Attached files
| file | filename |
|---|---|
| EX-3.3 - EXHIBIT 3.3 - CPG OpCo GP LLC | opcogp-2016331xex33.htm |
| EX-3.4 - EXHIBIT 3.4 - CPG OpCo GP LLC | opcogp-2016331xex34.htm |
| EX-32.1 - EXHIBIT 32.1 - CPG OpCo GP LLC | opcogp-2016331xex321.htm |
| EX-3.1 - EXHIBIT 3.1 - CPG OpCo GP LLC | opcogp-2016331xex31.htm |
| 10-Q - 10-Q - CPG OpCo GP LLC | opcogp-2016331x10q.htm |
| EX-32.2 - EXHIBIT 32.2 - CPG OpCo GP LLC | opcogp-2016331xex322.htm |
| EX-99.1 - EXHIBIT 99.1 - CPG OpCo GP LLC | opcogp-2016331xex991.htm |
| EX-3.2 - EXHIBIT 3.2 - CPG OpCo GP LLC | opcogp-2016331xex32.htm |
| EX-31.2 - EXHIBIT 31.2 - CPG OpCo GP LLC | opcogp-2016331xex312.htm |
| EX-31.1 - EXHIBIT 31.1 - CPG OpCo GP LLC | opcogp-2016331xex311.htm |
Exhibit 99.2
COLUMBIA PIPELINE PARTNERS LP
RISK FACTORS FROM ANNUAL REPORT ON FORM 10-K
There are many factors that could have a material adverse effect on the Partnership’s operating results, financial condition and cash flows. New risks may emerge at any time, and the Partnership cannot predict those risks or estimate the extent to which they may affect financial performance. Each of the risks described below could adversely impact the value of the Partnership’s common units.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of costs and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.
We may not have sufficient cash each quarter to pay the full amount of our minimum quarterly distribution of $0.1675 per unit, or $0.67 per unit per year, which will require us to have cash available for distribution of approximately $16.9 million per quarter, or $67.4 million per year, based on the number of common and subordinated units outstanding as of December 31, 2015.
We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. 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 based on, among other things:
• | the rates we charge for our transmission, storage and gathering services; |
• | the level of firm transmission and storage capacity sold and volumes of natural gas we transport, store and gather for our customers; |
• | regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm transmission and storage agreements; |
• | legislative or regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, operating costs and operating flexibility; |
• | the imposition of requirements by state agencies that materially reduce the demand of Columbia OpCo’s customers, such as LDCs and power generators, for its pipeline services; |
• | the commodity price of natural gas, which could reduce the quantities of natural gas available for transport; |
• | the creditworthiness of our customers, particularly in light of recent declines in commodity prices; |
• | the level of Columbia OpCo’s operating and maintenance and general and administrative costs; |
• | the level of capital expenditures Columbia OpCo incurs to maintain its assets; |
• | regulatory and economic limitations on the development of LNG export terminals in the Gulf Coast region; |
• | successful development of LNG export terminals in the eastern or northeastern U.S., which could reduce the need for natural gas to be transported on the Columbia Gulf pipeline system; |
• | changes in insurance markets and the level, types and costs of coverage available, and the financial ability of our insurers to meet their obligations; |
• | changes in, or new, statutes, regulations or governmental policies by federal, state and local authorities with respect to protection of the environment; |
• | changes in accounting rules and/or tax laws or their interpretations; |
• | nonperformance or force majeure by, or disputes with or changes in contract terms with, major customers, suppliers, dealers, distributors or other business partners; and |
• | changes in, or new, statutes, regulations, governmental policies and taxes, or their interpretations. |
In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
• | the level and timing of capital expenditures we or Columbia OpCo makes; |
• | construction costs; |
• | fluctuations in our or Columbia OpCo’s working capital needs; |
• | our or Columbia OpCo’s ability to borrow funds and access capital markets; |
• | our or Columbia OpCo’s debt service requirements and other liabilities; |
• | restrictions contained in our or Columbia OpCo’s existing or future debt agreements; and |
• | the amount of cash reserves established by our general partner. |
Columbia OpCo is a restricted subsidiary and a guarantor under CPG’s credit facilities and guarantees $2.75 billion in aggregate principal amount of CPG’s senior unsecured notes and, if requested by CPG, will guarantee future CPG indebtedness. Such indebtedness could limit Columbia OpCo’s ability to take certain actions, including incurring indebtedness, making acquisitions and capital expenditures and making distributions to us, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
All of our cash is generated from cash distributions from Columbia OpCo. CPG’s credit facility has customary covenants and restrictions on CPG and Columbia OpCo, as a restricted subsidiary and a guarantor of the credit facility. On May 22, 2015, CPG sold $2.75 billion in aggregate principal amount of senior notes in a private placement, which such amount is guaranteed by certain of our subsidiaries, including Columbia OpCo. In addition, at CPG’s request Columbia OpCo will guarantee future indebtedness of CPG. There is no agreement between CPG and Columbia OpCo limiting the amount of CPG indebtedness that Columbia OpCo will be obligated to guarantee. The amount of CPG indebtedness in general, as well as the amount that is guaranteed by Columbia OpCo, may limit the ability of Columbia OpCo to borrow to fund its operations, capital expenditures or growth strategy. Furthermore, to the extent that Columbia OpCo is required to guarantee such indebtedness, Columbia OpCo could be subject to significant operating and financial restrictions. For example, these restrictions could include covenants limiting Columbia OpCo’s ability to:
• | make investments and other restricted payments; |
• | incur additional indebtedness or issue preferred stock; |
• | create liens; |
• | sell all or substantially all of its assets or consolidate or merge with or into other companies; and |
• | engage in transactions with affiliates. |
These covenants or any more restrictive covenants agreed to by CPG in the future could adversely affect Columbia OpCo’s ability to finance future business opportunities and make cash distributions to us. A breach by CPG of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against any collateral securing that debt, including Columbia OpCo and its assets. In addition, any acceleration of debt under CPG’s bank syndicated credit facility could constitute a default under other CPG debt, which Columbia OpCo may also guarantee. If CPG’s lenders or other debt creditors were to proceed against Columbia OpCo’s assets, the value of our ownership interests in Columbia OpCo could be significantly reduced which could adversely affect the value of our common units.
CPG would not owe us or our unitholders any fiduciary duty in allocating exceptions or baskets to covenants and financial ratios among itself and its guarantors or in amending its debt agreements to include provisions more burdensome to our operations and financing capabilities.
Columbia OpCo is a party to a money pool agreement with CPG, which provides Columbia OpCo with access to short-term borrowings to fund expansion capital expenditures and working capital needs. The money pool is supported by CPG’s credit
facility as a source of external funding for all participants. If there were insufficient capacity under the CPG credit facility to support the financing of Columbia OpCo’s needs, it could have a material adverse effect on us.
Columbia OpCo and its subsidiaries have entered into an intercompany money pool agreement with CPG, under which borrowing capacity of $750 million has been reserved for Columbia OpCo and its subsidiaries to fund expansion capital expenditures and working capital needs. The ability of CPG to make loans under the money pool is subject to financial covenants in its credit facility. Therefore, Columbia OpCo’s capacity to borrow under the money pool may be adversely impacted by the level of borrowings by CPG under its credit agreement and by adverse changes in CPG’s financial condition or results of operations, which will be beyond the control of Columbia OpCo and us. In the event CPG were to default under its credit facility, CPG could lose access to this facility, and thus may not be able to fund a request by Columbia OpCo under the money pool agreement. If Columbia OpCo is unable to obtain needed capital or financing on satisfactory terms to fund its organic growth projects, the amount of cash that Columbia OpCo is able to distribute to us may be reduced, which could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our common units.
The amount of cash we have available for distribution to holders of our units depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may be unable to pay cash distributions during periods when we record net income.
Our only asset is a 15.7% interest in Columbia OpCo, over which we have operating control. Because our interest in Columbia OpCo represents our only cash-generating asset, our cash flow will depend entirely on the performance of Columbia OpCo and its subsidiaries and its ability to distribute cash to us.
We are a holding company with no material operations and only limited assets, and the source of our earnings and cash flow will consist exclusively of cash distributions from Columbia OpCo. Therefore, our ability to make quarterly distributions to our unitholders is completely dependent on the performance of Columbia OpCo and its subsidiaries and its ability to distribute funds to us.
Columbia OpCo’s limited partnership agreement requires it to distribute all of its available cash each quarter, less the amounts of cash reserves its general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Columbia OpCo’s business, to enable it to make distributions to us so that we can make timely distributions or to comply with applicable law or any of Columbia OpCo’s debt or other agreements.
The amount of cash Columbia OpCo generates from its operations will fluctuate from quarter to quarter based on, among other things:
• | the fees it charges and the margins it realizes for its services; |
• | regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility; |
• | the level of its operating, maintenance and general and administrative costs; and |
• | prevailing economic conditions. |
In addition, the actual amount of cash Columbia OpCo will have available for distribution to its partners, including us, also will depend on other factors, such as:
• | the level of capital expenditures it makes; |
• | its debt service requirements and other liabilities; |
• | restrictions contained in its debt agreements, including CPG’s credit facility; |
• | its ability to borrow funds; |
• | fluctuations in its working capital needs; |
• | the cost of acquisitions, if any; and |
• | the amount of cash reserves established by it. |
Our future business opportunities may be limited as a result of our agreement with CPG to refrain from taking any action that would prevent CPG from complying with the tax sharing agreement that entered into with NiSource in connection with the Separation.
Under the omnibus agreement, we have agreed to refrain from taking any action that would prevent CPG from complying with the tax sharing agreement that CPG entered into with NiSource in connection with the Separation. Under such tax sharing agreement, CPG has agreed to take certain actions, or refrain from taking certain actions, to ensure that the Separation qualifies for tax-free status under Section 355 of the Internal Revenue Code of 1986, as amended (the “Code”), such as issuing or redeeming common stock or other securities, or permitting its subsidiaries to do so. In compliance with our obligations under the omnibus agreement, we also have agreed not to take any action that could cause CPG to violate one of the covenants in the tax sharing agreement. For example, subject to certain limited exceptions, CPG has agreed that, for the two years following the Separation, CPG will not permit CEG to enter into a transaction that would result in CEG no longer owning our general partner or that would result in CEG owning less than 55% of Columbia OpCo. As a result, certain of our business opportunities and plans may be restricted or limited, such as our ability to acquire additional interests in Columbia OpCo, our ability to sell the general partner of Columbia OpCo, our ability to direct Columbia OpCo to sell assets outside the ordinary course of business and our ability to direct Columbia OpCo to dispose of business assets relied upon to satisfy the “active trade or business” requirement of Section 355 of the Code for the two-year period following the Separation, which may adversely impact our financial condition, results of operations and ability to make distributions to you. Please see “Business and Properties-Separation of Columbia Pipeline Group.”
Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations on a per unit basis.
Even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations on a per unit basis. Any expansion project involves potential risks, including, among other things:
• | service interruptions or increased downtime associated with our projects, including the reversal of Columbia Gulf’s pipelines; |
• | a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the project or acquisition; |
• | an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits, among other factors; |
• | the assumption of unknown liabilities when making acquisitions for which we are not indemnified or for which our indemnity is inadequate; |
• | the diversion of our management’s attention from other business concerns; |
• | mistaken assumptions about the overall costs of equity or debt, demand for our services, supply volumes, reserves, revenues and costs, including synergies and potential growth; |
• | an inability to successfully integrate acquired assets or the businesses we build; |
• | an inability to receive cash flows from a newly built asset until it is operational; and |
• | unforeseen difficulties operating in new product areas or new geographic areas. |
If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per unit, our ability to make distributions to you may be reduced.
The expansion of our existing assets and construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition, and reduce our cash from operations on a per unit basis.
One of the ways we intend to grow our business is through the expansion of our existing assets and construction of new energy infrastructure assets. The construction of additions or modifications to our existing pipelines, and the construction of other new energy infrastructure assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant capital that we may be unable to raise. If we undertake these projects they may not be
completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a new pipeline, the construction may occur over an extended period of time, and we will not receive any material increases in revenues until the project is completed. We may also construct facilities to capture anticipated future growth in production or demand in regions such as the Marcellus and Utica shale production areas, which may not materialize or where contracts are later cancelled.
Since we are not engaged in the exploration for and development of natural gas reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reserves in an area prior to constructing facilities in such area. To the extent we rely on estimates of future production in our decision to acquire or construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new pipelines may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. The construction of new pipelines may also require us to obtain new rights-of-way, and it may become more expensive for us to obtain these new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.
Certain of our internal growth projects may require regulatory approval from federal and state authorities prior to construction, including any extensions from or additions to our transmission and storage system. The approval process for storage and transportation projects located in the Northeast has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering activities in new production areas, including the Marcellus and Utica shale plays. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.
A substantial portion of Columbia OpCo’s organic growth projects are supported by binding precedent agreements that are subject to certain conditions, which, if not satisfied, would permit the customer to opt out of the agreement.
A substantial portion of Columbia OpCo’s estimated capital costs for organic growth projects are supported by a combination of (i) service agreements, which are long-term legally binding obligations that secure Columbia OpCo’s revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either Columbia OpCo or the customer to terminate the agreement. These conditions include, among others, the receipt of governmental approvals and the achievement of certain in-service dates. If the conditions in a precedent agreement are not satisfied and the customer elects to terminate the agreement, the underlying project and the related revenue streams could be at risk, which could have a material adverse effect on our financial condition, results of operations and our ability to make distributions to unitholders.
We depend on certain key customers for a significant portion of our revenues and to anchor our portfolio of growth projects. The loss of key customers could have a material adverse effect on our business, results of operations, financial condition, growth plans and ability to pay distributions to our unitholders.
We are subject to risks of loss resulting from nonperformance by our customers. We depend on certain key customers for a significant portion of our revenues. In addition, we are making significant capital expenditures to expand our existing assets and construct new energy infrastructure based on long-term contracts with customers, including natural gas producers who may be adversely impacted by sustained low commodity prices. Our credit procedures and policies and credit support arrangements may not be adequate to fully eliminate customer credit risk. Further, we may not be able to effectively remarket capacity related to nonperforming customers. The deterioration in the creditworthiness of our customers or the failure of our customers to meet their contractual obligations could have a material adverse effect on our business, results of operations, financial condition, growth plans and ability to pay distributions to our unitholders.
Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available for distribution to unitholders.
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our systems will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, the competition for natural gas supplies to serve other markets could reduce the amount of natural gas supply for our customers or lower natural gas prices could cause producers to determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. For example, in response to historically low natural gas prices, a number of large natural gas producers have announced their intention to re-evaluate and/or reduce their drilling programs in certain areas. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to
grow our operations and increase cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas transported, stored and gathered on our systems and cash flows associated therewith, our customers must continually obtain adequate supplies of natural gas.
The primary factors affecting our ability to obtain sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering system or the rate at which production from a well declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported LNG; the ability to export LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials and premiums; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves.
A portion of the cash available for distribution to our unitholders is derived from royalty payments we receive on our mineral rights positions through our working interests and overriding royalty interests. We are not the operator of the wells from which we receive royalty payments and therefore, we are not able to control the timing of exploration or development efforts, or associated costs.
Through our subsidiary, CEVCO, we own production rights to approximately 460,000 acres in the Marcellus and Utica shale areas and have subleased the production rights in three storage fields and have also contributed our production rights in one other field. We do not currently operate any of these properties and do not have plans to develop the capacity to operate any of our properties. As owner of both non-operating working interests and overriding royalty interests, we are dependent on contract operators to develop our properties. Our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by our contract operators over which we have little or no control. Such decisions include:
• | the timing and amount of capital expenditures; |
• | the timing of initiating the drilling and recompleting of wells; |
• | the extent of operating costs; |
• | selection of technology and drilling and completion methods; and |
• | the rate of production of reserves, if any. |
If the royalty payments we receive from our sublessees are reduced, our ability to make cash distributions to our unitholders could be adversely affected.
Our revenues from CEVCO royalty interests will decrease if production on our sub-leased production rights declines, which would reduce the amount of cash we have available for distribution to our unitholders.
The amount of the royalty payments we receive on our sub-leased production rights depends in part on the amount of production on our properties. In addition, the royalty payments vary with the natural gas liquids and oil content of the production. For example, “dry gas” wells produce mainly natural gas, or methane, as opposed to “wet gas” wells, which produce methane along with other byproducts such as ethane, which may result in additional revenue streams from such production. During 2015 and 2014, natural gas prices remained relatively low, as well as a decrease in oil and natural gas liquids prices, leading some producers to announce significant reductions to their drilling plans. A significant reduction in the level of production on our properties could adversely affect on our ability to make distributions to our unitholders.
Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities and changes in these laws could have a material adverse effect on our results of operations.
Our natural gas transportation activities are subject to stringent and complex federal, state and local environmental laws and regulations. As with the industry generally, compliance with current and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade pipelines and other facilities. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; monitor for, limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment or replace aging pipelines and other facilities; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species; and incur potentially substantial new obligations or liabilities for any pollution or contamination that may result from our operations. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates PCBs at specific gas transmission facilities pursuant to a 1995 AOC (subsequently modified in 1996 and 2007) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs will cease on January 31, 2015. As of December 31, 2015, Columbia Gas Transmission has remaining $1.8 million to cover costs associated with PCB remediation related to this AOC.
Moreover, new, modified or stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our or our customer’s compliance costs, pollution mitigation costs, or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material. For example, in October 2015, the U.S. Environmental Protection Agency (“EPA”) issued a final rule under the federal Clean Air Act (“CAA”), lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations, which could apply to our or our customers’ operations. Compliance with this final rule could, among other things, require installation of new emission controls, result in longer permitting timelines, and significantly increase capital expenditures and operating costs. In another example, the EPA released a final rule in May 2015 that attempted to clarify federal jurisdiction under the Clean Water Act (“CWA”) over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the 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. Our compliance with such new or amended legal requirements could result in our incurring significant additional expense and operating restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers, to whom we provide our services, may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business.
In addition, a number of state and regional legal initiatives have emerged in recent years that seek to reduce greenhouse gas (“GHG”) emissions and require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources and onshore processing sources, such as emissions from gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations, in the U.S. on an annual basis. On an international level, the United States is one of almost 200 nations that agreed on December 12, 2015 to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets. It is not possible at this time to predict how or when the United States might impose legal requirements as a result of this international agreement. New regulations or any new federal laws restricting emissions of GHGs from our or our customer operations could result in increased compliance costs and delay or curtail activities that and, in turn, could adversely affect our business. Moreover, any such future laws and regulations that limit emissions of GHGs or that otherwise promote the use of renewable fuels could adversely affect demand for the natural gas our customers produce, which could thereby reduce demand for our services and adversely affect our business. In another example, the EPA has asserted limited regulatory authority over hydraulic fracturing, and has indicated it might seek to further expand its regulation of hydraulic fracturing while the U.S. Congress, certain state agencies, and some local governments have from time to time considered or adopted and implemented legal requirements that have imposed, and in the future could continue to impose, new or more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, which requirements could cause our customers to incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which subsequently could reduce demand for our transportation services.
In another example, pursuant to President Obama’s Strategy to Reduce Methane Emissions from the oil and gas sector by up to 45% from 2012 levels by 2025, in August 2015, the EPA proposed a suite of requirements and draft guidance related to the reduction in methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities, including proposed requirements for fugitive emissions of methane and new leak
detection and repair requirements. If finalized, these rules and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which costs, delays or curtailment could adversely affect our business.
Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial or compliance obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for noncompliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other impacts of our operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you. Please read “Business and Properties-Regulatory Matters” for more information.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline inspection, repair, or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:
• | perform ongoing assessments of pipeline integrity; |
• | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
• | improve data collection, integration and analysis; |
• | repair and remediate the pipeline as necessary; and |
• | implement preventive and mitigating actions. |
In addition, the DOT is examining the possibility of expanding integrity management principles beyond high consequence areas in addition to other potential requirements. For example, in March of 2015, the Pipeline Hazardous Materials Safety Administration (“PHMSA”) finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements related to maximum allowable operating pressure calculations. While we cannot predict the outcome of such future regulation at this time, new pipeline safety regulatory requirements could result in significant costs and have the potential to adversely impact our operations.
There may be additional costs associated with any other major repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. In addition, any additional regulatory requirements that are enacted could significantly increase the amount of these expenditures. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business and Properties-Regulatory Matters” for more information.
We may incur significant costs from time to time in order to comply with DOT regulations regarding the design, strength and testing of our pipelines if the population density near any particular portion of our pipelines increases beyond specified levels.
DOT regulations govern the design strength and testing of our pipelines. The required design strength and testing of the pipe depends upon the population density near the pipeline. In the event the population density around any specific section of our pipelines increases above levels established by the DOT, we may be required to upgrade the section of our pipelines traversing through the area with pipe of higher strength or, in some cases, retest the pipe, unless a waiver from the DOT is obtained. While the majority of our pipelines are located in remote areas, the possibility exists that we could be required to incur significant expenses in the future in response to increases in population density near sections of our pipelines.
We may incur significant costs and liabilities to comply with new DOT regulations that are anticipated to be issued in the future.
The NGPSA was amended on January 3, 2012 when the president signed the 2011 Pipeline Safety Act. The DOT issued an advanced notice of proposed rulemaking in August of 2011 that addressed approximately 15 specific topics associated with the legislation. The topics included the role of valves in mitigating consequences, metal loss evaluation and response, pressure testing to address manufacturing and construction threats, expanding integrity management principles, underground storage of natural gas and leak detection systems, among other topics. In addition, the DOT is working on other rulemaking topics such as operator verification
of records confirming the maximum allowable operating pressure of certain pipelines and integrity verification of previously untested pipelines or pipelines with other potential integrity issues, as well as others. There may be additional costs and liabilities associated with many of these pending future requirements. We continue to monitor regulatory developments associated with these pending regulations to help anticipate potential future operational and financial risks associated with the implementation of any new regulations.
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 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and Hazardous Liquid Pipeline Safety Act pipeline safety laws, requiring increased safety measures for natural gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification of records confirming the maximum allowable pressure of certain interstate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as well as any implementation of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto 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 be significant and have a material adverse effect on our results of operations or financial condition. For example, in October 2015, PHMSA issued an Advanced Notice of Proposed Rulemaking (“ANPR”) in which the agency seeks public comment on, among other things, extending reporting requirements to all gravity and gathering lines, requiring periodic inline integrity assessments of pipelines and that are located outside of high consequence areas, and requiring the use of leak detection systems on pipelines in all locations, including outside of high consequence areas. While the ANPR relates to the regulation of hazardous liquid lines, it is possible that PHMSA will propose additional requirements on gas pipelines in the future. In addition, legislation that would reauthorize federal pipeline safety programs through 2019, referred to as Securing America’s Future Energy: Protecting Infrastructure of Pipelines and Enhancing Safety (“SAFE PIPES”), was approved by the Senate Commerce Committee and will be considered by the U.S. Senate. Among other things, the SAFE PIPES legislation would require PHMSA to conduct an assessment of its inspection process and integrity management programs for natural gas and hazardous liquid pipelines. While we cannot predict the outcome of these initiatives or future legislative or regulatory efforts, new laws and regulations related to pipeline inspection and integrity management requirements have the potential to adversely impact our business. More recently, in February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators. The bulletin recommends that operators review operations to identify the potential for leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in piping, tubing, casing, valves, and other associated facilities. The bulletin further advises operators to review storage facility locations and operations of shut-off and isolation systems, and review and update emergency plans as necessary. Finally, the advisory directs compliance with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommends the voluntary implementation of certain industry-recognized recommended practices for natural gas storage facilities. PHMSA indicated when it issued the advisory bulletin that additional regulations related to safety standards for natural gas storage facilities are likely forthcoming. At this time, we cannot predict the impact of any future regulatory actions in this area.
Moreover, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas pipelines, which regulations may impose more stringent requirements than those found under federal law. Compliance with these rules and regulations can result in significant maintenance costs; however, at this time, we cannot predict the ultimate cost of such compliance. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in shut-downs, capacity constraints or operational limitations to our pipelines. Should any of these risks materialize, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Our natural gas transportation and storage operations are subject to extensive regulation by the FERC.
Our business operations are subject to extensive regulation by the FERC, including the types and terms of services we may offer to our customers, construction of new facilities, creation, modification or abandonment of services or facilities, recordkeeping and relationships with affiliated companies. Compliance with these requirements can be costly and burdensome and the FERC action in any of these areas could adversely affect our ability to compete for business, construct new facilities, offer new services or recover the full cost of operating our pipelines. This regulatory oversight can result in longer lead times to develop and complete any future project than competitors that are not subject to the FERC’s regulations. We cannot give any assurance regarding the
likely future regulations under which we will operate our natural gas transportation and storage business or the effect such regulation could have on our business, financial condition and results of operations.
Rate regulation could limit our ability to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions to you.
The rates we can charge for our natural gas transportation and storage operations are regulated by the FERC pursuant to the NGA. Under the NGA, we may only charge rates that have been determined to be just and reasonable by the FERC and are prohibited from unduly preferring or unreasonably discriminating against any person with respect to our rates or terms and conditions of service. The FERC establishes both the maximum and minimum rates we can charge. The basic elements that the FERC considers are the costs of providing service, the volumes of gas being transported or stored, the rate design, the allocation of costs between services, the capital structure and the rate of return a natural gas company is permitted to earn.
We may not be able to recover all of our costs through existing or future rates. Proposed rate increases may be challenged by protest and allowed to go into effect subject to refund. Even if a rate increase is permitted by the FERC to become effective, the rate increase may not be adequate. To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and obtain rate increases, our operating results would be negatively affected.
Our existing rates may be challenged by complaint or sua sponte by the FERC. In recent years, the FERC has exercised this authority with respect to several other pipeline companies. In a potential proceeding involving the challenge of our existing rates, the FERC may, on a prospective basis, order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. Any successful challenge against our rates could have an adverse impact on our revenues associated with providing transportation and storage services. In addition, future changes to laws, regulations and policies may impair our ability to recover costs and the ability to make distributions to you.
Certain of our gas pipeline services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.
Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated, cost-based recourse rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue as result of these “negotiated rate” contracts could decrease our cash flow.
We are exposed to costs associated with lost and unaccounted for volumes.
A certain amount of natural gas is naturally lost in connection with its transportation across a pipeline system, and under our contractual arrangements with our customers we are entitled to retain a specified volume of natural gas in order to compensate us for such lost and unaccounted for volumes as well as the natural gas used to run our compressor stations, which we refer to as fuel usage. The level of fuel usage and lost and unaccounted for volumes on our transmission and storage system and our gathering system may exceed the natural gas volumes retained from our customers as compensation for our fuel usage and lost and unaccounted for volumes pursuant to our contractual agreements. The FERC-approved tariffs of our transmission and storage companies provide for annual filings to adjust the amount of gas retained from customers to eliminate any overages or shortfalls from the prior year. Our gathering companies have contracts that provide for specified levels of fuel retainage, so they may find it necessary to purchase natural gas in the market to make up for the difference, which exposes us to commodity price risk. Future exposure to the volatility of natural gas prices as a result of gas imbalances on our gathering systems could have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly cash distributions to our unitholders.
We could be subject to penalties and fines if we fail to comply with FERC regulations.
Should the FERC find that we have failed to comply with all applicable FERC-administered statutes, rules, regulations, and orders, or the terms of our tariffs on file with the FERC, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005 (“EPAct 2005”), the FERC has civil penalty authority under the NGA and NGPA to impose penalties for violations of up to $1,000,000 per day for each violation, to revoke existing certificate authority and to order disgorgement of profits associated with any violation.
Certain of our assets may become subject to FERC regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of substantial litigation and the FERC currently determines whether facilities are gathering facilities on a case-by-case basis. Consequently, the classification and regulation of our gathering facilities could change based on future determinations
by the FERC, the courts or Congress. If more of our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
We do not own all of the land on which our pipelines and storage facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and storage facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use rights required to conduct our operations. We obtain the rights to construct and operate our pipelines and storage facilities on land owned by third parties and governmental agencies for a specific period of time. In certain instances, our rights-of-way may be subordinate to that of government agencies, which could result in costs or interruptions to our service. Restrictions on our ability to use our rights-of-way, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions to you.
Our operations are subject to operational hazards and unforeseen interruptions. If a significant accident or event occurs that results in a business interruption or shutdown for which we are not adequately insured, our operations and financial results could be materially adversely affected.
Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:
• | aging infrastructure, mechanical or other performance problems; |
• | damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism; |
• | inadvertent damage from third parties, including from construction, farm and utility equipment; |
• | leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; |
• | operator error; |
• | environmental hazards, such as natural gas leaks, product and waste spills, pipeline and tank ruptures, and unauthorized discharges of products, wastes and other pollutants into the surface and subsurface environment, resulting in environmental pollution; and |
• | explosions and blowouts. |
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations or services. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.
Debt that we or Columbia OpCo incur in the future may limit our or Columbia OpCo’s flexibility to obtain additional financing and to pursue other business opportunities.
As of December 31, 2015, we and our subsidiaries had $15 million in outstanding indebtedness under our $500 million credit facility, which is guaranteed by CPG, CEG, OpCo GP and Columbia OpCo. Additionally, Columbia OpCo and its subsidiaries have entered into an intercompany money pool agreement with CPG, with $750 million of reserved borrowing capacity. Columbia OpCo, CEG and OpCo GP guarantee CPG’s $1,500.0 million revolving credit facility, $2.75 billion in aggregate principal amount of CPG’s senior unsecured notes, CPG's commercial paper program and future CPG indebtedness if requested. Our existing and future level of debt, as well as Columbia OpCo’s future level of debt, could have important consequences to us, including the following:
• | our ability and Columbia OpCo’s ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
• | the funds that we or Columbia OpCo have available for operations and cash distributions to unitholders will be reduced by that portion of our and Columbia OpCo’s respective cash flow required to make principal and interest payments on outstanding debt; and |
• | our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally. |
Our ability to service our debt and Columbia OpCo’s 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. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.
Restrictions in our credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the value of our common units.
Our credit facility, or any future credit facility we or Columbia OpCo may enter into, is likely to limit our ability and Columbia OpCo’s ability to, among other things:
• | make distributions if any default or event of default occurs; |
• | make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests; |
• | incur additional indebtedness or guarantee other indebtedness; |
• | grant liens or make certain negative pledges; |
• | make certain loans or investments; |
• | engage in transactions with affiliates; |
• | transfer, sell or otherwise dispose of all or substantially all of our or Columbia OpCo’s assets; or |
• | enter into a merger, consolidate, liquidate, wind up or dissolve. |
Our credit facility may also contain covenants requiring us or Columbia OpCo to maintain certain financial ratios and tests. Our ability and Columbia OpCo’s ability to comply with the covenants and restrictions contained in our credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability and Columbia OpCo’s ability to comply with these covenants may be impaired. If we or Columbia OpCo violates any of the restrictions, covenants, ratios or tests in our credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, our lenders’ commitment to make further loans to us may terminate and Columbia OpCo will be prohibited from making any distribution to us and, ultimately, to you. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources.” Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.
The credit and risk profiles of our general partner and CPG, or Columbia OpCo’s guarantee of CPG debt, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
The credit and business risk profiles of our general partner and CPG, or Columbia OpCo’s guarantee of CPG debt, may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of CPG, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.
If we seek a credit rating in the future, our credit rating may be adversely affected by our guarantee of CPG debt and the leverage of our general partner or CPG, as credit rating agencies such as Standard & Poor’s Ratings Services and Moody’s Investors Service may consider the leverage and credit profile of CPG and its respective affiliates because of its ownership interest in and control of us and the strong operational links between CPG and us. Any adverse effect on our credit rating could increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which could impair our ability to grow our business and make distributions to unitholders.
There can be no assurance that we will be able to access the capital markets on acceptable terms.
From time to time, we will need to access the capital markets to obtain equity or long-term or short-term debt financing. Although we believe that the sources of capital currently in place will permit us to finance our near-term operations on acceptable terms and conditions, our access to, and the availability of, financing on acceptable terms and conditions in the future will be impacted by many factors, including, without limitation: (1) our financial performance, (2) the liquidity of the overall capital markets, (3) the terms of our outstanding debt, and (4) the state of the economy. There can be no assurance that we will have access to the capital markets on terms acceptable to us or at all.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available for distribution could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines. For example, our pipelines interconnect with virtually every major interstate pipeline in the eastern portion of the U.S. and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these pipeline connections were to become unavailable for current or future volumes of natural gas due to repairs, damage, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnect which causes a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to you.
The current Columbia Gulf and Columbia Gas Transmission pipeline infrastructure is aging, which may adversely affect our business, results of operations, financial condition and ability to make distributions.
The Columbia Gulf and Columbia Gas Transmission pipeline systems have been in operation for many years, with some portions of these pipelines being more than 50 years old. Segments of the Columbia Gulf and Columbia Gas Transmission pipeline systems are located in or near areas determined to be high consequence areas. We implement integrity management testing of the pipelines that we operate, including the Columbia Gulf and Columbia Gas Transmission pipelines, and we repair, remediate or replace segments on those pipelines as necessary when anomaly conditions are identified during the integrity testing process or are determined to have occurred during the course of operations. Nonetheless, we also are currently investing significant capital over the next several years to replace aging infrastructure, including replacement of the relatively older pipe found on the Columbia Gulf and Columbia Gas Transmission systems. If, due to their age, these pipeline sections were to become unexpectedly unavailable for current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could result in a material adverse impact on our business, financial condition and results of operation as well as our ability to make distributions to our unitholders.
LNG export terminals may not be developed in the Gulf Coast region or may be developed outside our areas of operations.
We are in the process of reversing the flow of the Columbia Gulf pipeline system in order to supply new and developing LNG export facilities located along the Gulf Coast. However, we may not realize expected increases in future natural gas demand from LNG exports due to factors including:
• | new projects may fail to be developed; |
• | new projects may not be developed at their announced capacity; |
• | development of new projects may be significantly delayed; |
• | new projects may be built in locations that are not connected to our system; or |
• | new projects may not influence sources of supply on our system. |
Similarly, the development of new, or the expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas on our assets. This could reduce the amount of natural gas transported by our pipeline.
We are exposed to counterparty risk. Commitment termination or nonperformance by our vendors, lenders or derivative counterparties could materially reduce our revenue, impair our liquidity, increase our expenses or otherwise negatively impact our results of operations, financial position or cash flows and our ability to pay cash distributions.
We utilize third-party vendors to provide various functions, including, for example, certain construction activities, engineering services, facility inspections and operation of certain software systems. Using third parties to provide these functions has the effect of reducing our direct control over the services rendered. The failure of one or more of our third-party providers to deliver the expected services on a timely basis, at the prices we expect and as required by contract could result in significant disruptions, costs
to our operation or instances of a contractor’s non-compliance with applicable laws and regulations, which could materially adversely affect our business, financial condition, operating results and cash flows.
We also rely to a significant degree on the banks that lend to us under our revolving credit facility for financial liquidity, and any failure of those banks to perform on their obligations to us could significantly impair our liquidity. Furthermore, nonpayment by the counterparties to our interest rate and commodity derivatives could expose us to additional interest rate or commodity price risk.
Any take-or-pay commitment terminations or substantial increase in the nonperformance by our vendors, lenders or derivative counterparties could have a material adverse effect on our results of operations, financial position and cash flows and our ability to pay cash distributions.
If we are unable to make acquisitions from our sponsor or third parties on economically acceptable terms, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.
Our strategy to grow our business and increase distributions to unitholders is dependent on our ability to make acquisitions that result in an increase in our cash available for distribution per unit. If we are unable to make acquisitions of additional interests in Columbia OpCo from CEG on acceptable terms, or we are unable to obtain financing for these acquisitions on economically acceptable terms, our future growth and ability to increase distributions will be limited. In addition, we may be unable to make acquisitions from third parties as an alternative avenue to growth. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in our cash available for distribution per unit. Any acquisition involves potential risks, some of which are beyond our control, including, among other things:
• | mistaken assumptions about revenues and costs, including synergies; |
• | the inability to successfully integrate the businesses we acquire; |
• | the inability to hire, train or retain qualified personnel to manage and operate our business and newly acquired assets; |
• | the assumption of unknown liabilities; |
• | limitations on rights to indemnity from the seller; |
• | mistaken assumptions about the overall costs of equity or debt; |
• | the diversion of management’s attention from other business concerns; |
• | unforeseen difficulties in connection with operating in new product areas or new geographic areas; and |
• | customer or key employee losses at the acquired businesses. |
If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our funds and other resources.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the U.S., whether or not targeted at our assets or the assets of our customers, could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from customers or disruptions of fuel supplies and markets if domestic and global utilities are direct targets or indirect casualties of an act of terror or war. Terrorist activities and the threat of potential terrorist activities and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.
A failure in Columbia OpCo’s computer systems or a cyber-attack on any of its facilities or any third parties’ facilities upon which Columbia OpCo relies may adversely affect its ability to operate.
Columbia OpCo relies on technology to run its businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of its business, including the operation of its gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of Columbia OpCo’s computer systems, or those of its customers, suppliers or others with whom it does
business, could materially disrupt Columbia OpCo’s ability to operate its businesses and could result in a financial loss and possibly do harm to Columbia OpCo’s reputation.
Additionally, Columbia OpCo’s information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach Columbia OpCo’s cyber-defenses. Although Columbia OpCo attempts to maintain adequate defenses to these attacks and works through industry groups and trade associations to identify common threats and assess Columbia OpCo’s countermeasures, a security breach of Columbia OpCo’s information systems could (i) impact the reliability of Columbia OpCo’s transmission and storage systems and potentially negatively impact Columbia OpCo’s compliance with certain mandatory reliability standards, (ii) subject Columbia OpCo to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to Columbia OpCo’s customers or employees or (iii) impact Columbia OpCo’s ability to manage its businesses.
Sustained extreme weather conditions and climate change may negatively impact Columbia OpCo’s operations.
Columbia OpCo conducts its operations across a wide geographic area subject to varied and potentially extreme weather conditions, which may from time to time persist for sustained periods of time. Despite preventative maintenance efforts, persistent weather related stress on Columbia OpCo’s infrastructure may reveal weaknesses in its systems not previously known to it or otherwise present various operational challenges across all business segments. Although Columbia OpCo makes every effort to plan for weather related contingencies, adverse weather may affect its ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. Columbia OpCo endeavors to minimize such service disruptions, but may not be able to avoid them altogether.
There is also a concern that climate change may exacerbate the risks to physical infrastructure arising from significant physical effects, such as increased severity and frequency of storms, droughts and floods as well as associated with heat and other extreme weather conditions. Climate change and the costs that may be associated with its impacts have the potential to affect Columbia OpCo’s business in many ways, including increasing the cost Columbia OpCo incurs in providing its products and services, impacting the demand for and consumption of its products and services (due to change in both costs and weather patterns), and affecting the economic health of the regions in which Columbia OpCo operates.
Growing competition in the gas transportation and storage industries could result in the failure by customers to renew existing contracts.
As a consequence of the increase in competition and the shift in natural gas production areas, customers such as LDCs and other end users may be reluctant to enter into long-term service contracts. The renewal or replacement of existing contracts with Columbia OpCo’s customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond its control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. The inability of Columbia OpCo to renew or replace its current contracts as they expire and respond appropriately to changing market conditions could materially impact its financial results and cash flows.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse impact on Columbia OpCo’s operations.
Our business is dependent on CEG’s and our general partner’s ability to attract, retain and motivate employees. Competition for skilled employees in some areas is high and CEG and our general partner may experience difficulty in recruiting and retaining employees following the Separation. The inability to recruit and retain these employees could adversely affect our business and future operating results. CEG seeks to mitigate some of this risk by training its management on how to attract and select the needed talent and also measures its level of employee engagement annually, developing action plans where necessary to improve CEG’s workplace, but there is no assurance that such mitigation measures will be effective.
Columbia OpCo’s insurance policies do not cover all losses, costs or liabilities that it may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
Columbia OpCo’s assets are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes certain pollution liabilities. All of the insurance policies relating to Columbia OpCo’s assets and operations are subject to policy limits and deductibles. In addition, the waiting period under the business interruption insurance policies is 30 days. Columbia OpCo does not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and Columbia OpCo may elect to self-insure portions of its asset portfolio. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on Columbia OpCo’s business, financial condition and results of operations. Insurance
companies may reduce the insurance capacity they are willing to offer or may demand significantly higher premiums to cover Columbia OpCo’s assets and operations. If significant changes in the number or financial solvency of insurance companies for the energy industry occur, Columbia OpCo may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of full insurance coverage to cover events in which Columbia OpCo suffers significant losses could have a material adverse effect on our business, financial condition and results of operation, and therefore on our ability to pay cash distributions.
Adverse economic and market conditions or increases in interest rates could reduce net revenue growth, increase costs, decrease future net income and cash flows and impact capital resources and liquidity needs.
While the national economy is experiencing some recovery from the recent downturn, we cannot predict how robust the recovery will be or whether or not it will be sustained.
Continued sluggishness in the economy impacting our operating jurisdictions could adversely impact our ability to grow our customer base and collect revenues from customers, which could reduce net revenue growth and increase operating costs. An increase in the interest rates we pay would adversely affect future net income and cash flows. In addition, we depend on debt to finance our operations, including both working capital and capital expenditures, and would be adversely affected by increases in interest rates. As of December 31, 2015, we had $15 million in outstanding indebtedness, all of which will be subject to variable interest rates.
If the current economic recovery remains slow or credit markets again tighten, our ability to raise additional capital or refinance debt at a reasonable cost could be negatively impacted.
Capital market performance and other factors may decrease the value of benefit plan assets, which then could require significant additional funding and impact earnings.
The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuations and may yield uncertain returns, which fall below our projected rates of return. A decline in the market value of assets may increase the funding requirements of the obligations under the defined benefit pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under these benefit plans; as interest rates decrease, the liabilities increase, which could potentially increase funding requirements. Further, the funding requirements of the obligations related to these benefits plans may increase due to changes in governmental regulations and participant demographics, including increased numbers of retirements or changes in life expectancy assumptions. Ultimately, significant funding requirements and increased pension expense could negatively impact our results of operations and financial condition.
We have significant goodwill and definite-lived intangible assets. An impairment of goodwill or definite-lived intangible assets could result in a significant charge to earnings.
In accordance with GAAP, we test goodwill for impairment at least annually and review our definite-lived intangible assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill also is tested for impairment when factors, examples of which include reduced cash flow estimates, a sustained decline in unit price or market capitalization below book value, indicate that the carrying value may not be recoverable. We would be required to record a charge in the financial statements during the period in which any impairment of the goodwill or definite-lived intangible assets is determined, negatively impacting the results of operations. A significant charge could impact the capitalization ratio covenant under certain financing agreements. We are subject to a financial covenant under our credit facilities which requires CPG and the MLP to maintain a total quarterly leverage ratio that does not exceed a ratio of 5.00 to 1.00 until December 31, 2017 and 5.00 to 1.00 for any quarterly period thereafter, with some exceptions. Also, CPG and the MLP are required to maintain a consolidated interest coverage ratio of no less than 3.00 to 1.00. As of December 31, 2015, our quarterly leverage ratio was 3.64 to 1.00 and our consolidated interest coverage ratio was 13.3 to 1.00.
Our sponsor owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including our sponsor, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.
As of December 31, 2015, our sponsor owns a 46.5% limited partner interest in us and controls our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to our sponsor. Therefore, conflicts of interest may arise between our sponsor or any of its affiliates, including our general partner, on the one hand, and us or any of our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests
and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:
• | our general partner is allowed to take into account the interests of parties other than us, such as our sponsor, in exercising certain rights under our partnership agreement; |
• | neither our partnership agreement nor any other agreement requires our sponsor to pursue a business strategy that favors us; |
• | our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duties; |
• | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
• | our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of reserves, each of which can affect the amount of cash that is distributed to our unitholders; |
• | our general partner determines the amount and timing of any cash expenditure and whether an expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash from operating surplus that is distributed to our unitholders which, in turn, may affect the ability of the subordinated units to convert into common units; |
• | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; |
• | in determining whether to request a guarantee from Columbia OpCo, CPG may elect to act in a manner that protects CPG’s credit rating or credit availability to our detriment or to the detriment of Columbia OpCo, or may take actions that increase the risk that CPG would default on its debt obligations and therefore increase the likelihood that the Columbia OpCo guarantee would be called on; |
• | our partnership agreement permits us to distribute up to $62 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights; |
• | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
• | 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 its affiliates 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 common units if it and its affiliates own more than 80% of the common units; |
• | our general partner controls the enforcement of obligations that it and its affiliates owe to us; |
• | our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and |
• | CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to CEG’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the unitholders. This election may result in lower distributions to the common unitholders in certain situations. |
In addition, we may compete directly with our sponsor and entities in which it has an interest for acquisition opportunities and potentially will compete with these entities for new business or extensions of the existing services provided by us.
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.
Pursuant to our cash distribution policy we intend to distribute quarterly at least $0.1675 per unit on all of our units to the extent we have sufficient cash after the establishment of cash reserves and the payment of our expenses, including payments to our general partner and its affiliates. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters.
In addition, our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our unitholders, which may permit it to favor its own interests or the interests of our sponsor to the detriment of our common unitholders.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.
We expect to distribute a significant portion of our cash available for distribution to our partners, which could limit our ability to grow and make acquisitions.
We expect to distribute most of our cash available for distribution, which may cause our growth to proceed at a slower pace than that of businesses that reinvest their cash to expand ongoing operations. To the extent we issue additional common units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units 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 units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the cash that we have available to distribute to our unitholders.
If you are not an Eligible Holder, your common units may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are limited partners or types of limited partners (a) whose, or whose owners’, U.S. federal income tax status does not, in the determination of our general partner, create or is not reasonably likely to create substantial risk of an adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or a similar regulatory body, as determined by our general partner with the advice of counsel or (b) whose nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest, as determined by our general partner with the advice of counsel. If you are not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, your units may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Our partnership agreement replaces our general partner’s fiduciary duties to us and holders of our units.
Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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, or otherwise free of fiduciary 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. Examples of decisions that our general partner may make in its individual capacity include:
• | how to allocate business opportunities among us and its affiliates; |
• | whether to exercise its call right; |
• | how to exercise its voting rights with respect to the units it owns; |
• | whether to exercise its registration rights; |
• | whether to elect to reset target distribution levels; and |
• | whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. |
By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above.
Our partnership agreement restricts the remedies available to us and holders of our units 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 generally required to make such determination, or take or decline to take such other action, not in bad faith, meaning that they did not believe that the decision was adverse to the interest of the partnership, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; |
• | 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 such losses or liabilities were the result of conduct in which our general partner or its officers or directors engaged in bad faith, meaning that they believed that the decision was adverse to the interest of the partnership, or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and |
• | our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is: |
(1) | approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or |
(2) | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates. |
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, any determination by our general partner must not be made in bad 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 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. Any matters approved by the conflicts committee will be conclusively deemed approved by all of our partners and not a breach by our general partner of any duties it may owe us or our common unitholders.
Our sponsor and other affiliates of our general partner may compete with us.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory, and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including our sponsor, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, our sponsor may compete with us for investment opportunities and may own an interest in entities that compete with us.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and our sponsor. 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. 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.
CEG may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.
CEG has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and we have made cash distributions in excess of the then-applicable third target distribution for each of the prior four consecutive fiscal quarters and the aggregate amount of cash distributions during such four-quarter period does exceed adjusted operating surplus generated during such four-quarter period, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset the minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.
If CEG elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to CEG will equal the number of common units that would have entitled the holder to an aggregate quarterly cash distribution for the quarter prior to the reset election equal to the distribution on the incentive distribution rights for the quarter prior to the reset election. We anticipate that CEG would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that CEG could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights are transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. CEG may transfer all or a portion of the incentive distribution rights in the future. After any such transfer, the holder or holders of a majority of our incentive distribution rights will be entitled to exercise the right to reset the target distribution levels.
The market price of our common units may fluctuate significantly
The market price of our common units may fluctuate significantly, depending on many factors, some of which may be beyond our control, including:
• | a shift in our investor base; |
• | our quarterly or annual earnings, or those of other companies in our industry; |
• | actual or anticipated fluctuations in our operating results; |
• | our payment of distributions, if any; |
• | success or failure of our business strategy; |
• | our ability to obtain financing as needed; |
• | changes in accounting standards, policies, guidance, interpretations or principles; |
• | changes in laws and regulations affecting our business; |
• | announcements by us or our competitors of significant acquisitions or dispositions; |
• | the failure of securities analysts to cover our common units; |
• | changes in earnings estimates by securities analysts or our ability to meet our earnings guidance; |
• | the operating and stock price performance of other comparable companies; |
• | future sales of our common units; and |
• | overall market fluctuations and general economic conditions. |
Stock markets in general have also experienced volatility that has often been unrelated to the operating performance of a particular company. These broad market fluctuations could negatively affect the trading price of our common units.
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’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 will be the exclusive forum for any claims, suits, actions or proceedings (1) 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 limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty owed by any director, officer or other employee of our general partner, or owed by our general partner, to us or the limited partners, (4) asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) or (5) asserting a claim against us governed by the internal affairs doctrine. In addition, if any unitholder brings any of the aforementioned claims, suits, actions or proceedings 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. By purchasing a common unit, a unitholder is irrevocably consenting to these limitations, provisions and potential reimbursement obligations 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’s directors and officers.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.
Compared to the holders of common stock in a corporation, unitholders have limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by our sponsor, as a result of it owning our general partner, and not by our unitholders. Unlike publicly traded corporations, we do conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
If our unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of December 31, 2015, our sponsor owned an aggregate of 46.5% of our common and subordinated units. In addition, any vote to remove our general partner during the subordination period must provide for the election of a successor general partner by the holders of a majority of the common units and a majority of the subordinated units, voting as separate classes. This provides our sponsor the ability to prevent the removal of our general partner.
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 to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests 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 executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.
The incentive distribution rights may be transferred to a third party without unitholder consent.
CEG may transfer the incentive distribution rights to a third party at any time without the consent of our unitholders. If CEG transfers the incentive distribution rights to a third party, CEG would not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time. For example, a transfer of incentive distribution rights by CEG could reduce the likelihood of it accepting offers made by us relating to assets owned by CEG, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.
Our general partner has a limited call right that may require 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 the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As of December 31, 2015, our sponsor owned an aggregate of 46.5% of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our sponsor will own 46.5% of our common units.
We may issue additional units without unitholder approval, which would dilute existing unitholder ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity interests of equal or senior rank may have the following effects:
• | our existing unitholders’ proportionate ownership interest in us will decrease; |
• | the amount of cash available for distribution on each unit may decrease; |
• | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
• | the ratio of taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding unit may be diminished; and |
• | the market price of the common units may decline. |
There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.
In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and 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’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.
Our partnership agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, 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.
Cost reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our general partner.
We are obligated under our partnership agreement to reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses 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. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash available for distribution to our unitholders.
Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of 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 interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded partnership, the NYSE 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. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. 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 federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to you. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation 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.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S. federal, state, local or foreign income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied 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 changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
In addition, the Internal Revenue Service, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.
Any modification to the U.S. federal income tax laws may be applied retroactively 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 of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.
Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.
Even if you do not receive any cash distributions from us, you are required to pay taxes on your share of our taxable income.
You are required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons 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 (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, are unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal tax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
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 for other reasons, we have adopted depreciation and amortization positions that 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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular 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 prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention
for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter. If the IRS were to 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 units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those 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 units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those 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, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those 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 are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, which could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. CEG indirectly owns 46.5% of the total interests in our capital and profits. Therefore, a transfer by CEG of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.
Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs.
You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, you 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 own property now or in the future, even if you do not live in any of those jurisdictions. We own assets and conduct business in several states, each of which currently imposes a personal income tax and also imposes income taxes on corporations and other
entities. You may be required to file state and local income tax returns and pay state and local income taxes in these states. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.