SOUTHERN Co GAS - FORM 8-K - EX-99.1 - EXHIBIT 99.1

Attached files

file	filename
EX-99.3 - EXHIBIT 99.3 - SOUTHERN Co GAS	exhibit993.htm
EX-99.2 - EXHIBIT 99.2 - SOUTHERN Co GAS	sogas8-kex99x2assignofsonat.htm
EX-23.1 - EXHIBIT 23.1 - SOUTHERN Co GAS	sogas8-kex23x1assignofsonat.htm
EX-2.1B - EXHIBIT 2.1B - SOUTHERN Co GAS	sogas8-kex2x1basignofsonat.htm
EX-2.1A - EXHIBIT 2.1A - SOUTHERN Co GAS	sogas8-kex2x1aassignofsonat.htm
8-K - 8-K - SOUTHERN Co GAS	sogas8-kassignofsonat.htm

Exhibit 99.1

CONSOLIDATED FINANCIAL STATEMENTS

With Independent Auditor's Report

SOUTHERN NATURAL GAS COMPANY, L.L.C.

As of December 31, 2015 and 2014 and

For the Years Ended December 31, 2015 and 2014

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

TABLE OF CONTENTS



	Page Number
Independent Auditor's Report	1

Consolidated Financial Statements
Consolidated Statements of Income	2
Consolidated Balance Sheets	3
Consolidated Statements of Cash Flows	4
Consolidated Statements of Member's Equity	5
Notes to Consolidated Financial Statements	6

Independent Auditor’s Report

To the Management of Southern Natural Gas Company, L.L.C.:

We have audited the accompanying consolidated financial statements of Southern Natural Gas Company, L.L.C. and its subsidiaries (the “Company”), which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related consolidated statements of income, of member’s equity, and of cash flows for the years then ended.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design 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. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southern Natural Gas Company, L.L.C. and its subsidiaries at December 31, 2015 and 2014, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As discussed in Note 7 to the consolidated financial statements, the Company has extensive operations and relationships with affiliated entities. Our opinion is not modified with respect to this matter.

/s/PricewaterhouseCoopers LLP

Houston, Texas

April 14, 2016

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

(In Millions)



	Year Ended December 31,
	2015			2014
Revenues	$	573		$	571

Operating Costs and Expenses
Operations and maintenance	113			106
Depreciation and amortization	92			95
General and administrative	34			33
Taxes, other than income taxes	37			37
Gain on sale of long-lived assets	(10		)	(2		)
Total Operating Costs and Expenses	266			269

Operating Income	307			302

Other Income (Expense)
Earnings from equity investment	9			12
Interest, net	(77		)	(77		)
Other, net	1			1
Total Other Income (Expense)	(67		)	(64		)

Income Before Income Taxes	240			238

Income Tax Expense	—			(1		)

Net Income	$	240		$	237

The accompanying notes are an integral part of these consolidated financial statements.

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

(In Millions)



	December 31,
	2015		2014
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts receivable, net	49		56
Inventories	18		18
Regulatory assets	13		14
Other current assets	2		8
Total current assets	82		96

Property, plant and equipment, net	2,439		2,473
Investment	61		61
Note receivable from affiliate	80		166
Regulatory assets	40		49
Deferred charges and other assets	32		43
Total Assets	$	2,734	$	2,888

LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Accounts payable	$	43	$	41
Accrued interest	19		19
Accrued taxes, other than income taxes	6		10
Regulatory liabilities	3		5
Customer deposits	2		6
Other current liabilities	4		3
Total current liabilities	77		84

Long-term liabilities and deferred credits
Long-term debt, net of debt issuance costs	1,205		1,203
Other long-term liabilities and deferred credits	21		42
Total long-term liabilities and deferred credits	1,226		1,245
Total Liabilities	1,303		1,329

Commitments and contingencies (Notes 2 and 10)
Member's Equity	1,431		1,559
Total Liabilities and Member's Equity	$	2,734	$	2,888

The accompanying notes are an integral part of these consolidated financial statements.

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)



	Year Ended December 31,
	2015			2014
Cash Flows From Operating Activities
Net income	$	240		$	237
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	92			95
Earnings from equity investment	(9		)	(12		)
Gain on sale of long-lived assets	(10		)	(2		)
Other non-cash items	3			4
Distributions from equity investment earnings	9			11
Changes in components of working capital:
Accounts receivable	3			13
Regulatory assets	(10		)	(1		)
Accounts payable	(6		)	15
Other current assets and liabilities	(3		)	(2		)
Other long-term assets and liabilities	19			(20		)
Net Cash Provided by Operating Activities	328			338

Cash Flows From Investing Activities
Capital expenditures	(63		)	(54		)
Net change in note receivable from affiliates	86			17
Sale or disposal of property, plant and equipment, net of salvage	14			—
Other, net	3			—
Net Cash Used in Investing Activities	40			(37		)

Cash Flows From Financing Activities
Distributions to Member	(368		)	(301		)
Net Cash Used in Financing Activities	(368		)	(301		)

Net Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents, beginning of period	—			—
Cash and Cash Equivalents, end of period	$	—		$	—

Non-cash Investing Activities
Net increases in property, plant and equipment accruals	$	9		$	—

Supplemental Disclosure of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	74		$	74

The accompanying notes are an integral part of these consolidated financial statements.

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF MEMBER'S EQUITY

(In Millions)



	Year Ended December 31,
	2015			2014
Beginning Balance	$	1,559		$	1,623
Net income	240			237
Distributions	(368		)	(301		)
Ending Balance	$	1,431		$	1,559

The accompanying notes are an integral part of these consolidated financial statements.

SOUTHERN NATURAL GAS COMPANY, L.L.C. AND SUBSIDIARY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General

We are a Delaware limited liability company, originally formed in 1935 as a corporation. When we refer to “us,” “we,” “our,” “ours,” “the Company,” or “SNG,” we are describing Southern Natural Gas Company, L.L.C and its consolidated subsidiary.

Prior to January 1, 2015, we were wholly owned by El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC), a wholly owned subsidiary of El Paso Pipeline Partners, L.P., (EPB), a master limited partnership indirectly controlled by Kinder Morgan, Inc. (KMI). On January 1, 2015, EPB and its subsidiary, EPPOC, merged with and into Kinder Morgan Energy Partners, L.P. (KMP), with KMP surviving the merger. As a result of such merger, we became a direct wholly owned subsidiary of KMP, which is a subsidiary of by KMI.

Our operations are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. The FERC approves tariffs that establish rates, cost recovery mechanisms and other terms and conditions of service to our customers.

Our primary business consists of the interstate transportation and storage of natural gas. We own a 6,900 mile pipeline system with a design capacity of approximately 3.9 billion cubic feet per day for natural gas. This pipeline system extends from the supply basins in Louisiana, Mississippi, Alabama and the Gulf of Mexico to market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham. We also own and operate 100% of the Muldon storage facility in Monroe County, Mississippi and a 50% interest in Bear Creek Storage Company, L.L.C. (Bear Creek) in Bienville Parish, Louisiana. Our interest in Bear Creek, the Muldon storage facilities and contracted storage have a combined working natural gas storage capacity of approximately 68 billion cubic feet (Bcf) and peak withdrawal capacity of 1.3 Bcf per day. Bear Creek is a joint venture equally owned by us and Tennessee Gas Pipeline Company, L.L.C., an affiliate.

2. Summary of Significant Accounting Policies

Basis of Presentation

We have prepared our accompanying consolidated financial statements in accordance with the accounting principles contained in the Financial Accounting Standards Board's (FASB) Accounting Standards Codification, the single source of United States Generally Accepted Accounting Principles (GAAP) and referred to in this report as the Codification. Additionally, certain amounts from the prior year have been reclassified to conform to the current presentation.

Management has evaluated subsequent events through April 14, 2016, the date the financial statements were available to be issued.

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. All significant intercompany items have been eliminated in consolidation.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

Cash Equivalents

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Accounts Receivable, net

We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method. The allowance for doubtful accounts as of December 31, 2015 and 2014 was not significant.

Inventories

Our inventories, which consist of materials and supplies, are valued at the lower of average cost or market.

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system or storage facility differs from the scheduled amount of gas to be delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of our FERC tariff. Imbalances due from customers and affiliates are reported on our accompanying Consolidated Balance Sheets in “Other current assets.” Imbalances owed to customers and affiliates are reported on our accompanying Consolidated Balance Sheets in “Other current liabilities.” We classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment, net

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in utility service. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Our indirect construction costs primarily include an interest and equity return component (as more fully described below) and labor and related costs associated with supporting construction activities. The indirect capitalized labor and related costs are based upon estimates of time spent supporting construction projects.

We use the composite method to depreciate property, plant and equipment. Under this method, assets with similar economic characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals its salvage value. For certain general plant, the asset is depreciated to zero. As

part of periodic filings with the FERC, we also re-evaluate and receive approval for our depreciation rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize gains or losses unless we sell land or sell or retire an entire operating unit (as approved by the FERC). In those instances where we receive recovery in rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. For more information on our regulatory asset we recorded associated with the sale of certain of our assets, see Note 9.

Included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss on our accompanying Consolidated Statements of Income or defer the loss as a regulatory asset on our accompanying Consolidated Balance Sheets if deemed probable of recovery through future rates charged to customers.

We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs capitalized are included as a reduction in “Interest, net” on our accompanying Consolidated Statements of Income. The equity portion is calculated based on our most recent FERC approved rate of return. Equity amounts capitalized are included in “Other, net” on our accompanying Consolidated Statements of Income. The amounts of capitalized AFUDC were not significant for the years ended December 31, 2015 and 2014.

Asset Retirement Obligations (ARO)

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of ARO on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

We are required to operate and maintain our natural gas pipelines and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the ARO for the substantial majority of our assets because these assets have indeterminate lives. We continue to evaluate our ARO and future developments could impact the amounts we record. Our recorded ARO were not significant as of December 31, 2015 and 2014.

Asset and Investment Impairments

We evaluate our assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in market conditions or in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on either (i) the long-lived asset's ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value.

Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted future cash flows. There were no impairments for the years ended December 31, 2015 and 2014.

Equity Method of Accounting

We account for investments, which we do not control but do have the ability to exercise significant influence, by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received.

Revenue Recognition

We are subject to FERC regulations, therefore fees and rates established under our tariff are a function of our cost of providing services to our customers, including a reasonable return on our invested capital. Our revenues are primarily generated from natural gas transportation and storage services and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation services and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. The revenues we collect may be subject to refund in a rate proceeding. We had no reserves for potential rate refunds as of December 31, 2015 and 2014.

For the year ended December 31, 2015, revenues from our three largest non-affiliate customers were approximately $148 million, $108 million and $58 million, respectively, each of which exceeded 10% of our operating revenues. For the year ended December 31, 2014, revenues from our three largest non-affiliate customers were approximately $149 million, $107 million and $61 million, respectively, each of which exceeded 10% of our operating revenues.

Environmental Matters

We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required in obtaining rights-of-way, regulatory approvals or permitting as part of the construction. We accrue and expense environmental costs that relate to an existing condition caused by past operations. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental disclosures, see Note 10.

Other Contingencies

We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue an undiscounted liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees that we have made contributions to in the past. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded on our accompanying Consolidated Statements of Income and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For more information on our policies with respect to our postretirement benefit plan, see Note 6.

In accounting for our postretirement benefit plan, we record an asset or liability based on the difference between the fair value of the plan's assets and the plan's benefit obligation. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded on our Consolidated Balance Sheets as a regulatory asset or liability until those gains or losses are recognized on our accompanying Consolidated Statements of Income.

Income Taxes

We are a limited liability company and are not subject to federal income taxes or state income taxes. Our member is responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. However, we are subject to Texas margin tax (a revenue based calculation), which is presented as “Income Tax Expense” on our accompanying Consolidated Statements of Income.

Regulated Operations

Our interstate natural gas pipeline and storage operations are subject to the jurisdiction of the FERC and are accounted for in accordance with Accounting Standards Codification Topic 980, “Regulated Operations.” Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, losses on reacquired debt, losses on the sale of certain long lived assets, taxes related to an equity return component on regulated capital projects prior to our change in legal structure to a non taxable entity, certain cost differences between gas retained and gas consumed in operations and other costs included in, or expected to be included in, future rates. For more information on our regulated operations, see Note 9.

3. Divestiture

On December 15, 2014, we filed an application with the FERC seeking authorization to abandon by sale approximately 33.6 miles of our 10-inch diameter Carthage Lateral Pipeline (Carthage Pipeline) located in Panola and Shelby Counties, Texas and DeSoto Parish, Louisiana. On March 19, 2015, the FERC issued an order approving the sale and related abandonment of approximately 300 feet of the Carthage Pipeline. On April 30, 2015, we completed the sale of the Carthage Pipeline, as well as three associated receiving stations and other appurtenant facilities for an aggregate consideration of $12 million in cash. Upon closing, we recorded a gain on sale of long-lived assets of approximately $10 million on our accompanying Consolidated Statement of Income for the year ended December 31, 2015.

4. Property, Plant and Equipment, net

Our property, plant and equipment, net consisted of the following (in millions, except for %):



		December 31,
	Annual Depreciation Rates %	2015			2014
Transmission and storage facilities	0.9-2.25	$	3,490		$	3,480
General plant	3.33-20	25			26
Intangible plant	5-10	16			16
Other		108			131
Accumulated depreciation and amortization (a)		(1,281		)	(1,212		)
		2,358			2,441
Land		12			12
Construction work in progress		69			20
Property, plant and equipment, net		$	2,439		$	2,473

_______________


(a)	The composite weighted average depreciation rates for the years ended December 31, 2015 and 2014 were approximately 2.3% and 2.4%, respectively.

5. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense on our accompanying Consolidated Statements of Income.

The following table summarizes the net carrying value of our outstanding debt (in millions):



	December 31,
	2015		2014
5.90% Notes due April 2017	$	500	$	500
4.40% Notes due June 2021	300		300
7.35% Notes due February 2031	153		153
8.00% Notes due March 2032	258		258
	1,211		1,211
Less: Unamortized discount and debt issuance costs	6		8
Total debt	$	1,205	$	1,203

KMI and substantially all of its domestic subsidiaries, including us, are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.

Debt Covenants

Under our various financing documents, we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. For the years ended December 31, 2015 and 2014, we were in compliance with our debt-related covenants.

6. Retirement Benefits

Pension and Retirement Savings Plans

KMI maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including certain of our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, KMI contributes an amount equal to 5% of participants’ eligible compensation per year. KMI is responsible for benefits accrued under its plans and allocates certain costs based on a benefit allocation rate applied on payroll charged to its affiliates.

Postretirement Benefits Plan

We provide postretirement benefits, including medical benefits for a closed group of retirees. Medical benefits for this closed group may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs, and are subject to further benefit changes by KMI, the plan sponsor. Effective January 1, 2014, the plan was amended to provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. In addition, certain employees continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs were prefunded and were recoverable under prior rate case settlements. Currently, there is no cost recovery or related funding that is required as part of our current FERC approved rates, however, we can seek to recover any funding shortfall that may be required in the future. We do not expect to make any contributions to our postretirement benefit plan in 2016 and there were no contributions made in 2015 and 2014. KMI's postretirement plans have been merged. We are permitted to use combined plan assets under the structure of the plans of our affiliated entities to fund participant benefits, including participants of affiliated entities.

Postretirement Benefit Obligation, Plan Assets and Funded Status

Our postretirement benefit obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rates used in calculating the benefit obligations. For 2015, we selected our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.

Effective January 1, 2016, we changed our estimate of the service and interest cost components of net periodic benefit cost (credit) for our other postretirement benefit plan. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. The change does not affect the measurement of our postretirement benefit obligation and it is accounted for as a change in accounting estimate, which is applied prospectively. The change in the service and interest costs going forward will not be significant.

In accounting for our postretirement benefit plan, we record an asset based on its overfunded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as a regulatory asset or liability as allowed by the FERC.

The table below provides information about our postretirement benefit plan (in millions):



	December 31,
	2015			2014
Change in postretirement benefit obligation:
Postretirement benefit obligation - beginning of period	$	35		$	37
Interest cost	1			1
Actuarial (gain) loss	(1		)	—
Benefits paid (a)	(3		)	(3		)
Postretirement benefit obligation - end of period	$	32		$	35
Change in plan assets:
Fair value of plan assets - beginning of period	$	71		$	67
Actual return on plan assets	(12		)	6
Employer contributions/transfers	2			1
Benefits paid	(3		)	(3		)
Fair value of plan assets - end of period	$	58		$	71
Reconciliation of funded status:
Fair value of plan assets	$	58		$	71
Less: Postretirement benefit obligation	32			35
Net asset at December 31(b)	$	26		$	36

________________


(a)	Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2015 and 2014 related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.


(b)	Net asset amounts are included in “Deferred charges and other assets” on our accompanying Consolidated Balance Sheets.

Plan Assets

The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 30% equity, 30% fixed income and 40% master limited partnerships.

We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. Generally, we separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2015, assets were comprised of a money market fund with a fair value of $2 million, domestic equity securities with a fair value of $2 million, and master limited partnerships with a fair value of $14 million. As of December 31, 2014, assets were comprised of domestic equity securities with a fair value of $7 million, and master limited partnerships with a fair value of $20 million. Money market funds are valued at amortized cost, which approximates fair value (which is

considered a Level 2 measurement). The domestic equity securities and the master limited partnerships are exchange traded, and the fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the investment in actively traded markets. In 2015, we adopted Accounting Standards Update (ASU) No. 2015-07, “Fair Value Measurement (Topic 820) - Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent).” This ASU removes the requirement to include investments in the fair value hierarchy for which the fair value is measured at Net Asset Value (NAV) using the practical expedient under Topic 820. Plan assets with fair values that are based on NAV per share, or its equivalent, as reported by the issuers, are determined based on the fair value of the underlying securities as of the valuation date and include fixed income trusts and limited partnerships which are primarily invested in global equity securities. The fair value of the fixed income trusts as of December 31, 2015 and 2014 is $17 million and $19 million, respectively. The fair value of the limited partnerships as of December 31, 2015 and 2014 is $23 million and $25 million, respectively. The plan does not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2015 and 2014.

Expected Payment of Future Benefits

As of December 31, 2015, we expect the following benefit payments under our plan (in millions):



Year	Total
2016	$	3
2017	3
2018	3
2019	3
2020	3
2021 - 2025	11

Actuarial Assumptions and Sensitivity Analysis

Postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs.



	2015	2014
	(%)
Assumptions related to benefit obligations at December 31:
Discount rate	3.81	3.44
Assumptions related to benefit costs for the year ended December 31:
Discount rate	3.44	4.17
Expected return on plan assets(a)	7.25	7.60

______________


(a)	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes with a weighted average rate of 21% for both 2015 and 2014.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4%, gradually decreasing to 4.5% by the year 2038. A one-percentage point

change in assumed health care trends would not have had a significant effect on the postretirement benefit obligation or interest costs as of December 31, 2015 and 2014.

Components of Net Benefit Income

The components of net benefit costs (income) are as follows (in millions):



	Year Ended December 31,
	2015					2014
Interest cost	$	1				$	1
Expected return on plan assets	(4				)	(4				)
Amortization of prior service credit	(2				)	(1				)
Amortization of net actuarial gain	(1				)	(1				)
Net benefit income			$	(6	)			$	(5	)

7. Related Party Transactions

Cash Management Program

We participate in KMI's cash management program, which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. KMI uses the cash management program to settle intercompany transactions between participating affiliates. As of December 31, 2015 and 2014, we had a note receivable from KMI of $80 million and $166 million, respectively. The interest rate on the note was variable and was 1.0% and 1.5% as of December 31, 2015 and 2014, respectively.

Other Affiliate Balances and Activities

We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to and from affiliates under long-term contracts, storage contracts and various operating agreements.

We do not have employees. Employees of KMI provide services to us. We are managed and operated by KMI. Under policies with KMI, we reimburse KMI without a profit component for the provision of various general and administrative services for our benefit and for direct expenses incurred by KMI on our behalf. Additionally, KMI bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us at cost.

The following table summarizes our other balance sheet affiliate balances (in millions):



	December 31,
	2015		2014
Accounts receivable	$	—	$	1
Natural gas imbalance receivable (a)	—		1
Accounts payable	—		13

——————

(a) Included in “Other current assets” on our accompanying Consolidated Balance Sheets.

The following table shows revenues and costs from our affiliates (in millions):



	Year Ended December 31,
	2015		2014
Revenues	$	8	$	8
Operation, maintenance and capitalized costs	58		49
General and administrative	28		28

Subsequent Event

In March 2016, we made a cash distribution to our Member of $78 million.

8. Fair Value

The following table reflects the carrying amount and estimated fair value of our outstanding debt balances (in millions):



	As of December 31,
	2015		2014
	Carrying Amount	Estimated Fair Value	Carrying Amount	Estimated Fair Value
Total debt	$1,205	$1,155	$1,203	$1,366

We separate the fair values of our financial instruments into levels based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the estimated fair value. We estimate the fair values of our long-term debt primarily based on quoted market prices for the same or similar issues, a Level 2 fair value measurement. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and this change would be reflected at the end of the period in which the change occurs. During the years ended December 31, 2015 and 2014, there were no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they were classified.

As of December 31, 2015 and 2014, the carrying amounts of our affiliate note receivable approximates its fair value due to the market-based nature of the interest rate.

9. Accounting for Regulatory Activities

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. As of December 31, 2015, the regulatory assets are being recovered as cost of service in our rates over a period of approximately one year to 28 years. Below are the details of our regulatory assets and liabilities as of (in millions):



	December 31,
	2015		2014
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	12	$	2
Unamortized loss on sale of assets	—		11
Other	1		1
Total current regulatory assets	13		14
Non-current regulatory assets
Taxes on capitalized funds used during construction	25		26
Unamortized loss on reacquired debt	13		16
Other	2		7
Total non-current regulatory assets	40		49
Total regulatory assets	$	53	$	63

Current regulatory liabilities
Difference between gas retained and gas consumed in operations	$	—	$	4
Other	3		1
Total current regulatory liabilities	3		5
Non-current regulatory liabilities
Postretirement benefits	18		35
Other	3		4
Total non-current regulatory liabilities (a)	21		39
Total regulatory liabilities	$	24	$	44

_______________

(a) Included in “Other long-term liabilities and deferred credits” on our accompanying Consolidated Balance Sheets.

Our significant regulatory assets and liabilities include:

Difference between gas retained and gas consumed in operations

These amounts reflect the value of the volumetric difference between the gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers in subsequent fuel filing periods.

Taxes on capitalized funds used during construction

Amounts represent the recovery of deferred income taxes on AFUDC Equity recognized during the time prior to 2007 when we were a taxable entity. These taxes are included in the tax component of our rates and are recovered over the depreciable lives of the asset in which they apply.

Unamortized loss on reacquired debt

Amounts represent the deferred and unamortized portion of loss on reacquired debt which are recovered through the cost of service over the original life of the debt issue, or in the case of refinanced debt, over the life of the new debt issue.

Unamortized loss on sale of asset

Amount represents the deferred and unamortized portion of the loss on sale of the offshore assets. In accordance with our rate case settlement, the recovery of the total regulatory asset occurred over a three-year period ending on October 31, 2015.

Postretirement Benefits

Amount represents unrecognized gains and losses related to our postretirement benefit plan.

Regulatory Assets Amortization

Our amortization of the regulatory assets for 2015 and 2014 was $15 million and $18 million, respectively, which primarily consisted of (i) deferred losses on sale of offshore assets included in “Depreciation and amortization” of $11 million and $13 million, respectively, and (ii) deferred losses on reacquired debt included in “Interest, net” of $3 million for each respective year on our accompanying Consolidated Statements of Income.

Regulatory Matters

Rate Case

On January 31, 2013, the FERC approved our request to amend our January 2010 rate settlement with our customers. The amendment extended the required filing date for our rate case from February 28, 2013 to no later than May 31, 2013. On May 2, 2013, we filed a comprehensive settlement with our customers to resolve all matters relating to our rates. The FERC approved the comprehensive settlement on July 12, 2013. Under the settlement, customers must extend all firm service agreements through August 31, 2016, and we cannot file a Section 4 rate case to be effective earlier than September 1, 2016. The settlement also includes a two-phase reduction in rates. The first phase, effective on September 1, 2013, resulted in an approximately $11 million revenue reduction for 2013 and an additional revenue reduction of approximately $23 million for 2014. The second phase, effective November 1, 2015, resulted in an additional revenue reduction of approximately $2 million for 2015 and will result in an additional revenue reduction of approximately $12 million in 2016. The settlement prohibits both us and our customers from requesting a change to our rates during a three-year moratorium through August 31, 2016 and requires us to file a new rate case to be effective no later than September 1, 2018.

Other

On October 15, 2015 the FERC issued a “Notice of Schedule for Environmental Review of the Elba Liquefaction Project” relating to the application before the FERC in Docket No. CP14-115 by our affiliate Elba Express Company, L.L.C. (“EEC”). In such application, EEC proposes to provide firm transportation service to us and others so that we, in turn, will be able to provide additional firm transportation service of up to 235,110 Mcf/day to ten (10) of our existing customers. We have applied with FERC in Docket No. CP14-493 to expand our system and provide such additional service (“Zone 3 Expansion Project”). Our application for the Zone 3 Expansion Project proposed an in-service date of June 1, 2016. The FERC has informed us that

because of the nexus with the EEC application, it will not issue an order approving our application until it is able to rule on the EEC application. Based on the schedule published by the FERC for the EEC application, we will not be able to place the facilities in service by the proposed start date of June 1, 2016. Depending on the actual issuance date of the FERC Order, the current schedule provides that the in-service date could be as late as November 1, 2016.

10. Litigation, Environmental and Commitments

We are party to various legal, regulatory and other matters arising from the day-to-day operations of our businesses that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed.

Legal Proceeding

Cliffs Natural Resources (Cliffs)

We are engaged in a lawsuit against Cliffs in the Circuit Court of Jefferson County, Alabama (Case No. 68-CV-2014-900533) to determine whether Cliffs’ longwall coal mining operations require the relocation of a large segment of our pipelines in Jefferson County, Alabama and who will be responsible for the cost of any such relocation. Prior to the initiation of the lawsuit, Cliffs notified us of its intent to conduct underground longwall coal mining operations in the vicinity of four of our pipelines in Jefferson County. Upon being informed by Cliffs that its planned coal mining operations would cause surface subsidence of three to six feet, we determined that such level of subsidence presented a safety hazard to our pipelines and that relocating the affected pipelines may be the safest and most economical option to mitigate the safety hazard. We allege in the lawsuit that easements governing our property rights to operate our pipelines do not allow Cliffs’ mining operations to proceed as planned. We also allege, among other things, that if Cliffs is allowed to proceed with its mining plan, Cliffs should be responsible for the pipeline relocation costs and any other damages, which are estimated to be approximately $32 million. We have completed the relocation of the pipelines to avoid the mining threat.

General

As of both December 31, 2015 and 2014, we had approximately $3 million accrued for our outstanding legal proceedings.

Environmental Matters

We are subject to environmental cleanup and enforcement actions from time to time. In particular, the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in our operations, and there can be no assurance that we will not incur significant costs and liabilities. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

Southeast Louisiana Flood Protection Litigation

On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority - East (SLFPA) filed a petition for damages and injunctive relief in state district court for Orleans Parish, Louisiana (Case No. 13-6911) against us, and approximately 100 other energy companies, alleging that defendants’ drilling, dredging, pipeline and industrial operations since the 1930’s have caused direct land loss and increased erosion and submergence resulting in alleged increased storm surge risk, increased flood protection costs and unspecified damages to the plaintiff. The SLFPA asserts claims for negligence, strict liability, public nuisance, private nuisance, and breach of contract. Among other relief, the petition seeks unspecified monetary damages, attorney fees, interest, and injunctive relief in the form of abatement and restoration of the alleged coastal land loss including but not limited to backfilling and re-vegetation of canals, wetlands and reef creation, land bridge construction, hydrologic restoration, shoreline protection, structural protection, and bank stabilization. On August 13, 2013, the suit was removed to the U.S. District Court for the Eastern District of Louisiana. On February 13, 2015, the Court granted defendants’ motion to dismiss the suit for failure to state a claim, and issued an order dismissing the SLFPA’s claims with prejudice. The SLFPA filed a notice of appeal on February 20, 2015. The U.S. Court of Appeals for the Fifth Circuit heard oral argument on the SLFPA’s appeal on February 29, 2016 and we await the court's decision.

Superfund Matters

Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under CERCLA, commonly known as Superfund, or state equivalents for one active site. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities.

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiary are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of December 31, 2015 and 2014, we had less than $1 million accrued for our environmental matters.

Commitments

Capital Commitments

As of December 31, 2015, we have capital commitments of $29 million, which we expect to spend during 2016. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Other Commercial Commitments

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Our obligations under these easements are not material to our results of operations.

Storage Commitments

We have entered into storage capacity contracts totaling $7 million at December 31, 2015, most of which are related to storage capacity contracts with our affiliate, Bear Creek, which we expect to spend during 2016. We expect annual renewal of this contract to occur into the foreseeable future.

Operating Leases

We lease property, facilities and equipment under various operating leases. Our primary commitment under operating leases is the lease of our office space in Birmingham, Alabama. KMI guarantees our obligations under these lease agreements. Our future minimum annual rental commitments under our operating leases as of December 31, 2015, are as follows (in millions):



Year	Total
2016	$	2
2017	2
2018	2
2019	2
2020	2
Thereafter	16
Total	$	26

Rent expense on our lease obligations for the years ended December 31, 2015 and 2014 was approximately $2 million and $1 million, respectively, and is reflected in “Operations and maintenance” on our accompanying Consolidated Statements of Income. While we hold the contractual obligations for the operating leases, the rent expense, which is considered a shared services cost and allocated to various KMI subsidiaries, is administered and funded by KMI.

11. Recent Accounting Pronouncement

ASU No. 2014-09

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU is designed to create greater comparability for financial statement users across industries and jurisdictions. The provisions of ASU No. 2014-09 include a five-step process by which entities will recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the payment to which an entity expects to be entitled in exchange for those goods or services. The standard also will require enhanced disclosures, provide more comprehensive guidance for transactions such as service revenue and contract modifications, and enhance guidance for multiple-element arrangements. ASU No. 2014-09 will be effective for us January 1, 2018. Early adoption is permitted for the interim periods within the adoption year. We are currently reviewing the effect of ASU No. 2014-09 on our revenue recognition and assessing the timing of our adoption.

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