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•	changes in general economic conditions;

•	competitive conditions in our industry;

•	actions taken by our customers and competitors;

•	the supply and demand for natural gas, NGLs, crude oil and midstream services;

•	our ability to successfully implement our business plan;

•	our ability to complete internal growth projects on time and on budget;

•	the price and availability of debt and equity financing;

•	operating hazards and other risks incidental to transporting, storing and gathering natural gas, NGLs, crude oil and midstream products;

•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•	interest rates;

•	labor relations;

•	large customer defaults;

•	changes in the availability and cost of capital;

•	changes in tax status;

•	the effects of existing and future laws and governmental regulations;

•	changes in insurance markets impacting costs and the level and types of coverage available;

•	the timing and extent of changes in commodity prices;

•	the suspension, reduction or termination of our customers’ obligations under our commercial agreements;

•	disruptions due to equipment interruption or failure at our facilities, or third-party facilities on which our business is dependent;

•	the effects of future litigation; and

•	other factors set forth in this report and our other filings with the SEC.

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Capitalize on Organic Growth Opportunities Associated with Our Strategically Located Assets. We own and operate assets servicing four of the largest basins in the United States, including some of the most productive shale plays in these basins. We expect to grow our business and distributable cash flow by developing new energy infrastructure projects to support new and existing customers as they expand beyond our current footprint. As a result of this expanding activity, we are constructing natural gas gathering and compression infrastructure, crude oil gathering infrastructure, and two additional processing facilities in Oklahoma that are expected to provide an additional 400 MMcf/d of processing capacity. For the year ended December 31, 2014, we invested $669 million in expansion capital expenditures.

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Continue to Minimize Direct Commodity Price Exposure Through Long-Term, Fee-Based Contracts. We continually seek ways to minimize our exposure to commodity price risk, and management believes that our focus on fee-based revenues reduces our direct commodity price exposure and is essential to maintaining stable cash flows and increasing our quarterly distributions over time. Since 2009, we have focused on increasing the percentage of long-term, fee-based contracts with our customers. For the year ended December 31, 2014, 72% of our gross margin was generated from fee-based contracts. As we grow, we intend to maintain our focus on long-term, fee-based contracts.

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Maintain Strong Customer Relationships to Attract New Volumes and Expand Beyond Our Existing Asset Footprint and Business Lines. We plan to grow our business through our strong relationships with existing customers. Management believes that we have built a strong and loyal customer base through exemplary customer service and reliable project execution. We have invested in multiple organic growth projects in support of our existing and new customers. We

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Grow Through Accretive Acquisitions and Disciplined Development. We plan to pursue accretive acquisitions of complementary assets that provide attractive potential returns in new operating regions or midstream business lines. We will continue to analyze acquisition opportunities using disciplined financial and operating practices, including a process for evaluating and managing risks to cash distributions.

•	Leverage the Scale of Our Existing Assets to Realize Significant Synergies. Given the complementary features of our assets, we expect operating synergies from the interconnection and optimization of our systems to increase our cash flows over time.

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Anadarko Basin (Oklahoma, Texas Panhandle). We currently operate in the liquids-rich Granite Wash, Cleveland, Tonkawa, Cana Woodford, SCOOP and Mississippi Lime plays. As of December 31, 2014, our assets include approximately 7,300 miles of natural gas gathering pipelines and nine natural gas processing plants with approximately 1,445 MMcf/d of processing capacity. We also have two processing plants under construction that will add 400 MMcf/d of processing capacity. For the year ended December 31, 2014, this system had average daily gathered throughput of approximately 1.38 TBtu/d of natural gas and produced 51,561 Bbl/d of NGLs. We currently serve over 200 producers in these areas and have secured 4.3 million gross acres dedicated under long-term contracts in this basin. The majority of these arrangements are fee-based with long-term acreage dedications. These contracts provide for gathering and compression services, which are typically fee-based, and processing services under fee-based, percent-of-liquids, percent-of-proceeds or keep-whole structures.

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Arkoma Basin (Oklahoma, Arkansas). In Oklahoma, we operate in the rich and lean gas areas of the western portion of the Arkoma basin. In Arkansas, we operate in the eastern Arkoma and the Fayetteville Shale play. As of December 31, 2014, our assets include approximately 2,900 miles of natural gas gathering pipelines and one natural gas processing plant with approximately 60 MMcf/d of processing capacity. For the year ended December 31, 2014, this system had average daily gathered throughput of approximately 0.77 TBtu/d of natural gas and produced 4,408 Bbl/d of NGLs. We currently serve over 85 producers in these areas and have secured over 1.4 million acres dedicated under long-term contracts in this basin. Additionally, in the lean gas area of the Fayetteville Shale we have secured fee-based contracts that provide minimum revenues in time periods when natural gas prices are depressed.

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Ark-La-Tex Basin (Arkansas, Louisiana and Texas). In Arkansas, Louisiana, and Texas, we operate primarily in the Haynesville, Cotton Valley and the lower Bossier plays. As of December 31, 2014, our assets include approximately 1,700 miles of natural gas gathering pipelines, two natural gas processing plants with approximately 545 MMcf/d of processing capacity, an NGL fractionation facility and approximately 40 miles of ethane pipelines. For the year ended December 31, 2014, this system had average daily gathered throughput of approximately 1.19 TBtu/d of natural gas

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Williston Basin (North Dakota). In November 2013, we commenced operations on our initial crude oil gathering pipeline system, located in Dunn and McKenzie Counties in North Dakota, within the Bakken Shale formation. Additionally, in February 2014, we executed an agreement to gather crude oil production through a new system in Williams and Mountrail Counties in North Dakota that is expected to commence operations in the first quarter of 2015. During 2014, we placed most of the Dunn and McKenzie County crude oil gathering system into service and we expect to complete construction and place the Williams and Mountrail County system into service by the end of 2015. These systems will have a combined planned capacity of 49,500 barrels per day and are supported by over 0.2 million gross acres dedicated under a long-term, minimum volume commitment agreement with XTO Energy Inc. (XTO), an affiliate of Exxon Mobil Corporation, to provide crude oil gathering along with water transportation and other complementary services. For the year ended December 31, 2014, the Dunn and McKenzie County crude oil gathering system had average daily throughput of approximately 3.6 MBbl/d.

(1)	Ark-La-Tex basin assets also include 14,500 Bbl/d of fractionation capacity and 6,300 Bbl/d of ethane pipeline capacity, which are not listed in the table.

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(1)	Excludes condensate capacity.

(2)	The Grady County Plant is under construction and estimated to be in service in the first quarter of 2016.

(3)	The Bradley Plant is under construction and estimated to be in service in the first quarter of 2015.

(4)	All of our processing plants are located on properties that are owned by us except for Roger Mills, which is located on property that is leased.

(5)	Average daily inlet volumes and inlet capacity includes 24 MMcf/d and 25MMcf/d, respectively, related to a separate cryogenic unit.

(6)	A processing plant has been in operation on the Waskom plant site since 1940. The Waskom plant was upgraded to cryogenic in 1995.

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(1)	Except with respect to length, this information does not include amounts for SESH. SESH is a non-consolidated entity in which we own a 49.90% ownership interest.

(2)	Actual volumes transported per day may be less than total firm contracted capacity based on demand.

(3)

This represents the maximum single day receipts on the intrastate systems. Our Oklahoma intrastate pipeline system is a web-like configuration with multidirectional flow capabilities between numerous receipt and delivery points, which limits our ability to determine an overall system capacity. During the year ended December 31, 2014, the peak daily throughput was 1.9 TBtu/d or, on a volumetric basis, 1.9 Bcf/d.

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(1)	Excludes SESH, which is accounted for as an equity investment and described under “—Other Assets” below.

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•	rates, operating terms, conditions of service and service contracts;

•	certification and construction of new facilities or expansion of existing facilities;

•	extension or abandonment of services and facilities;

•	maintenance of accounts and records;

•	acquisition and disposition of facilities;

•	initiation and discontinuation of services;

•	depreciation and amortization policies;

•	conduct and relationship with certain affiliates;

•	market manipulation in connection with interstate natural gas sales, purchases or transportation; and

•	various other matters.

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•	the overall cost of service, including operating costs and overhead;

•	the allocation of overhead and other administrative and general expenses to the regulated entity;

•	the appropriate capital structure to be utilized in calculating rates;

•	the appropriate rate of return on equity and interest rates on debt;

•	the rate base, including the proper starting rate base;

•	the throughput underlying the rate; and

•	the proper allowance for federal and state income taxes.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact an HCA;

•	improve data collection, integration and analysis;

•	repair and remediate pipelines as necessary; and

•	implement preventive and mitigating actions.

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•	the fees and gross margins we realize with respect to the volume of natural gas and crude oil that we handle;

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•	the prices of, levels of production of, and demand for natural gas and crude oil;

•	the volume of natural gas and crude oil we gather, compress, treat, dehydrate, process, fractionate, transport and store;

•	the relationship among prices for natural gas, NGLs and crude oil;

•	cash calls and settlements of hedging positions;

•	margin requirements on open price risk management assets and liabilities;

•	the level of competition from other midstream energy companies;

•	adverse effects of governmental and environmental regulation;

•	the level of our operation and maintenance expenses and general and administrative costs; and

•	prevailing economic conditions.

•	the level and timing of capital expenditures we make;

•	the cost of acquisitions;

•	our debt service requirements and other liabilities;

•	fluctuations in working capital needs;

•	our ability to borrow funds and access capital markets;

•	restrictions contained in our debt agreements;

•	the amount of cash reserves established by our general partner; and

•	other business risks affecting our cash levels.

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•	the availability and cost of capital;

•	prevailing and projected commodity prices, including the prices of natural gas, NGLs and crude oil;

•	demand for natural gas, NGLs and crude oil;

•	levels of reserves;

•	geological considerations;

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

•	the availability of drilling rigs and other costs of production and equipment.

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•	our joint venture partners may share certain approval rights over major decisions;

•	our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;

•	we may be unable to control the amount of cash we will receive from the joint venture;

•	we may incur liabilities as a result of an action taken by our joint venture partners;

•	we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

•	our insurance policies may not fully cover loss or damage incurred by both us and our joint venture partners in certain circumstances;

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•	our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

•	disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

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•	damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

•	inadvertent damage from construction, vehicles, farm and utility equipment;

•	leaks of natural gas, crude oil and other hydrocarbons or losses of natural gas and crude oil as a result of the malfunction of equipment or facilities;

•	ruptures, fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;

•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;

•	we may assume liabilities that were not disclosed to us, that exceed our estimates, or for which our rights to indemnification from the seller are limited;

•	we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems; and

•	acquisitions, or the pursuit of acquisitions, could disrupt our ongoing businesses, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures.

•	the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or the financing may not be available on favorable terms, if at all;

•	a portion of cash flows will be required to make interest payments on the debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions;

•	our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our debt level may limit our flexibility in responding to changing business and economic conditions.

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•	permit our subsidiaries to incur or guarantee additional debt;

•	incur or permit to exist certain liens on assets;

•	dispose of assets;

•	merge or consolidate with another company or engage in a change of control;

•	enter into transactions with affiliates on non-arm’s length terms; and

•	change the nature of our business.

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•	rates, operating terms, conditions of service and service contracts;

•	certification and construction of new facilities;

•	extension or abandonment of services and facilities or expansion of existing facilities;

•	maintenance of accounts and records;

•	acquisition and disposition of facilities;

•	initiation and discontinuation of services;

•	depreciation and amortization policies;

•	conduct and relationship with certain affiliates;

•	market manipulation in connection with interstate sales, purchases or natural gas transportation; and

•	various other matters.

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•	develop a baseline plan to prioritize the assessment of a covered pipeline segment;

•	identify and characterize applicable threats that could impact a high consequence area;

•	improve data collection, integration, and analysis;

•	repair and remediate pipelines as necessary; and

•	implement preventive and mitigating action.

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Neither our partnership agreement nor any other agreement requires CenterPoint Energy or OGE Energy to pursue a business strategy that favors us. The directors and officers of CenterPoint Energy and OGE Energy have a fiduciary duty to make decisions in the best interests of the stockholders of their respective companies, which may be contrary to our interests. CenterPoint Energy and OGE Energy may choose to shift the focus of their investment and growth to areas not served by our assets.

•	Our general partner is allowed to take into account the interests of parties other than us, such as CenterPoint Energy and OGE Energy, in resolving conflicts of interest.

•	Some of the directors of our general partner are also directors of CenterPoint Energy or OGE Energy and will owe fiduciary duties to their respective companies. These individuals may also devote significant time to the business of CenterPoint Energy and OGE Energy.

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•	Our partnership agreement replaces the fiduciary duties that would otherwise be owed to us by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Disputes may arise under our commercial agreements with CenterPoint Energy and OGE Energy.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership units and the creation, reduction or increase of cash reserves, each of which can affect the amount of distributable cash flow.

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Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units.

•	Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

•	Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

•	Our partnership agreement permits us to classify up to $300 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated or general partner units or to our general partner in respect of the incentive distribution rights.

•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner intends to limit its liability regarding our contractual and other obligations.

•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 90% of the common units. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%.

•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our general partner may transfer its incentive distribution rights without unitholder approval.

•	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the Board of Directors or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

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•	how to allocate corporate opportunities among us and its other affiliates;

•	whether to exercise its limited call right;

•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the Board of Directors;

•	whether to elect to reset target distribution levels;

•	whether to transfer the incentive distribution rights to a third party; and

•	whether or not to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

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whenever our general partner, the Board of Directors or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the Board of Directors and any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in the best interests of the Partnership, and, except as specifically provided by our partnership agreement, will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•	our general partner will not be in breach of its obligations under the partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:

•	approved by the conflicts committee of the Board of Directors, although our general partner is not obligated to seek such approval;

•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

•	determined by the Board of Directors to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

•	determined by the Board of Directors to be fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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•	our existing unitholders’ proportionate ownership interest in us will decrease;

•	the amount of distributable cash flow on each unit may decrease;

•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•	because the amount payable to holders of incentive distribution rights is based on a percentage of the total distributable cash flow, the distributions to holders of incentive distribution rights will increase even if the per unit distribution on common units remains the same;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

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•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	a unitholder's right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

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(1)	The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

•	less, the amount of cash reserves established by our general partner to:

•	provide for the proper conduct of our business (including cash reserves for our future capital expenditures, future acquisitions, and anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

•	comply with applicable law, any of our debt instruments or other agreements; or

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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

•	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

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•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.15 per unit (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

•	the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.15 (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

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•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

•	distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.725 (150% of the annualized minimum quarterly distribution) for the four-consecutive-quarter period immediately preceding that date;

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the adjusted operating surplus generated during the four-consecutive-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.725 per unit (150% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

•	there are no arrearages in payment of the minimum quarterly distributions on the common units.

•	the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;

•	if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

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(1)	Limited partners’ interest in net income attributable to Enable Midstream Partners, LP and basic and diluted earnings per unit reflect net income attributable to Enable Midstream Partners, LP subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date.

(2)	Historical basic and diluted earnings per common limited partner unit reflects the 1 for 1.279082616 reverse unit split effected on March 25, 2014.

(3)	Basic and diluted earnings per subordinated unit reflect net income attributable to the Partnership for periods subsequent to its Offering, as no subordinated units were outstanding prior to this date.

(4)	Distributions attributable to periods prior to the Offering are in accordance with the First Amended and Restated Agreement of Limited Partnership. Distributions declared per unit prior to the Offering relate to common units, as no subordinated units were outstanding prior to the date of the Offering.

(5)	Distributions attributable to periods subsequent to the Offering are in accordance with the Second Amended and Restated Agreement of Limited Partnership. Distributions declared per unit relate to common and subordinated units.

(6)	Excludes condensate.

(7)	Initial operation of our crude oil gathering system began on November 1, 2013.

(8)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

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(1)	2013 daily averages are computed utilizing a 365 day convention, and are not computed using a weighted average convention for the acquisition of Enogex.

(2)	Excludes condensate.

(3)	Initial operation of our crude oil gathering system began on November 1, 2013.

(4)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

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(1)	Gross margin, Adjusted EBITDA and distributable cash flow are defined and reconciled to their most directly comparable financial measures calculated and presented below under the caption Non-GAAP Financial Measure.

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•	The Partnership’s operating performance as compared to those of other publicly traded partnerships in the midstream energy industry, without regard to capital structure or historical cost basis;

•	The ability of the Partnership’s assets to generate sufficient cash flow to make distributions to its partners;

•	The Partnership’s ability to incur and service debt and fund capital expenditures; and

•	The viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

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•	the acquisition of Enogex on May 1, 2013, which added $186 million in gross margin and $70 million in operation and maintenance expenses during the year ended December 31, 2014; and

•	excluding the acquisition of Enogex:

•	higher Gathering and Processing gross margin of $32 million;

•	higher Transportation and Storage gross margin of $59 million; and

•	higher payroll related expenses of $29 million and higher non-capital costs of $16 million, offset by lower integration costs of $9 million and other costs of $8 million, all within operation and maintenance expenses.

•	the acquisition of Enogex on May 1, 2013, which added $326 million in gross margin and $134 million in operation and maintenance expenses during the year ended December 31, 2013; and

•	excluding the acquisition of Enogex:

•	higher Gathering and Processing gross margin of $44 million;

•	lower Transportation and Storage gross margin of $17 million;

•	integration costs of $8 million, higher payroll related expenses of $11 million and higher contracts and services expenses of $6 million, all within operation and maintenance expenses; and

•	the impact of the timing of payments and receipts on changes in assets and liabilities.

•	higher gathering and processing capital expenditures of $299 million;

•	the payment of $434 million on notes receivable-affiliated companies in 2013;

•	investment in equity method affiliates of $189 million;

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•	lower transportation and storage capital expenditures of $45 million; and

•	distributions from equity method affiliates of $198 million in 2014.

•	flat gathering and processing capital expenditures, including acquisitions of $360 million in 2012;

•	higher transportation and storage capital expenditures of $10 million; and

•	the receipt of $514 million on notes receivable-affiliated companies.

•	decrease in gross borrowings under the Revolving Credit Facility of $1,011 million and decrease in gross repayments of $267 million;

•	issuance of commercial paper of $253 million in 2014;

•	decrease in notes payable-affiliated companies of $1,542 million;

•	increase in capital contributions from partners of $421 million; and

•	increase in distributions to partners of $346 million.

•	the net cash used in financing activities of $217 million for the year ended December 31, 2013 resulting from the financing transactions associated with our formation and the acquisition of Enogex on May 1, 2013, compared to net cash provided from notes payable-affiliated companies of $194 million for the year ended December 31, 2012; and

•	the distribution of $183 million to partners in the year ended December 31, 2013.

•	cash on hand;

•	cash generated from operations;

•	proceeds of commercial paper issuances and borrowings under our Revolving Credit facility; and

•	capital raised through debt and equity markets

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•	maintenance capital expenditures, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long-term, our operating capacity or operating income; and

•	expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

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(1)	The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

(1)	Estimated contractual interest payments associated with long-term debt are $157 million, $157 million and $859 million in 2015 through 2016, 2017 through 2018 and after 2018, respectively. The Revolving Credit Facility estimated contractual interest payments are calculated utilizing the respective variable interest rates as of December 31, 2014.

(2)	Excludes premium on Enable Oklahoma Senior Notes of $28 million.

(3)	Estimated contractual interest payments associated with notes payable-affiliated companies are $16 million, $8 million and $-0- in 2015 through 2016, 2017 through 2018 and after 2018, respectively.

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(1)	Excludes condensate.

(2)	Initial operation of our crude oil gathering system began on November 1, 2013.

(3)	NGLs sold includes volumes of NGLs withdrawn from inventory or purchased for system balancing purposes.

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(1)	Excludes $198 million in special distributions for the return of investment in SESH for the year ended December 31, 2014.

(2)	Adjusted interest expense, net excludes the effect of the amortization of the premium on Enogex’s fixed rate senior notes. This exclusion is the primary reason for the difference between “Interest expense, net” and “Adjusted interest expense, net.”

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•	Include the historical results of Enogex beginning on January 1, 2012;

•	Include incremental depreciation and amortization incurred on the step-up of Enogex’s assets;

•	Include adjustments to revenue and cost of sales to reflect Enogex purchase price adjustments for the recurring impact of certain loss contracts and deferred revenues; and

•	Include a reduction to interest expense for recognition of a premium on Enogex’s fixed rate senior notes.

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(1)	The quarterly distribution for three months ended June 30, 2014 was prorated for the period beginning immediately after the closing of the Partnership's Offering, April 16, 2014 through June 30, 2014.

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(1)	See Note 3 for further discussion regarding the acquisition of Enogex.

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(1)	Excludes $198 million in special distributions for the return of investment in SESH for the year ended December 31, 2014.

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(1)	Short-term debt includes $253 million of commercial paper as of December 31, 2014, and $200 million 6.875% senior notes due July 15, 2014, as of December 31, 2013.

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(1)	Borrowing capacity is reduced by our borrowings outstanding under the commercial paper program. $253 million of commercial paper was outstanding as of December 31, 2014, and no amount was outstanding as of December 31, 2013.

(2)	No amount is included in the current portion of long term debt as of December 31, 2014, and $204 million is included as of December 31, 2013.

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(1)

The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. Gas imbalances held by Enable Oklahoma are valued using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices. There were no netting adjustments as of December 31, 2014 and December 31, 2013.

(2)	Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of $4 million and $2 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

(3)	Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of $1 million and $3 million at December 31, 2014 and December 31, 2013, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

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•	NGL put options, NGL futures and swaps, and WTI crude futures and swaps for condensate sales are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;

•	natural gas futures and swaps are used to manage the Partnership’s keep-whole natural gas exposure associated with its processing operations and the Partnership’s natural gas exposure associated with operating its gathering, transportation and storage assets; and

•	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its storage and transportation contracts and asset management activities.

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(1)	91.2 percent of the natural gas contracts have durations of one year or less, 6.5 percent have durations of more than one year and less than two years and 2.2 percent have durations of more than two years.

(2)	100.0 percent of the condensate contracts have durations of one year or less.

(1)	94.8 percent of the natural gas contracts have durations of one year or less, 2.5 percent have durations of more than one year and less than two years and 2.7 percent have durations of more than two years.

(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2014.

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(1)	See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Consolidated Balance Sheet as of December 31, 2013.

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(1)

The Partnership's contracts with OGE Energy to transport and sell natural gas to OGE Energy’s natural gas-fired generation facilities and store natural gas are reflected in Partnership’s Combined and Consolidated Statement of Income beginning on May 1, 2013. On March 17, 2014, the Partnership and the electric utility subsidiary of OGE Energy signed a new transportation agreement effective May 1, 2014 with a primary term through April 30, 2019. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least 180 days prior to the commencement of the succeeding annual period.

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(1)	Beginning on May 1, 2013, CenterPoint Energy assumed all employees of the Partnership and seconded such employees to the Partnership. Therefore, costs historically incurred directly by the Partnership for employment services are reflected as seconded employee costs subsequent to formation on May 1, 2013.

(2)	Corporate services and seconded employee expenses from OGE Energy are reflected in the Combined and Consolidated Statement of Income beginning on May 1, 2013.

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(1)	For performance units, this represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target.

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(1)

Gathering and processing recorded equity income of $0 million, $0 million and $5 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, from its 50% interest in a jointly-owned gas processing plant, Waskom. These amounts are included in Equity in earnings of equity method affiliates under the Other income (expense) caption. The Partnership consolidated Waskom during the third quarter of 2012. See Note 9 for further discussion regarding Waskom.

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(2)

Transportation and Storage recorded equity income of $20 million, $15 million and $26 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, from its interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of equity method affiliates under the Other Income (Expense) caption. Transportation and Storage’s investment in SESH was $348 million and $198 million as of December 31, 2014 and December 31, 2013, respectively, and is included in Investments in equity method affiliates. The Partnership reflected a 50% interest in SESH until May 1, 2013 when the Partnership distributed a 25.05% interest in SESH to CenterPoint Energy. For the period of May 1, 2013 through May 29, 2014 the Partnership reflected a 24.95% interest in SESH. On May 30, 2014, CenterPoint Energy contributed its 24.95% interest in SESH to the Partnership. As of December 31, 2014, the Partnership owns 49.90% interest in SESH. See Note 9 for further discussion regarding SESH.

(3)	The Partnership had no external customers accounting for 10% or more of revenues in periods shown. See Note 13 for revenues from affiliated companies.

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(1)	Basic and diluted earnings per unit reflect net income attributable to the Partnership for periods subsequent to its formation as a limited partnership on May 1, 2013, as no limited partner units were outstanding prior to this date. See Note 4.

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•	possesses appropriate skills and professional experience;

•	has a reputation for integrity and other qualities;

•	possesses expertise, including industry knowledge, determined in the context of the needs of the Board of Directors;

•	has experience in positions with a high degree of responsibility;

•	is a leader in the organizations with which he or she is affiliated;

•	is diverse in terms of geography, gender, ethnicity and age;

•	has the time, energy, interest and willingness to serve as a member of the Board of Directors; and

•	meets such standards of independence and financial knowledge as may be required or desirable.

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(1)	321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101

(2)	One Leadership Square, 211 North Robinson Avenue, Suite 950, Oklahoma City, Oklahoma 73102

(3)	1111 Louisiana Street, Houston, Texas 77002

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(1)	Amounts represent a signing bonus upon employment with the Partnership.

(2)

Amounts in this column reflect the aggregate grant date fair value amount of the Partnership equity-based unit awards granted to each named executive officer. The grant date fair value amount is computed in accordance with FASB ASC Topic 718 based on the probable achievement level of the underlying performance conditions as of the grant date. Please refer to the Grants of Plan-Based Awards table for 2014 and the accompanying footnotes. Assuming

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(3)	Amounts in this column reflect payments under the Partnership's Short Term Incentive Plan.

(4)

Amounts in this column reflect the actuarial increase in the present value of the named executive officer’s benefits under CenterPoint Energy's and OGE Energy's qualified defined benefit pension plans as reported to us by CenterPoint Energy and OGE Energy, which CenterPoint Energy and OGE Energy have represented to us will be reported in the Notes to CenterPoint Energy’s Consolidated Financial Statements for the year ended December 31, 2014 that will be included in CenterPoint Energy’s 10-K for the year ended December 31, 2014 and in the Notes to OGE Energy’s Consolidated Financial Statements for the year ended December 31, 2014 that will be included in OGE Energy’s 10-K for the year ended December 31, 2014. Under the terms of the Master Formation Agreement, the Partnership has no current or future liability for any accumulated pension obligations under either OGE Energy's or CenterPoint Energy's qualified defined benefit pension plans. During 2014, the Partnership reimbursed CenterPoint Energy and OGE Energy for the aggregate period costs recognized by CenterPoint Energy and OGE Energy in accordance with FASB ASC Topic 718 attributable to participants seconded to us by CenterPoint Energy and OGE Energy. Such period costs were not allocated to individual participants.

(5)	The following table sets forth the elements of All Other Compensation for 2014.

(6)	Represents salary from hire date on February 1, 2014 to December 31, 2014.

(7)	Represents salary from hire date on September 29, 2014 to December 31, 2014.

(8)

This amount represents a $132,000 signing bonus with the Partnership and a discretionary bonus of $50,000. Although Ms. Farmer was not eligible to receive an award for 2014 under the Partnership’s Short Term Incentive Plan, the Compensation Committee elected to pay Ms. Farmer a discretionary bonus of $50,000 that was calculated in accordance with the methodology used for 2014 awards to named executive officers under the Short Term Incentive Plan.

(9)	Represents salary from hire date on April 1, 2014 to December 31, 2014.

(10)	Represents salary during secondment to the Partnership from March 1, 2014 to December 31, 2014.

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(1)

Amounts in columns (c), (d) and (e) of the Grants of Plan-Based Awards Table for 2014 above represent the threshold, target and maximum amounts that would be payable to named executive officers pursuant to the 2014 annual incentive awards made under the Enable Midstream Partners, LP Short Term Incentive Plan. The short term incentive plan was designed with a funding trigger that requires threshold performance for the plan to payout. If threshold performance is not met, no payments would be made. For each performance measure, established thresholds were set (at which 50% payout would be made), a target level of performance (at which a 100% payout would be made) and a maximum level of performance (at or above which a 150% payout would be made). The award may be increased or decreased based on the performance of the named executive officer, but the award may not exceed 200% of the named executive officer's target. For 2013, payouts of these annual incentive awards were made in cash and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. As discussed in the Compensation Discussion and Analysis above, the amount that each executive officer will receive is dependent upon Partnership performance against a distributable cash flow per unit target (80%) and a safety target (20%).

(2)

Amounts in columns (f), (g) and (h) above represent awards of performance units under Enable Midstream Partners, LP Long Term Incentive Plan. All payouts of such performance units will be made in units and any accumulated distribution equivalent rights will be paid in cash. Due to their variable nature, accumulated distribution equivalent rights are not disclosed in the table above. The conditions of the 2014 award entitle the named executive officer to receive from 0 percent to 200 percent of the performance units granted depending upon the Partnership’s total unitholder return over a three-year period (defined as unit price increase (decrease) since December 31, 2013 plus distributions paid, divided by unit price at December 31, 2013) measured against the total unitholder return for such period of our performance peer group consisting of 21 companies. At the end of the three-year period (i.e., December 31, 2016), the terms of these performance units provide for payout of 100 percent of the performance units initially granted if Enable Midstream Partners’ total unitholder return is at the 50th percentile of the peer group, with higher payouts for performance above the 50th percentile up to 200 percent of the performance units granted if total unitholder return is at or above the 90th percentile of the peer group. The terms of these performance units provide for payouts of less than 100 percent of the performance units granted if the Partnership's total unitholder return is below the 50th percentile of the peer group, with no payout for performance below the 30th percentile.

(3)	Amounts reflect the grant date fair value based on a probable value of these awards or target value, of 100% payout. See Note 16 to the financial statements for further information.

(4)	These grants were contingent upon the closing of our Offering, which occurred on April 16, 2014.

(5)	These grants were contingent upon Ms. Farmer’s appointment as Executive Vice President and Chief Administrative Officer, which occurred on September 29, 2014.

(6)	These grants were approved by the Board of Directors on April 1, 2014, and were contingent upon the closing of our Offering, which occurred on April 16, 2014, and were granted on April 21, 2014 as determined in accordance with FASB ASC Topic 718.

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(1)	This amount represents two restricted unit awards, of which 75,000 units vested on February 1, 2015, and 75,000 units vest on each of 2016 and 2017, and 150,000 will vest on April 16, 2018. Values were calculated based on a $19.39 closing price of the Partnership's common units, as reported on the NYSE at December 31, 2014.

(2)	This amount represents a restricted unit award, of which 12,000 units vest on each of September 1, 2015 and 2016. Values were calculated based on a $19.39 closing price of the Partnership's common units, as reported on the NYSE at December 31, 2014.

(3)	This amount represents a phantom unit award which will vest on April 21, 2015. Values were calculated based on a $19.39 closing price of the Partnership's common units, as reported on the NYSE at December 31, 2014.

(4)	This amount represents two restricted unit awards, of which 62,507 units will vest on March 1, 2015, 74,993 units will vest on March 1, 2016 and 25,000 units will vest on April 16, 2018. Values were calculated based on a $19.39 closing price of the Partnership's common units, as reported on the NYSE at December 31, 2014.

(5)

This amount represents awards under the Enable Midstream Partners long term incentive plan for the performance period April 11, 2014 through December 31, 2016. The number of units is based on achieving the maximum performance resulting in payout of 200% of target. Values were calculated based on a $19.39 closing price of the Partnership's common units, as reported on the NYSE at December 31, 2014.

(6)

This amount represents awards under OGE Energy's long term incentive plan. This amount represents the portion of the performance units allocated to us for the performance period January 1, 2013 through December 31, 2015. The number of units is based on achieving the maximum performance resulting in payout of 200% of target. Each performance unit will be payable, if earned in one share of OGE Energy common stock. Values were calculated based on a $35.48 closing price of OGE Energy's common stock, as reported on the NYSE at December 31, 2014.

(7)

This amount represents awards under OGE Energy's long term incentive plan. This amount represents the portion of the performance units allocated to us for the performance period January 1, 2012 through December 31, 2014. The number of units is based on achieving the maximum performance resulting in payout of 200% of target. Each performance unit will be payable, if earned in one share of OGE Energy common stock. Values were calculated based on a $35.48 closing price of OGE Energy's common stock, as reported on the NYSE at December 31, 2014.

(8)

This amount represents awards under the CenterPoint long term incentive plan. This amount represents the portion of the performance units allocated to us for the performance period of January 1, 2012 through December 31, 2014. 2,200 shares are subject to only one achievement level, the remaining 7,530 are shown at maximum achievement of 150%. Each performance share will be payable, if earned in one share of CenterPoint Energy common stock. Values were calculated based on a $23.43 closing price of CenterPoint Energy's common stock, as reported on the NYSE at December 31, 2014.

(9)

This amount represents awards under the CenterPoint long term incentive plan. This amount represents the portion of the performance units allocated to us for the performance period of January 1, 2013 through December 31, 2015. 2,000 shares are subject to only one achievement level, the remaining 7,050 are shown at maximum achievement of 150%. Each performance share will be payable, if earned in one share of CenterPoint Energy common stock. Values were calculated based on a $23.43 closing price of CenterPoint Energy's common stock, as reported on the NYSE at December 31, 2014.

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(1)	Reflects value of payout of 150,000 restricted units awarded in April 2014. The units vested on August 1, 2014 and the award was paid out in units of the Partnership.

(2)

Reflects value of payout of OGE Energy performance units awarded in January 2012, 75% of whose payout was dependent on the achievement of a performance goal based on OGE Energy total shareholder return for the three-year period ended December 31, 2014 and 25% was dependent on the achievement of a performance goal based on annual growth in OGE Energy EPS over the same period. Awards were all paid out in shares of OGE Energy common stock, the cost of which was reimbursed by the Partnership.

(1)	Generally, a participant's years of credited service are based on his or her years of employment with CenterPoint Energy or OGE Energy.

(2)

Amounts in this column reflect the present value of the named executive officer’s benefits under CenterPoint Energy's or OGE Energy's qualified defined benefit pension plans and y determined using interest rate and mortality rate assumptions as reported to us by CenterPoint Energy and OGE Energy, which CenterPoint Energy and OGE Energy have represented to us will be reported in the Notes to CenterPoint Energy’s Consolidated Financial Statements for the year ended December 31, 2014  that will be included in CenterPoint Energy’s 10-K for the year ended December 31, 2014 and in the Notes to OGE Energy’s Consolidated Financial Statements for the year ended December 31, 2014, that will be included in OGE Energy’s 10-K for the year ended December 31, 2014, and includes amounts which the named executive officer may not currently be entitled to receive because such amounts are not vested. Under the terms of the Master Formation Agreement, the Partnership has no current or future obligation for any accumulated pension obligations under either OGE Energy or CenterPoint Energy defined benefit pension plans. During 2014, the Partnership reimbursed CenterPoint Energy and OGE Energy for the aggregate period costs recognized by CenterPoint Energy and OGE Energy in accordance with FASB ASC Topic 718 related to all participants seconded to us by CenterPoint Energy and OGE Energy. Such period costs were not allocated to individual participants.

(3)	The Partnership has not adopted a pension plan. Accordingly, information is only shown with respect to the participants in CenterPoint Energy's and OGE Energy's pension plans and associated restoration plans.

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(1)	All named executive officer and registrant contributions in the last fiscal year are reported as compensation to such named executive officer in the Summary Compensation Table. The specific aggregate amount reported for Stephen E. Merrill is $44,616, for E. Keith Mitchell is $157,056, and Mark Schroeder is $9,731.

(2)	Represents the portion allocated to the Partnership.

(3)	The Partnership adopted a nonqualified, unfunded deferred compensation plan in 2014. Compensation may be deferred under the plan beginning in 2015. Accordingly, information is only shown with respect to the participants in the CenterPoint Energy and OGE Energy nonqualified, unfunded deferred compensation plans.

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(1)	Reflects the aggregate grant date fair value of 2014 unit awards computed in accordance with FASB ASC Topic 718. As of December 31, 2014, each of Messrs. Kind and Hobbs held 3,359 unvested awards. See Note 16 to the financial statements for further information.

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*	Less than 1%

(1)	CenterPoint Energy, Inc. indirectly owns all of the outstanding equity interests in CenterPoint Energy Resources Corp., which is the record holder of the common units and subordinated units. CenterPoint Energy, Inc. is the beneficial owner of all common and subordinated units held by CenterPoint Energy Resources Corp.

(2)	OGE Energy Corp. owns all of the outstanding membership interests in OGE Enogex Holdings LLC, which is the record holder of the common units and subordinated units. OGE Energy Corp. is the beneficial owner of all common and subordinated units held by OGE Enogex Holdings LLC.

(3)

ArcLight Capital Partners, LLC is the investment advisor for, and ArcLight Capital Holdings, LLC is the managing partner of the general partner of ArcLight Energy Partners Fund V, L.P. and ArcLight Energy Partners Fund IV, L.P. ArcLight Capital Holding, LLC is the sole member of the general partner of Bronco Midstream Partners, L.P. The common units reported herein are held by Enogex Holdings and Bronco Midstream Infrastructure LLC. ArcLight Energy Partners Fund V, L.P., ArcLight Energy Partners Fund IV, L.P. and Bronco Midstream Partners, L.P. have monetary interests in the common units. Each of the foregoing entities disclaims beneficial ownership except to the extent of their monetary interest therein.

(4)	1111 Louisiana Street, Houston, Texas 77002

(5)	321 North Harvey, P.O. Box 321, Oklahoma City, Oklahoma 73101

(6)	One Leadership Square, 211 North Robinson Avenue, Suite 950, Oklahoma City, Oklahoma 73102

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(1)	Our Long Term Incentive Plan was adopted by our general partner for the benefit of our officers, directors and employees. See Item 11. "Executive Compensation-Compensation Discussion and Analysis." The plan provides for the issuance of a total of 13,100,000 common units under the plan.

(2)	The number of securities includes 838,068 restricted units that have been granted under our long term incentive plan that have not vested.

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•	their authority to enter into the transactions that formed us and the capitalization of the entities contributed to us;

•	permits related to the operation of the assets contributed to us;

•	compliance with environmental laws;

•	title to properties and rights of way;

•	the tax classification of the entities contributed to us;

•	indemnified taxes; and

•	events and conditions associated with their ownership and operation of the contributed assets.

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a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)	Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c)	Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.