Dcp Midstream Partners (DCP) Risk Analysis

The Merger Agreement restricts us from entering into certain corporate transactions, entering into certain material contracts, making certain changes to our capital budget, incurring certain indebtedness and taking other specified actions without the consent of Phillips 66, and generally requires us to continue our operations in the ordinary course of business during the pendency of the Merger. These restrictions may prevent us from pursuing attractive business opportunities or adjusting our capital plan prior to the completion of the Merger.

FERC, pursuant to the NGA, regulates many aspects of our interstate natural gas pipeline transportation service, including the rates our pipelines are permitted to charge for such service. Under the NGA, interstate transportation rates must be just and reasonable and not unduly discriminatory. If FERC fails to permit our requested tariff rate increases, or if FERC lowers the tariff rates we are permitted to charge, on its own initiative, or as a result of challenges raised by customers or third parties, our tariff rates may be insufficient to recover the full cost of providing interstate transportation service. In certain circumstances, FERC also has the power to order refunds. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and the disgorgement of profits. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.5 million per day for each violation and possible criminal penalties of up to $1.5 million per violation and five years in prison.

The majority of our natural gas gathering and intrastate transportation operations are exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. FERC's policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines, however there can be no assurance that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transportation services and federally unregulated gathering services has been the subject of regular litigation, so the classification and regulation of some of our gathering facilities and intrastate transportation pipelines may be subject to change based on any reassessment by us of the jurisdictional status of our facilities or on future determinations by FERC and the courts. In addition, the rates, terms and conditions of some of the transportation services we provide on certain of our pipeline systems are subject to FERC regulation under Section 311 of the NGPA. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Several of our pipelines are interstate transporters of NGLs and are subject to FERC jurisdiction under the Interstate Commerce Act and the Elkins Act. The base interstate tariff rates for our NGL pipelines are determined either by a FERC cost-of-service proceeding or by agreement with an unaffiliated party, and adjusted annually through the FERC's indexing methodology. The NGL pipelines may also provide incentive rates, which offer tariff rates below the base tariff rates for high volume shipments. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and disgorgement of profits. Under EPACT 2005, FERC has civil penalty authority under the NGA to impose penalties of up to $1.5 million per day for each violation and possible criminal penalties of up to $1.5 million per violation and five years in prison. Under the NGPA, FERC may impose civil penalties of up to $1.5 million for any one violation and may impose criminal penalties of up to $1.5 million and five years in prison. Other state and local regulations also affect our business. Our non-proprietary gathering lines are subject to ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport oil or natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination. Other state regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our proprietary gathering lines are currently subject to limited state regulation, there is a risk that state laws will change, which may give producers a stronger basis to challenge the proprietary status of a line, or the rates, terms and conditions of a gathering line providing transportation service.

On April 16, 2019, Governor Polis signed into law Senate Bill 19-181 ("SB-181"), which amended existing laws and enacted new laws concerning the conduct of oil and gas operations in Colorado. The bill changed the mandate of the Colorado Oil and Gas Conservation Commission (the "COGCC") to regulate oil and gas development in a manner that protects the public health, safety, welfare, and the environment and wildlife, from the previous mandate to foster the development and production of oil and gas. Other key elements of SB-181 include granting local governments ability to regulate facility siting and surface impacts of oil and gas operations as well as the ability to inspect and impose fines for leaks, spills, and emissions, and requiring the Colorado Department of Public Health and Environment (the "CDPHE") to adopt additional rules that call for the minimization and continual monitoring of emissions at oil and gas facilities. SB-181 also requires the COGCC to conduct rulemakings concerning the cumulative impacts of oil and gas development, additional flowline regulations, as well as other matters. The COGCC completed the most significant rulemaking to implement SB-181 in late 2020, with the final SB-181 rulemaking concerning financial assurance having been completed in early 2022. These rules are focused on upstream oil and gas development, and as a whole touch on nearly every aspect of oil and gas development activity. Due to the scope and complexity of the rules, the COGCC has issued guidance materials that will be central to achieving successful rule implementation. Although our customers have expressed confidence in their ability to conform to the rules and move forward with predictable development plans, the number of drilling permits issued by the COGCC slowed considerably in 2021 as staff began reviewing permit applications in accordance with the new rules. We expect the approval of well permit applications to improve as operators and COGCC staff both gain experience with the new regulatory regime, and because our customers are increasingly focused on permitting comprehensive area plans that will allow for the approval of a larger number of wells as part of larger long-term development plans. While much of our oil and gas infrastructure in Colorado is not located near populous areas, the population in Colorado continues to grow, which may result in populated areas coming closer to existing and proposed oil and gas development. Notably, Weld County has exercised the authority granted under SB-181 to enact its own local siting and permitting regulatory framework, in a manner that is intended to and has allowed for continued oil and gas development in the jurisdiction where the majority of our assets are located. However, local regulations enacted under SB-181 do not supplant the COGCC's authority over well permitting and approval, and thus even in Weld County our customers may experience additional costs or delays associated with obtaining those state permits. Any such impact on new oil and gas development, would, as production from existing and previously permitted wells depletes, lead to a reduction in demand for our gathering, processing, and transportation services in the state, which reduction, over time, may be material. In addition, in 2019 the Colorado legislature enacted HB19-1261 establishing statewide greenhouse gas emission reduction goals and included agency authorities and mandates to promulgate regulations to achieve greenhouse gas reduction goals. In January 2021, Governor Polis issued the "Greenhouse Gas Pollution Reduction Roadmap," which describes state actions and the regulatory pathway to achieve the HB19-1261 greenhouse gas reduction goals. The Greenhouse Gas Reduction Roadmap specifies, among other things, intended reductions by economic sector, including the oil and gas sector as well as the "residential, commercial and industrial" sector that includes emissions from the combustion of fuels. In 2021, the governor signed HB21-1266 into law, which required the adoption of rules to reduce greenhouse gas ("GHG") emissions from "oil and gas exploration, production, processing, transmission, and storage operations" by at least 36% by 2025 and 60% by 2030 below a 2005 baseline. These regulatory actions have been and will be pursued by various state agencies, including the Colorado Energy Office and the Colorado Air Quality Control Commission ("AQCC"). In December 2021, the AQCC adopted regulations to reduce GHGs from the oil and gas sector through myriad requirements to address emissions and control requirements, including emissions reduction requirements for production well sites, and capture requirements for pigging activities and capture and control requirements for equipment blowdowns. The AQCC also adopted requirements for a Steering Committee to assess methods and feasibility to reduce GHG emissions from industrial combustion of hydrocarbon fuels, specifically including oil and gas sector compression equipment to gather and transport natural gas, ultimately resulting in plans and regulations for oil and gas sector industrial combustion equipment to achieve the HB21-1266 reduction goals. These regulations collectively are anticipated to impose near- and longer-term obligations and costs on our producer customers as well as on our own midstream equipment and facilities. These rulemaking proceedings to reduce greenhouse gas emissions could increase costs on or inhibit or adversely influence the ability of our producer customers to develop and operate production wells. These rulemaking proceedings could increase costs for us to operate our compressor stations or gas plants in the state, and they could affect the types of equipment or the manner in which we operate our midstream equipment. These rulemaking proceedings, or future related rulemaking proceedings, have the potential to result in some manner of greenhouse gas emissions caps in the state, or greenhouse gas sector-specific performance standards, either of which could result in increased costs on our producer customers or increased costs on us to operate our facilities, and could affect the types of equipment that we operate or the manner in which it is operated. These rulemaking proceedings have the potential to affect the operations and production of our customers, which can in turn affect our operations, and they also have the potential to affect our costs and facility operations, either of which could adversely affect our financial results or have such an effect on our operations. The official title of HB21-1266 is the Environmental Justice Act and the legislation also created the Environmental Justice Action Task Force, a 22-member body charged with recommending and promoting strategies for incorporating environmental justice and equity into how state agencies discharge their responsibilities. The Task Force completed its duties with the issuance of a final report on November 14, 2022, which presented to the governor and the general assembly a set of seven recommendations including topics such as environmental justice coordination, agency consideration of cumulative impacts, data collection, and best practices for community engagement. While none of the recommendations are binding, they do represent the basis for which future legislation and agency rulemakings could impose additional legal requirements that impact our ability or that of our producer customers to obtain necessary permits, construct and expand our assets, and operate our facilities.

Certain states in which we operate have adopted or are considering adopting measures that could impose new or more stringent requirements on oil and gas exploration and production activities. Those measures could include heightened permitting requirements for upstream operations that impact the location, timing, and scope of new development activity, and may include additional drilling and operational restrictions in order to address environmental justice concerns, minimize impacts to disproportionately impacted communities, and possibly to contend with elevated ground-level ozone days. Local governments may exercise their land use authority and police powers to impose additional development restrictions and ongoing regulation of odor, traffic, noise and other community impacts. In Colorado, private organizations have sponsored and may in the future sponsor citizen initiatives to limit hydraulic fracturing, increase mandatory setbacks of oil and gas operations from occupied structures, and achieve more restrictive state or local control over such activities. In the event state or local restrictions or prohibitions are adopted in our areas of operations, our customers may incur significant compliance costs or may experience delays or curtailment in the pursuit of their exploration, development, or production activities, and possibly be limited or precluded in the drilling of certain wells altogether. Any adverse impact on our customers' activities would have a corresponding negative impact on our throughput volumes. In addition, while the general focus of debate is on upstream development activities, certain proposals may, if adopted, directly impact our ability to competitively locate, construct, maintain, and operate our own assets. Accordingly, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, cash flows and ability to make distributions to our unitholders.

On January 29, 2019, the New Mexico governor issued an executive order establishing an interagency Climate Change Task Force and directing the Energy, Minerals and Natural Resources Department ("EMNRD") and the New Mexico Environment Department ("NMED") to develop a statewide, enforceable regulatory framework to reduce methane emissions from new and existing sources in the oil and gas sector. Following a year-long stakeholder process by both agencies, the Oil Conservation Division ("OCD") adopted the EMNRD rules in mid-2021, which institute gas capture requirements for both upstream and midstream operators, prohibit routine flaring, and require operation plans for operators of gas gathering systems. In 2022, NMED adopted an Ozone Precursor rule to regulate and control ozone precursor pollutants, including volatile organic compounds ("VOCs") and nitrogen oxides ("NOx"), from the oil and gas industry, which will also control or reduce methane emissions. The rule establishes emission standards and emission reduction requirements for various equipment and processes as well as leak detection and repair requirements. The EMNRD rules impose additional operational requirements and costs, and potential regulatory compliance and enforcement risk, on our facilities and operations. The NMED rule will impose additional operational costs and potential regulatory compliance and enforcement risks. Similarly, our customers are expected to incur compliance costs of their own under these rules and may, if out of compliance, experience delays or curtailment in the pursuit of their exploration, development, or production activities. Any adverse impact on our customers' activities could have a corresponding negative impact on our throughput volumes. Accordingly, such restrictions or prohibitions could have an adverse effect on our business, prospects, results of operations, financial condition, cash flows and ability to make distributions to our unitholders.

The Biden administration has generally taken a more rigorous approach to environmental regulations and permitting reviews, particularly as they related to air quality and climate issues. In January 2021, President Biden issued Executive Order 13990, which directed executive departments and agencies at the time to review all existing regulations, orders, guidance documents, policies and any other similar action taken during the previous Administration that are inconsistent with President Biden's plan to elevate climate issues and, as appropriate, suspend, revise, or rescind those that are inconsistent with that plan. Those initial actions included the revocation of certain prior Executive Orders concerning federal regulation executed by the previous Administration, as well as new Executive Orders directing a focused regulatory freeze and review of rulemaking actions taken by the prior Administration. Additionally, in January 2021, President Biden issued Executive Order 14008 imposing a temporary moratorium on the issuance of new oil and gas leases on public lands and offshore waters, pending a comprehensive review and reconsideration of oil and gas permitting and leasing practices. That same Order directed a government-wide effort to address climate change by reducing greenhouse gas emissions and achieving net-zero global carbon emissions by mid-century or before. That effort was designed to infuse climate policy in all aspects of federal decision-making, including specific directives that touch for example on foreign policy, national security, financial regulation, federal procurement, infrastructure, and environmental justice. The moratorium on new oil and gas leases was challenged in several courts, including in Louisiana federal district court in a lawsuit filed in March 2021 by officials representing 13 states and in Wyoming federal district court in a similar lawsuit by officials representing the State of Wyoming and various trade organizations, and in North Dakota federal district court in a similar lawsuit by officials representing State of North Dakota. In June 2021, the Louisiana federal judge issued a preliminary injection and in August 2022, a permanent injunction against the moratorium as it pertains to the states that are parties to the Louisiana litigation. When on-shore lease sales resumed in 2022, the acreage was geographically limited, and the lease terms included higher federal royalty rates more in line with royalties required by many states, and the environmental review accompanying the lease sale notices generally contained more robust greenhouse gas emissions and climate change impact analyses. As of the end of the 2022 fiscal year on September 30, 2022, the Biden Administration had offered only 127,691 onshore acres for lease. On August 16, 2022, President Biden signed the reconciliation budget bill, known as the Inflation Reduction Act of 2022 ("IRA"), which imposed an expression of interest fee for nominating federal lands for potential lease sale, increased the royalty rate, annual rental rate, and minimum bid on federal oil and gas leases issued after that date, and ended the noncompetitive oil and gas leasing process. Furthermore, royalty will now also be imposed on gas that is vented, flared, or leaked, except for safety purposes. However, as a concession to Senator Manchin, wind and solar development was tied to the reinstatement of federal oil and gas lease sales. The IRA requires Department of the Interior to offer at least two million acres a year for federal onshore oil and gas lease sales or half of all the land nominated for leasing and hold a lease sale within 120 days of issuing any wind or solar rights-of-way. The IRA also includes a new "waste emission charge" imposed for methane emissions for oil and gas production and onshore pipelines, storage, gathering, and boosting for facilities that emit more than 25,000 metric tons of carbon dioxide annually beginning in 2025. On November 3, 2022, the U.S. Environmental Protection Agency issued a Request for Information seeking comments on implementation of both the methane emissions charge and the methane emissions reduction incentives program authorized and funded by the IRA. Also in November 2022, the Department of Interior issued seven Instruction Memoranda outlining the agency's policies for implementing the IRA. On November 15, 2021, PHMSA published a Final Rule amending the gas pipeline safety regulations at 49 CFR Parts 191 and 192 to extend regulation over larger diameter gas gathering pipelines located in rural (Class 1) locations (the "Final Gathering Rule"). The Final Gathering Rule imposes Part 191 or Part 192 requirements on such rural gathering pipelines. All rural gathering pipelines will be subject to annual and incident reporting under Part 191, while those pipelines over 8.625 inches in diameter that are operated at a maximum allowable operating pressure ("MAOP") of more than 20% of specified minimum yield strength ("SMYS") or, where SMYS is not known, where the MAOP exceeds 125 psig, must also comply with certain Part 192 requirements. The applicable Part 192 requirements increase with increased diameter and with proximity to buildings intended for human occupancy or impacted sites. For gathering pipelines between 8.625 inches and 16 inches in diameter, the new regulations require annual and incident reporting, as well as design and construction standards, damage prevention, and emergency planning on new pipelines or those that are repaired or replaced or otherwise substantially changed. If the potential impact radius of the pipeline segment includes a building intended for human occupancy or an impacted site, corrosion control, line markers, public awareness and leakage survey and repair for pipelines of less than 12.75 inches in diameter are also added, and MAOP requirements and standards for plastic pipelines for lines are added for pipelines between 12.75 inches and 16 inches in diameter. Pipelines of more than 16 inches in diameter are subject to all of the above, whether or not the potential impact radius includes any structures intended for human occupancy or impacted sites. The Part 191 reporting requirements of the Final Gathering Rule took effect on May 16, 2022. The remaining Part 192 requirements were to take effect on November 15, 2022, or May 16, 2023, depending on the rule section. However, following GPA Midstream Association's petition for judicial review of the new rule, PHMSA agreed to stay enforcement until May 16, 2024, with respect to smaller-diameter pipelines (8.625 to 12.75 inches). In November 2021, EPA proposed the expansion of the federal new source performance standards ("NSPS") for new and modified, and existing, oil and gas sector sources that regulate emissions of VOCs and methane from these sources. EPA had promulgated enhanced NSPS regulations for VOCs in 2012 and the NSPS for VOCs and methane in 2016. The regulations, contained in 40 CFR Part 60, Subpart OOOO and OOOOa, among other things, require control of VOC and methane emissions from subject sources through ensuring adequate design, requiring installation of emission controls, and institution of leak detection and repair programs. EPA's November 2021 proposed regulations would expand the scope and breadth of the existing regulations. The 2021 proposed rules include provisions that: 1) extend emission control and reduction requirements under this part of the Clean Air Act to existing oil and gas sources, which is a first; and 2) expand and tighten the existing emission reduction requirements for new or modified oil and gas sources adopted in 2012 and 2016. In December 2022, EPA issued a supplemental proposal to update, strengthen, and expand the 2021 proposed rules. EPA is expected to finalize the rule in 2023. In the event federal executive or legislative initiatives result in increased federal lease costs or requirements, restrictions or prohibitions that apply to our areas of operations, our customers may incur increased compliance costs or may experience delays or curtailment in the pursuit of their exploration, development, or production activities, and possibly be limited or precluded in the drilling of certain wells. Any adverse impact on our customers' activities could have a corresponding negative impact on our throughput volumes. In addition, certain administrative rules and legislative proposals specifically target existing law and direct future federal rulemaking activity that may, if adopted, directly impact our ability to competitively locate, construct, maintain, and operate our own assets. Accordingly, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, cash flows and ability to make distributions to our unitholders.

Certain of our customers' natural gas is developed from formations requiring hydraulic fracturing as part of the completion process. Fracturing is a process where water, sand, and chemicals are injected under pressure into subsurface formations to stimulate hydrocarbon production. While the underground injection of fluids is regulated by the EPA under the Safe Drinking Water Act, or SDWA, hydraulic fracturing is excluded from regulation except where the injection fluid is diesel fuel. The EPA has published an interpretive memorandum and permitting guidance related to regulation of fracturing fluids using this regulatory authority. Over the past several years, the EPA has finalized various regulatory programs directed at hydraulic fracturing. For example, in June 2016, the EPA issued regulations under the federal Clean Water Act to further regulate wastewater discharges from hydraulic fracturing and other natural gas production to publicly owned treatment works. States can propose or promulgate regulations or enact initiatives or legislation imposing conditions or restrictions on hydraulic fracturing practices or oil and gas well development using hydraulic fracturing or horizontal drilling techniques. The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting or regulating, the hydraulic fracturing process could make it more difficult for our customers to complete oil and natural gas wells in shale formations and increase their costs of compliance. Several states in which our customers operate have also adopted regulations requiring disclosure of fracturing fluid components or otherwise regulate their use more closely. In Oklahoma, induced seismicity from injection of fluids in wastewater disposal wells has resulted in regulatory limitations on wastewater disposal into such wells. The implementation of rules relating to hydraulic fracturing could result in increased expenditures for our exploration and production customers, which could cause them to reduce their production and thereby result in reduced demand for our services by these customers. President Biden has taken action to roll back many of the policies and regulations that the Trump administration had put in place to ease burdens on the development or use of domestically produced energy resources. President Biden issued Executive Order 13990 on January 20, 2021, directing executive departments and agencies to review all existing regulations, orders, guidance documents, policies and any other similar action taken during the Trump administration that are inconsistent with President Biden's plan to elevate climate issues and, as appropriate, suspend, revise, or rescind those that are inconsistent with that plan. Our customers will continue to be subject to uncertainty associated with new regulatory measures as well as new regulatory suspensions, revisions, or rescissions and conflicting state and federal regulatory mandates, which could adversely affect their production and thereby result in reduced demand for our services by these customers.

Investment in units by tax-exempt entities, such as individual retirement accounts, or IRAs, other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income, which may be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) may be required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business or vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. Gain recognized from a sale or other disposition of our units by a non-U.S. person will be subject to federal income tax as income effectively connected with a U.S. trade or business. Moreover, the transferee of our units (or the transferee's broker, if applicable) is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Recent final Treasury regulations provide for the application of this withholding rule to open market transfers of interests in publicly traded partnerships beginning on January 1, 2023. Under these regulations, the "amount realized" for purposes of this withholding is the gross proceeds paid or credited upon the transfer. If a unitholder is a tax-exempt entity or a non-U.S. person, the unitholder should consult its tax advisor before investing in our units.

In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder's share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder's units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder's tax basis in its units. In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our assets.

The tax treatment of distributions on our Preferred Units is uncertain. We will treat the holders of our Preferred Units as partners for tax purposes and will treat distributions on our Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of our Preferred Units as ordinary income and will not be eligible for the deduction provided for under Code Section 199A. Although a holder of our Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions associated with the Preferred Units. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payments attributable to the period beginning December 15 and ending December 31 will accrue as income to the holder of record of a Preferred Unit on December 31 for such period, regardless of whether such holder continues to own the Preferred Units at the time the actual distribution is made. Otherwise, the holders of our Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction, except to the extent necessary to provide, to the extent possible, the Preferred Units with the benefit of the liquidation preference. We will not allocate any share of our nonrecourse liabilities to the holders of our Preferred Units. If our Preferred Units were treated as indebtedness for tax purposes, rather than as partnership interests, distributions on our Preferred Units likely would be treated as payments of interest by us to the holders of our Preferred Units, rather than as guaranteed payments for the use of capital. A holder of our Preferred Units will be required to recognize gain or loss on a sale of its Preferred Units equal to the difference between the amount realized by such holder and tax basis in the Preferred Units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder of the Preferred Unit to acquire such Preferred Unit. Gain or loss recognized by a holder of a Preferred Unit on the sale or exchange of a Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of our Preferred Units will generally not be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS regarding our status as a partnership. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation, the IRS could disagree with the positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state income tax at varying rates. Distributions to a unitholder would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to the unitholder. Because a tax would be imposed upon us as a corporation, our cash available for distribution to a unitholder would be substantially reduced. Therefore, treatment of us as a corporation for federal tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to a unitholder, likely causing a substantial reduction in the value of our units.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our units, may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Moreover, any such modification could make it more difficult or impossible for us to meet the exception that allows publicly traded partnerships that generate qualifying income to be treated as partnerships (rather than corporations) for federal income tax purposes, affect or cause us to change our business activities, or affect the tax consequences of an investment in our units. The U.S. Treasury Department issued final regulations interpreting the scope of activities that generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended, or the Code. We believe that the income we currently treat as qualifying income satisfies the requirements for qualifying income under the final regulations. Public Law 115-97, known as the Tax Cuts and Jobs Act enacted on December 22, 2017 (the "Tax Cuts and Jobs Act") provides a deduction under Code Section 199A to a non-corporate common unitholder, for taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, equal to 20% of his or her allocable share of our "qualified business income." For purposes of this deduction, our "qualified business income" is equal to the sum of the net amount of our items of income, gain, deduction and loss to the extent such items are included or allowed in the determination of taxable income for the year, excluding, however, certain specified types of passive investment income (such as capital gains and dividends); and any gain recognized upon a disposition of our units to the extent such gain is attributable to certain assets, such as depreciation recapture and our "inventory items," and is thus treated as ordinary income under Section 751 of the Code. This law also includes certain new limitations on the use of losses and other deductions to offset taxable income. Various aspects of this deduction and these limitations may be modified by administrative, legislative or judicial interpretations at any time, which may or may not be applied retroactively. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation, which would reduce the cash available for distribution to our unitholders. For example, we are required to pay the State of Texas a margin tax that is assessed at 0.75% of taxable margin apportioned to Texas.

We are subject to extensive tax laws and regulations, with respect to federal, state and foreign income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future.

Our operations, and the operations of third parties, are subject to many hazards inherent in the gathering, compressing, treating, processing, storing, transporting and fractionating, as applicable, of natural gas and NGLs, including: - damage to pipelines, plants, terminals, storage facilities and related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;- inadvertent damage from construction, farm and utility equipment;- leaks of natural gas, NGLs and other hydrocarbons from our pipelines, plants, terminals, or storage facilities, or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;- contaminants in the pipeline system;- fires and explosions; and - other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. We are not fully insured against all risks inherent to our business, including offshore wind. We insure our underground pipeline systems against property damage, although coverage on certain of our small diameter gathering pipelines is subject to usual and customary sublimits. We are not insured against all environmental accidents that might occur, which may include toxic tort claims, other than those considered to be sudden and accidental. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage, or may become prohibitively expensive, and we may elect not to carry such a policy.

Our pipelines and facilities are located either on land that we own in fee, or on land in which our right to use such land for our operations is derived from leases, easements, rights of way, permits, or licenses from landowners or governmental authorities either in perpetuity or for a specific period of time. We may become subject to more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or if such rights of way lapse or terminate. Certain of our leases contain renewal provisions that allow for our continued use and access of the subject land and, although we review and renew our leases as a routine business matter, there may be instances where we may not be able to renew our contract leases on commercially reasonable terms or may have to commence eminent domain proceedings to establish our right to continue to use the land. Any loss of rights with respect to land on which we operate, could disrupt our ability to continue operations thereon and adversely affect our business, results of operations, and financial position.

Our unit price has experienced volatility in the past, and volatility in the price of our units may occur in the future as a result of any of the risk factors contained herein and the risks described in our other public filings with the SEC. For instance, our units may experience price volatility as a result of changes in investor sentiment with respect to our competitors, our business partners and our industry in general, which may be influenced by volatility in prices for NGLs, natural gas and crude oil. In addition, the securities markets have from time to time experienced significant price and volume fluctuations that are unrelated to the operating performance of particular companies but affect the market price of their securities. These market fluctuations may also materially and adversely affect the market price of our units.

The construction of new midstream facilities or additions or modifications to our existing midstream asset systems involves numerous regulatory, environmental, political, legal, and economic uncertainties beyond our control and may require the expenditure of significant amounts of capital. For example, public participation in review and permitting processes can introduce uncertainty and additional costs associated with project timing and completion. Relatedly, civil protests regarding environmental and social issues, including construction of infrastructure associated with fossil fuels, may lead to increased legislative and regulatory initiatives and review at federal, state, and local levels of government that could prevent or delay the construction of such infrastructure and realization of associated revenues. Construction expenditures may occur over an extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully operational. Moreover, our cash flow from a project may be delayed or may not meet our expectations. These projects may not be completed on schedule or within budgeted cost, or at all. We may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for, and development of, natural gas and oil reserves, we often do not have access to third party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to construct new systems or additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, these facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The construction of new systems or additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing these facilities. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. The construction of new systems or additions to our existing gathering and transportation assets may also require us to obtain various regulatory approvals. For example, under the NGA and the National Environmental Policy Act of 1969, FERC has broad authority to approve the construction of new interstate natural gas pipeline facilities, including imposing environmental conditions on certificates of public convenience and necessity. New pipeline infrastructure projects could face increased scrutiny and enhanced regulatory reviews by federal, state and/or environmental regulators due to an increased focus on climate change policies and the fossil fuel industry. While we do not currently have projects pending that are subject to material risk, any governmental or regulatory actions that place additional burdens and/or costs on future projects, could adversely impact our ability to develop new infrastructure. The construction of new systems or additions to our existing gathering and transportation assets may require us to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas and NGLs. If such third-party facilities are not constructed or operational at the time that the addition to our facilities is completed, we may experience adverse effects on our results of operations and financial condition. The construction of additional systems may require greater capital investment if the commodity prices of certain supplies, such as steel, increase. Construction also subjects us to risks related to the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials, labor, or other factors beyond our control that could adversely affect results of operations, financial position or cash flows.

The profitability of our NGL pipelines is dependent on the level of production of NGLs from processing plants. When natural gas prices are high relative to NGL prices, it is less profitable to process natural gas because of the higher value of natural gas compared to the value of NGLs and because of the increased cost (principally that of natural gas as a feedstock and fuel) of separating the NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce the volume of natural gas processed at plants connected to our NGL pipelines, and reduce the amount of NGL extraction, which would decrease the volumes and gross margins attributable to our NGL pipelines and NGL storage facilities.

Our business is affected by natural gas, NGL and crude oil prices. The prices of natural gas, NGLs and crude oil have historically been volatile, and we expect this volatility to continue. The level of drilling activity is dependent on economic and business factors beyond our control. Among the factors that impact drilling decisions are commodity prices, the liquids content of the natural gas production, drilling requirements for producers to hold leases, the cost of finding and producing natural gas and crude oil and the general condition of the financial markets. Commodity prices experienced volatility during 2022, as illustrated by the following table: Year Ended December 31, 2022December 31, 2022 Daily HighDaily LowCommodity:NYMEX Natural Gas ($/MMBtu)$9.68 $3.72 $4.48 NGLs ($/Gallon)$1.35 $0.66 $0.72 Crude Oil ($/Bbl)$123.70 $71.02 $80.26

We are subject to risks of loss resulting from nonpayment or nonperformance by our producer customers and counterparties. Any material nonpayment or nonperformance by our producer customers or counterparties could reduce our ability to make distributions to our unitholders. Furthermore, some of our producer customers or counterparties may be highly leveraged and subject to their own operating and regulatory risks, which could increase the risk that they may default on their obligations to us. Additionally, a decline in the availability of credit to producers in and surrounding our geographic footprint could decrease the level of capital investment and growth that would otherwise bring new volumes to our existing assets and facilities. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices, or financial difficulties that could impact their creditworthiness and ability to perform their contractual obligations, including their ability to pay us.

We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering, processing and transportation systems for resale to third parties, including natural gas marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be unbalanced. While we attempt to balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.

The capital markets may experience volatility, which may lead to financial uncertainty. Our access to funds under the Credit Agreement is dependent on the ability of the lenders that are party to the Credit Agreement to meet their funding obligations. Those lenders may not be able to meet their funding commitments if they experience shortages of capital and liquidity. If lenders under the Credit Agreement were to fail to fund their share of the Credit Agreement, our available borrowings could be further reduced. In addition, our borrowing capacity may be further limited by the financial covenants contained in the Credit Agreement. A significant downturn in the economy could adversely affect our results of operations, financial position or cash flows. In the event that our results were negatively impacted, we could require additional borrowings. A deterioration of the capital markets could adversely affect our ability to access funds on reasonable terms in a timely manner.