We derive a substantial portion of our revenue from Noble. If Noble changes its business strategy, alters its current drilling and development plan on our dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders would be materially and adversely affected.
A substantial portion of our commercial agreements are with Noble or its affiliates. Accordingly, because we derive a substantial portion of our revenue from our commercial agreements with Noble, we are subject to the operational and business risks of Noble, the most significant of which include the following:
In addition, we are indirectly subject to the business risks of Noble generally and other factors, including, among others:
Further, we have no control over Noble’s business decisions and operations, and Noble is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of cancellation of planned development, breach of commitments with respect to future dedications; and other non-payment or non-performance by Noble, including with respect to our commercial agreements, which do not contain minimum volume commitments. Noble is currently conducting development drilling activities in both the DJ and Delaware Basins. A decrease in development drilling and completion activities on our dedicated acreage could result in lower throughput on our midstream infrastructure. Furthermore, we cannot predict the extent to which Noble’s businesses would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Noble’s ability to execute its drilling and development plan on our dedicated acreage or to perform under our commercial agreements. Any material non-payment or non-performance by Noble under our commercial agreements would have a significant adverse impact on our business, financial condition, results of operations and cash flows and could therefore materially adversely affect our ability to make cash distributions to our unitholders. Our long-term commercial agreements with Noble carry initial terms for 15 years, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our commercial agreements following their expiration at rates sufficient to maintain our current revenues and cash flows could be adversely affected by activities beyond our control, including the activities of our competitors and Noble.
In addition to our commercial agreements with Noble, we provide midstream services and crude oil sales for unaffiliated, non-investment grade third-party customers. We may engage in significant business with new third-party customers or enter into material commercial contracts with customers for which we do not have material commercial arrangements or commitments today and who may not have investment grade credit ratings. Each of the risks indicated above applies to our current third-party customers and to the extent we derive substantial income from or commit to capital projects to service new or existing customers, each of the risks indicated above would apply to such arrangements and customers.
In the event any customer, including Noble, elects to sell acreage that is dedicated to us to a third party, the third party’s financial condition could be materially worse than the customer with whom we have contracted, and thus we could be subject to the nonpayment or nonperformance by the third party.
The third party may be subject to its own operating and regulatory risks, which increases the risk that it may default on its obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our unitholders.
We may not generate sufficient distributable cash flow to enable us to make quarterly distributions to our unitholders at our current distribution rate.
We may not generate sufficient distributable cash flow to enable us to make quarterly distributions at our current distribution rate. For example, in response to the unprecedented impact on our business from the significant decline in commodity prices and the COVID-19 outbreak, on March 25, 2020, the Board of Directors of our General Partner approved a 73% reduction of the quarterly distribution to $0.1875 per unit for the first quarter 2020. We maintained the reduced quarterly distribution for the second, third and fourth quarter 2020.
The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
In addition, the actual amount of distributable cash flow that we generate will also depend on other factors, some of which are beyond our control, including:
Because of the natural decline in production from existing wells, our success, in part, depends on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our dedicated acreage.
The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. In order to maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Noble and any third-party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.
We have no control over Noble’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over Noble or other producers or their exploration and development decisions, which may be affected by, among other things:
Our midstream assets are currently primarily located in the DJ Basin in Colorado and the Delaware Basin in Texas, making us vulnerable to risks associated with operating in a limited geographic area.
As a result of this concentration, we will be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, market limitations, water shortages, drought related conditions or other weather-related conditions or interruption of the processing or transportation of crude oil and natural gas. If any of these factors were to impact the DJ Basin or Delaware Basin more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions could be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.
Our acreage dedication and commitments from our customers cover midstream services in a number of areas that are at the early stages of development, in areas that our customers are still determining whether to develop and in areas where we may have to acquire operating assets from third parties. In addition, our customers own acreage in areas that are not dedicated to us. We cannot predict which of these areas our customers will determine to develop and at what time. Our customers may decide to explore and develop areas where the acreage is not dedicated to us. Our customers’ decisions to develop acreage that is not dedicated to us may adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
While we have been granted a right of first refusal to provide midstream services on certain acreage that Noble currently owns and on allcertain acreage that Noble acquires onshore in the U.S., portions of this acreage may be subject to preexisting dedications that may require Noble to use third parties for midstream services.
Portions of this acreage may be subject to preexisting dedications, rights of first refusal, rights of first offer and other preexisting encumbrances that require Noble to use third parties for midstream services, and, as a result, Noble may be precluded from offering us the opportunity to provide these midstream services on this acreage. Because we do not have visibility as to which acreage Noble may acquire or divest, and what existing dedications, rights of first refusal, rights of first
offer or other overriding rights may exist on such acreage, we are unable to predict the value, if any, of our ROFR to provide midstream services on Noble’s acreage onshore in the United States.
We may not be able to economically accept an offer from Noble for us to provide services or purchase assets with respect to which we have a right of first refusal.
Noble is required to offer us, prior to contracting for such opportunity with a third party, the opportunity to provide the midstream services covered by our commercial agreements, which include crude oil gathering, natural gas gathering, produced water gathering, fresh water services and crude oil treating, as well as services of a type provided at natural gas processing plants on certain acreage located in the United States that Noble currently owns or in the future acquires or develops. In addition, Noble is required to offer us, prior to contracting for such opportunity with a third party, the ownership interest in any midstream assets that are located on the acreage for which Noble has granted us a ROFR to provide services. The acreage and assets subject to this ROFR may be located in areas far from our existing infrastructure or may otherwise be undesirable in the context of our business. In addition, we can make no assurances that the terms at which Noble offers us the opportunity to provide these services or purchase these assets will be acceptable to us. Furthermore, another midstream service provider or third party may be willing to accept an offer from Noble that we are unwilling to accept. Our inability to take advantage of the opportunities with respect to such acreage or assets could adversely affect our growth strategy or our ability to maintain or increase our cash distribution level.
We may be unable to grow by acquiring midstream assets retained, acquired or developed by Noble, which could limit our ability to increase our distributable cash flow.
Part of our strategy for growing our business and increasing distributions to our unitholders is dependent upon our ability to make acquisitions that increase our distributable cash flow. Noble is under no obligation to offer to sell us additional assets, we are under no obligation to buy any additional assets from Noble and we do not know when or if Noble will decide to make any offers to sell assets to us.
AnWe may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any ability to do so may disrupt our business and hinder our ability to grow and an acquisition from Noble or a third party may reduce, rather than increase, our distributable cash flow or may disrupt our business.
We may not be able to identify attractive acquisition opportunities. Even if we make acquisitionsdo identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we believe will be accretive, theseable to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions may nevertheless result in a decrease in our distributable cash flow.on acceptable terms or successfully acquire identified targets. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:
•mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
•an inability to successfully integrate the acquired assets or businesses;
•the assumption of unknown liabilities;
•exposure to potential lawsuits;
•limitations on rights to indemnity from the seller;
•the diversion of management’s and employees’ attention from other business concerns;
•unforeseen difficulties operating in new geographic areas; and
•customer or key employee losses at the acquired businesses.
We may not be able to attract dedications of additional third-party volumes, in part because our industry is highly competitive, which could limit our ability to grow and increase our dependence on Noble. Further, increased competition from other companies that provide midstream services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Part of our long-term growth strategy includes continuing to diversify our customer base by identifying additional opportunities to offer services to third parties in our areas of operation. To date and over the near term, a substantial portion of our revenues have been and will continue to be earned from Noble relating to its operated wells on our dedicated acreage. Our ability to increase throughput on our midstream systems and any related revenue from third parties is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when requested by
third parties. Any lack of available capacity on our systems for third-party volumes will detrimentally affect our ability to compete effectively with third-party systems for crude oil and natural gas from reserves associated with acreage other than our then-current dedicated acreage. In addition, some of our competitors for third-party volumes have greater financial resources and access to larger supplies of crude oil and natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.
Our efforts to attract additional third parties as customers may be adversely affected by our relationship with Noble and the fact that a substantial majority of the capacity of our midstream systems will be necessary to service its production on our dedicated acreage and our desire to provide services pursuant to fee-based agreements. As a result, we may not have the capacity to provide services to additional third parties and/or potential third-party customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, potential third-party customers who are significant producers of crude oil and natural gas may develop their own
midstream systems in lieu of using our systems. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, cash flows and ability to make cash distributions to our unitholders.
Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to retain our existing customers or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
To maintain and grow our business, we will be required to make substantial capital expenditures. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.
In order to maintain and grow our business, we will need to make substantial capital expenditures to fund growth capital expenditures, to purchase or construct new midstream systems, or to fulfill our commitments to service acreage committed to us by our customers. If we do not make sufficient or effective capital expenditures, we will be unable to maintain and grow our business and, as a result, we may be unable to maintain or raise the level of our future cash distributions over the long term. To fund our capital expenditures, we will be required to use cash from our operations, incur debt or sell additional Common Units or other equity securities. Using cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. For example, the significant volatility in energy commodity prices in recent years combined with environmental, social and governance concerns about the oil and gas industry has led to negative investor sentiment and an adverse impact on the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all. Also, due to our relationship with Noble, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairment to the financial condition of Noble or adverse changes in Noble’s credit ratings.Noble. Any material limitation on our ability to access capital as a result of such adverse changes to Noble could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes affecting Noble could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our business activities, or could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
Even if we are successful in obtaining the necessary funds to support our growth plan, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then current distribution rate, which could materially decrease our ability to pay distributions at the then prevailing distribution rate. While we have historically received funding from Noble, none of Noble, our General Partner or any of their respective affiliates is committed to providing any direct or indirect financial support to fund our growth.
The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from making distributions, even during periods in which we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss
for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.
Increased competition from other companies that provide midstream services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete for third-party customers primarily with other crude oil and natural gas gathering systems and fresh and saltwater service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil and natural gas than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third-party customers. In addition, potential third-party customers may develop their own gathering systems instead of using ours. Moreover, Noble and its affiliates are not limited in their ability to compete with us outside of our dedicated area.
Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services.
All of these competitive pressures could make it more difficult for us to retain our existing customers or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
Our construction of new midstream assets may not result in revenue increases and may be subject to regulatory, environmental, political, contractual, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to unitholders.
The construction of additions or modifications to our existing systems and the expansion into new production areas to service Noble or our third-party customer involve numerous regulatory, environmental, political and legal uncertainties beyond our control, may require the expenditure of significant amounts of capital, and we may not be able to construct in certain locations due to setback requirements or expand certain facilities that are deemed to be part of a single source. Regulations clarifying how oil and gas production facility emissions must be aggregated under the CAA permitting program were finalized in June 2016. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs. Moreover, Colorado has its own test for aggregating emission sources, and aggressive application of state preconstruction permitting requirements could result in delays and additional costs for midstream construction projects. Financing may not be available on economically acceptable terms or at all. As we build infrastructure to meet our customers’ needs, we may not be able to complete such projects on schedule, at the budgeted cost or at all.
Our revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. We may construct facilities to capture anticipated future production growth from Noble or another customer in an area where such growth does not materialize. As a result, new midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flows and ability to make cash distributions.
The construction of additions to our existing assets may require us to obtain new permits or approvals, rights-of-way, surface use agreements or other real estate agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way, leases or other agreements, and our fees may only be increased above the annual year-over-year increase by mutual agreement between us and our customer. If the cost of renewing or obtaining new agreements increases, our cash flows could be adversely affected.
We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.
We are subject to regulation by multiple federal, state and local governmental agencies. Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals or proceedings may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry can increase our cost of doing business and affect our profitability.
The rates of our regulated assets are subject to review and reporting by federal regulators, which could adversely affect our revenues.
Our crude oil gathering system servicing the East Pony IDP area transports crude oil in interstate commerce. In addition, the Black Diamond crude oil gathering system, Empire Pipeline crude oil gathering system and Green River crude oil gathering system, completed in 2018, transport crude oil in interstate commerce.
Pipelines that transport crude oil in interstate commerce are, among other things, subject to rate regulation by the FERC, unless such rate requirements are waived. We have received a waiver of the FERC’s tariff requirements for all of these crude oil gathering systems listed above. These temporary waivers are subject to revocation in certain circumstances. We are required to inform the FERC of any change in circumstances upon which the waivers were granted. Should the circumstances change, the FERC could find that transportation on these systems no longer qualify for a waiver. FERC could,revoke the waiver, either at the request of other entities or on its own initiative, assert that some or all of our pipelines no longer qualify for a waiver.initiative. In the event that the FERC were to determine that these crude oil gathering systems no longer qualified for the waiver, we would likely be required to comply with the tariff and reporting requirements, including filing a tariff with the FERC and providing a cost justification for the applicable transportation rates, and providing service to all potential shippers, without undue discrimination. A revocation of the temporary waivers for these pipelines could adversely affect the results of our revenues.
We may be required to respond to requests for information from government agencies, including compliance audits conducted by the FERC.
The FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received on our FERC jurisdictional pipelines that have tariffs on file, including White Cliffs Pipeline, EPIC Y-Grade, EPIC Crude and the gathering systems listed above in the event the temporary waivers do not remain in effect, and any other natural gas or liquids pipeline that is determined to be under the jurisdiction of the FERC. Pipelines may utilize the FERC oil pipeline indexing methodology which, as currently in effect, allows common carriers to change their rates within
prescribed ceiling levels that are tied to changes in the Producer Price Index. The FERC’s establishment of a just and reasonable rate, including the determination of the oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance for income taxes and the amount for accumulated deferred income taxes (“ADIT”). The FERC’s oil pipeline index is reviewed every five years. On March 15, 2018, as clarified on July 18, 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating, among other things, that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service-rates. To the extent a regulated entity is permitted to include an income tax allowance in its cost-of-service, the FERC directed entities to calculate the income tax allowance at the reduced 21% maximum corporate tax rate established by the Tax Cuts and Jobs Act of 2017. Further, should such regulated entity not include an income tax allowance in their cost-of-service rates, such entity may also elect to exclude the ADIT balance from the rate calculation. The impacts of the Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in the FERC’s next five-year review of the oil pipeline index, which will be initiated in 2020 to generate the index level to be effective July 1, 2021. Accordingly,In addition, if any of our waivers are revoked, the FERC’sFERC's Revised Policy Statement on the Treatment of Income Taxes may result in an adverse impact on our revenues associated with the transportation and storage if we are required to set and charge cost-based rates in the future, including indexed rates.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The Pipeline Safety and Job Creation Act, is the most recent federal legislation to amend the NGPSA, and the HLPSA, which are pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creation Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, material strength testing, and verification of the maximum allowable pressure of certain pipelines.
Changes to existing pipeline safety regulations may result in increased operating and compliance costs. For example, in October 2019, PHMSA published three final rules that create or expand reporting, , inspection, maintenance, and other pipeline safety obligations. We are in the process of assessing the impact of these rules on our future costs of operations and revenue from operations.
PHMSA is working on two additional rules related to gas pipeline safety that are expected to modify pipeline repair criteria and extend regulatory safety requirements to certain gathering lines in rural areas. These additional rulemakings are expectedAdditionally, as part of the Consolidated Appropriations Act of 2021, Congress reauthorized PHMSA through 2023 and directed the agency to be effective by mid-2020.move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemakings. Congress has also instructed PHMSA to issue final regulations that will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans
to align with those regulations. The adoption of these or other regulations requiring more comprehensive or stringent safety standards could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, assets or properties, and any inability to do so may disrupt our business and hinder our ability to grow.
We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business, asset or property into our existing operations. The process of integrating acquired businesses, assets and properties may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses, assets and properties into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
Our investments in joint ventures involve numerous risks that may affect the ability of such joint ventures to make distributions to us.
We conduct some of our operations through joint ventures in which we share control with our joint venture participants. Our joint venture participants may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture. Furthermore, our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with such joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations. In addition, should any of these risks materialize, it could have a material adverse effect on the ability of the joint venture to make future distributions to us.
If third-party pipelines or other facilities interconnected to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Our midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.
Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with our customers.
We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows have little direct exposure to commodity price risk. However, our customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels.
Historically, crude oil, natural gas and NGL prices have been volatile and subject to wide fluctuations. For example, the significant decline in crude oil prices during 2020 has largely been attributable to the actions of Saudi Arabia and Russia, which have resulted in a substantial decrease in crude oil and natural gas prices, and the global outbreak of COVID-19, which has reduced demand for crude oil and natural gas because of significantly reduced global and national economic activity. While commodity prices have experienced some increased stability recently, we cannot predict whether or when commodity prices and economic activities will return to normalized levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.
Our contracts are subject to renewal risks.
We are a party to certain long term, fixed fee contracts with terms of various durations. As these contracts expire, we will have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
the level of existing and new competition to provide services to our markets;
the macroeconomic factors affecting our current and potential customers;
the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
the extent to which the customers in our markets are willing to contract on a long-term basis; and
the effects of federal, state or local regulations on the contracting practices of our customers.
Our inability to renew our existing contracts on terms that are favorable or to successfully manage our overall contract mix over time may have a material adverse effect on our business, results of operations and financial condition.
Restrictions in our revolving credit facility and term loan credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
Our revolving credit facility and term loan credit facility limit our ability to, among other things:
•incur or guarantee additional debt;
•redeem or repurchase units or make distributions under certain circumstances;
•make certain investments and acquisitions;
•incur certain liens or permit them to exist;
•enter into certain types of transactions with affiliates;
•merge or consolidate with another company; and
•transfer, sell or otherwise dispose of assets.
Our revolving credit facility and term loan credit facility also contain covenants requiring us to maintain certain financial ratios.
The provisions of our revolving credit facility and term loan credit facility may affect our ability to obtain future financing and to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility and term loan credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources.
Our contracts are subject to renewal risks.
We are a party to certain long term, fixed fee contracts with terms of various durations. As these contracts expire, we will have to negotiate extensions or renewals with existing suppliers and customers or enter into new contracts with other suppliers and customers. We may not be able to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or maintain the overall mix of our contract portfolio. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
•the level of existing and new competition to provide services to our markets;
•the macroeconomic factors affecting our current and potential customers;
•the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
•the extent to which the customers in our markets are willing to contract on a long-term basis; and
•the effects of federal, state or local regulations on the contracting practices of our customers.
Our inability to renew our existing contracts on terms that are favorable or to successfully manage our overall contract mix over time may have a material adverse effect on our business, results of operations and financial condition.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our Common Units.
Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of fresh water, including:
•damage to, loss of availability of and delays in gaining access to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;
•mechanical or structural failures at our or Noble’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions and power grid failures;
•leaks of crude oil, natural gas, NGLs or produced water or losses of crude oil, natural gas, NGLs or produced water as a result of the malfunction of, or other disruptions associated with, equipment or facilities;
•unexpected business interruptions;
•curtailments of operations due to severe seasonal weather;
•riots, strikes, lockouts or other industrial disturbances;
•fires, ruptures and explosions; and
•other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
•injury or loss of life;
•damage to and destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations; and
•repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We do not own in fee some of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Our only interests in the land on which our pipeline and facilities are located are rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of Noble and our other potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
•a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
•a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
•a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
•a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
•business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.
Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Events outside of our control, including a pandemic, epidemic or outbreak of an infectious disease, such as the recent global outbreak of COVID-19, political unrest and economic recessions occurring around the globe, could have a material adverse impact on our financial position, results of operations and cash flows.
The U.S. and other world economies are experiencing recessions due to the global outbreak of COVID-19, which began late in 2019. In March 2020, OPEC and non-OPEC producers failed to agree to production cuts, causing a significant drop in crude oil prices. Subsequently, certain of these producers agreed to long-term production cuts and, most recently, Saudi Arabia announced additional production costs in January 2021. While these production cuts could rebalance the market in the long-term, in the short-term, we do not believe they will be large enough to offset the sharp decrease in demand caused by COVID-19. Additionally, recent acts of protest and civil unrest related to the 2020 presidential election have caused economic and political disruption in the United States. These factors collectively have contributed to unprecedented negative global economic impacts, including a significant drop in hydrocarbon product demand, which may extend into the future.
Recessions would likely extend the time for the current oil markets to absorb excess supplies and rebalance inventory resulting in decreased demand for our midstream services for a number of future quarters. Our profitability will likely be significantly affected by this decreased demand and could lead to material impairments of our long-lived assets, intangible assets and equity method investments. Additionally, these factors could lead to further reductions in our distributions to unitholders or may cause us to fall out of compliance with the covenants in our revolving credit facility and term loans. The global outbreak of COVID-19 and impact of lower commodity prices could lead to disruptions in our supply network, including, among other things, storage and pipeline constraints brought on by overproduction and decreased demand from refiners.
Our future access to capital, as well as that of our partners and contractors, could be limited due to tightening capital markets that could delay or inhibit our capital projects.
The outbreak of COVID-19 could potentially further impact our workforce. The infection of key personnel, or the infection of a significant amount of our workforce, could have a material adverse impact on our business, financial condition and results of operations. Much of our workforce is working remotely until the risks of COVID-19 are reduced. Additionally, in response to reduced development and activity levels stemming from the commodity price environment, a number of our employees were placed on furlough or part-time work programs. A remote workforce combined with workforce reduction programs could introduce risks to achieving business objectives and/or the ability to maintain our controls and procedures. For example, the technology required for the transition to remote work increases our vulnerability to cybersecurity threats, including threats of unauthorized access to sensitive information or to render data or systems unusable, the impact of which may have material adverse effects on our business and operations. See “A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss” above.
The impacts of COVID-19 and the significant drop in commodity prices has had an unprecedented impact on the global economy and our business. We are unable to predict all potential impacts to our business, the severity of such impacts or duration.
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.
We do not conduct hydraulic fracturing operations, but substantially all of Noble’s crude oil and natural gas production on our dedicated acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our fresh water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped into a well at high pressure to crack open previously impenetrable rock to release hydrocarbons.
Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent chemical disclosure or well construction requirements on hydraulic fracturing operations, or otherwise seek to ban some or all of these activities. For example, in Colorado, state ballot and other regulatory initiatives have been proposed from time to time to impose additional restrictions or bans on hydraulic fracturing or other facets of crude oil and natural gas exploration, production or related activities. For example, in November 2018,
In 2019, Colorado voters considered a ballot measure known as Proposition #112 that, if passed, would have significantly limited, or even prevented, the future development of crude oil and natural gas in areas where we perform midstream services by imposing strict setback requirements for operations near occupied structures or environmental sensitive areas. While the proposition was not approved by voters, Colorado’s new governor, Jared Polis, has previously supported enhanced setback requirements. We cannot predict whether any similar ballot initiatives will be proposed in the future or what actions the new Governor may take with respect to the regulation of hydraulic fracturing.
During first quarter 2019,adopted SB 181, was passed by the State Legislature. On April 16, 2019, the Governor signed the bill into law. The legislationwhich makes sweeping changes in Colorado oil and gas law, including, among other matters, requiring the COGCC to prioritize public health and environmental concerns in its decisions, instructing the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and delegating considerable new authority to local governments to regulate surface impacts. In keeping with SB 181, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental resources. Most significantly, these revisions establish more stringent setbacks (2,000 feet, instead of the prior 500-foot) on new oil and gas development and eliminate routine flaring and venting of natural gas at new and existing wells across the state, each subject to only limited exceptions. Some local communities have adopted, additionalor are considering adopting, further restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with SB 181. Additionally, activist groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements.setbacks.
Nevertheless, at this time, we are not aware of any significant changes to Noble’s or other third-party customers’ development plans. However, if additional regulatory measures are adopted, Noble and other third-party customers in Colorado could experience delays and/or curtailment in the permitting or pursuit of their exploration, development, or production activities.
Any new limitations or prohibitions on oil and gas exploration and production activities could result in decreased demand for our midstream services and have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity. At the federal level, several agencies have asserted jurisdiction over certain aspects of the hydraulic fracturing process. For example,process and the EPAcurrent U.S. Administration has moved forward with various regulatoryannounced plans to take certain actions including the issuance of new regulations requiring green completions for hydraulically fractured wells, and emission requirements for certain midstream equipment. Also, in June 2016, the EPA finalized rules which prohibit the discharge of wastewater fromto further regulate or constrain hydraulic fracturing operations to publicly owned wastewater treatment plants.operations. Certain environmental groups have also suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.
We, Noble or any third-party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.
As an owner and operator of gathering systems, we are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection, the imposition of certain restrictions on operations to prevent impacts to protected species, and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. Failure to comply with these laws, regulations and permits may result in joint and several or strict liability or the assessment of
administrative, civil and criminal penalties, the imposition of remedial obligations, or the issuance of injunctions or administrative orders limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations or limit our growth and revenues, which in turn could affect the amount of cash we have available for distribution. We cannot provide any assurance that changes in or additions to public policy regarding the protection of the environment, and worker health and safety, and impacts to hydraulic fracturing, permitting, and GHG emissions, will not have a significant impact on our operations and the amount of cash we have available for distribution. It is possible that our operations and those of our customers may be subject to greater environmental, health, and safety restrictions.
Our operations also pose risks of environmental liability due to leakage, migration, releases or spills to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, the trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, potentially resulting in increased costs of doing business and consequently affecting the amount of cash we have available for distribution. For example, in June 2015, the EPA and the Corps, issued a final rule under the CWA, defining the scope of the EPA’s and the Corps’ jurisdiction over waters of the United States. Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule, also known as the Clean Water Rule. Most recently, in September 2019, the EPA and Corps rescinded the 2015 Clean Water Rule. Legal challenges have occurred for both the 2015 rule and the 2019 rescission. Therefore, the scope of jurisdiction under CWA is uncertain at this time. To the extent a rule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Such potential regulations, or litigation, could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our business, financial condition and results of operations. See Items 1. and 2. Business and Properties – Regulations. Our and our customers’ operations are subject to a series of risks arising out of the threat ofrelated to climate change and associated government action that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.
The threat of climate change continuesClimate change-related issues continue to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and production customers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oil and natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Following the change in presidential administrations, there have been attempts to modify certain of these regulations, and litigation is ongoing.
Additionally, various federal agencies, states, and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of GHG emissions. AtFor more information, see our regulatory disclosure titled Climate Change and Air Quality Standards. Such actions could include limits on emissions and curtailment of the international level, there is a non-binding agreement, the United Nations-sponsored “Paris Agreement,” for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020. The adoption and implementationproduction of new or more stringent legislation or regulations could result in increased costs of compliance or costs of consuming, and thereby reduce demand for, oil and natural gas, which could reduce demand for our services and products.
Concern over the threat of climate change may also result in political action deleterious to our interests. For example, various pledges to curtail oil and gas, operations have been made by candidates runningsuch as through the cessation of leasing public land for hydrocarbon development. For more information, see our regulatory disclosure titled Hydraulic Fracturing. Other actions that could be pursued include more restrictive requirements for the Democratic nomination for Presidentdevelopment of
the United States in 2020. pipeline infrastructure or LNG export facilities. Separately, increased attention to climate change risks has increased the possibility of claims brought by public and private entities against oil and gas companies in connection with their GHG emissions. While courts have generally declined to assign direct liability for climate change to large sources of GHG emissions, new claims for damages and increased government scrutiny, especially from state and local governments, will likely continue. Moreover, to the extent societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.
At the international level, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. Although the United States had previously withdrawn from the Paris Agreement, an executive order was signed on January 20, 2021 recommitting the United States to the agreement. The impacts of this order, and any legislation or regulation that may be adopted as a result, are unclear at this time. However, new or more stringent legislation or regulations could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand for our services and products.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally,There is also a risk that financial institutions will be required to adopt policies that have the lending practiceseffect of institutional lenders have beenreducing the subject of intensive lobbying effortsfunding provided to the fossil fuel sector. A material reduction in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change notcapital available to providethe fossil fuel industry could make it more difficult to secure funding for fossil fuel producers. Limitation of investments inexploration, development, production, transportation, and financings for fossil fuel energy companiesprocessing activities, which could result in the restriction, delay or cancellation of drilling programs or development or production activities.decreased demand for our midstream services. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Finally, it should be noted that many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations or our customers’ exploration and production operations, which in turn could affect demand for our services. In addition, while our consideration of changing weather conditions and inclusion of safety factors in design covers the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality. See Items 1. and 2. Business and Properties – Regulations. Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and Noble’s operations.
The ESA restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect endangered or threatened species. Such protections, and the designation of previously undesignated species under such laws, may affect our and Noble’s operations by imposing additional costs, approvals and accompanying delays. For example, the Bureau of Land Management has deferred the sale of leases on certain lands due to concerns about protections for the greater sage grouse, a species that, while not currently listed, has been the subject of long-term and recently renewed calls for protection under the ESA.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of cash we have available for distribution.
Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. Although the FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our natural gas gathering pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and are therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by the FERC.
Subject to the foregoing, our natural gas gathering pipelines are exempt from the jurisdiction of the FERC under the NGA, but FERC regulation may indirectly impact gathering services. The FERC’s policies and practices across the range of its crude oil and natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate crude oil and natural gas pipelines. However, we cannot assure that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.
Natural gas gathering may receive greater regulatory scrutiny at the state level. Therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
In addition, certain of our crude oil gathering pipelines do not provide interstate services and therefore are not subject to regulation by the FERC pursuant to the ICA. The distinction between FERC-regulated crude oil interstate pipeline transportation, on the one hand, and crude oil intrastate pipeline transportation, on the other hand, also is a fact-based determination. The classification and regulation of these crude oil gathering pipelines are subject to change based on changed circumstances on the pipeline or on future determinations by the FERC, federal courts, Congress or by regulatory commissions, courts or legislatures in the states in which our crude oil gathering pipelines are located. We cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of our gathering pipeline systems and the services we provide on those systems are within the FERC’s jurisdiction. If it is determined that some or all of our crude oil gathering pipeline systems are subject to the FERC’s jurisdiction under the ICA, and are not otherwise exempt from any applicable regulatory requirements, the imposition of possible cost-of-service rates and common carrier requirements on those systems could adversely affect the results of our operations on and revenues associated with those systems.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our Common Units.
Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of fresh water, including:
damage to, loss of availability of and delays in gaining access to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;
mechanical or structural failures at our or Noble’s facilities or at third-party facilities on which our customers’ or our operations are dependent, including electrical shortages, power disruptions and power grid failures;
leaks of crude oil, natural gas, NGLs or produced water or losses of crude oil, natural gas, NGLs or produced water as a result of the malfunction of, or other disruptions associated with, equipment or facilities;
unexpected business interruptions;
curtailments of operations due to severe seasonal weather;
riots, strikes, lockouts or other industrial disturbances;
fires, ruptures and explosions; and
other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
injury or loss of life;
damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
regulatory investigations and penalties;
suspension of our operations; and
repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
Our asset inspection, maintenance or repair costs may increase in the future. In addition, there could be service interruptions due to unforeseen events or conditions or increased downtime associated with our pipelines that could have a material adverse effect on our business and results of operations.
Gathering systems, pipelines and facilities are generally long-lived assets, and construction and coating techniques have varied over time. Depending on the condition and results of inspections, some assets will require additional maintenance, which could
result in increased expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.
It is difficult to predict future maintenance capital expenditures related to inspections and repairs. Additionally, there could be service interruptions associated with these maintenance capital expenditures or other unforeseen events. Similarly, laws and regulations may change which could also lead to increased maintenance capital expenditures. Any increase in these expenditures could adversely affect our results of operations, financial position, or cash flows which in turn could impact our ability to make cash distributions to our unitholders.
We do not own in fee some of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Our only interests in these properties are rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
A shortage of equipment and skilled labor could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.
Our gathering and other midstream services require special equipment and laborers who are skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.
The loss of key personnel could adversely affect our ability to operate.
We depend on the services of a relatively small group of our General Partner’s senior management. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our General Partner’s senior management, including Brent J. Smolik,Robin H. Fielder, our Chief Executive Officer, Thomas W. Christensen, our Chief Financial Officer, Robin H. Fielder,John S. Reuwer, our Chief Operating Officer, Phillip S. Welborn, our Chief Accounting Officer,Vice President of Business and Corporate Development, and Aaron G. Carlson, our General Counsel and Secretary, could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions.
We do not have any officers or employees and rely on officers of our General Partner and employees of Noble.Chevron.
We are managed and operated by the board of directors and executive officers of our General Partner. Our General Partner has no employees and relies on the employees of NobleChevron to conduct our business and activities.
NobleChevron conducts businesses and activities of its own in which we have no economic interest. As a result, there could be material competition for the time and effort of the officers and employees who provide services to both our General Partner and Noble.Chevron. If our General Partner and the officers and employees of NobleChevron do not devote sufficient attention to the management and operation of our business and activities, our business, financial condition, results of operations, cash flows and ability to make cash distributions could be materially adversely affected.
Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.
Our future level of debt could have important consequences to us, including the following:
•our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;
•our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
•we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
•our flexibility in responding to changing business and economic conditions may be limited.
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are
beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.
Increases in interest rates could adversely affect our business.
We have exposure to increases in interest rates. As of December 31, 2019, $5952020, $710 million and $900 million were outstanding under our revolving credit facility and term loan credit facility, respectively. A 1.0% increase in our interest rates would have resulted in an estimated $9.5$16.7 million increase in interest expense for the year ended December 31, 2019.2020. As a result, our results of operations, cash flows and financial condition and, as a further result, our ability to make cash distributions to our unitholders, could be adversely affected by significant increases in interest rates.
Terrorist attacks or cyber-attacks could have a material adverse effect on our business, financial condition or results of operations.
Terrorist attacks or cyber-attacks may significantly affect the energy industry, including our operations and those of Noble and our other potential customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business partners. Our business partners, including vendors, service providers, and financial institutions, are also dependent on digital technology. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
a cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;
a cyber attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
a cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.
Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources
to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
Risks Inherent in an Investment in Us
There can be no assurances that we will enter into a definitive agreement with Chevron related to Chevron’s proposal to acquire all of our Common Units that it does not already own, or that we will complete any transaction contemplated by such an agreement.
On February 4, 2021, the board of directors of our General Partner received a non-binding proposal (the “Proposal”) from Chevron Corporation, pursuant to which Chevron would acquire all our Common Units that Chevron and its affiliates do not already own. While the Conflicts Committee has been engaged by our General Partner to evaluate the Proposal and any potential transaction with Chevron related to the Proposal (the “Potential Transaction”), there can be no assurances that we will enter into a definitive agreement with Chevron related to any Potential Transaction. Furthermore, should we enter into a definitive agreement with Chevron, we anticipate that the consummation of any Potential Transaction will be subject to a number of conditions, and there can be no assurances that such conditions will be satisfied or waived or that any Potential Transaction will be completed in a timely manner or at all.
Our General Partner and its affiliates including Noble, have conflicts of interest with us and our partnership agreement eliminates their default fiduciary duties to us and our unitholders and replaces them with contractual standards that may allow our General Partner and its affiliates to favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over the business decisions and operations of Noble,Chevron, and NobleChevron is under no obligation to adopt a business strategy that favors us.
Noble directlyChevron indirectly owns an aggregate 62.6% limited partner interest in us. In addition, NobleChevron, indirectly, owns and controls our General Partner. Although our General Partner has a duty to manage us in a manner that is not adverse to the interests of our partnership, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is in the best interests of its owner, Noble.owner. Conflicts of interest may arise between NobleChevron and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the General Partner may favor its own interests and the interests of its affiliates, including Noble,Chevron, over the interests of our common unitholders. These conflicts include, among others, the following situations:
•neither our partnership agreement nor any other agreement requires NobleChevron to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by NobleChevron to increase or decrease crude oil or natural gas production on our dedicated acreage, pursue and grow particular markets or undertake acquisition opportunities for itself. Noble’sChevron’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of Noble;Chevron;
Noble•Chevron may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
•our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties and limits our General Partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;
•except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;
•our General Partner will determine the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash
reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;
•our General Partner will determine which costs incurred by it are reimbursable by us;
•our General Partner may cause us to borrow funds in order to permit the payment of cash distributions;
•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 it and its affiliates own more than 80% of the Common Units;
•our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including our gathering agreements with Noble, the ROFR and ROFO; and
•our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
Neither our partnership agreement nor our omnibus agreement will prohibit NobleChevron or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our General Partner or any of its affiliates, including NobleChevron and executive officers and directors of our General Partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, NobleChevron and other affiliates of our General Partner may acquire, construct or
dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets (except to the extent the ROFR or ROFO pertain to such assets). As a result, competition from NobleChevron and other affiliates of our General Partner could materially and adversely impact our results of operations and distributable cash flow. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.
We expect to distribute a substantial portion of our cash available for distribution, which could limit our ability to grow and make acquisitions.
We expect to distribute most of our available cash for distribution. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, our growth may not be as fast as that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional partnership interests in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional partnership interests may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional partnership interests, including partnership interests ranking senior to our Common Units as to distributions or in liquidation or that have special voting rights and other rights, and our common unitholders will have no preemptive or other rights (solely as a result of their status as common unitholders) to purchase any such additional partnership interests. The incurrence of additional commercial bank borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash that we have available to distribute to our unitholders.
Our partnership agreement replaces our General Partner’s fiduciary duties to holders of our Common Units with contractual standards governing its duties.
Delaware law provides that a Delaware limited partnership may, in its partnership agreement, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership. As permitted by Delaware law, our partnership agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner, free of any duties to us and our unitholders. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder agrees to be bound by our partnership agreement and approves the elimination and replacement of fiduciary duties disclosed above.
Our partnership agreement restricts the remedies available to holders of our units and for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
•whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner 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 determination or the decision to take or decline to take such action was not adverse to the interests of our partnership, and 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 it acted in good faith;
•our General Partner and its officers and directors will not be liable for monetary damages or otherwise 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 our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our General Partner is permitted to act in its sole discretion, our partnership agreement provides that any determination by our
General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee, then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our General Partner acted in good faith and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our Common Units.
Unitholders’ voting rights are restricted by a provision of our partnership agreement providing that any person or group that owns 20% or more of any class of our units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner cannot vote on any matter.
Cost reimbursements and fees due to our General Partner and its affiliates for services provided will be substantial and will reduce the amount of cash we have available for distribution to unitholders.
Under our partnership agreement, we are required to reimburse our General Partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services and secondment agreement, our General Partner determines the amount of these expenses. Under the terms of the omnibus agreement, we will be required to reimburse NobleChevron for the provision of certain administrative support services to us. Under our operational services and secondment agreement, we will be required to reimburse NobleChevron for the provision of certain operation services and related management services in support of our operations. Our General Partner and its affiliates also may provide us other services for which we will be charged fees as determined by our General Partner. The costs and expenses for which we will reimburse our General Partner and its affiliates may include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. The costs and expenses for which we are required to reimburse our General Partner and its affiliates are not subject to any caps or other limits. Payments to our General Partner and its affiliates will be substantial and will reduce the amount of cash we have available to distribute to unitholders.
Unitholders have very limited voting rights and, even if they are dissatisfied, they cannot remove our General Partner.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our General Partner or the board of directors of our General Partner and will have no right to elect our General Partner or the board of directors of our General Partner on an annual or other continuing basis. The board of directors of our General Partner is chosen by its sole member, which is owned by Noble. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our Common Units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our General Partner may not be removed unless such removal is both (i) for cause and (ii) approved by a vote of the holders of at least 66 2⁄3% of the outstanding units, including any units owned by our General Partner and its affiliates, voting together as a single class. “Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our General Partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our General Partner. Noble currentlyChevron indirectly owns 62.6% of our total outstanding Common Units. As a result, our public unitholders do not have limited ability to remove our General Partner.
Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our General Partner cannot vote on any matter.
Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
Our partnership agreement restricts the voting rights of certain unitholders owning 20% or more of our Common Units.
Unitholders’ voting rights are restricted by a provision of our partnership agreement providing that any person or group that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.
Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.
Our General Partner may transfer its General Partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of NobleChevron to transfer its membership interest in our General Partner to a third party. The new owner of
our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own choices.
We may issue an unlimited number of additional partnership interests without unitholder approval, which would dilute unitholder interests.
At any time, we may issue an unlimited number of General Partner interests or limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such General Partner interests or limited partner interests. Further, there are no limitations in our partnership agreement on our ability to issue equity securities that rank equal or senior to our common unitsCommon Units as to distributions or in liquidation or that have special voting rights and other rights. The issuance by us of additional Common Units or other equity securities of equal or senior rank will have the following effects:
•our unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash we have available to distribute on each unit may decrease;
•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 our Common Units may decline.
The issuance by us of additional General Partner interests may have the following effects, among others, if such General Partner interests are issued to a person who is not an affiliate of Noble:Chevron:
•management of our business may no longer reside solely with our current General Partner; and
•affiliates of the newly admitted General Partner may compete with us, and neither that General Partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first refusal contained in our omnibus agreement.
NobleOur General Partner has a call right that may require our unitholders to sell their Common Units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our then-outstanding Common Units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the Common Units held by unaffiliated persons at a price not less than their then current market price. As a result, our unitholders may be required to sell their Common Units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our General Partner and its affiliates currently own approximately 62.6% of our Common Units (excluding any Common Units owned by the directors and executive officers of our General Partner and certain other individuals as selected by our General Partner under our directed unit program).
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a
period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Chevron may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the Common Units.
Noble currently holdsChevron indirectly owns 56,447,616 Common Units. Additionally, we have agreed to provide Noble with registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the Common Units or on any trading market that may develop.
Our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our partnership agreement permits the General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business (including reserves for future capital expenditures and for our anticipated future credit needs) to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.
Affiliates of our General Partner, including Noble, may compete with us, and neither our General Partner nor its affiliates have any obligation to present business opportunities to us except with respect to dedications contained in our commercial agreements and rights of first refusal and rights of first offer contained in our omnibus agreement.
None of our partnership agreement, our omnibus agreement, our commercial agreements or any other agreement in effect will prohibit Noble or any other affiliates of our General Partner from owning assets or engaging in businesses that compete directly or indirectly with us. Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our General Partner or any of its affiliates, including Noble and executive officers and directors of our General Partner. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us except with respect to dedications contained in our commercial agreements and rights of first refusal and rights of first offer contained in our omnibus agreement. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Consequently, Noble and other affiliates of our General Partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from Noble and other affiliates of our General Partner could materially and adversely impact our results of operations and distributable cash flow.
Our General Partner has a call right that may require our unitholders to sell their Common Units at an undesirable time or price.
If at any time our General Partner and its affiliates own more than 80% of our then-outstanding common units, our General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the Common Units held by unaffiliated persons at a price not less than their then current market price. As a result, our unitholders may be required to sell their Common Units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their units. Our General Partner and its affiliates currently own approximately 62.6% of our Common Units (excluding any Common Units owned by the directors and executive officers of our General Partner and certain other individuals as selected by our General Partner under our directed unit program).
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Units held by persons who our General Partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption.
As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our Common Units to certify that they are both U.S. citizens and subject to U.S. federal income taxation on our income. Units held by persons who our General Partner determines are not “eligible holders” at the time of any requested certification in the future may be subject to redemption. “Eligible holders” are limited partners whose (or whose owners’) (i) U.S. federal income tax status or lack of proof of U.S. federal income tax status does not have and is not reasonably likely to have, as determined by our General Partner, a material adverse effect on the rates that can be charged to customers by us or our subsidiaries with respect to assets that are subject to regulation by the FERC or similar regulatory body and (ii) nationality, citizenship or other related status does not create and is not reasonably likely to create, as determined by our General Partner, a substantial risk of cancellation or forfeiture of any property in which we have an interest. The aggregate redemption price for redeemable interests will be an amount equal to the current market price (the date of determination of which will be the date fixed for redemption) of limited partner interests of the class to be so redeemed multiplied by the number of limited partner interests of each such class included among the redeemable interests. For these purposes, the “current market price” means, as of any date for any class of limited partner interests, the average of the daily closing prices per limited partner interest of such class for the 20 consecutive trading days immediately prior to such date. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner. The units held by any person the General Partner determines is not an eligible holder will not be entitled to voting rights.
Our partnership agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’sGeneral Partner’s directors, officers or other employees. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.
Our partnership agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to our partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our partnership agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (ii) brought in a derivative manner on our behalf, (iii) asserting a claim of breach of a duty owed by any of our, or our general partner’s,General Partner’s, directors, officers, or other employees, or owed by our general partner,General Partner, to us or our partners, (iv) asserting a claim against us arising pursuant to any provision of the Delaware Act or (v) asserting a claim against us governed by the internal affairs doctrine.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore,
Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our partnership agreement to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws. This exclusive forum provision may limit the ability of a limited partner to commence litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our general partner’sGeneral Partner’s directors or officers. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition.
If any person brings any of the aforementioned claims, suits, actions or proceedings (including any claims, suits, actions or proceedings arising out of this offering) and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. In addition, our partnership agreement provides that each limited partner irrevocably waives the right to trial by jury in any such claim, suit, action or proceeding. However, such waiver of the right to trial by jury does not impact the ability of a limited partner to make a claim under either federal or state law. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other court) in connection with any such claims, suits, actions or proceedings. These provisions may have the effect of discouraging lawsuits against us and our general partner’sGeneral Partner’s directors and officers.
Our partnership agreement provides that unitholders irrevocably waive the right to trial by jury in any claim, suit, action or proceeding under either state or federal laws, including any claim under U.S. federal securities laws, which could result in less favorable outcomes to unitholders in any such action.
Our partnership agreement provides that unitholders irrevocably waive the right to trial by jury for any claims, suits, actions or proceedings under either state or federal laws, including any claim under U.S. federal securities laws. Regardless, such waiver of the right to trial by jury does not impact the ability of a unitholder to make a claim under either federal or state law. The waiver of the right to a jury trial is not intended to be deemed a waiver by a unitholder with respect to the Partnership’s compliance with U.S. federal securities laws and the rules and regulations promulgated thereunder. If the Partnership or one of its unitholders opposed a jury trial demand based on the waiver, the applicable court would determine whether the waiver was enforceable based on the facts and circumstances of that case in accordance with applicable state and federal laws. To our knowledge, the enforceability of a contractual pre-dispute jury trial waiver in connection with claims arising under the U.S. federal securities laws has not been finally adjudicated by the United States Supreme Court. However, we believe that a contractual pre-dispute jury trial waiver provision is generally enforceable, including under the laws of the State of Delaware, which govern our partnership agreement.
If a unitholder brings a claim in connection with matters arising under our partnership agreement, including claims under U.S. federal securities laws, such unitholder may not be entitled to a jury trial with respect to such claims, which may have the effect of limiting and discouraging lawsuits. If a lawsuit is brought by a unitholder under our partnership agreement, it may be heard only by a judge or justice of the applicable trial court, which would be conducted according to different civil procedures and may result in a different outcome than a trial by jury, including results that could be less favorable to the unitholder(s) bringing such lawsuit.
Nasdaq does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our Common Units are listed on Nasdaq. Because we are a publicly traded limited partnership, Nasdaq does not require us to have a majority of independent directors on our General Partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional Common Units or other securities, including to affiliates, will not be subject to Nasdaq’s shareholder approval rules that apply to a corporation. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of Nasdaq’s corporate governance requirements.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our Common Units and could have a material adverse effect on our business.
If a sufficient amount of our assets, such as our ownership interests in other midstream ventures, now owned or in the future acquired, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, or the Investment Company Act, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. In that event, it is possible that our ownership of these interests, combined with our assets acquired in the future, could result in our being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying our organizational structure or applicable contract rights. Treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes in which case we would be treated as a corporation for federal income tax purposes. As a result, we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our Common Units.
Moreover, registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase of additional interests in our midstream systems from Noble, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our Common Units and could have a material adverse effect on our business.
Tax Risks
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in the Common Units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates.rate. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits),distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our Common Units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of a material amount of any of these taxes in the jurisdictions in which we own assets or conduct business could substantially reduce the cash available for distribution to our unitholders.
If we were treated as a corporation for U.S. federal income tax purposes or otherwise subjected
The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretationchanges or differing interpretations at any time. From time to time, membersMembers of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination ofproposals that would eliminate our ability to qualify for partnership tax treatment for certain publicly traded partnerships.treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws and interpretations thereof may or may not
be retroactively applied and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our Common Units.
You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our Common Units.
Our unitholders’ share of our income is taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
If the IRS contests the U.S. federal income tax positions we take, the market for our Common Units may be adversely impacted and our cash available to our unitholders might be substantially reduced.
The IRS may adopt positions that differ from the conclusions of our counsel expressed in this Annual Report or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained.take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS and the outcome of any IRS contest, may materially and adversely impact on the market for our Common Units and the price at which they trade. In addition, our costs of any contest between us and the IRS will be borne indirectly by our unitholders because the costs will reduce our distributable cash flow.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Legislation applicable to partnership tax years beginning after 2017 alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit. If the IRS makes an audit adjustment to our partnership tax return, to the extent possible under the new rules our General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS in the year in which the audit is completed or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted partnership tax return. Although our General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. If, as a result of any such adjustment, we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if the current unitholders did not own Common Units in us during the tax year under audit.
Our unitholders’ shareTax-exempt entities face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.
Investment in Common Units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), raises issues unique to them. For example, virtually all of our income is taxableallocated to them fororganizations that are exempt from U.S. federal income tax, purposes even if they do not receive any cash distributions from us.
Each unitholder is treated as a partner to whom weincluding IRAs and other retirement plans, will allocatebe unrelated business taxable income even if the unitholder does not receive any cash distributions from us. Unitholders are requiredand will be taxable to pay federal income taxes and,them. Tax exempt entities should consult a tax advisor before investing in some cases, state and local income taxes, on their shareour Common Units.
Tax gain or loss on the disposition of our Common Units could be more or less than expected.
If our unitholders sell Common Units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those Common Units. Because distributions in excess of theirunitholders’ allocable share of our net taxable income decrease theirunitholders’ tax basis in their Common Units, the amount, if any, of such prior excess distributions with respect to the Common Units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such Common Units at a price greater than its tax basis in those Common Units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells its units,Common Units, a unitholder may incur a tax liability in excess of the amount of cash received from the sale.
Furthermore, a substantial portion of the amount realized on any sale of Common Units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of Common Units if the amount realized on a sale of the Common Units is less than the unitholder’s adjusted basis in Common Units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities,taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that sells Common Units may incur a tax liability in excessgenerally cannot be offset by any capital loss recognized upon the sale of the amount of cash received from the sale.
units.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or
business during our taxable year. However, subject to certain exemptions in the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act” discussed below), under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Tax-exempt entities face unique tax issues from owningFor our Common Units that2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase. For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in adverse tax consequences to them.
Investment in Common Units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), raises issues unique to them. For example, virtually alla greater business interest expense deduction. In addition, unitholders may treat 50% of our incomeany excess business interest allocated to organizations that are exempt from U.S. federal income tax, including IRAsthem in 2019 as deductible in the 2020 taxable year without regard to the 2020 business interest expense limitations. The remaining 50% of such unitholder’s excess business interest is carried forward and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregationsame limitations as other taxable years.
If our “business interest” is subject to limitation under these rules, for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business cannot aggregate losses from one unrelated trade or businessour unitholders will be limited in their ability to offset income from anotherdeduct their share of any interest expense that has been allocated to reduce total unrelated business taxable income.them. As a result, for the years beginning after December 31, 2017, itunitholders may not be possible for tax-exempt entitiessubject to utilize losses from an investment in uslimitation on their ability to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax exempt entities should consult a tax advisor before investing in our Common Units.deduct interest expense incurred by us.
Non-U.S. unitholders will be subject to U.S. federal income taxes and withholding with respect to their income and gain from owning our Common Units.
Non-U.S. unitholders are generally taxed and subject to U.S. federal income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and under recently enacted legislation, any gain from the sale of our Common Units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate, and a non-U.S. unitholder who sells or otherwise disposes of a common unitCommon Unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that Common Unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized“amount realized” by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold fromperson. While the transferee amounts that should have been withheld bydetermination of the transferees but were not withheld. Because thepartner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, 10%recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our Common Units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the amount realized could exceed the total cash purchase price for the units. However, pending the issuancetransferor, and thus will be determined without regard to any decrease in that partner’s share of final regulations, the IRS has suspended the application of this withholding rule to transfers ofa publicly traded interestspartnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respectpartnership will not be imposed on a transfer that occurs prior to transfers of publicly traded interests in publicly traded partnershipsJanuary 1, 2022, and after that date, if effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s sharebroker.
We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Because we cannot match transferors and transferees of Common Units and because of other reasons, our depreciation and amortization positions may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of Common Units and could have a negative impact on the value of our Common Units or result in tax return audit adjustments.
We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each
month, instead of on the basis of the date a particular unitCommon Unit is transferred. Although Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention, to allocate tax items among transferor and transferee unitholders, these Treasury Regulationsbut such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose Common Units are loanedthe subject of a securities loan (e.g., a loan to a “short seller” to effectcover a short sale of Common UnitsUnits) may be considered as havingto have disposed of those Common Units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those Common Units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose Common Units are loaned tothe subject of a “short seller” to effect a short sale of Common Unitssecurities loan may be considered as havingto have disposed of the loaned Common Units, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those Common Units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those Common Units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Common Units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their Common Units.
As a result of investing in our Common Units, our unitholders may becomewill likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to U.S. federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
Item 1B. Unresolved Staff Comments
None.
Item 3. Legal Proceedings
We may become involved in various legal proceedings in the ordinary course of business. These proceedings would be subject to the uncertainties inherent in any litigation, and we will regularly assess the need for accounting recognition or disclosure of these contingencies. We will defend ourselves vigorously in all such matters.
Item 4. Mine Safety Disclosures
Not Applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
On December 16, 2019, acting pursuant to authorization from the Board of our General Partner, we provided notice to the New York Stock Exchange (“NYSE”) of our intent to voluntarily withdraw the principal listing of our Common Units representing limited partner interests, from the NYSE and transfer the listing to Nasdaq. Our Common Units were voluntarily delisted effective as of the close of trading on December 27, 2019, and trading commenced on Nasdaq at market open on December 30, 2019. Our Common Units continue to trade under the symbol “NBLX”.
on the Nasdaq. As of December 31, 2019,2020, our units were held by 193 holders of record. The number of holders does not include the holders for whom units are held in a “nominee” or “street” name. In addition, as of December 31, 2019, Noble owned2020, Chevron indirectly owns 56,447,616 of our Common Units, which represent a 62.6% limited partner interest in us.
Securities Authorized for Issuance Under Equity Compensation Plans
In 2016, the board of directors of our General Partner adopted the Noble Midstream Partners LP 2016 Long-Term Incentive Plan (the “LTIP”), which permits the issuance of up to 1,860,000 Common Units. See Item 8. Financial Statements and Supplementary Data – Note 11. Unit-Based Compensation for information regarding our equity compensation plan as of December 31, 2019.2020. The following table summarizes information regarding the number of Common Units that are available for issuance under our LTIP as of December 31, 2019.2020 included: |
| | | | | | | | | | |
Plan Category | Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) |
(a) | (b) | (c) |
Equity Compensation Plans Approved by Security Holders | — |
| — |
| 1,630,6381,484,907 |
|
Equity Compensation Plans Not Approved by Security Holders | — |
| — |
| — |
|
Total | — |
| — |
| 1,630,6381,484,907 |
|
Distributions of Available Cash
General
Our partnership agreement requires that, within 45 days after the end of each quarter we distribute all of our available cash to unitholders of record on the applicable record date. On January 23, 2020,22, 2021, the Board of our General Partner declared a quarterly cash distribution of $0.6878$0.1875 per limited partner unit. The distribution will be paid on February 14, 2020,12, 2021, to unitholders of record on February 4, 2020.5, 2021.
Definition of Available Cash
Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
| |
• | •less, the amount of cash reserves established by our General Partner to: •, the amount of cash reserves established by our General Partner to: |
provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and for anticipated future credit needs);
•comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or
•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 pursuant to this bullet point if the effect of such reserves will prevent us from distributing $0.375);
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• | •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. |
The purpose and effect of the last bullet point above is to allow our General Partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings incurred under a credit facility, commercial paper facility or similar financing arrangement that are used solely for working capital purposes or to pay distributions to our partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.
General Partner Interest
Our General Partner owns a non-economic General Partner interest in us, which does not entitle it to receive cash distributions. However, our General Partner may in the future own Common Units or other equity securities in us that will entitle it to receive distributions.
Simplification of Incentive Distribution Rights
Conversion of Subordinated Units
On April 25, 2019, the Board of our General Partner declared a quarterly cash distribution of $0.6132 per unit See Item 8. Financial Statements and Supplementary Data – Note 12. Partnership Distributionsfor the quarter ended March 31, 2019. The distribution was paid on May 13, 2019 to unitholders of record as of the close of business on May 6, 2019. Upon payment of such distribution, the requirements for the conversion of all Subordinated Units were satisfied under our partnership agreement. As a result, on May 14, 2019, all 15,902,584 Subordinated Units, which were owned entirely by Noble, converted into Common Units on a one-for-one basis and thereafter have or will continue to participate on terms equal with all other Common Units in distributions from available cash..
Item 6. Selected Financial Data
Selected Financial Data for periods prior to September 20, 2016 represent the Contributed Businesses of certain of Noble’s midstream assets as the accounting Predecessor to the Partnership, presented on a carve-out basis of Noble’s historical ownership of the Predecessor. The Predecessor financial data has been prepared from the separate records maintained by Noble and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. OurNoble. Beginning with 2019, our consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of NBL Holdings, as the acquisition of NBL Holdings by the Partnership in the Drop-Down and Simplification Transaction represented a transaction between entities under common control. The selected financial data covering the periods prior to the aforementioned transactions may not necessarily be indicative of the actual results of operations had these entities been operated together during those periods.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in thousands, except as noted) | 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
Statements of Operations | | | | | | | | | |
Total Revenues | $ | 764,625 | | | $ | 703,801 | | | $ | 558,735 | | | $ | 289,622 | | | $ | 193,453 | |
Net Income | 94,866 | | | 245,467 | | | 216,719 | | | 160,767 | | | 96,290 | |
Net Income Attributable to Noble Midstream Partners LP | 134,031 | | | 159,996 | | | 162,734 | | | 140,572 | | | 28,458 | |
| | | | | | | | | |
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic | | | | | | | | | |
Common Units | $ | 1.49 | | | $ | 3.09 | | | $ | 3.96 | | | $ | 4.10 | | | $ | 0.89 | |
Subordinated Units | — | | | 3.86 | | | 3.96 | | | 4.10 | | | 0.89 | |
Cash Distributions Declared per Limited Partner Unit | 0.7500 | | | 2.6144 | | | 2.1913 | | | 1.8113 | | | 0.4333 | |
| | | | | | | | | |
Balance Sheet | | | | | | | | | |
Cash and Cash Equivalents | $ | 16,332 | | | $ | 12,676 | | | $ | 14,761 | | | $ | 20,090 | | | $ | 57,443 | |
Total Property, Plant and Equipment, Net | 1,759,349 | | | 1,762,957 | | | 1,570,923 | | | 821,962 | | | 380,310 | |
Investments | 904,955 | | | 660,778 | | | 82,317 | | | 80,461 | | | 11,151 | |
Intangible Assets, Net | 245,510 | | | 277,900 | | | 310,202 | | | — | | | — | |
Goodwill | — | | | 109,734 | | | 109,734 | | | — | | | — | |
Total Assets | 3,037,196 | | | 2,926,082 | | | 2,192,178 | | | 1,038,465 | | | 537,430 | |
Long-Term Debt | 1,109,652 | | | 1,495,679 | | | 559,021 | | | 85,000 | | | — | |
Total Liabilities | 1,736,845 | | | 1,665,221 | | | 705,623 | | | 251,806 | | | 50,368 | |
Mezzanine Equity | 119,658 | | | 106,005 | | | — | | | — | | | — | |
Total Equity | 1,180,693 | | | 1,154,856 | | | 1,486,555 | | | 786,659 | | | 487,062 | |
| | | | | | | | | |
Throughput and Crude Oil Sales Volumes | | | | | | | | | |
Crude Oil Sales Volumes (Bbl/d) | 16,964 | | | 9,354 | | | 6,129 | | | — | | | — | |
Crude Oil Gathering Volumes (Bbl/d) | 228,991 | | | 231,963 | | | 177,127 | | | 69,249 | | | 45,236 | |
Natural Gas Gathering Volumes (MMBtu/d) | 669,826 | | | 631,760 | | | 387,804 | | | 244,940 | | | 180,262 | |
Total Barrels of Oil Equivalent (Boe/d) | 314,866 | | | 322,312 | | | 232,974 | | | 100,652 | | | 68,347 | |
Natural Gas Processing Volumes (MMBtu/d) | 41,511 | | | 50,039 | | | 61,766 | | | 49,531 | | | 42,269 | |
Produced Water Gathering Volumes (Bbl/d) | 173,639 | | | 188,515 | | | 121,215 | | | 37,365 | | | 10,592 | |
Fresh Water Services Volumes (Bbl/d) | 91,886 | | | 164,524 | | | 175,754 | | | 155,990 | | | 94,227 | |
|
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
(in thousands, except as noted) | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Statements of Operations | | | | | | | | | |
Total Revenues | $ | 703,801 |
| | $ | 558,735 |
| | $ | 289,622 |
| | $ | 193,453 |
| | $ | 117,878 |
|
Net Income | 245,467 |
| | 216,719 |
| | 160,767 |
| | 96,290 |
| | (88,344 | ) |
Net Income Attributable to Noble Midstream Partners LP | 159,996 |
| | 162,734 |
| | 140,572 |
| | 28,458 |
| | N/A |
|
| | | | | | | | | |
Net Income Attributable to Limited Partners Per Limited Partner Unit — Basic | | | | | | | | | |
Common Units | $ | 3.09 |
| | $ | 3.96 |
| | $ | 4.10 |
| | $ | 0.89 |
| | N/A |
|
Subordinated Units | 3.86 |
| | 3.96 |
| | 4.10 |
| | 0.89 |
| | N/A |
|
Cash Distributions Declared per Limited Partner Unit | 2.6144 |
| | 2.1913 |
| | 1.8113 |
| | 0.4333 |
| | N/A |
|
| | | | | | | | | |
Balance Sheet | | | | | | | | | |
Cash and Cash Equivalents | $ | 12,676 |
| | $ | 14,761 |
| | $ | 20,090 |
| | $ | 57,443 |
| | $ | 30,299 |
|
Total Property, Plant and Equipment, Net | 1,762,957 |
| | 1,570,923 |
| | 821,962 |
| | 380,310 |
| | 352,764 |
|
Investments | 660,778 |
| | 82,317 |
| | 80,461 |
| | 11,151 |
| | 12,279 |
|
Intangible Assets, Net | 277,900 |
| | 310,202 |
| | — |
| | — |
| | — |
|
Goodwill | 109,734 |
| | 109,734 |
| | — |
| | — |
| | — |
|
Total Assets | 2,926,082 |
| | 2,192,178 |
| | 1,038,465 |
| | 537,430 |
| | 481,853 |
|
Long-Term Debt | 1,495,679 |
| | 559,021 |
| | 85,000 |
| | — |
| | — |
|
Total Liabilities | 1,665,221 |
| | 705,623 |
| | 251,806 |
| | 50,368 |
| | 61,674 |
|
Mezzanine Equity | 106,005 |
| | — |
| | — |
| | — |
| | — |
|
Total Equity | 1,154,856 |
| | 1,486,555 |
| | 786,659 |
| | 487,062 |
| | 420,179 |
|
| | | | | | | | | |
Throughput and Crude Oil Sales Volumes | | | | | | | | | |
Crude Oil Sales Volumes (Bbl/d) | 9,354 |
| | 6,129 |
| | — |
| | — |
| | — |
|
Crude Oil Gathering Volumes (Bbl/d) | 231,963 |
| | 177,127 |
| | 69,249 |
| | 45,236 |
| | 33,977 |
|
Natural Gas Gathering Volumes (MMBtu/d) | 631,760 |
| | 387,804 |
| | 244,940 |
| | 180,262 |
| | 100,298 |
|
Total Barrels of Oil Equivalent (Boe/d) | 322,312 |
| | 232,974 |
| | 100,652 |
| | 68,347 |
| | 46,836 |
|
Natural Gas Processing Volumes (MMBtu/d) | 50,039 |
| | 61,766 |
| | 49,531 |
| | 42,269 |
| | 11,735 |
|
Produced Water Gathering Volumes (Bbl/d) | 188,515 |
| | 121,215 |
| | 37,365 |
| | 10,592 |
| | 5,198 |
|
Fresh Water Services Volumes (Bbl/d) | 164,524 |
| | 175,754 |
| | 155,990 |
| | 94,227 |
| | 51,980 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion should be read in conjunction with the consolidated financial statements and accompanying notes included in Part II, Item 8 of this Annual Report. This section of this Annual Report generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to provide a narrative about our business from the perspective of our management. Our MD&A is presented in the following major sections:
MD&A is the Partnership’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Partnership’s plans, strategies, objectives, expectations and intentions. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target,” “on schedule,” “strategy,” and similar expressions identify forward-looking statements. The Partnership does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readersreaders are cautioned that such forward-looking statements should be read in conjunction with the Partnership’s disclosures under “Disclosure Regarding Forward-Looking Statements” in this Form 10-K.
EXECUTIVE OVERVIEW AND OPERATING OUTLOOK
OverviewImpact of COVID-19 and Declining Commodity Prices
Our business was highly impacted by the COVID-19 pandemic and the decline in commodity prices.
COVID-19 Ongoing containment measures and responsive actions to the COVID-19 pandemic continue to contribute to severe declines in general economic activity and energy demand. As a result, the global economy has experienced a slowing of economic growth, disruption of global manufacturing supply chains, stagnation of crude oil and natural gas consumption and interference with workforce continuity.
The virus continues to impact the global demand for commodities, a trend we expect to continue into 2021. Additionally, the risks associated with COVID-19 have impacted our workforce and the way we meet our business objectives. In response to this, we executed the following actions:
•Remote workforce – Due to concerns over health and safety, much of our workforce continues to work remotely until further notice. Throughout 2020, working remotely did not significantly impact our ability to maintain operations, including use of financial reporting systems, nor did it significantly impact our internal control environment. In addition, certain of our employees and contractors work in remote field locations. We implemented various health and safety protocols including, among others, reduction of certain operational workloads to critical maintenance and personnel, mandating use of certain secure travel options, review of critical medical supplies and procedures and implementation of other safeguards to protect operational personnel. We have not incurred, and in the future do not expect to incur, significant expenses related to business continuity as employees work from home.
•Mobilized a Crisis Management Team (“CMT”) – Our corporate CMT is responsible for ensuring the organization implements our corporate Employee Health and Wellness plan elements pertaining to pandemic response. This plan follows the Centers for Disease Control and Prevention (“CDC”), national, state and local guidance in preparing and responding to COVID-19. The CMT implemented communication protocols should an employee become sick, and we continue to follow CDC guidance, which is subject to change in the future. Throughout 2020, we did not experience significant business or operational interruption due to workforce health or safety concerns pertaining to COVID-19.
The rapid and unprecedented decreases in energy demand have continued to impact certain elements of our distribution channels. For example, the significant decline in energy demand has resulted in downstream market impacts as refineries reduced activity or declared force majeure. Additionally, inventory surpluses have, at times, overwhelmed U.S. storage capacity, leading to a further strain on the supply chain.
Commodity Prices The COVID-19 pandemic has continued to cause unprecedented and prolonged declines in the global demand for crude oil and natural gas. While relaxing of certain containment measures resulted in increased demand and commodity prices in the second half of 2020, demand continues to be significantly lower than levels experienced prior to the COVID-19 pandemic. Additional outbreaks and/or a return of more stringent containment measures or further restrictions could negatively impact commodity prices in the near future. The continuing uncertainty regarding the longevity and severity of the impacts of COVID-19 to the crude oil and natural gas industry, including the reduced demand for crude oil and natural gas commodities and its resulting impact on commodity prices, may continue until vaccines or alternative treatments are made widely available across the globe.
Contemporaneously with the COVID-19 pandemic, the crude oil and natural gas industry continues to be impacted by excess supply in the global marketplace. The Organization of Petroleum Exporting Countries (“OPEC”) and certain non-OPEC producers agreed to production cuts beginning in May 2020 that extend through first quarter 2022. While these production cuts have proven unable to sufficiently offset the ongoing decreases in demand caused by COVID-19, production from these producers has fallen to its lowest levels in decades.
These factors caused a growth-oriented Delaware master limited partnership formednumber of producers to reduce capital spending levels and shut-in production at certain fields for a portion of 2020. These temporary shut-ins served to lower inventory levels and thereby alleviate some of the crude oil storage constraints experienced in December 2014the beginning of second quarter 2020; however, by third quarter 2020, a number of producers brought back online previously shut-in production. Inventory levels, and resulting storage constraints, could be impacted as producers continue bringing production back online with relatively higher commodity prices.
In addition to the U.S. crude oil market, the U.S. domestic natural gas market continues to be oversupplied and has contributed to depressed pricing. We expect that if development activity remains at lower levels in the U.S. leading to reduced crude oil and associated natural gas production, U.S. domestic natural gas prices will adjust as supply and demand levels equalize.
The sustained decline in commodity prices adversely affected shale producers in the U.S., including our customers. In response, certain of our customers reduced their capital investment programs and temporarily shut-in production. Collectively these actions by our Parent, Noble, to own, operate, develop and acquire a wide range of domestic midstream infrastructure assets. Our current areas of focus are in the DJ Basin in Colorado and the Delaware Basin in Texas. We currently provide crude oil, natural gas, and water-related midstream services through long-term, fixed-fee contracts, as well as purchase crude oil from producers and sell crude oil to customers at various delivery points. Our business activities are conducted through four reportable segments: Gathering Systems (primarily includes crude oil gathering, natural gas gathering and processing, produced water gathering and crude oil sales), Fresh Water Delivery, Investments in Midstream Entities and Corporate. We often refer to the services of our Gathering Systems and Fresh Water Delivery reportable segments collectively as our midstream services.
We are Noble’s primary vehicle for its midstream operations in the onshore United States. We believe that our diverse midstream infrastructure assets and our relationship with Noble position us as a leading midstream service provider.
2019 Initiatives and Results
During 2019, our activities were focused on positioning the Partnership for sustainable, long-term cash flows through the following initiatives:
Developing Strategic Relationships Our strategic relationships, including with Saddlehorn, in the DJ Basin, and with EPIC Y-Grade, EPIC Crude Holdings, and Delaware Crossing in the Delaware Basin,have resulted in expansion of our long-haul business downstream ofdecreased throughput volumes on our gathering systems and an increasesignificant decreases in dedications.fresh water deliveries due to decreases in well completion activity.
The commodity price environment is expected to remain depressed based on sustained decreases in demand, over-supply and global economic instability caused by COVID-19, discussed further below. In addition, we expect downstream capacity and storage constraints to continue to have a negative impact on the ability to transport production. If constraints continue such that storage becomes unavailable to our customers or commodity prices remain depressed, they may be forced or elect to further shut-in production and delay or discontinue drilling plans, which would result in a further decline in demand for our services.
In this market environment, we are focused on protecting our balance sheet. In response, starting with the first quarter of 2020, the Board of Directors of our General Partner approved a 73% reduction of the quarterly distribution to $0.1875 per unit. We intend to utilize funds from our distribution reduction and maintenance to reduce our debt levels. Our Board of Directors of our General Partner will continue reviewing the quarterly distribution in context of market conditions.
Global Economic Instability COVID-19, coupled with the drop in commodity prices, has contributed to equity market volatility and what experts have now concluded amounted to a recession in first quarter 2020. Estimated ranges of the duration of these impacts to equity markets and the global economy vary widely, especially given the continued impacts of COVID-19 are unknown. Throughout 2020, the U.S. government passed a series of stimulus packages which, collectively, have provided the largest relief packages in U.S. history. These packages include various provisions intended to provide relief to individuals and businesses in the form of tax changes, loans and grants, among others. At this time, we do not believe these stimulus measures will have a material impact on the Partnership; however, we do believe they could aid the economy by providing relief to certain individuals and smaller businesses.
Improving Cost Structure Despite record throughput, capital expenditures trended belowThe decline in our expectationsunit price and corresponding reduction in our market capitalization were sustained throughout most of 2020, a condition that is consistent across our sector. We do not have any debt covenants or other lending arrangements that depend upon our unit price. Throughout 2020, we remained in compliance with the covenants contained in our revolving credit facility and term loans, which provide that our consolidated leverage ratio as of the end of each fiscal quarter may not exceed 5.00 to 1.0, and our consolidated interest coverage ratio as of the end of each fiscal quarter to be no less than 3.00 to 1.0. The consolidated leverage ratio and consolidated interest coverage ratio are defined in the respective agreements.
As cities, states and countries continue relaxing confinement restrictions, the risk for the year, dueresurgence and recurrence of COVID-19 remains. The reinstatement of containment measures could potentially lead to consistent cost focus, utilizationan extended period of existing infrastructure,reduced demand for crude oil and to a lesser extent, the timing of customer activity. Cost savings initiatives included project scope and design optimization and more efficient construction processesnatural gas commodities, as well as an enhanced contracting strategy.assert further pressure on the global economy.
Potential Future Impacts
Impairment testing involves uncertainties related to key assumptions such as expectations of our customers’ development and capital spending plans, among others, and a significant number of interdependent variables are derived from these key assumptions. There is a high degree of complexity in their application in determining use and value in recovery tests and fair value determinations.
Given the inherent volatility of the current market conditions driven by the COVID-19 pandemic and the oil and gas supply dynamics, the potential for future conditions to deviate from our current assumptions exists. For example, further erosion in
consumer energy demand, lower crude oil and natural gas development and production, and/or lower commodity prices could trigger future impairments of our Third-party Business We significantly increased midstream services revenues, particularly inassets or non-compliance with the DJ Basin, through additional well connections to existing customers and adding new customers to our systems.
Managing Liquidity We utilized a new term loan facility, preferred equity commitment and common unit offerings to provide liquidity while executing our growth opportunities, including the entry into multiple new partnerships.
Returning Value to Unit Holders While executing our growth opportunities, we were able to provide consistent quarterly distribution increases to our unitholders.
Increasing Alignment and Operational Synergies with Noble Through the Drop-Down and Simplification Transaction, we simplified our relationship with Noble through the elimination of IDRs and the acquisition of the remaining ownership interestfinancial covenants in our DevCos as well as gained additional midstream assets.revolving credit facility and term loans.
Specifically, weWorkforce Adjustments
As previously disclosed, the officers of our General Partner manage our operations and activities. In 2020, Noble engaged in corporate restructuring activities, resulting in reductions in its employee and contractor work forces. Additionally, certain employees were participating in furlough and part-time work programs implemented in first quarter 2020 and continued into third quarter 2020. Certain employees that support our operations were impacted by these activities. Additionally, Noble lowered executive leadership salaries by 10% to 20%. Certain officers of our General Partner were impacted by the salary reductions. The aforementioned actions did not significantly impact our ability to maintain operations, including use of financial reporting systems, nor have they significantly impacted our internal control environment.
2020 Significant Results
We accomplished the following significant transactional and financial results for the year ended December 31, 2019.
2020.
Significant Transactional Highlights Include:
completed the Drop-Down•exercised our 20% option on Saddlehorn, which provided $24.2 million of income and Simplification Transaction;$25.0 million in distributions since February 2020;
completed the formation of •Delaware Crossing;Crossing began delivering crude oil into all connection points in April 2020;
closed options to acquire interests in •EPIC Y-Grade transitioned back to NGL service beginning in May 2020, with completion of its first new build fractionator in June; and
•EPIC Crude;
secured equity commitment and issued preferred equity to GIP CAPS Dos Rios Holding Partnership, L.P. (“GIP”);
Crude entered into an additional term loan credit facility that permitted aggregate borrowing up to $400 million; and
extended the borrowing capacity of our revolving credit facility to $1.15 billion.full service in April 2020;
Significant Financial Highlights Include:
•net income of $245.5$94.9 million, an increasea decrease of 13%61% as compared with 2018;2019;
•net cash provided by operating activities of $385.1$376.6 million, an increasea decrease of 41%2% as compared with 2018;2019;
•Adjusted EBITDA (non-GAAP financial measure) of $385.9$425.8 million, an increase of 18%10% as compared with 2018;2019;
•Adjusted EBITDA (non-GAAP financial measure) attributable to the partnership of $254.6$392.9 million, an increase of 14%54% as compared with 2018;2019; and
•distributable cash flow (non-GAAP financial measure) of $213.4$326.2 million, an increase of 17%53% as compared with 2018.2019.
OPERATING OUTLOOK
2019 Development Project Updates
DJ Basin
In addition to our transactional and financial achievements, we remained focused on environmental, social and governance initiatives by identifying opportunities to reduce environmental impact, improve safety and support the Greeley Crescent IDP area,communities in which we commenced construction onoperate through social investment. In 2020, we reduced flaring intensity in the trunkline extensions supporting future produced water gatheringDelaware Basin by 53% compared to 2019, while reducing overall emissions and fresh water delivery services. During the year, we connected 72 wells in Greeley Crescent IDP for two stream gathering services and delivered fresh water to 70 wells.
In the Black Diamond dedication area, we progressed the Milton Phase I Terminal expansion project that increased outlet pumping capacity and we installed new oil gathering infrastructure for upcoming well connections from third-party producers. During the year, we connected 260 third-party wells to the Black Diamond gathering system. Black Diamond added a long-term oil gathering dedication from a third-party customer. The dedication increased Black Diamond dedicated acres by approximately 85,000 acres, or 54%.
In the Mustang IDP area, we extended infrastructure for crude oil,increasing natural gas and produced water gathering systems to facilitate further development and support future well connections. We also completed additional natural gas offload capacity to facilitate future growththroughput from the area. During the year, we connected 56 wells to the Mustang gathering system.field.
In the Wells Ranch IDP area, we commenced construction on extensions of gathering infrastructure to support future well connections. During the year, we connected and delivered fresh water to 42 wells.
In the East Pony IDP area, we connected and delivered fresh water to 22 wells during the year.
Delaware Basin
In the Permian, we connected 13 sponsored wells and six third-party wells to our gathering systems. We are now connected to 151 sponsor and 15 third-party wells. We also plan to add further compression capacity to our CGFs during 2020.
Saddlehorn Transportation Commitment and Investment Option
During 2019, Black Diamond entered into a strategic relationship with Saddlehorn. Saddlehorn is jointly owned by affiliates of Magellan, Plains and Western Midstream. The Saddlehorn pipeline is currently capable of transporting approximately 190 MBbl/d of crude oil and condensate from the DJ Basin and the Powder River Basin to storage facilities in Cushing, Oklahoma owned by Magellan and Plains. With the recent successful open season, the Saddlehorn pipeline will be expanded by 100 MBbl/d, to a new total capacity of 290 MBbl/d. The higher capacity is expected to be available in late 2020 following the addition of incremental pumping and storage capabilities.
As part of the strategic relationship, Black Diamond and Noble entered into long-term firm transportation commitments with Saddlehorn. See Item 8. Financial Statements and Supplementary Data – Note 15. Commitments and Contingencies. Black Diamond received an option to acquire an ownership interest of up to 20% in Saddlehorn. Black Diamond’s investment option was scheduled to expire in April 2020. In February 2020, Black Diamond exercised its option, effective February 1, 2020, and acquired the 20% ownership interest for $155 million, or $84 million net to the Partnership. After Black Diamond’s purchase, with Magellan and Plains each selling a 10% interest, Magellan and Plains each own a 30% membership interest and Black
Diamond and Western Midstream each own a 20% membership interest in Saddlehorn. Magellan continues to serve as operator of the Saddlehorn pipeline. The Partnership funded its share of the transaction price with available cash and a draw under its revolving credit facility.
20202021 Capital Program
Organic Capital Program
Our 20202021 organic capital program will accommodate a net investment level of approximately $190$65 to $230$85 million. The Partnership has lowered previously-issued 2020Our 2021 organic net capital expectations by 25% due to continued progressprogram will primarily be focused on sustainable costs savings, including a reductionaffiliate and third-party well connections in pipeline installation coststhe DJ and improved planning and construction solutions for projects as well as better line of sight to customer activity. We will evaluate theDelaware Basins. The level of capital spending will be evaluated throughout the year based on the following factors, among others, and their effect on project financial returns:
•pace of our customers’ development;
•operating and construction costs and our ability to achieve materialadditional contractual supplier price reductions;cost savings;
•impact of new laws and regulations on our business practices;
•indebtedness levels; and
•availability of financing or other sources of funding.
We plan to fund our capital program with cash on hand, from cash generated from operations, and borrowings under our revolving credit facility and, if necessary, the issuance of additional equity or debt securities.facility.
Investment Capital Program
Our 20202021 investment capital program will accommodate a net investment level inclusive of the $84approximately $15 to $25 million to acquire the 20% interest in Saddlehorn, of approximately $220 to $260 million. The partnership has increased previously-issued 2020 investment capital guidance due to scope changescomplete projects at EPIC Crude and phasing of investments from 2019 to 2020 as well as factoring higher cost assumptions to complete the projects.
EPIC Y-Grade.
How We Evaluate Our Operations
Our management uses a variety of financial and operating metrics, each as described in more detail below, to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include:
throughput volumes (Gathering Systems and Fresh Water Delivery reportable segments);
operating costs and expenses;
Adjusted EBITDA (non-GAAP financial measure);
distributable cash flow (non-GAAP financial measure); and
capital expenditures.
RESULTS OF OPERATIONS
Results of operations were as follows:
| | | | | | | | | | | | | |
| Year Ended December 31, | | |
(in thousands) | 2020 | | 2019 | | |
Revenues | | | | | |
Midstream Services — Affiliate | $ | 389,192 | | | $ | 417,835 | | | |
Midstream Services — Third Party | 94,228 | | | 96,194 | | | |
Crude Oil Sales — Third Party | 281,205 | | | 189,772 | | | |
Total Revenues | 764,625 | | | 703,801 | | | |
Costs and Expenses | | | | | |
Cost of Crude Oil Sales | 270,678 | | | 181,390 | | | |
Direct Operating | 92,387 | | | 116,675 | | | |
Depreciation and Amortization | 105,697 | | | 96,981 | | | |
General and Administrative | 24,721 | | | 25,777 | | | |
Goodwill Impairment | 109,734 | | | — | | | |
Other Operating (Income) Expense | 4,698 | | | (488) | | | |
Total Operating Expenses | 607,915 | | | 420,335 | | | |
Operating Income | 156,710 | | | 283,466 | | | |
Other Expense (Income) | | | | | |
Interest Expense, Net of Amount Capitalized | 26,570 | | | 16,236 | | | |
Investment Loss (Income) | 34,891 | | | 17,748 | | | |
Total Other Expense (Income) | 61,461 | | | 33,984 | | | |
Income Before Income Taxes | 95,249 | | | 249,482 | | | |
Tax Provision | 383 | | | 4,015 | | | |
Net Income | 94,866 | | | 245,467 | | | |
Less: Net Income Prior to the Drop-Down and Simplification | — | | | 12,929 | | | |
Net Income Subsequent to the Drop-Down and Simplification | 94,866 | | | 232,538 | | | |
Less: Net (Loss) Income Attributable to Noncontrolling Interests | (39,165) | | | 72,542 | | | |
Net Income Attributable to Noble Midstream Partners LP | $ | 134,031 | | | $ | 159,996 | | | |
| | | | | |
Adjusted EBITDA (1) Attributable to Noble Midstream Partners LP | $ | 392,926 | | | $ | 254,586 | | | |
| | | | | |
Distributable Cash Flow (1) of Noble Midstream Partners LP | $ | 326,192 | | | $ | 213,442 | | | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
(in thousands) | 2019 | | 2018 | | 2017 |
Revenues | | | | | |
Midstream Services — Affiliate | $ | 417,835 |
| | $ | 338,747 |
| | $ | 271,269 |
|
Midstream Services — Third Party | 96,194 |
| | 78,498 |
| | 18,353 |
|
Crude Oil Sales — Third Party | 189,772 |
| | 141,490 |
| | — |
|
Total Revenues | 703,801 |
| | 558,735 |
| | 289,622 |
|
Costs and Expenses | | | | | |
Cost of Crude Oil Sales | 181,390 |
| | 136,368 |
| | — |
|
Direct Operating | 116,675 |
| | 95,852 |
| | 67,832 |
|
Depreciation and Amortization | 96,981 |
| | 79,568 |
| | 22,990 |
|
General and Administrative | 25,777 |
| | 25,910 |
| | 14,792 |
|
Other Operating (Income) Expense | (488 | ) | | 2,159 |
| | — |
|
Total Operating Expenses | 420,335 |
| | 339,857 |
| | 105,614 |
|
Operating Income | 283,466 |
| | 218,878 |
| | 184,008 |
|
Other Expense (Income) | | | | | |
Interest Expense, Net of Amount Capitalized | 16,236 |
| | 10,447 |
| | 1,603 |
|
Investment Loss (Income) | 17,748 |
| | (16,289 | ) | | (6,334 | ) |
Total Other Expense (Income) | 33,984 |
| | (5,842 | ) | | (4,731 | ) |
Income Before Income Taxes | 249,482 |
| | 224,720 |
| | 188,739 |
|
Tax Provision | 4,015 |
| | 8,001 |
| | 27,972 |
|
Net Income | 245,467 |
| | 216,719 |
| | 160,767 |
|
Less: Net Income Prior to the Drop-Down and Simplification Transaction | 12,929 |
| | 27,843 |
| | (2,869 | ) |
Net Income Subsequent to the Drop-Down and Simplification Transaction | 232,538 |
| | 188,876 |
| | 163,636 |
|
Less: Net Income Attributable to Noncontrolling Interests | 72,542 |
| | 26,142 |
| | 23,064 |
|
Net Income Attributable to Noble Midstream Partners LP | $ | 159,996 |
| | $ | 162,734 |
| | $ | 140,572 |
|
| | | | | |
Adjusted EBITDA(1) Attributable to Noble Midstream Partners LP | $ | 254,586 |
| | $ | 223,144 |
| | $ | 156,526 |
|
| | | | | |
Distributable Cash Flow(1) of Noble Midstream Partners LP | $ | 213,442 |
| | $ | 182,024 |
| | $ | 136,156 |
|
Throughput and Crude Oil Sales Volumes
The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services as well as the crude oil volumes we sell to customers. These volumes are affected primarily by the level of drilling and completion activity by our customers in our areas of operations, and by changes in the supply of and demand for crude oil, natural gas and NGLs in the markets served directly or indirectly by our assets.
Our customers’ willingness to engage in drilling and completion activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill and operate a well, expected well performance, the availability and cost of capital, and environmental and government regulations. We generally expect the level of drilling to positively correlate with long-term trends in commodity prices. Similarly, production levels nationally and regionally generally tend to positively correlate with drilling activity.
Our customers have dedicated acreage to us based on the services we provide. Our commercial agreements with Noble provide that, in addition to our existing dedicated acreage, any future acreage that is acquired by Noble in the IDP areas, and that is not subject to a pre-existing third-party commitment, will be included in the dedication to us for midstream services.
Throughput and crude oil sales volumes related to our Gathering Systems reportable segment and throughput volumes related to our Fresh Water Delivery reportable segment were as follows:
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
DJ Basin | | | |
Crude Oil Sales Volumes (Bbl/d) | 16,964 | | | 9,354 | |
Crude Oil Gathering Volumes (Bbl/d) | 174,644 | | | 182,121 | |
Natural Gas Gathering Volumes (MMBtu/d) | 503,794 | | | 476,605 | |
Natural Gas Processing Volumes (MMBtu/d) | 41,511 | | | 50,039 | |
Produced Water Gathering Volumes (Bbl/d) | 35,190 | | | 39,629 | |
Fresh Water Delivery Volumes (Bbl/d) | 91,886 | | | 164,524 | |
| | | |
Delaware Basin | | | |
| | | |
Crude Oil Gathering Volumes (Bbl/d) | 54,347 | | | 49,842 | |
Natural Gas Gathering Volumes (MMBtu/d) | 166,032 | | | 155,155 | |
| | | |
Produced Water Gathering Volumes (Bbl/d) | 138,449 | | | 148,886 | |
| | | |
| | | |
Total Gathering Systems | | | |
Crude Oil Sales Volumes (Bbl/d) | 16,964 | | | 9,354 | |
Crude Oil Gathering Volumes (Bbl/d) | 228,991 | | | 231,963 | |
Natural Gas Gathering Volumes (MMBtu/d) | 669,826 | | | 631,760 | |
Total Barrels of Oil Equivalent (Boe/d) (1) | 314,866 | | | 322,312 | |
Natural Gas Processing Volumes (MMBtu/d) | 41,511 | | | 50,039 | |
Produced Water Gathering Volumes (Bbl/d) | 173,639 | | | 188,515 | |
| | | |
Total Fresh Water Delivery | | | |
Fresh Water Services Volumes (Bbl/d) | 91,886 | | | 164,524 | |
|
| | | | | | | | |
| Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
DJ Basin | | | | | |
Crude Oil Sales Volumes (Bbl/d) | 9,354 |
| | 6,129 |
| | — |
|
Crude Oil Gathering Volumes (Bbl/d) | 182,121 |
| | 143,095 |
| | 61,864 |
|
Natural Gas Gathering Volumes (MMBtu/d) | 476,605 |
| | 308,929 |
| | 228,768 |
|
Natural Gas Processing Volumes (MMBtu/d) | 50,039 |
| | 61,766 |
| | 49,531 |
|
Produced Water Gathering Volumes (Bbl/d) | 39,629 |
| | 29,903 |
| | 16,435 |
|
Fresh Water Delivery Volumes (Bbl/d) | 164,524 |
| | 175,754 |
| | 155,990 |
|
| | | | | |
Delaware Basin | | | | | |
Crude Oil Gathering Volumes (Bbl/d) | 49,842 |
| | 34,032 |
| | 7,385 |
|
Natural Gas Gathering Volumes (MMBtu/d) | 155,155 |
| | 78,875 |
| | 16,172 |
|
Produced Water Gathering Volumes (Bbl/d) | 148,886 |
| | 91,312 |
| | 20,930 |
|
| | | | | |
Total Gathering Systems | | | | | |
Crude Oil Sales Volumes (Bbl/d) | 9,354 |
| | 6,129 |
| | — |
|
Crude Oil Gathering Volumes (Bbl/d) | 231,963 |
| | 177,127 |
| | 69,249 |
|
Natural Gas Gathering Volumes (MMBtu/d) | 631,760 |
| | 387,804 |
| | 244,940 |
|
Total Barrels of Oil Equivalent (Boe/d) | 322,312 |
| | 232,974 |
| | 100,652 |
|
Natural Gas Processing Volumes (MMBtu/d) | 50,039 |
| | 61,766 |
| | 49,531 |
|
Produced Water Gathering Volumes (Bbl/d) | 188,515 |
| | 121,215 |
| | 37,365 |
|
| | | | | |
Total Fresh Water Delivery | | | | | |
Fresh Water Services Volumes (Bbl/d) | 164,524 |
| | 175,754 |
| | 155,990 |
|
(1)Includes crude oil sales volumes that are transported on our gathering systems and sold to third-party customers.
Revenues
Revenues from our Gathering System and Fresh Water Delivery reportable segments were as follows:
|
| | | | | | | | | | | | | | | | | |
| | | Increase (Decrease) from Prior Year | | | | Increase (Decrease) from Prior Year | | |
(in thousands, except percentages) | 2019 | | | 2018 | | | 2017 |
Year Ended December 31, | | | | | | | | | |
Gathering and Processing — Affiliate | $ | 337,086 |
| | 27 | % | | $ | 265,505 |
| | 40 | % | | $ | 189,732 |
|
Gathering and Processing — Third Party | 76,645 |
| | 42 | % | | 54,017 |
| | 626 | % | | 7,444 |
|
Fresh Water Delivery — Affiliate | 77,566 |
| | 12 | % | | 69,266 |
| | (9 | )% | | 75,860 |
|
Fresh Water Delivery — Third Party | 12,591 |
| | (35 | )% | | 19,345 |
| | 77 | % | | 10,909 |
|
Crude Oil Sales — Third Party | 189,772 |
| | 34 | % | | 141,490 |
| | N/M |
| | — |
|
Other — Affiliate | 3,183 |
| | (20 | )% | | 3,976 |
| | (30 | )% | | 5,677 |
|
Other — Third Party | 6,958 |
| | 35 | % | | 5,136 |
| | N/M |
| | — |
|
Total Midstream Services Revenues | $ | 703,801 |
| | 26 | % | | $ | 558,735 |
| | 93 | % | | $ | 289,622 |
|
N/M amount is not meaningful. | | | | | | | | | | | | | | | | | |
(in thousands) | 2020 | | 2019 | | Increase (Decrease) from Prior Year |
Year Ended December 31, | | | | | |
Gathering and Processing — Affiliate | $ | 328,411 | | | $ | 337,086 | | | (3) | % |
Gathering and Processing — Third Party | 78,654 | | | 76,645 | | | 3 | % |
Fresh Water Delivery — Affiliate | 57,834 | | | 77,566 | | | (25) | % |
Fresh Water Delivery — Third Party | 7,680 | | | 12,591 | | | (39) | % |
| | | | | |
Crude Oil Sales — Third Party | 281,205 | | | 189,772 | | | 48 | % |
Other — Affiliate | 2,947 | | | 3,183 | | | (7) | % |
Other — Third Party | 7,894 | | | 6,958 | | | 13 | % |
Total Midstream Services Revenues | $ | 764,625 | | | $ | 703,801 | | | 9 | % |
Revenues Trend Analysis
Revenues increased during 20192020 as compared with 2018 and increased during 2018 as compared with 2017.2019. The increaseschanges in revenues by reportable segment were as follows:
Gathering Systems Gathering Systems revenues increased by $143.5$85.5 million during 20192020 as compared with 20182019 due to the following:
•an increase of $48.3$91.4 million in crude oil sales and $17.4due to increased activity associated with the fulfillment of our transportation commitments, which was partially offset by decreased commodity prices during 2020;
•an increase of $9.0 million in crude oil gathering services driven by an increase in throughput volumes resulting from an increase in the number of wells connected to the Black Diamond system;
an increase of $54.8 million in crude oil, produced water and natural gas gathering services revenues driven by an increase in throughput volumes resulting from an increase in wells connected to our gathering systems in the Wells RanchMustang IDP Greeley Crescent IDP, and Mustang IDP.area;
•an increase of $43.6$5.3 million in crude oil and natural gas and produced water gathering services revenues driven by an increase in throughput volumes resulting from an increase in wells connected to our gathering systems in the Delaware Basin;
partially offset by:
a decrease of $10.1 million in natural gas gathering and processing revenues driven by a decrease in natural gas throughput volumes in the East Pony IDP; and
a decrease of $7.2 million in crude oil gathering driven by a decrease in crude oil throughput volumes in the East Pony IDP.
Gathering Systems revenues increased by $267.3 million during 2018 as compared with 2017 due to the following:
an increase of $141.5 million in crude oil sales due to the commencement of services upon closing of Black Diamond’s and Greenfield Midstream, LLC’s (the “Greenfield Member”) acquisition of all of the issued and outstanding limited liability company interests (the “Black Diamond Acquisition”) in Saddle Butte Rockies Midstream, LLC and certain affiliates (collectively, “Saddle Butte”) from Saddle Butte Pipeline II, LLC;
an increase of $43.1 million in crude oil, natural gas and produced water gathering services revenues driven by an increase in throughput volumes in the Delaware Basin resulting from a full year of gathering services revenues and the commencement of services with a third-party customer during 2018;
an increase in the number of $34.1 million in crude oil and natural gaswells connected to our gathering services revenues due to the commencementsystems;
partially offset by:
•a decrease of services upon closing of the Black Diamond Acquisition;
an increase of $19.9$12.7 million in crude oil, natural gas and produced water gathering services revenues driven by an increase indecreased throughput volumeson our gathering systems resulting from temporary well shut-ins by our customer in the Wells Ranch IDP area; and East Pony IDP;
an increase•a decrease of $10.3$5.2 million in crude oil natural gas and produced water gathering services revenues due to the commencement of services in the Mustang IDP during 2018;
an increase of $8.2 million in crude oil and produced water gathering services due to providing a full year of services in the Greeley Crescent IDP to an unaffiliated third party; and
an increase of $3.5 million in crude oil, natural gas and produced water gathering services revenue driven by rate escalations in the Wells Ranch IDP and East Pony IDP;
partially offset by:
a decrease of $15.0 million in produced water hauling, recycling and disposal services driven by decreased use of third-party servicesthroughput on our gathering systems resulting from temporary well shut-ins by our customers in the Wells Ranch IDP and East Pony IDP.Black Diamond area.
Fresh Water Delivery Fresh Water Delivery revenues increaseddecreased by $1.5$24.6 million during 20192020 as compared with 20182019 due to the following:
an increase of $19.8 million in fresh water delivery revenues due to the recommencement of services in the East Pony IDP area during 2019;
substantially offset by:
a decrease of $18.3 million in fresh water delivery revenues in the Mustang IDP, Greeley Crescent IDP and Wells Ranch IDP driven by decreased fresh water volumesdeliveries in 2020 in the DJ Basin resulting from reduced well completion activity by Noble.our customers.
Fresh Water Delivery revenues increased by $1.8 million during 2018 as compared with 2017 due to the following:
an increase of $36.7 million in fresh water delivery revenues due to the recommencement of services in the Mustang IDP during 2018; and
an increase of $8.4 million in fresh water delivery revenues driven by increased fresh water volumes delivered to a third-party customer in the Greeley Crescent IDP;
substantially offset by:
a decrease of $43.3 million in fresh water delivery revenues due to a decrease in fresh water deliveries in the Wells Ranch IDP and East Pony IDP resulting from reduced well completion activity by Noble.
Costs and Expenses
Direct Operating Expense
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly associated with operating our assets. Direct labor costs, ad valorem taxes, repair and maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Many of these expenses remain relatively stable across broad ranges of throughput volumes, but a portion of these expenses can fluctuate from period to period depending on the mix of activities performed during that period and the timing of these expenses. We also seek to manage operating expenditures on our midstream systems by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow.
General and Administrative Expense
Noble charges us for general and administrative services. Direct charges include a fixed fee under our omnibus agreement and compensation of our executives under our secondment agreement based on the percentage of time spent working on us.
We incur incremental general and administrative expenses attributable to being a publicly traded partnership, including expenses associated with: annual, quarterly and current reporting with the SEC; tax return and Schedule K-1 preparation and distribution; Sarbanes-Oxley Act of 2002 compliance; Nasdaq listing; independent auditor fees; legal fees; investor relations expenses; transfer agent and registrar fees; incremental salary and benefits costs of seconded employees; outside director fees; director and officer insurance coverage expenses; and compensation expense associated with the LTIP.
Costs and Expenses Trend Analysis
Costs and expenses were as follows: | | | | | Increase (Decrease) from Prior Year | | | | Increase from Prior Year | | | |
(in thousands, except percentages) | 2019 | | 2018 | | 2017 | |
(in thousands) | | (in thousands) | 2020 | | 2019 | | Increase (Decrease) from Prior Year |
Year Ended December 31, | | | | | | | | | | Year Ended December 31, | |
Cost of Crude Oil Sales | $ | 181,390 |
| | 33 | % | | $ | 136,368 |
| | N/M |
| | $ | — |
| Cost of Crude Oil Sales | $ | 270,678 | | | $ | 181,390 | | | 49 | % |
Direct Operating | 116,675 |
| | 22 | % | | 95,852 |
| | 41 | % | | 67,832 |
| Direct Operating | 92,387 | | | 116,675 | | | (21) | % |
Depreciation and Amortization | 96,981 |
| | 22 | % | | 79,568 |
| | 246 | % | | 22,990 |
| Depreciation and Amortization | 105,697 | | | 96,981 | | | 9 | % |
General and Administrative | 25,777 |
| | (1 | )% | | 25,910 |
| | 75 | % | | 14,792 |
| General and Administrative | 24,721 | | | 25,777 | | | (4) | % |
Goodwill Impairment | | Goodwill Impairment | 109,734 | | | — | | | N/M |
Other Operating (Income) Expense | (488 | ) | | (123 | )% | | 2,159 |
| | N/M |
| | — |
| Other Operating (Income) Expense | 4,698 | | | (488) | | | N/M |
Total Operating Expenses | $ | 420,335 |
| | 24 | % | | $ | 339,857 |
| | 222 | % | | $ | 105,614 |
| Total Operating Expenses | $ | 607,915 | | | $ | 420,335 | | | 45 | % |
N/M Amount is not meaningful
Cost of Crude Oil Sales Cost of crude oil sales is recorded within our Gathering Systems reportable segment. Cost of crude oil sales increased $45.0$89.3 million during 20192020 as compared with 2018.2019. The increase iswas primarily attributable to increased sales volumes resulting from an increase in the numberpurchases of wells connectedcrude oil to the Black Diamond system.meet our crude oil transportation commitments.
Direct Operating Expenses Direct operating expenses increaseddecreased during 20192020 as compared with 2018 and increased during 2018 as compared with 2017.2019. The increaseschanges in direct operating expenses by reportable segment were as follows:
Gathering Systems Gathering Systems direct operating expenses increased $15.9decreased $15.5 million during 20192020 as compared with 2018. The increase was primarily attributable2019 due to operating expenses associated with expanding our systemsability to gather increased volumescapture cost efficiencies as well as defer non-essential program work due to COVID-19 and decreased use of third party providers for produced water logistics services resulting from an increasereduced well completion activity and temporary well shut-ins by our customer in the number of wells connected in the Delaware Basin, Wells Ranch IDP Greeley Crescent IDP, and Mustang IDP areas during 2019.area.
Gathering systems direct operating expenses increased $28.9 million during 2018 as compared with 2017. The increases were primarily attributable to operating expenses associated with the CGFs in the Delaware Basin that were completed during 2018, operating expenses associated with the facilities acquired in the Black Diamond Acquisition, and operating expenses associated with the commencement of gathering services in the Mustang IDP during 2018.
Fresh Water Delivery Fresh Water Delivery direct operating expenses increased $4.4decreased $10.0 million during 20192020 as compared with 20182019 primarily due to operating expenses associated with the recommencementdecreased use of third-party providers for fresh water logistics services in the East Pony IDP area.
Fresh Water Delivery direct operating expenses decreased $1.7 million during 2018 as compared with 2017 primarily due to decreased volumesDJ Basin resulting from the timing ofreduced well completion activity by Noble in the Wells Ranch and East Pony IDP areas and decreased use of third-party services.our customers.
Corporate Corporate direct operating expenses increased $0.5$1.2 million during 20192020 as compared with 2018 and $0.9 million during 2018 as compared with 20172019 primarily due to increased insurance expense.
Depreciation and Amortization Depreciation and amortization expense increased during 20192020 as compared with 2018 and increased during 2018 as compared with 2017.2019. The increaseschanges by reportable segment were as follows:
Gathering Systems Gathering Systems depreciation and amortization expense increased $17.1$8.3 million during 20192020 as compared with 20182019 primarily due to assets placed in service in 2019.2020. Assets placed in service were associated with the Mustang gathering system, the expansion of the Delaware Basin infrastructure, and the continued development of the Black Diamond system.assets.
Gathering Systems depreciation and amortization expense increased $56.6 million during 2018 as compared with 2017 primarily due to assets placed in service in 2018. Assets placed in service were associated with the expansion of the Wells Ranch CGF and gathering system, construction of the Greeley Crescent gathering system, construction of the Delaware Basin CGFs, and assets acquired in the Black Diamond Acquisition. Additionally, depreciation and amortization expense includes the amortization of intangible assets that consist of customer contracts and relationships acquired in the Black Diamond Acquisition.
Fresh Water Delivery Fresh Water Delivery depreciation and amortization expense remained consistent during 20192020 as compared with 2018 as a substantial portion of the assets placed in service during 2019 were placed in service during fourth quarter 2019. Fresh Water Delivery depreciation and amortization expense remained consistent during 2018 as compared with 2017 asdue to our fresh water delivery assets in service remained consistent.
General and Administrative Expense General and administrative expense is recorded within our Corporate reportable segment. General and administrative expense remained consistentdecreased $1.1 million during 20192020 as compared with 2018.2019. The increase indecrease was primarily attributable to decreased transaction expenses incurred in connectionassociated with the Drop-Down and Simplification Transaction wereTransaction. The decrease was substantially offset by transactions expenses incurredan increase in connection with the Black Diamond acquisition.fixed annual fee payable under our omnibus agreement which became effective March 1, 2020.
General and administrative expense increased $11.1 million during 2018 as compared with 2017. The increase is primarily related to legal and financial advisory transaction expenses associated with the Black Diamond Acquisition as well as other professional fees. Transaction expenses associated with the Black Diamond Acquisition during 2018 were approximately $6.8 million. See Item 8. Financial Statements and Supplementary Data – Note 3. Transactions with Affiliates4. Offerings.Other Operating Expense (Income) Other operating expense (income) is recorded within our Gathering Systems reportable segment. Other operating expenses during 2020 primarily related to impairments and losses incurred during 2018 include losses onassociated with the sale of crude oil inventory as well as the net impairment related to a damaged asset.miscellaneous assets.
Other Expense (Income) Trend Analysis | | | | | Increase (Decrease) from Prior Year | | | | Increase from Prior Year | | | | | | | | | | | | | | | | | |
(in thousands) | 2019 | | 2018 | | 2017 | (in thousands) | 2020 | | 2019 | | Increase (Decrease) from Prior Year |
Year Ended December 31, | | | | | | | | | | Year Ended December 31, | |
Interest Expense | $ | 33,723 |
| | 100 | % | | $ | 16,863 |
| | 308 | % | | $ | 4,130 |
| Interest Expense | $ | 32,030 | | | $ | 33,723 | | | (5) | % |
Capitalized Interest | (17,487 | ) | | 173 | % | | (6,416 | ) | | 154 | % | | (2,527 | ) | Capitalized Interest | (5,460) | | | (17,487) | | | (69) | % |
Interest Expense, Net | 16,236 |
| | 55 | % | | 10,447 |
| | 552 | % | | 1,603 |
| Interest Expense, Net | 26,570 | | | 16,236 | | | 64 | % |
Investment Loss (Income) | 17,748 |
| | (209 | )% | | (16,289 | ) | | 157 | % | | (6,334 | ) | |
Total Other Expense (Income) | $ | 33,984 |
| | (682 | )% | | $ | (5,842 | ) | | 23 | % | | $ | (4,731 | ) | |
Investment Loss, Net | | Investment Loss, Net | 34,891 | | | 17,748 | | | 97 | % |
| Total Other Expense, Net | | Total Other Expense, Net | $ | 61,461 | | | $ | 33,984 | | | 81 | % |
Interest Expense, Net Interest expense is recorded within our Corporate reportable segment. Interest expense represents interest incurred in connection with our revolving credit facility and term loan credit facilities. Our interest expense includes interest on outstanding balances on the facilities and commitment fees on the undrawn portion of our revolving credit facility as well as the non-cash amortization of origination fees. A portion of the interest expense is capitalized based upon construction-in-progress activity as well as our investments in equity method investees engaged in construction activities during the year. See Item 8. Financial Statements and Supplementary Data – Note 5. Property, Plant and Equipment for our construction-in-progress balances as of December 31, 2020 and 2019 and 2018 and See Item 8. Financial Statements and Supplementary Data – Note 6. Investments.
Interest expense increased $16.9decreased $1.7 million during 20192020 as compared with 2018.2019. The increasedecrease was primarily due to increasedhigher interest rates during 2019, partially offset by higher outstanding long-term debtbalances during 20192020.
Capitalized interest decreased $12.0 million during 2020 as compared with 2018, partially offset by a2019. The decrease in interest rates. Capitalized interest increased $11.1 million during 2019 as compared with 2018,is primarily attributable to capitalizeddecreased construction-in-progress balances during 2020 as well as no longer capitalizing interest associated with our capital contributions to Delaware Crossing, EPIC Y-GradeCrude and EPIC Crude during 2019.
Interest expense increased $12.7 million during 2018 as comparedY-Grade. As the aforementioned investments have commenced planned, principal operations, we no longer capitalize interest associated with 2017. The increase was primarily due to increased outstanding long-term debt during 2018 as compared with 2017. During 2018, we utilized proceeds from long-term debt to fund portions of our construction activities and the Black Diamond Acquisition. In addition, interest rates increased during 2018. Capitalized interest increased $3.9 million during 2018 as compared with 2017 due to an increase in construction-in-progress during 2018 as compared with 2017.capital contributions.
Investment Loss, (Income) Net
Investment incomeloss is recorded within our Investments in Midstream Entities reportable segment. Investment income decreased $34.0segment and increased $17.1 million during 20192020 as compared with 2018 primarily2019. Our Investment loss, net is driven by increased losses from the Delaware Crossing,EPIC Crude and EPIC Y-Grade and EPIC Crude investmentsinvestments. The losses are primarily attributable to expenses incurred in connection with the formation of the entities as well as general and administrate expenses incurred prior to service commencement. Earnings from Advantage also decreased in 2019 as compared to 2018 resulting from decreased crude oil throughput.
Investment income increased $10.0 million during 2018 as compared with 2017 due to highercommencement and the gradual ramp of throughput volumes. The losses were partially offset by earnings from our investment in Advantage resulting from increased crude oil throughput volumes during 2018 as compared with 2017 as well as a full period of activity from Advantage which closed during second quarter 2017.Saddlehorn.
Income Tax Provision
We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes are generally borne by our partners through the allocation of taxable income and we do not record deferred taxes related to the aggregate difference in the basis of our assets for financial and tax reporting purposes. We are subject to a Texas margin tax due to our operations in the Delaware Basin, and we recorded a de minimis state tax provision for the years ended December 31, 20192020 and December 31, 2018.2019. For periods prior to the Drop-Down and Simplification Transaction, our consolidated financial statements include a provision for tax expense on income related to the assets contributed to the Partnership. See Item 8. Financial Statements and Supplementary Data – Note 16.15. Income Taxes for a discussion of the changes in our income tax provision and effective tax rates. Adjusted EBITDA (Non-GAAP Financial Measure)
Adjusted EBITDA should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our Adjusted EBITDA may not be comparable to similar measures of other companies in our industry.
For a reconciliation of Adjusted EBITDA to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
As a result of our increased investment in midstream entities, we have refined our presentation of Adjusted EBITDA to adjust for certain items with respect to our equity method investments. We now define Adjusted EBITDA“Adjusted EBITDA” as net income before income taxes, net interest expense, depreciation and amortization transaction expenses, unit-based compensation and certain other items that we do not view as indicative of our ongoing performance. Additionally, Adjusted EBITDA reflects the adjusted earnings impact of our equity method investments by adjusting our equity earnings or losses from our equity method investments to reflect our proportionate share of the EBITDA of such equity method investments. The table below also reflects Adjusted EBITDA prior to Drop-Down and Simplification Transaction. Prior period Adjusted EBITDA has been reclassified to conform to the current period presentation.
Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
•our operating performance as compared with those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;
•the ability of our assets to generate sufficient cash flow to make distributions to our partners;unitholders;
•our ability to incur and service debt and fund capital expenditures; and
•the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.
Distributable Cash Flow (Non-GAAP Financial Measure)
Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash provided by operating activities, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similar measures of other companies in our industry.
For a reconciliation of distributable cash flow to its most comparable measures calculated and presented in accordance with GAAP, see Reconciliation of Non-GAAP Financial Measures, below.
As a result of our increased investment in midstream entities, we have refined our presentation of distributable cash flow to adjust for certain items with respect to our equity method investments. We now define distributable cash flow as Adjusted EBITDA plus distributions received from our equity method investments less our proportionate share of Adjusted EBITDA from such equity method investments, estimated maintenance capital expenditures and cash interest paid. The table below also reflects Adjusted EBITDA prior
Distributable cash flow does not reflect changes in working capital balances. Our partnership agreement requires us to distribute all available cash on a quarterly basis, and distributable cash flow is one of the factors used by the board of directors
of our General Partner to help determine the amount of cash that is available to our unitholders for a given period. Therefore, we believe distributable cash flow provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to, or more meaningful than, net income, net cash provided by operating activities or any other measure as reported in accordance with GAAP.
Reconciliation of Non-GAAP Financial Measures
The following tables present reconciliations of Adjusted EBITDA and distributable cash flow to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures, for each of the periods indicated.
Reconciliation of Net Income to Adjusted EBITDA and Distributable Cash Flow
| | | | | | | | | | | |
| Year Ended December 31, |
(in thousands) | 2020 | | 2019 |
Reconciliation from Net Income | | | |
Net Income | $ | 94,866 | | | $ | 245,467 | |
Add: | | | |
Depreciation and Amortization | 105,697 | | | 96,981 | |
Interest Expense, Net of Amount Capitalized | 26,570 | | | 16,236 | |
Proportionate Share of Equity Method Investment EBITDA Adjustments | 82,363 | | | 16,160 | |
Goodwill Impairment | 109,734 | | | — | |
Other | 6,531 | | | 11,104 | |
Adjusted EBITDA | 425,761 | | | 385,948 | |
Less: | | | |
Adjusted EBITDA Prior to Drop-Down and Simplification | — | | | 26,629 | |
Adjusted EBITDA Subsequent to Drop-Down and Simplification | 425,761 | | | 359,319 | |
Less: | | | |
Adjusted EBITDA Attributable to Noncontrolling Interests | 32,835 | | | 104,733 | |
Adjusted EBITDA Attributable to Noble Midstream Partners LP | 392,926 | | | 254,586 | |
Add: | | | |
Distribution from Equity Method Investments Attributable to Noble Midstream Partners LP | 25,574 | | | 10,135 | |
Less: | | | |
Proportionate Share of Equity Method Investment EBITDA Attributable to Noble Midstream Partners LP | 31,583 | | | (6,275) | |
Cash Interest Paid | 31,251 | | | 32,984 | |
Maintenance Capital Expenditures | 29,474 | | | 24,570 | |
Distributable Cash Flow of Noble Midstream Partners LP | $ | 326,192 | | | $ | 213,442 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
(in thousands) | 2019 | | 2018 | | 2017 |
Reconciliation from Net Income | | | | | |
Net Income | $ | 245,467 |
| | $ | 216,719 |
| | $ | 160,767 |
|
Add: | | | | | |
Depreciation and Amortization | 96,981 |
| | 79,568 |
| | 22,990 |
|
Interest Expense, Net of Amount Capitalized | 16,236 |
| | 10,447 |
| | 1,603 |
|
Tax Provision | 4,015 |
| | 8,001 |
| | 27,972 |
|
Transaction and Integration Expenses | 6,338 |
| | 7,601 |
| | — |
|
Proportionate Share of Equity Method Investment EBITDA Adjustments | 16,160 |
| | 1,700 |
| | 2,017 |
|
Unit-Based Compensation and Other | 751 |
| | 2,392 |
| | 790 |
|
Adjusted EBITDA | 385,948 |
| | 326,428 |
| | 216,139 |
|
Less: | | | | | |
Adjusted EBITDA Prior to Drop-Down and Simplification Transaction | 26,629 |
| | 49,832 |
| | 35,120 |
|
Adjusted EBITDA Subsequent to Drop-Down and Simplification Transaction | 359,319 |
| | 276,596 |
| | 181,019 |
|
Less: | | | | | |
Adjusted EBITDA Attributable to Noncontrolling Interests | 104,733 |
| | 53,452 |
| | 24,493 |
|
Adjusted EBITDA Attributable to Noble Midstream Partners LP | 254,586 |
| | 223,144 |
| | 156,526 |
|
Add: | | | | | |
Distribution from Equity Method Investments | 10,135 |
| | 9,219 |
| | — |
|
Less: | | | | | |
Proportionate Share of Equity Method Investment Adjusted EBITDA | (6,275 | ) | | 13,580 |
| | 3,796 |
|
Cash Interest Paid | 32,984 |
| | 16,320 |
| | 3,734 |
|
Maintenance Capital Expenditures | 24,570 |
| | 20,439 |
| | 12,840 |
|
Distributable Cash Flow of Noble Midstream Partners LP | $ | 213,442 |
| | $ | 182,024 |
| | $ | 136,156 |
|
Reconciliation of Net Cash Provided by Operating Activities to Adjusted EBITDA and Distributable Cash Flow
| | | | | | | | | | | |
| Year Ended December 31, |
(in thousands) | 2020 | | 2019 |
Reconciliation from Net Cash Provided by Operating Activities | | | |
Net Cash Provided by Operating Activities | $ | 376,629 | | | $ | 385,143 | |
Add: | | | |
Interest Expense, Net of Amount Capitalized | 26,570 | | | 16,236 | |
Changes in Operating Assets and Liabilities | 16,144 | | | (4,165) | |
Equity Method Investment EBITDA Adjustments | 7,664 | | | (16,413) | |
Other | (1,246) | | | 5,147 | |
Adjusted EBITDA | 425,761 | | | 385,948 | |
Less: | | | |
Adjusted EBITDA Prior to Drop-Down and Simplification | — | | | 26,629 | |
Adjusted EBITDA Subsequent to Drop-Down and Simplification | 425,761 | | | 359,319 | |
Less: | | | |
Adjusted EBITDA Attributable to Noncontrolling Interests | 32,835 | | | 104,733 | |
Adjusted EBITDA Attributable to Noble Midstream Partners LP | 392,926 | | | 254,586 | |
Add: | | | |
Distribution from Equity Method Investments Attributable to Noble Midstream Partners LP | 25,574 | | | 10,135 | |
Less: | | | |
Proportionate Share of Equity Method Investment EBITDA Attributable to Noble Midstream Partners LP | 31,583 | | | (6,275) | |
Cash Interest Paid | 31,251 | | | 32,984 | |
Maintenance Capital Expenditures | 29,474 | | | 24,570 | |
Distributable Cash Flow of Noble Midstream Partners LP | $ | 326,192 | | | $ | 213,442 | |
|
| | | | | | | | | | | |
| Year Ended December 31, |
(in thousands) | 2019 | | 2018 | | 2017 |
Reconciliation from Net Cash Provided by Operating Activities | | | | | |
Net Cash Provided by Operating Activities | $ | 385,143 |
| | $ | 273,687 |
| | $ | 196,362 |
|
Add: | | | | | |
Interest Expense, Net of Amount Capitalized | 16,236 |
| | 10,447 |
| | 1,603 |
|
Changes in Operating Assets and Liabilities | (4,165 | ) | | 33,320 |
| | 14,742 |
|
Transaction and Integration Expenses | 6,338 |
| | 7,601 |
| | — |
|
Equity Method Investment EBITDA Adjustments | (16,413 | ) | | 4,361 |
| | 3,796 |
|
Other Adjustments | (1,191 | ) | | (2,988 | ) | | (364 | ) |
Adjusted EBITDA | 385,948 |
| | 326,428 |
| | 216,139 |
|
Less: | | | | | |
Adjusted EBITDA Prior to Drop-Down and Simplification Transaction | 26,629 |
| | 49,832 |
| | 35,120 |
|
Adjusted EBITDA Subsequent to Drop-Down and Simplification Transaction | 359,319 |
| | 276,596 |
| | 181,019 |
|
Less: | | | | | |
Adjusted EBITDA Attributable to Noncontrolling Interests | 104,733 |
| | 53,452 |
| | 24,493 |
|
Adjusted EBITDA Attributable to Noble Midstream Partners LP | 254,586 |
| | 223,144 |
| | 156,526 |
|
Add: | | | | | |
Distribution from Equity Method Investments | 10,135 |
| | 9,219 |
| | — |
|
Less: | | | | | |
Proportionate Share of Equity Method Investment Adjusted EBITDA | (6,275 | ) | | 13,580 |
| | 3,796 |
|
Cash Interest Paid | 32,984 |
| | 16,320 |
| | 3,734 |
|
Maintenance Capital Expenditures | 24,570 |
| | 20,439 |
| | 12,840 |
|
Distributable Cash Flow of Noble Midstream Partners LP | $ | 213,442 |
| | $ | 182,024 |
| | $ | 136,156 |
|
LIQUIDITY AND CAPITAL RESOURCES
Financing Strategy
Our primary sources include cash generated from operations, borrowings under our revolving credit facility, and equity or debt offerings. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements and quarterly cash distributions. We do not have any commitment from Noble or our General Partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us.
Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including our revolving credit facility and the issuance of debt and equity securities, to fund acquisitions and our expansion capital expenditures.
Available Liquidity
Our operating cash flows are a significant source of liquidity. Additional sources of funding were available through debt and equity financing activities, as described below. Year-end liquidity was as follows:
| | | | | | | | | | | |
| December 31, |
(in thousands) | 2020 | | 2019 |
Cash, Cash Equivalents, and Restricted Cash (1) | $ | 16,332 | | | $ | 12,726 | |
Amount Available to be Borrowed Under Our Revolving Credit Facility (2) | 440,000 | | | 555,000 | |
Available Liquidity | $ | 456,332 | | | $ | 567,726 | |
|
| | | | | | | | | | | |
| December 31, |
(in thousands) | 2019 | | 2018 | | 2017 |
Cash, Cash Equivalents, and Restricted Cash (1) | $ | 12,726 |
| | $ | 15,712 |
| | $ | 57,595 |
|
Amount Available to be Borrowed Under Our Revolving Credit Facility (2) | 555,000 |
| | 740,000 |
| | 265,000 |
|
Available Liquidity | $ | 567,726 |
| | $ | 755,712 |
| | $ | 322,595 |
|
(1)See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation.Term Loan Credit Facility Maturity
Our $500 million term loan credit facility matures on July 31, 2021. We are assessing various options and Term Loanexpect to address the maturity prior to July 31, 2021.
Revolving Credit Facility
Our revolving credit facility is available to fund working capital requirements, acquisitions and expansion capital expenditures. In 2019,2020, we utilized our revolving credit facility to fund our capital contributions to Saddlehorn, Delaware Crossing, EPIC Crude, EPIC Y-Grade and EPIC Crude and a portion of the cash consideration in the Drop-Down and Simplification Transaction. On December 13, 2019, we exercised the $350 million accordion feature on the revolving credit facility and increased the capacity from $800 million to $1.15 billion.Propane. As of December 31, 2019, $5952020, $710 million was outstanding under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt. On August 23, 2019, we entered into an additional three-year senior unsecured term loan credit facility that permits aggregate borrowings of up to $400 million. Proceeds were used to repay a portion of the outstanding borrowings under our revolving credit facility and pay fees and expenses in connection with the term loan credit facility transactions. See Item 8. Financial Statements and Supplementary Data – Note 8. Long-Term Debt.Preferred Equity
On March 25, 2019, we secured the GIP preferred equity commitment totaling $200 million. During 2019, preferred equity proceeds totaled $100 million and we incurred offering costs of $3.4 million. The remaining $100 million equity commitment is available for a one-year period, subject to certain conditions precedent. Proceeds from the preferred equity were utilized to repay a portion of outstanding borrowings under our revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 4. Offerings and Acquisition.2019 Private Placement
On November 14, 2019, we completed the 2019 Private Placement and sold 12,077,295 Common Units for gross proceeds of approximately $250 million. Net proceeds totaled approximately $242.9 million, after deducting offering expenses of approximately $7.1 million. Proceeds from the 2019 Private Placement were utilized to fund a portion of the cash consideration for the Drop-Down and Simplification Transaction. See Item 8. Financial Statements and Supplementary Data – Note 4. Offerings and Acquisition.
Cash Flows
Summary cash flow information was as follows: | | | Year Ended December 31, | | Year Ended December 31, |
(in thousands) | 2019 | | 2018 | | 2017 | (in thousands) | 2020 | | 2019 |
Total Cash Provided By (Used in) | | | | | | Total Cash Provided By (Used in) | |
Operating Activities | $ | 385,143 |
| | $ | 273,687 |
| | $ | 196,362 |
| Operating Activities | $ | 376,629 | | | $ | 385,143 | |
Investing Activities | (872,593 | ) | | (1,268,488 | ) | | (381,745 | ) | Investing Activities | (427,554) | | | (872,593) | |
Financing Activities | 484,464 |
| | 952,918 |
| | 185,535 |
| Financing Activities | 54,531 | | | 484,464 | |
(Decrease) Increase in Cash and Cash Equivalents | $ | (2,986 | ) | | $ | (41,883 | ) | | $ | 152 |
| |
Increase (Decrease) in Cash and Cash Equivalents | | Increase (Decrease) in Cash and Cash Equivalents | $ | 3,606 | | | $ | (2,986) | |
Operating Activities Net cash provided by operating activities increaseddecreased during 20192020 as compared with 2018 primarily due2019. The decrease was attributable to an increase of net income driven by increaseddecreased midstream services revenues resulting from highera decrease in throughput volumes, due to expansion of existing systems and providing services to new areas and customers. Thean increase in revenuesnet interest expense, and changes in working capital. The decrease was partially offset by an increasea decrease in direct operating expenses.
Net cash provided by operating activities increased during 2018 as compared with 2017 primarily due to an increase of net income driven by increased revenues resulting from higher throughput volumes due to expansion of existing systems and providing services to new areas and customers. The increase in revenues was partially offset by an increase in direct operating expenses resulting from providing services to new areas and customers as well as an increase in general and administrative expense due to legal and financial advisory fees associated with the Black Diamond Acquisition.distributions from equity method investees.
Investing Activities Cash used in investing activities decreased during 20192020 as compared with 20182019 primarily due to the Black Diamond Acquisition and increased additionsdecreased capital contributions to property, plant and equipment during 2018 related to construction of the Mustang gathering system, expansion of the Mustang fresh water delivery system and construction of the Delaware Basin CGFs.
The decrease was partially offset by our additions toequity method investments during 2019 due to ouras well as decreased capital expenditures in 2020. Our decreased capital contributions to Delaware Crossing, EPIC Y-GradeCrude and EPIC Crude.
Cash used in investing activities increased during 2018 as compared with 2017 primarily drivenY-Grade were partially offset by the Black Diamond Acquisition. Additionsour capital contributions to property, plantSaddlehorn and equipment were also higher in 2018 due to construction of the Mustang gathering system, expansion of the Mustang fresh water delivery system and construction of the Delaware Basin CGFs.EPIC Propane.
Financing Activities Cash provided by financing activities decreased during 20192020 as compared with 20182019 primarily due to the distribution to Noble for the Drop-Down and Simplification Transaction, a decrease in contributions from noncontrolling interest holders and an increase in distributions to unitholders. The decrease was partially offset by an increasedecreases in net long-term borrowings, proceeds from the preferred equity issuance and other equity offerings.
Cash provided The decrease was partially offset by financing activities increasedthe cash outflow associated with the Drop-Down and Simplification Transaction during 20182019 as compared with 2017. Thewell as an increase was primarily due to increased net long-term debt borrowings and increasedin contributions from noncontrolling interest owners, which included the contribution from Greenfield Member to fund the Black Diamond Acquisition.holders.
Off-Balance Sheet Arrangements
As of December 31, 2019,2020, our material off-balance sheet arrangements that we have entered into include our transportation commitments, undrawn letters of credit and guarantees.
Contractual Obligations
The following table summarizes certain contractual obligations as of December 31, 20192020 that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Obligation | Note Reference (1) | | 2021 | | 2022 and 2023 | | 2024 and 2025 | | 2026 and Beyond | | Total |
(in thousands) | | | | | | | | | | | |
Long-Term Debt (2) | | | $ | 500,000 | | | $ | 1,110,000 | | | $ | — | | | $ | — | | | $ | 1,610,000 | |
| | | | | | | | | | | |
Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (3) | | | 21,512 | | | 18,128 | | | — | | | — | | | 39,640 | |
Asset Retirement Obligations (4) | | | — | | | — | | | 8,431 | | | 33,141 | | | 41,572 | |
| | | | | | | | | | | |
Finance Lease Obligations (5) | | | 2,063 | | | — | | | — | | | — | | | 2,063 | |
Operating Lease Obligations (6) | | | 260 | | | — | | | — | | | — | | | 260 | |
Purchase Obligations (7) | | | 2,064 | | | — | | | — | | | — | | | 2,064 | |
Transportation Fees (8) | | | 34,101 | | | 69,074 | | | 72,530 | | | 26,072 | | | 201,777 | |
Surface Lease Obligations (9) | | | 217 | | | 352 | | | 352 | | | 3,698 | | | 4,619 | |
Total Contractual Obligations | | | $ | 560,217 | | | $ | 1,197,554 | | | $ | 81,313 | | | $ | 62,911 | | | $ | 1,901,995 | |
|
| | | | | | | | | | | | | | | | | | | | | |
Obligation | Note Reference (1) | | 2020 | | 2021 and 2022 | | 2023 and 2024 | | 2025 and Beyond | | Total |
(in thousands) | | | | | | | | | | | |
Long-Term Debt (2) | | | $ | — |
| | $ | 900,000 |
| | $ | 595,000 |
| | $ | — |
| | $ | 1,495,000 |
|
Long-Term Debt Interest Payments and Revolving Credit Facility Commitment Fee (3) | | | 45,221 |
| | 66,253 |
| | 3,677 |
| | — |
| | 115,151 |
|
Asset Retirement Obligations (4) | | | — |
| | — |
| | 8,461 |
| | 29,381 |
| | 37,842 |
|
Omnibus Fee (5) | | | 6,850 |
| | — |
| | — |
| | — |
| | 6,850 |
|
Finance Lease Obligations (6) | | | — |
| | 2,005 |
| | — |
| | — |
| | 2,005 |
|
Operating Lease Obligations (7) | | | 2,528 |
| | 260 |
| | — |
| | — |
| | 2,788 |
|
Purchase Obligations (8) | | | 4,947 |
| | — |
| | — |
| | — |
| | 4,947 |
|
Transportation Fees (9) | | | 17,961 |
| | 67,296 |
| | 70,552 |
| | 60,809 |
| | 216,618 |
|
Surface Lease Obligations (10) | | | 215 |
| | 391 |
| | 350 |
| | 3,857 |
| | 4,813 |
|
Total Contractual Obligations | | | $ | 77,722 |
| | $ | 1,036,205 |
| | $ | 678,040 |
| | $ | 94,047 |
| | $ | 1,886,014 |
|
(1)References are to the Notes accompanying Item 8. Financial Statements and Supplementary Data. | |
(1)(2)Long-term debt includes our revolving credit facility and term loan credit facility balances based on the maturity dates of the facilities. (3)Interest payments are based on the outstanding balance, scheduled maturity and interest rate in effect at December 31, 2020. The commitment fee is associated with the unused portion of the revolving credit facility and is based on the unused capacity as of December 31, 2020, $440 million, for all periods presented and assumes no borrowing capacity increases. (4)Asset retirement obligations are discounted. (5)Annual capital lease payments exclude regular maintenance and operational costs. (6)Operating lease obligations represent non-cancelable leases for equipment used in our daily operations. Amounts have not been discounted. (7)Purchase obligations represent contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including: fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. (8)Our transportation fees include fixed fees for the transportation of crude oil. We have entered into long-term agreements with unaffiliated third parties to satisfy a substantial portion of our transportation commitment. (9)Surface lease obligations represent annual payments to landowners. | |
| |
(2)
| Long-term debt includes our revolving credit facility and term loan credit facility balances based on the maturity dates of the facilities. |
| |
(3)
| Interest payments are based on the outstanding balance, scheduled maturity and interest rate in effect at December 31, 2019. The commitment fee is associated with the unused portion of the revolving credit facility and is based on the unused capacity as of December 31, 2019, $555 million, for all periods presented and assumes no borrowing capacity increases. |
| |
(4)
| Asset retirement obligations are discounted. |
| |
(5)
| Annual general and administrative fee we pay to Noble for certain administrative and operational support services being provided to us. The cap on the initial rate expired in September 2019 and we have commenced the annual redetermination process. |
| |
(6)
| Annual capital lease payments exclude regular maintenance and operational costs. |
| |
(7)
| Operating lease obligations represent non-cancelable leases for equipment used in our daily operations. Amounts have not been discounted. |
| |
(8)
| Purchase obligations represent contractual agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including: fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. |
| |
(9)
| Our transportation fees include fixed fees for the transportation of crude oil. We have entered into long-term agreements with unaffiliated third parties to satisfy a substantial portion of our transportation commitment. |
| |
(10)
| Surface lease obligations represent annual payments to landowners. |
In addition to the above contractual obligations, an affiliate of Black Diamond enters into agreements to purchase crude oil from producers at market-based prices. The agreements do not contain provisions regarding fixed or minimum quantities of crude oil to be purchased.
Omnibus Agreement Our omnibus agreement contractually requires us to pay a fixed annual fee for certain administrative and support services being provided to us. The omnibus agreement generally remains in full force and effect so long as Noble controls our General Partner and is redetermined annually. The current rate is $15.7 million and became effective March 1, 2020. During February 2021, we completed the annual redetermination process and have established an annual rate of $18.0 million, effective March 1, 2021.
Preferred Equity We can redeem the preferred equity in whole or in part at any time for cash at a predetermined redemption price. The predetermined redemption price is the greater of (i) an amount necessary to achieve a 12% internal rate of return or (ii) an amount necessary to achieve a 1.375x multiple on invested capital. GIP can request redemption of the preferred equity following the later of the sixth anniversary of the closingon or the fifth anniversary of the EPIC Crude pipeline completion date at a pre-determined base return.after March 25, 2025. The preferred equity is perpetual and has a 6.5% annual dividend rate, payable quarterly in cash, with the ability to accrue unpaid dividends during the first two years following the closing.See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies and Basis of Presentation and Note 4. Offerings and Acquisition. Letters of Credit In the ordinary course of business, we maintain letters of credit in support of certain performance obligations of our subsidiaries. Outstanding letters of credit, including Black Diamond, totaled approximately $42.4$39.0 million at December 31, 20192020.
Capital Requirements
Capital Expenditures and Planned Capital Expenditures
The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Based on the nature of the expenditure, we categorize our capital expenditures as either:
| |
• | •maintenance capital expenditures, whichare additions to property, plant and equipment made to maintain, over the long term, our production and/or operating income. We use an estimate of maintenance capital expenditures to determine our operating surplus, for purposes of determining cash available for distributions; or •, whichare additions to property, plant and equipment made to maintain, over the long term, our production and/or operating income. We use an estimate of maintenance capital expenditures to determine our operating surplus, for purposes of determining cash available for distributions; or |
| |
• | expansion capital expenditures, which are additions to property, plant and equipment made to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput. |
Our planned expansion capital expenditures, driven primarily by Noble’s and our third-party customers’ planned well completions and production growth on our dedicated acreage, will consist primarily of well connections and gathering line additions. We expect to fund at least a portion of future expansion capital expenditures with borrowings under our revolving credit facility. We expect our maintenance capital expenditures to be funded primarily from cash flows from operations.
Capital expenditures and other investing activities (on an accrual basis) were as follows: | | | Year Ended December 31, | | Year Ended December 31, |
(in thousands) | 2019 | | 2018 | | 2017 | (in thousands) | 2020 | | 2019 |
Gathering System Expenditures (1) | $ | 257,066 |
| | $ | 738,427 |
| | $ | 393,184 |
| |
Gathering System Expenditures | | Gathering System Expenditures | $ | 70,118 | | | $ | 257,066 | |
Fresh Water Delivery System Expenditures | 7,330 |
| | 23,018 |
| | 16,469 |
| Fresh Water Delivery System Expenditures | — | | | 7,330 | |
Other | 1,068 |
| | 555 |
| | — |
| Other | 523 | | | 1,068 | |
Total Capital Expenditures | $ | 265,464 |
| | $ | 762,000 |
| | $ | 409,653 |
| |
Total Capital Expenditures (1) | | Total Capital Expenditures (1) | $ | 70,641 | | | $ | 265,464 | |
| | | | | | |
Additions to Investments | $ | 611,325 |
| | $ | 426 |
| | $ | 68,504 |
| |
Additions to Investments (1)(2)(3) | | Additions to Investments (1)(2)(3) | $ | 317,229 | | | $ | 611,325 | |
Our partnership agreement requires that we distribute all of our available cash quarterly. Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on the applicable record date.
The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of U.S. GAAP used in the preparation of the consolidated financial statements.
In assessing long-lived assets for impairments, our management evaluates changes in our business and economic conditions and their implications for recoverability of the assets’ carrying amounts. A substantial portion of our revenues arise from services provided to Noble. Therefore, sustained decreases in commodity prices, significant changes in Noble’sour customer’s future development plans, to the extent they affect our operations, may necessitate assessment of the carrying amount of our affected assets for recoverability. In addition, an increase in our construction or operating costs may also necessitate an assessment.