial statements for the three months ended September 30, 2015 and December 31, 2015, respectively, that an other than temporary decrease in the value of our investment in Enable had occurred. The impairment analysis compared the estimated fair value of our investment in Enable to its carrying value. The fair value of the investment was determined using multiple valuation methodologies under both the market and income approaches.

Key assumptions in the market approach include recent market transactions of comparable companies and EBITDA to total enterprise multiples for comparable companies. Due to volatility of the quoted price of Enable’s units, a volume weighted average price was used under the market approach to best approximate fair value at the measurement date. Key assumptions in the income

approach include Enable’s forecasted cash distributions, projected cash flows of incentive distribution rights, forecasted growth rate of Enable’s cash distributions beyond 2020, and the discount rate used to determine the present value of the estimated future cash flows. A weighing of the different approaches was utilized to determine the estimated fair value of our investment in Enable.

As a result of the analysis, we recorded other than temporary impairments on our investment in Enable of $250 million and $975 million during the three months ended September 30, 2015 and December 31, 2015, respectively. We based our assumptions on projected financial information that we believe is reasonable; however, actual results may differ materially from those projections. It is reasonably possible that the estimate of the impairment of our investment in Enable will change in the near term due to the following: actual Enable cash distribution is materially lower than expected, significant adverse changes in Enable’s operating environment, increase in the discount rate, and changes in other key assumptions which require judgment and are forward looking in nature.

Unbilled Energy Revenues

Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month either electronically through advanced metering system (AMS) meter communications or manual readings. At the end of each month, deliveries to non-AMS customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Information regarding deliveries to AMS customers after the last billing is obtained from actual AMS meter usage data. Unbilled electricity delivery revenue is estimated each month based on actual AMS meter data, daily supply volumes and applicable rates. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Pension and Other Retirement Plans

We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2(o) to our consolidated financial statements for a discussion of new accounting pronouncements that affect us.

OTHER SIGNIFICANT MATTERS

Pension Plans. As discussed in Note 6(b) to our consolidated financial statements, we maintain a non-contributory qualified defined benefit pension plan covering substantially all employees. Employer contributions for the qualified plan are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes.

Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA.

The minimum funding requirements for the qualified pension plan were $-0-, $87 million and $83 million for 2015, 2014 and 2013, respectively. We made contributions of $35 million, $87 million and $83 million in 2015, 2014 and 2013 for the respective years. We are not required to make any contribution in 2016.

Additionally, we maintain an unfunded non-qualified benefit restoration plan that allows participants to receive the benefits to which they would have been entitled under our non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. Employer contributions for the non-qualified benefit restoration plan represent benefit payments made to participants and totaled $31 million, $10 million

and $8 million in 2015, 2014 and 2013, respectively. We expect to make contributions aggregating approximately $8 million in 2016.

Changes in pension obligations and assets may not be immediately recognized as pension expense in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.

As the sponsor of a plan, we are required to (a) recognize on our balance sheet as an asset a plan’s over-funded status or as a liability such plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of our fiscal year and (c) recognize changes in the funded status of our plans in the year that changes occur through adjustments to other comprehensive income and regulatory assets.

The projected benefit obligation for all defined benefit pension plans was $2,193 million and $2,403 million as of December 31, 2015 and 2014, respectively. The adoption of the new mortality table by the Society of Actuaries as of December 31, 2014 significantly contributed to the increase in the projected benefit obligation for 2014.

As of December 31, 2015, the projected benefit obligation exceeded the market value of plan assets of our pension plans by $514 million. Changes in interest rates or the market values of the securities held by the plan during 2016 could materially, positively or negatively, change our funded status and affect the level of pension expense and required contributions.

Pension cost was $90 million, $77 million and $72 million for 2015, 2014 and 2013, respectively, of which $59 million, $71 million and $64 million impacted pre-tax earnings, respectively. Included in the 2015 and 2014 pension costs were a $10 million settlement charge and $6 million curtailment loss, respectively, as discussed below.

A one-time, non-cash settlement charge is required when lump sum distributions or other settlements of plan benefit obligations during the year exceed the service cost and interest cost components of net periodic cost for the year. Due to the amount of lump sum payment distributions from the non-qualified pension plan during the year ended December 31, 2015, CenterPoint Energy recognized a non-cash settlement charge of $10 million. This charge is an acceleration of costs that would otherwise be recognized in future periods.

During the fourth quarter of 2014, CenterPoint Energy received notification from Enable of its intent to provide employment offers to substantially all seconded employees. As a result, an additional pension cost of $6 million was recognized for the curtailment loss related to our pension plans. Substantially all of the seconded employees became employees of Enable effective January 1, 2015.

The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

As of December 31, 2015, our qualified pension plan had an expected long-term rate of return on plan assets of 6.25%, which is a 0.25% decrease from the rate assumed as of December 31, 2014 due to lower expected capital market return rates. The expected rate of return assumption was developed using the targeted asset allocation of our plans and the expected return for each asset class. We regularly review our actual asset allocation and periodically rebalance plan assets to reduce volatility and better match plan assets and liabilities.

As of December 31, 2015, the projected benefit obligation was calculated assuming a discount rate of 4.40%, which is 0.35% higher than the 4.05% discount rate assumed in 2014. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan.

Pension cost for 2016, including the benefit restoration plan, is estimated to be $102 million, of which we expect $66 million to impact pre-tax earnings, based on an expected return on plan assets of 6.25% and a discount rate of 4.40% as of December 31, 2015. If the expected return assumption were lowered by 0.50% from 6.25% to 5.75%, 2016 pension cost would increase by approximately $8 million.

As of December 31, 2015, the pension plan projected benefit obligation, including the unfunded benefit restoration plan, exceeded plan assets by $514 million. If the discount rate were lowered by 0.50% from 4.40% to 3.90%, the assumption change would increase our projected benefit obligation by approximately $115 million and decrease our 2016 pension expense by approximately $2 million. The expected reduction in pension expense due to the decrease in discount rate is a result of the expected

correlation between the reduced interest rate and appreciation of fixed income assets in pension plans with significantly more fixed income instruments than equity instruments. In addition, the assumption change would impact our Consolidated Balance Sheet by increasing the regulatory asset recorded as of December 31, 2015 by $101 million and would result in a charge to comprehensive income in 2015 of $9 million, net of tax.

Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.

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