10-K

EX-99.3 7 cpgx-exx993x20160222.htm EXHIBIT 99.3 10-K

Exhibit 99.3

CPG OPCO LP

INDEX



	Page No.
Selected Financial Data	2
Management’s Discussion and Analysis of Financial Condition and Results of Operations	7
Quantitative and Qualitative Disclosures About Market Risk	23
Report of Independent Registered Public Accounting Firm	24
Consolidated and Combined Balance Sheets	25
Statements of Consolidated and Combined Operations	27
Statements of Consolidated and Combined Comprehensive Income	28
Statements of Consolidated and Combined Cash Flows	29
Statements of Consolidated and Combined Equity	30
Notes to Consolidated and Combined Financial Statements	31

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CPG OpCo LP

SELECTED FINANCIAL DATA

The following selected financial data should be read in connection with the Consolidated and Combined Financial Statements including the related notes included in this Exhibit 99.3.

On February 11, 2015, CPPL completed its offering of common units to the public ("CPPL's IPO"). For periods prior to the closing of CPPL's IPO on February 11, 2015, the selected data presented represents CPG OpCo LP Predecessor (the “Predecessor”). The Predecessor is comprised of NiSource Inc.’s ("NiSource") Columbia Pipeline Group Operations reportable segment. Substantially all of the Columbia Pipeline Group Operations reportable segment was contributed to CPG OpCo LP (the "Partnership") on February 11, 2015. The selected data covering periods prior to the closing of CPPL's IPO may not necessarily be indicative of the actual results of operations had the Partnership operated separately during those periods.

The following table presents the non-GAAP financial measures of Adjusted EBITDA and Partnership Distributable Cash Flow, which we use in our business as important supplemental measures of our performance. Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. Partnership Distributable Cash Flow is defined as Adjusted EBITDA less interest expense, maintenance capital expenditures and gain on sale of assets plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income. Adjusted EBITDA and Partnership Distributable Cash Flow are not calculated or presented in accordance with Generally Accepted Accounting Principles ("GAAP"). We explain these measures under “—Non-GAAP Financial Measures” below and reconcile Adjusted EBITDA and Partnership Distributable Cash Flow to their most directly comparable financial measures calculated and presented in accordance with GAAP.

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CPG OpCo LP

SELECTED FINANCIAL DATA (continued)



Year Ended December 31, (dollars in millions except operating data)	2015			2014			2013			2012			2011
				Predecessor			Predecessor			Predecessor			Predecessor
Statement of Operations Data:
Total Operating Revenues	$	1,331.8		$	1,346.9		$	1,179.4		$	1,000.4		$	1,005.6
Operating Expenses
Operation and maintenance	524.7			630.7			507.1			374.2			377.9
Operating and maintenance-affiliated	163.8			122.9			118.1			105.6			98.3
Depreciation and amortization	135.0			118.6			106.9			99.3			130.0
(Gain) loss on sale of assets and impairment, net	(54.7		)	(34.5		)	(18.6		)	(0.6		)	0.1
Property and other taxes	71.2			67.1			62.2			59.2			56.6
Total Operating Expenses	840.0			904.8			775.7			637.7			662.9
Equity Earnings in Unconsolidated Affiliates	60.2			46.6			35.9			32.2			14.6
Operating Income	552.0			488.7			439.6			394.9			357.3
Other Income (Deductions)
Interest expense	(0.1		)	—			—			—			—
Interest expense-affiliated	(26.8		)	(62.0		)	(37.9		)	(29.5		)	(29.8		)
Other, net	32.0			8.8			17.6			1.5			1.2
Income Taxes	23.9			166.4			152.4			136.9			125.6
Net Income	533.2			$	269.1		$	266.9		$	230.0		$	203.1
Less: Predecessor net income prior to CPPL IPO on February 11, 2015	42.7
Net income attributable to Partnership	$	490.5

Balance Sheet Data (at period end):
Total assets	$	9,159.7		$	8,107.5		$	7,261.8		$	6,623.2		$	6,142.6
Net property, plant and equipment	5,970.8			4,960.2			4,303.4			3,741.5			3,398.7
Long-term debt-affiliated, excluding amounts due within one year	630.9			1,472.8			819.8			754.7			294.7
Total liabilities	1,570.0			3,936.2			3,361.9			2,883.7			2,430.6
Total equity	7,589.7			4,171.3			3,899.9			3,739.5			3,712.0
Statement of Cash Flow Data:
Net cash from (used for):
Operating Activities	$	629.8		$	568.1		$	454.0		$	474.9		$	435.3
Investing Activities	(1,052.4		)	(864.5		)	(797.4		)	(455.5		)	(307.2		)
Financing Activities	500.3			296.6			343.1			(18.8		)	(128.1		)
Other Data:
Adjusted EBITDA	$	685.9		$	598.5		$	542.7		$	496.9		$	491.5
Adjusted EBITDA attributable to Partnership subsequent to CPPL IPO	606.5
Partnership Distributable Cash Flow	457.1
Maintenance and other capital expenditures	132.7			143.4			132.7			209.6			220.0
Expansion capital expenditures	1,073.4			700.5			664.8			280.0			81.5
Operating Data:⁽¹⁾
Contracted firm capacity (MMDth/d)⁽²⁾	14.3			13.2			12.9			13.2			13.2
Throughput (MMDth)⁽³⁾	2,022.8			2,006.1			1,997.3			2,200.0			2,393.7
Natural gas storage capacity (MMDth)⁽³⁾	287			287			287			283			282

⁽¹⁾ Excludes equity investments.

⁽²⁾ One million Dekatherms per day

⁽³⁾ One million Dekatherms

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CPG OpCo LP

SELECTED FINANCIAL DATA (continued)

Non-GAAP Financial Measures

We provide below a discussion of certain non-GAAP financial measures that from time to time we provide as additional information in order to supplement our financial statements, which are presented in accordance with GAAP.

Adjusted EBITDA and Partnership Distributable Cash Flow

We define Adjusted EBITDA as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. In addition, to the extent transactions occur that are considered unusual, infrequent or not representative of underlying trends, we will remove the effect of these items from Adjusted EBITDA. Examples of these transactions include impairments. We define Partnership Distributable Cash Flow as Adjusted EBITDA less interest expense, maintenance capital expenditures and gain on sale of assets plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income.

Adjusted EBITDA and Partnership Distributable Cash Flow are non-GAAP supplemental financial measures that management and external users of our financial statements, such as industry analysts, lenders and rating agencies, may use to assess the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentations of Adjusted EBITDA and Partnership Distributable Cash Flow will provide useful information in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Partnership Distributable Cash Flow are Net Income and Net Cash Flows from Operating Activities. Our non-GAAP financial measures of Adjusted EBITDA and Partnership Distributable Cash Flow should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA and Partnership Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA or Partnership Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA or Partnership Distributable Cash Flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA or Partnership Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

The following tables present a reconciliation of Adjusted EBITDA and Partnership Distributable Cash Flow to the most directly comparable GAAP financial measures, on a historical basis for each of the periods indicated.

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CPG OpCo LP

SELECTED FINANCIAL DATA (continued)



Year Ended December 31, (in millions)	2015			2014			2013			2012			2011
				Predecessor			Predecessor			Predecessor			Predecessor
Net Income	$	533.2		$	269.1		$	266.9		$	230.0		$	203.1
Add:
Interest expense	1.4			—			—			—			—
Interest expense-affiliated	26.8			62.0			37.9			29.5			29.8
Income taxes	23.9			166.4			152.4			136.9			125.6
Depreciation and amortization	135.0			118.6			106.9			99.3			130.0
Asset impairment⁽¹⁾	0.6			—			—			—			—
Distributions of earnings received from equity investees⁽²⁾	57.2			37.8			32.1			34.9			18.8
Less:
Equity earnings in unconsolidated affiliates⁽²⁾	60.2			46.6			35.9			32.2			14.6
Other, net⁽³⁾	32.0			8.8			17.6			1.5			1.2
Adjusted EBITDA	$	685.9		$	598.5		$	542.7		$	496.9		$	491.5
Less:
Adjusted EBITDA attributable to Predecessor prior to CPPL IPO	79.4
Adjusted EBITDA attributable to Partnership subsequent to CPPL IPO	$	606.5

Net Cash Flows from Operating Activities	$	629.8		$	568.1		$	454.0		$	474.9		$	435.3
Interest expense	1.4			—			—			—			—
Interest expense-affiliated	26.8			62.0			37.9			29.5			29.8
Current taxes	13.4			27.1			(27.5		)	92.2			48.8
Gain (loss) on sale of assets and impairment, net	54.7			34.5			18.6			0.6			(0.1		)
Other adjustments to operating cash flows	(12.7		)	(5.7		)	(12.5		)	0.8			(4.0		)
Changes in assets and liabilities	(27.5		)	(87.5		)	72.2			(101.1		)	(18.3		)
Adjusted EBITDA	$	685.9		$	598.5		$	542.7		$	496.9		$	491.5
Less:
Adjusted EBITDA attributable to Predecessor prior to CPPL IPO	79.4
Adjusted EBITDA attributable to Partnership subsequent to CPPL IPO	$	606.5

Adjusted EBITDA	$	685.9
Less:
Interest expense⁽⁴⁾	28.2
Maintenance capital expenditures⁽⁵⁾	133.8
Separation maintenance capital expenditures⁽⁶⁾	3.5
Gain on sale of assets⁽⁷⁾	55.3
Distributable cash flow attributable to Predecessor prior to CPPL IPO	67.8
Add:
Proceeds from sales of assets⁽⁸⁾	84.1
Interest income⁽⁹⁾	4.9
Capital (received) costs related to Separation⁽¹⁰⁾	(29.2		)
Partnership Distributable Cash Flow	$	457.1

⁽¹⁾ Asset impairment is an impairment charge that we consider to be unusual and not indicative of underlying trends.

⁽²⁾ These adjustments result in Adjusted EBITDA only including actual cash received from equity investees.

⁽³⁾ Refer to Note 15, "Other, Net" in the Notes to Consolidated and Combined Financial Statements for additional information.

⁽⁴⁾ Interest expense consists of interest expense and interest expense-affiliated, net of capitalized amounts.

⁽⁵⁾ Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets to replace or improve existing capital assets) made to maintain, over the long term, our operating capacity, system integrity and reliability. Examples of maintenance capital expenditures are expenditures to replace pipelines, to fund the acquisition of certain equipment, to maintain equipment reliability, integrity and safety and to address environmental laws and regulations.

⁽⁶⁾ Separation maintenance capital expenditures are capital expenditures related to the Separation.

⁽⁷⁾ Gain on sale of assets consists primarily of gains on conveyances of mineral rights positions.

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CPG OpCo LP

SELECTED FINANCIAL DATA (continued)

⁽⁸⁾ Proceeds from sales of assets includes $32.7 million cash received for asset transfers made under common control with CEG related to the Separation.

⁽⁹⁾ Interest income is primarily composed of income earned on the Partnership's lendings to the NiSource Finance money pool prior to the Separation and the CPG money pool subsequent to the Separation.

⁽¹⁰⁾ Capital (received) costs related to Separation are capital expenditures related to the Separation, offset by $32.7 million cash received for asset transfers made under common control with CEG related to the Separation, which is included in proceeds from sales of assets.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

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.

We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities.

Interstate Pipeline and Storage Assets. We own the following natural gas transportation and storage assets, which are regulated by the Federal Energy Regulatory Commission ("FERC"):

•

Columbia Gas Transmission. We own 100% of the ownership interests in Columbia Gas Transmission, LLC ("Columbia Gas Transmission"), which is an interstate natural gas pipeline system that transports and stores natural gas from the Marcellus and Utica shales and other producing basins to the midwest, mid-Atlantic and northeast regions. The system consists of 11,272 miles of natural gas transmission pipeline, 89 compressor stations with 674,905 horsepower of installed capacity and approximately 3,432 underground storage wells with approximately 290 MMDth of working gas capacity. Columbia Gas Transmission’s operations are located in Delaware, Kentucky, Maryland, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Virginia and West Virginia.

•

Columbia Gulf. We own 100% of the ownership interests in Columbia Gulf Transmission, LLC ("Columbia Gulf"), an interstate natural gas pipeline system with 3,341 miles of natural gas transmission pipeline and 11 compressor stations with approximately 470,238 horsepower of installed capacity. Interconnected to virtually every major natural gas pipeline system operating in the Gulf Coast, Columbia Gulf provides significant access to both diverse gas supplies and markets. Prompted by the rapid development of the Marcellus shale and Utica, Columbia Gulf has recently executed binding agreements for several capital projects to make the system bi-directional, which will ultimately reverse the historical flow on the system. As a result, once these projects are completed, the system will be able to receive Marcellus and Utica supplies, through upstream pipelines such as Columbia Gas Transmission, and transport those supplies to pipeline interconnects and markets along the Gulf Coast, including liquefied natural gas ("LNG") export facilities that are currently in development. Columbia Gulf’s operations are located in Kentucky, Louisiana, Mississippi, Tennessee, Texas and Wyoming.

•

Millennium Pipeline. We own a 47.5% ownership interest in Millennium Pipeline Company, L.L.C. ("Millennium Pipeline"), which transports an average of 1.1 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 for the pipeline, and DTE Millennium Company and National Grid Millennium LLC each own an equal remaining share of Millennium Pipeline.

•

Hardy Storage. We own a 49% ownership interest in Hardy Storage Company, LLC ("Hardy Storage"), which owns an underground natural gas storage field in the 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 Dekatherms per day ("Dth/d"). Columbia Hardy, a subsidiary of CEG, and Piedmont Natural Gas Company, Inc. own a 1% and 50% ownership interest, respectively, in Hardy Storage.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Gathering, Processing and Other Assets. We own the following gathering, processing and other assets:

•

Columbia Midstream. We own 100% of the ownership interests in Columbia Midstream Group, LLC ("Columbia Midstream"), which provides natural gas producer services including gathering, treating, conditioning, processing and liquids handling in the Appalachian Basin. Columbia Midstream owns approximately 123 miles of natural gas gathering pipeline and one compressor station with 6,800 horsepower of installed capacity and is currently building out infrastructure to support the growing production in the Utica and Marcellus shale plays.

•

Pennant. We own a 47.5% ownership interest in Pennant Midstream, LLC ("Pennant"), which owns approximately 49 miles of natural gas gathering pipeline infrastructure, a gas processing facility and a 36 mile natural gas liquids ("NGL") pipeline supporting natural gas production in the Utica shale. Columbia Midstream and an affiliate of Hilcorp Energy Company ("Hilcorp") jointly own Pennant, with Columbia Midstream serving as the operator of Pennant and its facilities.

•

CEVCO and Other. We own 100% of the ownership interests in Columbia Energy Ventures, LLC ("CEVCO"), which 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 productions rights in one other field. In addition, we own 100% of the ownership interests in CNS Microwave, LLC ("CNS Microwave"), which provides ancillary communication services to us and third parties.

Factors and Trends That Impact Our Business

Key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate; our customers and their requirements; and the government regulation of natural gas production, pipelines and storage. These key factors also play an important role in how we evaluate our business and how we implement our long-term strategies.

Natural gas continues to be a critical component of energy supply and demand in the U.S. The NYMEX natural gas futures contract reached a high of $13.58/one million British Thermal Units ("MMBtu") in July 2008, but has declined significantly from that high as a result of increased natural gas supply, due in large part to increased production of unconventional sources (defined by the US Energy Information Administration ("EIA") as natural gas produced from shale formations, tight gas and coal beds) such as natural gas shale plays particularly in the Marcellus and Utica shale regions. To illustrate, the EIA reported dry gas production for the month of December 2008, at 1,744,458 million cubic feet. That same statistic increased to 2,302,546 million cubic feet in October 2015. Additionally, due to the longer lead times associated with pipeline infrastructure build-outs, pipeline capacity to transport natural gas out of these shale producing regions is constrained and has led to strong interest in pipeline expansions out of the region. The significant increase in supply has maintained downward pressure on the price of natural gas with the prompt month NYMEX natural gas futures price at $2.36/MMBtu as of December 31, 2015. We believe that over the short term, natural gas prices are likely to remain relatively flat until the supply overhang has been reduced by infrastructure build-outs to connect production with consuming regions and/or exportation.

As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain areas where the economics of natural gas production are less favorable. Despite these reductions, we believe that increased drilling efficiencies and the backlog of drilled but uncompleted wells will likely lead to flat to slightly increasing year-over-year production growth levels out of the Marcellus and Utica regions. Additionally, we believe our assets are well positioned to take advantage of the targeted drilling areas.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, exportation off the continent via LNG, exportation to Mexico, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. This displacement will continue due to lower cost of natural gas as a fuel for electric generation and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, in 2010, approximately 45% of the electricity in the U.S. was generated by coal-fired power plants, and in 2014, approximately 38% of the electricity in the U.S. was generated by coal-fired power plants. In addition, the EIA’s 2015 Annual Energy Outlook projects that annual domestic consumption of natural gas will increase by approximately 13.4% from 26.1 quadrillion British Thermal Units ("Btu") in 2012 to 29.6 quadrillion Btu in 2035.

Commercial Growth and Expansion. As production and demand for our services increase in our areas of operations, we believe that we are well-positioned to attract volumes to our systems through cost-effective capacity expansions. For example, we have recently completed or we are currently undertaking the following expansion projects:

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)


•	Chesapeake LNG. This approximately $28 million project was placed into service in the second quarter of 2015 and replaced 120,000 Dth/d of existing LNG peak shaving facilities nearing the end of their useful lives.


•	Big Pine Expansion. We are investing approximately $75 million to extend the Big Pine pipeline and add compression facilities that will add incremental capacity. The project will support Marcellus shale production in western Pennsylvania. The project piping was placed into service in the third quarter of 2015 and we expect the compression to be placed into service in the second quarter of 2016.


•	East Side Expansion. This project provides access for production from the Marcellus shale to northeastern and mid-Atlantic markets. The approximately $295 million project added 312,000 Dth/d of capacity and was placed into service in the fourth quarter of 2015.


•	Washington County Gathering. A producer has contracted with us to build an approximately 20 mile gas gathering system in southwestern Pennsylvania. The initial project went into service during the third quarter of 2015 and we expect to invest approximately $120 million through 2018.


•	Kentucky Power Plant Project. We expect to invest approximately $25 million to construct 2.7 miles of 16-inch pipeline and other facilities to a power plant near Columbia Gas Transmission’s Line P. This project will provide up to 72,000 Dth/d of new firm service and is expected to be placed into service in the second quarter of 2016.


•	Gibraltar Pipeline Project. We expect to invest approximately $270 million to construct an approximately 1 MMDth/d dry gas header pipeline in southwest Pennsylvania. We expect this to be the first of multiple phases with a projected initial in-service date in the fourth quarter of 2016.


•	Utica Access Project. We expect to invest approximately $50 million to construct 4.7 miles of 24-inch pipeline to provide 205,000 Dth/d of new firm transportation to provide Utica production access to liquid trading points on Columbia Gas Transmission's system. This project is expected to be placed into service in the fourth quarter of 2016.

•

Leach XPress. This project will provide approximately 1.5 MMDth/d of capacity from the Marcellus and Utica production regions to the Leach compressor station located on the Columbia Gulf system, TCO Pool, and other markets on the Columbia Gas Transmission system. We expect the project, which involves an estimated investment of approximately $1.4 billion, to be placed into service in the fourth quarter of 2017.

•

Rayne XPress. This project will transport approximately 1 MMDth/d of southwest Marcellus and Utica production from the Leach, Kentucky interconnect with Columbia Gas Transmission towards the Rayne compressor station in southern Louisiana to reach various Gulf Coast markets. We expect the project, which involves an estimated investment of approximately $380 million, to be placed into service in the fourth quarter of 2017.


•	Millennium Lateral. We intend to invest approximately $20 million through our ownership stake in Millennium Pipeline to construct approximately 8 miles of 16-inch pipeline to a new power plant situated near Wawayanda, New York. This project will provide up to 127,000 Dth/d of new firm capacity and is expected to be placed into service in the second quarter of 2017.


•	Cameron Access Project. This project, which involves an investment of approximately $310 million, will provide 800,000 Dth/d of transportation capacity on the Columbia Gulf system to the Cameron LNG export terminal in Louisiana. We expect the project to be placed into service in the first quarter of 2018.


•	WB XPress. This project, which involves an investment of approximately $850 million, will expand Columbia Gas Transmission's WB system in order to transport approximately 1.3 MMDth/d of Marcellus production to pipeline interconnects and East Coast markets, including access to the Cove Point LNG terminal. We expect this project to be placed into service in the fourth quarter of 2018.


•	Mountaineer XPress. This approximately $2.0 billion project will provide new takeaway capacity for Marcellus and Utica production. The project will provide up to 2.7 MMDth/d of firm transportation capacity on the Columbia Gas Transmission system. We expect this project to be placed into service in the fourth quarter of 2018.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)


•	Gulf XPress. This project will provide 860,000 Dth/d of firm transportation capacity for Marcellus and Utica production on the Columbia Gulf system. This project involves an investment of approximately $0.7 billion and is expected to be placed into service in the fourth quarter of 2018.


•	Millennium Eastern System Upgrade. We intend to invest approximately $130 million through our ownership stake in Millennium Pipeline to expand eastward flow capacity by 237,500 Dth/d to Ramapo and other nearby points on the system. We expect this project to be placed into service in the fourth quarter of 2018.

In 2013, the FERC approved the modernization settlement entered into by Columbia Gas Transmission and its customers that provides recovery and return on an investment of up to $1.5 billion over a five-year period to modernize its system to improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Columbia Gas Transmission placed approximately $319 million in modernization investments into service during 2015. In January 2016, the FERC approved Columbia Gas Transmission's third annual filing for recovery under this program. In December 2015, Columbia Gas Transmission filed an extension of this settlement and has requested FERC’s approval of the customer agreement by March 31, 2016. This extension will allow Columbia Gas Transmission to invest an additional $1.1 billion over an additional three-year period through 2020. This agreement also expands the scope of facility investments covered by the program.

Our Customers. Our customer mix for natural gas transportation services includes local distribution companies ("LDC"), municipal utilities, direct industrial users, electric power generators, marketers, producers and LNG exporters. Our customers use our transportation services for a variety of reasons:


•	LDCs, municipal utilities, and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. These customers will typically enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract;


•	Producers of natural gas and LNG exporters require the ability to deliver their product to market and typically enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity; and


•	Marketers use our transportation services to capitalize on natural gas price volatility over time or between markets.

Impact of New Supply Basins and End-Use Markets. The Columbia Gulf pipeline system was originally constructed for the primary purpose of moving natural gas produced on the Gulf Coast north through Columbia Gas Transmission to midwestern and mid-Atlantic end-use markets. Increases in production in the Marcellus and Utica regions have resulted in a shift of production supply to Northeast markets, displacing the need for production in the Gulf Coast and other Western supply sources. In the past several years, access to new supply and access to new markets have been added to the system through new interconnections and other system modifications. For example, we are currently implementing projects that will make much of the system bi-directional, increasing the flexibility of how we operate this system. As a result of the development of laterals, interconnects, and bi-directional capability, we now have access to multiple strategic natural gas supply sources, including supplies on the Gulf Coast, basins in North Texas (Barnett Shale), East Texas, North Louisiana, the Marcellus and Utica regions, and the Appalachian Basin. Similarly, through interconnections with major interstate and intrastate pipelines, we also access large and growing markets in the northeast, midwest, mid-Atlantic and southeast U.S., and serve industrial, commercial, electric generation and residential customers in various states within our footprint.

Increasing Competition. Our pipeline systems compete primarily with other interstate and intrastate pipelines. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, at least in particular supply or market areas where we serve, and the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term basis, our revenues are not significantly affected by variation in customers’ actual usage resulting from increased competition during the near term. Our ability to remarket the capacity as our contracts expire may be impacted by increased competition.

Regulatory Compliance. Regulation of natural gas transportation by the FERC and other federal and state regulatory agencies, including the Department of Transportation ("DOT") has a significant impact on our business. For example, the Pipeline and

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Hazardous Materials Safety Administration ("PHMSA") office of the DOT has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. The FERC regulatory policies govern the rates and services that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under a September 15, 1999 FERC order approving an April 5, 1999 settlement, Columbia Gas Transmission remediates PCBs at specific gas transmission facilities pursuant to the Administrative Order by Consent ("AOC") and recovered a portion of those costs in rates. Columbia Gas Transmission’s ability to recover these specific costs ceased on January 31, 2015. As of December 31, 2015, Columbia Gas Transmission has remaining liabilities of $1.8 million to cover costs associated with PCB remediation related to this AOC. The cost of this PCB remediation is not expected to have a material adverse impact on our financial condition or results of operations.

Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits. Additionally, increased regulation of natural gas producers in our areas of operations, including regulation associated with hydraulic fracturing, could reduce regional supply of natural gas and therefore throughput on our assets.

Cost Recovery Trackers and other similar mechanisms. Under section 4 of the Natural Gas Act, 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.

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:


•	Revenues and contract mix, particularly the level of firm capacity subscribed;


•	Operating expenses; and


•	Adjusted EBITDA and Partnership Distributable Cash Flow.

Revenues and Contract Mix. Our results are driven primarily by the volume of natural gas transportation and storage capacity under firm and interruptible contracts, the volume of natural gas that we gather and transport, and the fees assessed for such services, as well as fees derived from royalties. One of our primary financial goals is to maximize the portion of our physical transportation and storage capacity that is contracted under multi-year firm contracts in order to enhance the stability of our revenues and cash flows. 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. To the extent that physical capacity that is contracted by firm service customers is not being fully utilized or there is excess capacity that is not contracted for firm service, we can offer such capacity to interruptible service customers.

We manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our contracts mature at various times and in various amounts of capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. We attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

of our available capacity. As of December 31, 2015, our firm revenue contracts had a weighted average remaining contract life of 4.8 years.

Transmission and Storage. Firm transportation service allows the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm transportation contracts obligate our customers to pay a fixed monthly charge to reserve an agreed-upon amount of pipeline capacity regardless of the actual pipeline capacity used by the customer during each month, which we refer to as a monthly reservation charge. In addition to monthly reservation charges, we also collect usage charges when a firm transportation customer uses the capacity it has reserved under these firm transportation contracts. Usage charges are assessed on the actual volume of natural gas transported on the transportation system. In addition, firm transportation customers are charged an overrun usage charge when the level of natural gas received for delivery from a firm transportation customer exceeds its reserved capacity. The FERC-regulated transportation and storage operators are obligated to provide firm services only if a shipper is willing to pay the FERC-approved tariff rate.

Firm storage contracts obligate our customers to pay a fixed monthly reservation charge for the right to inject, withdraw and store a specified volume of natural gas regardless of the amount of storage capacity actually utilized by the customer. Firm storage customers are also assessed usage charges for the actual quantities of natural gas injected into or withdrawn from storage.

We generate a high percentage of our transportation and storage services revenue from reservation charges under long-term, fee-based contracts, which mitigates the risk of revenue fluctuations due to changes in near-term supply and demand conditions and commodity prices.

For the year ended December 31, 2015, approximately 94.6% of the transportation and storage revenues were derived from capacity reservation fees paid under firm contracts and 3.9% of the transportation and storage revenues were derived from usage fees under firm contracts compared to 94.1% and 4.0%, respectively, for the year ended December 31, 2014.

Interruptible transportation and storage service is typically less than a year and is generally used by customers that either do not need firm service, have been unable to contract for firm service or require transportation volumes in excess of their contracted firm service. Interruptible customers and firm customers that overrun their reserved capacity level are not guaranteed capacity or service on the applicable pipeline and storage facilities. To the extent that firm contracted capacity is not being fully utilized or there is excess capacity that has not been contracted for firm service, the system can allocate such excess capacity to interruptible services. The FERC-regulated transportation and storage operators are obligated to provide interruptible services only if a shipper is willing to pay the FERC-approved tariff rate. We believe that our interruptible services are competitively priced in order to be in a position to capture short-term market opportunities as they occur. Included in our interruptible transportation and storage services is our natural gas ‘‘park and loan’’ services to assist customers in managing short-term natural gas surpluses or deficits. Under our park and loan service agreements, customers are charged a fee based on the quantities of natural gas they store in (park), or borrow from (loan), our storage facilities.

For the years ended December 31, 2015 and 2014, approximately 1.5% and 1.9%, respectively, of the transportation and storage revenues were derived from interruptible contracts.

Gathering and Processing. Our long-term, fee-based agreements provide for a fixed fee for one or more of the following midstream natural gas services: natural gas gathering, treating, conditioning, processing, compression and liquids handling. Under these agreements, which contain minimum volume commitment features, we are paid a fixed fee based on the volume of the natural gas that we gather and process. Under these agreements, our customers commit to ship a minimum annual volume of natural gas on our gathering system, or, in lieu of shipping such volumes, to pay us periodically as if that minimum amount had been shipped. If capacity is available on the pipeline or at the processing plant, a customer may exceed its minimum volume amounts and pay a fixed fee on the additional volumes. We also provide interruptible gathering and transportation service on our gathering pipelines to optimize our revenues on those systems.

Other Assets. We own the production rights in association with many of Columbia Gas Transmission’s storage facilities. Some of these production rights have been subleased to producers in return for an overriding royalty interest and upfront bonus payments. Each sublease negotiation is unique and may have additional rights or options attached to the agreement such as the option to participate as a working interest owner in drilling operations. We have also contributed our production rights in another field, Brinker storage field, to Hilcorp, and participate as an up to 5% working interest partner with an overriding interest in the development of a broader acreage dedication.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Operating Expenses. The primary component of our operating costs and expenses that we evaluate is operations and maintenance expenses. These expenses represent the cost of operating and maintaining our plants and equipment or the cost of running the physical systems. Operations and maintenance expenses are comprised primarily of labor, materials and supplies, outside services and other expenses. Maintenance and repairs, including the cost of removal of minor items of property, are charged to expense as incurred.

We are also charged or allocated expenses from Columbia Pipeline Group Services Company ("CPGSC"), a centralized service company that provides executive, financial, legal, information technology and other administrative and general services. Costs incurred for these services consist of employee compensation and benefits, outside services and other expenses. Costs are allocated using various methodologies based on a combination of gross fixed assets, total operating expense, number of employees and other measures.

Adjusted EBITDA and Partnership Distributable Cash Flow. We evaluate our business on the basis of Adjusted EBITDA and Partnership Distributable Cash Flow. Adjusted EBITDA and Partnership Distributable Cash Flow are used as supplemental financial measures by management and by external users of our financial statements such as commercial banks and others, to assess:


•	the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;


•	the ability of our assets to generate cash; and


•	the operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to their financing methods and capital structure.

Adjusted EBITDA is defined as net income before interest expense, income taxes, and depreciation and amortization, plus distributions of earnings received from equity investees and one-time transaction costs, less equity earnings in unconsolidated affiliates and other, net. Partnership Distributable Cash Flow is defined as Adjusted EBITDA less interest expense, maintenance capital expenditures and gain on sale of assets plus proceeds from the sale of assets, interest income, capital (received) costs related to the Separation and any other known differences between cash and income.

Adjusted EBITDA and Partnership Distributable Cash Flow are not calculated or presented in accordance with GAAP. Adjusted EBITDA and Partnership Distributable Cash Flow should not be considered as an alternative to GAAP net income or net cash flows from operating activities. Adjusted EBITDA and Partnership Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash flows from operating activities. You should not consider Adjusted EBITDA or Partnership Distributable Cash Flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA or Partnership Distributable Cash Flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA or Partnership Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and Partnership Distributable Cash Flow to the most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Selected Financial Data—Non-GAAP Financial Measures.”

Items Affecting Comparability of our Financial Results

The historical financial results discussed below may not be comparable to our future financial results for the following reasons:

•

For periods prior to the closing of CPPL's IPO on February 11, 2015, the financial statements included in this Exhibit 99.3 were derived from the financial statements and accounting records of the Predecessor. The Predecessor’s results of operations historically included revenues and expenses relating to 100% of NiSource’s Columbia Pipeline Group reportable segment. NiSource did not contribute Crossroads Pipeline Company, CPGSC and Central Kentucky Transmission Company to us. Such assets were historically included in NiSource’s Columbia Pipeline Group reportable segment, but constituted an immaterial impact on the Predecessor’s results of operations. CNS Microwave is not included in the Predecessor but was contributed to us.


•	Upon the closing of CPPL's IPO, short-term borrowings-affiliated and a portion of the long-term debt-affiliated (including current portion of long-term debt-affiliated) have been transferred to an affiliate of CPG and the related interest expense is no longer being incurred.


•	We are a limited partnership treated as a partnership for U.S. federal income tax purposes and, therefore, are not liable for entity-level federal income taxes. We are subject to state and local income taxes in certain jurisdictions. The

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Predecessor’s tax expense was determined on a separate return basis. Accordingly, we expect our tax expense to be significantly reduced subsequent to CPPL's IPO as compared to that of the Predecessor.

General Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on management assumptions and currently available information. To the extent management’s underlying assumptions about or interpretations of available information prove to be incorrect, actual results could vary materially from our expected results.

Benefits from System Expansions. Results of operations for the year ending December 31, 2015 and thereafter will benefit from increased revenues associated with the expansion projects identified under “—Factors and Trends That Impact Our Business—Growth Associated with Expansions” above. These projects have provided our customers with increased access to new sources of supply while extending their market reach. We are also continuing to pursue expansion across our footprint that will allow for the transport of constrained natural gas production in the Marcellus and Utica producing regions to areas of demand and/or to locations for conversion to LNGs for exportation off the continent. We expect that completion of these projects will increase utilization along our pipeline system.

Growth Opportunities. We expect the revenues generated from our businesses will increase as we execute on our significant portfolio of organic growth opportunities, which include the growth projects listed herein.

Growing Export Market. Domestic dry natural gas production in the U.S. is expected to outpace domestic consumption. According to the EIA, domestic dry natural gas production is estimated to grow approximately 1.61% per year, from 25.57 trillion Btu in 2014 to 33.01 trillion Btu in 2030, while growth in U.S. natural gas demand is only estimated to grow by approximately 0.2% per year, from 27.12 trillion Btu in 2014 to 28.08 trillion Btu in 2030. The net difference between supply and demand is expected, largely, to be exported out of the country through pipeline to Mexico or off the continent by conversion to LNG. The EIA forecasts that the U.S. will transition from a net importer of gas in 2014 of 1.14 trillion cubic feet ("Tcf") to a net exporter of gas in 2030 of 4.81 Tcf of which net exports of LNG will be 3.29 Tcf. We believe our assets provide a unique footprint from the Marcellus and Utica regions to the Gulf of Mexico where the majority of the liquefaction facilities for LNG export have been announced, putting us in position to capitalize on the LNG export market.

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CPG OpCo LP

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)	2015			2014			2013
				Predecessor			Predecessor
Operating Revenues
Transportation revenues	$	1,052.2		$	990.9		$	850.9
Transportation revenues-affiliated	47.1			95.8			94.3
Storage revenues	171.4			144.0			142.8
Storage revenues-affiliated	26.2			53.2			53.6
Other revenues	34.9			63.0			37.8
Total Operating Revenues	1,331.8			1,346.9			1,179.4
Operating Expenses
Operation and maintenance	524.7			630.7			507.1
Operating and maintenance-affiliated	163.8			122.9			118.1
Depreciation and amortization	135.0			118.6			106.9
Gain on sale of assets and impairment, net	(54.7		)	(34.5		)	(18.6		)
Property and other taxes	71.2			67.1			62.2
Total Operating Expenses	840.0			904.8			775.7
Equity Earnings in Unconsolidated Affiliates	60.2			46.6			35.9
Operating Income	552.0			488.7			439.6
Other Income (Deductions)
Interest expense	(0.1		)	—			—
Interest expense-affiliated	(26.8		)	(62.0		)	(37.9		)
Other, net	32.0			8.8			17.6
Total Other Income (Deductions), net	5.1			(53.2		)	(20.3		)
Income before Income Taxes	557.1			435.5			419.3
Income Taxes	23.9			166.4			152.4
Net Income	533.2			$	269.1		$	266.9
Less: Predecessor net income prior to CPPL IPO on February 11, 2015	42.7
Net income attributable to the Partnership	490.5
Throughput (MMDth)
Columbia Gas Transmission	1,460.1			1,379.4			1,354.3
Columbia Gulf	562.7			626.7			643.0
Total	2,022.8			2,006.1			1,997.3

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 due primarily 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 Capital Cost Recovery Mechanism ("CCRM"), the West Side Expansion growth project and other new contracts. Additionally, there were higher shorter term transportation services of $3.5 million.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

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 variances 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 Allowance for Funds Used During Construction ("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 was primarily due 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 MMDth was primarily due to increased transportation of Marcellus and Utica natural gas production.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Operating Revenues. Operating revenues were $1,346.9 million for 2014, an increase of $167.5 million from the same period in 2013. The increase in operating revenues was due primarily to increased revenue of $88.4 million attributable to recovery of operating costs under our regulatory tracker mechanisms, which are offset in operating expenses, increased revenue of $54.7 million primarily from the West Side Expansion, Warren County and Big Pine projects and other new contracts. Additionally there was increased mineral rights royalty revenue of $22.6 million primarily attributable to increased third-party drilling activity.

Operating Expenses. Operating expenses were $904.8 million for 2014, an increase of $129.1 million from the same period in 2013. The increase in operating expenses was primarily due to $88.4 million of increased operating costs under certain regulatory tracker mechanisms, which are offset in operating revenues, increased employee and administrative expenses of $28.3 million due to higher employee costs, increased outside service costs of $13.3 million, higher depreciation and amortization of $11.7 million primarily due to increased capital expenditures related to projects placed in service, and higher property taxes of $4.0 million. These increases were partially offset by higher gains on the sale of assets of $15.9 million resulting from higher gains on the conveyances of mineral interests of $27.2 million, offset by the sale of storage base gas in 2013 of $11.1 million. Operating expenses were further offset by lower software data conversion costs of $8.9 million.

Equity Earnings in Unconsolidated Affiliates. Equity Earnings in Unconsolidated Affiliates were $46.6 million in 2014, an increase of $10.7 million compared to the same period in 2013. Equity earnings increased primarily due to new compression assets being placed into service at Millennium Pipeline.

Other Income (Deductions). Other Income (Deductions) in 2014 reduced income by $53.2 million compared to a reduction in income of $20.3 million in 2013. The increase in deductions was primarily due to a $24.1 million increase in interest expense resulting from $768.9 million of additional borrowings on the intercompany long-term note that originated on December 9, 2013, and a $10.5 million gain from insurance proceeds in 2013. These increases were partially offset by a $4.2 million increase in the equity portion of AFUDC.

Income Taxes. The effective income tax rates were 38.2% and 36.3% in 2014 and 2013, respectively. The change in the overall effective tax rates between 2014 and 2013 were due primarily to higher AFUDC Equity and consolidated state income taxes.

Throughput. Throughput for the Predecessor totaled 2,006.1 MMDth for 2014, compared to 1,997.3 MMDth for the same period in 2013. The increase of 8.8 million is primarily due to colder weather experienced during early 2014 throughout much of the Partnership's system.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Liquidity and Capital Resources

Our principal liquidity requirements are to finance our operations and fund capital expenditures. Our ability to meet these liquidity requirements will depend on our ability to generate cash in the future. Prior to CPPL's IPO, our sources of liquidity included cash generated from operations and intercompany loans from NiSource Finance Corp. ("NiSource Finance"), a wholly owned subsidiary of NiSource. We also participated in NiSource’s money pool administered by NiSource Corporate Services Company ("NiSource Corporate Services"), whereby on a daily basis cash balances residing in our bank accounts were swept into a NiSource corporate account. Therefore, our historical financial statements reflect little or no cash balances.

In connection with CPPL's IPO, we established separate bank accounts, but CEG or its affiliates continue to provide treasury services on our general partner’s behalf under our omnibus agreement. Unlike our transactions with third parties, which ultimately settle in cash, our affiliate transactions are settled on a net basis through an intercompany receivable/payable with affiliates. In connection with CPPL's IPO, CEG assumed the liability for $1,217.3 million of intercompany debt owed to NiSource Finance by certain subsidiaries in the Columbia Pipeline Group Operations segment, and NiSource Finance novated the $1,217.3 million of intercompany debt from the subsidiaries to CEG.

Subsequent to CPPL's IPO, our sources of liquidity include:


•	cash generated from our operations;


•	issuances of additional ownership interests;


•	$750.0 million of reserved borrowing capacity under an intercompany money pool with CPG, in which us and our subsidiaries are participants; and


•	long-term intercompany borrowings.

We believe that cash on hand, cash generated from operations and the issuance of additional ownership interests will be adequate to meet our operating needs.

Cash Flow. Net cash from operating activities, net cash used for investing activities and net cash from financing activities for the years ended December 31, 2015, 2014 and 2013, were as follows:



(in millions)	2015			2014			2013
				Predecessor			Predecessor
Net cash from operating activities	$	629.8		$	568.1		454.0
Net cash used for investing activities	(1,052.4		)	(864.5		)	(797.4	)
Net cash from financing activities	500.3			296.6			343.1

Operating Activities

Net cash from operating activities for the year ended December 31, 2015 was $629.8 million, an increase of $61.7 million from December 31, 2014. The increase in net cash from operating activities was primarily due to a decrease in income tax amounts subsequent to CPPL's IPO as we are not subject to income tax at the partnership level, offset by a customer deposit related to growth projects received in the prior year and higher distribution of earnings from equity investees and other changes in working capital.

Net cash from operating activities for the year ended December 31, 2014 was $568.1 million, an increase of $114.1 million from December 31, 2014. The increase in net cash from operating activities was primarily due to an increase in customer deposits related to growth projects of $75.6 million partially offset by a decrease in working capital from income tax receivables of $27.4 million primarily due to a refund from the IRS received in 2013.

Pension and Other Postretirement Plan Funding. We expect to make contributions of approximately $0.1 million to our pension plans and approximately $0.9 million to our postretirement medical and life plans in 2016. For the year ended December 31, 2015, we contributed $16.5 million to our pension plans and $11.3 million to our other postretirement medical and life plans.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Investing Activities

The table below reflects actual maintenance and expansion capital expenditures and other investing activities for years ended December 31, 2015, 2014 and 2013 and estimates for 2016.



(in millions)	2016E		2015		2014		2013
					Predecessor		Predecessor
Expansion - modernization, system growth and equity investments	$	1,446.1	$	1,073.4	$	700.5	$	664.8
Maintenance and other	139.3		132.7		143.4		132.7
Separation	—		3.5		—		—
Total⁽¹⁾	$	1,585.4	$	1,209.6	$	843.9	$	797.5

⁽¹⁾The difference between total capital expenditures in this table and the capital expenditures line item on our statement of cash flows primarily consists of (i) contributions to equity investees, (ii) the non-cash change in capital expenditures included in current liabilities, (iii) the non-cash change in working interest payable and (iv) non-cash AFUDC equity.

Capital expenditures for the year ended December 31, 2015 were $1,209.6 million, compared to $843.9 million for the comparable period in 2014. This increased spending is mainly due to higher spending on various growth projects primarily in the Marcellus and Utica Shale areas and for expenditures under the modernization program. Capital expenditures in 2014 were $46.4 million higher compared to 2013 due to system growth in the Marcellus and Utica shale areas. We project 2016 capital expenditures to be approximately $1.6 billion.

Contributions to equity investees were $1.4 million for the year ended December 31, 2015, a decrease of $67.8 million from a year ago. The contributions in 2015 were made to Millennium Pipeline. During the year ended December 31, 2014, the Predecessor contributed $66.6 million and $2.6 million to Pennant and Millennium Pipeline, respectively. Contributions to equity investees in 2014 were $56.3 million lower compared to 2013. During the year ended December 31, 2013, the Predecessor contributed $108.9 million and $16.6 million to Pennant and Millennium Pipeline, respectively. Distributions received from equity investees increased $16.0 million during the year ended December 31, 2015, primarily due to an additional member joining the Pennant joint venture.

Proceeds from disposition of assets increased $74.8 million during the year ended December 31, 2015, primarily due to increased proceeds received on conveyances of mineral rights positions and proceeds received from asset transfers related to the Separation.

Financing Activities

Net cash from financing activities for the year ended December 31, 2015 was $500.3 million, an increase of $203.7 million compared to the year ended December 31, 2014. The increase in net cash from financing activities was primarily due to CPPL's purchase of initial ownership of $1,170.0 million offset by the distribution of $722.2 million to the limited partners, including a $500.0 million return of preformation capital expenditures. Refer to Note 1, “Nature of Operations and Summary of Significant Accounting Policies” in the Notes to Consolidated and Combined Financial Statements for more information.

Net cash from financing activities for the year ended December 31, 2014 was $296.6 million, a decrease of $46.5 million compared to the year ended December 31, 2013. The decrease in net cash from financing activities was due to a decrease in short-term borrowings from the money pool to fund capital expenditures. These decreases were partially offset by a decrease in dividends to parent and additional borrowings on the intercompany long-term note that originated on December 9, 2013.

Intercompany Credit Agreement Amendment. On January 31, 2016, we amended our 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 outstanding borrowings bear interest at a fixed rate of 4.70%.

Money Pool Agreement and CPG Credit Agreement. In connection with the closing of CPPL's IPO, we and our subsidiaries entered into an intercompany money pool agreement, initially with NiSource Finance, with $750.0 million of reserved borrowing capacity. Following the Separation, the agreement is now with CPG. The money pool is available for our general partnership purposes, including capital expenditures and working capital.

In furtherance of the money pool arrangement, CPG has entered into a $1,500.0 million senior revolving credit facility of which $750.0 million will be utilized as credit support for us and our subsidiaries in connection with the money pool arrangement. The remaining $750.0 million will be available for CPG's general corporate purposes, including working capital. The revolving credit

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

facility will provide liquidity support for CPG's $1,000.0 million commercial paper program. The revolving credit facility became effective as of the Separation with a termination date of July 2, 2020.

Obligations under the CPG revolving credit facility are unsecured. We, together with CEG and CPG OpCo GP LLC ("OpCo GP"), are guarantors of CPG’s revolving credit facility. The loans thereunder shall bear interest at CPG’s option at either (i) the greatest of (a) the federal funds effective rate plus 0.500 percent, (b) the reference prime rate of JPMorgan Chase Bank, N.A., or (c) the Eurodollar rate which is based on the LIBOR, plus 1.000 percent, each of which is subject to a margin that varies from 0.000 percent to 0.650 percent per annum, according to the credit rating of CPG, or (ii) the Eurodollar rate plus a margin that varies from 1.000 percent to 1.650 percent per annum, according to the credit rating of CPG. CPG’s revolving credit facility is subject to a facility fee that varies from 0.125 percent to 0.350 percent per annum, according to the credit rating of CPG.

CPG’s revolving credit facility was executed on December 5, 2014, but did not become effective until the completion of the Separation. Additionally, as a guarantor and restricted subsidiary, we are subject to various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance with their respective organizational documents unless there has been an event of default (as defined in CPG's revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. If we fail to perform its obligations under these and other covenants, it could adversely affect our ability to finance future business opportunities. CPG’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million.

CPG’s revolving credit facility also contains certain financial covenants that will require CPG to maintain a consolidated total leverage ratio that does not exceed (i) 5.75 to 1.00 for the period of four consecutive fiscal quarters (“test period”) ending December 31, 2015, (ii) 5.50 to 1.00 for any test period ending after December 31, 2015 and on or before December 31, 2017, and (iii) 5.00 to 1.00 for any test period ending after December 31, 2017, provided that after December 31, 2017 and during a Specified Acquisition Period (as defined in CPG’s revolving credit facility), the leverage ratio shall not exceed 5.50 to 1.00.

A breach of any of these covenants could result in a default in respect of the related debt. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against us as a guarantor.

As of December 31, 2015, CPG was in compliance with these covenants. As of December 31, 2015, CPG had no borrowings outstanding and had $18.1 million in letters of credit under the revolving credit facility.

CPG Commercial Paper Program. On October 5, 2015, CPG established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended. Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. We, together with CEG and OpCo GP, have 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. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

Contractual Obligations. We have certain contractual obligations requiring payments at specified periods. The obligations include long-term debt-affiliated, operating lease obligations and service obligations for pipeline service agreements. The total contractual obligations in existence at December 31, 2015 and their maturities were:



(in millions)	Total		2016		2017		2018		2019		2020		After
Long-term debt-affiliated	630.9		—		—		—		—		630.9		—
Interest payments on long-term debt-affiliated	148.6		29.8		29.7		29.7		29.7		29.7		—
Pipeline transportation capacity arrangements	259.4		51.5		49.5		42.0		25.4		24.2		66.8
Operating leases⁽¹⁾	46.6		4.5		5.9		5.5		4.8		4.7		21.2
Total contractual obligations	$	1,085.5	$	85.8	$	85.1	$	77.2	$	59.9	$	689.5	$	88.0

⁽¹⁾ Operating lease expense was $18.5 million in 2015, $14.9 million in 2014 and $13.4 million in 2013, which 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.

We have third-party transportation agreements that provide for transportation and storage services. These agreements, which have expiration dates ranging from 2016 to 2025, require us to pay fixed monthly charges and allow us to use third-party transportation as operationally needed. Most of these costs are eligible to be collected through a FERC-approved regulatory tracker from our shippers.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements.

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CPG OpCo LP

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 and Combined Balance Sheets.

Basis of Accounting for Rate-Regulated Subsidiaries. Accounting Standards Codification ("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 and Combined 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 and Combined Balance Sheets were $139.1 million and $310.9 million at December 31, 2015, and $158.0 million and $295.6 million at December 31, 2014, 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, 2015. Regulatory assets of $7.2 million are covered by specific regulatory orders and are being recovered as components of cost of service over a remaining life up to 7 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 Financial Accounting Standards Board ("FASB"). Columbia Gas Transmission Operations is a component and has been determined to be a reporting unit. Our goodwill assets at December 31, 2015 and 2014 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 2014 and 2015, 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 this assessment indicated that it is not more likely than not that its 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, 2015, 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 the market capitalization of our parent stays below book value for an extended period of time. We reviewed the market capitalization method

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CPG OpCo LP

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (continued)

due to the recent decline in CPPL's unit price. Following this review, we determined there were no impairment triggers identified subsequent to May 1, 2015.

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 $26.5 million, $43.8 million and $21.2 million for the years ended December 31, 2015, 2014 and 2013, 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 $52.3 million, $34.5 million and $7.3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in “Gain on sale of assets and impairment, net” 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.

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CPG OpCo LP

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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: commodity market risk, interest rate risk and credit 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 are exposed 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. As of December 31, 2015 and 2014, the outstanding balance on this term loan was $630.9 million and $834.0 million, respectively. 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 and $8.3 million for the years ended December 31, 2015 and 2014, respectively.

Credit Risk. Due to the nature of the industry, credit risk is embedded in our business activities. Our extension of credit is governed by CPG’s Corporate Credit Risk Policy. In addition, CPG’s Risk Management Committee guidelines are in place which document management approval levels for credit limits, evaluation of creditworthiness, and credit risk mitigation efforts. Exposures to credit risks are monitored by CPG’s Corporate Credit Risk function which is independent of operations. Credit risk arises due to the possibility that a customer, supplier or counterparty will not be able or willing to fulfill its obligations on a transaction on or before the settlement date. Exposure to credit risk is measured in terms of current obligations net of any posted collateral such as cash, letters of credit and qualified guarantees of support.

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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 and combined balance sheets of CPG OpCo LP and subsidiaries (the “Partnership”) as of December 31, 2015 and 2014, and the related statements of consolidated and combined operations, comprehensive income, cash flows, and equity and partners’ capital for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the 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 audits 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 22, 2016

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG OpCo LP

CONSOLIDATED AND COMBINED BALANCE SHEETS



(in millions)	December 31, 2015			December 31, 2014
				Predecessor
ASSETS
Current Assets
Cash and cash equivalents	$	78.2		$	0.5
Accounts receivable (less reserve of $0.3 and $0.3, respectively)	145.9			149.3
Accounts receivable-affiliated	149.4			153.8
Materials and supplies, at average cost	32.8			24.9
Exchange gas receivable	18.8			34.8
Deferred property taxes	52.0			48.9
Deferred income taxes	—			24.6
Prepayments and other	33.8			20.9
Total Current Assets	510.9			457.7
Investments
Unconsolidated affiliates	437.1			444.3
Other investments	1.8			6.2
Total Investments	438.9			450.5
Property, Plant and Equipment
Property, plant and equipment	8,930.9			7,931.6
Accumulated depreciation and amortization	(2,960.1		)	(2,971.4		)
Net Property, Plant and Equipment	5,970.8			4,960.2
Other Noncurrent Assets
Regulatory assets	134.1			151.9
Goodwill	1,975.5			1,975.5
Postretirement and postemployment benefits assets	120.5			102.7
Deferred charges and other	9.0			9.0
Total Other Noncurrent Assets	2,239.1			2,239.1
Total Assets	$	9,159.7		$	8,107.5

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG OpCo LP

CONSOLIDATED AND COMBINED BALANCE SHEETS



(in millions, except unit amounts)	December 31, 2015			December 31, 2014
				Predecessor
LIABILITIES AND EQUITY
Current Liabilities
Current portion of long-term debt-affiliated	$	—		$	115.9
Short-term borrowings-affiliated	42.1			247.3
Accounts payable	49.9			56.1
Accounts payable-affiliated	85.9			49.9
Customer deposits	17.8			13.4
Taxes accrued	108.2			106.9
Exchange gas payable	18.2			34.7
Deferred revenue	15.0			22.2
Accrued capital expenditures	95.9			61.1
Accrued compensation and related costs	26.6			31.2
Other accruals	43.9			39.0
Total Current Liabilities	503.5			777.7
Noncurrent Liabilities
Long-term debt-affiliated	630.9			1,472.8
Deferred income taxes	1.0			1,239.0
Accrued liability for postretirement and postemployment benefits	36.1			44.7
Regulatory liabilities	309.7			294.3
Asset retirement obligations	25.3			23.2
Other noncurrent liabilities	63.5			84.5
Total Noncurrent Liabilities	1,066.5			3,158.5
Total Liabilities	1,570.0			3,936.2
Commitments and Contingencies (Refer to Note 13)
Equity
Net parent investment	—			4,188.0
Limited Partner Interest - Columbia Energy Group	6,300.1			—
Limited Partner Interest - Columbia Hardy Corporation	39.7			—
Limited Partner Interest - Columbia Pipeline Partners LP	1,275.6			—
Accumulated other comprehensive loss	(25.7		)	(16.7		)
Total Equity	7,589.7			4,171.3
Total Liabilities and Equity	$	9,159.7		$	8,107.5

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG OpCo LP

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS



Year Ended December 31, (in millions, except per unit amounts)	2015			2014			2013
				Predecessor			Predecessor
Operating Revenues
Transportation revenues	$	1,052.2		$	990.9		$	850.9
Transportation revenues-affiliated	47.1			95.8			94.3
Storage revenues	171.4			144.0			142.8
Storage revenues-affiliated	26.2			53.2			53.6
Other revenues	34.9			63.0			37.8
Total Operating Revenues	1,331.8			1,346.9			1,179.4
Operating Expenses
Operation and maintenance	524.7			630.7			507.1
Operating and maintenance-affiliated	163.8			122.9			118.1
Depreciation and amortization	135.0			118.6			106.9
Gain on sale of assets and impairment, net	(54.7		)	(34.5		)	(18.6		)
Property and other taxes	71.2			67.1			62.2
Total Operating Expenses	840.0			904.8			775.7
Equity Earnings in Unconsolidated Affiliates	60.2			46.6			35.9
Operating Income	552.0			488.7			439.6
Other Income (Deductions)
Interest expense	(0.1		)	—			—
Interest expense-affiliated	(26.8		)	(62.0		)	(37.9		)
Other, net	32.0			8.8			17.6
Total Other Income (Deductions), net	5.1			(53.2		)	(20.3		)
Income before Income Taxes	557.1			435.5			419.3
Income Taxes	23.9			166.4			152.4
Net Income	533.2			$	269.1		$	266.9
Less: Predecessor net income prior to CPPL IPO on February 11, 2015	42.7
Net income attributable to the Partnership	$	490.5

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

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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)	2015			2014		2013
				Predecessor		Predecessor
Net Income	$	533.2		$	269.1	$	266.9
Other comprehensive income
Net unrealized gain on cash flow hedges⁽¹⁾	1.5			1.0		1.1
Unrecognized pension and OPEB costs⁽²⁾	(0.2		)	—		—
Total other comprehensive income	1.3			1.0		1.1
Total comprehensive income	534.5			$	270.1	$	268.0
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	$	491.7

⁽¹⁾Net unrealized gain on derivatives qualifying as cash flow hedges, net of $0.1 million, $0.7 million and $0.6 million tax expense in 2015, 2014 and 2013, respectively.

⁽²⁾Unrecognized pension and OPEB costs, net of zero tax expense in 2015, 2014 and 2013, respectively.

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

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FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

CPG OpCo LP

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS



Year Ended December 31, (in millions)	2015			2014			2013
				Predecessor			Predecessor
Operating Activities
Net Income	$	533.2		$	269.1		$	266.9
Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
Depreciation and amortization	135.0			118.6			106.9
Deferred income taxes and investment tax credits	10.5			139.3			179.9
Deferred revenue	4.2			1.6			(0.5		)
Equity-based compensation expense and profit sharing contribution	5.4			6.3			2.2
Gain on sale of assets and impairment, net	(54.7		)	(34.5		)	(18.6		)
Equity earnings in unconsolidated affiliates	(60.2		)	(46.6		)	(35.9		)
AFUDC equity	(28.3		)	(11.0		)	(6.8		)
Distributions of earnings received from equity investees	57.2			37.8			32.1
Changes in Assets and Liabilities:
Accounts receivable	(11.0		)	(20.3		)	2.5
Accounts receivable-affiliated	21.6			2.2			(7.6		)
Accounts payable	(10.0		)	2.8			5.5
Accounts payable-affiliated	29.8			8.6			16.3
Customer deposits	(22.9		)	77.5			1.3
Taxes accrued	19.5			11.8			(28.5		)
Exchange gas receivable/payable	—			1.1			(0.5		)
Other accruals	10.4			0.6			0.4
Prepayments and other current assets	(13.5		)	(4.4		)	21.7
Regulatory assets/liabilities	27.6			9.0			42.6
Postretirement and postemployment benefits	(5.2		)	2.2			(113.3		)
Deferred charges and other noncurrent assets	(13.8		)	(4.3		)	2.5
Other noncurrent liabilities	(5.0		)	0.7			(15.1		)
Net Cash Flows from Operating Activities	629.8			568.1			454.0
Investing Activities
Capital expenditures	(1,106.6		)	(747.2		)	(674.8		)
Insurance recoveries	2.1			11.3			6.4
Changes in short-term lendings-affiliated	(24.3		)	(61.6		)	(10.0		)
Proceeds from disposition of assets	84.1			9.3			15.4
Contributions to equity investees	(1.4		)	(69.2		)	(125.5		)
Distributions from equity investees	16.0			—			—
Other investing activities	(22.3		)	(7.1		)	(8.9		)
Net Cash Flows used for Investing Activities	(1,052.4		)	(864.5		)	(797.4		)
Financing Activities
Change in short-term borrowings-affiliated	(205.2		)	(472.3		)	391.0
Issuance of long-term debt-affiliated	—			768.9			65.1
Payments of long-term debt-affiliated, including current portion	(959.6		)	—			—
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		)	—			—
Distribution to parent	—			—			(113.0		)
Quarterly distributions to limited partners	(222.2		)	—			—
Net Cash Flows from Financing Activities	500.3			296.6			343.1
Change in cash and cash equivalents	77.7			0.2			(0.3		)
Cash and cash equivalents at beginning of period	0.5			0.3			0.6
Cash and Cash Equivalents at End of Period	$	78.2		$	0.5		$	0.3

The accompanying Notes to Consolidated and Combined Financial Statements are an integral part of these statements.

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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, 2013	$	3,758.3		$	—		$	—		$	—		$	(18.8	)	$	3,739.5
Net Income	266.9			—			—			—			—			266.9
Other comprehensive income, net of tax	—			—			—			—			1.1			1.1
Dividends to parent	(113.0		)	—			—			—			—			(113.0		)
Net transfers from parent	5.4			—			—			—			—			5.4
Balance as of December 31, 2013	$	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

⁽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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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 Inc. ("NiSource"). The general partner of the Partnership, CPG OpCo GP LLC ("OpCo GP"), is 100% owned by its sole member Columbia Pipeline Partners LP ("CPPL"). On February 11, 2015 CPPL completed its offering of common units to the public ("CPPL's IPO"). At or prior to the closing of CPPL's IPO the following transactions occurred:


•	Columbia Energy Group ("CEG") contributed $1,217.3 million of capital to certain subsidiaries of the Predecessor to repay intercompany debt owed to NiSource Finance Corp. ("NiSource Finance"). CEG entered into new intercompany debt agreements with NiSource Finance for $1,217.3 million;


•	CEG and Columbia Hardy Corporation ("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 Columbia Pipeline Group, Inc. ("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. 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 Columbia Pipeline Group Services Company ("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 that include 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.

For periods subsequent to the closing of CPPL's IPO, the financial statements included in this current report are the financial statements and accounting records of the Partnership. For periods prior to the closing of CPPL's IPO, the financial statements

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

included in this current report are the financial statements and accounting records of the Predecessor. The consolidated and combined financial statements were prepared as follows:


•	The Consolidated and Combined Balance Sheets consist of the consolidated balance sheet of the Partnership as of December 31, 2015 and the combined balance sheet of the Predecessor as of December 31, 2014.


•	The Statements of Consolidated and Combined Operations consist of the consolidated results of the Partnership 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 years ended December 31, 2014 and 2013.


•	The Statements of Consolidated and Combined Comprehensive Income consist of the consolidated results of the Partnership 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 years ended December 31, 2014 and 2013.


•	The Statements of Consolidated and Combined Cash Flows consist of the consolidated cash flows of the Partnership 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 years ended December 31, 2014 and 2013.


•	The Statements of Consolidated and Combined Equity consist of the consolidated activity of the Partnership 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 years ended December 31, 2014 and 2013.

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, LLC ("Columbia Gas Transmission"), Columbia Gulf Transmission, LLC ("Columbia Gulf"), Columbia Midstream Group, LLC ("Columbia Midstream"), Columbia Energy Ventures, LLC ("CEVCO"), CNS Microwave, LLC ("CNS Microwave"), and the Partnership. Also included in the Consolidated and Combined Financial Statements are equity method investments Hardy Storage Company, LLC ("Hardy Storage"), Millennium Pipeline Company, L.L.C ("Millennium Pipeline"), and Pennant Midstream, LLC ("Pennant"). All intercompany transactions and balances have been eliminated.

Subsequent events have been evaluated through February 22, 2016, the date these financial statements were available to be issued. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the financial statements.

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 and Combined 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

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 ADUFC equity are summarized in the table below:



	2015				2014				2013
	Debt		Equity		Debt		Equity		Debt		Equity
					Predecessor				Predecessor
Columbia Gas Transmission	1.8	%	6.3	%	0.9	%	3.0	%	2.5	%	3.2	%
Columbia Gulf	2.9	%	6.3	%	2.1	%	9.4	%	2.5	%	3.2	%

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, 2015, 2014 and 2013. Please see Note 4, "Gain on Sale of Assets," in the Notes to Consolidated and Combined Financial Statements for information regarding the sale of storage base gas in 2013. Gas stored-base gas is included in Property, plant and equipment on the Consolidated and Combined Balance Sheets.

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 $5.8 million in 2015, $4.3 million in 2014 and $5.0 million in 2013 related to software costs. The Partnership’s unamortized software balance was $27.1 million and $18.3 million at December 31, 2015 and 2014, respectively.

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 $0.6 million for the year ended December 31, 2015 and zero for the years ended December 31, 2014 and 2013.

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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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.

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 $26.5 million, $43.8 million and $21.2 million for the years ended December 31, 2015, 2014 and 2013, 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 $52.3 million, $34.5 million and $7.3 million for the years ended December 31, 2015, 2014 and 2013, respectively, and are included in "Gain on sale of assets and impairment, net" 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 and Combined Balance Sheets, as appropriate.

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 and Combined 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 and Combined 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% interest in Hardy Storage. The Predecessor had a 50% interest in Hardy Storage. The Partnership and the Predecessor reflect the investment in Hardy Storage as an equity method investment.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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%. 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 (at least quarterly) 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.

The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2015 and 2014:



(in millions)	2015			2014
Beginning Balance	$	14.9		$	1.9
Additions pending the determination of proved reserves	1.3			20.1
Reclassifications of proved properties	(14.5		)	(7.1		)
Ending Balance	$	1.7		$	14.9

As of December 31, 2015, 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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


2.	Recent Accounting Pronouncements

In April 2015, the FASB issued Accounting Standards Update ("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 is required to adopt ASU 2015-03 and ASU 2015-15 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively with early adoption permitted. The Partnership does not anticipate the adoption of ASU 2015-03 and ASU 2015-15 will have a material impact on the Consolidated and Combined Financial Statements or Notes to Consolidated and Combined Financial Statements.

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. The Partnership is currently evaluating the impact the adoption of ASU 2014-09 and ASU 2015-14 will have 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 is required to adopt ASU 2015-02 for periods beginning after December 15, 2015, including interim periods, and the guidance is to be applied retrospectively or using a modified retrospective approach, with early adoption permitted. The Partnership is currently evaluating the impact the adoption of ASU 2015-02 will have on the Consolidated and Combined Financial Statements and Notes to Consolidated and Combined Financial Statements but does not anticipate that the impact will be material.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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)	2015		2014		2013
			Predecessor		Predecessor
Transportation revenues	$	47.1	$	95.8	$	94.3
Storage revenues	26.2		53.2		53.6
Other revenues	0.2		0.3		0.3
Operation and maintenance expense	163.8		122.9		118.1
Interest expense	26.8		62.0		37.9
Interest income	4.8		0.5		0.5

Balance Sheet



(in millions)	December 31, 2015		December 31, 2014
			Predecessor
Accounts receivable	$	149.4	$	153.8
Current portion of long-term debt	—		115.9
Short-term borrowings	42.1		247.3
Accounts payable	85.9		49.9
Long-term debt	630.9		1,472.8

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 Columbia Pipeline Group Services Company ("CPGSC"). Prior to CPPL's IPO, the Predecessor received similar services from NiSource Corporate Services Company ("NiSource Corporate Services"). Expenses incurred as a result of these services consist 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.

Interest Expense and Income. The Partnership and Predecessor were charged interest for long-term debt of $35.1 million, $61.6 million and $40.6 million for the years ended December 31, 2015, 2014 and 2013, respectively, offset by associated AFUDC of $9.2 million, $2.7 million and $6.8 million for the years ended December 31, 2015, 2014 and 2013, respectively.

The Partnership and its subsidiaries entered into an intercompany money pool agreement with NiSource Finance Corp. ("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

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

by subsidiaries of the Partnership were swept into a CPG corporate account on a daily basis, creating an affiliated receivable or decreasing an affiliated 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, 2015 and 2014 was 1.21% and 0.70%, respectively. The interest expense for short-term borrowings charged for the years ended December 31, 2015, 2014 and 2013 was $0.9 million, $3.1 million and $4.1 million, respectively.

Accounts Receivable. The Partnership includes in accounts receivable amounts due from the money pool discussed above of $140.5 million at December 31, 2015 for subsidiaries of the Partnership in a net deposit position. The Predecessor includes in accounts receivable amounts due from the money pool discussed above of $125.0 million at December 31, 2014 for subsidiaries in a net deposit position. Also included in the balance at December 31, 2015 and December 31, 2014 are amounts due from subsidiaries of CPG, subsequent to the Separation, or NiSource, prior to the Separation, of $8.9 million and $28.8 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 is now with CPG. In furtherance of the money pool agreement, CPG entered into a $1,500.0 million revolving credit agreement on December 5, 2014. The CPG revolving credit agreement became effective at the completion of the Separation with a termination date of July 2, 2020. Each of CEG, OpCo GP and the Partnership is a guarantor of CPG's revolving credit facility. As a guarantor and restricted subsidiary, the Partnership is subject to various customary covenants and restrictive provisions which, among other things, limit CPG’s and its restricted subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of their assets; make certain investments or restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness; each of which is subject to customary and usual exceptions and baskets, including an exception to the limitation on restricted payments for distributions of available cash, as permitted by their organizational documents. The restricted payment provision does not prohibit CPG or any of its restricted subsidiaries from making distributions in accordance to their respective organizational documents unless there has been an event of default (as defined in the revolving credit agreement), and neither CPG nor any of its restricted subsidiaries has any restrictions on its ability to make distributions under its organizational documents. Under the Partnership's partnership agreement, it is required to distribute all of its available cash each quarter, less the amounts of cash reserves that OpCo GP determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of the Partnership's business. In addition, subject to Delaware law, the board of directors of CPG may similarly determine whether to declare dividends at CPG without restriction under its revolving credit agreement. At December 31, 2015, neither CPG nor its subsidiaries had any restricted assets. If the Partnership and the other loan parties fail to perform their obligations under these and other covenants, it could adversely affect the Partnership’s ability to finance future business opportunities and make cash distributions to its limited partners. CPG’s revolving credit facility also contains customary events of default, including cross default provisions that apply to any other indebtedness CPG may have with an outstanding principal amount in excess of $50.0 million. If a default occurred, the relevant lenders could elect to declare the debt, together with accrued interest and other fees, to be immediately due and payable and proceed against the Partnership as a guarantor.

The balance of Short-term Borrowings at December 31, 2015 and December 31, 2014 of $42.1 million and $247.3 million, respectively, includes those subsidiaries of the Partnership and includes those subsidiaries of the Predecessor 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, subsequent to the Separation, and NiSource Corporate Services, prior to the Separation, and interest payable to CPG, subsequent to the Separation, and NiSource Finance, prior to the Separation.

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Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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. Details of the long-term debt balance are summarized in the table below:



Origination Date	Interest Rate		Maturity Date	December 31, 2015		December 31, 2014
(in millions)						Predecessor
November 28, 2005⁽¹⁾	5.41	%	November 30, 2015	$	—	$	115.9
November 28, 2005	5.45	%	November 28, 2016	—		45.3
November 28, 2005	5.92	%	November 28, 2025	—		133.5
November 28, 2012	4.63	%	November 28, 2032	—		45.0
November 28, 2012	4.94	%	November 30, 2037	—		95.0
December 19, 2012	5.16	%	December 21, 2037	—		55.0
November 28, 2012	5.26	%	November 28, 2042	—		170.0
December 19, 2012	5.49	%	December 18, 2042	—		95.0
December 9, 2013⁽²⁾	4.70	%	December 31, 2020	630.9		834.0
Total long-term debt, including current portion				$	630.9	$	1,588.7

⁽¹⁾ The debt balance for the note originating on November 28, 2005 and maturing on November 30, 2015 is included in "Current portion of long-term debt-affiliated" on the Combined Balance Sheet as of December 31, 2014.

⁽²⁾ 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, 2015.

Dividends. 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 and paid $113.0 million to CEG in the year ended December 31, 2013. 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, 2015, 2014 and 2013, gains on conveyances amounted to $52.3 million, $34.5 million and $7.3 million, respectively, and are included in "Gain on sale of assets and impairment, net" on the Statements of Consolidated and Combined Operations. Included in the gains on conveyances is a cash bonus payment of $35.8 million received by CEVCO from CNX Gas Company LLC during the year ended December 31, 2015, 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, 2015 and 2014, deferred gains of approximately $8.1 million and $19.6 million, respectively, were deferred pending performance of future obligations and recorded in "Deferred revenue" on the Consolidated and Combined Balance Sheets.

In 2013, Columbia Gas Transmission sold storage base gas. The difference between the sale proceeds and amounts capitalized to Property, plant and equipment resulted in a gain of $11.1 million.

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Notes to Consolidated and Combined Financial Statements

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)	2015			2014
				Predecessor
Property, plant and equipment
Pipeline and other transmission assets	$	6,120.0		$	5,328.2
Storage facilities	1,370.1			1,326.5
Gas stored base gas	299.5			299.5
Gathering and processing facilities	370.2			263.3
Construction work in process	463.5			454.2
General plant, software, and other assets	307.6			259.9
Property, plant and equipment	8,930.9			7,931.6
Accumulated Depreciation and Amortization	(2,960.1		)	(2,971.4		)
Net Property, plant and equipment	$	5,970.8		$	4,960.2

The table below lists the Partnership's applicable annual depreciation rates:



	Year Ended December 31,
	2015	2014	2013
		Predecessor	Predecessor
Depreciation rates
Pipeline and other transmission assets	1.00% - 1.73%	1.00% - 2.55%	1.50 % - 2.55%
Storage facilities	2.19% - 3.00%	2.19% - 3.30%	2.19% - 3.50%
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, 2015 and December 31, 2014 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 its 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.

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Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

Under the market approach, the Partnership utilized three market-based models to estimate the fair value of the reporting unit: (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, 2015. 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 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. The Partnership reviewed the market capitalization method due to the recent decline in CPPL's unit price. Following this review, the Partnership determined there were no indicators that would require goodwill impairment testing subsequent to May 1, 2015.


7.	Asset Retirement Obligations

Changes in the Partnership’s liability for asset retirement obligations for the years 2015 and 2014 are presented in the table below:



(in millions)	2015			2014
				Predecessor
Balance as of January 1,	$	23.2		$	26.3
Noncontributed net parent investment adjustments⁽¹⁾	(0.4		)	—
Accretion expense	1.2			1.5
Additions	4.1			2.2
Settlements	—			(6.6		)
Change in estimated cash flows	(2.8		)	(0.2		)
Balance as of December 31,	$	25.3		$	23.2

⁽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

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)	2015		2014
			Predecessor
Assets
Unrecognized pension benefit and other postretirement benefit costs	$	127.1	$	120.9
Other postretirement costs	8.9		10.8
Deferred taxes on AFUDC equity	—		21.8
Other	3.1		4.5
Total Regulatory Assets	$	139.1	$	158.0



At December 31, (in millions)	2015		2014
			Predecessor
Liabilities
Cost of removal	$	153.5	$	156.2
Regulatory effects of accounting for income taxes	—		10.9
Unrecognized pension benefit and other postretirement benefit costs	0.6		8.3
Other postretirement costs	155.6		117.3
Other	1.2		2.9
Total Regulatory Liabilities	$	310.9	$	295.6

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.

Deferred taxes on AFUDC equity - ASC 740 considers the equity component of AFUDC a temporary difference for which deferred income taxes must be provided. The Partnership is required to record the deferred tax liability for the equity component of AFUDC offset to this regulatory asset for wholly-owned subsidiaries and equity method investments. The regulatory asset is itself a temporary difference for which deferred incomes taxes are recognized. The regulatory asset was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level.

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

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Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

property. The regulatory liability was not contributed to the Partnership as the Partnership is not subject to income tax at the partnership level.

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 benefits as a regulatory liability in accordance with regulatory orders.

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.

Regulatory Matters

Columbia Gas Transmission Customer Settlement. On January 24, 2013, the FERC approved the Settlement. In March 2013, Columbia Gas Transmission paid $88.1 million in refunds to customers pursuant to the Settlement with its customers in conjunction with its comprehensive interstate natural gas pipeline modernization program. The refunds were made as part of the 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 Settlement with firm customers includes an initial five-year term with provisions for potential extensions thereafter.

The 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 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 28, 2016, Columbia Gas Transmission received FERC approval of its December 2015 filing to recover costs associated with the third year of its comprehensive system modernization program. Total program adjusted spend to date is $937.1 million. 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 settlement and has requested FERC’s approval of the customer agreement by March 31, 2016.

Columbia Gulf. On January 21, 2016, the FERC issued an Order (the "January 21 Order") initiating an investigation pursuant to Section 5 of the Natural Gas Act ("NGA") to determine whether Columbia Gulf ’s existing rates for jurisdictional services are unjust and unreasonable. Columbia Gulf intends to file a cost and revenue study with 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. The outcome of this proceeding to Columbia Gulf is not currently determinable.

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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


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. During the year ended December 31, 2015, the Partnership had billed approximately $13.1 million for services and other costs to Millennium Pipeline. Contributions are made to these equity investees to fund the Partnership's share of projects.

The following is a list of the Partnership's equity method investments at December 31, 2015:



Investee	Type of Investment	% of Voting Power or Interest Held
Hardy Storage Company, LLC	LLC Membership	49.0	%
Pennant Midstream, LLC	LLC Membership	47.5	%
Millennium Pipeline Company, L.L.C.	LLC Membership	47.5	%

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Notes to Consolidated and Combined Financial Statements

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)	2015		2014			2013
			Predecessor			Predecessor
Millennium Pipeline
Statement of Income Data:
Net Revenues	$	206.3	$	190.5		$	157.8
Operating Income	136.1		128.8			101.3
Net Income	98.0		89.6			63.0
Balance Sheet Data:
Current Assets	35.7		32.1			38.3
Noncurrent Assets	987.1		1,016.3			1,033.8
Current Liabilities	44.4		42.6			58.8
Noncurrent Liabilities	535.8		568.3			599.7
Total Members’ Equity	442.6		437.5			413.6
Contribution/Distribution Data:⁽¹⁾
Contributions to Millennium Pipeline	1.4		2.6			16.6
Distribution of earnings from Millennium Pipeline	47.5		35.6			29.0
Hardy Storage
Statement of Operations Data:
Net Revenues	$	23.4	$	23.6		$	24.4
Operating Income	15.3		16.1			16.5
Net Income	10.3		10.6			10.6
Balance Sheet Data:
Current Assets	12.1		12.0			12.5
Noncurrent Assets	155.5		157.4			160.2
Current Liabilities	19.3		17.1			18.3
Noncurrent Liabilities	68.5		77.4			85.7
Total Members’ Equity	79.8		74.9			68.7
Contribution/Distribution Data:⁽¹⁾
Contributions to Hardy Storage	—		—			—
Distribution of earnings from Hardy Storage	2.6		2.2			3.1
Pennant
Statement of Operations Data:
Net Revenues	$	34.6	$	8.5		$	2.0
Operating Income (Loss)	17.8		(2.4		)	1.3
Net Income (Loss)	17.8		(2.4		)	1.3
Balance Sheet Data:
Current Assets	11.0		23.7			34.1
Noncurrent Assets	389.6		380.0			231.9
Current Liabilities	8.4		8.6			11.4
Total Members’ Equity	392.2		395.1			254.6
Contribution/Distribution Data:⁽¹⁾
Contributions to Pennant	—		66.6			108.9
Distribution of earnings from Pennant	7.1		—			—
Return of capital from Pennant	16.0		—			—

⁽¹⁾Contribution and distribution data represents the Partnership's portion based on the Partnership's ownership percentage of each investment.

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Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)


10.	Income Taxes

The components of income tax expense were as follows:



Year Ended December 31, (in millions)	2015		2014			2013
			Predecessor			Predecessor
Income Taxes
Current
Federal	$	12.0	$	21.3		$	(16.1	)
State	1.2		5.8			(11.4		)
Total Current	13.2		27.1			(27.5		)
Deferred
Federal	8.8		117.7			155.9
State	1.9		21.7			24.1
Total Deferred	10.7		139.4			180.0
Deferred Investment Credits	—		(0.1		)	(0.1		)
Total Income Taxes	$	23.9	$	166.4		$	152.4

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)	2015					2014					2013
						Predecessor					Predecessor
Book income before income taxes	$	557.1				$	435.5				$	419.3
Tax expense at statutory federal income tax rate	193.9			35.0	%	152.4			35.0	%	146.8			35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal income tax benefit	2.0			0.4		17.9			4.1		8.2			1.9
Income not subject to income tax at the partnership level	(170.6		)	(30.9	)	—			—		—			—
AFUDC-Equity	(0.3		)	—		(3.8		)	(0.9	)	(2.4		)	(0.6	)
Other, net	(1.1		)	(0.2	)	(0.1		)	—		(0.2		)	—
Total Income Taxes	$	23.9		4.3	%	$	166.4		38.2	%	$	152.4		36.3	%

The effective income tax rates were 4.3%, 38.2%, and 36.3% in 2015, 2014 and 2013, respectively. The effective tax rate for 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 2014 and 2013 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, 2015. As of December 31, 2014 and 2013, the Predecessor financial statements included unrecognized tax benefits of zero and $0.1 million, respectively.

Deferred income taxes result from temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities.

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Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The principal components of the Partnership’s net deferred tax liability were as follows:



At December 31, (in millions)	2015		2014
			Predecessor
Deferred tax liabilities
Accelerated depreciation and other property differences	$	1.0	$	1,235.3
Pension and other postretirement/postemployment benefits	—		24.3
Other regulatory assets	—		62.8
Other, net	—		77.9
Total Deferred Tax Liabilities	1.0		1,400.3
Deferred tax assets
Deferred investment tax credits and other regulatory liabilities	—		(116.7		)
Net operating loss carryforward and AMT credit carryforward	—		(67.8		)
Other accrued liabilities	—		(1.4		)
Total Deferred Tax Assets	—		(185.9		)
Net Deferred Tax Liabilities less Deferred Tax Assets	1.0		1,214.4
Less: Deferred income taxes related to current assets and liabilities	—		(24.6		)
Non-Current Deferred Tax Liabilities	$	1.0	$	1,239.0


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 grantor 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 grantor 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. Other assets such as private equity funds may be used judiciously to enhance long-term returns while improving portfolio diversification. 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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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 2012, an asset allocation policy for the pension fund was approved. This policy calls for a gradual reduction in the allocation to return-seeking assets (equities, real estate, private equity and hedge funds) and a corresponding increase in the allocation to liability-hedging assets (fixed income) as the funded status of the plans increase above 90% (as measured by the projected benefit obligations of the qualified pension plans divided by the market value of qualified pension plan assets). 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, 2015 are as follows:

Asset Mix Policy of Funds:



	Defined Benefit Pension Plan		Postretirement Benefit Plan
Asset Category	Minimum	Maximum	Minimum	Maximum
Domestic Equities	25%	45%	35%	55%
International Equities	15%	25%	15%	25%
Fixed Income	23%	37%	20%	50%
Real Estate/Private Equity/Hedge Funds	0%	15%	0%	0%
Short-Term Investments	0%	10%	0%	10%

Pension Plan and Postretirement Plan Asset Mix at December 31, 2015 and December 31, 2014:



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	%

December 31, 2014	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	$	125.2	41.1	%	$	99.9	47.2	%
International Equities	55.0		18.1	%	38.9		18.4	%
Fixed Income	105.0		34.4	%	72.2		34.1	%
Real Estate/Private Equity/Hedge Funds	15.4		5.0	%	—		—	%
Cash/Other	4.2		1.4	%	0.6		0.3	%
Total	$	304.8	100.0	%	$	211.6	100.0	%

The categorization of investments into the asset classes in the table above are based on definitions established by the CPG Benefits Committee.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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, 2015 and 2014. 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 and $15.3 million as of December 31, 2015 and December 31, 2014, respectively. Such amounts were approximately zero and 3% of the CPG Pension Plan Trust and OPEB’s total investments as reported on the statement of net assets available for benefits at fair value as of December 31, 2015 and 2014, respectively.

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.

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.

Commingled funds that hold underlying investments that have prices which are derived from the quoted prices in active markets are classified as Level 2. 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.

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.

For the year ended December 31, 2015, there were no significant changes to valuation techniques to determine the fair value of CPG's pension and other postretirement benefits' assets.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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	25.5			—		25.5		—
U.S. equities	115.9			—		115.9		—
International equities	45.7			—		45.7		—
Fixed income	83.1			—		83.1		—
Pension plan assets subtotal	294.3			6.2		288.1		—
Other postretirement benefit plan assets
Commingled funds
Short-term money markets	6.8			—		6.8		—
U.S. equities	13.0			—		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		19.8		—
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	$	307.9	$	—

⁽¹⁾ This class represents pending trades with brokers.

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		)	—
Distressed 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.

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CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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, 2014			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	$	2.2		$	2.2	$	—	$	—
Equity securities
International equities	17.6			17.5		0.1		—
Fixed income securities
Government	15.5			13.7		1.8		—
Corporate	33.6			—		33.6		—
Mortgages/Asset backed securities	0.4			—		0.4		—
Other fixed income	0.1			—		—		0.1
Commingled funds
Short-term money markets	4.3			—		4.3		—
U.S. equities	125.2			—		125.2		—
International equities	36.6			—		36.6		—
Fixed income	53.5			—		53.5		—
Private equity limited partnerships
U.S. multi-strategy⁽¹⁾	7.3			—		—		7.3
International multi-strategy⁽²⁾	4.6			—		—		4.6
Distressed opportunities	1.0			—		—		1.0
Real Estate	2.3			—		—		2.3
Pension plan assets subtotal	304.2			33.4		255.5		15.3
Other postretirement benefit plan assets
Commingled funds
Short-term money markets	0.7			—		0.7		—
U.S. equities	13.6			—		13.6		—
Mutual funds
U.S. equities	86.4			86.4		—		—
International equities	38.9			38.9		—		—
Fixed income	72.0			72.0		—		—
Other postretirement benefit plan assets subtotal	211.6			197.3		14.3		—
Due to brokers, net⁽³⁾	(0.1		)
Accrued investment income/dividends	0.1
Net receivables	0.6
Total pension and other postretirement benefit plan assets	$	516.4		$	230.7	$	269.8	$	15.3

⁽¹⁾ This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily in the United States.

⁽²⁾ This class includes limited partnerships/fund of funds that invest in a diverse portfolio of private equity strategies, including buy-outs, venture capital, growth capital, special situations and secondary markets, primarily outside the United States.

⁽³⁾ This class represents pending trades with brokers.

Table of Contents

CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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, 2014:



(in millions)	Balance at January 1, 2014		Total gains or losses (unrealized / realized)			Purchases		(Sales)			Transfers into/(out of) level 3		Balance at December 31, 2014
Fixed income securities
Other fixed income	$	—	$	—		$	0.1	$	—		$	—	$	0.1
Private equity limited partnerships
U.S. multi-strategy	7.6		0.3			0.3		(0.9		)	—		7.3
International multi-strategy	5.0		(0.1		)	0.1		(0.4		)	—		4.6
Distress opportunities	1.2		—			—		(0.2		)	—		1.0
Real estate	2.6		0.3			—		(0.6		)	—		2.3
Total	$	16.4	$	0.5		$	0.5	$	(2.1	)	$	—	$	15.3

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.

Table of Contents

CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

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)	2015			2014			2015			2014
				Predecessor						Predecessor
Change in projected benefit obligation⁽¹⁾
Benefit obligation at beginning of year	$	345.2		$	327.1		$	108.9		$	105.5
Service cost	5.3			4.8			1.0			1.1
Interest cost	12.5			13.7			4.0			4.6
Plan participants’ contributions	—			—			1.6			1.9
Actuarial loss (gain)	(7.3		)	20.0			(11.6		)	4.6
Benefits paid	(23.5		)	(20.4		)	(7.5		)	(9.1		)
Estimated benefits paid by incurred subsidy	—			—			0.2			0.3
Contributed/noncontributed projected benefit obligation⁽²⁾	(4.6		)	—			(3.2		)	—
Projected benefit obligation at end of year	$	327.6		$	345.2		$	93.4		$	108.9
Change in plan assets
Fair value of plan assets at beginning of year	$	304.7		$	299.1		$	211.6		$	198.8
Actual return on plan assets	0.6			19.3			(2.0		)	9.2
Employer contributions	16.5			6.7			11.3			10.8
Plan participants’ contributions	—			—			1.6			1.9
Benefits paid	(23.5		)	(20.4		)	(7.5		)	(9.1		)
Contributed/noncontributed plan assets⁽²⁾	(4.0		)	—			(1.1		)	—
Fair value of plan assets at end of year	$	294.3		$	304.7		$	213.9		$	211.6
Funded status at end of year	$	(33.3	)	$	(40.5	)	$	120.5		$	102.7
Amounts recognized in the statement of financial position consist of:
Noncurrent assets	—			—			120.5			109.8
Current liabilities	(0.1		)	—			—			—
Noncurrent liabilities	(33.2		)	(40.5		)	—			(7.1		)
Net amount recognized at end of year⁽³⁾	$	(33.3	)	$	(40.5	)	$	120.5		$	102.7
Amounts recognized as regulatory assets/liabilities⁽⁴⁾
Unrecognized prior service (credit) cost	$	(3.0	)	$	(4.0	)	$	0.1		$	0.1
Unrecognized actuarial loss (gain)	130.3			124.5			(0.4		)	(8.3		)
Total recognized regulatory assets (liabilities)	$	127.3		$	120.5		$	(0.3	)	$	(8.2	)

⁽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 $127.1 million and $0.6 million, respectively, as of December 31, 2015, and $120.9 million and $8.3 million, respectively, as of December 31, 2014 that would otherwise have been recorded to accumulated other comprehensive loss.

The Partnership’s accumulated benefit obligation for its pension plans was $327.6 million and $345.2 million as of December 31, 2015 and 2014, 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 $33.3 million at December 31, 2015, compared to being underfunded by $40.5 million by December 31, 2014. The improvement in the funded status was due primarily to an increase in the discount rate from the prior measurement date and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed $16.5 million and $6.7 million to its pension plans in 2015 and 2014, respectively.

Table of Contents

CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

The Partnership’s funded status for its other postretirement benefit plans improved by $17.8 million to an overfunded status of $120.5 million primarily due to favorable claims experience and the implementation of new mortality assumptions released by the Society of Actuaries in 2015, offset by unfavorable asset returns. The Partnership contributed approximately $11.3 million and $10.8 million to its other postretirement benefit plans in 2015 and 2014, respectively. 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 2016.

In 2013, NiSource pension plans had year to date lump sum payouts exceeding the plans' 2013 service cost plus interest cost and, therefore, settlement accounting was required. As a result, the Predecessor recorded a settlement charge of $12.4 million in 2013. The Predecessor's net periodic pension benefit cost for 2013 was decreased by $1.2 million as a result of the interim remeasurements.

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
	2015		2014		2015		2014
			Predecessor				Predecessor
Weighted-average assumptions to determine benefit obligation
Discount Rate	4.05	%	3.64	%	4.28	%	3.95	%
Rate of Compensation Increases	4.00	%	4.00	%
Health Care Trend Rates
Trend for Next Year					8.38	%	6.90	%
Ultimate Trend					4.50	%	4.50	%
Year Ultimate Trend Reached					2022		2021

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	2.5		(2.3		)

The Partnership expects to make contributions of approximately $0.1 million to its pension plans and approximately $0.9 million to its postretirement medical and life plans in 2016.

Table of Contents

CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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)
2016	$	27.2	$	6.2	$	0.3
2017	27.1		6.2		0.3
2018	27.9		6.3		0.3
2019	28.0		6.4		0.3
2020	30.0		6.4		0.3
2021-2025	145.8		31.4		1.2

The following table provides the components of the plans’ net periodic benefits cost for the years ended December 31, 2015, 2014 and 2013:



	Pension Benefits									Other Postretirement Benefits
(in millions)	2015			2014			2013			2015			2014			2013
				Predecessor			Predecessor						Predecessor			Predecessor
Components of Net Periodic Benefit Cost (Income)
Service cost	$	5.3		$	4.8		$	4.8		$	1.0		$	1.1		$	1.5
Interest cost	12.5			13.7			12.6			4.0			4.6			4.9
Expected return on assets	(23.6		)	(23.8		)	(22.0		)	(17.4		)	(16.5		)	(13.5		)
Amortization of prior service (credit) cost	(0.9		)	(1.0		)	(0.9		)	0.1			0.1			0.1
Recognized actuarial loss (gain)	8.2			6.6			10.6			(0.2		)	(0.1		)	1.0
Net Periodic Benefit Cost (Income)	1.5			0.3			5.1			(12.5		)	(10.8		)	(6.0		)
Settlement loss	—			—			12.4			—			—			—
Total Net Periodic Benefit Cost (Income)	$	1.5		$	0.3		$	17.5		$	(12.5	)	$	(10.8	)	$	(6.0	)

The $1.2 million increase in the actuarially-determined pension benefit cost is due primarily to decreased discount rates and unfavorable asset returns in 2015 compared to 2014. For its other postretirement benefit plans, the Partnership recognized $12.5 million in net periodic benefit income in 2015 compared to net periodic benefit income of $10.8 million in 2014 due primarily to favorable claims experience, offset by a decrease in discount rates in 2015 compared to 2014.

Table of Contents

CPG OpCo LP

Notes to Consolidated and Combined Financial Statements

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

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
	2015		2014		2013		2015		2014		2013
			Predecessor		Predecessor				Predecessor		Predecessor
Weighted-average assumptions to determine net periodic benefit cost
Discount Rate	3.84	%	4.34	%	3.36	%	4.09	%	4.74	%	3.92	%
Expected Long-Term Rate of Return on Plan Assets	8.20	%	8.30	%	8.30	%	8.06	%	8.14	%	8.15	%
Rate of Compensation Increases	4.00	%	4.00	%	4.00	%

The Partnership believes it is appropriate to assume an 8.20% and 8.06% rate of return on pension and other postretirement plan assets, respectively, for its calculation of 2015 pension benefits cost. This is primarily based on asset mix and historical rates of return.

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)	2015			2014			2015			2014
				Predecessor						Predecessor
Other changes in plan assets and projected benefit obligations recognized in regulatory assets/liabilities
Net actuarial loss	$	14.1		$	24.4		$	7.8		$	11.7
Less: amortization of prior service (credit) cost	0.9			1.0			(0.1		)	—
Less: amortization of net actuarial (gain) loss	(8.2		)	(6.6		)	0.2			—
Total recognized in regulatory assets/liabilities	$	6.8		$	18.8		$	7.9		$	11.7
Amount recognized in net periodic benefit cost and regulatory assets/liabilities	$	8.3		$	19.1		$	(4.6	)	$	0.9

Based on a December 31 measurement date, the net unrecognized actuarial loss, unrecognized prior service cost (credit), and unrecognized transition obligation that will be amortized into net periodic benefit cost during 2016 for the pension plans are $10.1 million, $(0.9) million and zero, respectively, and for other postretirement benefit plans are $0.2 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, short-term borrowings 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 values of these securities are estimated based on the quoted market prices for similar issues or on the rates offered for securities of the same remaining maturities. As of December 31, 2015, the fair value approximates carrying value as these securities bear interest at variable rates. These fair value measurements are classified as Level 2 within the

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fair value hierarchy. For the years ended December 31, 2015 and 2014, 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 2015		Estimated Fair Value 2015		Carrying Amount 2014		Estimated Fair Value 2014
					Predecessor
Current portion of long-term debt-affiliated	$	—	$	—	$	115.9	$	120.0
Long-term debt-affiliated	630.9		630.9		1,472.8		1,550.4

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, 2015 and the years in which they expire were:



(in millions)	Total		2016		2017		2018		2019		2020		After
Guarantees of debt	$	2,750.0	$	—	$	—	$	500.0	$	—	$	750.0	$	1,500.0
Lines and letters of credit	33.1		33.1		—		—		—		—		—
Total commercial commitments	$	2,783.1	$	33.1	$	—	$	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. First, if CPG discharges or defeases its obligations with respect to any series of CPG’s senior notes, then any guarantee will be released with respect to that series. Second, if no event of default has occurred and is continuing under the indenture, a Guarantor will be automatically and unconditionally released and discharged from its guarantee (i) at any time after June 1, 2018, upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not CPG’s affiliate, of all of CPG’s direct or indirect limited partnership, limited liability or other equity interests in the Guarantor; (ii) upon the merger of a guarantor into CPG or any other Guarantor or the liquidation and dissolution of such Guarantor; or (iii) at any time after June 1, 2018, upon release of all guarantees or other obligations of the Guarantor with respect to any of CPG’s funded debt, except CPG’s senior notes.

Lines and Letters of Credit. CPPL maintains a $500.0 million senior revolving credit facility, of which $50.0 million is available for issuance of letters of credit. The purpose of the facility is to provide cash for general partnership purposes, including working capital, capital expenditures, and the funding of capital calls. The Partnership, together with CPG, CEG and OpCo GP, have each fully guaranteed the CPPL credit facility. As of December 31, 2015, CPPL had $15.0 million in outstanding borrowings and no letters of credit under its revolving credit facility. CPG maintains a $1,500.0 million senior revolving credit facility, of which $250.0 million in letters of credit is available. CPG expects that $750.0 million of the facility will be utilized as credit support for the Partnership and its subsidiaries and the remaining $750.0 million of the facility will be available for CPG’s general corporate purposes, including working capital. The revolving credit facility will provide liquidity support for CPG's $1,000.0 million commercial paper program. The Partnership, together with CEG and OpCo GP, have each fully guaranteed the CPG credit facility. As of December 31, 2015, CPG had no borrowings outstanding and $18.1 million in letters of credit outstanding under its revolving credit facility.

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CPG has established a commercial paper program (the “Program”) pursuant to which CPG may issue short-term promissory notes (the “Promissory Notes”) pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act of 1933, as amended (the "Securities Act"). Amounts available under the Program may be borrowed, repaid and re-borrowed from time to time, with the aggregate face or principal amount of the Promissory Notes outstanding under the Program at any time not to exceed $1,000.0 million. The Partnership, together with CEG and OpCo GP, have 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. The net proceeds of issuances of the Promissory Notes are expected to be used for general corporate purposes. As of December 31, 2015, CPG had no Promissory Notes outstanding under the Program.

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 solid waste. The Partnership believes that it is in substantial compliance with those environmental regulations currently applicable to its operations and believes that it has all necessary material permits to conduct its operations.

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 and Combined Balance Sheets. The noncurrent portion is included in “Other noncurrent liabilities” in the Consolidated and Combined 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 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.

The following NAAQS were recently added or modified:

Ozone: On October 1, 2015, the EPA issued a final rule lowering the NAAQS for ground-level ozone to 70 parts per billion ("ppb") under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is required to include an adequate margin of safety in establishing the primary ozone standard for protection of public health, whereas the secondary ozone standard is intended to improve protection for trees, plants and ecosystems. The final rule becomes effective sixty days after the rule is published in the Federal Register. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017 and, depending on the severity of the ozone present, non-attainment areas will have until between 2020 and 2037 to meet the health standard. With the EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations. Based on the current version of the rule, the Partnership does not expect a material impact on its operations.

Nitrogen Dioxide (NO2): The EPA revised the NO2 NAAQS by adding a one-hour standard while retaining the annual standard. The new standard could impact some CPG combustion sources. The EPA designated all areas of the country as unclassifiable/attainment in January 2012. After the establishment of a new monitoring network and possible modeling implementation, areas

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will potentially be re-designated sometime in 2016. States with areas that do not meet the standard will be required to develop rules to bring areas into compliance within five years of designation. Additionally, under certain permitting circumstances, emissions from some existing Partnership combustion sources may need to be assessed and mitigated. The Partnership will continue to monitor this matter and cannot estimate the impact of these rules at this time.

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 U.S. on an annual basis. Future legislative and regulatory programs could significantly restrict emissions of greenhouse gases including methane.

New Source Performance Standards: On August 18, 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. Semiannual leak detection and repair requirements using optical gas imaging are proposed for all components at new or existing compressor stations. Existing compressor stations trigger leak detection and repair requirements if any unit at the facility is modified. The EPA proposed additional requirements for any new or modified centrifugal or reciprocating compressors. Replacement of wet seals with dry seals or demonstrating a 95% reduction of methane emissions from wet seals is proposed for centrifugal compressors and rod packing replacement for reciprocating compressors is proposed every 26,000 hours of operation or every three years. 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 $18.5 million in 2015, $14.9 million in 2014 and $13.4 million in 2013, 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⁾
2016	$	4.5
2017	5.9
2018	5.5
2019	4.8
2020	4.7
After	21.2
Total future minimum payments	$	46.6

⁽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 2016 to 2025, require the Partnership to pay fixed monthly charges.

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The estimated aggregate amounts of minimum fixed payments at December 31, 2015, were:



(in millions)	Pipeline Service Agreements
2016	$	51.5
2017	49.5
2018	42.0
2019	25.4
2020	24.2
After	66.8
Total future minimum payments	$	259.4

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, 2013 - Predecessor	$	(18.7	)	$	(0.1	)	$	(18.8	)
Other comprehensive income before reclassifications	—			—			—
Amounts reclassified from accumulated other comprehensive income	1.1			—			1.1
Net current-period other comprehensive income	1.1			—			1.1
Balance as of December 31, 2013 - 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⁽³⁾	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	)

⁽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.

⁽³⁾ Includes amounts allocated to noncontrolling interest.

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 $25.0 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 $25.0 million

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and $16.6 million at December 31, 2015 and December 31, 2014, respectively, is included in unrealized losses on cash flow hedges above.


15.	Other, Net



Year Ended December 31, (in millions)	2015		2014			2013
			Predecessor			Predecessor
AFUDC Equity	$	28.3	$	11.0		$	6.8
Miscellaneous⁽¹⁾	3.7		(2.2		)	10.8
Total Other, net	$	32.0	$	8.8		$	17.6

⁽¹⁾Miscellaneous in 2013 primarily consists of a gain from insurance proceeds.


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. The Chief Executive Officer of CPPL is the chief operating decision maker for the periods presented.

At December 31, 2015, 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, 2015, 2014 and 2013:



Year Ended December 31, (in millions)	2015		2014		2013
			Predecessor		Predecessor
Supplemental Disclosures of Cash Flow Information
Non-cash transactions:
Capital expenditures included in current liabilities⁽¹⁾	$	122.7	$	78.5	$	53.1
Schedule of interest and income taxes paid:
Cash paid for interest, net of interest capitalized amounts	$	39.3	$	53.6	$	39.5
Cash paid for income taxes	0.2		21.5		10.2

⁽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.

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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, 2015, 2014 and 2013. The following table provides this customer's operating revenues and percentage of total operating revenues for the years ended December 31, 2015, 2014 and 2013:



Year Ended December 31,	2015				2014				2013
(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				Predecessor
Columbia Gas of Ohio⁽¹⁾	$	167.3	12.6	%	$	168.5	12.5	%	$	167.5	14.2	%

⁽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.

19. Subsequent Events

Partnership Distribution. On February 16, 2016, the Partnership distributed $129.2 million of earnings to limited partners. CPPL received a distribution of $20.3 million, Columbia Hardy received $1.0 million and CEG received $107.9 million based on the respective ownership percentages in the Partnership.