Attached files
| file | filename |
|---|---|
| 10-K - 10-K - CPG OpCo LP | opcolp-2016123110k.htm |
| EX-32.2 - EXHIBIT 32.2 - CPG OpCo LP | opcolp-20161231xex322.htm |
| EX-32.1 - EXHIBIT 32.1 - CPG OpCo LP | opcolp-20161231xex321.htm |
| EX-31.2 - EXHIBIT 31.2 - CPG OpCo LP | opcolp-20161231xex312.htm |
| EX-31.1 - EXHIBIT 31.1 - CPG OpCo LP | opcolp-20161231xex311.htm |
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
RISK FACTORS
Our business, results of operations, cash flows and financial condition are subject to a number of risks and uncertainties. You should carefully consider the risks and uncertainties described below, together with all of the other information in this Form 10-K. The risks and uncertainties we face are not limited to those described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially adversely affect our business, results of operations, cash flows and financial condition. This Form 10-K also contains forward-looking statements that involve risks and uncertainties. You should carefully read the section entitled “Cautionary Note Concerning Forward-Looking Statements” on page 6 of this Form 10-K.
If any of the following risks were to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, the value of the Notes could decline and you could lose all or part of your investment.
We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium (if any), and interest on our indebtedness, including the notes.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, or to sell assets, seek additional capital or restructure or refinance our indebtedness, including the notes. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments and the indenture governing the notes may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.
We may be subject to class action lawsuits relating to the CPPL Merger, which could materially adversely affect our business, financial condition and operating results.
Our directors and officers may be subject to class action lawsuits relating to the CPPL Merger and other additional lawsuits that may be filed. Such litigation is very common in connection with acquisitions of public companies, regardless of any merits related to the underlying acquisition. While we will evaluate and defend against any actions vigorously, the costs of the defense of such lawsuits and other effects of such litigation could have an adverse effect on our business, financial condition and operating results.
One of the conditions to consummating the CPPL Merger is that no injunction or other order prohibiting or otherwise preventing the consummation of the CPPL Merger transactions shall have been issued by any court or governmental entity of competent jurisdiction in the United States. Consequently, if any lawsuit is filed challenging the CPPL Merger and is successful in obtaining an injunction preventing the parties to the CPPL Merger Agreement from consummating the CPPL Merger, such injunction may prevent the CPPL Merger from being completed in the expected timeframe, or at all.
Expansion projects that are expected to be accretive may nevertheless reduce our cash from operations.
Even if we complete expansion projects that we believe will be accretive, these expansion projects may nevertheless reduce our cash from operations. 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; |
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
• | 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. |
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 and growth plans.
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 and growth plans.
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.
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 from such project 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 shale area. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
A substantial portion of our 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 our 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 our revenue streams, and (ii) binding precedent agreements, which are subject to certain conditions to their effectiveness, which, if not satisfied, would enable either us 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 and results of operations.
Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results.
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. 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.
We receive cash from royalty payments 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:
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
• | 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 business and financial condition could be adversely affected.
Our revenues from CEVCO royalty interests will decrease if production on our subleased production rights declines, which could adversely affect our business and operation results.
The amount of the royalty payments we receive on our subleased 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 2016 and 2015, 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 our business and operation results.
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 polychlorinated biphenyls (“PCBs”) at specific gas transmission facilities pursuant to a 1995 Administrative Order on Consent (subsequently modified in 1996 and 2007) (“AOC”) and recovers a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these costs ceased on January 31, 2015. As of December 31, 2016, Columbia Gas Transmission had remaining liabilities of $1.5 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, revisions to the National Ambient Air Quality Standard (“NAAQS”) for ozone to may result in the addition of non-attainment designations in additional counties in which our pipeline systems operates, which could result in additional permitting delays, capital expenditures and operating costs to our and our customers’ operations. 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.
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 investigatory, remedial or corrective action obligations or the incurrence of capital expenditures, the occurrence of delays in the permitting or performance or expansion of projects and the issuance of injunctions limiting or preventing some or all of our operations in a particular area. 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
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
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 non-compliance, 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 and financial condition.
Current and future emissions regulation legislation or regulations restricting emissions of GHG could result in increased operating costs.
There have been a number of legislative initiatives to regulate GHG emissions; however, substantial uncertainty exists regarding the impact of new and proposed GHG laws and regulations. Moreover, implementation of GHG regulations is the subject of significant litigation which has created uncertainty in compliance requirements with both the regulatory agencies and industry. Recent federal rulemakings have focused on the emission of methane. For example, in June 2016, the EPA published New Source Performance Standards, known as Subpart Quad OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New Source Performance Standards published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. Moreover, in November 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from existing facilities and operators in the oil and natural gas industry that the agency may potentially use to develop guidelines that the states must consider in developing their own rules for regulating sources within their borders. EPA has indicated that this information may also be used to develop standards for certain kinds of new and modified equipment and facilities not currently covered under Subpart OOOOa. Furthermore, the EPA has passed a rule, known as the Clean Power Plan, to limit GHGs from power plants but in February 2016, the U.S. Supreme Court stayed this rule while it is being challenged in the federal D.C. Circuit Court of Appeals. If this rule survives legal challenge, then depending on the methods used to implement this rule, it could increase demand for the oil and natural gas our customers produce or increase the cost of electricity for our operations. While we do not believe that compliance with the new Subpart OOOOa regulations will have a material adverse effect on our operations, we cannot estimate the effect of proposed and final regulations, and industry litigation related to the control of GHG emissions on our future financial position, results of operations or cash flow. However, such legislation, regulation and litigation could materially increase their operating costs, including their cost of environmental compliance. Given the uncertainty of policy and regulatory schemes, the future effects on our pipelines cannot be predicted.
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 United States Department of Transportation (“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, on March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things, expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain as few as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures; and requiring certain onshore and offshore gathering lines in Class I areas to comply with damage prevention, corrosion control, public education, operating pressure limits, line markers and emergency planning standards. Additional requirements proposed by this proposed rulemaking would increase PHMSA’s integrity management requirements for natural gas pipelines and also require consideration of seismicity in evaluating threats to pipelines.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
We continue to evaluate the impact of many PHMSA initiatives and mandates. At this time, we cannot predict the ultimate impact of this legislation on our operations; however, the adoption of any new legislation or regulations regarding increased pipeline safety could cause us to incur increased capital and operating costs, which costs could be significant.
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.
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.
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 Natural Gas Pipeline Safety Act (“NGPSA”) was amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed 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 natural gas transmission pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the "2016 Pipeline Safety Act”) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Act and developing new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of natural gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act as further amended by the 2016 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.
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 and financial condition. In February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators. The bulletin recommended 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 advised 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 directed compliance with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommended the voluntary implementation of certain industry-recognized recommended practices for natural gas storage facilities. More recently, in December 2016, PHMSA issued an interim final rule that revises federal pipeline safety regulations to address safety issues related to downhole facilities, including well integrity, wellbore tubing, and casing. Pursuant to the interim rule, PHMSA incorporates by reference into its rules the American Petroleum Institute’s Recommended Practices for the design and operation of solution-mined salt caverns used for natural gas storage, and functional integrity of natural gas storage in depleted hydrocarbon reservoirs and aquifer
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
reservoirs. PHMSA indicated when it issued the interim final rule that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. At this time, we cannot predict the impact of any future regulatory actions in this area.
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. FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce. 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.
Compliance with these requirements can be costly and burdensome and 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.
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.
On December 15, 2016, FERC issued a Notice of Inquiry requesting energy industry input on how FERC should address income tax allowances in cost-based rates proposed by pipeline companies organized as part of a master limited partnership. FERC’s current policy on income tax allowance permits an income tax allowance in cost-based rates proposed by such pipeline companies to the extent the pipeline companies can show an actual or potential income tax liability to be paid on income generated by the companies’ FERC-regulated assets. FERC issued the Notice of Inquiry in response to a remand from the U.S. Court of Appeals for the D.C. Circuit in United Airlines v. FERC, a case involving an oil pipeline organized as a partnership. In that case, the D.C. Circuit determined that FERC had not justified its conclusion that there was no double recovery of taxes by the oil pipeline when FERC granted the pipeline a tax allowance in its cost-based rates and at the same time set a return on equity underlying the cost-based rates on a pre-tax basis. We cannot predict whether FERC will successfully justify its conclusion that there is no double recovery of taxes under these circumstances or whether FERC will modify its current policy on income tax allowances for pipeline companies organized as part of a master limited partnership. However, any modification that reduces or eliminates an income tax allowance for pipeline companies organized as a part of a master limited partnership or decreases the return on equity for such pipeline companies could result in an adverse impact on our revenues associated with the transportation and storage services we provide pursuant to cost-based rates.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
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 and results of operations.
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 approximately $1.2 million 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.
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; |
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
• | 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.
Our existing indebtedness and debt that we incur in the future may limit our flexibility to obtain additional financing and to pursue other business opportunities.
As of December 31, 2016, we and our subsidiaries had $2.75 billion in outstanding indebtedness, comprised of our senior notes (the “Notes”).
Our existing and future level of debt, could have important consequences to us, including the following:
• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
• | the funds that we have available for operations will be reduced by that portion of our 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, including the notes, 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 facilities 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 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.
Deterioration in our credit profile could increase our costs of borrowing money, adversely affect our business relationships and limit our access to the capital markets and commercial credit.
We currently have an investment grade credit rating from Standard & Poor’s Rating Service (S&P), Moody’s Investor Service (Moody's) and Fitch Ratings. Our parent, TCPL, currently has an investment grade rating from S&P, Moody's and DBRS Limited. However, our credit ratings and those of our parent could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our or our parent's rating below investment grade, our borrowing costs would increase and our funding sources could decrease. In addition, a failure to maintain an investment grade credit rating could affect our business relationships with suppliers and operating partners. A downgrade of our or our parent's credit ratings could also adversely affect the availability and cost of capital needed to fund the growth investments that are a central element of our long-term business strategy.
If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues 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 United States and a significant number of intrastate pipelines. Because we do not own these third-party pipelines or facilities, their continuing operation is not
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
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 and financial condition.
The current Columbia Gulf and Columbia Gas Transmission pipeline infrastructure is aging, which may adversely affect our business, results of operations and financial condition.
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.
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.
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 commercial paper program and 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.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
If we are unable to make acquisitions 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.
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 earnings. 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 bondholders 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 United States, 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 our computer systems or a cyber-attack on any of our facilities or any third parties’ facilities upon which we rely may adversely affect our ability to operate.
We rely on technology to run our businesses, which depend on financial and operational computer systems to process information critically important for conducting various elements of our business, including the operation of our gas pipelines and storage facilities and the recording and reporting of commercial and financial transactions to regulators, investors and other stakeholders. Any failure of our computer systems, or those of our customers, suppliers or others with whom we do business, could materially disrupt our ability to operate our businesses and could result in a financial loss and possibly do harm to our reputation.
Additionally, our information systems experience ongoing, often sophisticated, cyber-attacks by a variety of sources with the apparent aim to breach our cyber-defenses. Although we attempt to maintain adequate defenses to these attacks and work through industry groups and trade associations to identify common threats and assess our countermeasures, a security breach of our information systems could (i) impact the reliability of our transmission and storage systems and potentially negatively impact our compliance with certain mandatory reliability standards, (ii) subject us to harm associated with theft or inappropriate release of certain types of information such as system operating information, personal or otherwise, relating to our customers or employees or (iii) impact our to manage our businesses.
Sustained extreme weather conditions and climate change may negatively impact our operations.
We conduct our 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 our infrastructure may reveal weaknesses in our systems not previously known to us or otherwise present various operational challenges across all business segments. Although we make every effort to plan for weather-related contingencies, adverse weather
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
may affect our ability to conduct operations in a manner that satisfies customer expectations or contractual obligations. We endeavor 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 our business in many ways, including increasing the costs we incur in providing our products and services, impacting the demand for and consumption of our products and services (due to changes in both costs and weather patterns), and affecting the economic health of the regions in which we operate.
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 our customers at rates sufficient to maintain current or projected revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines and gatherers, the proximity of supplies to the markets, and the price of, and demand for, natural gas. Our inability to renew or replace our current contracts as they expire and respond appropriately to changing market conditions could materially impact our financial results and cash flows.
Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.
Our assets are insured for certain property damage, business interruption, and third-party liabilities, which includes certain pollution liabilities. All of the insurance policies relating to our assets and operations are subject to policy limits and deductibles including the waiting period under business interruption insurance. We do 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. The occurrence of an event that is not fully covered by insurance, the unavailability of insurance coverage, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our 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 our assets and operations. If significant changes in the number or financial solvency of insurance companies for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost.
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, 2016, we had $2.75 billion in outstanding indebtedness, none of which is 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 could result in additional funding and impact earnings.
The performance of capital markets affects the value of assets held in trust to satisfy future obligations under defined benefit pension and other postretirement benefit plans. These assets are invested in financial instruments (i.e. equities and fixed income securities) subject to market fluctuations which may yield uncertain returns, including falling below our projected rates of return. A decline in the market value of assets may increase our funding requirements. Additionally, changes in interest rates are inversely related to liabilities. In particular, as interest rates decrease, liabilities increase, potentially increasing funding requirements. Other factors that could impact funding requirements include changes in government regulations and participant demographics (i.e. increased pace of retirements or changes in life expectancy assumptions). Ultimately, higher funding requirements and pension expense could negatively impact our results of operations and financial condition.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
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 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.
If the Distribution were to fail to qualify as tax-free for U.S. federal income tax purposes, then NiSource could be subject to significant tax liability, and we could be required to indemnify NiSource for all or a portion of such liability.
NiSource received an opinion from its counsel, Sidley Austin LLP, confirming the tax-free status of the Distribution. NiSource’s receipt of the opinion was a condition to the completion of the Distribution. The opinion was based upon various factual representations and assumptions, as well as certain undertakings made by us and NiSource. If any of those factual representations or assumptions are untrue or incomplete in any material respect, any undertaking is not complied with, or the facts upon which the opinion was based are materially different from the facts at the time of the Distribution, the Distribution may not qualify for tax-free treatment. Opinions of counsel are not binding on the Internal Revenue Service (“IRS”) or the courts. As a result, the conclusions expressed in an opinion of counsel could be challenged by the IRS, and if the IRS prevails in such challenge, the tax consequences to you could be materially less favorable.
If the Distribution ultimately is determined to be taxable, the Distribution could be treated as a taxable dividend to stockholders who received our stock in the Distribution or cause them to recognize taxable capital gain for U.S. federal income tax purposes. Those prior stockholders could incur significant U.S. federal income tax liabilities. In addition, NiSource would recognize gain in an amount equal to the excess of the fair market value of the shares of our common stock distributed to NiSource stockholders on the Distribution Date over NiSource’s tax basis in such shares as of such date.
In addition, under the terms of the Tax Allocation Agreement that we entered into in connection with the Distribution (as described under Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements” of this Form 10-K), in the event that the Distribution were determined to be taxable as the result of actions taken after the Distribution by us or any of our subsidiaries, we would be responsible for all taxes imposed on NiSource as a result thereof. In addition, in the event the Distribution were determined to be taxable and neither we nor NiSource were at fault, we would be responsible for a portion of the taxes imposed on NiSource as a result of such determination. Any such tax amounts could be significant.
We might not be able to engage in desirable strategic transactions and equity issuances following the Distribution because of certain restrictions relating to requirements for tax-free distributions.
Our ability to engage in significant transactions could be limited or restricted after the Distribution in order to preserve, for U.S. federal income tax purposes, the tax-free nature of the Distribution by NiSource. We have agreed to take reasonable action or reasonably refrain from taking action to ensure that the Separation qualifies for tax-free status under Section 355 of the Code. We also have agreed to various other covenants in the Tax.
Allocation Agreement intended to ensure the tax-free status of the Distribution. These covenants may restrict our ability to sell assets outside the ordinary course of business, to issue or sell additional securities (including securities convertible into our common stock), or to enter into certain other corporate transactions. Any acquisitions or issuances of our stock or NiSource’s stock (or any successor thereto) within two years after the Distribution are generally presumed to be related to the Separation, although we or NiSource may be able to rebut that presumption.
To preserve the tax-free treatment to NiSource of the Distribution, under the Tax Allocation Agreement that we have entered into with NiSource, for the two-year period following the Distribution, without obtaining the consent of NiSource, an unqualified opinion of a nationally recognized law firm or a private letter ruling from the IRS, we may be prohibited from:
• | approving or allowing issuance of our common stock, except in certain limited circumstances, |
• | approving or allowing an issuance or sale of equity securities in Columbia OpCo that results in our owning less than 55% of the outstanding equity securities of Columbia OpCo, |
• | redeeming equity securities, |
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
• | selling or otherwise disposing of the ownership of the general partner of CPPL or of a specified percentage of our assets or the assets of certain of our subsidiaries, or |
• | engaging in certain other transactions that could jeopardize the tax-free status of the Distribution. |
These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business. Moreover, the Tax Allocation Agreement also provides that we are responsible for any taxes imposed on NiSource or any of its affiliates as a result of the failure of the Distribution to qualify for favorable treatment under the Code if such failure is attributable to certain actions taken at any time (even outside the two-year period described above) after the Distribution by or in respect of us or any of our subsidiaries.
We will not have complete control over our tax decisions and could be liable for income taxes owed by NiSource.
For any tax periods (or portion thereof) in which NiSource owned at least 80% of the total voting power and value of our common stock, we and our U.S. subsidiaries were included in NiSource’s consolidated group for U.S. federal income tax purposes. In addition, we or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of NiSource or one or more of its subsidiaries for U.S. state or local income tax purposes. Moreover, notwithstanding the Tax Allocation Agreement, U.S. federal law provides that each member of a federal consolidated group is liable for the group’s entire federal income tax obligation. Thus, to the extent NiSource or other members of NiSource’s consolidated group fail to make any U.S. federal income tax payments required by law, we could be liable for the shortfall with respect to periods in which we were a member of NiSource’s consolidated group. Similar principles may apply for non-U.S., state or local income tax purposes where we filed combined, consolidated or unitary returns with NiSource or its subsidiaries for non-U.S., state or local income tax purposes.
The indemnification arrangements we entered into with NiSource in connection with the Separation may require us to make certain indemnification payments to NiSource to satisfy our indemnification obligations and any indemnification payments we receive from NiSource may not be sufficient to cover the full amount of losses for which NiSource has agreed to indemnify us.
Pursuant to the Separation and Distribution Agreement and certain other agreements, NiSource has agreed to indemnify us from certain liabilities and we have agreed to indemnify NiSource for certain liabilities, as discussed further in Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements.
A court could deem the Distribution to be a fraudulent conveyance and void the transaction or impose substantial liabilities upon us.
A court could deem the Distribution or certain internal restructuring transactions undertaken by NiSource in connection with the Separation to be a fraudulent conveyance or transfer. Fraudulent conveyances or transfers are defined to include transfers made or obligations incurred with the actual intent to hinder, delay or defraud current or future creditors or transfers made or obligations incurred for less than reasonably equivalent value when the debtor was insolvent, or that rendered the debtor insolvent, inadequately capitalized or unable to pay its debts as they become due. A court could void the transactions or impose substantial liabilities upon us, which could adversely affect our results of operations, cash flows and financial condition. Among other things, the court could require our stockholders to return to NiSource, for the benefit of its creditors, some or all of the shares of our common stock issued in the Distribution, or require us to fund liabilities of other companies involved in the restructuring transaction. Whether a transaction is a fraudulent conveyance or transfer under applicable state law may vary depending upon the jurisdiction whose law is being applied.
Our agreements with NiSource relating to the Separation require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.
We negotiated all of our agreements with NiSource relating to the Separation as a wholly owned subsidiary of NiSource. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to the Separation and Distribution Agreement, we have assumed all past, present and future liabilities (other than tax liabilities which will be governed by the Tax Allocation Agreement as described further in Refer to Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements) related to our business, and have agreed to indemnify NiSource for these liabilities, among other matters. Such liabilities include unknown liabilities that could be significant. The allocation of assets and liabilities between NiSource and us may not reflect the allocation that would have been reached between two unaffiliated parties. In addition, we have limited remedies under the Separation and Distribution Agreement. See Note 1A, “Company Structure and Basis of Presentation” in the Company’s audited Notes to Consolidated and Combined Financial Statements for a description of these obligations and the allocation of liabilities between NiSource and us.
Columbia Pipeline Group, Inc. Exhibit 99.1
ITEM 1A. RISK FACTORS
Third parties may seek to hold us responsible for liabilities of NiSource that we did not assume in our agreements.
Third parties may seek to hold us responsible for retained liabilities of NiSource. Under the agreements we entered into with NiSource, NiSource has agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from NiSource.
Our prior and continuing relationship with NiSource exposes us to risks attributable to businesses of NiSource.
Under the Separation and Distribution Agreement we entered into with NiSource, NiSource is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of NiSource that are incurred through a breach of the Separation and Distribution Agreement or any ancillary agreement by NiSource or its affiliates other than us or our post-Separation affiliates, or losses that are attributable to NiSource in connection with the Separation or are not expressly assumed by us under our agreements with NiSource. Immediately following the Separation, any claims made against us that are properly attributable to NiSource in accordance with these arrangements would require us to exercise our rights under our agreements with NiSource to obtain payment from them. We are exposed to the risk that, in these circumstances, NiSource cannot, or will not, make the required payment.
If in the future we cease to manage and control CPPL through our direct and indirect ownership of the general partner interests in CPPL, we may be deemed to be an investment company under the Investment Company Act of 1940.
If we cease to manage and control CPPL and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.