Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - CPG OpCo LP | opcolp-20161231xex991.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 |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) | ||
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2016
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) | ||
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 333-209653-02
CPG OpCo LP
(Exact name of registrant as specified in its charter)
Delaware | 38-3940976 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
5151 San Felipe St., Suite 2500 Houston, Texas | 77056 | |
(Address of principal executive offices) | (Zip Code) | |
(713) 386-3701
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes þ No ¨
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12-b-2 of the Exchange Act.
Large accelerated filer ¨ | Accelerated filer ¨ | |
Non-accelerated filer þ | Smaller reporting company ¨ | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ
At February 16, 2017, Columbia Pipeline Partners LP owns a 15.7% limited partner interest, Columbia Hardy Corporation owns a 0.77% limited partner interest and Columbia Energy Group owns the remaining 83.53% limited partner interest in CPG OpCo LP.
This Annual Report on Form 10-K filed by CPG OpCo LP meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore being filed with the reduced disclosure format allowed under that General Instruction.
CPG OPCO LP
INDEX TO FINANCIAL STATEMENTS
Page No. | ||
Item 1 and 2. | ||
Item 1A. | ||
Item 1B. | ||
Item 3. | ||
Item 4. | ||
Item 5. | ||
Item 6. | ||
Item 7. | ||
Item 7A. | ||
Item 8. | ||
Item 9. | ||
Item 9A. | ||
Item 9B. | ||
Item 10. | ||
Item 11. | ||
Item 12. | ||
Item 13. | ||
Item 14. | ||
Item 15. | ||
DEFINED TERMS The following is a list of frequently used abbreviations or acronyms that are found in this report: | |
Affiliates and Subsidiaries of CPG OpCo LP | |
CEG | Columbia Energy Group |
CEVCO | Columbia Energy Ventures, LLC |
CNS Microwave | CNS Microwave, LLC |
Columbia Gas Transmission | Columbia Gas Transmission, LLC |
Columbia Gulf | Columbia Gulf Transmission, LLC |
Columbia Hardy | Columbia Hardy Corporation |
Columbia Midstream | Columbia Midstream Group, LLC |
CPPL | Columbia Pipeline Partners LP |
CPG | Columbia Pipeline Group, Inc. |
CPGSC | Columbia Pipeline Group Services Company |
Hardy Storage | Hardy Storage Company, LLC |
Millennium Pipeline | Millennium Pipeline Company, L.L.C. |
MLP GP | CPP GP LLC |
OpCo GP | CPG OpCo GP LLC |
Pennant | Pennant Midstream, LLC |
TCPL | TransCanada PipeLines Limited |
TransCanada | TransCanada Corporation |
US Parent | TransCanada PipeLine USA Ltd. |
Abbreviations | |
AFUDC | Allowance for funds used during construction, is the method prescribed by the FERC for inclusion in our tariff rates as reimbursement for the cost of financing construction projects with investor capital and borrowed funds until a project is placed in service |
AOC | Administrative Order by Consent |
ASC | Accounting Standards Codification |
ASU | Accounting Standards Update |
Btu | British Thermal Unit |
CAA | Clean Air Act |
CCRM | Capital Cost Recovery Mechanism |
condensate | A natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon functions |
CPPL's IPO | Initial public offering of Columbia Pipeline Partners LP, which was completed on February 11, 2015 |
CPPL Merger | Effective February 17, 2017, Pony Merger Sub LLC merged with and into CPPL, with CPPL surviving. Following the CPPL Merger, MLP GP remains an indirect wholly owned subsidiary of CPG and the sole general partner of CPPL, and CPG and CEG are the only limited partners of CPPL. |
DOT | Department of Transportation |
Dth/d | Dekatherms per day |
end-user markets | The ultimate users and consumers of transported energy products |
EIA | U.S. Energy Information Administration |
EPA | United States Environmental Protection Agency |
FASB | Financial Accounting Standards Board |
FERC | Federal Energy Regulatory Commission |
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DEFINED TERMS (continued) | |
GAAP | Generally Accepted Accounting Principles |
Hilcorp | Hilcorp Energy Company |
IPO | Initial public offering of Columbia Pipeline Partners LP, which was completed on February 11, 2015 |
LDC | Local distribution companies are involved in the delivery of natural gas to consumers within a specific geographic area. |
LNG | Natural gas that has been cooled to minus 161 degrees Celsius for transportation, typically by ship. The cooling process reduces the volume of natural gas by 600 times |
Merger | Effective July 1, 2016, Taurus Merger Sub Inc. was merged with and into Columbia Pipeline Group, Inc. with Columbia Pipeline Group, Inc. surviving the merger as an indirect, wholly owned subsidiary of TransCanada Corporation. |
MMBtu | One million British Thermal Units |
MMDth | One million Dekatherms |
MMDth/d | One million Dekatherms per day |
NAAQS | National Ambient Air Quality Standards |
NGA | Natural Gas Act of 1938 |
NGL | Hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. Generally such liquids consist of propane and heavier hydrocarbons and are commonly referred to as lease condensate, natural gasoline and liquefied petroleum gases. Natural gas liquids include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities) |
NiSource | NiSource Inc. |
NiSource Corporate Services | NiSource Corporate Services Company |
NiSource Finance | NiSource Finance Corp. |
OCI | Other Comprehensive Income (Loss) |
OPEB | Other postretirement benefits |
park and loan services | Those services pursuant to which customers receive the right for a fee to store natural gas in (park), or borrow gas from (loan), our facilities on a contractual basis |
Partnership Distributable Cash Flow | A supplemental non-GAAP financial measure defined by us as Adjusted EBITDA less interest expense, maintenance capital expenditures, gain on sale of assets and distributable cash flow attributable to noncontrolling interest plus proceeds from the sale of assets, interest income, capital (received) costs related to Separation and any other known differences between cash and income. |
PHMSA | Pipeline and Hazardous Materials Safety Administration |
Piedmont | Piedmont Natural Gas Company, Inc. |
play | A proven geological formation that contains commercial amounts of hydrocarbons |
ppb | parts per billion |
reservoir | A porous and permeable underground formation containing an individual and separate natural accumulation of producible hydrocarbons (crude oil and/or natural gas) which is confined by impermeable rock or water barriers and is characterized by a single natural pressure system |
shale gas | Natural gas produced from organic (black) shale formations |
Tcf | One trillion cubic feet |
throughput | The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility during a particular period |
Williams Partners | Williams Partners L.P. |
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
Some of the information in this report may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
• | changes in general economic conditions; |
• | competitive conditions in our industry; |
• | actions taken by third-party operators, processors and transporters; |
• | the demand for natural gas storage and transportation services; |
• | our ability to successfully implement our business plan; |
• | our ability to complete internal growth projects on time and on budget; |
• | the price and availability of debt and equity financing; |
• | restrictions in our existing and any future credit facilities; |
• | capital market performance and other factors that may decrease the value of benefit plan assets; |
• | the availability and price of natural gas to the consumer compared to the price of alternative and competing fuels; |
• | competition from the same and alternative energy sources; |
• | energy efficiency and technology trends; |
• | operating hazards and other risks incidental to transporting, storing and gathering natural gas; |
• | natural disasters, weather-related delays, casualty losses and other matters beyond our control; |
• | interest rates; |
• | labor relations; |
• | large customer defaults; |
• | changes in the availability and cost of capital; |
• | changes in tax status; |
• | the effects of existing and future laws and governmental regulations; |
• | the effects of future litigation, including litigation relating to the Merger; |
• | the occurrence of any event, change or other circumstance in connection with the recent Merger; |
• | risks related to the disruption of management's attention from our ongoing business operations due to the Merger; |
• | risks associated with the loss and ongoing replacement of key personnel due to the recent Merger; |
• | risks relating to unanticipated costs of integration in connection with the Merger, including operating costs, customer loss or business disruption being greater than expected; |
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• | risks relating to the difficulties in integrating the businesses and management of CPG, including the business and management of the Partnership and TransCanada; and |
• | certain factors discussed elsewhere in this report. |
Other factors described herein, as well as factors that are unknown or unpredictable, could also have a material adverse effect on future results. Please see Item 1A “Risk Factors.” Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Organizational History
Unless the context otherwise requires, references in this annual report on Form 10-K to the “Predecessor,” “our predecessor,” “we,” “our,” “us” or like terms when used in a historical context for periods prior to February 11, 2015, the date on which CPPL closed their IPO, refer to the accounting predecessor to CPG OpCo LP. The Predecessor is comprised of substantially all of the subsidiaries in NiSource’s Columbia Pipeline Group Operations segment, including its equity method investments in Hardy Storage Company, LLC, Millennium Pipeline Company, L.L.C. and Pennant Midstream, LLC. References to “CPG OpCo,” “we,” “our,” “us” and the “Partnership” or like terms when used in the present tense or prospectively, or in reference to the period subsequent to the CPPL IPO, refer to CPG OpCo LP and its subsidiaries. We refer to our general partner, CPG OpCo GP LLC, as our “general partner” and refer to Columbia Pipeline Group Inc. and its subsidiaries other than us and our general partner as “CPG.”
On March 17, 2016, CPG entered into an Agreement and Plan of Merger (the “Merger Agreement”), among CPG, TransCanada PipeLines Limited, a Canadian corporation (“Parent”), TransCanada PipeLine USA Ltd., a Nevada corporation and a wholly owned subsidiary of Parent (“US Parent”), Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent (“Merger Sub”), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada Corporation, a Canadian corporation and the direct parent company of Parent (“TransCanada”). Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016, Merger Sub was merged with and into CPG (the “Merger”) with CPG surviving the Merger as an indirect, wholly owned subsidiary of TransCanada. The Merger did not affect the ownership of OpCo GP, but OpCo GP is indirectly managed by TransCanada after the Merger.
We are a fee-based, growth-oriented Delaware limited partnership formed to own, operate and develop a portfolio of pipelines, storage and related midstream assets. On February 11, 2015, concurrent with CPPL's IPO, CEG and Columbia Hardy contributed substantially all of the subsidiaries in the Predecessor to us. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource (the "Separation"). The Partnership's parent company, CEG, was contributed to CPG prior to the Separation.
CPPL Merger. On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.
The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the merger agreement and transactions contemplated by the merger agreement and determined that the merger agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the merger agreement and the merger transactions. The GP Board resolved that the merger agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the merger agreement and the merger transactions at the special meeting of the unitholders.
On February 16, 2017, the CPPL common unitholders voted to approve the CPPL Merger. The transaction closed on February 17, 2017 and as of that date CPPL became a wholly owned subsidiary of CPG. The CPPL Merger did not affect the ownership of the Partnership's general partner or limited partner interests.
Business Segment
Our operations comprise one reportable segment containing our portfolio of pipelines, storage and related midstream assets. Please see Note 16, “Segments of Business” in Item 8, Financial Statements and Supplementary Data for further discussion regarding our segment.
Description of Businesses and Properties
Interstate Pipeline and Storage Assets. We own the FERC-regulated natural gas transportation and storage assets described below.
Columbia Gas Transmission. Columbia Gas Transmission owns and operates a FERC-regulated interstate natural gas transportation pipeline and storage system, which has historically largely operated as a means to transport gas from the Gulf Coast, via Columbia Gulf, from various pipeline interconnects, and from production areas in the Appalachia region to markets in the midwest, Atlantic, and northeast regions. As Marcellus and Utica shale gas production has grown, Columbia Gas Transmission’s operations and assets also have grown due to the increased production within the pipeline’s operating area. As the market continues
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to evolve, Columbia Gas Transmission is in various phases of execution and construction on a multitude of growth projects to help move the growing production of gas out of the Marcellus and Utica shale plays and into on-system markets in the northeast and mid-Atlantic markets as well as off-system markets in the Gulf Coast.
Columbia Gas Transmission’s pipeline system consists of 11,255 miles of natural gas transmission pipeline. It has a transportation capacity of approximately 12 MMDth/d, transports an average of approximately 4.8 MMDth/d and serves communities in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia. Columbia Gas Transmission owns and leases approximately 819,400 acres of underground storage, 3,417 storage wells, which includes 35 storage fields in four states with approximately 630 MMDth in total operational capacity, with approximately 290 MMDth of working gas capacity.
Columbia Gulf. The Columbia Gulf pipeline system is a FERC-regulated interstate natural gas transportation pipeline system, which consists of 3,341 miles of natural gas transmission pipeline. The system offers shippers access to two actively traded market hubs—the Columbia Gulf Mainline Pool and the Columbia Gulf Onshore Pool. In addition, Columbia Gulf interconnects with the Henry Hub in South Louisiana and the Columbia Gas Transmission Pool near Leach, Kentucky. Through its interstate and intrastate pipeline interconnections, Columbia Gulf provides upstream supply to serve growing markets in the mid-Atlantic, midwest, Florida and southeast. Columbia Gulf also has a project underway that will connect its system with the Cameron LNG export facility. In addition, Columbia Gulf recently reconfigured its system so that it can reverse flow on one of its three pipelines. Flows on the other two pipelines will be reversed as part of expansion projects that are underway.
Millennium Pipeline Joint Venture. We own a 47.5% ownership interest in Millennium Pipeline, which transports an average of 1.3 MMDth/d of natural gas primarily sourced from the Marcellus shale to markets across southern New York and the lower Hudson Valley, as well as to the New York City market through its pipeline interconnections. Millennium Pipeline has access to the Northeast Pennsylvania Marcellus shale natural gas supply and is pursuing growth opportunities to expand its system. The Millennium Pipeline system consists of approximately 253 miles of natural gas transmission pipeline and three compressor stations with over 43,000 horsepower of installed capacity. Columbia Gas Transmission acts as operator of Millennium Pipeline, and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.
Hardy Storage Joint Venture. We own a 49% ownership interest in Hardy Storage, which owns an underground natural gas storage field in Hardy and Hampshire counties in West Virginia. Columbia Gas Transmission serves as operator of Hardy Storage. Hardy Storage has a working storage capacity of approximately 12 MMDth and the ability to deliver 176,000 Dth/d. Columbia Hardy Corporation, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% ownership interest, respectively, in Hardy Storage.
Gathering, Processing and Other Assets. We own the gathering, processing and other assets described below.
Columbia Midstream. Columbia Midstream provides natural gas producer services including gathering, treating, conditioning, processing, compression and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 148 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and also owns a 47.0% ownership interest in Pennant, which owns approximately 49 miles of natural gas gathering pipeline infrastructure, a cryogenic processing plant and a 36 mile NGL pipeline. Columbia Midstream supports the growing production in the Utica and Marcellus resource plays.
CEVCO. CEVCO manages our mineral rights positions in the Marcellus and Utica shale areas. CEVCO owns production rights to approximately 460,000 acres and has sub-leased the production rights in three storage fields and has also contributed its production rights in one other field. CEVCO has entered into multiple transactions to develop its minerals position and as a result receives revenue through working interests and/or royalty interests.
Regulation
The Company is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.
FERC has comprehensive jurisdiction over the Company. In accordance with the Natural Gas Act of 1938, FERC’s jurisdiction over natural gas companies encompasses, among other things, the acquisition, operation and disposition of assets and facilities, the services provided and rates charged.
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FERC has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce. FERC also has authority over the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities. The Company holds certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce.
The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.
For additional information regarding the Company’s regulation and rates, see “Item 1. Business - Environmental”, “Item 1A. Risk Factors.”
Pipeline Safety
The Company is also subject to federal pipeline safety statues, such as the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, (the PSI Act), the Pipeline Inspection, Protection, and Enforcement Act of 2006 (the PIPES Act, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the 2011 Pipeline Safety Act), and, Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act or the SAFE PIPES Act of 2016, which regulate the safety of natural gas pipelines. These statutes, and the associated regulations promulgated and administered under these acts are administered by PHMSA. Recently, PHMSA has promulgated both Interim Final Rules and Proposed Rules that, taken in its entirety, 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. We are closely monitoring and providing comment to PHMSA and industry groups regarding the proposed rules but at this time cannot predict the impact of any final rulemaking.
For additional information regarding the Company’s regulation and rates, see “Item 1A. Risk Factors.”
Environmental
The Company is subject to federal, state and local laws and regulations regarding water quality, hazardous and nonhazardous waste management, air quality control and other environmental matters. These laws and regulations require the Company to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental laws, regulations, licenses, permits, inspections and other approvals. Failure to comply with environmental requirements may expose the Company to significant liabilities including the assessment of fines, penalties and/or interruptions in operations. The Company’s environmental policies and procedures are designed to achieve compliance with such laws and regulations and, historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance costs will not have a material adverse effect on our business and operating results. The Company engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements. For additional information concerning the impact of environmental regulation on the Company, see “Item 1A. Risk Factors” and Note 13 to our consolidated and combined financial statements.
Customers and Contracts
Our customer mix for natural gas transportation services includes LDCs, municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. We provide a significant portion of our transportation and storage services through firm contracts and derive a small portion of our revenues through interruptible service contracts. Transportation and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs. We also provide interruptible transportation and storage services where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated market rates for this interruptible service. Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for approximately 13% of our total operating revenues for the year ended December 31, 2016. No other customer accounted for greater than 10% of total operating revenue. Please see Note 18, “Concentration of Credit Risk” in Item 8, Financial Statements and Supplementary Data for further discussion.
Our customers for our midstream operations consist of natural gas producers with whom we primarily have long-term, fee-based gas gathering agreements, with terms ranging from 10 to 15 years typically with minimum volume commitments.
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Employees
As of December 31, 2016, we had approximately 1,552 active employees. Of these 1,552 employees, 258 are covered by collective bargaining agreements, 51 of which expire in 2017.
Additional Information
We were formed on September 26, 2014 as a Delaware master limited partnership. Our principal executive offices are located at 5151 San Felipe St., Suite 2500, Houston, Texas 77056, and our telephone number is 713-386-3701. We electronically file various reports with the Securities and Exchange Commission (“SEC”), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
ITEM 1A. RISK FACTORS
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity are described in Item 1A. “Risk Factors” in Columbia Pipeline Group Inc.’s Annual Reports on Form 10-K for the year ended December 31, 2016 filed with the United States Securities and Exchange Commission (the “SEC”) on February 17, 2017, which material has been incorporated by reference and is being filed as Exhibit 99.1 to this Form 10-K for OpCo LP pursuant to Rule 12b-23(a) of the Exchange Act of 1934, as amended. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other partnerships, our operations are subject to extensive and rapidly changing federal and state environmental, occupational health and safety and other laws and regulations governing air emissions, wastewater discharges, and nonhazardous and hazardous waste management activities.
We are not a party to any material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Columbia Pipeline Partners LP owns a 15.7% limited partner interest, Columbia Hardy Corporation owns a 0.77% limited partner interest and Columbia Energy Group owns the remaining 83.53% limited partner interest in CPG OpCo LP. There is no market for CPG OpCo LP limited partner interests.
ITEM 6. SELECTED FINANCIAL DATA
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(a) of Form 10-K.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview
We meet the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and have omitted specific information called for by this Item pursuant to General Instruction (I)(2)(a) of Form 10-K.
We are a fee-based, growth-oriented Delaware limited partnership formed by NiSource to own, operate and develop a portfolio of pipelines, storage and related midstream assets. On February 11, 2015, concurrent with CPPL's IPO, Columbia Energy Group ("CEG") and Columbia Hardy Corporation ("Columbia Hardy") contributed substantially all of the subsidiaries in the Predecessor to us. On July 1, 2015, all the shares of Columbia Pipeline Group, Inc. ("CPG") were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource ("the Separation"). The Partnership's parent company, CEG, was contributed to CPG prior to the Separation.
We own substantially all of the natural gas transmission and storage assets of CEG, including approximately 15,000 miles of strategically located interstate pipelines extending from New York to the Gulf of Mexico and an underground natural gas storage system, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. For the year ended December 31, 2015, 94.6% of our revenue, excluding tracker-related revenues, was generated under firm revenue contracts. As of December 31, 2015, these contracts had a weighted average remaining contract life of 4.8 years.
On March 17, 2016, CPG entered into a Merger Agreement, among CPG, TCPL, US Parent, Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent (“Merger Sub”), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the Merger Agreement, effective July 1, 2016, Merger Sub was merged with and into CPG (the "Merger") with CPG surviving the Merger as an indirect, wholly owned subsidiary of TransCanada. The Merger did not affect the ownership of the Partnership's general partner or limited partner interests, but the Partnership is indirectly managed by TransCanada after the Merger.
CPPL Merger. On November 1, 2016, CPPL announced that it had entered into an agreement and plan of merger with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.
The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the merger agreement and transactions contemplated by the merger agreement and determined that the merger agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the merger agreement and the merger transactions. The GP Board resolved that the merger agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the merger agreement and the merger transactions at the special meeting of the unitholders.
On February 16, 2017, the CPPL common unitholders voted to approve the CPPL Merger. The transaction closed on February 17, 2017 and as of that date CPPL became a wholly owned subsidiary of CPG. The CPPL Merger did not affect the ownership of the Partnership's general partner or limited partner interests.
We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities.
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CPG OpCo LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Results of Operations
The following schedule presents the Partnership's and Predecessor's historical consolidated and combined key operating and financial metrics.
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Operating Revenues | |||||||||||
Transportation revenues | $ | 1,152.6 | $ | 1,052.2 | $ | 990.9 | |||||
Transportation revenues-affiliated | — | 47.1 | 95.8 | ||||||||
Storage revenues | 196.5 | 171.4 | 144.0 | ||||||||
Storage revenues-affiliated | — | 26.2 | 53.2 | ||||||||
Other revenues | 29.8 | 34.9 | 63.0 | ||||||||
Total Operating Revenues | 1,378.9 | 1,331.8 | 1,346.9 | ||||||||
Operating Expenses | |||||||||||
Operation and maintenance | 498.5 | 524.7 | 630.7 | ||||||||
Operation and maintenance-affiliated | 237.6 | 163.8 | 122.9 | ||||||||
Depreciation and amortization | 154.3 | 135.0 | 118.6 | ||||||||
Gain on sale of assets | (17.0 | ) | (55.3 | ) | (34.5 | ) | |||||
Impairment of long-lived assets | 18.8 | 0.6 | — | ||||||||
Property and other taxes | 77.2 | 71.2 | 67.1 | ||||||||
Total Operating Expenses | 969.4 | 840.0 | 904.8 | ||||||||
Equity Earnings in Unconsolidated Affiliates | 64.2 | 60.2 | 46.6 | ||||||||
Operating Income | 473.7 | 552.0 | 488.7 | ||||||||
Other Income (Deductions) | |||||||||||
Interest expense | (0.8 | ) | (0.1 | ) | — | ||||||
Interest expense-affiliated | (34.5 | ) | (26.8 | ) | (62.0 | ) | |||||
Other, net | 35.9 | 32.0 | 8.8 | ||||||||
Total Other Income (Deductions), net | 0.6 | 5.1 | (53.2 | ) | |||||||
Income before Income Taxes | 474.3 | 557.1 | 435.5 | ||||||||
Income Taxes | 0.2 | 23.9 | 166.4 | ||||||||
Net Income | 474.1 | 533.2 | $ | 269.1 | |||||||
Less: Predecessor net income prior to CPPL IPO on February 11, 2015 | — | 42.7 | |||||||||
Net income attributable to the Partnership | $ | 474.1 | $ | 490.5 | |||||||
Throughput (MMDth) | |||||||||||
Columbia Gas Transmission | 1,759.5 | 1,460.1 | 1,379.4 | ||||||||
Columbia Gulf | 552.2 | 562.7 | 626.7 | ||||||||
Total | 2,311.7 | 2,022.8 | 2,006.1 | ||||||||
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Operating Revenues. Operating revenues were $1,378.9 million for 2016, an increase of $47.1 million from the same period in 2015. The increase in operating revenues was due primarily to increased demand revenue of $106.7 million primarily from the East Side Expansion, Broad Run Connector and Rayne XPress growth projects, and the CCRM. Additionally, there were higher shorter term transportation services of $5.0 million and increased commodity revenue of $3.6 million. These increases were partially offset by a decrease of $66.6 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in operating expenses, and lower mineral rights royalty revenue of $4.6 million.
12
CPG OpCo LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Operating Expenses. Operating expenses were $969.4 million for 2016, an increase of $129.4 million from the same period in 2015. The increase in operating expenses was primarily due to increased costs related to the Merger of $114.2 million, decreased gains on the sale of assets of $38.3 million, primarily due to conveyances of mineral interests, higher depreciation and amortization of $19.3 million and increased property and other taxes of $4.3 million, both primarily due to higher levels of in-service assets. Additionally, there were higher impairment charges of $18.2 million due to the cancellation of IT system upgrades, increased maintenance expenses of $6.9 million and higher outside service costs of $2.3 million. These changes were partially offset by $66.6 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and lower employee and administrative expenses of $15.0 million.
Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $64.2 million in 2016, an increase of $4.0 million compared to the same period in 2015. Equity earnings increased primarily due to earnings generated by Millennium Pipeline and Pennant.
Other Income (Deductions). Other income (deductions) in 2016 increased income by $0.6 million compared to an increase in income of $5.1 million in 2015. The variance was primarily due to higher interest expense of $8.4 million due to increased short-term borrowings from the money pool, higher expense of $4.1 million in the debt portion of AFUDC and a decrease in interest income of $3.4 million, partially offset by an increase in other income of $6.6 million for the equity portion of AFUDC and a decrease in interest expense of $4.8 million due to the repayment of long-term debt.
Income Taxes. The effective income tax rates were zero and 4.3% in 2016 and 2015, respectively. The change in the overall effective tax rates between 2016 and 2015 was due to post-CPPL IPO income that is not subject to income tax at the partnership level.
Throughput. Throughput totaled 2,311.7 MMDth for 2016, compared to 2,022.8 MMDth for the same period in 2015. The increase of 288.9 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Operating Revenues. Operating revenues were $1,331.8 million for 2015, a decrease of $15.1 million from the same period in 2014. The decrease in operating revenues was primarily due to a decrease of $112.4 million attributable to recovery of operating costs under certain regulatory tracker mechanisms, which are offset in operating expenses, decreased mineral rights royalty revenue of $17.6 million, lower condensate revenues of $4.5 million, decreased revenue from the settlement of gas imbalances of $4.0 million and lower commodity revenue of $2.5 million. These decreases were partially offset by increased demand revenue of $128.0 million primarily from the CCRM, the West Side Expansion growth project and other new contracts. Additionally, there were higher shorter term transportation services of $3.5 million.
Operating Expenses. Operating expenses were $840.0 million for 2015, a decrease of $64.8 million from the same period in 2014. The decrease in operating expenses was primarily due to $112.4 million of decreased operating costs under certain regulatory tracker mechanisms, recoveries of which are offset in operating revenues, and increased gains on the conveyances of mineral interests of $17.8 million. These changes were partially offset by higher employee and administrative expenses of $25.0 million due to higher employee costs, increased depreciation of $16.4 million primarily due to increased capital expenditures related to projects placed in service, increased outside service costs of $13.4 million and increased property and other taxes of $4.1 million.
Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $60.2 million in 2015, an increase of $13.6 million compared to the same period in 2014. Equity earnings increased primarily due to the Pennant joint venture going fully in-service and new compression assets being placed into service at Millennium Pipeline.
Other Income (Deductions). Other income (deductions) in 2015 increased income by $5.1 million compared to a reduction in income of $53.2 million in 2014. The variance was primarily due to a decrease of $28.4 million in interest expense due to the repayment of long-term debt, an increase of $17.3 million in the equity portion of AFUDC, lower expense of $6.7 million in the debt portion of AFUDC and increased interest income of $5.5 million.
Income Taxes. The effective income tax rates were 4.3% and 38.2% in 2015 and 2014, respectively. The change in the overall effective tax rates between 2015 and 2014 were due primarily to post-IPO income that is not subject to income tax at the partnership level, as well as the effects of tax credits, state income taxes, utility rate making and other permanent book-to-tax differences.
Throughput. Throughput totaled 2,022.8 MMDth for 2015, compared to 2,006.1 MMDth for the same period in 2014. The increase of 16.7 million is primarily due to increased transportation of Marcellus and Utica natural gas production.
13
CPG OpCo LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
Other Information
Critical Accounting Policies
We apply certain accounting policies based on the accounting requirements discussed below that have had, and may continue to have, significant impacts on the Partnership’s results of operations and Consolidated Balance Sheets.
Basis of Accounting for Rate-Regulated Subsidiaries. ASC Topic 980, Regulated Operations, provides that rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. The total amounts of regulatory assets and liabilities reflected on the Consolidated Balance Sheets were $115.9 million and $282.2 million at December 31, 2016, and $139.1 million and $310.9 million at December 31, 2015, respectively. For additional information, refer to Note 8, “Regulatory Matters,” in the Notes to Consolidated and Combined Financial Statements.
In the event that regulation significantly changes the opportunity for us to recover our costs in the future, all or a portion of our regulated operations may no longer meet the criteria for the application of ASC Topic 980, Regulated Operations. In such event, a write-down of all or a portion of our existing regulatory assets and liabilities could result. If transition cost recovery is approved by the appropriate regulatory bodies that would meet the requirements under GAAP for continued accounting as regulatory assets and liabilities during such recovery period, the regulatory assets and liabilities would be reported at the recoverable amounts. If unable to continue to apply the provisions of ASC Topic 980, Regulated Operations, we would be required to apply the provisions of ASC Topic 980-20, Discontinuation of Rate-Regulated Accounting. In management’s opinion, our regulated companies will be subject to ASC Topic 980, Regulated Operations for the foreseeable future.
No regulatory assets are earning a return on investment at December 31, 2016. Regulatory assets of $8.6 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 6 years.
Pensions and Postretirement Benefits. CPG has defined benefit plans for both pensions and other postretirement benefits that cover employees of subsidiaries of the Partnership. The calculation of the net obligations and annual expense related to the plans requires a significant degree of judgment regarding the discount rates to be used in bringing the liabilities to present value, long-term returns on plan assets and employee longevity, among other assumptions. Due to the size of the plans and the long-term nature of the associated liabilities, changes in the assumptions used in the actuarial estimates could have material impacts on the measurement of the net obligations and annual expense recognition. For further discussion of CPG’s pensions and other postretirement benefits, please see Note 11, “Pension and Other Postretirement Benefits,” in the Notes to Consolidated and Combined Financial Statements.
Goodwill. In accordance with the provisions for goodwill accounting under GAAP, we test our goodwill for impairment annually as of May 1 each year unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit, which generally is an operating segment or a component of an operating segment as defined by the FASB. Columbia Gas Transmission Operations is a component and has been determined to be a reporting unit. Our goodwill assets at December 31, 2016 and December 31, 2015 were $1,975.5 million pertaining to NiSource's acquisition of CEG on November 1, 2000.
We completed a quantitative (“step 1”) fair value measurement of our reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed under the step 1 annual impairment test. For 2015 and 2016, a qualitative (“step 0”) test was performed as of May 1 of each respective period. We assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit in its baseline May 1, 2012 goodwill test. The results of these assessments indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value and no impairment is necessary.
Although there was no goodwill asset impairment as of May 1, 2016, an interim impairment test could be triggered by the following: actual earnings results that are materially lower than expected, significant adverse changes in the operating environment, an increase in the discount rate, changes in other key assumptions which require judgment and are forward looking in nature, or if our market capitalization stays below book value for an extended period of time. On November 1, 2016, CPPL announced that it entered into an agreement and plan of merger with CPG, in which CPG will acquire all outstanding common units of CPPL. The acquisition price leads to a similar valuation of the Partnership as that provided for in the CPG merger agreement, providing further evidence
14
CPG OpCo LP
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)
that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value. In consideration of all relevant factors, we determined there are no indicators that would require goodwill impairment testing subsequent to May 1, 2016.
Please see Notes 1-I and 6, “Goodwill” in the Notes to Consolidated and Combined Financial Statements for further discussion.
Revenue Recognition. Revenue is recognized as services are performed. For regulated entities, revenues are billed to customers monthly at rates established through the FERC’s cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.
The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.
We provide shorter term transportation services, for which cash is received at inception of the service period and is recorded as deferred revenue and recognized as income over the period the services are provided.
Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
Our subsidiary, CEVCO owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realizable. Royalty revenue was $21.5 million, $26.5 million and $43.8 million for the years ended December 31, 2016, 2015 and 2014, respectively, and are included in “Other revenues” on the Statements of Consolidated and Combined Operations.
We periodically recognize gains on the conveyance of mineral interest related to the pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if the Partnership has a substantial obligation for future performance. As the obligation for future performance is satisfied the deferred revenue is relieved and the associated gain is recognized. Gains on the conveyance of mineral interest amounted to $16.9 million, $52.3 million and $34.5 million for the years ended December 31, 2016, 2015 and 2014, respectively, and are included in “Gain on sale of assets” on the Statements of Consolidated and Combined Operations.
Recently Issued Accounting Pronouncements
Refer to Note 2, "Recent Accounting Pronouncements," in the Notes to Consolidated and Combined Financial Statements.
15
Risk is an inherent part of our business. The extent to which we properly and effectively identify, assess, monitor and manage each of the various types of risk involved in our businesses is critical to its profitability. We seek to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal risks that are involved in our businesses: credit risk, interest rate risk and commodity market risk. Our senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. These include but are not limited to market, operational, financial, compliance and strategic risk types. In recognition of the increasingly varied and complex nature of our business, our risk management processes, policies and procedures continue to evolve and are subject to ongoing review and modification.
Commodity Price Risk. Other than the base gas purchased and used in the natural gas storage facilities, which is necessary to maintain pressure and deliverability in the storage pools, we generally do not take title to the natural gas that we store and/or transport for customers and, accordingly, we are not exposed to commodity price fluctuations on natural gas stored in our facilities or transported through our pipelines by our customers. Base gas purchased and used in natural gas storage facilities is considered a long-term asset and is not re-valued at current market prices. A certain amount of gas is naturally lost in connection with transporting natural gas across our 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 our fuel usage. Except for the base gas in our natural gas storage facilities, which we consider to be a long-term asset, and volume and pricing variations related to the volumes of fuel we purchase to make up for line loss, our current business model is designed to minimize our exposure to fluctuations in commodity prices. As a result, absent other market factors that could adversely impact our operations, changes in the price of natural gas over the intermediate term should not materially impact our operations. We have not historically engaged in material commodity hedging activities relating to our assets. However, we may engage in commodity hedging activities in the future, particularly if we undertake growth projects or engage in acquisitions that expose us to direct commodity price risk.
Interest Rate Risk. We have exposure to interest rate risk as a result of changes in interest rates on borrowings under our intercompany term loan. We entered into a variable interest term loan with NiSource Finance which carries an interest rate of prime plus 150 basis points. The loan was transferred from NiSource Finance to CPG in May 2015. In January 2016, the loan agreement was amended and the interest rate was fixed at 4.70%. As of December 31, 2015, the outstanding balance on this term loan was $630.9 million. An increase or decrease in interest rates of 100 basis points (1%) would have resulted in increased or decreased annual interest expense of $6.3 million for the years ended December 31, 2015. For the year ended December 31, 2016, we do not have any credit agreements that carry a variable interest rate.
Credit Risk. Due to the nature of the industry, credit risk is embedded in our business activities. Our extension of credit is governed by TransCanada’s policies relating to credit risk, which include guidelines for documenting management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by TransCanada’s corporate credit risk function which is independent of operations. Credit risk arises due to the possibility that a customer will not be able or willing to fulfill its obligations on a transaction on or before the settlement date.
16
Index | Page |
17
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the General Partner and Limited Partners of CPG OpCo LP
Houston, Texas
We have audited the accompanying consolidated balance sheets of CPG OpCo LP and subsidiaries (the "Partnership") as of December 31, 2016 and 2015, and the related statements of consolidated and combined operations, comprehensive income, cash flows, and equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated and combined financial statements present fairly, in all material respects, the financial position of CPG OpCo LP and subsidiaries at as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 17, 2017
18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
CONSOLIDATED BALANCE SHEETS
(in millions) | December 31, 2016 | December 31, 2015 | |||||
ASSETS | |||||||
Current Assets | |||||||
Cash and cash equivalents | $ | 8.8 | $ | 78.2 | |||
Accounts receivable (less reserve of $0.3 and $0.3, respectively) | 192.1 | 145.9 | |||||
Accounts receivable-affiliated | 170.5 | 149.4 | |||||
Materials and supplies, at average cost | 26.0 | 32.8 | |||||
Exchange gas receivable | 27.3 | 18.8 | |||||
Deferred property taxes | 61.2 | 52.0 | |||||
Prepayments and other | 24.4 | 33.8 | |||||
Total Current Assets | 510.3 | 510.9 | |||||
Investments | |||||||
Unconsolidated affiliates | 445.8 | 437.1 | |||||
Other investments | 0.8 | 1.8 | |||||
Total Investments | 446.6 | 438.9 | |||||
Property, Plant and Equipment | |||||||
Property, plant and equipment | 10,327.5 | 8,930.9 | |||||
Accumulated depreciation and amortization | (3,079.8 | ) | (2,960.1 | ) | |||
Net Property, Plant and Equipment | 7,247.7 | 5,970.8 | |||||
Other Noncurrent Assets | |||||||
Regulatory assets | 111.9 | 134.1 | |||||
Goodwill | 1,975.5 | 1,975.5 | |||||
Postretirement and postemployment benefits assets | 125.4 | 120.5 | |||||
Deferred charges and other | 8.4 | 9.0 | |||||
Total Other Noncurrent Assets | 2,221.2 | 2,239.1 | |||||
Total Assets | $ | 10,425.8 | $ | 9,159.7 | |||
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
19
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
CONSOLIDATED BALANCE SHEETS
(in millions) | December 31, 2016 | December 31, 2015 | |||||
LIABILITIES AND EQUITY | |||||||
Current Liabilities | |||||||
Short-term borrowings-affiliated | $ | 1,432.9 | $ | 42.1 | |||
Accounts payable | 63.9 | 49.9 | |||||
Accounts payable-affiliated | 29.2 | 85.9 | |||||
Customer deposits | 17.1 | 17.8 | |||||
Taxes accrued | 122.6 | 108.2 | |||||
Exchange gas payable | 26.6 | 18.2 | |||||
Deferred revenue | 3.9 | 15.0 | |||||
Accrued capital expenditures | 109.6 | 95.9 | |||||
Accrued compensation and related costs | 48.7 | 26.6 | |||||
Other accruals | 85.3 | 43.9 | |||||
Total Current Liabilities | 1,939.8 | 503.5 | |||||
Noncurrent Liabilities | |||||||
Long-term debt-affiliated | 630.9 | 630.9 | |||||
Deferred income taxes | 1.0 | 1.0 | |||||
Accrued liability for postretirement and postemployment benefits | 25.8 | 36.1 | |||||
Regulatory liabilities | 262.3 | 309.7 | |||||
Asset retirement obligations | 20.3 | 25.3 | |||||
Other noncurrent liabilities | 52.5 | 63.5 | |||||
Total Noncurrent Liabilities | 992.8 | 1,066.5 | |||||
Total Liabilities | 2,932.6 | 1,570.0 | |||||
Commitments and Contingencies (Refer to Note 13) | |||||||
Equity | |||||||
Limited Partner Interest - Columbia Energy Group | 6,217.5 | 6,300.1 | |||||
Limited Partner Interest - Columbia Hardy Corporation | 39.0 | 39.7 | |||||
Limited Partner Interest - Columbia Pipeline Partners LP | 1,260.0 | 1,275.6 | |||||
Accumulated other comprehensive loss | (23.3 | ) | (25.7 | ) | |||
Total Equity | 7,493.2 | 7,589.7 | |||||
Total Liabilities and Equity | $ | 10,425.8 | $ | 9,159.7 | |||
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
20
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Operating Revenues | |||||||||||
Transportation revenues | $ | 1,152.6 | $ | 1,052.2 | $ | 990.9 | |||||
Transportation revenues-affiliated | — | 47.1 | 95.8 | ||||||||
Storage revenues | 196.5 | 171.4 | 144.0 | ||||||||
Storage revenues-affiliated | — | 26.2 | 53.2 | ||||||||
Other revenues | 29.8 | 34.9 | 63.0 | ||||||||
Total Operating Revenues | 1,378.9 | 1,331.8 | 1,346.9 | ||||||||
Operating Expenses | |||||||||||
Operation and maintenance | 498.5 | 524.7 | 630.7 | ||||||||
Operation and maintenance-affiliated | 237.6 | 163.8 | 122.9 | ||||||||
Depreciation and amortization | 154.3 | 135.0 | 118.6 | ||||||||
Gain on sale of assets | (17.0 | ) | (55.3 | ) | (34.5 | ) | |||||
Impairment of long-lived assets | 18.8 | 0.6 | — | ||||||||
Property and other taxes | 77.2 | 71.2 | 67.1 | ||||||||
Total Operating Expenses | 969.4 | 840.0 | 904.8 | ||||||||
Equity Earnings in Unconsolidated Affiliates | 64.2 | 60.2 | 46.6 | ||||||||
Operating Income | 473.7 | 552.0 | 488.7 | ||||||||
Other Income (Deductions) | |||||||||||
Interest expense | (0.8 | ) | (0.1 | ) | — | ||||||
Interest expense-affiliated | (34.5 | ) | (26.8 | ) | (62.0 | ) | |||||
Other, net | 35.9 | 32.0 | 8.8 | ||||||||
Total Other Income (Deductions), net | 0.6 | 5.1 | (53.2 | ) | |||||||
Income before Income Taxes | 474.3 | 557.1 | 435.5 | ||||||||
Income Taxes | 0.2 | 23.9 | 166.4 | ||||||||
Net Income | 474.1 | 533.2 | $ | 269.1 | |||||||
Less: Predecessor net income prior to CPPL IPO on February 11, 2015 | — | 42.7 | |||||||||
Net income attributable to the Partnership | $ | 474.1 | $ | 490.5 | |||||||
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
21
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
STATEMENTS OF CONSOLIDATED AND COMBINED COMPREHENSIVE INCOME
Year Ended December 31, (in millions, net of taxes for periods prior to CPPL IPO) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Net Income | $ | 474.1 | $ | 533.2 | $ | 269.1 | |||||
Other comprehensive income | |||||||||||
Net unrealized gain on cash flow hedges(1) | 2.1 | 1.5 | 1.0 | ||||||||
Unrecognized pension and OPEB benefit (cost)(2)(3) | 0.3 | (0.2 | ) | — | |||||||
Total other comprehensive income | 2.4 | 1.3 | 1.0 | ||||||||
Total comprehensive income | 476.5 | 534.5 | $ | 270.1 | |||||||
Total other comprehensive income prior to CPPL IPO | — | 0.1 | |||||||||
Predecessor net income prior to CPPL IPO | — | 42.7 | |||||||||
Total comprehensive income prior to CPPL IPO | — | 42.8 | |||||||||
Total comprehensive income attributable to the Partnership | $ | 476.5 | $ | 491.7 | |||||||
(1)Net unrealized gain on derivatives qualifying as cash flow hedges, net of zero, $0.1 million and $0.7 million tax expense in 2016, 2015 and 2014, respectively.
(2)Unrecognized pension and OPEB benefit (cost), net of zero tax expense in 2016, 2015 and 2014, respectively.
(3)Unrecognized pension and OPEB benefits (costs) are primarily related to pension and OPEB remeasurements recorded during 2016 and 2015.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Operating Activities | |||||||||||
Net Income | $ | 474.1 | $ | 533.2 | $ | 269.1 | |||||
Adjustments to Reconcile Net Income to Net Cash from Operating Activities: | |||||||||||
Depreciation and amortization | 154.3 | 135.0 | 118.6 | ||||||||
Deferred income taxes and investment tax credits | — | 10.5 | 139.3 | ||||||||
Deferred revenue | (3.2 | ) | 4.2 | 1.6 | |||||||
Equity-based compensation expense and profit sharing contribution | — | 5.4 | 6.3 | ||||||||
Gain on sale of assets | (17.0 | ) | (55.3 | ) | (34.5 | ) | |||||
Impairment of long-lived assets | 18.8 | 0.6 | — | ||||||||
Income from unconsolidated affiliates | (64.2 | ) | (60.2 | ) | (46.6 | ) | |||||
AFUDC equity | (34.9 | ) | (28.3 | ) | (11.0 | ) | |||||
Distributions of earnings received from equity investees | 61.5 | 57.2 | 37.8 | ||||||||
Changes in Assets and Liabilities: | |||||||||||
Accounts receivable | (43.7 | ) | (11.0 | ) | (20.3 | ) | |||||
Accounts receivable-affiliated | 5.7 | 21.6 | 2.2 | ||||||||
Accounts payable | 15.1 | (10.0 | ) | 2.8 | |||||||
Accounts payable-affiliated | (57.2 | ) | 29.8 | 8.6 | |||||||
Customer deposits | (0.6 | ) | (22.9 | ) | 77.5 | ||||||
Taxes accrued | 13.8 | 19.5 | 11.8 | ||||||||
Exchange gas receivable/payable | — | — | 1.1 | ||||||||
Other accruals | 30.5 | 10.4 | 0.6 | ||||||||
Prepayments and other current assets | 6.2 | (13.5 | ) | (4.4 | ) | ||||||
Regulatory assets/liabilities | 7.4 | 27.6 | 9.0 | ||||||||
Postretirement and postemployment benefits | (9.8 | ) | (5.2 | ) | 2.2 | ||||||
Deferred charges and other noncurrent assets | (4.3 | ) | (13.8 | ) | (4.3 | ) | |||||
Other noncurrent liabilities | 4.0 | (5.0 | ) | 0.7 | |||||||
Net Cash Flows from Operating Activities | 556.5 | 629.8 | 568.1 | ||||||||
Investing Activities | |||||||||||
Capital expenditures | (1,411.8 | ) | (1,106.6 | ) | (747.2 | ) | |||||
Insurance recoveries | 3.0 | 2.1 | 11.3 | ||||||||
Changes in short-term lendings-affiliated | (26.9 | ) | (24.3 | ) | (61.6 | ) | |||||
Proceeds from disposition of assets | 10.1 | 84.1 | 9.3 | ||||||||
Contributions to equity investees | (6.2 | ) | (1.4 | ) | (69.2 | ) | |||||
Distributions from equity investees | 2.2 | 16.0 | — | ||||||||
Other investing activities | (9.7 | ) | (22.3 | ) | (7.1 | ) | |||||
Net Cash Flows used for Investing Activities | (1,439.3 | ) | (1,052.4 | ) | (864.5 | ) | |||||
Financing Activities | |||||||||||
Change in short-term borrowings-affiliated | 1,390.8 | (205.2 | ) | (472.3 | ) | ||||||
Issuance of long-term debt-affiliated | — | — | 768.9 | ||||||||
Payments of long-term debt-affiliated, including current portion | — | (959.6 | ) | — | |||||||
Payments of capital lease obligations and other debt related costs | (4.4 | ) | — | — | |||||||
Capital contribution from CEG | — | 1,217.3 | — | ||||||||
Capital contribution from Columbia Pipeline Partners LP for additional interest | — | 1,170.0 | — | ||||||||
Proceeds from capital contribution from Columbia Pipeline Partners LP distributed to CEG | — | (500.0 | ) | — | |||||||
Quarterly distributions to limited partners | (573.0 | ) | (222.2 | ) | — | ||||||
Net Cash Flows from Financing Activities | 813.4 | 500.3 | 296.6 | ||||||||
Change in cash and cash equivalents | (69.4 | ) | 77.7 | 0.2 | |||||||
Cash and cash equivalents at beginning of period | 78.2 | 0.5 | 0.3 | ||||||||
Cash and Cash Equivalents at End of Period | $ | 8.8 | $ | 78.2 | $ | 0.5 | |||||
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG OpCo LP
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY
Predecessor | CPG OpCo LP | ||||||||||||||||||||||
(in millions) | Net Parent Investment | Limited Partner Interest - CEG | Limited Partner Interest - Columbia Hardy | Limited Partner Interest - CPPL | Accumulated Other Comprehensive Loss | Total | |||||||||||||||||
Balance as of January 1, 2014 | $ | 3,917.6 | $ | — | $ | — | $ | — | $ | (17.7 | ) | $ | 3,899.9 | ||||||||||
Net Income | 269.1 | — | — | — | — | 269.1 | |||||||||||||||||
Other comprehensive income, net of tax | — | — | — | — | 1.0 | 1.0 | |||||||||||||||||
Net transfers from parent | 1.3 | — | — | — | — | 1.3 | |||||||||||||||||
Balance as of December 31, 2014 | $ | 4,188.0 | $ | — | $ | — | $ | — | $ | (16.7 | ) | $ | 4,171.3 | ||||||||||
Net income from January 1, 2015 to February 10, 2015 | 42.7 | — | — | — | — | 42.7 | |||||||||||||||||
Other comprehensive income, net of tax, from January 1, 2015 through February 10, 2015 | — | — | — | — | 0.1 | 0.1 | |||||||||||||||||
Contribution of capital from parent | 1,217.3 | — | — | — | — | 1,217.3 | |||||||||||||||||
Predecessor net tax liabilities not assumed by the Partnership(1) | 1,232.5 | — | — | — | (10.3 | ) | 1,222.2 | ||||||||||||||||
Contribution/Noncontributed Net Parent Investment Adjustments(2) | (7.7 | ) | — | — | — | — | (7.7 | ) | |||||||||||||||
Balance as of February 11, 2015 (prior to CPPL's IPO) | $ | 6,672.8 | $ | — | $ | — | $ | — | $ | (26.9 | ) | $ | 6,645.9 | ||||||||||
Allocation of net investment to partners' capital | (6,672.8 | ) | 6,148.1 | 37.6 | 487.1 | — | — | ||||||||||||||||
Capital contribution from CPPL for additional interest | — | — | — | 1,170.0 | — | 1,170.0 | |||||||||||||||||
CPPL's purchase of additional interest in the Partnership(3) | — | 424.4 | — | (424.4 | ) | — | — | ||||||||||||||||
Distributions to parent | — | (500.0 | ) | — | — | — | (500.0 | ) | |||||||||||||||
Net income from February 11, 2015 through December 31, 2015 | — | 409.7 | 3.8 | 77.0 | — | 490.5 | |||||||||||||||||
Other comprehensive income, net of tax, from February 11, 2015 through December 31, 2015 | — | — | — | — | 1.2 | 1.2 | |||||||||||||||||
Quarterly distributions | — | (185.6 | ) | (1.7 | ) | (34.9 | ) | — | (222.2 | ) | |||||||||||||
Transfers from parent(4) | — | 3.5 | — | 0.8 | — | 4.3 | |||||||||||||||||
Balance as of December 31, 2015 | $ | — | $ | 6,300.1 | $ | 39.7 | $ | 1,275.6 | $ | (25.7 | ) | $ | 7,589.7 | ||||||||||
Net income from January 1, 2016 through December 31, 2016 | — | 396.0 | 3.7 | 74.4 | — | 474.1 | |||||||||||||||||
Other comprehensive income, net of tax, from January 1, 2016 through December 31, 2016 | — | — | — | — | 2.4 | 2.4 | |||||||||||||||||
Quarterly distributions | — | (478.6 | ) | (4.4 | ) | (90.0 | ) | — | (573.0 | ) | |||||||||||||
Balance as of December 31, 2016 | $ | — | $ | 6,217.5 | $ | 39.0 | $ | 1,260.0 | $ | (23.3 | ) | $ | 7,493.2 | ||||||||||
(1)Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-CPPL IPO, as well as associated regulatory assets and liabilities.
(2)Reflects the removal of amounts related to Crossroads Pipeline Company, CPGSC, Central Kentucky Transmission Company and 1% of the 50% interest in Hardy Storage that were included in the Predecessor but were not contributed to the Partnership, as well as the inclusion of CNS Microwave, which was not part of the Predecessor.
(3)Represents CPPL's purchase of an additional 8.4% limited partner interest in the Partnership, recorded at the historical carrying value of the Partnership's net assets after giving effect to the $1,170.0 million equity contribution. This decreases CPPL's limited partner interest by the same amount it increases CEG's limited partner interest because CPPL's purchase price for its additional 8.4% interest in the Partnership exceeded book value.
(4)As part of the Separation from NiSource, certain assets on the Partnership's subsidiaries' accounts were purchased by CEG at fair value and then sold to NiSource. As the Partnership and CEG are entities under common control, this amount represents the difference between book value and fair value of those assets.
The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.
24
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
1. | Nature of Operations and Summary of Significant Accounting Policies |
A. Company Structure and Basis of Presentation. CPG OpCo LP (the "Partnership") was formed in Delaware on September 26, 2014, as a subsidiary of NiSource. The general partner of the Partnership, OpCo GP, is 100% owned by its sole member CPPL. At or prior to the closing of CPPL's IPO the following transactions occurred:
• | CEG contributed $1,217.3 million of capital to certain subsidiaries of the Predecessor to repay intercompany debt owed to NiSource Finance. CEG entered into new intercompany debt agreements with NiSource Finance for $1,217.3 million; |
• | CEG and Columbia Hardy contributed substantially all of the subsidiaries in the Predecessor to the Partnership; |
• | CEG assumed responsibility for all historical current and deferred income taxes other than Tennessee state income taxes that continue to be borne by the Partnership post-IPO, as well as associated regulatory assets and liabilities; |
• | CEG contributed to CPPL a 7.3% limited partner interest in the Partnership in exchange for 46,811,398 subordinated units in CPPL and all of CPPL's incentive distribution rights; |
• | CPPL purchased from the Partnership an additional 8.4% limited partner interest in exchange for $1,170.0 million from the net proceeds of CPPL's IPO, resulting in CPPL owning a 15.7% limited partner interest in the Partnership; |
• | The Partnership distributed $500.0 million to CEG as a reimbursement of preformation capital expenditures with respect to the assets contributed to the Partnership. |
• | Following CPPL's IPO, CPPL owns a 15.7% limited partner interest in the Partnership, Columbia Hardy owns a 0.77% limited partner interest and CEG owns the remaining 83.53% limited partner interest. |
On February 11, 2015, concurrent with the completion of CPPL's IPO, NiSource contributed its subsidiary, CEG, to CPG. Following this contribution, CPG owns and operates, through its subsidiaries, approximately 15,000 miles of strategically located interstate gas pipelines extending from New York to the Gulf of Mexico and one of the nation’s largest underground natural gas storage systems, with approximately 300 MMDth of working gas capacity, as well as related gathering and processing assets. CEG owns and operates, through its subsidiaries, substantially all of the natural gas transmission and storage assets of CPG. Prior to July 1, 2015, CPG was a wholly owned subsidiary of NiSource. On July 1, 2015, all the shares of CPG were distributed by NiSource to holders of NiSource common stock completing CPG's separation from NiSource ("the Separation"). As a result of the Separation, CPG became an independent publicly traded company. The Partnership is a guarantor of CPG's senior notes. Through the registration of CPG's senior notes, the Partnership must comply with the reporting requirements of Rule 3-10 of Regulation S-X. The Partnership has suspended its obligations to file periodic reports with the SEC based on CPG’s senior notes and once it has filed its Form 10-K for the year ended December 31, 2016, it will no longer have reporting obligations with respect to CPG’s senior notes. CPG OpCo LP Predecessor (the “Predecessor”) is comprised of NiSource’s Columbia Pipeline Group Operations reportable segment.
The Partnership entered into an omnibus agreement with CEG and its affiliates (together with a services agreement with CPGSC) at the closing of CPPL's IPO that addresses (1) centralized corporate, general and administrative services to be provided by CEG for the Partnership and the reimbursement by the Partnership for the Partnership's portion of these services, (2) CPPL's right of first offer for CEG's 84.3% interest in the Partnership, (3) the indemnification of the Partnership for certain potential environmental and toxic tort claims losses and expenses associated with the operation of the assets and occurring before the closing date of the IPO and (4) the Partnership's requirement to guarantee future indebtedness that CPG incurs.
The Partnership is engaged in regulated interstate gas transportation and storage services for LDCs, marketers, producers and industrial and commercial customers located in northeastern, mid-Atlantic, midwestern and southern states and the District of Columbia along with unregulated businesses such as midstream services, including gathering, treating, conditioning, processing, compression and liquids handling, and development of mineral rights positions. The regulated services are performed under tariffs at rates subject to FERC approval.
CPG Merger. On March 17, 2016, CPG entered into an Agreement and Plan of Merger (the “CPG Merger Agreement”), among CPG, TCPL, US Parent, Taurus Merger Sub Inc., a Delaware corporation and a wholly owned subsidiary of US Parent (“Merger Sub”), and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII of the CPG Merger Agreement, TransCanada. Upon the terms and subject to the conditions set forth in the CPG Merger Agreement, effective July 1, 2016, Merger
25
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Sub was merged with and into CPG (the “Merger”) with CPG surviving the Merger as an indirect, wholly owned subsidiary of TransCanada. The Merger did not affect the ownership of the Partnership's general partner or limited partner interests, but the Partnership is indirectly managed by TransCanada after the Merger. The Partnership incurred approximately $114.2 million of Merger related costs within operation and maintenance and property and other taxes, including approximately $104.7 million of employee related costs. Additionally, as a result of the Merger, the Partnership recognized an impairment charge of $18.8 million related to the cancellation of IT system upgrades that were in process prior to the Merger.
CPPL Merger. On November 1, 2016, CPPL entered into an agreement and plan of merger (the "CPPL Merger Agreement") with CPG, Pony Merger Sub LLC, a Delaware limited liability company and wholly owned subsidiary of CPG (“Pony Merger Sub”) and MLP GP.
The conflicts committee of the board of directors of MLP GP (the “GP Conflicts Committee”) and the board of directors of the MLP GP (the "GP Board") approved the CPPL Merger Agreement and transactions contemplated by the CPPL Merger Agreement and determined that the CPPL Merger Agreement and the merger transactions are fair and reasonable to and in the best interests of CPPL and to the holders of CPPL common units unaffiliated with CPG, CEG and MLP GP (collectively, the “CPPL unaffiliated unitholders”). The GP Conflicts Committee recommended the GP Board approve the CPPL Merger Agreement and the merger transactions. The GP Board resolved that the CPPL Merger Agreement and the merger transactions be submitted to the unitholders of CPPL at a special meeting of the unitholders for approval. The GP Board recommended that the unitholders of CPPL vote in favor of the proposal to approve the CPPL Merger Agreement and the merger transactions at the special meeting of the unitholders.
On February 16, 2017, the CPPL common unitholders voted to approve the CPPL Merger. The transaction closed on February 17, 2017 and as of that date CPPL became a wholly owned subsidiary of CPG. The CPPL Merger did not affect the ownership of the Partnership's general partner or limited partner interests.
For periods subsequent to the closing of CPPL's IPO, the financial statements included in this annual report are the financial statements and accounting records of the Partnership. For periods prior to the closing of CPPL's IPO, the financial statements included in this annual report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows:
• | The Consolidated Balance Sheets consist of the consolidated balance sheet of the Partnership as of December 31, 2016 and December 31, 2015. |
• | The Statements of Consolidated and Combined Operations consist of the consolidated results of the Partnership for the year ended December 31, 2016 and for the period February 11, 2015 through December 31, 2015, and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the year ended December 31, 2014. |
• | The Statements of Consolidated and Combined Comprehensive Income consist of the consolidated results of the Partnership for the year ended December 31, 2016 and for the period from February 11, 2015 through December 31, 2015, and the combined results of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the year ended December 31, 2014. |
• | The Statements of Consolidated and Combined Cash Flows consist of the consolidated cash flows of the Partnership for the year ended December 31, 2016 and for the period from February 11, 2015 through December 31, 2015, and the combined cash flows of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the year ended December 31, 2014. |
• | The Statements of Consolidated and Combined Equity and Partners' Capital consist of the consolidated activity of the Partnership for the year ended December 31, 2016 and for the period from February 11, 2015 through December 31, 2015, and the combined activity of the Predecessor for the period from January 1, 2015 through February 10, 2015 and for the year ended December 31, 2014. |
The Partnership’s accompanying Consolidated and Combined Financial Statements have been prepared in accordance with GAAP. These financial statements include the accounts of the following subsidiaries: Columbia Gas Transmission, Columbia Gulf, Columbia Midstream, CEVCO and CNS Microwave. All intercompany transactions and balances have been eliminated. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage, Millennium Pipeline and Pennant.
26
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
B. Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
C. Cash and Cash Equivalents. Cash and cash equivalents are liquid marketable securities with an original maturity date of less than three months.
D. Allowance for Uncollectible Accounts. The reserve for uncollectible receivables is the Partnership's best estimate of the amount of probable credit losses in the existing accounts receivable. Collectability of accounts receivable is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
E. Basis of Accounting for Rate-Regulated Subsidiaries. Rate-regulated subsidiaries account for and report assets and liabilities consistent with the economic effect of the way in which regulators establish rates, if the rates established are designed to recover the costs of providing the regulated service and it is probable that such rates can be charged and collected. Certain expenses and credits subject to utility regulation or rate determination normally reflected in income are deferred on the Consolidated Balance Sheets and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers.
In the event that regulation significantly changes the opportunity for the Partnership to recover its costs in the future, all or a portion of the Partnership’s regulated operations may no longer meet the criteria for regulatory accounting. In such an event, a write-down of all or a portion of the Partnership’s existing regulatory assets and liabilities could result. If unable to continue to apply the provisions of regulatory accounting, the Partnership would be required to apply the provisions of Discontinuation of Rate-Regulated Accounting. In management’s opinion, the Partnership’s regulated subsidiaries will be subject to regulatory accounting for the foreseeable future. Please see Note 8, "Regulatory Matters," in the Notes to Consolidated and Combined Financial Statements for further discussion.
F. Property, Plant and Equipment and Related AFUDC and Maintenance. Property, plant and equipment is stated at cost. The Partnership's rate-regulated subsidiaries record depreciation using composite rates on a straight-line basis over the remaining service lives of the properties as approved by the appropriate regulators. The Partnership's non-regulated companies depreciate assets on a component basis on a straight-line basis over the remaining service lives of the properties.
The Partnership capitalizes AFUDC on all classes of property except organization costs, land, autos, office equipment, tools and other general property purchases. The allowance is applied to construction costs for that period of time between the date of the expenditure and the date on which such project is placed in service. A combination of short-term borrowings, long-term debt and equity were used to fund construction efforts for all three years presented. The pre-tax rate for AFUDC debt and AFUDC equity are summarized in the table below:
2016 | 2015 | 2014 | |||||||||||||||
Debt | Equity | Debt | Equity | Debt | Equity | ||||||||||||
Predecessor | |||||||||||||||||
Columbia Gas Transmission | 0.6 | % | 4.8 | % | 1.8 | % | 6.3 | % | 0.9 | % | 3.0 | % | |||||
Columbia Gulf | 0.6 | % | 3.7 | % | 2.9 | % | 6.3 | % | 2.1 | % | 9.4 | % | |||||
The Partnership follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When regulated property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, net of salvage, is charged to the accumulated provision for depreciation in accordance with composite depreciation.
G. Gas Stored-Base Gas. Base gas, which is valued at original cost, represents storage volumes that are maintained to ensure that adequate well pressure exists to deliver current gas inventory. There were no purchases of base gas during the years ended December 31, 2016, 2015 and 2014. Gas stored-base gas is included in Property, plant and equipment on the Consolidated Balance Sheets.
27
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
H. Amortization of Software Costs. External and internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of each project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis generally over a period of five years. The Partnership amortized $9.7 million in 2016, $5.8 million in 2015 and $4.3 million in 2014 related to software costs. The Partnership’s unamortized software balance was $29.1 million and $27.1 million at December 31, 2016 and 2015, respectively. The increase in software amortization and unamortized software balance is primarily due to software placed in service subsequent to the Separation. The additional software was necessary for CPG to operate as an independent company.
I. Goodwill. The Partnership has $1,975.5 million in goodwill. All goodwill relates to the excess of cost over the fair value of the net assets acquired in the CEG acquisition on November 1, 2000. Please see Note 6, "Goodwill," in the Notes to Consolidated and Combined Financial Statements for further discussion.
J. Impairments. An impairment loss on long-lived assets shall be recognized only if the carrying amount of a long-lived assets is not recoverable and exceeds its fair value. The test for impairment compares the carrying amount of the long-lived asset to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. The Partnership recognized an impairment loss of $18.8 million, $0.6 million, and zero for the years ended December 31, 2016, 2015, and 2014, respectively. As a result of the Merger, the Partnership recognized an impairment loss for the year ended December 31, 2016 related to the cancellation of IT system upgrades that were in process prior to the Merger.
K. Revenue Recognition. Revenue is recorded as services are performed. Revenues are billed to customers monthly at rates established through the FERC's cost-based rate-making process or at rates less than those allowed by the FERC. Revenues are recorded on the accrual basis and include estimates for transportation provided but not billed.
The demand and commodity charges for transportation of gas under long-term agreements are recognized separately. Demand revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of natural gas transported. Commodity revenues for both firm and interruptible transportation are recognized in the period the transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point.
The Partnership provides shorter term transportation and storage services for which cash is received at inception of the service period resulting in the recording of deferred revenues that are recognized in revenues over the period the services are provided.
Storage capacity revenues are recognized monthly over the term of the agreement with the customer regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage.
The Partnership includes the subsidiary CEVCO, which owns the mineral rights to approximately 460,000 acres in the Marcellus and Utica shale areas. CEVCO leases or contributes the mineral rights to producers in return for royalty interest. Royalties from mineral interests are recognized on an accrual basis when earned and realized. Royalty revenue was $21.5 million, $26.5 million and $43.8 million for the years ended December 31, 2016, 2015 and 2014, respectively, and is included in "Other revenues" on the Statements of Consolidated and Combined Operations.
The Partnership periodically recognizes gains on the conveyance of mineral interest related to pooling of assets (production rights) in joint undertakings intended to find, develop, or produce oil or gas from a particular property or group of properties. The gains are initially deferred if the Partnership has a substantial obligation for future performance. As the obligation for future performance is satisfied, the deferred revenue is relieved and the associated gain is recognized. Gains on conveyances amounted to $16.9 million, $52.3 million and $34.5 million for the years ended December 31, 2016, 2015 and 2014, respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations.
L. Estimated Rate Refunds. The Partnership collects revenue subject to refund pending final determination in rate proceedings. In connection with such revenues, estimated rate refund liabilities are recorded which reflect management’s current judgment of the ultimate outcomes of the proceedings. No provisions are made when, in the opinion of management, the facts and circumstances preclude a reasonable estimate of the outcome.
M. Accounting for Exchange and Balancing Arrangements of Natural Gas. The Partnership enters into balancing and exchange arrangements of natural gas as part of its operations. The Partnership records a receivable or payable for its respective cumulative gas imbalances. These receivables and payables are recorded as “Exchange gas receivable” or “Exchange gas payable” on the Partnership’s Consolidated Balance Sheets, as appropriate.
28
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
N. Income Taxes and Investment Tax Credits. The Partnership is a limited partnership and is treated as a partnership for U.S. federal income tax purposes and therefore, is not liable for entity-level federal income taxes. The Predecessor's operating results were included in NiSource's consolidated U.S. federal and in consolidated, combined or stand-alone state income tax returns. Amounts presented in the combined financial statements prior to CPPL's IPO relate to income taxes that have been determined on a separate tax return basis, and the Predecessor's contribution to NiSource's net operating losses and tax credits have been included in the Predecessor's financial statements.
O. Environmental Expenditures. The Partnership accrues for costs associated with environmental remediation obligations when the incurrence of such costs is probable and the amounts can be reasonably estimated, regardless of when the expenditures are actually made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations, existing technology and estimated site-specific costs where assumptions may be made about the nature and extent of site contamination, the extent of cleanup efforts, costs of alternative cleanup methods and other variables. The liability is adjusted as further information is discovered or circumstances change. The reserves for estimated environmental expenditures are recorded on the Consolidated Balance Sheets in “Other Accruals” for short-term portions of these liabilities and “Other noncurrent liabilities” for the respective long-term portions of these liabilities. The Partnership establishes regulatory assets on the Consolidated Balance Sheets to the extent that future recovery of environmental remediation costs is probable through the regulatory process. Please see Note 13, "Other Commitments and Contingencies" in the Notes to Consolidated and Combined Financial Statements for further discussion.
P. Accounting for Investments. The Partnership accounts for its ownership interests in Millennium Pipeline using the equity method of accounting. Columbia Gas Transmission owns a 47.5% interest in Millennium Pipeline. The equity method of accounting is applied for investments in unconsolidated companies where the Partnership (or a subsidiary) owns 20 to 50 percent of the voting rights and can exercise significant influence.
The Partnership has a 49.0% interest in Hardy Storage. The Predecessor had a 50.0% interest in Hardy Storage. The Partnership and the Predecessor reflect the investment in Hardy Storage as an equity method investment.
Columbia Midstream entered into a 50:50 joint venture in 2012 with Hilcorp to construct Pennant, a new wet natural gas gathering infrastructure and NGL processing facilities to support natural gas production in the Utica Shale region of northeastern Ohio and western Pennsylvania. During the third quarter of 2015, an additional member, an affiliate of Williams Partners, joined the Pennant joint venture. Williams Partners' initial ownership investment in Pennant is 5.00%, and by funding specified investment amounts for future growth projects, Williams Partners can invest directly in the growth of Pennant. Such funding will potentially increase Williams Partners' ownership in Pennant up to 33.33% over a defined investment period. As a result of the buy-in, Columbia Midstream received $12.7 million in cash and recorded a gain of $2.9 million, and its ownership interest in Pennant decreased from 50.0% to 47.5%. During 2016, Williams Partners funded additional specified growth projects. As a result, Columbia Midstream's ownership interest decreased to 47.0%. The Partnership accounts for the joint venture under the equity method of accounting.
Q. Natural Gas and Oil Properties. CEVCO participates as a working interest partner in the development of a broader acreage dedication. The working interest allows CEVCO to invest in the drilling operations of the partnership in addition to a royalty interest in well production. Please see Note 1K, “Revenue Recognition,” in the Notes to Consolidated and Combined Financial Statements for further discussion regarding the royalty revenue. CEVCO uses the successful efforts method of accounting for natural gas and oil producing activities for their portion of drilling activities. Capitalized well costs are depleted based on the units of production method.
CEVCO’s portion of unproved property investment is periodically evaluated for impairment. The majority of these costs generally relate to CEVCO’s portion of the working interest. The costs are capitalized and evaluated as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of individually significant unproved property is assessed on a field-by-field basis considering a combination of time, geologic and engineering factors.
29
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2016 and 2015:
(in millions) | 2016 | 2015 | |||||
Beginning Balance | $ | 1.7 | $ | 14.9 | |||
Additions pending the determination of proved reserves | — | 1.3 | |||||
Reclassifications of proved properties | (1.3 | ) | (14.5 | ) | |||
Ending Balance | $ | 0.4 | $ | 1.7 | |||
As of December 31, 2016, there was $0.3 million of capitalized exploratory well costs that have been capitalized for more than one year relating to one project initiated in 2013.
2. | Recent Accounting Pronouncements |
In January 2017, the FASB issued ASU 2017-04, Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ASU 2017-04 simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The Partnership is required to adopt ASU 2017-04 for its annual or any interim goodwill impairment tests for annual periods beginning after December 15, 2019, and the guidance is to be applied on a prospective basis. The Partnership is currently evaluating the impact the adoption of ASU 2017-04 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.
In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. ASU 2017-01 provides a framework that gives entities a basis for making reasonable judgments about whether a transaction involves an asset or a business. The Partnership is required to adopt ASU 2017-01 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied on a prospective basis. The Partnership is currently evaluating the impact the adoption of ASU 2017-01 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements.
In October 2016, the FASB issued ASU 2016-17, Consolidation (Topic 810): Interests Held through Related Parties that are Under Common Control, which amends the guidance on related parties that are under common control. Specifically, ASU 2016-17 requires that a single decision maker consider indirect interest held by related parties under common control on a proportionate basis in a manner consistent with its evaluation of indirect interests held through other related parties. The Partnership is required to adopt ASU 2016-17 for periods beginning after December 15, 2016, including interim periods, and the guidance is to be applied on a retrospective basis. The Partnership is currently evaluating the impact the adoption of ASU 2016-17 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate the impact will be material.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. ASU 2016-15 amends the guidance in ASC 230 on the classification of certain cash receipts and payments in the statement of cash flows. The Partnership is required to adopt ASU 2016-15 for periods beginning after December 15, 2017, including interim periods, and the guidance is to be applied retrospectively, with early adoption permitted. The Partnership is currently evaluating the impact the adoption of ASU 2016-15 will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 outlines a single, comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB issued ASU 2015-14 to extend the adoption date for ASU 2014-09 to periods beginning after December 15, 2017, including interim periods, and the new standard is to be applied retrospectively, with early adoption permitted on the original effective date of ASU 2014-09 on a limited basis. In March 2016, the FASB issued ASU 2016-08, which amends the principal-versus-agent implementation guidance and illustrations in ASU 2014-09. Among other things, ASU 2016-08 clarifies that an entity should evaluate whether it is the principal or the agent for each specified good or service promised in a contract with a customer. In April 2016, the FASB issued ASU 2016-10, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in ASU 2014-09. In May 2016, the FASB issued ASU 2016-12, which contains narrow scope improvements for certain aspects of ASU 2014-09 including collectability, presentation of sales tax and other similar taxes collected from customers, noncash consideration, contract modifications and completed contracts at transition and transition technical correction. The Partnership is currently identifying existing customer contracts or groups of contracts that are within the scope of the new guidance and has begun an assessment in order to determine the impact the adoption of ASU 2014-09, and the related ASUs, will have on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). ASU 2016-02 introduces a lessee model that brings most leases on the balance sheet. The new standard also aligns many of the underlying principles of the new lessor model with those in ASC 606, the FASB's new revenue recognition standard (e.g., those related to evaluating when profit can be recognized). Furthermore, ASU 2016-02 addresses other concerns related to the current leases model. For example, ASU 2016-02 eliminates the requirement in current U.S. GAAP for an entity to use bright-line tests in determining lease classification. The standard also requires lessors to increase the transparency of their exposure to changes in value of their residual assets and how they manage that exposure. The Partnership is required to adopt ASU 2016-02 for periods beginning after December 15, 2018, including interim periods, with early adoption permitted. The Partnership is currently identifying existing lease agreements that may have an impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. ASU 2015-03 changes the way entities present debt issuance costs in financial statements by presenting issuance costs on the balance sheet as a direct deduction from the related liability rather than as a deferred charge. Amortization of these costs will continue to be reported as interest expense. In August 2015, the FASB issued ASU 2015-15 to clarify the SEC staff's position on these costs in relation to line-of-credit agreements stating that the SEC staff would not object to an entity deferring and presenting debt issuance costs related to a line-of-credit arrangement as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of such arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. The Partnership retrospectively adopted ASU 2015-03 and ASU 2015-15 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. ASU 2015-02 amends consolidation guidance by including changes to the variable and voting interest models used by entities to evaluate whether an entity should be consolidated. The Partnership retrospectively adopted ASU 2015-02 as of January 1, 2016. The adoption of this guidance did not have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
3. Transactions with Affiliates
Prior to CPG's separation from NiSource, the Partnership engaged in transactions with subsidiaries of NiSource which were deemed to be affiliates of the Partnership. The Partnership continues to engage in transactions with subsidiaries of CPG subsequent to the Separation. These affiliate transactions are summarized in the tables below:
Statement of Operations
Year Ended December 31, | |||||||||||
(in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Transportation revenues | $ | — | $ | 47.1 | $ | 95.8 | |||||
Storage revenues | — | 26.2 | 53.2 | ||||||||
Other revenues | — | 0.2 | 0.3 | ||||||||
Operation and maintenance expense | 237.6 | 163.8 | 122.9 | ||||||||
Interest expense | 34.5 | 26.8 | 62.0 | ||||||||
Interest income | 1.4 | 4.8 | 0.5 | ||||||||
Balance Sheet
(in millions) | December 31, 2016 | December 31, 2015 | |||||
Accounts receivable | $ | 170.5 | $ | 149.4 | |||
Short-term borrowings | 1,432.9 | 42.1 | |||||
Accounts payable | 29.2 | 85.9 | |||||
Long-term debt | 630.9 | 630.9 | |||||
Transportation, Storage and Other Revenues. Prior to the Separation, the Partnership provided natural gas transportation, storage and other services to subsidiaries of NiSource, the Partnership's former affiliates. Prior to CPPL's IPO, the Predecessor provided similar services to subsidiaries of NiSource.
Operation and Maintenance Expense. The Partnership receives executive, financial, legal, information technology and other administrative and general services from CPGSC. Prior to CPPL's IPO, the Predecessor received similar services from NiSource Corporate Services. Expenses incurred as a result of these services consist primarily of employee compensation and benefits, outside services and other expenses. The expenses are charged directly or allocated using various allocation methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures. Management believes the allocation methodologies are reasonable. However, these allocations and estimates may not represent the amounts that would have been incurred had the services been provided by an outside entity. Subsequent to the completion of the Merger, the Partnership incurred merger related operation and maintenance expense of $80.7 million primarily related to employee and administrative expenses.
Interest Expense and Income. The Partnership and Predecessor were charged interest for long-term debt of $30.3 million, $35.1 million and $61.6 million for the years ended December 31, 2016, 2015 and 2014, respectively, offset by associated AFUDC of $5.1 million, $9.2 million and $2.7 million for the years ended December 31, 2016, 2015 and 2014, respectively.
The Partnership and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance, which became effective on the date of CPPL's IPO. Following the Separation, the agreement is now with CPG. The money pool is available for the Partnership and its subsidiaries' general purposes, including capital expenditures and working capital. This intercompany money pool agreement is discussed in connection with Short-term Borrowings below. Prior to CPPL's IPO, the subsidiaries of the Predecessor participated in a similar money pool agreement with NiSource Finance. CPGSC administers the current money pool agreement. The cash accounts maintained by the subsidiaries of the Partnership and the Predecessor were, prior to the Separation, swept into a NiSource corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated payable, as appropriate, between NiSource and the subsidiary. Subsequent to the Separation, cash accounts maintained by subsidiaries of the Partnership were swept into a CPG corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
payable, as appropriate, between CPG and the subsidiary. The amount of interest expense and income for short-term borrowings was determined by the net position of each subsidiary in the money pool. The money pool weighted-average interest rate at December 31, 2016 and 2015 was 0.94% and 1.21%, respectively. The interest expense for short-term borrowings charged for the years ended December 31, 2016, 2015 and 2014 was $9.3 million, $0.9 million and $3.1 million, respectively.
Accounts Receivable. The Partnership includes in accounts receivable amounts due from the money pool discussed above of $167.4 million and $140.5 million at December 31, 2016 and 2015, respectively, for subsidiaries of the Partnership in a net deposit position. Also included in the balance at December 31, 2016 and December 31, 2015 are amounts due from subsidiaries of CPG for transportation and storage services of $2.5 million and $8.9 million, respectively. Net cash flows related to the money pool receivables are included as Investing Activities on the Statements of Consolidated and Combined Statements of Cash Flows. All other affiliated receivables are included as Operating Activities.
Short-term Borrowings. In connection with the closing of CPPL's IPO, the subsidiaries of the Partnership entered into an intercompany money pool agreement with NiSource Finance with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement was with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. Effective July 1, 2016, in connection with the Merger, the $1,500.0 million CPG revolving credit facility was terminated and replaced by a $2,000.0 million revolving credit facility with US Parent.
The balance of Short-term Borrowings at December 31, 2016 and December 31, 2015 of $1,432.9 million and $42.1 million, respectively, includes those subsidiaries of the Partnership in a net borrower position of the money pool discussed above. Net cash flows related to Short-term Borrowings are included as Financing Activities on the Statements of Consolidated and Combined Statements of Cash Flows.
Accounts Payable. The affiliated accounts payable balance primarily includes amounts due for services received from CPGSC, and interest payable to CPG.
Long-term Debt. In May 2015, the Partnership's outstanding intercompany debt transferred from NiSource Finance to CPG. The Partnership's long-term financing requirements are satisfied through borrowings from CPG. On January 31, 2016, the Partnership amended its intercompany credit agreement with CPG to extend the maturity date of the note originating on December 9, 2013 from December 31, 2016 to December 31, 2020. The Partnership may borrow at any time from the origination date to December 31, 2016 not to exceed $2.6 billion. From January 1, 2017 to December 31, 2020, the Partnership may borrow at any time not to exceed $2.3 billion. As of the January 2016 amendment, the note carries a fixed interest rate of 4.70% for the outstanding borrowings as of December 31, 2016. Details of the long-term debt balance are summarized in the table below:
Origination Date | Interest Rate | Maturity Date | December 31, 2016 | December 31, 2015 | |||||||
(in millions) | |||||||||||
December 9, 2013 | 4.70 | % | December 31, 2020 | 630.9 | 630.9 | ||||||
Dividends. During the year ended December 31, 2016, the Partnership distributed $573.0 million to the limited partners. During the year ended December 31, 2015, the Partnership distributed $722.2 million to the limited partners, of which $500.0 million was a reimbursement of preformation capital expenditures with respect to the assets contributed to the Partnership. The Predecessor paid no dividends to CEG in the year ended December 31, 2014. There were no restrictions on the payment of distributions by the Partnership.
4. Gain on Sale of Assets
The Partnership recognizes gains on conveyances of mineral rights positions into earnings as any obligation associated with conveyance is satisfied. For the years ended December 31, 2016, 2015 and 2014, gains on conveyances amounted to $16.9 million, $52.3 million and $34.5 million, respectively, and are included in "Gain on sale of assets" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $9.0 million and $35.8 million received by CEVCO during the years ended December 31, 2016 and 2015, respectively, for the lease of Utica Shale and Upper Devonian gas rights in Greene and Washington Counties in Pennsylvania and Marshall and Ohio Counties in West Virginia. As of December 31, 2016 and 2015, deferred gains of approximately $0.3 million and $8.1 million, respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated Balance Sheets.
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
5. | Property, Plant and Equipment |
The Partnership’s property, plant and equipment on the Consolidated and Combined Balance Sheets are classified as follows:
At December 31, (in millions) | 2016 | 2015 | |||||
Property, plant and equipment | |||||||
Pipeline and other transmission assets | $ | 6,640.4 | $ | 6,120.0 | |||
Storage facilities | 1,415.3 | 1,370.1 | |||||
Gas stored base gas | 299.5 | 299.5 | |||||
Gathering and processing facilities | 566.9 | 370.2 | |||||
Construction work in process | 1,090.0 | 463.5 | |||||
General plant, software, and other assets | 315.4 | 307.6 | |||||
Property, plant and equipment | 10,327.5 | 8,930.9 | |||||
Accumulated Depreciation and Amortization | (3,079.8 | ) | (2,960.1 | ) | |||
Net Property, plant and equipment | $ | 7,247.7 | $ | 5,970.8 | |||
The table below lists the Partnership's applicable annual depreciation rates:
Year Ended December 31, | |||||
2016 | 2015 | 2014 | |||
Predecessor | |||||
Depreciation rates | |||||
Pipeline and other transmission assets | 1.00% - 1.73% | 1.00% - 1.73% | 1.00% - 2.55% | ||
Storage facilities | 2.19% - 3.00% | 2.19% - 3.00% | 2.19% - 3.30% | ||
Gathering and processing facilities | 1.67% - 2.50% | 1.67% - 2.50% | 1.67% - 2.50% | ||
General plant, software, and other assets | 1.00% - 10.00% | 1.00% - 10.00% | 1.00% - 10.00% | ||
6. | Goodwill |
The Partnership tests its goodwill for impairment annually as of May 1 unless indicators, events, or circumstances would require an immediate review. Goodwill is tested for impairment using financial information at the reporting unit level, referred to as the Columbia Gas Transmission Operations reporting unit, which is consistent with the level of discrete financial information reviewed by management. The Columbia Gas Transmission Operations reporting unit includes the following entities: Columbia Gas Transmission (including its equity method investment in the Millennium Pipeline joint venture), Columbia Gulf and the equity method investment in Hardy Storage. All of the Partnership's goodwill relates to NiSource's acquisition of CEG in 2000, which was contributed to the Partnership prior to the IPO. The Partnership's goodwill assets at December 31, 2016 and December 31, 2015 were $1,975.5 million.
The Predecessor completed a quantitative ("step 1") fair value measurement of the reporting unit during the May 1, 2012 goodwill test. The test indicated that the fair value of the reporting unit substantially exceeded the carrying value, indicating that no impairment existed.
In estimating the fair value of Columbia Gas Transmission Operations for the May 1, 2012 test, the Partnership used a weighted average of the income and market approaches. The income approach utilized a discounted cash flow model. This model was based on management’s short-term and long-term forecast of operating performance for each reporting unit. The two main assumptions used in the models were the growth rates, which were based on the cash flows from operations for the reporting unit, and the weighted average cost of capital, or discount rate. The starting point for the reporting unit’s cash flow from operations was the detailed five year plan, which takes into consideration a variety of factors such as the current economic environment, industry trends, and specific operating goals set by management. The discount rates were based on trends in overall market as well as industry specific variables and include components such as the risk-free rate, cost of debt, and company volatility at May 1, 2012. Under the market approach, the Partnership utilized three market-based models to estimate the fair value of the reporting unit:
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
(i) the comparable company multiples method, which estimated fair value of the reporting unit by analyzing EBITDA multiples of a peer group of publicly traded companies and applying that multiple to the reporting unit’s EBITDA, (ii) the comparable transactions method, which valued the reporting unit based on observed EBITDA multiples from completed transactions of peer companies and applying that multiple to the reporting unit’s EBITDA, and (iii) the market capitalization method, which used the NiSource share price and allocated NiSource’s total market capitalization among both the goodwill and non-goodwill reporting units based on the relative EBITDA, revenues, and operating income of each reporting unit. Each of the three market approaches were calculated with the assistance of a third-party valuation firm, using multiples and assumptions inherent in today’s market. The degree of judgment involved and reliability of inputs into each model were considered in weighting the various approaches. The resulting estimate of fair value of the reporting unit, using the weighted average of the income and market approaches, exceeded its carrying value, indicating that no impairment exists under step 1 of the annual impairment test.
Certain key assumptions used in determining the fair value of the reporting unit included planned operating results, discount rates and the long-term outlook for growth. In 2012, the Partnership used the discount rate of 5.60% for Columbia Gas Transmission Operations, resulting in excess fair value of approximately $1,643.0 million.
GAAP allows entities testing goodwill for impairment the option of performing a qualitative ("step 0") assessment before calculating the fair value of a reporting unit for the goodwill impairment test. If a step 0 assessment is performed, an entity is no longer required to calculate the fair value of a reporting unit unless the entity determines that, based on that assessment, it is more likely than not that its fair value is less than its carrying amount.
The Partnership applied the qualitative step 0 analysis to the reporting unit for the annual impairment test performed as of May 1, 2016. For the current year test, the Partnership assessed various assumptions, events and circumstances that would have affected the estimated fair value of the reporting unit as compared to its base line May 1, 2012 step 1 fair value measurement. The recent CPG Merger Agreement and acquisition price were incorporated into the current year testing. The results of this assessment indicated that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value.
The Partnership considered whether there were any events or changes in circumstances subsequent to the annual test that would reduce the fair value of the reporting unit below its carrying amount and necessitate another goodwill impairment test. On November 1, 2016, CPPL announced that it entered into an agreement and plan of merger with CPG, in which CPG will acquire all outstanding common units of CPPL. The acquisition price leads to a similar valuation of the Partnership as that provided for in the CPG Merger Agreement, providing further evidence that it is not more likely than not that the reporting unit fair value is less than the reporting unit carrying value. In consideration of all relevant factors, there were no indicators that would require goodwill impairment testing subsequent to May 1, 2016.
7. | Asset Retirement Obligations |
Changes in the Partnership’s liability for asset retirement obligations for the years 2016 and 2015 are presented in the table below:
(in millions) | 2016 | 2015 | |||||
Balance as of January 1, | $ | 25.3 | $ | 23.2 | |||
Noncontributed net parent investment adjustments(1) | — | (0.4 | ) | ||||
Accretion expense | 1.1 | 1.2 | |||||
Additions | — | 4.1 | |||||
Change in estimated cash flows | (6.1 | ) | (2.8 | ) | |||
Balance as of December 31, | $ | 20.3 | $ | 25.3 | |||
(1) Reflects the removal of amounts related to Crossroads Pipeline Company, which was included in the Predecessor, but was not contributed to the Partnership.
The asset retirement obligations above relate to the modernization program of pipelines and transmission facilities, the retiring of offshore facilities, polychlorinated biphenyl ("PCB") remediation and asbestos removal at several compressor and measuring stations. The Partnership recognizes that certain assets, which include gas pipelines and natural gas storage wells, will operate for an indeterminate future period when properly maintained. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified.
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
8. | Regulatory Matters |
Regulatory Assets and Liabilities
Current and noncurrent regulatory assets and liabilities were comprised of the following items:
At December 31, (in millions) | 2016 | 2015 | |||||
Assets | |||||||
Unrecognized pension benefit and other postretirement benefit costs | $ | 107.3 | $ | 127.1 | |||
Other postretirement costs | 6.1 | 8.9 | |||||
Other | 2.5 | 3.1 | |||||
Total Regulatory Assets | $ | 115.9 | $ | 139.1 | |||
At December 31, (in millions) | 2016 | 2015 | |||||
Liabilities | |||||||
Cost of removal | $ | 140.5 | $ | 153.5 | |||
Modernization revenue sharing | 7.4 | — | |||||
Other postretirement costs | 134.3 | 155.6 | |||||
Other | — | 1.8 | |||||
Total Regulatory Liabilities | $ | 282.2 | $ | 310.9 | |||
No regulatory assets are earning a return on investment at December 31, 2016. Regulatory assets of $8.6 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life of up to 6 years.
Assets:
Unrecognized pension benefit and other postretirement benefit costs – In 2007, the Predecessor adopted certain updates of ASC 715 which required, among other things, the recognition in other comprehensive income or loss of the actuarial gains or losses and the prior service costs or credits that arise during the period but that are not immediately recognized as components of net periodic benefit costs. Certain subsidiaries defer the costs as a regulatory asset in accordance with regulatory orders to be recovered through base rates.
Other postretirement costs – Primarily comprised of costs approved through rate orders to be collected through future base rates, revenue riders or tracking mechanisms.
Liabilities:
Cost of removal - Represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of some rate-regulated subsidiaries for future costs to be incurred.
Regulatory effects of accounting for income taxes - Represents amounts related to state income taxes collected at a higher rate than the current statutory rates assumed in rates, which is being amortized to earnings in association with depreciation on related property. The regulatory liability was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level.
Modernization revenue sharing - Represents amounts related to the revenue sharing mechanism within the Columbia Gas Transmission modernization program. The revenue sharing mechanism requires Columbia Gas Transmission to share 75% of specified revenues in excess of an annual threshold.
Other postretirement costs - Primarily represents amounts being collected through rates in excess of the GAAP expense on a cumulative basis. In addition, according to regulatory order, a certain level of benefit expense is recognized in the Partnership’s results, which exceeds the amount funded in the plan.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Regulatory Matters
Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved the Columbia Gas Transmission Customer Settlement (the "MOD I Settlement"). In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the MOD I Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the MOD I Settlement, which included a $50.0 million refund to max rate contract customers and a base rate reduction retroactive to January 1, 2012. Columbia Gas Transmission expects to invest approximately $1.5 billion over a five-year period, which began in 2013, to modernize its system to improve system integrity and enhance service reliability and flexibility. The MOD I Settlement with firm customers included an initial five-year term with provisions for potential extensions thereafter.
The MOD I Settlement also provided for a depreciation rate reduction to 1.5% and elimination of negative salvage rate effective January 1, 2012 and for a second base rate reduction, which began January 1, 2014, which equates to approximately $25.0 million in revenues annually thereafter.
The MOD I Settlement includes a CCRM, a tracker mechanism that will allow Columbia Gas Transmission to recover, through an additive capital demand rate, its revenue requirement for capital investments made under Columbia Gas Transmission's long-term plan to modernize its interstate transmission system. The CCRM provides for a 14.0% revenue requirement with a portion designated as a recovery of taxes other than income taxes. The additive demand rate is earned on costs associated with projects placed into service by October 31 each year. The initial additive demand rate was effective on February 1, 2014. The CCRM will give Columbia Gas Transmission the opportunity to recover its revenue requirement associated with a $1.5 billion investment in the modernization program. The CCRM recovers the revenue requirement associated with qualifying modernization costs that Columbia Gas Transmission incurs after satisfying the requirement associated with $100.0 million in annual maintenance capital expenditures. The CCRM applies to Columbia Gas Transmission's transportation shippers. The CCRM will not exceed $300.0 million per year in investment in eligible facilities, subject to a 15.0% annual tolerance and a total cap of $1.5 billion for the entire five-year initial term.
On January 31, 2017, Columbia Gas Transmission received FERC approval of its December 2016 filing to recover costs associated with the fourth year of its comprehensive system modernization program. In 2016, Columbia Gas Transmission placed approximately $330.0 million in modernization investments into service, bringing the total gross investment to approximately $1.3 billion over the four year period. The program includes replacement of bare steel and wrought iron pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. In December 2015, Columbia Gas Transmission filed an extension of this MOD I Settlement and has requested FERC’s approval of the customer agreement by March 31, 2016.
On March 17, 2016, Columbia Gas Transmission received approval from the Commission of its December 18, 2015 filing for the Modernization II Settlement (the "MOD II Settlement"). The MOD II Settlement continues a rate mechanism that was designed to enable Columbia Gas Transmission to recover costs associated with a multi-year modernization program focused on replacing, rehabilitating and/or rebuilding critical pipeline infrastructure and ensuring the safety and reliability of the Columbia Gas Transmission system.
The MOD II Settlement preserves and extends the core elements of the MOD I Settlement between Columbia Gas Transmission and its shippers that addressed previous modernization issues on the Columbia Gas Transmission system for three additional years. Columbia Gas Transmission expects to invest approximately $1.1 billion over the three-year extension period. Among other things, the MOD II Settlement preserves the MOD I Settlement’s $60.0 million base rate reduction and extends for a second term the CCRM that allows Columbia Gas Transmission to make annual limited filings under Section 4 of the Natural Gas Act to charge an additive capital demand rate in order to recover the revenue requirement related to certain eligible projects.
The MOD II Settlement includes an additional reduction in base rates equal to approximately $8.4 million annually effective as of January 1, 2016, discontinuing the collection of OPEB costs no longer required because of the substantial over-recovered position, and a further base rate reduction equal to approximately $12.4 million annually for a 6-year period also beginning January 1, 2016, which basically refunds amounts to customers as a result of the over-collection of OPEB costs. Columbia Gas Transmission's base rates will reset effective February 1, 2019, without the need for a rate case, and a simultaneous reduction in those base rates equal to $7.5 million annually. The MOD II Settlement includes a one-time $5.0 million settlement payment effective after FERC’s approval of the 5th year CCRM for recovery under the first phase; payment would not be expected until 2018, and a revenue sharing mechanism, which requires Columbia Gas Transmission to share 50.0% of specified revenues in
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
excess of an annual threshold. Columbia Gas Transmission has agreed to maintain a transmission depreciation rate of 1.5%, a storage depreciation rate of 2.2%, a negative salvage rate of zero percent and a moratorium through January 31, 2022 to changes in Columbia Gas Transmission’s base rates. The MOD II Settlement includes specified storage projects as eligible facilities whereby Columbia Gas Transmission may undertake construction of additional eligible facility projects in 2016-2017, with cost recovery on those projects beginning in 2019.
Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the NGA to determine whether Columbia Gulf's existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf filed a cost and revenue study with the FERC on April 5, 2016, as required by the January 21 Order. The January 21 Order directed that a hearing be conducted pursuant to an accelerated timeline and that an initial decision be issued by February 28, 2017. On June 13, 2016, the FERC trial staff, Columbia Gulf, and all of the active parties filed a Joint Motion to Suspend the Procedural Schedule and Waive Answer Period (the "Motion"). The Motion represents that the parties unanimously support the Motion and requested waiver of the answer period, which was granted. The parties reached an agreement in principle during a June 2, 2016 settlement conference that would fully resolve all matters set for hearing by the FERC. The Motion represents that the parties expect to file an offer of settlement memorializing the agreement in principle no later than July 29, 2016, and suspension of the procedural schedule will promote an efficient and speedy resolution of this matter by allowing the participants to focus their efforts on drafting the necessary settlement documents. Columbia Gulf filed the offer of settlement with the FERC in accordance with the agreement noted above.
On August 15, 2016, the administrative law judge issued a Certification of Uncontested Settlement, which noted that no parties objected to the provisions in the offer of settlement. On September 22, 2016, the FERC issued an order approving the uncontested settlement, which requires a reduction in Columbia Gulf’s daily maximum recourse rate and addresses Columbia Gulf’s treatment of postretirement benefits other than pensions, pension expenses, and regulatory expenses. The order also requires Columbia Gulf to file a general rate case under section 4 of the NGA by January 31, 2020, for rates to take effect by August 1, 2020. Other terms of the settlement are included in FERC Docket No. RP16-302-000.
Cost Recovery Trackers and other similar mechanisms. Under section 4 of the NGA, the FERC allows for the recovery of certain operating costs of our interstate transmission and storage companies that are significant and recurring in nature via cost tracking mechanisms. These tracking mechanisms allow the transmission and storage companies’ rates to fluctuate in response to changes in certain operating costs or conditions as they occur to facilitate the timely recovery of costs incurred. The tracking mechanisms involve a rate adjustment that is filed at a predetermined frequency, typically annually, with the FERC and is subject to regulatory review before new rates go into effect.
A significant portion of our revenues and expenses are related to the recovery of costs under these tracking mechanisms. The associated costs for which we are obligated are reported in operating expenses with the offsetting recoveries reflected in revenues. These costs include: third-party transportation, electric compression, and certain approved operational purchases of natural gas. The tracking of certain environmental costs ended in 2015.
Additionally, we recover fuel for company used gas and lost and unaccounted for gas through in-kind trackers where a retainage rate is charged to each customer to collect fuel. The recoveries and costs are both reflected in operating expenses.
9. | Equity Method Investments |
Certain investments of the Partnership are accounted for under the equity method of accounting. These investments are recorded within "Unconsolidated Affiliates" on the Partnership's Consolidated and Combined Balance Sheets and the Partnership's portion of the results are reflected in "Equity Earnings in Unconsolidated Affiliates" on the Partnership's Statements of Consolidated and Combined Operations. In the normal course of business, the Partnership engages in various transactions with these unconsolidated affiliates. The Partnership billed approximately $10.5 million and $13.1 million to Millennium Pipeline for services and other costs during the years ended December 31, 2016 and 2015, respectively. Contributions are made to these equity investees to fund the Partnership's share of projects.
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CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following is a list of the Partnership's equity method investments at December 31, 2016:
Investee | Type of Investment | % of Voting Power or Interest Held | |
Hardy Storage Company, LLC | LLC Membership | 49.0 | % |
Pennant Midstream, LLC | LLC Membership | 47.0 | % |
Millennium Pipeline Company, L.L.C. | LLC Membership | 47.5 | % |
39
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
As the Millennium Pipeline, Hardy Storage and Pennant investments are considered, in aggregate, material to the Partnership's business, the following table contains condensed summary financial data.
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Millennium Pipeline | |||||||||||
Statement of Income Data: | |||||||||||
Net Revenues | $ | 205.0 | $ | 206.3 | $ | 190.5 | |||||
Operating Income | 138.1 | 136.1 | 128.8 | ||||||||
Net Income | 102.5 | 98.0 | 89.6 | ||||||||
Balance Sheet Data: | |||||||||||
Current Assets | 34.8 | 35.7 | 32.1 | ||||||||
Noncurrent Assets | 969.8 | 987.1 | 1,016.3 | ||||||||
Current Liabilities | 48.0 | 44.4 | 42.6 | ||||||||
Noncurrent Liabilities | 497.2 | 535.8 | 568.3 | ||||||||
Total Members’ Equity | 459.4 | 442.6 | 437.5 | ||||||||
Contribution/Distribution Data:(1) | |||||||||||
Contributions to Millennium Pipeline | 6.2 | 1.4 | 2.6 | ||||||||
Distribution of earnings from Millennium Pipeline | 48.9 | 47.5 | 35.6 | ||||||||
Hardy Storage | |||||||||||
Statement of Operations Data: | |||||||||||
Net Revenues | $ | 23.5 | $ | 23.4 | $ | 23.6 | |||||
Operating Income | 15.7 | 15.3 | 16.1 | ||||||||
Net Income | 11.2 | 10.3 | 10.6 | ||||||||
Balance Sheet Data: | |||||||||||
Current Assets | 10.3 | 12.1 | 12.0 | ||||||||
Noncurrent Assets | 151.3 | 155.5 | 157.4 | ||||||||
Current Liabilities | 17.2 | 19.3 | 17.1 | ||||||||
Noncurrent Liabilities | 57.5 | 68.5 | 77.4 | ||||||||
Total Members’ Equity | 86.9 | 79.8 | 74.9 | ||||||||
Contribution/Distribution Data:(1) | |||||||||||
Contributions to Hardy Storage | — | — | — | ||||||||
Distribution of earnings from Hardy Storage | 2.0 | 2.6 | 2.2 | ||||||||
Pennant | |||||||||||
Statement of Operations Data: | |||||||||||
Net Revenues | $ | 38.2 | $ | 34.6 | $ | 8.5 | |||||
Operating Income (Loss) | 21.2 | 17.8 | (2.4 | ) | |||||||
Net Income (Loss) | 21.2 | 17.8 | (2.4 | ) | |||||||
Balance Sheet Data: | |||||||||||
Current Assets | 9.8 | 11.0 | 23.7 | ||||||||
Noncurrent Assets | 384.0 | 389.6 | 380.0 | ||||||||
Current Liabilities | 3.5 | 8.4 | 8.6 | ||||||||
Total Members’ Equity | 390.3 | 392.2 | 395.1 | ||||||||
Contribution/Distribution Data:(1) | |||||||||||
Contributions to Pennant | — | — | 66.6 | ||||||||
Distribution of earnings from Pennant | 10.6 | 7.1 | — | ||||||||
Return of capital from Pennant | 2.2 | 16.0 | — | ||||||||
(1)Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.
40
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
10. | Income Taxes |
The components of income tax expense were as follows:
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Income Taxes | |||||||||||
Current | |||||||||||
Federal | $ | — | $ | 12.0 | $ | 21.3 | |||||
State | 0.2 | 1.2 | 5.8 | ||||||||
Total Current | 0.2 | 13.2 | 27.1 | ||||||||
Deferred | |||||||||||
Federal | — | 8.8 | 117.7 | ||||||||
State | — | 1.9 | 21.7 | ||||||||
Total Deferred | — | 10.7 | 139.4 | ||||||||
Deferred Investment Credits | — | — | (0.1 | ) | |||||||
Total Income Taxes | $ | 0.2 | $ | 23.9 | $ | 166.4 | |||||
Total income taxes were different from the amount that would be computed by applying the statutory federal income tax rate to book income before income tax. The major reasons for this difference were as follows:
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | |||||||||||||||||
Predecessor | ||||||||||||||||||||
Book income before income taxes | $ | 474.3 | $ | 557.1 | $ | 435.5 | ||||||||||||||
Tax expense at statutory federal income tax rate | 166.0 | 35.0 | % | 193.9 | 35.0 | % | 152.4 | 35.0 | % | |||||||||||
Increases (reductions) in taxes resulting from: | ||||||||||||||||||||
State income taxes, net of federal income tax benefit | 0.2 | — | 2.0 | 0.4 | 17.9 | 4.1 | ||||||||||||||
Income not subject to federal income tax at the partnership level | (166.0 | ) | (35.0 | ) | (170.6 | ) | (30.9 | ) | — | — | ||||||||||
AFUDC-Equity | — | — | (0.3 | ) | — | (3.8 | ) | (0.9 | ) | |||||||||||
Other, net | — | — | (1.1 | ) | (0.2 | ) | (0.1 | ) | — | |||||||||||
Total Income Taxes | $ | 0.2 | — | % | $ | 23.9 | 4.3 | % | $ | 166.4 | 38.2 | % | ||||||||
The effective income tax rates were zero, 4.3%, and 38.2% in 2016, 2015 and 2014, respectively. The effective tax rate for 2016 and 2015 differs from the federal tax rate of 35% primarily due to the income received following CPPL's IPO that is not subject to income tax at the partnership level. The effective tax rate is impacted by CPPL’s IPO which modified the ownership structure and now reflects partnership earnings for which the limited partners are directly responsible for the related income taxes. The effective tax rate for 2015 also differs from the federal tax rate of 35% due to the effects of tax credits, state income taxes, utility rate-making, as well as other permanent book-to-tax differences. The effective tax rate for 2014 differs from the federal tax rate of 35% primarily due to the effects of tax credits, state income taxes, utility rate-making, as well as other permanent book-to-tax differences.
Net earnings for financial statement purposes may differ significantly from taxable income reportable to limited partners as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items.
The Partnership had no unrecognized tax benefits related to uncertain tax positions as of December 31, 2016 and 2015. As of December 31, 2014, the Predecessor financial statements included no unrecognized tax benefits.
41
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.
The principal components of the Partnership’s net deferred tax liability were as follows:
At December 31, (in millions) | 2016 | 2015 | |||||
Deferred Tax Liabilities | |||||||
Accelerated depreciation and other property differences | $ | 1.0 | $ | 1.0 | |||
Deferred Tax Assets | — | — | |||||
Net Deferred Tax Liabilities | $ | 1.0 | $ | 1.0 | |||
11. | Pension and Other Postretirement Benefits |
CPG provides defined contribution plans and noncontributory defined benefit retirement plans that cover employees of subsidiaries of the Partnership. Prior to the Separation, employees of subsidiaries of the Partnership were covered by defined contributions plans and noncontributory defined benefit plans provided by NiSource. Benefits under the defined benefit retirement plans reflect the employees’ compensation, years of service and age at retirement. Additionally, CPG provides health care and life insurance benefits for certain retired employees of subsidiaries of the Partnership. The majority of employees may become eligible for these benefits if they reach retirement age while working for subsidiaries of the Partnership. The expected cost of such benefits is accrued during the employees’ years of service. Current rates charged to customers of subsidiaries of the Partnership include postretirement benefit costs. Cash contributions are remitted to tax-qualified trusts.
As of July 1, 2015, in connection with the Separation, accrued pension and postretirement benefit obligations for subsidiaries of the Partnership participants and related plan assets were transferred from NiSource to CPG. Subsidiaries of the Partnership are participants in the consolidated CPG defined benefit retirement plans ("the Plans"), and therefore, subsidiaries of the Partnership are allocated a ratable portion of CPG's trusts for the Plans in which its employees and retirees participate. As a result, the Partnership follows multiple employer accounting under the provisions of GAAP.
Pension and Other Postretirement Benefit Plans’ Asset Management. CPG employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and asset class volatility. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, small and large capitalizations. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying assets. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
To establish a long-term rate of return for plan assets assumption, past historical capital market returns and a proprietary forecast are evaluated. The long-term historical relationships between equities and fixed income are analyzed to ensure that they are consistent with the widely accepted capital market principle that assets with higher volatility generate greater return over the long run. Current market factors such as inflation and interest rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to check for reasonability and appropriateness.
The most important component of an investment strategy is the portfolio asset mix, or the allocation between the various classes of securities available to the pension and other postretirement benefit plans for investment purposes. The asset mix and acceptable minimum and maximum ranges established for the CPG plan assets represents a long-term view and are listed in the following table.
In 2016, a revised asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status (as measured by the projected benefit obligation of the qualified pension plan divided by the market value of qualified pension plan assets) increases. The asset mix and acceptable minimum and maximum ranges established by the policy for the pension fund at the pension plans funded status on December 31, 2016 are as follows:
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CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Asset Mix Policy of Funds:
Defined Benefit Pension Plan | Postretirement Benefit Plan | ||||||
Asset Category | Minimum | Maximum | Minimum | Maximum | |||
Domestic Equities | 35% | 55% | 35% | 55% | |||
International Equities | 10% | 20% | 15% | 25% | |||
Fixed Income | 30% | 50% | 20% | 50% | |||
Short-Term Investments | 0% | 10% | 0% | 10% | |||
Pension Plan and Postretirement Plan Asset Mix at December 31, 2016 and December 31, 2015:
December 31, 2016 | Defined Benefit Pension Plan Assets | Postretirement Benefit Plan Assets | |||||||||||
Asset Class | Asset Value | % of Total Assets | Asset Value | % of Total Assets | |||||||||
(in millions) | (in millions) | ||||||||||||
Domestic Equities | $ | 120.4 | 42.7 | % | $ | 90.6 | 41.5 | % | |||||
International Equities | 45.6 | 16.2 | % | 41.0 | 18.8 | % | |||||||
Fixed Income | 110.3 | 39.2 | % | 72.6 | 33.2 | % | |||||||
Cash/Other | 5.5 | 1.9 | % | 14.3 | 6.5 | % | |||||||
Total | $ | 281.8 | 100.0 | % | $ | 218.5 | 100.0 | % | |||||
December 31, 2015 | Defined Benefit Pension Plan Assets | Postretirement Benefit Plan Assets | |||||||||||
Asset Class | Asset Value | % of Total Assets | Asset Value | % of Total Assets | |||||||||
(in millions) | (in millions) | ||||||||||||
Domestic Equities | $ | 115.9 | 39.4 | % | $ | 95.3 | 44.6 | % | |||||
International Equities | 51.4 | 17.5 | % | 40.1 | 18.7 | % | |||||||
Fixed Income | 101.5 | 34.4 | % | 71.8 | 33.6 | % | |||||||
Cash/Other | 25.5 | 8.7 | % | 6.7 | 3.1 | % | |||||||
Total | $ | 294.3 | 100.0 | % | $ | 213.9 | 100.0 | % | |||||
The categorization of investments into the asset classes in the table above are based on definitions established by the CPG Benefits Committee.
Fair Value Measurements. The following table sets forth, by level within the fair value hierarchy, the CPG Pension Plan Trust and OPEB investment assets at fair value as of December 31, 2016 and 2015. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Total CPG Pension Plan Trust and OPEB investment assets at fair value classified within Level 3 were zero as of December 31, 2016 and December 31, 2015.
Valuation Techniques Used to Determine Fair Value:
Level 1 Measurements
Most common and preferred stock are traded in active markets on national and international securities exchanges and are valued at closing prices on the last business day of each period presented. Cash is stated at cost which approximates their fair value, with the exception of cash held in foreign currencies which fluctuates with changes in the exchange rates. Government bonds, short-term bills and notes are priced based on quoted market values.
43
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Level 2 Measurements
Most U.S. Government Agency obligations, mortgage/asset-backed securities, and corporate fixed income securities are generally valued by benchmarking model-derived prices to quoted market prices and trade data for identical or comparable securities. To the extent that quoted prices are not available, fair value is determined based on a valuation model that includes inputs such as interest rate yield curves and credit spreads. Securities traded in markets that are not considered active are valued based on quoted market prices, broker or dealer quotations, or alternative pricing sources with reasonable levels of price transparency. Other fixed income includes futures and options which are priced on bid valuation or settlement pricing.
Level 3 Measurements
Commingled funds that hold underlying investments that have prices which are not derived from the quoted prices in active markets are classified as Level 3. The respective fair values of these investments are determined by reference to the funds' underlying assets, which are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. These investments are often valued by investment managers on a periodic basis using pricing models that use market, income, and cost valuation methods.
The hedge funds of funds invest in several strategies including fundamental long/short, relative value, and event driven. Hedge fund of fund investments may be redeemed annually, usually with 100 days' notice. Private equity investment strategies include buy-out, venture capital, growth equity, distressed debt, and mezzanine debt. Private equity investments are held through limited partnerships.
Limited partnerships are valued at estimated fair market value based on their proportionate share of the partnership's fair value as recorded in the partnerships' audited financial statements. Partnership interests represent ownership interests in private equity funds and real estate funds. Real estate partnerships invest in natural resources, commercial real estate and distressed real estate. The fair value of these investments is determined by reference to the funds' underlying assets, which are principally securities, private businesses, and real estate properties. The value of interests held in limited partnerships, other than securities, is determined by the general partner, based upon third-party appraisals of the underlying assets, which include inputs such as cost, operating results, discounted cash flows and market based comparable data. Private equity and real estate limited partnerships typically call capital over a 3 to 5 year period and pay out distributions as the underlying investments are liquidated. The typical expected life of these limited partnerships is 10-15 years and these investments typically cannot be redeemed prior to liquidation.
Net Asset Value Measurements
Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are measure at net asset value. The funds' underlying assets are principally marketable equity and fixed income securities. Units held in commingled funds are valued at the unit value as reported by the investment managers. The fair value of the investments in commingled funds has been estimated using the net asset value per share of the investments.
For the year ended December 31, 2016, there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets.
44
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts:
Fair Value Measurements (in millions) | December 31, 2016 | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||
Pension plan assets | |||||||||||||||
Cash | $ | 0.2 | $ | 0.2 | $ | — | $ | — | |||||||
Fixed income securities | |||||||||||||||
Government | 7.1 | — | 7.1 | — | |||||||||||
Corporate | 15.8 | — | 15.8 | — | |||||||||||
Commingled funds | |||||||||||||||
Short-term money markets(2) | 5.3 | ||||||||||||||
U.S. equities(2) | 75.4 | ||||||||||||||
International equities(2) | 45.6 | ||||||||||||||
Fixed income(2) | 59.2 | ||||||||||||||
Mutual funds | |||||||||||||||
U.S. equities | 45.0 | 45.0 | — | — | |||||||||||
Fixed income | 28.2 | 28.2 | — | — | |||||||||||
Pension plan assets subtotal | 281.8 | 73.4 | 22.9 | — | |||||||||||
Other postretirement benefit plan assets | |||||||||||||||
Cash | 0.4 | 0.4 | — | — | |||||||||||
Commingled funds | |||||||||||||||
Short-term money markets(2) | 13.9 | ||||||||||||||
U.S. equities(2) | 0.9 | ||||||||||||||
Mutual funds | |||||||||||||||
U.S. equities | 89.7 | 89.7 | — | — | |||||||||||
International equities | 41.0 | 41.0 | — | — | |||||||||||
Fixed income | 72.6 | 72.6 | — | — | |||||||||||
Other postretirement benefit plan assets subtotal | 218.5 | 203.7 | — | — | |||||||||||
Due to brokers, net(1) | (0.2 | ) | |||||||||||||
Accrued investment income/dividends | 0.5 | ||||||||||||||
Total pension and other postretirement benefit plan assets | $ | 500.6 | $ | 277.1 | $ | 22.9 | $ | — | |||||||
(1)This class represents pending trades with brokers.
(2)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2016:
(in millions) | Fair Value | Unfunded Commitments | Redemption Frequency | Redemption Notice Period | |||||||
Commingled Funds | |||||||||||
Short-term money markets | $ | 19.2 | $ | — | Daily | 1 day | |||||
U.S. equities | 76.3 | — | Daily | 1 day | |||||||
International equities | 45.6 | — | Daily | 2 days | |||||||
Fixed income | 59.2 | — | Daily | 2-3 days | |||||||
Total | $ | 200.3 | $ | — | |||||||
45
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table reflects the Partnership's allocation of pension and other postretirement benefit amounts:
Fair Value Measurements (in millions) | December 31, 2015 | Quoted Prices in Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | |||||||||||
Pension plan assets | |||||||||||||||
Cash | $ | 0.8 | $ | 0.8 | $ | — | $ | — | |||||||
Equity securities | |||||||||||||||
International equities | 5.4 | 5.4 | — | — | |||||||||||
Fixed income securities | |||||||||||||||
Government | 7.1 | — | 7.1 | — | |||||||||||
Corporate | 10.8 | — | 10.8 | — | |||||||||||
Commingled funds | |||||||||||||||
Short-term money markets(2) | 25.5 | ||||||||||||||
U.S. equities(2) | 115.9 | ||||||||||||||
International equities(2) | 45.7 | ||||||||||||||
Fixed income(2) | 83.1 | ||||||||||||||
Pension plan assets subtotal | 294.3 | 6.2 | 17.9 | — | |||||||||||
Other postretirement benefit plan assets | |||||||||||||||
Commingled funds | |||||||||||||||
Short-term money markets(2) | 6.8 | ||||||||||||||
U.S. equities(2) | 13.0 | ||||||||||||||
Mutual funds | |||||||||||||||
U.S. equities | 82.3 | 82.3 | — | — | |||||||||||
International equities | 40.1 | 40.1 | — | — | |||||||||||
Fixed income | 71.7 | 71.7 | — | — | |||||||||||
Other postretirement benefit plan assets subtotal | 213.9 | 194.1 | — | — | |||||||||||
Due to brokers, net(1) | (0.3 | ) | |||||||||||||
Accrued investment income/dividends | 0.5 | ||||||||||||||
Total pension and other postretirement benefit plan assets | $ | 508.4 | $ | 200.3 | $ | 17.9 | $ | — | |||||||
(1)This class represents pending trades with brokers.
(2)This class of investments is measured at fair value using the net asset value per share and has not been classified in the fair value hierarchy.
46
CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The table below sets forth a summary of changes in the fair value of the Plan’s Level 3 assets for the year ended December 31, 2015:
(in millions) | Balance at January 1, 2015 | Total gains or losses (unrealized / realized) | Purchases | (Sales) | Transfers into/(out of) level 3 | Separation Allocation(1) | Balance at December 31, 2015 | ||||||||||||||||||||
Fixed income securities | |||||||||||||||||||||||||||
Other fixed income | $ | 0.1 | $ | — | $ | — | $ | — | $ | — | $ | (0.1 | ) | $ | — | ||||||||||||
Private equity limited partnerships | |||||||||||||||||||||||||||
U.S. multi-strategy | 7.3 | — | — | — | — | (7.3 | ) | — | |||||||||||||||||||
International multi-strategy | 4.6 | — | — | — | — | (4.6 | ) | — | |||||||||||||||||||
Distress opportunities | 1.0 | — | — | — | — | (1.0 | ) | — | |||||||||||||||||||
Real estate | 2.3 | — | — | — | — | (2.3 | ) | — | |||||||||||||||||||
Total | $ | 15.3 | $ | — | $ | — | $ | — | $ | — | $ | (15.3 | ) | $ | — | ||||||||||||
(1)Level 3 assets were not contributed to the Plans upon Separation from NiSource and no subsequent investments were made in Level 3 assets post Separation.
The table below sets forth a summary of unfunded commitments, redemption frequency and redemption notice periods for certain investments that are measured at fair value using the net asset value per share for the year ended December 31, 2015:
(in millions) | Fair Value | Unfunded Commitments | Redemption Frequency | Redemption Notice Period | |||||||
Commingled Funds | |||||||||||
Short-term money markets | $ | 32.3 | $ | — | Daily | 1 day | |||||
U.S. equities | 128.9 | — | Monthly | 3 days | |||||||
International equities | 45.7 | — | Monthly | 14-30 days | |||||||
Fixed income | 83.1 | — | Monthly | 3 days | |||||||
Total | $ | 290.0 | $ | — | |||||||
As noted above, the Partnership follows multiple employer accounting under the provisions of GAAP and therefore, is allocated a ratable portion of the CPG’s grantor trusts for the plans in which its employees and retirees participate. The allocation of the fair value of assets is based upon the ratable share of plan funding and participant benefit payments. Investment activity within the trust occurs at the trust level, and the Partnership is allocated a portion of investment gains and losses based on its percentage of the total CPG projected benefit obligation.
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CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
CPG Pension and Other Postretirement Benefit Plans’ Funded Status and Related Disclosure. The following table provides a reconciliation of the plans’ funded status and amounts reflected in the Partnership’s Consolidated and Combined Balance Sheets at December 31 based on a December 31 measurement date:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
(in millions) | 2016 | 2015 | 2016 | 2015 | |||||||||||
Change in projected benefit obligation(1) | |||||||||||||||
Benefit obligation at beginning of year | $ | 327.6 | $ | 345.2 | $ | 93.4 | $ | 108.9 | |||||||
Service cost | 5.3 | 5.3 | 0.8 | 1.0 | |||||||||||
Interest cost | 12.3 | 12.5 | 3.8 | 4.0 | |||||||||||
Plan participants’ contributions | — | — | 1.8 | 1.6 | |||||||||||
Actuarial (gain) loss | (9.5 | ) | (7.3 | ) | 3.9 | (11.6 | ) | ||||||||
Settlement loss | 2.0 | — | — | — | |||||||||||
Benefits paid | (33.5 | ) | (23.5 | ) | (10.8 | ) | (7.5 | ) | |||||||
Estimated benefits paid by incurred subsidy | — | — | 0.2 | 0.2 | |||||||||||
Contributed/noncontributed projected benefit obligation(2) | — | (4.6 | ) | — | (3.2 | ) | |||||||||
Projected benefit obligation at end of year | $ | 304.2 | $ | 327.6 | $ | 93.1 | $ | 93.4 | |||||||
Change in plan assets | |||||||||||||||
Fair value of plan assets at beginning of year | $ | 294.3 | $ | 304.7 | $ | 213.9 | $ | 211.6 | |||||||
Actual return on plan assets | 19.2 | 0.6 | 14.2 | (2.0 | ) | ||||||||||
Employer contributions | 1.8 | 16.5 | (0.6 | ) | 11.3 | ||||||||||
Plan participants’ contributions | — | — | 1.8 | 1.6 | |||||||||||
Benefits paid | (33.5 | ) | (23.5 | ) | (10.8 | ) | (7.5 | ) | |||||||
Contributed/noncontributed plan assets(2) | — | (4.0 | ) | — | (1.1 | ) | |||||||||
Fair value of plan assets at end of year | $ | 281.8 | $ | 294.3 | $ | 218.5 | $ | 213.9 | |||||||
Funded status at end of year | $ | (22.4 | ) | $ | (33.3 | ) | $ | 125.4 | $ | 120.5 | |||||
Amounts recognized in the statement of financial position consist of: | |||||||||||||||
Noncurrent assets | — | — | 129.1 | 120.5 | |||||||||||
Current liabilities | — | (0.1 | ) | — | — | ||||||||||
Noncurrent liabilities | (22.4 | ) | (33.2 | ) | (3.7 | ) | — | ||||||||
Net amount recognized at end of year(3) | $ | (22.4 | ) | $ | (33.3 | ) | $ | 125.4 | $ | 120.5 | |||||
Amounts recognized as regulatory assets/liabilities(4) | |||||||||||||||
Unrecognized prior service (credit) cost | $ | (2.0 | ) | $ | (3.0 | ) | $ | — | $ | 0.1 | |||||
Unrecognized actuarial loss (gain) | 106.2 | 130.3 | 3.3 | (0.4 | ) | ||||||||||
Total recognized regulatory assets (liabilities) | $ | 104.2 | $ | 127.3 | $ | 3.3 | $ | (0.3 | ) | ||||||
(1)The change in benefit obligation for Pension Benefits represents the change in Projected Benefit Obligation while the change in benefit obligation for Other Postretirement Benefits represents the change in Accumulated Postretirement Benefit Obligation.
(2)Reflects the removal of amounts related to Crossroads Pipeline Company and CPGSC, which were included in the Predecessor, but were not contributed to the Partnership, as well as the inclusion of CNS Microwave, which was not part of the Predecessor.
(3)The Partnership recognizes in its Consolidated and Combined Balance Sheets the underfunded and overfunded status of its defined benefit postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation.
(4)The Partnership determined that the future recovery of pension and other postretirement benefits costs is probable. The Partnership recorded regulatory assets and liabilities of $107.3 million and zero, respectively, as of December 31, 2016, and $127.1 million and $0.6 million, respectively, as of December 31, 2015 that would otherwise have been recorded to accumulated other comprehensive loss.
The Partnership’s accumulated benefit obligation for its pension plans was $304.2 million and $327.6 million as of December 31, 2016 and 2015, respectively. The accumulated benefit obligation as of a date is the actuarial present value of benefits attributed by the pension benefit formula to employee service rendered prior to that date and based on current and past compensation levels.
The Partnership's pension plans were underfunded by $22.4 million at December 31, 2016, compared to being underfunded by $33.3 million by December 31, 2015. The improvement in the funded status is due primarily to the return on plan assets. The Partnership contributed $1.8 million and $16.5 million to its pension plans in 2016 and 2015, respectively.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
During 2016, the Partnership's funded status for its other postretirement benefit plans improved by $4.9 million to an overfunded status of $125.4 million primarily due to the return on plan assets, offset by a decrease in the discount rates in 2016 compared to 2015. The Partnership received a reimbursement of approximately $0.6 million in 2016 and contributed approximately $11.3 million to its other postretirement benefit plans in 2015. No amounts of the Partnership’s pension or other postretirement benefit plans’ assets are expected to be returned to CPG or any of its subsidiaries in 2017.
In 2016, CPG's pension plans had year to date lump sum payouts exceeding the plans' 2016 service cost plus interest cost due to Merger related payouts as well as the non-qualified pension plan being terminated in connection with the Merger. As a result, settlement accounting was required and CPG recorded a settlement charge of $7.5 million for the year ended December 31, 2016.
The following table provides the key assumptions that were used to calculate the pension and other postretirement benefits obligations for the Partnership’s various plans as of December 31:
Pension Benefits | Other Postretirement Benefits | ||||||||||
2016 | 2015 | 2016 | 2015 | ||||||||
Weighted-average assumptions to determine benefit obligation | |||||||||||
Discount Rate | 4.10 | % | 4.05 | % | 4.25 | % | 4.28 | % | |||
Rate of Compensation Increases | 2.50 | % | 4.00 | % | |||||||
Health Care Trend Rates | |||||||||||
Trend for Next Year | 8.46 | % | 8.38 | % | |||||||
Ultimate Trend | 4.50 | % | 4.50 | % | |||||||
Year Ultimate Trend Reached | 2024 | 2022 | |||||||||
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
(in millions) | 1% point increase | 1% point decrease | |||||
Effect on service and interest components of net periodic cost | $ | 0.1 | $ | (0.1 | ) | ||
Effect on accumulated postretirement benefit obligation | 2.2 | (2.0 | ) | ||||
The Partnership expects to make contributions of zero dollars to its pension plan and approximately $1.3 million to its postretirement medical and life plans in 2017.
The following table provides benefits expected to be paid in each of the next five fiscal years, and in the aggregate for the five fiscal years thereafter. The expected benefits are estimated based on the same assumptions used to measure the Partnership's benefit obligation at the end of the year and includes benefits attributable to the estimated future service of employees:
(in millions) | Pension Benefits | Other Postretirement Benefits | Federal Subsidy Receipts | ||||||||
Year(s) | |||||||||||
2017 | $ | 25.7 | $ | 6.2 | $ | 0.3 | |||||
2018 | 26.1 | 6.3 | 0.3 | ||||||||
2019 | 26.7 | 6.4 | 0.3 | ||||||||
2020 | 28.2 | 6.4 | 0.3 | ||||||||
2021 | 28.4 | 6.4 | 0.3 | ||||||||
2022-2026 | 138.8 | 30.4 | 0.8 | ||||||||
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides the components of the plans’ net periodic benefits cost for the years ended December 31, 2016, 2015 and 2014:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
(in millions) | 2016 | 2015 | 2014 | 2016 | 2015 | 2014 | |||||||||||||||||
Predecessor | Predecessor | ||||||||||||||||||||||
Components of Net Periodic Benefit Cost (Income) | |||||||||||||||||||||||
Service cost | $ | 5.3 | $ | 5.3 | $ | 4.8 | $ | 0.8 | $ | 1.0 | $ | 1.1 | |||||||||||
Interest cost | 12.3 | 12.5 | 13.7 | 3.8 | 4.0 | 4.6 | |||||||||||||||||
Expected return on assets | (20.6 | ) | (23.6 | ) | (23.8 | ) | (14.2 | ) | (17.4 | ) | (16.5 | ) | |||||||||||
Amortization of prior service (credit) cost | (0.9 | ) | (0.9 | ) | (1.0 | ) | 0.1 | 0.1 | 0.1 | ||||||||||||||
Recognized actuarial loss (gain) | 9.9 | 8.2 | 6.6 | 0.3 | (0.2 | ) | (0.1 | ) | |||||||||||||||
Net Periodic Benefit Cost (Income) | 6.0 | 1.5 | 0.3 | (9.2 | ) | (12.5 | ) | (10.8 | ) | ||||||||||||||
Additional loss recognized due to: | |||||||||||||||||||||||
Settlement loss | 7.5 | — | — | — | — | — | |||||||||||||||||
Total Net Periodic Benefit Cost (Income) | $ | 13.5 | $ | 1.5 | $ | 0.3 | $ | (9.2 | ) | $ | (12.5 | ) | $ | (10.8 | ) | ||||||||
The $12.0 million increase in the actuarially-determined pension benefit cost (income) is due primarily to the settlement charge and a decrease in the expected return on plan assets in 2016 compared to 2015. For its other postretirement benefit plans, the Partnership recognized $9.2 million in net periodic benefit income in 2016 compared to net periodic benefit income of $12.5 million in 2015 due primarily to a decrease in the expected return on plan assets in 2016 compared to 2015.
The following table provides the key assumptions that were used to calculate the net periodic benefits cost for the Partnership’s various plans:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||||
2016 | 2015 | 2014 | 2016 | 2015 | 2014 | ||||||||||||
Predecessor | Predecessor | ||||||||||||||||
Weighted-average assumptions to determine net periodic benefit cost | |||||||||||||||||
Discount Rate | 3.90 | % | 3.84 | % | 4.34 | % | 4.11 | % | 4.09 | % | 4.74 | % | |||||
Expected Long-Term Rate of Return on Plan Assets | 7.29 | % | 8.20 | % | 8.30 | % | 6.81 | % | 8.06 | % | 8.14 | % | |||||
Rate of Compensation Increases | 4.00 | % | 4.00 | % | 4.00 | % | |||||||||||
The Partnership believes it is appropriate to assume an 7.29% and 6.81% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2016 pension benefits cost. This is primarily based on asset mix and historical rates of return.
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
The following table provides other changes in plan assets and projected benefit obligations recognized in other comprehensive income or regulatory asset or liability:
Pension Benefits | Other Postretirement Benefits | ||||||||||||||
(in millions) | 2016 | 2015 | 2016 | 2015 | |||||||||||
Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities | |||||||||||||||
Settlements | $ | (7.5 | ) | $ | — | $ | — | $ | — | ||||||
Net actuarial (gain) loss | (6.2 | ) | 14.1 | 3.9 | 7.8 | ||||||||||
Less: amortization of prior service cost (credit) | 0.9 | 0.9 | (0.1 | ) | (0.1 | ) | |||||||||
Less: amortization of net actuarial (gain) loss | (9.9 | ) | (8.2 | ) | (0.3 | ) | 0.2 | ||||||||
Total recognized in regulatory assets/liabilities | $ | (22.7 | ) | $ | 6.8 | $ | 3.5 | $ | 7.9 | ||||||
Amount recognized in net periodic benefit cost and regulatory assets/liabilities | $ | (9.2 | ) | $ | 8.3 | $ | (5.7 | ) | $ | (4.6 | ) | ||||
Based on a December 31, 2016 measurement date, the net unrecognized actuarial (gain) loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2017 for the pension plans are $8.1 million, $(0.9) million and zero, respectively, and for other postretirement benefit plans are $0.4 million, $0.1 million and zero, respectively.
12. | Fair Value |
The Partnership has certain financial instruments that are not measured at fair value on a recurring basis but nevertheless are recorded at amounts that approximate fair value due to their liquid or short-term nature, including cash and cash equivalents, customer deposits, and short-term borrowings-affiliated. The Partnership’s long-term debt-affiliated is recorded at historical amounts.
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value.
Long-term debt-affiliated. The fair value of these securities is estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. On January 31, 2016, the Partnership amended its intercompany credit agreement to extend the maturity date and apply a fixed interest rate. Prior to this amendment, the fair value approximated carrying value as these securities bore interest at variable rates. These fair value measurements are classified as Level 2 within the fair value hierarchy. For the years ended December 31, 2016 and 2015, there were no changes in the method or significant assumptions used to estimate the fair value of the financial instruments.
The carrying amount and estimated fair values of financial instruments were as follows:
At December 31, (in millions) | Carrying Amount 2016 | Estimated Fair Value 2016 | Carrying Amount 2015 | Estimated Fair Value 2015 | |||||||||||
Long-term debt-affiliated | $ | 630.9 | $ | 670.5 | $ | 630.9 | $ | 630.9 | |||||||
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
13.Other Commitments and Contingencies
A.Guarantees and Indemnities. In the normal course of its business, the Partnership and certain subsidiaries enter into various agreements providing financial or performance assurance to third parties on behalf of the parent or certain subsidiaries. Such agreements include guarantees and stand-by letters of credit. These agreements are entered into primarily to support or enhance the creditworthiness otherwise attributed to the parent or a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the parent or the subsidiaries' intended commercial purposes. The total guarantees and indemnities in existence at December 31, 2016 and the years in which they expire were:
(in millions) | Total | 2017 | 2018 | 2019 | 2020 | 2021 | After | ||||||||||||||
Guarantees of debt | $ | 2,750.0 | $ | — | $ | 500.0 | $ | — | $ | 750.0 | $ | — | $ | 1,500.0 | |||||||
Guarantees of Debt. The Partnership, together with CEG and OpCo GP (the "Guarantors"), have guaranteed payment of $2,750.0 million in aggregated principal amount of CPG's senior notes. Each Guarantor is required to comply with covenants under the debt indenture and in the event of default the Guarantors would be obligated to pay the debt's principal and related interest. The Partnership does not anticipate that it will have any difficulty maintaining compliance. The guarantees of any Guarantor may be released under certain circumstances.
Lines and Letters of Credit. CPPL maintained a $500.0 million senior revolving credit facility, of which $50.0 million was available for issuance of letters of credit. The Partnership, together with CPG, CEG and OpCo GP, each fully guaranteed the CPPL credit facility. On June 29, 2016, in anticipation of the Merger, all outstanding borrowings, facility fees and interest were paid in full and the revolving credit facility was terminated. CPG maintained a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit was available. The Partnership, together with CEG and OpCo GP, each fully guaranteed the CPG credit facility. On July 1, 2016, in connection with the Merger, all existing letters of credit were migrated to a TransCanada credit facility and the CPG revolving credit facility was terminated.
CPG's commercial paper program (the “Program”) had a program limit up to $1,000.0 million. The Partnership, together with CEG and OpCo GP, each agreed, jointly and severally, unconditionally and irrevocably to guarantee payment in full of the principal of and interest (if any) on the promissory notes. On June 30, 2016, in anticipation of the Merger, the Program was terminated. CPG had no Promissory Notes outstanding under the Program at the time of termination.
Other Legal Proceedings. In the normal course of its business, the Partnership has been named as a defendant in various legal proceedings. In the opinion of management, the ultimate disposition of these currently asserted claims will not have a material impact on the Partnership’s consolidated and combined financial statements.
B.Environmental Matters. The Partnership's operations are subject to environmental statutes and regulations related to air quality, water quality, hazardous waste and nonhazardous waste. Historically, the Partnership’s environmental compliance costs have not had a material adverse effect on its results of operations; but there can be no assurance that such costs will not be material in the future or that such compliance with existing, amended or new legal requirements will not have a material adverse effect on the Partnership’s business and operating results.
It is the Partnership's continued intent to address environmental issues in cooperation with regulatory authorities in such a manner as to achieve mutually acceptable compliance plans. However, there can be no assurance that fines and penalties will not be incurred.
The Partnership records accruals to cover environmental remediation at various sites. The current portion of this accrual is included in “Other accruals” in the Consolidated Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated Balance Sheets.
Air
The Clean Air Act ("CAA") and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. The actions listed below
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
could require further reductions in emissions from various emission sources. The Partnership will continue to closely monitor developments in these matters.
National Ambient Air Quality Standards ("NAAQS"). The federal CAA requires the United States Environmental Protection Agency ("EPA") to set NAAQS for particulate matter and five other pollutants considered harmful to public health and the environment. Periodically, the EPA imposes new or modifies existing NAAQS. States that contain areas that do not meet the new or revised standards must take steps to maintain or achieve compliance with the standards. These steps could include additional pollution controls on boilers, engines, turbines, and other facilities owned by gas transmission operations.
Climate Change. The EPA has already promulgated regulations requiring the monitoring and reporting of GHG emissions from, among other sources, certain onshore natural gas transmission and storage facilities, including 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 United States on an annual basis. In August 2016, the EPA proposed a rule revising provisions of the Prevention of Significant Deterioration ("PSD") and Title V Permitting Regulations to conform with the United States Supreme Court's decision in UARG v. EPA, 134 S. Ct. 2427 (2014), and the amended judgment issued by the D.C. Circuit, in Coalition for Responsible Regulation v. EPA, Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir. April 10, 2015). For instance, the August 2016 proposed rule seeks to ensure that neither the PSD nor the Title V rules require a source to obtain a permit solely because the source emits or has the potential to emit ("PTE") GHGs above the applicable regulatory thresholds. In addition, the EPA is also proposing a significant emissions rate ("SER") of 75,000 tons per year carbon dioxide equivalent for GHGs under the PSD program that would establish an appropriate threshold level below which Best Available Control Technology ("BACT") is not required for a source’s GHG emissions. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.
New Source Performance Standards: In August 2015, the EPA proposed to regulate fugitive methane emissions for compressor stations in the natural gas transmission and storage sector. The proposed rule was subsequently published in the Federal Register on September 18, 2015. In May 2016, the EPA finalized the rule to regulate fugitive methane emissions in the natural gas transmission and storage sector. The final rule was subsequently published in the Federal Register on June 3, 2016. The Partnership is working with industry groups to litigate the delay of repair criteria in the Final Rule and to clarify ambiguities within the rule. Currently, the Partnership's facilities are not impacted by this rule. New or modified sources installed in subsequent years will be impacted by this rule at a cost of approximately $30,000/site/year. Based on the current capital project schedule, 16 new or modified facilities will be impacted by this rule in 2019 at a total estimated cost of $500,000 annually thereafter.
Pipeline Safety
In March 2016, PHMSA announced a proposed rulemaking that would, if adopted, impose more stringent requirements for certain gas lines and gathering lines under varying circumstances. Among other things, the proposed rulemaking would extend certain of PHMSA’s current regulatory safety programs for gas pipelines beyond “high consequence areas” to cover gas pipelines found in newly defined “moderate consequence areas” that contain as few as 5 dwellings within the potential impact area; require gas pipelines installed before 1970 that are currently exempted from certain pressure testing obligations to be tested to determine their maximum allowable operating pressures (“MAOP”); and require gathering lines in Class I areas, both onshore and offshore, to comply with standards regarding damage prevention, corrosion control (for metallic pipe), public education, MAOP limits, line markers and emergency planning if such gathering lines’ nominal design is 8 inches or more. In order to provide clarity and greater certainty on what may constitute a “gathering line,” PHMSA is proposing a new definition of that term under the rulemaking, which term would now encompass “a pipeline, or a connected series of pipelines, and equipment used to collect gas from the endpoint of a production facility/operation and transport it to the furthermost point downstream of the following endpoints” including the “inlet of 1st gas processing plant;” the “outlet of” a gas treatment facility (not associated with a processing plant or compressor station); the “[o]utlet of the furthermost downstream compressor” leading to a pipeline, or the “point where separate production fields are commingled.” Other new requirements proposed by PHMSA under the rulemaking would require pipeline operators to: report to PHMSA in the event of certain MAOP exceedances; strengthen PHMSA integrity management requirements; consider seismicity in evaluating threats to a pipeline; conduct hydrostatic testing for all pipeline segments manufactured using longitudinal seam welds; and use more detailed guidance from PHMSA in the selection of assessment methods to inspect pipelines. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.
On June 22, 2016, President Obama signed the new pipeline safety legislation, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016" (the “2016 Pipeline Safety Act”). Extending PHMSA’s statutory mandate through 2019, the 2016
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
Pipeline Safety Act establishes or continues the development of stringent requirements affecting pipeline safety. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.
PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe natural gas and hazardous liquid pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. This new rule allows PHMSA to impose restrictions, prohibitions, and require safety measures without giving operators prior notice or an opportunity for a hearing. In contrast to PHMSA’s past practice of issuing Corrective Action Orders to an individual owner, operator, or facility, under the new rule PHMSA can issue an Emergency Order for numerous entities. PHMSA has until March 19, 2017 to issue a permanent final rule, when this temporary rule expires. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.
C.Operating Lease Commitments. The Partnership leases assets in several areas of its operations. Payments made in connection with operating leases were $20.3 million in 2016, $18.5 million in 2015 and $14.9 million in 2014, and are primarily charged to operation and maintenance expense as incurred.
Future minimum rental payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are:
(in millions) | Operating Leases (1) | ||
2017 | $ | 8.5 | |
2018 | 7.4 | ||
2019 | 6.6 | ||
2020 | 6.3 | ||
2021 | 5.5 | ||
After | 23.5 | ||
Total future minimum payments | $ | 57.8 | |
(1) Operating lease expense includes amounts for fleet leases and storage well leases that can be renewed beyond the initial lease term, but the anticipated payments associated with the renewals do not meet the definition of expected minimum lease payments and, therefore, are not included above.
D.Service Obligations. The Partnership has entered into various service agreements whereby the Partnership is contractually obligated to make certain minimum payments in future periods. The Partnership has pipeline service agreements that provide for pipeline capacity, transportation and storage services. These agreements, which have expiration dates ranging from 2017 to 2031, require the Partnership to pay fixed monthly charges.
The estimated aggregate amounts of minimum fixed payments at December 31, 2016, were:
(in millions) | Pipeline Service Agreements | ||
2017 | $ | 67.0 | |
2018 | 63.4 | ||
2019 | 55.9 | ||
2020 | 38.4 | ||
2021 | 32.2 | ||
After | 187.0 | ||
Total future minimum payments | $ | 443.9 | |
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
14.Accumulated Other Comprehensive Loss
The following table displays the activity of Accumulated Other Comprehensive Loss, net of tax:
(in millions) | Gains and Losses on Cash Flow Hedges(1) | Pension and OPEB Items(1) | Accumulated Other Comprehensive Loss(1) | ||||||||
Balance as of January 1, 2014 - Predecessor | $ | (17.6 | ) | $ | (0.1 | ) | $ | (17.7 | ) | ||
Other comprehensive income before reclassifications | — | — | — | ||||||||
Amounts reclassified from accumulated other comprehensive income | 1.0 | — | 1.0 | ||||||||
Net current-period other comprehensive income | 1.0 | — | 1.0 | ||||||||
Balance as of December 31, 2014 - Predecessor | $ | (16.6 | ) | $ | (0.1 | ) | $ | (16.7 | ) | ||
Predecessor net tax liabilities not assumed by the Partnership(2) | (10.2 | ) | (0.1 | ) | (10.3 | ) | |||||
Other comprehensive income before reclassifications | — | (0.3 | ) | (0.3 | ) | ||||||
Amounts reclassified from accumulated other comprehensive income | 1.5 | 0.1 | 1.6 | ||||||||
Net current-period other comprehensive income | 1.5 | (0.2 | ) | 1.3 | |||||||
Balance as of December 31, 2015 | $ | (25.3 | ) | $ | (0.4 | ) | $ | (25.7 | ) | ||
Other comprehensive income before reclassifications | — | 1.4 | 1.4 | ||||||||
Amounts reclassified from accumulated other comprehensive income | 2.1 | (1.1 | ) | 1.0 | |||||||
Net current-period other comprehensive income | 2.1 | 0.3 | 2.4 | ||||||||
Balance as of December 31, 2016 | $ | (23.2 | ) | $ | (0.1 | ) | $ | (23.3 | ) | ||
(1)All amounts prior to CPPL's IPO are net of tax. Amounts in parentheses indicate debits.
(2) Reflects the non-cash elimination of all historical current and deferred income taxes other than Tennessee state income taxes that will continue to be borne by the Partnership post-IPO.
Equity Method Investment
During 2008, Millennium Pipeline, in which the Partnership has an equity investment, entered into three interest rate swap agreements with a notional amount totaling $420.0 million with seven counterparties. During August 2010, Millennium Pipeline completed the refinancing of its long-term debt, securing permanent fixed-rate financing through the private placement issuance of two tranches of notes totaling $725.0 million, $375.0 million at 5.33% due June 30, 2027 and $350.0 million at 6.00% due June 30, 2032. Upon the issuance of these notes, Millennium Pipeline repaid all outstanding borrowings under its credit agreement, terminated the sponsor guarantee, and cash settled the interest rate hedges. These interest rate swap derivatives were primarily accounted for as cash flow hedges by Millennium Pipeline. As an equity method investment, the Partnership is required to recognize a proportional share of Millennium Pipeline’s OCI. The remaining unrecognized loss of $23.2 million, before tax, related to these terminated interest rate swaps is being amortized over a 15 year period ending June 2025 into earnings using the effective interest method through interest expense as interest payments are made by Millennium Pipeline. The unrecognized loss of $23.2 million and $25.0 million at December 31, 2016 and December 31, 2015, respectively, is included in unrealized losses on cash flow hedges above.
15. | Other, Net |
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
AFUDC Equity | $ | 34.9 | $ | 28.3 | $ | 11.0 | |||||
Miscellaneous | 1.0 | 3.7 | (2.2 | ) | |||||||
Total Other, net | $ | 35.9 | $ | 32.0 | $ | 8.8 | |||||
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Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
16. | Segments of Business |
Operating segments are components of an enterprise for which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. As of December 31, 2016, TransCanada's EVP and President, Natural Gas Pipelines is the chief operating decision maker.
At December 31, 2016, the Partnership’s operations comprise one operating segment. The Partnership's segment offers gas transportation and storage services for LDCs, marketers and industrial and commercial customers located in northeastern, mid-Atlantic, Midwestern and southern states and the District of Columbia along with unregulated businesses that include midstream services and development of mineral rights positions. The chief operating decision maker evaluates the performance of the Partnership operations and determines how to allocate resources on a consolidated basis.
17.Supplemental Cash Flow Information
The following tables provide additional information regarding the Partnership’s Statements of Consolidated and Combined Cash Flows for the years ended December 31, 2016, 2015 and 2014:
Year Ended December 31, (in millions) | 2016 | 2015 | 2014 | ||||||||
Predecessor | |||||||||||
Supplemental Disclosures of Cash Flow Information | |||||||||||
Non-cash transactions: | |||||||||||
Capital expenditures included in current liabilities(1) | $ | 143.7 | $ | 122.7 | $ | 78.5 | |||||
Schedule of interest and income taxes paid: | |||||||||||
Cash paid for interest, net of interest capitalized amounts | $ | 33.4 | $ | 39.3 | $ | 53.6 | |||||
Cash paid for income taxes | — | 0.2 | 21.5 | ||||||||
(1)Capital expenditures included in current liabilities is comprised of "Accrued capital expenditures" and certain other amounts included within "Accounts payable" on the Consolidated and Combined Balance Sheets.
18. Concentration of Credit Risk
Columbia Gas of Ohio, an affiliated party prior to the Separation, accounted for greater than 10% of total operating revenues in the years ended December 31, 2016, 2015 and 2014. The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended December 31, 2016, 2015 and 2014:
Year Ended December 31, | 2016 | 2015 | 2014 | |||||||||||||||||
(in millions) | Total Operating Revenues | Percentage of Total Operating Revenues | Total Operating Revenues | Percentage of Total Operating Revenues | Total Operating Revenues | Percentage of Total Operating Revenues | ||||||||||||||
Predecessor | ||||||||||||||||||||
Columbia Gas of Ohio(1) | $ | 169.7 | 12.3 | % | $ | 167.3 | 12.6 | % | $ | 168.5 | 12.5 | % | ||||||||
(1) Represents the gross amount of revenue contracted for with Columbia Gas of Ohio and, therefore, subject to risk at the loss of this customer. Columbia Gas of Ohio has entered into certain capacity release arrangements with third parties which ultimately can decrease the net revenue amount we receive from Columbia Gas of Ohio in any given period.
The loss of a significant portion of operating revenues from this customer would have a material adverse effect on the business of the Partnership.
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CPG OpCo LP
Notes to Consolidated and Combined Financial Statements
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
19. Quarterly Financial Data (Unaudited)
(in millions, except per unit data) | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||
2016 | |||||||||||||||
Operating Revenues | $ | 363.5 | $ | 313.2 | $ | 326.5 | $ | 375.7 | |||||||
Operating Income | 182.7 | 130.4 | 15.7 | 144.9 | |||||||||||
Net Income | 181.4 | 133.0 | 21.4 | 138.3 | |||||||||||
2015 | |||||||||||||||
Operating Revenues | $ | 339.2 | $ | 315.6 | $ | 320.0 | $ | 357.0 | |||||||
Operating Income | 162.5 | 109.5 | 143.3 | 136.7 | |||||||||||
Net Income | 131.8 | 108.6 | 145.4 | 147.4 | |||||||||||
Predecessor net income prior to CPPL's IPO on February 11, 2015 | 42.7 | — | — | — | |||||||||||
Net income attributable to the Partnership | 89.1 | 108.6 | 145.4 | 147.4 | |||||||||||
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The principal executive officer and its principal financial officer of the general partner of CPPL, the sole member of our general partner, are responsible for evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). The Company's disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and its principal financial officer of the general partner of CPPL, the sole member of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, the principal executive officer and its principal financial officer of the general partner of CPPL, the sole member of our general partner, concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective at the reasonable assurance level.
Management’s Report on Internal Control over Financial Reporting
The Company's management, including the principal executive officer and its principal financial officer of the general partner of CPPL, the sole member of our general partner, are responsible for establishing and maintaining the Company’s internal control over financial reporting, as such term is defined under Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. However, management would note that a control system can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The Company’s management has adopted the 2013 framework set forth in the Committee of Sponsoring Organizations of the Treadway Commission report, Internal Control - Integrated Framework, the most commonly used and understood framework for evaluating internal control over financial reporting, as its framework for evaluating the reliability and effectiveness of internal control over financial reporting. During 2016, the Company conducted an evaluation of its internal control over financial reporting. Based on this evaluation, the Company's management concluded that the Company’s internal control over financial reporting was effective as of the end of the period covered by this annual report.
Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the principal executive officer and its principal financial officer of the general partner of CPPL, the sole member of our general partner, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Controls
There have been no changes in the Company’s internal control over financial reporting during the most recently completed quarter covered by this report that has materially affected, or is reasonably likely to affect, the Company’s internal control over financial reporting.
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ITEM 9B. OTHER INFORMATION
None.
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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and has omitted the information called for by this Item pursuant to General Instruction (I)(2)(c) of Form 10-K.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
We have engaged Deloitte & Touche LLP ("Deloitte") as our independent registered public accounting firm. The following table sets forth fees we have paid to Deloitte & Touche LLP for the year ended December 31, 2016.
(in millions) | 2016 | |||
Audit Fees(1) | $ | 0.5 | ||
Audit-Related Fees(2) | — | |||
Tax Fees(3) | — | |||
All Other Fees(4) | — | |||
Total | $ | 0.5 | ||
(1)Audit fees relate to professional services rendered in connection with the audit of our 2016 and 2015 annual financial statements on our Form 10-K and review of financial statements included in our Form 10-Q.
(2)Audit-related fees relate to assurance and related services that are reasonably related to the performance of the audit or review of our financial statements or that are traditionally performed by the independent auditor, such as employee benefit plan audits, agreed upon procedures required to comply with financial, accounting or regulatory reporting and assistance with internal control documentation requirements.
(3)Tax fees relate to professional services rendered in connection with tax audits and tax consulting and planning services.
(4)All other fees represent fees for services not classifiable under the other categories listed in the table above.
Audit Committee Pre-Approval Policies and Procedures
During fiscal year, the Audit Committee of the MLP GP pre-approved all audit services and permitted non-audit services (other than de minimis non-audit services as defined by the Sarbanes-Oxley Act of 2002) to be provided by our independent registered public accounting firm, as required by the audit committee charter which is available at CPPL’s website at http://www.columbiapipelinepartners.com. The Audit Committee’s practice was to consider for pre-approval annually all audit, audit related and non-audit services proposed to be provided by our independent auditors for the fiscal year.
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Financial Statements and Financial Statement Schedules
The following financial statements and financial statement schedules filed as a part of the Annual Report on Form 10-K are included in Item 8, "Financial Statements and Supplementary Data."
Index | Page |
Exhibits
The exhibits filed herewith as a part of this report on Form 10-K are listed on the Exhibit Index immediately following the signature page.
Pursuant to Item 601(b), paragraph (4)(iii)(A) of Regulation S-K, certain instruments representing long-term debt of the Partnership’s subsidiaries have not been included as Exhibits because such debt does not exceed 10% of the total assets of the Partnership and its subsidiaries on a consolidated basis. The Partnership agrees to furnish a copy of any such instrument to the SEC upon request.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.
CPG OpCo LP | ||
(Registrant) | ||
By: | CPG OpCo GP LLC, its general partner | |
By: | Columbia Pipeline Partners LP, its sole member | |
By: | CPP GP LLC, its general partner | |
Date: February 17, 2017 | By: | /s/ STANLEY G. CHAPMAN, III |
Stanley G. Chapman, III | ||
President | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ | STANLEY G. CHAPMAN, III | Director and President | Date: February 17, 2017 | |||
Stanley G. Chapman, III | (Principal Executive Officer) | |||||
/s/ | NATHANIEL A. BROWN | Controller and Principal Financial Officer | Date: February 17, 2017 | |||
Nathaniel A. Brown | (Principal Financial Officer and Principal Accounting Officer) | |||||
/s/ | KRISTINE L. DELKUS | Director | Date: February 17, 2017 | |||
Kristine L. Delkus | ||||||
/s/ | KARL JOHANNSON | Director | Date: February 17, 2017 | |||
Karl Johannson | ||||||
/s/ | ALEXANDER J. POURBAIX | Director | Date: February 17, 2017 | |||
Alexander J. Pourbaix | ||||||
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EXHIBIT INDEX
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
(3.1) | Certificate of Limited Partnership of CPG OpCo LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s Quarterly Report on Form 10-Q (File No. 333-209653-02) filed on May 3, 2016). |
(3.2) | Amended and Restated Agreement of Limited Partnership of CPG OpCo LP (Incorporated by reference to Exhibit 3.2 of the Partnership’s Quarterly Report on Form 10-Q (File No. 333-209653-02) filed on May 3, 2016). |
(31.1)* | Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(31.2)* | Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
(32.1)** | Certification of Chief Executive Officer, pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(32.2)** | Certification of Chief Financial Officer, pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
(99.1)* | “Risk Factors” section excerpted and incorporated by reference from Columbia Pipeline Group, Inc.’s Annual Report on Form 10-K filed with the SEC on February 17, 2017 for the fiscal year ended December 31, 2016 filed herewith pursuant to Rule 12b-23(a)(3). |
(101.INS)* | XBRL Instance Document |
(101.SCH)* | XBRL Schema Document |
(101.CAL)* | XBRL Calculation Linkbase Document |
(101.LAB)* | XBRL Labels Linkbase Document |
(101.PRE)* | XBRL Presentation Linkbase Document |
(101.DEF)* | XBRL Definition Linkbase Document |
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