UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 8-K/A
(Amendment No. 1)

CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported):    July 1, 2018

SOUTH JERSEY INDUSTRIES, INC.
(Exact name of registrant as specified in Charter)
New Jersey	1-6364	22-1901645	
(State or other jurisdiction Of incorporation)	(Commission File Number)	(IRS Employer Identification No.)	

1 South Jersey Plaza, Folsom, NJ	 	08037	
(Address of principal executive offices)	 	(Zip Code)	

(609) 561-9000

(Registrant’s telephone number, including area code)

N/A

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
 
☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	

☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	

☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	

☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	
 
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

EXPLANATORY NOTE
 
This Amendment No. 1 to the Current Report on Form 8-K (this “Amendment”) is being filed by South Jersey Industries, Inc. (the “Company”) for the purpose of amending Item 9.01 Financial Statements and Exhibits of that certain Current Report on Form 8-K originally filed by the Company with the U.S. Securities and Exchange Commission (“SEC”) on July 2, 2018 (the “Original Form 8-K”) in connection with the closing of the acquisition of Elizabethtown Gas Company from Pivotal Utility Holdings, Inc. As indicated in the Original Form 8-K, this Amendment is being filed to provide the financial statements and pro forma financial information required by Items 9.01(a) and (b) of Form 8-K, which were not previously filed with the Original Form 8-K as permitted by the rules of the SEC.
 
Item 9.01	Financial Statements and Exhibits.	
 
 	(a)	Financial Statements of Businesses Acquired	
 
The following financial statements of Elizabethtown Gas Company are being filed as exhibits hereto and are incorporated by reference herein:
 
Exhibit 99.2 — Audited Financial Statements of Elizabethtown Gas as of December 31, 2017 and 2016 and for the years then ended and as of December 31, 2016 and 2015 and for the years then ended.
 
Exhibit 99.3 — Unaudited Condensed Financial Statements of Elizabethtown Gas as of June 30, 2018 and December 31, 2017 and for the six months ended June 30, 2018 and 2017.

 	(b)	Pro forma financial information.	
 
The following pro forma financial information is being filed as an exhibit hereto and is incorporated by reference herein:
 
Exhibit 99.4 — Unaudited pro forma condensed combined financial statements and explanatory notes for the Company as of June 30, 2018, for the six months ended June 30, 2018 and for the year ended December 31, 2017.
 
 	(d)	Exhibits	
 
Exhibit No.	 	Description	
23.1	 	Consent of Deloitte & Touche LLP with respect to the Audited Financial Statements of Elizabethtown Gas as of December 31, 2017 and 2016 and for the two years ended December 31, 2017	
23.2	 	Consent of PricewaterhouseCoopers LLP with respect to the Audited Financial Statements of Elizabethtown Gas as of December 31, 2015 and for the year ended December 31, 2015.	
99.1*	 	Press release issued by South Jersey Industries, Inc. on July 2, 2018	
99.2	 	Audited Financial Statements of Elizabethtown Gas as of December 31, 2017 and 2016 and for the years then ended and as of December 31, 2016 and 2015 and for the years then ended.	
99.3	 	Unaudited Condensed Financial Statements of Elizabethtown Gas as of June 30, 2018 and December 31, 2017 and for the six months ended June 30, 2018 and 2017.	
99.4	 	Unaudited pro forma condensed combined financial statements and explanatory notes for South Jersey Industries, Inc. as of June 30, 2018, for the six months ended June 30, 2018 and for the year ended December 31, 2017	

* previously filed with the Original Form 8-k

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: September 12, 2018	SOUTH JERSEY INDUSTRIES, INC.	
 	 	
 	By:	/s/ Kenneth A. Lynch	
 	 	Name: Kenneth A. Lynch	
 	 	Title: Senior Vice President, Chief Risk and Accounting Officer
Principal Financial Officer	

Exhibit 23.1

CONSENT OF INDEPENDENT AUDITORS

We consent to the incorporation by reference in Registration Statements No. 333-207918 and 333-204553 on Form S-8 and Registration Statements No. 333-200543 and 333-211259 on Form S-3 of South Jersey Industries Inc. of our report dated March 13, 2018, relating to the financial statements of Elizabethtown Gas as of and for the years ended December 31, 2017 and 2016, appearing in this current report on Form 8-K of South Jersey Industries Inc.
 
/s/ Deloitte & Touche LLP
 
Atlanta, Georgia
September 12, 2018

Exhibit 23.2

CONSENT OF INDEPENDENT AUDITORS
 
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-207918 and 333-204553) and Registration Statements on Form S‑3 (Nos. 333-200543 and 333-211259) of South Jersey Industries, Inc. of our report dated February 11, 2016 relating to the financial statements of Elizabethtown Gas, which appears in this Current Report on Form 8‑K.

/s/ PricewaterhouseCoopers LLP
Atlanta, Georgia
September 12, 2018

Exhibit 99.2
 
Elizabethtown Gas
 
(A division of Pivotal Utility Holdings, Inc., a wholly-owned subsidiary
of Southern Company Gas)

Financial Statements as of December 31, 2017 and 2016
and for the Years Then Ended, and Independent Auditor’s Report

Index to the Notes to Financial Statements
 	 	Page	
 Independent Auditor’s Report	3	
 	 	 	
Financial Statements	 	
 	Statements of Income	4	
 	Statements of Comprehensive Income	5	
 	Statements of Cash Flows	6	
 	Balance Sheets	8	
 	Statements of Equity	9	
Notes to Financial Statements	 	
 	1.  Summary of Significant Accounting Policies	10	
 	2.  Retirement Benefits	16	
 	3.  Contingencies and Regulatory Matters	25	
 	4.  Income Taxes	26	
 	5.  Financing	28	
 	6.  Commitments	30	
 	7.  Fair Value Measurements	31	
 	8.  Derivatives	31	
 	9.  Disposition	34	
 	10. Affiliate Transactions	34	
 	11. Subsequent Events	34	

2

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Stockholder of
Elizabethtown Gas

We have audited the accompanying financial statements of Elizabethtown Gas (the “Company”), which comprise the balance sheets as of December 31, 2017 and 2016 and the related statements of income, comprehensive income, cash flows, and equity for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the 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 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 financial statements referred to above present fairly, in all material respects, the financial position of Elizabethtown Gas as of December 31, 2017 and 2016, 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.
 
/s/ Deloitte & Touche LLP
Atlanta, Georgia

March 13, 2018

3

STATEMENTS OF INCOME
Elizabethtown Gas
For the Years Ended December 31, 2017 and 2016
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Operating Revenues	 	$	304,747	 	 	$	292,699	 	
Operating Expenses:	 	 	 	 	 	 	 	 	
Cost of natural gas	 	 	135,850	 	 	 	132,122	 	
Other operations and maintenance	 	 	66,574	 	 	 	82,599	 	
Depreciation and amortization	 	 	27,163	 	 	 	25,439	 	
Taxes other than income taxes	 	 	4,917	 	 	 	2,572	 	
Total operating expenses	 	 	234,504	 	 	 	242,732	 	
Operating Income	 	 	70,243	 	 	 	49,967	 	
Other Income and (Expense):	 	 	 	 	 	 	 	 	
Interest expense, net of amounts capitalized	 	 	(15,960	)	 	 	(14,932	)	
Other income (expense), net	 	 	1,460	 	 	 	1,610	 	
Total other income and (expense)	 	 	(14,500	)	 	 	(13,322	)	
Earnings Before Income Taxes	 	 	55,743	 	 	 	36,645	 	
Income taxes	 	 	21,926	 	 	 	14,751	 	
Net Income	 	$	33,817	 	 	$	21,894	 	

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

4

STATEMENTS OF COMPREHENSIVE INCOME
Elizabethtown Gas
For the Years Ended December 31, 2017 and 2016
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Net Income	 	$	33,817	 	 	$	21,894	 	
Other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Pension and other postretirement benefit plans:	 	 	 	 	 	 	 	 	
Benefit plan net loss, net of tax of $- and $(6,314), respectively	 	 	—	 	 	 	(9,142	)	
Reclassification adjustment for amounts included in net income, net of tax of $- and $454, respectively	 	 	 	 	 	 	 	 	
Total Other Comprehensive Loss	 	 	—	 	 	 	(8,485	)	
Comprehensive Income	 	$	33,817	 	 	$	13,409	 	

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

5

STATEMENTS OF CASH FLOWS
Elizabethtown Gas
For the Years Ended December 31, 2017 and 2016
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Operating Activities:	 	 	 	 	 	 	
Net income	 	$	33,817	 	 	$	21,894	 	
Adjustments to reconcile net income to net cash provided from operating activities —	 	 	 	 	 	 	 	 	
Depreciation and amortization, total	 	 	27,163	 	 	 	25,439	 	
Deferred income taxes	 	 	33,355	 	 	 	7,819	 	
Pension, postretirement, and other employee benefits	 	 	1,448	 	 	 	(13,083	)	
Mark-to-market adjustments	 	 	10,391	 	 	 	(22,243	)	
Other, net	 	 	(18,083	)	 	 	(17,315	)	
Changes in certain current assets and liabilities —	 	 	 	 	 	 	 	 	
—Receivables	 	 	(21,798	)	 	 	(16,458	)	
—Inventories	 	 	(476	)	 	 	3,029	 	
—Other current assets	 	 	(161	)	 	 	3,672	 	
—Accrued taxes	 	 	(13,451	)	 	 	7,381	 	
—Accounts payable	 	 	27,765	 	 	 	2,611	 	
—Accrued compensation	 	 	1,604	 	 	 	(997	)	
—Other current liabilities	 	 	(31,572	)	 	 	21,099	 	
Net cash provided from operating activities	 	 	50,002	 	 	 	22,848	 	
Investing Activities:	 	 	 	 	 	 	 	 	
Property additions	 	 	(155,148	)	 	 	(117,221	)	
Cost of removal, net of salvage	 	 	(2,520	)	 	 	(6,612	)	
Change in construction payables, net	 	 	(2,584	)	 	 	5,542	 	
Other investing activities	 	 	243	 	 	 	—	 	
Net cash used for investing activities	 	 	(160,009	)	 	 	(118,291	)	
Financing Activities:	 	 	 	 	 	 	 	 	
Net borrowings from parent	 	 	100,878	 	 	 	51,698	 	
Dividends to parent	 	 	(25,229	)	 	 	(23,494	)	
Capital contributions from parent company	 	 	34,358	 	 	 	67,239	 	
Net cash provided from financing activities	 	 	110,007	 	 	 	95,443	 	
Net Change in Cash and Cash Equivalents	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at Beginning of Period	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at End of Period	 	$	—	 	 	$	—	 	
Supplemental Cash Flow Information:	 	 	 	 	 	 	 	 	
Cash paid during the period for —	 	 	 	 	 	 	 	 	
Interest, net of amounts capitalized	 	$	15,872	 	 	$	12,324	 	
Income taxes	 	 	1,062	 	 	 	3,216	 	
Noncash transactions — Accrued property additions at end of period	 	 	7,469	 	 	 	10,053	 	

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

6

BALANCE SHEETS
Elizabethtown Gas
At December 31, 2017 and 2016
Assets	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Receivables —	 	 	 	 	 	 	
Customer accounts receivable	 	$	29,078	 	 	$	22,979	 	
Unbilled revenues	 	 	35,209	 	 	 	24,948	 	
Other accounts and notes receivable	 	 	6,659	 	 	 	1,221	 	
Accumulated provision for uncollectible accounts	 	 	(4,904	)	 	 	(4,054	)	
Materials and supplies	 	 	307	 	 	 	304	 	
Natural gas for sale	 	 	20,913	 	 	 	20,437	 	
Prepaid taxes	 	 	21,544	 	 	 	3,682	 	
Assets from risk management activities, net of collateral	 	 	—	 	 	 	7,473	 	
Regulatory assets, current	 	 	7,922	 	 	 	10,186	 	
Other current assets	 	 	141	 	 	 	218	 	
Total current assets	 	 	116,869	 	 	 	87,394	 	
Property, Plant, and Equipment:	 	 	 	 	 	 	 	 	
In service	 	 	1,290,302	 	 	 	1,140,213	 	
Less: Accumulated depreciation	 	 	267,019	 	 	 	274,679	 	
Plant in service, net of depreciation	 	 	1,023,283	 	 	 	865,534	 	
Construction work in progress	 	 	32,052	 	 	 	54,994	 	
Total property, plant, and equipment	 	 	1,055,335	 	 	 	920,528	 	
Other Property and Investments:	 	 	 	 	 	 	 	 	
Goodwill	 	 	126,020	 	 	 	126,020	 	
Deferred Charges and Other Assets:	 	 	 	 	 	 	 	 	
Regulatory assets, deferred	 	 	131,590	 	 	 	114,680	 	
Other deferred charges and assets	 	 	40	 	 	 	919	 	
Total deferred charges and other assets	 	 	131,630	 	 	 	115,599	 	
Total Assets	 	$	1,429,854	 	 	$	1,249,541	 	

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

7

BALANCE SHEETS
Elizabethtown Gas
At December 31, 2017 and 2016
Liabilities and Stockholder’s Equity	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Current Liabilities:	 	 	 	 	 	 	
Due to affiliates	 	$	81,903	 	 	$	55,186	 	
Accounts payable	 	 	12,751	 	 	 	14,287	 	
Customer deposits	 	 	7,299	 	 	 	9,686	 	
Other accrued taxes	 	 	140	 	 	 	2,720	 	
Accrued compensation	 	 	3,445	 	 	 	1,781	 	
Liabilities from risk management activities, net of collateral	 	 	1,694	 	 	 	—	 	
Regulatory liabilities, current	 	 	10,197	 	 	 	16,276	 	
Accrued environmental remediation, current	 	 	9,700	 	 	 	29,000	 	
Other current liabilities	 	 	1,506	 	 	 	1,530	 	
Total current liabilities	 	 	128,635	 	 	 	130,466	 	
Long-term Debt (See notes)	 	 	447,825	 	 	 	346,879	 	
Deferred Credits and Other Liabilities:	 	 	 	 	 	 	 	 	
Accumulated deferred income taxes	 	 	130,889	 	 	 	210,826	 	
Deferred credits related to income tax	 	 	121,041	 	 	 	673	 	
Other cost of removal obligations	 	 	57,819	 	 	 	55,873	 	
Accrued environmental remediation, deferred	 	 	75,437	 	 	 	77,054	 	
Other regulatory liabilities, deferred	 	 	456	 	 	 	1,583	 	
Employee benefit obligations	 	 	18,909	 	 	 	20,700	 	
Other deferred credits and liabilities	 	 	1,438	 	 	 	1,028	 	
Total deferred credits and other liabilities	 	 	405,989	 	 	 	367,737	 	
Total Liabilities	 	 	982,449	 	 	 	845,082	 	
 	 	 	 	 	 	 	 	 	
Stockholder’s Equity	 	 	 	 	 	 	 	 	
Common stock, no par value; 12,807,111 shares authorized, issued, and outstanding	 	 	—	 	 	 	—	 	
Paid-in capital	 	 	166,377	 	 	 	132,019	 	
Retained earnings	 	 	281,028	 	 	 	272,440	 	
Total Stockholder’s Equity	 	 	447,405	 	 	 	404,459	 	
Total Liabilities and Stockholder’s Equity	 	$	1,429,854	 	 	$	1,249,541	 	
Commitments and Contingent Matters (See Notes)	 	 	 	 	 	 	 	 	

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

8

STATEMENTS OF EQUITY
Elizabethtown Gas
For the Years Ended December 31, 2017 and 2016
 	 	Paid-in Capital	 	 	Retained
Earnings	 	 	Accumulated Other
Comprehensive Loss	 	 	Total	 	
 	 	(in thousands)	 	
Balance at December 31, 2015	 	$	64,858	 	 	$	274,040	 	 	$	(19,961	)	 	$	318,937	 	
Net income	 	 	—	 	 	 	21,894	 	 	 	—	 	 	 	21,894	 	
Other comprehensive loss	 	 	—	 	 	 	—	 	 	 	(8,485	)	 	 	(8,485	)	
Reclassification of accumulated other comprehensive loss to regulatory assets	 	 	—	 	 	 	—	 	 	 	28,446	 	 	 	28,446	 	
Dividends to parent	 	 	—	 	 	 	(23,494	)	 	 	—	 	 	 	(23,494	)	
Capital contributions from parent company	 	 	67,161	 	 	 	—	 	 	 	—	 	 	 	67,161	 	
Balance at December 31, 2016	 	$	132,019	 	 	$	272,440	 	 	$	—	 	 	$	404,459	 	
Net income	 	 	—	 	 	 	33,817	 	 	 	—	 	 	 	33,817	 	
Dividends to parent	 	 	—	 	 	 	(25,229	)	 	 	—	 	 	 	(25,229	)	
Capital contributions from parent company	 	 	34,358	 	 	 	—	 	 	 	—	 	 	 	34,358	 	
Balance at December 31, 2017	 	$	166,377	 	 	$	281,028	 	 	$	—	 	 	$	447,405	 	

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

9

Elizabethtown Gas
Notes to Financial Statements
December 31, 2017 and 2016

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Elizabethtown Gas (the Company) engages in the sale and distribution of natural gas to approximately 292 thousand customers in New Jersey. Elizabethtown Gas is a division of Pivotal Utility Holdings, Inc. (Pivotal Utility), which is a wholly-owned subsidiary of Southern Company Gas. On July 1, 2016, Southern Company Gas completed its previously announced merger (Merger) with The Southern Company (Southern Company) and became a wholly-owned, direct subsidiary of Southern Company.

The Company is subject to regulation by the New Jersey Board of Public Utilities (New Jersey BPU). As such, the Company’s financial statements reflect the effects of rate regulation in accordance with accounting principles generally accepted in the United States of America (GAAP) and comply with the accounting policies and practices prescribed by the New Jersey BPU. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

The impact of the acquisition method of accounting was not pushed down to Elizabethtown Gas and is not reflected in the financial statements included herein.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation used by Southern Company Gas.

Recently Issued Accounting Standards

Revenue

In 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers  (ASC 606), replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the new standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. The new standard also requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

Most of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term.

The Company has completed the evaluation of all revenue streams and determined that the adoption of ASC 606 will not change the current timing of revenue recognition for such transactions. Some revenue arrangements, such as alternative revenue programs, are excluded from the scope of ASC 606 and, therefore, will be accounted for and disclosed or presented separately from revenues under ASC 606 on the Company’s financial statements. The Company has concluded contributions in aid of construction are not in scope for ASC 606 and will continue to be accounted for as an offset to property, plant, and equipment.

The new standard is effective for reporting periods beginning after December 15, 2017. The Company applied the modified retrospective method of adoption effective January 1, 2018. The Company also utilized practical expedients which allowed it to apply the standard to open contracts at the date of adoption and to reflect the aggregate effect of all modifications when identifying performance obligations and allocating the transaction price for contracts modified before the effective date. Under the modified retrospective method of adoption, prior year reported results are not restated; however, a cumulative-effect adjustment to retained earnings at January 1, 2018 is recorded. The adoption of ASC 606 did not result in a cumulative-effect adjustment.

Leases

In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and the Company will adopt the new standard effective January 1, 2019.

10

The Company is currently implementing an information technology system along with the related changes to internal controls and accounting policies that will support the accounting for leases under ASU 2016-02. In addition, the Company has substantially completed a detailed inventory and analysis of its leases. In terms of rental charges and duration of contracts, the most significant leases relate to fleet vehicles and real estate and where the Company is the lessee and there are no material leases where the Company is the lessor. While the Company has not yet determined the ultimate impact, adoption of ASU 2016-02 is not expected to have a significant impact on the Company’s balance sheet.

Other

On January 26, 2017, the FASB issued ASU No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment  (ASU 2017-04). ASU 2017-04 removes the requirement to compare the implied fair value of goodwill with the carrying amount as part of Step 2 of the goodwill impairment test. Under the new standard, the goodwill impairment loss will be measured as the excess of a reporting unit’s carrying amount over its fair value, not exceeding the total amount of goodwill allocated to that reporting unit, which may increase the frequency of goodwill impairment charges if a future goodwill impairment test does not pass the Step 1 evaluation. ASU 2017-04 is effective prospectively for periods beginning on or after December 15, 2019, with early adoption permitted. The Company adopted ASU 2017-04 effective January 1, 2018 with no impact on its financial statements.

On March 10, 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost  (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under Federal Energy Regulatory Commission (FERC) regulations. ASU 2017-07 will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and postretirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and postretirement benefit costs in assets will be applied on a prospective basis. ASU 2017-07 is effective for periods beginning after December 15, 2017. The presentation changes required for net periodic pension and postretirement benefit costs will not result in a material impact on the Company’s operating income or other income for 2016 and 2017. The Company adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements.

On August 28, 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities  (ASU 2017-12), amending the hedge accounting recognition and presentation requirements. ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements.

Regulatory Assets and Liabilities

The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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Regulatory assets and (liabilities) reflected in the balance sheets at December 31 relate to:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Environmental remediation	 	$	87,792	 	 	$	72,482	 	
Retiree benefit plans	 	 	32,188	 	 	 	35,283	 	
Under recovered regulatory clause revenues	 	 	12,426	 	 	 	10,186	 	
Other regulatory assets	 	 	7,106	 	 	 	6,915	 	
Deferred credits related to income tax(*)	 	 	(121,041	)	 	 	(673	)	
Other cost of removal obligations	 	 	(57,819	)	 	 	(55,873	)	
Over recovered regulatory clause revenues	 	 	(10,223	)	 	 	(7,425	)	
Other regulatory liabilities	 	 	(430	)	 	 	(10,434	)	
Total regulatory assets (liabilities), net	 	$	(50,001	)	 	$	50,461	 	

(*)   Includes excess deferred income tax assets/liabilities resulting from the Tax Cuts and Jobs Act that was signed into law on December 22, 2017 and became effective January 1, 2018 (Tax Reform Legislation), the recovery and amortization of which will be determined by the New Jersey BPU. See Note 3 under “Regulatory Matters” and Note 4 for additional details.

In the event that the Company’s operations are no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Regulatory Matters” for additional information.

Revenues

The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the New Jersey BPU. The Company has a rate structure that includes a volumetric rate design that allows the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of natural gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries to the end of the period.

The tariffs for the Company include weather normalization adjustments, which reduce customer bills when winter weather is colder than normal and increase customer bills when weather is warmer than normal and are included in the tariffs. These provisions, referred to as alternative revenue programs, allow for the recognition of certain revenues prior to the time such revenues are billed to customers, so long as the amounts recognized will be collected from customers within 24 months of recognition.

Concentration of Revenue

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 2% of revenues.

Cost of Natural Gas

The Company charges its customers for natural gas consumed using a natural gas cost recovery mechanism set by the New Jersey BPU, under which all prudently-incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively.

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Income and Other Taxes

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal investment tax credits (ITCs) utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheet.

The Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 4 under “Unrecognized Tax Benefits” for additional information.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

The Company’s property, plant, and equipment in service consisted of the following at December 31:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Utility plant in service	 	$	1,170,020	 	 	$	1,056,686	 	
Information technology equipment and software	 	 	46,885	 	 	 	37,124	 	
Storage facilities	 	 	27,888	 	 	 	7,193	 	
Other	 	 	45,509	 	 	 	39,210	 	
Total other plant in service	 	 	120,282	 	 	 	83,527	 	
Total plant in service	 	$	1,290,302	 	 	$	1,140,213	 	

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed.

Depreciation

Depreciation of the original cost of utility plant in service is provided using composite straight-line rates, which approximated 2.6% and 2.3% in 2017 and 2016, respectively. Depreciation studies are conducted periodically to update the composite rate that is approved by the New Jersey BPU. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. As such, gains or losses are not recognized, they are ultimately refunded to, or recovered from, customers through future rate adjustments. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.

Allowance for Funds Used During Construction (AFUDC)

The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. All current construction costs are included in rates. The Company’s AFUDC composite rate was 1.56% and 1.68% for the years ended 2017 and 2016, respectively. The Company recorded $0.4 million and $0.3 million of AFUDC for the years ended December 31, 2017 and 2016, respectively.

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any.

For the 2017 annual impairment test, the Company performed Step 1 of the two-step impairment test, which resulted in its fair value exceeding its carrying value. For the 2016 annual impairment test, the Company performed the qualitative Step 0 assessment and determined that it was more likely than not that its fair value exceeded its carrying value and therefore no quantitative assessment was required.

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Cash Management Money Pool

The Company participates in Southern Company Gas’ utility money pool, under which short-term borrowings are made from the money pool and surplus funds are contributed to the money pool. Borrowings from the money pool are recorded as due to affiliates in the balance sheets and intercompany interest expense is recorded in the statements of income for these borrowings. See Note 10 for additional information.

Receivables and Provision for Uncollectible Accounts

The Company’s receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, a provision for uncollectible accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer’s inability to pay, a provision for uncollectible accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers’ accounts are written off once they are deemed to be uncollectible.

Materials and Supplies

Generally, materials and supplies include propane gas inventory, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Natural Gas for Sale

The Company’s natural gas inventories are carried at cost on a weighted average cost of gas basis.

Fair Value Measurements

The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include derivative instruments. The carrying values of receivables, accounts payable, due to affiliates, other current assets and liabilities, accrued interest, and long-term debt approximate their respective fair value. The nonfinancial assets and liabilities include pension and other postretirement benefits. See Notes 2 and 7 for additional fair value disclosures.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1

Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets.

14

Level 2

Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include non-exchange-traded derivatives such as over-the-counter forwards and options and certain retirement plan assets.

Level 3

Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company’s pension and other postretirement benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as “Risk Management Activities”) and are measured at fair value. See Note 7 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in other comprehensive income (OCI) or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Cash flows from derivatives are classified on the statement of cash flows in the same category as the hedged item. See Note 8 for additional information regarding derivatives.

The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2017.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. In 2017, comprehensive income was equal to net income. In 2016, comprehensive income consisted of net income, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Dividend Distributions

The Company paid dividends of $25.2 million and $23.5 million to Southern Company Gas during 2017 and 2016, respectively. The Company is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to Southern Company Gas to the extent of 70% of its quarterly net income.

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2. RETIREMENT BENEFITS

The Company participates in the Southern Company Gas qualified defined benefit, trusteed, pension plan covering most eligible employees, which was closed in 2012 to new employees and reopened to all non-union employees on January 1, 2018. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended (ERISA). Southern Company Gas also provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of the Company’s management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. The Company also participates in the Southern Company Gas postretirement benefit plan, which provides certain medical care and life insurance benefits for eligible retired employees through a postretirement benefit plan.

In connection with the Merger, Southern Company Gas performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. The Company also recorded a related regulatory asset of $47.5 million as of July 1, 2016 related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates for the Company.

The following discussions reflect the Company’s balances and activity under the multiple-employer method of accounting.

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for all periods presented and the benefit obligations as of the measurement date are presented below.
Assumptions used to determine net periodic costs:	 	Year Ended
December 31, 2017	 	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016
through June 30, 2016	 	
Pension plans	 	 	 	 	 	 	 	 	 	
Discount rate - interest costs	 	 	3.76	%	 	 	3.21	%	 	 	4.00	%	
Discount rate - service costs	 	 	4.64	 	 	 	4.07	 	 	 	4.80	 	
Expected long-term return on plan assets	 	 	7.60	 	 	 	7.75	 	 	 	7.80	 	
Annual salary increase	 	 	3.50	 	 	 	3.50	 	 	 	3.70	 	
Other postretirement benefit plans	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate - interest costs	 	 	3.40	%	 	 	2.84	%	 	 	3.60	%	
Discount rate - service costs	 	 	4.55	 	 	 	3.96	 	 	 	4.70	 	
Expected long-term return on plan assets	 	 	6.03	 	 	 	5.93	 	 	 	6.60	 	
Annual salary increase	 	 	3.50	 	 	 	3.50	 	 	 	3.70	 	

Assumptions used to determine benefit obligations:	 	December 31, 2017	 	 	December 31, 2016	 	
Pension plans	 	 	 	 	 	 	
Discount rate	 	 	3.74	%	 	 	4.39	%	
Annual salary increase	 	 	2.88	 	 	 	3.50	 	
Other postretirement benefit plans	 	 	 	 	 	 	 	 	
Discount rate	 	 	3.62	%	 	 	4.15	%	
Annual salary increase	 	 	2.56	 	 	 	3.50	 	

The Company estimates the expected return on pension plan and other postretirement benefit plan assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year’s annual pension or other postretirement benefit plan cost; rather, this gain or loss reduces or increases future pension or other postretirement benefit plan costs.
16

An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2017 were as follows:
 	 	Initial Cost Trend
Rate	 	 	Ultimate Cost
Trend Rate	 	 	Year That
Ultimate Rate is
Reached	 	
Pre-65	 	 	6.40	%	 	 	4.50	%	 	 	2038	 	
Post-65 medical	 	 	7.80	 	 	 	4.50	 	 	 	2038	 	
Post-65 prescription	 	 	7.80	 	 	 	4.50	 	 	 	2038	 	

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO; however, the impact on the service and interest cost components would be immaterial.

Pension Plans

The total accumulated benefit obligation for the pension plans was $95.4 million at December 31, 2017 and $85.7 million at December 31, 2016. Changes in the projected benefit obligations and the fair value of plan assets for the Company’s qualified pension plans for all periods presented were as follows:
 	 	Year Ended
December 31, 2017	 	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016
through June 30, 2016	 	
 	 	(in thousands)	 	 	 	 	 	 	 	
Change in benefit obligation	 	 	 	 	 	 	 	 	 	
Benefit obligation at beginning of period	 	$	94,963	 	 	$	105,458	 	 	$	90,910	 	
Service cost	 	 	1,393	 	 	 	990	 	 	 	861	 	
Interest cost	 	 	4,383	 	 	 	2,044	 	 	 	2,238	 	
Benefits paid	 	 	(10,407	)	 	 	(3,592	)	 	 	(3,338	)	
Actuarial (gain) loss	 	 	15,175	 	 	 	(9,937	)	 	 	14,787	 	
Balance at end of period	 	 	105,507	 	 	 	94,963	 	 	 	105,458	 	
Change in plan assets	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of period	 	 	74,849	 	 	 	60,687	 	 	 	61,044	 	
Actual return on plan assets	 	 	20,986	 	 	 	3,706	 	 	 	2,981	 	
Employer contributions	 	 	—	 	 	 	14,048	 	 	 	—	 	
Benefits paid	 	 	(10,407	)	 	 	(3,592	)	 	 	(3,338	)	
Fair value of plan assets at end of period	 	 	85,428	 	 	 	74,849	 	 	 	60,687	 	
Accrued liability	 	$	20,079	 	 	$	20,114	 	 	$	44,771	 	

At December 31, 2017, the projected benefit obligations for the qualified and non-qualified pension plans were $105.5 million and $1.1 million, respectively. All pension plan assets are related to the qualified pension plan.

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company’s pension plans consist of the following:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Other regulatory assets, deferred	 	$	28,176	 	 	$	30,484	 	
Employee benefit obligations	 	 	(20,079	)	 	 	(20,114	)	

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Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2018.
 	 	Amount Subject to
Regulatory Amortization	 	 	Prior Service
Costs	 	 	Net (Gain)
Loss	 	
 	 	(in thousands)	 	
Balance at December 31, 2017:	 	 	 	 	 	 	 	 	 	
Regulatory assets (liabilities)	 	$	38,584	 	 	$	(89	)	 	$	(10,319	)	
Balance at December 31, 2016:	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory assets (liabilities)	 	$	—	 	 	$	(2,000	)	 	$	32,484	 	
Estimated amortization in net periodic cost in 2018:	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory assets	 	$	2,691	 	 	$	10	 	 	$	—	 	

The components of OCI, and the changes in the balance of regulatory assets (liabilities), related to the defined benefit pension plans for all years presented were as follows:
 	 	Accumulated OCI	 	 	Regulatory Assets	 	
 	 	(in thousands)	 	
Balance at December 31, 2015:	 	$	27,789	 	 	$	—	 	
Net (gain) loss	 	 	15,216	 	 	 	(9,816	)	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	434	 	 	 	434	 	
Amortization of net loss	 	 	(1,396	)	 	 	(2,177	)	
Reclassification from accumulated OCI to regulatory assets	 	 	(42,043	)	 	 	42,043	 	
Total reclassification adjustments	 	 	(43,005	)	 	 	40,300	 	
Total change	 	 	(27,789	)	 	 	30,484	 	
Balance at December 31, 2016:	 	$	—	 	 	$	30,484	 	
Net (gain) loss	 	 	—	 	 	 	(149	)	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	—	 	 	 	424	 	
Amortization of net loss	 	 	—	 	 	 	(1,427	)	
Amortization of regulatory assets	 	 	—	 	 	 	(1,156	)	
Total reclassification adjustments	 	 	—	 	 	 	(2,159	)	
Total change	 	 	—	 	 	 	(2,308	)	
Balance at December 31, 2017:	 	$	—	 	 	$	28,176	 	

The Company’s pro rata components of Southern Company Gas’ net periodic pension costs for the years ended December 31, 2017 and 2016 were as follows:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Service cost	 	$	1,393	 	 	$	1,851	 	
Interest cost	 	 	4,383	 	 	 	4,282	 	
Expected return on plan assets	 	 	(6,534	)	 	 	(6,249	)	
Amortization of regulatory assets	 	 	1,156	 	 	 	—	 	
Amortization:	 	 	 	 	 	 	 	 	
Prior service costs	 	 	(424	)	 	 	(868	)	
Net loss	 	 	1,427	 	 	 	3,573	 	
Net periodic pension cost	 	$	1,401	 	 	$	2,589	 	

18

Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets.

Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2017, estimated benefit payments were as follows:
 	 	Benefit Payments	 	
 	 	(in thousands)	 	
2018	 	$	7,244	 	
2019	 	 	7,006	 	
2020	 	 	7,382	 	
2021	 	 	7,041	 	
2022	 	 	6,890	 	
2023 to 2027	 	 	32,623	 	

Other Postretirement Benefits

Changes in the APBO and the fair value of plan assets for all periods presented were as follows:
 	 	Year Ended
December 31, 2017	 	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016
through June 30, 2016	 	
 	 	(in thousands)	 	
Change in benefit obligation	 	 	 	 	 	 	 	 	 	
Benefit obligation at beginning of period	 	$	12,317	 	 	$	13,174	 	 	$	13,512	 	
Service cost	 	 	100	 	 	 	55	 	 	 	47	 	
Interest cost	 	 	416	 	 	 	187	 	 	 	218	 	
Benefits paid	 	 	(843	)	 	 	(293	)	 	 	(438	)	
Actuarial (gain) loss	 	 	1,424	 	 	 	(806	)	 	 	(165	)	
Benefit obligation at end of period	 	 	13,414	 	 	 	12,317	 	 	 	13,174	 	
Change in plan assets	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of period	 	 	13,177	 	 	 	12,829	 	 	 	12,737	 	
Actual return on plan assets	 	 	2,489	 	 	 	348	 	 	 	92	 	
Employer contributions	 	 	843	 	 	 	293	 	 	 	438	 	
Benefits paid	 	 	(843	)	 	 	(293	)	 	 	(438	)	
Fair value of plan assets at end of period	 	 	15,666	 	 	 	13,177	 	 	 	12,829	 	
(Prepaid asset) accrued liability	 	$	(2,252	)	 	$	(860	)	 	$	345	 	

Amounts recognized in the balance sheets at December 31, 2017 and 2016 related to the Company’s other postretirement benefit plans consist of the following:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Other regulatory assets, deferred	 	$	4,012	 	 	$	4,361	 	
Employee benefit obligations	 	 	2,252	 	 	 	860	 	

19

Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2017 and 2016 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2018 is immaterial.
 	 	Amount Subject to
Regulatory Amortization	 	 	Prior Service Costs	 	 	Net (Gain) Loss	 	
 	 	(in thousands) 	 	
Balance at December 31, 2017:	 	 	 	 	 	 	 	 	 	
Regulatory assets (liabilities)	 	$	5,285	 	 	$	395	 	 	$	(1,668	)	
Balance at December 31, 2016:	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory assets	 	$	—	 	 	$	—	 	 	$	4,361	 	

The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for all years presented were as follows:
 	 	Accumulated OCI	 	 	Regulatory Assets	 	
 	 	(in thousands)	 	
Balance at December 31, 2015:	 	$	5,548	 	 	$	—	 	
Net (gain) loss	 	 	90	 	 	 	(933	)	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	(1	)	 	 	(1	)	
Amortization of net loss	 	 	(137	)	 	 	(205	)	
Reclassification from accumulated OCI to regulatory assets	 	 	(5,500	)	 	 	5,500	 	
Total reclassification adjustments	 	 	(5,638	)	 	 	5,294	 	
Total change	 	 	(5,548	)	 	 	4,361	 	
Balance at December 31, 2016:	 	$	—	 	 	$	4,361	 	
Net (gain) loss	 	 	—	 	 	 	53	 	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of net loss	 	 	—	 	 	 	(149	)	
Amortization of regulatory assets	 	 	—	 	 	 	(253	)	
Total reclassification adjustments	 	 	—	 	 	 	(402	)	
Total change	 	 	—	 	 	 	(349	)	
Balance at December 31, 2017:	 	$	—	 	 	$	4,012	 	

The Company’s pro rata components of Southern Company Gas’ other postretirement benefit plans’ net periodic cost for the years ended December 31, 2017 and 2016 were as follows:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Service cost	 	$	100	 	 	$	102	 	
Interest cost	 	 	416	 	 	 	405	 	
Expected return on plan assets	 	 	(655	)	 	 	(673	)	
Amortization of regulatory assets	 	 	253	 	 	 	—	 	
Amortization:	 	 	 	 	 	 	 	 	
Prior service costs	 	 	—	 	 	 	2	 	
Net loss	 	 	149	 	 	 	342	 	
Net periodic pension cost	 	$	263	 	 	$	178	 	

20

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. At December 31, 2017, estimated benefit payments were as follows:
 	 	Benefit Payments	 	
 	 	(in thousands)	 	
2018	 	$	748	 	
2019	 	 	797	 	
2020	 	 	829	 	
2021	 	 	864	 	
2022	 	 	890	 	
2023 to 2027	 	 	4,295	 	

Benefit Plan Assets

Southern Company Gas’ pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Southern Company Gas minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

The composition of Southern Company Gas’ pension plan and other postretirement benefit plan assets as of December 31, 2017 and 2016, along with the targets for each plan, is presented below:
 	 	Target	 	 	2017	 	 	2016	 	
Pension plan assets:	 	 	 	 	 	 	 	 	 	
Equity	 	 	53	%	 	 	65	%	 	 	69	%	
Fixed Income	 	 	15	 	 	 	19	 	 	 	20	 	
Cash	 	 	2	 	 	 	6	 	 	 	1	 	
Other	 	 	30	 	 	 	10	 	 	 	10	 	
Total	 	 	100	%	 	 	100	%	 	 	100	%	
Other postretirement benefit plan assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Equity	 	 	72	%	 	 	76	%	 	 	74	%	
Fixed Income	 	 	24	 	 	 	20	 	 	 	23	 	
Cash	 	 	1	 	 	 	2	 	 	 	1	 	
Other	 	 	3	 	 	 	2	 	 	 	2	 	
Total	 	 	100	%	 	 	100	%	 	 	100	%	

The investment strategy for plan assets related to Southern Company Gas’ qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, Southern Company Gas employs a formal rebalancing program for its pension plan assets. To manage the actual asset class exposures relative to the target asset allocation, Southern Company Gas employs a formal rebalancing program for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices. Management believes the portfolio is well-diversified with no significant concentrations of risk.

21

Investment Strategies

Detailed below is a description of the investment strategies for each major asset category for the Southern Company Gas pension and other postretirement benefit plans disclosed above:

 	•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.	

 	•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.	

 	•	Fixed income. A mix of domestic and international bonds.	

 	•	Special situations.Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.	

 	•	Real estate investments. Investments in traditional private market equity-oriented investments in real properties (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.	

 	•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.	

The investment strategies prior to July 1, 2016 followed a policy to preserve the plans’ capital and maximize investment earnings in excess of inflation within acceptable levels of capital market volatility. To accomplish this goal, the plans’ assets were managed to optimize long-term return while maintaining a high standard of portfolio quality and diversification. In developing the allocation policy for the assets of the pension and other postretirement benefit plans, Southern Company Gas examined projections of asset returns and volatility over a long-term horizon. In connection with this analysis, the risk and return trade-offs of alternative asset classes and asset mixes were evaluated given long-term historical relationships as well as prospective capital market returns. Southern Company Gas also conducted asset-liability studies to match projected asset growth with projected liability growth to determine whether there is sufficient liquidity for projected benefit payments. Asset mix guidelines were developed by incorporating the results of these analyses with an assessment of Southern Company Gas’ risk posture, and taking into account industry practices. Southern Company Gas periodically evaluated its investment strategy to ensure that plan assets were sufficient to meet the benefit obligations of the plans. As part of the ongoing evaluation, the Company made changes to its targeted asset allocations and investment strategy.

Benefit Plan Asset Fair Values

Following are the fair value measurements for the pension plan and the other postretirement benefit plan assets as of December 31, 2017 and 2016. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan and other postretirement benefit plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate. Management believes the portfolio is well-diversified with no significant concentrations of risk.

Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:

 	•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.	

 	•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.	

 	•	Real estate investments and private equity. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.	

22

The Company’s pro rata portion of fair values of pension plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Absolute return investment assets are presented in the tables below based on the nature of the investment.
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active Markets
for Identical
Assets	 	 	Significant Other
Observable
Inputs	 	 	Net Asset Value
as a Practical
Expedient	 	 	 	 	
As of December 31, 2017	 	(Level 1)	 	 	(Level 2)	 	 	(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	13,978	 	 	$	29,196	 	 	$	—	 	 	$	43,174	 	
International equity(*)	 	 	—	 	 	 	14,988	 	 	 	—	 	 	 	14,988	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	7,710	 	 	 	—	 	 	 	7,710	 	
Corporate bonds	 	 	—	 	 	 	3,554	 	 	 	—	 	 	 	3,554	 	
Cash equivalents and other	 	 	7,574	 	 	 	2,251	 	 	 	4,379	 	 	 	14,204	 	
Real estate investments	 	 	288	 	 	 	—	 	 	 	1,399	 	 	 	1,687	 	
Private equity	 	 	—	 	 	 	—	 	 	 	111	 	 	 	111	 	
Total	 	$	21,840	 	 	$	57,699	 	 	$	5,889	 	 	$	85,428	 	

 	(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.	

 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active Markets
for Identical
Assets	 	 	Significant Other
Observable
Inputs	 	 	Net Asset Value
as a Practical
Expedient	 	 	 	 	
As of December 31, 2016	 	(Level 1)	 	 	(Level 2)	 	 	(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	10,800	 	 	$	26,103	 	 	$	—	 	 	$	36,903	 	
International equity(*)	 	 	—	 	 	 	14,117	 	 	 	—	 	 	 	14,117	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	6,482	 	 	 	—	 	 	 	6,482	 	
Corporate bonds	 	 	—	 	 	 	3,099	 	 	 	—	 	 	 	3,099	 	
Pooled funds	 	 	—	 	 	 	5,039	 	 	 	—	 	 	 	5,039	 	
Cash equivalents and other	 	 	931	 	 	 	375	 	 	 	6,328	 	 	 	7,634	 	
Real estate investments	 	 	275	 	 	 	—	 	 	 	1,110	 	 	 	1,385	 	
Private equity	 	 	—	 	 	 	—	 	 	 	190	 	 	 	190	 	
Total	 	$	12,006	 	 	$	55,215	 	 	$	7,628	 	 	$	74,849	 	

 	(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.	

23

The Company’s pro rata portion of fair values of other postretirement benefit plan assets as of December 31, 2017 and 2016 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases.
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active Markets
for Identical
Assets	 	 	Significant Other
Observable
Inputs	 	 	Net Asset Value
as a Practical
Expedient	 	 	 	 	
As of December 31, 2017	 	(Level 1)	 	 	(Level 2)	 	 	(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	370	 	 	$	8,811	 	 	$	—	 	 	$	9,181	 	
International equity(*)	 	 	—	 	 	 	2,858	 	 	 	—	 	 	 	2,858	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	70	 	 	 	—	 	 	 	70	 	
Corporate bonds	 	 	—	 	 	 	29	 	 	 	—	 	 	 	29	 	
Pooled funds	 	 	—	 	 	 	3,053	 	 	 	—	 	 	 	3,053	 	
Cash equivalents and other	 	 	289	 	 	 	—	 	 	 	133	 	 	 	422	 	
Real estate investments	 	 	8	 	 	 	—	 	 	 	42	 	 	 	50	 	
Private equity	 	 	—	 	 	 	—	 	 	 	3	 	 	 	3	 	
Total	 	$	667	 	 	$	14,821	 	 	$	178	 	 	$	15,666	 	

(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.	

 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active Markets
for Identical
Assets	 	 	Significant Other
Observable
Inputs	 	 	Net Asset Value
as a Practical
Expedient	 	 	 	 	
As of December 31, 2016	 	(Level 1)	 	 	(Level 2)	 	 	(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	315	 	 	$	7,264	 	 	$	—	 	 	$	7,579	 	
International equity(*)	 	 	—	 	 	 	2,206	 	 	 	—	 	 	 	2,206	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	63	 	 	 	—	 	 	 	63	 	
Corporate bonds	 	 	—	 	 	 	28	 	 	 	—	 	 	 	28	 	
Pooled funds	 	 	—	 	 	 	2,942	 	 	 	—	 	 	 	2,942	 	
Cash equivalents and other	 	 	99	 	 	 	—	 	 	 	209	 	 	 	308	 	
Real estate investments	 	 	8	 	 	 	—	 	 	 	37	 	 	 	45	 	
Private equity	 	 	—	 	 	 	—	 	 	 	6	 	 	 	6	 	
Total	 	$	422	 	 	$	12,503	 	 	$	252	 	 	$	13,177	 	

 	(*)	Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds.	

24

Employee Savings Plan

Southern Company Services, Inc. sponsors 401(k) defined contribution plans covering certain eligible employees. Through December 31, 2017, the 401(k) plans provided matching contributions of either 65% on up to 8% of an employee’s eligible compensation, or a 100% matching contribution on up to 3% of an employee’s eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee’s eligible compensation. Total matching contributions made to the 401(k) plans for each of the years ended December 31, 2017 and 2016 were $1.2 million.

For employees not accruing a benefit under the pension plan, additional contributions made to the 401(k) plans for the years ended December 31, 2017 and 2016 were immaterial.

Effective January 1, 2018, the 401(k) plans were merged into the Southern Company Employee Savings Plan, which is a defined contribution plan covering substantially all employees of the Company. Under this plan, Southern Company Gas matches a portion of the first 6% of employee base salary contributions. The maximum Company match is 5.1% of an employee’s base salary.

3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is assessing its alleged involvement in an incident that occurred in its service territory that resulted in several deaths, injuries, and property damage. The Company has been named as one of the defendants in several lawsuits related to this incident. At December 31, 2017, the Company has reserved for all of its potential exposure from this case. The ultimate outcome of this matter cannot be determined at this time.

The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be determined at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company’s financial statements.

Environmental Matters

The Company’s operations are regulated by state and federal environmental agencies through a variety of laws and regulations governing air, water, land, and protection of other natural resources. The Company maintains a comprehensive environmental compliance strategy to assess upcoming requirements and compliance costs associated with these environmental laws and regulations. The costs, including capital expenditures and operations and maintenance costs, required to comply with environmental laws and regulations impact future results of operations, cash flows, and financial condition. Compliance costs may result from the installation of additional environmental controls. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites. The Company has received authority from the New Jersey BPU to recover approved environmental compliance costs through regulatory mechanisms.

The Company is subject to environmental remediation liabilities associated with six former manufactured gas plant sites in New Jersey. Accrued environmental remediation costs of $85.1 million and $106.1 million have been recorded in the balance sheets as of December 31, 2017 and December 31, 2016, respectively. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the New Jersey BPU.

The Company’s ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.

Regulatory Matters

The Merger was approved by the New Jersey BPU on June 29, 2016. In connection with the Merger approval order, the Company was required to:

 	•	provide rate credits of $17.5 million to its customers; and	

 	•	file a rate case no later than September 1, 2016, with another rate case no later than three years after the 2016 rate case.	
25

The rate credits to customers were paid during the third quarter of 2016 and the Company filed a general base rate case with the New Jersey BPU on September 1, 2016. See “Customer Refunds” and “Base Rate Case” herein for additional information.

Regulatory Infrastructure Program

The Company’s 2013 extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program allowed for infrastructure investment of $115 million over four years and was focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital of 6.65%. Effective July 1, 2017, investments under this program, which ended September 30, 2017, are being recovered through base rate revenues. See “Base Rate Case” herein for additional information.

In 2015, the Company filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. During the first quarter 2018, the Company withdrew this filing in response to a proposed rule by the New Jersey BPU to incentivize utilities to accelerate investment in infrastructure replacement programs that enhance reliability, resiliency, and/or safety of the distribution system. The ultimate outcome of this matter cannot be determined at this time.

Base Rate Case

On June 30, 2017, the New Jersey BPU approved a settlement that provides for a $13 million increase in annual base rate revenues, effective July 1, 2017, based on a ROE of 9.6%. Also included in the settlement was a new composite depreciation rate that is expected to result in a $3 million annual reduction of depreciation. See Note 9 for information on the proposed sale of the Company.

Other

The New Jersey BPU issued an order effective January 1, 2018 that requires the Company to track as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. The Company made the required filing on March 2, 2018 seeking to reduce annual rates by $10.9 million with an April 1, 2018 interim effective date and final rates that are anticipated to take effect July 1, 2018. Credits will be issued to customers for the impact of the Tax Reform Legislation from January 2018 through March 2018.

Unrecognized Ratemaking Amounts

The following table illustrates the Company’s authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with the Company’s AIR program. These amounts will be recognized as revenues in the Company’s financial statements in the periods they are billable to customers. See Note 9 for information on the proposed sale of the Company.
 	 	(in thousands)	 	
December 31, 2017	 	$	7,229	 	
December 31, 2016	 	 	5,535	 	

Customer Refunds

In the third quarter 2016, the Company provided direct per-customer rate credits totaling $17.5 million to its customers in accordance with the Merger approval from the New Jersey BPU. These rate credits were allocated among the Company’s customer classes based on the base rate revenues reflected in the rates that resulted from its most recent base rate proceeding.

4. INCOME TAXES

Subsequent to the Merger, Southern Company files a consolidated federal income tax return and various combined and separate state income tax returns on behalf of the Company and Southern Company Gas. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with Internal Revenue Service (IRS) regulations, the Company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company was a part of Southern Company Gas’ U.S. federal consolidated income tax return and various state income tax returns.

26

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the Securities and Exchange Commission staff issued Staff Accounting Bulletin 118 - “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, the Company considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be “provisional” as discussed in SAB 118 and subject to revision. The Company is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time.

Current and Deferred Income Taxes

Details of income tax provisions are as follows:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Federal —	 	 	 	 	 	 	
Current	 	$	(10,363	)	 	$	5,630	 	
Deferred	 	 	29,339	 	 	 	6,661	 	
 	 	 	18,976	 	 	 	12,291	 	
State —	 	 	 	 	 	 	 	 	
Current	 	 	(1,066	)	 	 	1,302	 	
Deferred	 	 	4,102	 	 	 	1,277	 	
 	 	 	3,036	 	 	 	2,579	 	
Amortization of investment tax credits	 	 	(86	)	 	 	(119	)	
Total	 	$	21,926	 	 	$	14,751	 	

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
 	 	2017	 	 	2016	 	
 	 	(in thousands)	 	
Deferred tax liabilities —	 	 	 	 	 	 	
Accelerated depreciation	 	$	163,965	 	 	$	208,605	 	
Property basis differences	 	 	16,961	 	 	 	23,262	 	
Regulatory assets associated with employee benefit obligations	 	 	9,656	 	 	 	15,525	 	
Other	 	 	5,816	 	 	 	7,558	 	
Total	 	 	196,398	 	 	 	254,950	 	
Deferred tax assets —	 	 	 	 	 	 	 	 	
Federal net operating loss	 	 	5,829	 	 	 	8,275	 	
Federal effect of state deferred taxes	 	 	8,296	 	 	 	12,426	 	
Employee benefit obligations	 	 	10,275	 	 	 	15,566	 	
Regulatory liability associated with the Tax Reform Legislation	 	 	34,858	 	 	 	—	 	
Bad debt and insurance reserves	 	 	1,555	 	 	 	1,936	 	
Other	 	 	4,696	 	 	 	5,921	 	
Total	 	 	65,509	 	 	 	44,124	 	
Accumulated deferred income taxes, net	 	$	130,889	 	 	$	210,826	 	

27

The implementation of the Tax Reform Legislation significantly reduced accumulated deferred income taxes, partially offset by bonus depreciation provisions in the Protecting Americans from Tax Hikes Act. The Tax Reform Legislation also significantly increased tax-related regulatory liabilities.

At December 31, 2017, the tax-related regulatory liabilities to be credited to customers were $121.0 million. These liabilities are primarily attributable to deferred taxes previously recognized at rates higher than the current enacted tax law and to unamortized ITCs.

Deferred federal and state ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $0.1 million for each of the years ended December 31, 2017 and 2016. At December 31, 2017, all ITCs available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
 	 	Years Ended December 31,	 	
 	 	2017	 	 	2016	 	
Federal statutory rate	 	 	35.0	%	 	 	35.0	%	
State income tax, net of federal deduction	 	 	5.9	 	 	 	5.9	 	
Other	 	 	(1.6	)	 	 	(0.6	)	
Effective income tax rate	 	 	39.3	%	 	 	40.3	%	

Unrecognized Tax Benefits

The Company has no unrecognized tax benefits for any year presented.

The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any year presented.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Southern Company is a participant in the Compliance Assurance Process of the IRS. The IRS has finalized its audits of  Southern Company’s consolidated federal tax returns through 2016. However, the pre-Merger Southern Company Gas 2014, 2015, and June 30, 2016 federal tax returns are currently under audit. The audits for Southern Company Gas by any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for years prior to 2011.

5. FINANCING

The following table provides maturity dates, year-to-date weighted average interest rates, and amounts outstanding for various debt securities and facilities that are included in the balance sheets.
 	 	 	 	 	December 31, 2017	 	 	December 31, 2016	 	
(Dollars in thousands)	 	Year(s) due	 	 	Weighted
average interest
rate	 	 	Outstanding	 	 	Weighted average
interest rate	 	 	Outstanding	 	
Gas facility revenue bonds	 	 	2022-2033	 	 	 	1.7	%	 	$	180,100	 	 	 	1.3	%	 	$	180,100	 	
Affiliate promissory note	 	 	2034	 	 	 	4.5	%	 	 	268,406	 	 	 	7.2	%	 	 	167,528	 	
Total principal long-term debt	 	 	 	 	 	 	3.4	%	 	$	448,506	 	 	 	4.1	%	 	$	347,628	 	
Unamortized debt issuance costs	 	 	 	 	 	 	n/a	 	 	$	(681	)	 	 	n/a	 	 	$	(749	)	
Total debt	 	 	 	 	 	 	n/a	 	 	$	447,825	 	 	 	n/a	 	 	 	346,879	 	

28

Gas Facility Revenue Bonds

The Company is party to a series of loan agreements with the New Jersey Economic Development Authority under which, a series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies to investors, and proceeds from each issuance then are loaned to the Company. Southern Company Gas fully and unconditionally guarantees all of the Company’s gas facility revenue bonds.

The Company’s asset sale agreement requires that the gas facility revenue bonds, which are currently eligible for redemption at par, be redeemed on or prior to consummation of the sale. The ultimate outcome of this matter cannot be determined at this time. See Note 9 for information on the proposed sale of the Company.

Affiliate Promissory Note

Pivotal Utility entered into a promissory note with Southern Company Gas (Affiliate Promissory Note) for the purpose of refinancing its short-term debt and recapitalizing the capital structure of Pivotal Utility and those of its utility operating divisions including the Company’s, in accordance with the target capitalization of 47% and with authorization of the New Jersey BPU. The Affiliate Promissory Note is adjusted periodically to maintain the appropriate targeted capitalization percentages and, during 2017, $100.9 million was converted to the Affiliate Promissory Note and $34.4 million was converted to equity. The Affiliate Promissory Note is due December 31, 2034 and had an initial interest rate at December 31, 2004 of 6.3%, which adjusts on a periodic basis based upon weighted average costs and expenses of borrowing the then-outstanding long-term debt of both Southern Company Gas and Southern Company Gas Capital Corporation, a 100%-owned financing subsidiary of Southern Company Gas. As of December 31, 2017, the effective interest rate on this note was 4.5% which consists of two components. The first is incurred equal to the weighted average costs that is applied to the principal amount of the Affiliate Promissory Note. The second component is an adjustment to increase the effective interest incurred on long-term debt other than the Affiliate Promissory Note to the weighted average cost applicable to the Affiliate Promissory Note.

29

6. COMMITMENTS

Pipeline Charges, Storage Capacity, and Gas Supply

Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers of natural gas as well as demand charges associated with Sequent Energy Management, L.P. (Sequent), a wholly-owned subsidiary of Southern Company Gas that engages in wholesale marketing of natural gas supply services.

Contractual Obligations

Contractual obligations at December 31, 2017 were as follows:
 	 	2018	 	 	 	2019-2020	 	 	 	2021-2022	 	 	After 2022	 	 	Total	 	
 	 	(in thousands)	 	
Long-term debt(a) _	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Principal	 	$	—	 	 	$	—	 	 	$	46,500	 	 	$	401,325	 	 	 	447,825	 	
Interest	 	 	3,082	 	 	 	6,165	 	 	 	6,165	 	 	 	19,538	 	 	 	34,950	 	
Pipeline charges, storage capacity, and gas supply (b)	 	 	57,278	 	 	 	112,079	 	 	 	78,698	 	 	 	264,754	 	 	 	512,809	 	
Operating leases(c)	 	 	4,046	 	 	 	8,181	 	 	 	5,660	 	 	 	—	 	 	 	17,887	 	
Asset management agreements(d)	 	 	4,250	 	 	 	2,125	 	 	 	—	 	 	 	—	 	 	 	6,375	 	
Financial derivative obligations(e)	 	 	1,694	 	 	 	312	 	 	 	—	 	 	 	—	 	 	 	2,006	 	
Other purchase commitments(f)	 	 	7,000	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7,000	 	
Total	 	$	77,350	 	 	$	128,862	 	 	$	137,023	 	 	$	685,617	 	 	$	1,028,852	 	

(a)	Amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at December 31, 2017 and do not include interest on the affiliated promissory note.	

(b)	Includes charges recoverable through a natural gas cost recovery mechanism, subject to review by the New Jersey BPU.	

(c)	Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. In terms of rental charges and duration of contracts, the Company’s most significant operating leases relate to real estate and fleet vehicles.	

(d)	Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.	

(e)	See Notes 1 and 9 for additional information.	

(f)	Includes contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms.	

Indemnities

In certain instances, the Company has undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which it may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup. See Note 3 under “Environmental Matters” for additional information. The Company believes that the likelihood of payment under its other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.
30

7. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. See Note 1 under “Fair Value Measurements” for additional information on the fair value hierarchy.

As of December 31, 2017, liabilities measured at fair value on a recurring basis during the year, together with their associated level of the fair value hierarchy, were as follows:
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)	 	 	Significant
Other
Observable
Inputs
(Level 2)	 	 	Significant
Unobservable
Inputs
(Level 3)	 	 	Net Asset Value
as a Practical
Expedient
(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives	 	$	—	 	 	$	2,006	 	 	$	—	 	 	$	—	 	 	$	2,006	 	

As of December 31, 2016, assets measured at fair value on a recurring basis during the year, together with their associated level of the fair value hierarchy, were as follows:
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)	 	 	Significant
Other
Observable
Inputs
(Level 2)	 	 	Significant
Unobservable
Inputs
(Level 3)	 	 	Net Asset Value
as a Practical
Expedient
(NAV)	 	 	Total	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives	 	$	—	 	 	$	8,385	 	 	$	—	 	 	$	—	 	 	$	8,385	 	

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and non-exchange-traded derivatives such as over-the-counter forwards and options. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices and implied volatility. See Note 8 for additional information on how these derivatives are used.

8. DERIVATIVES

The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 7 for additional information. In the statements of cash flows, the cash impacts of settled energy-related are recorded as operating activities.

31

Energy-Related Derivatives

The Company enters into energy-related derivatives to hedge exposures to natural gas and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, the Company has limited exposure to market volatility in prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the New Jersey BPU, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.

Energy-related derivative contracts are accounted for under one of three methods:

 	•	Regulatory Hedges - Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through cost recovery clauses.	

 	•	Cash Flow Hedges - Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.	

 	•	Not Designated - Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income in the period of change.	

At December 31, 2017, the net volume of energy-related derivative contracts for natural gas positions totaled 18 billion cubic feet for the Company, together with the longest hedge date of 2019 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions.

Derivative Financial Statement Presentation and Amounts

The derivative contracts of the Company are subject to master netting arrangements or similar agreements and are reported net in the financial statements. Some of these energy-related derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements.

At December 31, 2017 and 2016, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
 	  	 	Asset Derivatives	 	 	 	Liability Derivatives	 	
Derivative
Category	Balance Sheet
Location	 	2017	 	 	2016	 	Balance Sheet
Location	 	2017	 	 	2016	 	
 	  	 	(in thousands)	 	 	 	(in thousands)	 	
Derivatives designated as hedging instruments for regulatory purposes	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets from risk management activities – current	 	$	—	 	 	$	7,473	 	Liabilities from risk management activities – current	 	$	1,694	 	 	$	—	 	
Other deferred charges and assets	 	 	—	 	 	 	912	 	Other deferred credits and liabilities	 	 	312	 	 	 	—	 	
Total derivatives designated as hedging instruments for regulatory purposes	 	$	—	 	 	$	8,385	 	 	 	$	2,006	 	 	$	—	 	
Gross amounts of recognized	 	$	—	 	 	$	8,385	 	 	 	$	2,006	 	 	$	—	 	
Gross amounts offset	 	$	—	 	 	$	—	 	 	 	$	—	 	 	$	—	 	
Net amounts recognized in the Balance Sheets	 	$	—	 	 	$	8,385	 	 	 	$	2,006	 	 	$	—	 	

32

At December 31, 2017 and 2016, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
 	  	 	Unrealized Losses	 	 	 	Unrealized Gains	 	
Derivative
Category	Balance Sheet
Location	 	2017	 	 	2016	 	Balance Sheet
Location	 	2017	 	 	2016	 	
 	 	(in thousands) 	 	 	 	(in thousands) 	 	
Energy-related derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other regulatory assets, current	 	$	(1,694	)	 	$	—	 	Other regulatory liabilities, current	 	$	—	 	 	$	7,473	 	
Other regulatory assets, deferred	 	 	(312	)	 	 	—	 	Other regulatory liabilities, deferred	 	 	—	 	 	 	912	 	
Total energy-related derivative gains (losses)	 	$	(2,006	)	 	$	—	 	 	 	$	—	 	 	$	8,385	 	

Contingent Features

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. At December 31, 2017, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.

At December 31, 2017, the fair value of derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features were immaterial.

Generally, collateral may be provided by a guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s Investors Service Inc. and S&P Global Ratings or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate its exposure to counterparty credit risk.

The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company’s credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

33

9. DISPOSITION

On October 15, 2017, Pivotal Utility entered into an agreement for the sale of the Company’s assets to South Jersey Industries, Inc. for a total cash purchase price of $1.7 billion. The completion of the asset sale is subject to the satisfaction or waiver of certain conditions, including, among other customary closing conditions, the receipt of required regulatory approvals, including the FERC, the Federal Communications Commission, and the New Jersey BPU. Pivotal Utility and South Jersey Industries, Inc. made a joint filing on December 22, 2017 with the New Jersey BPU requesting regulatory approval. The asset sale is expected to be completed by the end of the third quarter 2018.

The ultimate outcome of these matters cannot be determined at this time.

10. AFFILIATE TRANSACTIONS

The Company has agreements with Sequent for transportation and storage capacity to meet natural gas demands. The following table provides additional information on the Company’s asset management agreements with Sequent.
 	 	 	 	 	 	Profit sharing / fees payments	 	
Expiration date	Type of fee structure	 	Annual fee	 	 	2017	 	 	2016	 	
 	 	 	 	 	 	(in thousands)	 	
March 2019	Tiered	 	 	 	(*) 	 	$	11,195	 	 	$	15,043	 	

(*)	In March 2014, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent for five years. This renewed agreement began on April 1, 2014 and requires Sequent to pay minimum annual fees of $4.25 million to Elizabethtown Gas and includes tiered margin sharing levels between Elizabethtown Gas and Sequent.	

Upon consummation of the asset sale of Elizabethtown Gas, South Jersey Industries, Inc. will assume the asset management agreements of Elizabethtown Gas. See Note 9 for information on the proposed sale of the Company.

Amounts Due to Affiliates

The Company had $81.9 million and $55.2 million in payable at December 31, 2017 and 2016, respectively, which was due to Southern Company Gas, primarily related to the participation in the Southern Company Gas money pool. The Company also had $268.4 million and $167.5 million outstanding at December 31, 2017 and 2016, respectively, related to a promissory note with Southern Company Gas. See Note 5 for additional information on the Affiliate Promissory Note.

The Company is covered by Southern Company Gas’ agreement with Southern Company Services, Inc. under which various services are currently being rendered to the Company as direct or allocated cost. Additionally, the Company engages in transactions with Southern Company Gas’ affiliates consistent with its services and tax allocation agreements.

11. SUBSEQUENT EVENTS

Management evaluated subsequent events for potential recognition and disclosure through March 13, 2018, the date these financial statements were available to be issued, and determined that, except for the Company’s withdrawal of its Safety, Modernization and Reliability Tariff filing as discussed in Note 3 under “Regulatory Infrastructure Programs” and the Company’s filing with the New Jersey BPU for reduced annual rate base in response to the Tax Reform Legislation as discussed in Note 3 under “Other,” no significant events have occurred subsequent to period end.
 
34

 

Elizabethtown Gas

(A division of Pivotal Utility Holdings, Inc., a wholly-owned
subsidiary of Southern Company Gas)

Financial Statements as of December 31, 2016 and 2015
and for the years then ended, and Independent Auditors’ Report

Index to the Notes to Financial Statements
 	 	Page	
 Independent Auditor’s Report	4	
 	 	 	
Financial Statements	 	
 	Statements of Income	5	
 	Statements of Comprehensive Income	5	
 	Statements of Cash Flows	6	
 	Balance Sheets	7	
 	Statements of Equity	9	
 Notes to Financial Statements	 	
 	1.  Summary of Significant Accounting Policies	10	
 	2.  Retirement Benefits	16	
 	3.  Contingencies and Regulatory Matters	26	
 	4.  Income Taxes	27	
 	5.  Financing	29	
 	6.  Commitments	29	
 	7.  Fair Value Measurements	30	
 	8.  Derivatives	31	
 	9.  Affiliate Transactions	33	
 	10. Subsequent Events	33	

2

 
 
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3

Report of Independent Auditors

To the Management of Elizabethtown Gas:

We have audited the accompanying financial statements of Elizabethtown Gas (a division of Pivotal Utility Holdings, Inc., a wholly owned subsidiary of Southern Company Gas, the “Company”), which comprise the balance sheet as of December 31, 2015, and the related statements of income, comprehensive income, equity, and cash flows for the year then ended.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the 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 financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the financial statements based on our audit. We conducted our audit 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 financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the 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 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 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 financial statements referred to above present fairly, in all material respects, the financial position of Elizabethtown Gas as of December 31, 2015, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ PricewaterhouseCoopers LLP
Atlanta, Georgia

February 11, 2016
4

STATEMENTS OF INCOME
Elizabethtown Gas
For the Years Ended December 31, 2016 and 2015
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Operating Revenues	 	$	292,699	 	 	$	307,162	 	
Operating Expenses:	 	 	 	 	 	 	 	 	
Cost of natural gas	 	 	132,122	 	 	 	148,876	 	
Other operations and maintenance	 	 	82,599	 	 	 	65,403	 	
Depreciation and amortization	 	 	25,439	 	 	 	24,154	 	
Taxes other than income taxes	 	 	2,572	 	 	 	2,850	 	
Total operating expenses	 	 	242,732	 	 	 	241,283	 	
Operating Income	 	 	49,967	 	 	 	65,879	 	
Other income, net	 	 	1,610	 	 	 	367	 	
Interest expense, net of amounts capitalized	 	 	14,932	 	 	 	14,664	 	
Earnings Before Income Taxes	 	 	36,645	 	 	 	51,582	 	
Income taxes	 	 	14,751	 	 	 	20,230	 	
Net Income	 	$	21,894	 	 	$	31,352	 	

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

STATEMENTS OF COMPREHENSIVE INCOME
Elizabethtown Gas
For the Years Ended December 31, 2016 and 2015
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Net Income	 	$	21,894	 	 	$	31,352	 	
Other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Pension and other postretirement benefit plans:	 	 	 	 	 	 	 	 	
Benefit plan net loss, net of tax of $(6,314) and $(742), respectively	 	 	(9,142	)	 	 	(1,075	)	
Reclassification adjustment for amounts included in net income, net of tax of $454 and $1,143, respectively	 	 	657	 	 	 	1,654	 	
Total Other Comprehensive Income (Loss)	 	 	(8,485	)	 	 	579	 	
Comprehensive Income	 	$	13,409	 	 	$	31,931	 	

The accompanying notes are an integral part of these financial statements.
5

STATEMENTS OF CASH FLOWS
Elizabethtown Gas
For the Years Ended December 31, 2016 and 2015
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Operating Activities:	 	 	 	 	 	 	
Net income	 	$	21,894	 	 	$	31,352	 	
Adjustments to reconcile net income to net cash provided from operating activities —	 	 	 	 	 	 	 	 	
Depreciation and amortization, total	 	 	25,439	 	 	 	24,154	 	
Deferred income taxes	 	 	7,819	 	 	 	20,113	 	
Pension, postretirement, and other employee benefits	 	 	(13,083	)	 	 	1,490	 	
Mark-to-market adjustments	 	 	(22,243	)	 	 	(2,455	)	
Other, net	 	 	(17,315	)	 	 	(9,279	)	
Changes in certain current assets and liabilities —	 	 	 	 	 	 	 	 	
—Receivables	 	 	(16,458	)	 	 	31,467	 	
—Proceeds from insurance settlement	 	 	—	 	 	 	32,000	 	
—Inventories	 	 	3,029	 	 	 	6,635	 	
—Other current assets	 	 	3,672	 	 	 	67	 	
—Accrued taxes	 	 	7,381	 	 	 	(13,574	)	
—Accounts payable	 	 	2,611	 	 	 	(6,932	)	
—Accrued compensation	 	 	(997	)	 	 	(354	)	
—Other current liabilities	 	 	21,099	 	 	 	(7,492	)	
Net cash provided from operating activities	 	 	22,848	 	 	 	107,192	 	
Investing Activities:	 	 	 	 	 	 	 	 	
Property additions	 	 	(117,221	)	 	 	(89,525	)	
Cost of removal, net of salvage	 	 	(6,612	)	 	 	(5,016	)	
Change in construction payables, net	 	 	5,542	 	 	 	1,146	 	
Net cash used for investing activities	 	 	(118,291	)	 	 	(93,395	)	
Financing Activities:	 	 	 	 	 	 	 	 	
Net borrowings from parent	 	 	51,698	 	 	 	3,000	 	
Dividends to parent	 	 	(23,494	)	 	 	(24,001	)	
Capital contributions from parent company	 	 	67,239	 	 	 	7,204	 	
Net cash provided from (used for) financing activities	 	 	95,443	 	 	 	(13,797	)	
Net Change in Cash and Cash Equivalents	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at Beginning of Period	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at End of Period	 	$	—	 	 	$	—	 	
Supplemental Cash Flow Information:	 	 	 	 	 	 	 	 	
Interest, net of amounts capitalized	 	$	12,324	 	 	$	14,465	 	
Income taxes	 	 	3,216	 	 	 	13,799	 	
Accrued property additions at end of period	 	 	10,053	 	 	 	4,511	 	

The accompanying notes are an integral part of these financial statements.
6

BALANCE SHEETS
Elizabethtown Gas
At December 31, 2016 and 2015
Assets	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Receivables —	 	 	 	 	 	 	
Customer accounts receivable	 	$	22,979	 	 	$	16,295	 	
Unbilled revenues	 	 	24,948	 	 	 	14,745	 	
Other accounts and notes receivable	 	 	1,221	 	 	 	1,650	 	
Accumulated provision for uncollectible accounts	 	 	(4,054	)	 	 	(4,897	)	
Materials and supplies	 	 	304	 	 	 	322	 	
Natural gas for sale	 	 	20,437	 	 	 	23,466	 	
Prepaid taxes	 	 	3,682	 	 	 	14,205	 	
Assets from risk management activities, net of collateral	 	 	7,473	 	 	 	—	 	
Regulatory assets	 	 	10,186	 	 	 	5,663	 	
Other current assets	 	 	218	 	 	 	3,207	 	
Total current assets	 	 	87,394	 	 	 	74,656	 	
Property, Plant, and Equipment:	 	 	 	 	 	 	 	 	
In service	 	 	1,140,213	 	 	 	1,047,564	 	
Less accumulated depreciation	 	 	274,679	 	 	 	268,063	 	
Plant in service, net of depreciation	 	 	865,534	 	 	 	779,501	 	
Construction work in progress	 	 	54,994	 	 	 	44,883	 	
Total property, plant, and equipment	 	 	920,528	 	 	 	824,384	 	
Other Property and Investments:	 	 	 	 	 	 	 	 	
Goodwill	 	 	126,020	 	 	 	126,020	 	
Deferred Charges and Other Assets:	 	 	 	 	 	 	 	 	
Assets from risk management activities, net of collateral	 	 	912	 	 	 	—	 	
Regulatory assets	 	 	114,680	 	 	 	92,465	 	
Other deferred charges and assets	 	 	7	 	 	 	26	 	
Total deferred charges and other assets	 	 	115,599	 	 	 	92,491	 	
Total Assets	 	$	1,249,541	 	 	$	1,117,551	 	

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

7

BALANCE SHEETS
Elizabethtown Gas
At December 31, 2016 and 2015
Liabilities and Stockholder’s Equity	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Current Liabilities:	 	 	 	 	 	 	
Due to affiliates	 	$	55,186	 	 	$	50,031	 	
Accounts payable	 	 	14,287	 	 	 	11,289	 	
Customer deposits	 	 	9,686	 	 	 	10,684	 	
Other accrued taxes	 	 	2,720	 	 	 	5,215	 	
Accrued interest	 	 	167	 	 	 	166	 	
Accrued compensation	 	 	1,781	 	 	 	2,765	 	
Liabilities from risk management activities, net of collateral	 	 	—	 	 	 	12,291	 	
Regulatory liabilities	 	 	16,276	 	 	 	5,106	 	
Accrued environmental remediation	 	 	29,000	 	 	 	18,300	 	
Other current liabilities	 	 	1,363	 	 	 	3,242	 	
Total current liabilities	 	 	130,466	 	 	 	119,089	 	
Long-Term Debt (see notes)	 	 	346,879	 	 	 	295,114	 	
Deferred Credits and Other Liabilities:	 	 	 	 	 	 	 	 	
Accumulated deferred income taxes	 	 	210,826	 	 	 	187,880	 	
Accrued pension and retiree welfare benefits	 	 	20,700	 	 	 	32,234	 	
Other cost of removal  obligations	 	 	55,873	 	 	 	56,413	 	
Accrued environmental remediation	 	 	77,054	 	 	 	104,072	 	
Other regulatory liabilities	 	 	2,256	 	 	 	1,355	 	
Liabilities from risk management activities, net of collateral	 	 	—	 	 	 	1,567	 	
Other deferred credits and liabilities	 	 	1,028	 	 	 	890	 	
Total deferred credits and other liabilities	 	 	367,737	 	 	 	384,411	 	
Total Liabilities	 	 	845,082	 	 	 	798,614	 	
Stockholder’s Equity	 	 	 	 	 	 	 	 	
Paid-in capital	 	 	132,019	 	 	 	64,858	 	
Retained earnings	 	 	272,440	 	 	 	274,040	 	
Accumulated other comprehensive loss	 	 	—	 	 	 	(19,961	)	
Total Stockholder’s Equity	 	 	404,459	 	 	 	318,937	 	
Total Liabilities and Stockholder’s Equity	 	$	1,249,541	 	 	$	1,117,551	 	
Commitments and Contingent Matters (see notes)	 	 	 	 	 	 	 	 	

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

8

STATEMENTS OF EQUITY
Elizabethtown Gas
For the Years Ended December 31, 2016 and 2015
 	 	Paid-in Capital	 	 	Retained
Earnings	 	 	Accumulated Other
Comprehensive Loss	 	 	Total	 	
 	 	(in thousands)	 	
Balance at December 31, 2014	 	$	57,654	 	 	$	266,689	 	 	$	(20,540	)	 	$	303,803	 	
Net income	 	 	—	 	 	 	31,352	 	 	 	—	 	 	 	31,352	 	
Other comprehensive income	 	 	—	 	 	 	—	 	 	 	579	 	 	 	579	 	
Dividends to parent	 	 	—	 	 	 	(24,001	)	 	 	—	 	 	 	(24,001	)	
Capital contributions from parent company	 	 	7,204	 	 	 	—	 	 	 	—	 	 	 	7,204	 	
Balance at December 31, 2015	 	$	64,858	 	 	$	274,040	 	 	$	(19,961	)	 	$	318,937	 	
Net income	 	 	—	 	 	 	21,894	 	 	 	—	 	 	 	21,894	 	
Other comprehensive loss	 	 	—	 	 	 	—	 	 	 	(8,485	)	 	 	(8,485	)	
Reclassification of accumulated other comprehensive loss to regulatory assets	 	 	—	 	 	 	—	 	 	 	28,446	 	 	 	28,446	 	
Dividends to parent	 	 	—	 	 	 	(23,494	)	 	 	—	 	 	 	(23,494	)	
Capital contributions from parent company	 	 	67,239	 	 	 	—	 	 	 	—	 	 	 	67,239	 	
Stock-based compensation	 	 	(78	)	 	 	—	 	 	 	—	 	 	 	(78	)	
Balance at December 31, 2016	 	$	132,019	 	 	$	272,440	 	 	$	—	 	 	$	404,459	 	

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

9

Elizabethtown Gas
Notes to Financial Statements
December 31, 2016 and 2015

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Elizabethtown Gas (the Company) engages in the sale and distribution of natural gas to approximately 287 thousand customers in New Jersey. Elizabethtown Gas is a division of Pivotal Utility Holdings, Inc. (Pivotal Utility), which is a wholly-owned subsidiary of Southern Company Gas (formerly known as AGL Resources Inc.). On July 1, 2016, Southern Company Gas completed its previously announced merger (Merger) with The Southern Company (Southern Company) and became a wholly-owned, direct subsidiary of Southern Company.

The Company is subject to regulation by the New Jersey Board of Public Utilities (New Jersey BPU). As such, the Company’s financial statements reflect the effects of rate regulation in accordance with accounting principles generally accepted in the United States of America (GAAP) and comply with the accounting policies and practices prescribed by the New Jersey BPU. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

The impact of the acquisition method of accounting was not pushed down to Elizabethtown Gas and is not reflected in the financial statements included herein.

Certain prior year data in the financial statements has been modified or reclassified to conform to the presentation used by Southern Company Gas. Changes to the statements of cash flows include revised financial statement line item descriptions to align with the new balance sheet descriptions and expanded line items within each type of cash flow activity. Changes to the balance sheets include changing certain captions to conform to the presentation of Southern Company Gas.

Recently Issued Accounting Standards

In 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers,  replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the guidance is to recognize revenue to depict the transfer of goods or services to customers at an amount an entity expects to collect. The new standard also requires enhanced quantitative and qualitative disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.

While the Company expects most of its revenue to be within the scope of ASC 606, it has not fully completed its evaluation of such arrangements. The majority of the Company’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas without a defined contractual term. For such arrangements, the Company generally expects that the revenue from contracts with these customers will continue to be equivalent to the natural gas supplied and billed in that period (including unbilled revenues) and will not result in a significant shift in the timing of revenue recognition for such sales.

The Company’s ongoing evaluation of other revenue streams and related contracts includes longer term contractual commitments. Some revenue arrangements, such as certain alternative revenue programs, are expected to be excluded from the scope of ASC 606 and therefore, be accounted for and presented separately from revenues under ASC 606 on the Company’s financial statements. In addition, the power and utilities industry is currently addressing other specific industry issues.

The new standard is effective for interim and annual reporting periods beginning after December 15, 2017. The Company must select a transition method to be applied either retrospectively to each prior reporting period presented or retrospectively with a cumulative effect adjustment to retained earnings at the date of initial adoption. As the ultimate impact of the new standard has not yet been determined, the Company has not elected its transition method.

On November 20, 2015, the FASB issued ASU No. 2015-17, Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes  (ASU 2015-17), which simplifies the presentation of deferred income taxes. ASU 2015-17 requires deferred tax assets and liabilities to be presented as non-current in a classified balance sheet and is effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. As permitted, the Company elected to early adopt the guidance in 2016. Prior to the adoption of ASU 2015-17, all deferred income tax assets and liabilities were required to be separated into current and non-current amounts. The adoption of ASU 2015-17 did not have an impact on the results of operations, financial position, or cash flows.

10

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 requires lessees to recognize on the balance sheet a lease liability and a right-of-use asset for all leases. ASU 2016-02 also changes the recognition, measurement, and presentation of expense associated with leases and provides clarification regarding the identification of certain components of contracts that would represent a lease. The accounting required by lessors is relatively unchanged. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company is currently evaluating the new standard and has not yet determined its ultimate impact; however, adoption of ASU 2016-02 is expected to have a significant impact on the Company’s balance sheet.

On October 24, 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory  (ASU 2016-16). Current GAAP prohibits the recognition of current and deferred income taxes for an affiliate asset transfer until the asset has been sold to an outside party. ASU 2016-16 requires an entity to recognize the income tax consequences of an affiliate transfer of an asset other than inventory when the transfer occurs. ASU 2016-16 is effective for annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. The amendments will be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company is currently assessing the impact of the standard on its financial statements.

Regulatory Assets and Liabilities

The Company is subject to accounting requirements for the effects of rate regulation. Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

Regulatory assets and liabilities reflected in the balance sheets at December 31, relate to:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Regulatory Assets	 	 	 	 	 	 	
Recoverable weather normalization adjustment	 	$	10,186	 	 	$	—	 	
Deferred natural gas costs	 	 	—	 	 	 	5,663	 	
Regulatory assets – current	 	 	10,186	 	 	 	5,663	 	
Recoverable environmental remediation costs	 	 	72,481	 	 	 	85,922	 	
Recoverable pension and retiree welfare benefit costs	 	 	35,283	 	 	 	—	 	
Unamortized losses on reacquired debt	 	 	4,425	 	 	 	4,867	 	
Other	 	 	2,491	 	 	 	1,676	 	
Regulatory assets – long-term	 	 	114,680	 	 	 	92,465	 	
Total Regulatory Assets	 	$	124,866	 	 	$	98,128	 	
Regulatory Liabilities	 	 	 	 	 	 	 	 	
Accrued natural gas costs	 	$	     14,898	 	 	$	— 	 	
Other	 	 	   1,378	 	 	 	5,106	 	
Regulatory liabilities – current	 	 	16,276	 	 	 	5,106	 	
Other cost of removal obligations	 	 	55,873	 	 	 	56,413	 	
Regulatory income tax liability	 	 	673	 	 	 	907	 	
Other	 	 	1,583	 	 	 	448	 	
Regulatory liabilities – long-term	 	 	58,129	 	 	 	57,768	 	
Total Regulatory Liabilities	 	$	74,405	 	 	$	62,874	 	

11

In the event that the Company’s operations are no longer subject to applicable accounting rules for rate regulation, the Company would be required to write off to income related regulatory assets and liabilities that are not specifically recoverable through regulated rates. In addition, the Company would be required to determine if any impairment to other assets, including plant, exists and write down the assets, if impaired, to their fair values. All regulatory assets and liabilities are to be reflected in rates. See Note 3 under “Regulatory Matters” for additional information.

Revenues

The Company records revenues when goods or services are provided to customers. Those revenues are based on rates approved by the New Jersey BPU. The Company has a rate structure that includes a volumetric rate design that allows the opportunity to recover certain costs based on gas usage. Revenues from sales and transportation services are recognized in the same period in which the related volumes are delivered to customers. Revenues from residential and certain commercial and industrial customers are recognized on the basis of scheduled meter readings. Additionally, unbilled revenues are recognized for estimated deliveries of natural gas not yet billed to these customers, from the last bill date to the end of the accounting period. For other commercial and industrial customers, revenues are based on actual deliveries to the end of the period.

The tariffs for the Company contain weather normalization adjustments that partially mitigate the impact of unusually cold or warm weather on customer billings and natural gas revenues. The weather normalization adjustments have the effect of reducing customer bills when winter weather is colder than normal and increasing customer bills when weather is warmer than normal. The weather normalization adjustments are alternative revenue programs, which allow recognition of revenue prior to billing as long as the amounts will be collected within 24 months of recognition.

Concentration of Revenue

The Company has a diversified base of customers. No single customer or industry comprises 10% or more of revenues. For all periods presented, uncollectible accounts averaged less than 2% of revenues.

Cost of Natural Gas

The Company charges its customers for natural gas consumed using a natural gas cost recovery mechanism set by the New Jersey BPU, under which all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. The Company defers or accrues the difference between the actual cost of natural gas and the amount of commodity revenue earned in a given period such that no operating income is recognized related to these costs. The deferred or accrued amount is either billed or refunded to customers prospectively through adjustments to the commodity rate. Deferred and accrued natural gas costs are included in the balance sheets as regulatory assets and regulatory liabilities, respectively

Income and Other Taxes

The Company does not file its own federal or state income tax returns. Instead, the Company is included in Southern Company’s consolidated federal income tax return and Southern Company Gas’ various state income tax returns. Prior to the Merger, the Company was included in the consolidated tax returns of Southern Company Gas.

The Company uses the liability method of accounting for deferred income taxes and provides deferred income taxes for all significant income tax temporary differences. Federal investment tax credits utilized are deferred and amortized to income over the average life of the related property. Taxes that are collected from customers on behalf of governmental agencies to be remitted to these agencies are presented on the balance sheets.

The Company recognizes tax positions that are “more likely than not” of being sustained upon examination by the appropriate taxing authorities. See Note 4 under “Unrecognized Tax Benefits” for additional information.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost less any regulatory disallowances and impairments. Original cost includes: materials; labor; minor items of property; appropriate administrative and general costs; payroll-related costs such as taxes, pensions, and other benefits; and the interest capitalized and cost of equity funds used during construction.

12

The Company’s property, plant, and equipment in service consisted of the following at December 31:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Distribution and transmission	 	$	1,056,686	 	 	$	964,796	 	
Information technology equipment and software	 	 	37,124	 	 	 	35,515	 	
Storage facilities	 	 	7,193	 	 	 	7,112	 	
Other	 	 	39,210	 	 	 	40,141	 	
Total plant in service	 	$	1,140,213	 	 	$	1,047,564	 	

The cost of replacements of property, exclusive of minor items of property, is capitalized. The cost of maintenance, repairs, and replacement of minor items of property is charged to other operations and maintenance expenses as incurred or performed.

Depreciation

Depreciation of the original cost of plant in service is provided using composite straight-line rates, which approximated 2.3% and 2.4% in 2016 and 2015, respectively. Depreciation studies are conducted periodically to update the composite rate that is approved by the New Jersey BPU. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost, together with the cost of removal, less salvage, is charged to accumulated depreciation. As such, gains or losses are not recognized, instead they are ultimately refunded to, or recovered from, customers through future rate adjustments. Minor items of property included in the original cost of the asset are retired when the related property unit is retired.

Allowance for Funds Used During Construction (AFUDC)

The Company records AFUDC, which represents the estimated debt and equity costs of capital funds that are necessary to finance the construction of new regulated facilities. While cash is not realized currently, AFUDC increases the revenue requirement and is recovered over the service life of the asset through a higher rate base and higher depreciation. The AFUDC composite rate was 1.68% and 1.69% for the years ended 2016 and 2015, respectively. The Company recorded $343 thousand and $392 thousand of AFUDC for the years ended December 31, 2016 and 2015, respectively.

Goodwill

Goodwill is not amortized, but is subject to an annual impairment test during the fourth quarter of each year, or more frequently if impairment indicators arise. In assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine that it is more likely than not that fair value of its reporting unit exceeds its carrying value (commonly referred to as Step 0). If the Company chooses not to perform a qualitative assessment, or the result of Step 0 indicates a probable decrease in fair value of its reporting unit below its carrying value, a quantitative two-step test is performed (commonly referred to as Step 1 and Step 2). Step 1 compares the fair value of the reporting unit to its carrying value including goodwill. If the carrying value exceeds the fair value, Step 2 is performed to allocate the fair value of the reporting unit to its assets and liabilities in order to determine the implied fair value of goodwill, which is compared to the carrying value of goodwill to calculate an impairment loss, if any.

For the 2016 and 2015 annual goodwill impairment tests, the Step 0 assessment was performed focusing on the following qualitative factors: macroeconomic conditions, industry and market conditions, cost factors, financial performance, entity specific events, and events specific to each reporting unit. This Step 0 analysis concluded that it is more likely than not that the fair value of the Company’s reporting units that have goodwill exceeds their carrying amounts and a quantitative assessment was not required.

Cash Management Money Pool

The Company participates in Southern Company Gas’ utility money pool, under which short-term borrowings are made from the money pool and surplus funds are contributed to the money pool. Borrowings from the money pool are recorded as due to affiliates in the balance sheets and intercompany interest expense is recorded in the statements of income for these borrowings. See Note 9 for additional information.

Receivables and Allowance for Uncollectible Accounts

The Company’s receivables consist primarily of natural gas sales and transportation services billed to residential, commercial, industrial, and other customers. Customers are billed monthly and payment is due within 30 days. For the majority of receivables, an allowance for doubtful accounts is established based on historical collection experience and other factors. For the remaining receivables, if the Company is aware of a specific customer’s inability to pay, an allowance for doubtful accounts is recorded to reduce the receivable balance to the amount the Company reasonably expects to collect. If circumstances change, the estimate of the recoverability of accounts receivable could change as well. Circumstances that could affect this estimate include, but are not limited to, customer credit issues, customer deposits, and general economic conditions. Customers’ accounts are written off once they are deemed to be uncollectible.

13

Materials and Supplies

Generally, materials and supplies include propane, fleet fuel, and other materials and supplies. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, at weighted average cost when installed.

Natural Gas for Sale

The Company’s natural gas inventories are carried at cost on a weighted average cost of gas basis.

Fair Value Measurements

The Company has financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include derivative assets and liabilities. The carrying values of receivables, accounts payable, due to affiliates, other current assets and liabilities, accrued interest, and long-term debt approximate their respective fair value. The Company’s nonfinancial assets and liabilities include pension and other retirement benefits. See Notes 2 and 7 for additional fair value disclosures.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company primarily applies the market approach for recurring fair value measurements to utilize the best available information. Accordingly, the Company uses valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observance of those inputs. The guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by the guidance are as follows:

Level 1

Quoted prices in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 items consist of exchange-traded derivatives, money market funds, and certain retirement plan assets.

Level 2

Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Market price data is obtained from multiple sources in order to value certain Level 2 transactions and this data is representative of transactions that occurred in the marketplace. Level 2 instruments include non-exchange-traded derivatives such as over-the-counter forwards and options and certain retirement plan assets.

Level 3

Pricing inputs include significant unobservable inputs that may be used with internally developed methodologies to determine management’s best estimate of fair value from the perspective of market participants. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. Level 3 assets, liabilities, and any applicable transfers are primarily related to the Company’s pension and welfare benefit plan assets as described in Note 2. Transfers into and out of Level 3 are determined using values at the end of the interim period in which the transfer occurred.

14

Financial Instruments

The Company uses derivative financial instruments to limit exposure to fluctuations in natural gas prices, interest rates, and commodity prices. All derivative financial instruments are recognized as either assets or liabilities on the balance sheets (shown separately as “Risk Management Activities”) and are measured at fair value. See Note 7 for additional information regarding fair value. Derivative contracts that qualify as cash flow hedges of anticipated transactions or are recoverable through the respective state regulatory agency approved fuel-hedging programs result in the deferral of related gains and losses in other comprehensive income (OCI) or regulatory assets and liabilities, respectively, until the hedged transactions occur. Any ineffectiveness arising from cash flow hedges is recognized currently in net income. Cash flows from derivatives are classified on the statements of cash flows in the same category as the hedged item. See Note 8 for additional information regarding derivatives.

The Company offsets fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement. The Company had no outstanding collateral repayment obligations or rights to reclaim collateral arising from derivative instruments recognized at December 31, 2016.

Comprehensive Income

The objective of comprehensive income is to report a measure of all changes in common stock equity of an enterprise that result from transactions and other economic events of the period other than transactions with owners. Comprehensive income consists of net income, changes in the fair value of qualifying cash flow hedges, certain changes in pension and other postretirement benefit plans, and reclassifications for amounts included in net income.

Dividend Distributions

The Company paid dividends of $23.5 million and $24.0 million to Southern Company Gas during 2016 and 2015, respectively. The Company is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to Southern Company Gas to the extent of 70% of its quarterly net income.

15

2. RETIREMENT BENEFITS

Effective July 1, 2016, in connection with the Merger, Southern Company Services, Inc., a subsidiary of Southern Company, became the sponsor of Southern Company Gas’ pension and other postretirement benefit plans. The Company participates in the Southern Company Gas qualified defined benefit, trusteed, pension plan - AGL Resources Inc. Retirement Plan (AGL Plan) - that covers certain eligible employees. The qualified pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974 (ERISA), as amended. Southern Company Gas provides certain non-qualified defined benefit and defined contribution pension plans for a selected group of the Company’s management and highly compensated employees. Benefits under these non-qualified pension plans are funded on a cash basis. The Company also participates in the Southern Company Gas postretirement benefit plan - AGL Welfare Plan - which provides medical care and life insurance benefits for eligible retired employees.

In connection with the Merger, Southern Company Gas performed updated valuations of its pension and other postretirement benefit plan assets and obligations to reflect actual census data at the new measurement date of July 1, 2016. The Company recorded a regulatory asset of $35 million as of December 31, 2016 related to unrecognized prior service cost and actuarial gain/loss, as it is probable that this amount will be recovered through future rates.

The following disclosures reflect the Company’s balances and activity in the AGL Plan and the AGL Welfare Plan under the multiple-employer method of accounting.

Actuarial Assumptions

The weighted average rates assumed in the actuarial calculations used to determine both the net periodic costs for the pension and other postretirement benefit plans for the periods presented and the benefit obligations as of the measurement date are presented below.
Assumptions used to determine net periodic costs:	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016 through
June 30, 2016	 	 	Year Ended Ended
December 31, 2015	 	
Pension plans	 	 	 	 	 	 	 	 	 	
Discount rate - interest costs (*)	 	 	3.21	%	 	 	4.00	%	 	 	4.20	%	
Discount rate - service costs (*)	 	 	4.07	 	 	 	4.80	 	 	 	4.20	 	
Expected long-term return on plan assets	 	 	7.75	 	 	 	7.80	 	 	 	7.80	 	
Annual salary increase	 	 	3.50	 	 	 	3.70	 	 	 	3.70	 	
Other postretirement benefit plans	 	 	 	 	 	 	 	 	 	 	 	 	
Discount rate - interest costs (*)	 	 	2.84	%	 	 	3.60	%	 	 	4.00	%	
Discount rate - service costs (*)	 	 	3.96	 	 	 	4.70	 	 	 	4.00	 	
Expected long-term return on plan assets	 	 	5.93	 	 	 	6.60	 	 	 	7.80	 	
Annual salary increase	 	 	3.50	 	 	 	3.70	 	 	 	3.70	 	

(*)   Effective January 1, 2016, the Company uses a spot rate approach to estimate the service cost and interest cost components. Previously, the Company estimated these components using a single weighted average discount rate.
Assumptions used to determine benefit obligations:	 	December 31, 2016	 	 	December 31, 2015	 	
Pension plans	 	 	 	 	 	 	
Discount rate	 	 	4.39	%	 	 	4.60	%	
Annual salary increase	 	 	3.50	 	 	 	3.70	 	
Other postretirement benefit plans	 	 	 	 	 	 	 	 	
Discount rate	 	 	4.15	%	 	 	4.40	%	
Annual salary increase	 	 	3.50	 	 	 	3.70	 	

The Company estimates the expected return on plans assets by evaluating expected bond returns, equity risk premiums, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing, and historical performance. The Company also considers guidance from its investment advisors in making a final determination of its expected rate of return on assets. To the extent the actual rate of return on assets realized over the course of a year is greater or less than the assumed rate, it does not affect that year’s annual pension or welfare plan cost; rather, this gain or loss reduces or increases future pension or welfare plan costs.
16

An additional assumption used in measuring the accumulated other postretirement benefit obligations (APBO) was a weighted average medical care cost trend rate. The weighted average medical care cost trend rates used in measuring the APBO as of December 31, 2016 were as follows:
 	 	Initial Cost Trend
Rate	 	 	Ultimate Cost
Trend Rate	 	 	Year That Ultimate
Rate is Reached	 	
Pre-65	 	 	6.60	%	 	 	4.50	%	 	 	2038	 	
Post-65 medical	 	 	8.40	 	 	 	4.50	 	 	 	2038	 	
Post-65 prescription	 	 	8.40	 	 	 	4.50	 	 	 	2038	 	

An annual increase or decrease in the assumed medical care cost trend rate of 1% would affect the APBO; however, the impact on the service and interest cost components would be immaterial.

Pension Plans

The total accumulated benefit obligation for the pension plans was $86 million at December 31, 2016 and $80 million at December 31, 2015. Changes in the projected benefit obligation and the fair value of plan assets for the Company’s qualified pension plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 were as follows:
 	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016
through June 30, 2016	 	 	Year Ended Ended
December 31, 2015	 	
 	 	(in thousands)	 	
Change in benefit obligation	 	 	 	 	 	 	 	 	 	
Benefit obligation at beginning of period	 	$	105,458	 	 	$	90,910	 	 	$	93,042	 	
Service cost	 	 	990	 	 	 	861	 	 	 	1,713	 	
Interest cost	 	 	2,044	 	 	 	2,238	 	 	 	4,788	 	
Benefits paid	 	 	(3,592	)	 	 	(3,338	)	 	 	(6,812	)	
Actuarial loss (gain)	 	 	(9,937	)	 	 	14,787	 	 	 	(1,821	)	
Benefit obligation at end of period	 	 	94,963	 	 	 	105,458	 	 	 	90,910	 	
Change in plan assets	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of period	 	 	60,687	 	 	 	61,044	 	 	 	63,830	 	
Actual return on plan assets	 	 	3,706	 	 	 	2,981	 	 	 	4,026	 	
Employer contributions	 	 	14,048	 	 	 	—	 	 	 	—	 	
Benefits paid	 	 	(3,592	)	 	 	(3,338	)	 	 	(6,812	)	
Fair value of plan assets at end of period	 	 	74,849	 	 	 	60,687	 	 	 	61,044	 	
Accrued liability	 	$	20,114	 	 	$	44,771	 	 	$	29,866	 	

At December 31, 2016, the projected benefit obligations for the qualified and non-qualified pension plans were $95 million and $1 million, respectively. All pension plan assets are related to the qualified pension plan.

Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company’s qualified pension plans consist of the following:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Other regulatory assets, deferred	 	$	30,484	 	 	$	—	 	
Employee benefit obligations	 	 	(20,114	)	 	 	(29,866	)	

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Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the qualified defined benefit pension plans that had not yet been recognized in net periodic pension cost along with the estimated amortization of such amounts for 2017.
 	 	Prior Service Cost	 	 	Net (Gain) Loss	 	
 	 	(in thousands)	 	
Balance at December 31, 2016:	 	 	 	 	 	 	
Regulatory assets (liabilities)	 	$	(2,000	)	 	$	32,484	 	
Balance at December 31, 2015:	 	 	 	 	 	 	 	 	
Accumulated OCI	 	 	(2,848	)	 	 	30,637	 	
Estimated amortization in net periodic cost in 2017:	 	 	 	 	 	 	 	 	
Regulatory assets (liabilities)	 	 	847	 	 	 	(2,903	)	

The components of OCI and the changes in the balance of regulatory assets related to the qualified defined benefit pension plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 are presented in the following table:
 	 	Accumulated OCI	 	 	Regulatory Assets	 	
 	 	(in thousands)	 	
Balance at December 31, 2014:	 	$	29,172	 	 	$	—	 	
Net (gain) loss	 	 	997	 	 	 	—	 	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	907	 	 	 	—	 	
Amortization of net loss	 	 	(3,287	)	 	 	—	 	
Total reclassification adjustments	 	 	(2,380	)	 	 	—	 	
Total change	 	 	(1,383	)	 	 	—	 	
Balance at December 31, 2015:	 	$	27,789	 	 	$	—	 	
Net (gain) loss	 	 	15,216	 	 	 	(9,816	)	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	434	 	 	 	434	 	
Amortization of net loss	 	 	(1,396	)	 	 	(2,177	)	
Reclassification from accumulated OCI to regulatory assets	 	 	(42,043	)	 	 	42,043	 	
Total reclassification adjustments	 	 	(43,005	)	 	 	40,300	 	
Total change	 	 	(27,789	)	 	 	30,484	 	
Balance at December 31, 2016:	 	$	—	 	 	$	30,484	 	

The Company’s pro rata components of Southern Company Gas’ net periodic pension costs for the periods presented were as follows:
 	 	Years Ended December 31,	 	
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Service cost	 	$	1,851	 	 	$	1,713	 	
Interest cost	 	 	4,282	 	 	 	4,788	 	
Expected return on plan assets	 	 	(6,249	)	 	 	(5,733	)	
Amortization:	 	 	 	 	 	 	 	 	
Prior service costs	 	 	(868	)	 	 	(907	)	
Net loss	 	 	3,573	 	 	 	3,287	 	
Net periodic pension cost	 	$	2,589	 	 	$	3,148	 	

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Net periodic pension cost is the sum of service cost, interest cost, and other costs netted against the expected return on plan assets. The expected return on plan assets is determined by multiplying the expected rate of return on plan assets and the market-related value of plan assets.

Future benefit payments reflect expected future service and are estimated based on assumptions used to measure the projected benefit obligation for the pension plans. At December 31, 2016, the Company’s estimated benefit payments were as follows:
 	 	Benefit Payments	 	
 	 	(in thousands)	 	
2017	 	$	8,286	 	
2018	 	 	8,086	 	
2019	 	 	8,107	 	
2020	 	 	8,344	 	
2021	 	 	8,195	 	
2022 to 2026	 	 	40,610	 	

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Other Postretirement Benefits

Changes in the APBO and the fair value of plan assets for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 were as follows:
 	 	July 1, 2016 through
December 31, 2016	 	 	January 1, 2016
through June 30, 2016	 	 	Year Ended December
31, 2015	 	
 	 	(in thousands)	 	
Change in benefit obligation	 	 	 	 	 	 	 	 	 	
Benefit obligation at beginning of period	 	$	13,174	 	 	$	13,512	 	 	$	14,314	 	
Service cost	 	 	55	 	 	 	47	 	 	 	114	 	
Interest cost	 	 	187	 	 	 	218	 	 	 	553	 	
Benefits paid	 	 	(293	)	 	 	(438	)	 	 	(636	)	
Actuarial gain	 	 	(806	)	 	 	(165	)	 	 	(833	)	
Benefit obligation at end of period	 	 	12,317	 	 	 	13,174	 	 	 	13,512	 	
Change in plan assets	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at beginning of period	 	 	12,829	 	 	 	12,737	 	 	 	13,600	 	
Actual return (loss) on plan assets	 	 	348	 	 	 	92	 	 	 	(863	)	
Employer contributions	 	 	293	 	 	 	438	 	 	 	636	 	
Benefits paid	 	 	(293	)	 	 	(438	)	 	 	(636	)	
Fair value of plan assets at end of period	 	 	13,177	 	 	 	12,829	 	 	 	12,737	 	
(Prepaid asset) accrued liability	 	$	(860	)	 	$	345	 	 	$	775	 	

Amounts recognized in the balance sheets at December 31, 2016 and 2015 related to the Company’s other postretirement benefit plans consist of the following:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Other regulatory assets, deferred	 	$	4,361	 	 	$	—	 	
Employee benefit asset (obligation)	 	 	860	 	 	 	(775	)	

Presented below are the amounts included in accumulated OCI and regulatory assets at December 31, 2016 and 2015 related to the other postretirement benefit plans that had not yet been recognized in net periodic other postretirement benefit cost. The estimated amortization of such amounts for 2017 is immaterial.
 	 	Prior Service Cost	 	 	Net (Gain) Loss	 	
 	 	(in thousands)	 	
Balance at December 31, 2016:	 	 	 	 	 	 	
Regulatory assets	 	$	—	 	 	$	4,361	 	
Balance at December 31, 2015:	 	 	 	 	 	 	 	 	
Accumulated OCI	 	$	2	 	 	$	5,546	 	

20

The components of OCI, along with the changes in the balance of regulatory assets (liabilities), related to the other postretirement benefit plans for the periods ended December 31, 2016, June 30, 2016, and December 31, 2015 are presented in the following table:
 	 	Accumulated OCI	 	 	Regulatory Assets	 	
 	 	(in thousands)	 	
Balance at December 31, 2014:	 	$	5,058	 	 	$	—	 	
Net (gain) loss	 	 	891	 	 	 	—	 	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	(44	)	 	 	—	 	
Amortization of net loss	 	 	(357	)	 	 	—	 	
Total reclassification adjustments	 	 	(401	)	 	 	—	 	
Total change	 	 	490	 	 	 	—	 	
Balance at December 31, 2015:	 	$	5,548	 	 	$	—	 	
Net (gain) loss	 	 	90	 	 	 	(933	)	
Reclassification adjustments:	 	 	 	 	 	 	 	 	
Amortization of prior service costs	 	 	(1	)	 	 	(1	)	
Amortization of net loss	 	 	(137	)	 	 	(205	)	
Reclassification from accumulated OCI to regulatory assets	 	 	(5,500	)	 	 	5,500	 	
Total reclassification adjustments	 	 	(5,638	)	 	 	5,294	 	
Total change	 	 	(5,548	)	 	 	4,361	 	
Balance at December 31, 2016:	 	$	—	 	 	$	4,361	 	

The Company’s pro rata components of Southern Company Gas’ other postretirement benefit plans’ net periodic cost for the periods presented were as follows:
 	 	Years Ended December 31,	 	
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Service cost	 	$	102	 	 	$	114	 	
Interest cost	 	 	405	 	 	 	553	 	
Expected return on plan assets	 	 	(673	)	 	 	(1,015	)	
Amortization:	 	 	 	 	 	 	 	 	
Prior service costs	 	 	2	 	 	 	44	 	
Net loss	 	 	342	 	 	 	357	 	
Net periodic postretirement benefit cost	 	$	178	 	 	$	53	 	

Future benefit payments, including prescription drug benefits, reflect expected future service and are estimated based on assumptions used to measure the APBO for the other postretirement benefit plans. At December 31, 2016, estimated benefit payments were as follows:
 	 	Benefit Payments	 	
 	 	(in thousands)	 	
2017	 	$	693	 	
2018	 	 	745	 	
2019	 	 	790	 	
2020	 	 	826	 	
2021	 	 	861	 	
2022 to 2026	 	 	4,277	 	

Benefit Plan Assets

Southern Company Gas’ pension plan and other postretirement benefit plan assets are managed and invested in accordance with all applicable requirements, including ERISA and the Internal Revenue Code of 1986, as amended. The investment policies for both the pension plan and the other postretirement benefit plans cover a diversified mix of assets, including equity and fixed income securities, real estate, and private equity. Southern Company Gas minimizes the risk of large losses primarily through diversification but also monitors and manages other aspects of risk.

21

The assets of the AGL Plan were allocated 69% equity, 20% fixed income, 1% cash, and 10% other at December 31, 2016 compared to the Company’s targets of 53% equity, 15% fixed income, 2% cash, and 30% other. The plan’s investment policy provides for variation around the target asset allocation in the form of ranges. The Company’s pro rata share of the AGL Plan assets was 7.62% and 7.21% for December 31, 2016 and 2015, respectively.

The assets of the AGL Welfare Plan were allocated 74% equity, 23% fixed income, 1% cash, and 2% other at December 31, 2016 compared to the Company’s targets of 72% equity, 24% fixed income, 1% cash, and 3% other. The investment policy provides for variation around the target asset allocation in the form of ranges. The Company’s pro rata share of the AGL Welfare Plan assets was 12.56% and 12.82% for December 31, 2016 and 2015, respectively.

The assets of the AGL Plan and the AGL Welfare Plan were allocated 72% equity and 28% fixed income at December 31, 2015 compared to the Company’s targets of 70% to 95% equity, 5% to 20% fixed income, and up to 10% cash. The investment policies provided for some variation in these targets in the form of ranges around the target.

The investment strategy for plan assets related to the Southern Company Gas’ qualified pension plan is to be broadly diversified across major asset classes. The asset allocation is established after consideration of various factors that affect the assets and liabilities of the pension plan including, but not limited to, historical and expected returns and interest rates, volatility, correlations of asset classes, the current level of assets and liabilities, and the assumed growth in assets and liabilities. Because a significant portion of the liability of the pension plan is long-term in nature, the assets are invested consistent with long-term investment expectations for return and risk. To manage the actual asset class exposures relative to the target asset allocation, the Southern Company Gas employs a formal rebalancing program for its pension plan assets. As additional risk management, external investment managers and service providers are subject to written guidelines to ensure appropriate and prudent investment practices.

Investment Strategies

Detailed below is a description of the investment strategies for each major asset category for the Southern Company Gas pension plans disclosed above:

 	•	Domestic equity. A mix of large and small capitalization stocks with generally an equal distribution of value and growth attributes, managed both actively and through passive index approaches.	

 	•	International equity. A mix of growth stocks and value stocks with both developed and emerging market exposure, managed both actively and through passive index approaches.	

 	•	Fixed income. A mix of domestic and international bonds.	

 	•	Special situations. Investments in opportunistic strategies with the objective of diversifying and enhancing returns and exploiting short-term inefficiencies as well as investments in promising new strategies of a longer-term nature.	

 	•	Real estate investments. Investments in traditional private market equity-oriented investments (indirectly through pooled funds or partnerships) and in publicly traded real estate securities.	

 	•	Private equity. Investments in private partnerships that invest in private or public securities typically through privately-negotiated and/or structured transactions, including leveraged buyouts, venture capital, and distressed debt.	

Benefit Plan Asset Fair Values

Following are the fair value measurements for the pension plan assets as of December 31, 2016 and 2015. The fair values presented are prepared in accordance with GAAP. For purposes of determining the fair value of the pension plan assets and the appropriate level designation, management relies on information provided by the plan’s trustee. This information is reviewed and evaluated by management with changes made to the trustee information as appropriate.

Valuation methods of the primary fair value measurements disclosed in the following tables are as follows:

 	•	Domestic and international equity. Investments in equity securities such as common stocks, American depositary receipts, and real estate investment trusts that trade on a public exchange are classified as Level 1 investments and are valued at the closing price in the active market. Equity investments with unpublished prices (i.e. pooled funds) are valued as Level 2, when the underlying holdings used to value the investment are comprised of Level 1 or Level 2 equity securities.	

22

 	•	Fixed income. Investments in fixed income securities are generally classified as Level 2 investments and are valued based on prices reported in the market place. Additionally, the value of fixed income securities takes into consideration certain items such as broker quotes, spreads, yield curves, interest rates, and discount rates that apply to the term of a specific instrument.	

 	•	Real estate investments, private equity, and special situations investments. Investments in real estate, private equity, and special situations are generally classified as Net Asset Value as a Practical Expedient, since the underlying assets typically do not have publicly available observable inputs. The fund manager values the assets using various inputs and techniques depending on the nature of the underlying investments. Techniques may include purchase multiples for comparable transactions, comparable public company trading multiples, discounted cash flow analysis, prevailing market capitalization rates, recent sales of comparable investments, and independent third-party appraisals. The fair value of partnerships is determined by aggregating the value of the underlying assets less liabilities.	

The Company’s pro rata portion of fair values of pension plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. Absolute return investment assets are presented in the tables below based on the nature of the investment.
 	 	Fair Value Measurements Using	 	 	 	 	
As of December 31, 2016	 	Quoted Prices
in Active Markets
for Identical Assets
(Level 1)	 	 	Significant Other
Observable Inputs
(Level 2)	 	 	Net Asset Value
as a Practical
Expedient
(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	10,800	 	 	$	26,103	 	 	$	—	 	 	$	36,903	 	
International equity(*)	 	 	—	 	 	 	14,117	 	 	 	—	 	 	 	14,117	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	6,482	 	 	 	—	 	 	 	6,482	 	
Corporate bonds	 	 	—	 	 	 	3,099	 	 	 	—	 	 	 	3,099	 	
Pooled funds	 	 	—	 	 	 	5,039	 	 	 	—	 	 	 	5,039	 	
Cash equivalents and other	 	 	931	 	 	 	375	 	 	 	6,328	 	 	 	7,634	 	
Real estate investments	 	 	275	 	 	 	—	 	 	 	1,110	 	 	 	1,385	 	
Private equity	 	 	—	 	 	 	—	 	 	 	190	 	 	 	190	 	
Total	 	$	12,006	 	 	$	55,215	 	 	$	7,628	 	 	$	74,849	 	

(*) Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.

23

 	 	Pension plans	 	
As of December 31, 2015	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	Total	 	 	% of total	 	
 	 	(in thousands)	 	
Cash	 	$	300	 	 	$	21	 	 	$	—	 	 	$	321	 	 	 	1	%	
Equity securities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. large cap(a)	 	$	5,363	 	 	$	14,371	 	 	$	—	 	 	$	19,734	 	 	 	32	%	
U.S. small cap(a)	 	 	4,115	 	 	 	1,740	 	 	 	—	 	 	 	5,855	 	 	 	9	 	
International companies(b)	 	 	—	 	 	 	9,017	 	 	 	—	 	 	 	9,017	 	 	 	15	 	
Emerging markets(c)	 	 	—	 	 	 	1,992	 	 	 	—	 	 	 	1,992	 	 	 	3	 	
Total equity securities	 	$	9,478	 	 	$	27,120	 	 	$	—	 	 	$	36,598	 	 	 	59	%	
Fixed income securities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Corporate bonds(d)	 	$	—	 	 	$	6,528	 	 	$	—	 	 	$	6,528	 	 	 	10	%	
Other (or gov’t/muni bonds)	 	 	—	 	 	 	10,881	 	 	 	—	 	 	 	10,881	 	 	 	18	 	
Total fixed income securities	 	$	—	 	 	$	17,409	 	 	$	—	 	 	$	17,409	 	 	 	28	%	
Other types of investments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Global hedged equity(e)	 	$	—	 	 	$	—	 	 	$	2,900	 	 	$	2,900	 	 	 	5	%	
Absolute return(f)	 	 	—	 	 	 	—	 	 	 	3,075	 	 	 	3,075	 	 	 	5	 	
Private capital(g)	 	 	—	 	 	 	—	 	 	 	1,419	 	 	 	1,419	 	 	 	2	 	
Total other investments	 	$	—	 	 	$	—	 	 	$	7,394	 	 	$	7,394	 	 	 	12	%	
Total assets at fair value	 	$	9,778	 	 	$	44,550	 	 	$	7,394	 	 	$	61,722	 	 	 	100	%	
% of fair value hierarchy	 	 	16	%	 	 	72	%	 	 	12	%	 	 	100	%	 	 	 	 	

 	(a)	Includes funds that invest primarily in U.S. common stocks.	

 	(b)	Includes funds that invest primarily in foreign equity and equity-related securities.	

 	(c)	Includes funds that invest primarily in common stocks of emerging markets.	

 	(d)	Includes funds that invest primarily in investment grade debt and fixed income securities.	

 	(e)	Includes funds that invest in limited/general partnerships, managed accounts, and other investment entities issued by non-traditional firms or “hedge funds.”	

 	(f)	Includes funds that invest primarily in investment vehicles and commodity pools as a “fund of funds.”	

 	(g)	Includes funds that invest in private equity and small buyout funds, partnership investments, direct investments, secondary investments, directly/indirectly in real estate and may invest in equity securities of real estate related companies, real estate mortgage loans, and real estate mezzanine loans.	

The following is a reconciliation of the Company’s pension plan assets in Level 3 of the fair value hierarchy at December 31, 2015:
 	 	Global Hedged
Equity	 	 	Absolute Return	 	 	Private Capital	 	 	Total	 	
 	 	(in thousands) 	 	
Balance at December 31, 2014	 	$	2,043	 	 	$	2,959	 	 	$	1,409	 	 	$	6,411	 	
Actual return on plan assets	 	 	(82	)	 	 	116	 	 	 	(71	)	 	 	(37	)	
Purchases	 	 	975	 	 	 	—	 	 	 	—	 	 	 	975	 	
Sales	 	 	(36	)	 	 	—	 	 	 	81	 	 	 	45	 	
Balance at December 31, 2015	 	$	2,900	 	 	$	3,075	 	 	$	1,419	 	 	$	7,394	 	

There were no transfers out of Level 3 or between Level 1 and Level 2 in 2015. During 2016, the Level 3 assets were accounted for at net asset value as a practical expedient.

24

The fair values of other postretirement benefit plan assets as of December 31, 2016 and 2015 are presented below. These fair value measurements exclude cash, receivables related to investment income, pending investments sales, and payables related to pending investment purchases. For 2016, special situations (absolute return and hedge funds) investment assets are presented in the table below based on the nature of the investment.
 	 	Fair Value Measurements Using	 	
 	 	Quoted Prices
in Active Markets
for Identical Assets	 	 	Significant Other
Observable
Inputs	 	 	Net Asset Value
as a Practical
Expedient	 	 	 	 	
As of December 31, 2016	 	(Level 1)	 	 	(Level 2)	 	 	(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	
Domestic equity(*)	 	$	315	 	 	$	7,264	 	 	$	—	 	 	$	7,579	 	
International equity(*)	 	 	—	 	 	 	2,206	 	 	 	—	 	 	 	2,206	 	
Fixed income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. Treasury, government, and agency bonds	 	 	—	 	 	 	63	 	 	 	—	 	 	 	63	 	
Corporate bonds	 	 	—	 	 	 	28	 	 	 	—	 	 	 	28	 	
Pooled funds	 	 	—	 	 	 	2,942	 	 	 	—	 	 	 	2,942	 	
Cash equivalents and other	 	 	99	 	 	 	—	 	 	 	209	 	 	 	308	 	
Real estate investments	 	 	8	 	 	 	—	 	 	 	37	 	 	 	45	 	
Private equity	 	 	—	 	 	 	—	 	 	 	6	 	 	 	6	 	
Total	 	$	422	 	 	$	12,503	 	 	$	252	 	 	$	13,177	 	

(*)  Level 1 securities consist of actively traded stocks while Level 2 securities consist of pooled funds. Management believes that the portfolio is well-diversified with no significant concentrations of risk.
 	 	Other postretirement plans	 	
As of December 31, 2015	 	Level 1	 	 	Level 2	 	 	Level 3	 	 	Total	 	 	% of total	 	
 	 	(in thousands)	 	
Cash	 	$	122	 	 	$	—	 	 	$	—	 	 	$	122	 	 	 	1	%	
Equity securities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. large cap(a)	 	$	—	 	 	$	6,621	 	 	$	—	 	 	$	6,621	 	 	 	58	%	
International companies(b)	 	 	—	 	 	 	1,995	 	 	 	—	 	 	 	1,995	 	 	 	17	 	
Total equity securities	 	$	—	 	 	$	8,616	 	 	$	—	 	 	$	8,616	 	 	 	75	%	
Fixed income securities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Corporate bonds(c)	 	$	—	 	 	$	2,794	 	 	$	—	 	 	$	2,794	 	 	 	24	%	
Total fixed income securities	 	$	—	 	 	$	2,794	 	 	$	—	 	 	$	2,794	 	 	 	24	%	
Total assets at fair value	 	$	122	 	 	$	11,410	 	 	$	—	 	 	$	11,532	 	 	 	100	%	
% of fair value hierarchy	 	 	1	%	 	 	99	%	 	 	—	%	 	 	100	%	 	 	 	 	

 	(a)	Includes funds that invest primarily in U.S. common stocks.	

 	(b)	Includes funds that invest primarily in foreign equity and equity-related securities.	

 	(c)	Includes funds that invest primarily in common stocks of emerging markets.	

Employee Savings Plan

Southern Company Services, Inc. sponsors 401(k) defined contribution plans covering certain eligible employees. The AGL Resources Inc. 401(k) plans provide matching contributions of either 65% on up to 8% of an employee’s eligible compensation, or a 100% matching contribution on up to 3% of an employee’s eligible compensation, followed by a 75% matching contribution on up to the next 3% of an employee’s eligible compensation. Total matching contributions made to the AGL Resources Inc. 401(k) plans for each of the periods ended December 31, 2016 and 2015 were $1 million.

For employees not accruing a benefit under the AGL Plan, additional contributions made to the 401(k) plans for the period ended December 31, 2016 and 2015 were immaterial.

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3. CONTINGENCIES AND REGULATORY MATTERS

General Litigation Matters

The Company is assessing its alleged involvement in an incident that occurred in its service territory that resulted in several deaths, injuries, and property damage. The Company has been named as one of the defendants in several lawsuits related to this incident. At December 31, 2016, the Company recorded reserves for its potential exposure from this case. The ultimate outcome of this matter cannot be determined at this time.

The Company is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of these matters and such pending or potential litigation against the Company cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on the Company’s financial statements.

Environmental Matters

The Company’s operations are subject to extensive regulation by the state and federal environmental agencies under a variety of statutes and regulations governing environmental media, including the handling and disposal of waste and releases of hazardous substances. Compliance with these environmental requirements involves significant capital and operating costs to clean up affected sites. The Company conducts studies to determine the extent of any required clean up and has recognized in its financial statements the costs to clean up known impacted sites.

The Company is subject to environmental remediation liabilities associated with six former manufactured gas plant sites in New Jersey. Accrued environmental remediation costs of $106 million have been recorded in the balance sheets as of December 31, 2016, $29 million of which is expected to be incurred over the next 12 months. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the New Jersey BPU.

The Company’s ultimate environmental compliance strategy and future environmental capital expenditures will be affected by the final requirements of new or revised environmental regulations and the outcome of any legal challenges to the environmental rules. The ultimate outcome of these matters cannot be determined at this time.

In 2014, the Company reached a settlement with an insurance company for environmental claims relating to potential contamination at several manufactured gas plant sites. The terms of the settlement required the insurance company to pay the Company a total of $77 million in two installments. The Company received a $45 million installment in 2014 and the remaining $32 million in July 2015. The New Jersey BPU approved the use of the insurance proceeds to reduce the regulatory assets associated with environmental remediation costs that otherwise would have been recovered from Elizabethtown Gas customers.

Regulatory Matters

The Merger was approved by the New Jersey BPU on June 29, 2016. In connection with the Merger approval order, the Company was required to:

 	•	provide rate credits of $17.5 million to its customers; and	

 	•	file a rate case no later than September 1, 2016, with another rate case no later than three years after the 2016 rate case.	

See “Customer Refunds” and “Base Rate Case” below for additional information.

Regulatory Infrastructure Program

The Company has the following infrastructure improvement programs:

Elizabethtown Gas’ extension of the Aging Infrastructure Replacement (AIR) enhanced infrastructure program effective in 2013 allowed for infrastructure investment of $115 million over four years, and is focused on the replacement of aging cast iron in its pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a WACC of 6.65%. In conjunction with the general base rate case filed with the New Jersey BPU on September 1, 2016, the Company requested recovery of the AIR program. See “Base Rate Case” herein for additional information.

In 2014, the New Jersey BPU approved Natural Gas Distribution Utility Reinforcement Effort, a program that improved the Company’s distribution system’s resiliency against coastal storms and floods. Under the plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one-year period from August 2014 through September 2015. Effective November 2015, the Company increased its base rates for investments made under the program.

26

In September 2015, the Company filed the Safety, Modernization and Reliability Tariff plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel, and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered through a rider surcharge over a period of 10 years.

The ultimate outcome of these matters cannot be determined at this time.

Customer Refunds

In the third quarter 2016, the Company provided direct per-customer rate credits totaling $17.5 million to its customers in accordance with the Merger approval from the New Jersey BPU. These rate credits were allocated among the Company’s customer classes based on the base rate revenues reflected in the rates that resulted from its most recent base rate proceeding.

Base Rate Case

On September 1, 2016, the Company filed a general base rate case with the New Jersey BPU as required under its AIR program and in accordance with the Merger approval, requesting an increase in annual revenues of $19 million, based on an allowed return on equity of 10.25%. The Company expects the New Jersey BPU to issue an order on the filing in the third quarter 2017. The ultimate outcome of this matter cannot be determined at this time.

Unrecognized Ratemaking Amounts

The following table illustrates the Company’s authorized ratemaking amounts that are not recognized on its balance sheets. These amounts are primarily composed of an allowed equity rate of return on assets associated with the Company’s AIR program. These amounts will be recognized as revenues in the Company’s financial statements in the periods they are billable to customers.
 	 	(in thousands)	 	
December 31, 2016	 	$	5,535	 	
December 31, 2015	 	 	3,844	 	

4. INCOME TAXES

On behalf of the Company, Southern Company will file a consolidated federal income tax return and Southern Company Gas will file various state income tax returns. Under a joint consolidated income tax allocation agreement, each Southern Company subsidiary’s current and deferred tax expense is computed on a stand-alone basis and no subsidiary is allocated more current expense than would be paid if it filed a separate income tax return. In accordance with the Internal Revenue Service (IRS) regulations, the Company is jointly and severally liable for the federal tax liability. Prior to the Merger, the Company was a part of Southern Company Gas’ federal consolidated income tax return and various state income tax returns.

Current and Deferred Income Taxes

Details of income tax provisions for the years ended December 31, 2016 and 2015 are as follows:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Federal —	 	 	 	 	 	 	
Current	 	$	5,630	 	 	$	(852	)	
Deferred	 	 	6,661	 	 	 	17,430	 	
 	 	 	12,291	 	 	 	16,578	 	
State —	 	 	 	 	 	 	 	 	
Current	 	 	1,302	 	 	 	969	 	
Deferred	 	 	1,277	 	 	 	2,835	 	
 	 	 	2,579	 	 	 	3,804	 	
Amortization of investment tax credits	 	 	(119	)	 	 	(152	)	
Total	 	$	14,751	 	 	$	20,230	 	

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The tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases, which give rise to deferred tax assets and liabilities, are as follows:
 	 	2016	 	 	2015	 	
 	 	(in thousands)	 	
Deferred tax liabilities —	 	 	 	 	 	 	
Accelerated depreciation	 	$	208,605	 	 	$	185,274	 	
Property basis differences	 	 	23,262	 	 	 	25,767	 	
Regulatory assets associated with employee benefit obligations	 	 	15,525	 	 	 	—	 	
Other	 	 	7,558	 	 	 	11,825	 	
Total	 	 	254,950	 	 	 	222,866	 	
Deferred tax assets —	 	 	 	 	 	 	 	 	
Federal net operating loss	 	 	8,275	 	 	 	—	 	
Federal effect of state deferred taxes	 	 	12,426	 	 	 	10,609	 	
Employee benefit obligations	 	 	15,566	 	 	 	18,243	 	
Bad debt and insurance reserves	 	 	1,936	 	 	 	2,307	 	
Other	 	 	5,921	 	 	 	6,817	 	
Total	 	 	44,124	 	 	 	37,976	 	
Accumulated deferred income taxes, net	 	$	210,826	 	 	$	184,890	 	

In November 2015, the FASB issued ASU 2015-17, which simplifies the presentation of deferred income taxes. See Note 1 under “Recently Issued Accounting Standards” for additional information.

At December 31, 2016, the tax-related regulatory liabilities to be credited to customers were $673 thousand. These liabilities are primarily attributable to unamortized ITCs.

Deferred federal and state ITCs are amortized over the average life of the related property with such amortization normally applied as a credit to reduce depreciation in the statements of income. Credits amortized in this manner amounted to $119 thousand and $152 thousand for the years ended December 31, 2016 and 2015, respectively. At December 31, 2016, all ITCs available to reduce federal income taxes payable had been utilized.

Effective Tax Rate

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:
 	 	Years Ended December 31,	 	
 	 	2016	 	 	2015	 	
Federal statutory rate	 	 	35.0	%	 	 	35.0	%	
State income tax, net of federal deduction	 	 	5.9	 	 	 	5.9	 	
Other	 	 	(0.6	)	 	 	(1.7	)	
Effective income tax rate	 	 	40.3	%	 	 	39.2	%	

Unrecognized Tax Benefits

The Company has no unrecognized tax benefits for any period presented. The Company classifies interest on tax uncertainties as interest expense; however, the Company had no accrued interest or penalties for unrecognized tax benefits for any period presented.

It is reasonably possible that the amount of the unrecognized tax benefits could change within 12 months. The settlement of federal and state audits could impact the balances. At this time, an estimate of the range of reasonably possible outcomes cannot be determined.

Southern Company is a participant in the Compliance Assurance Process of the IRS. The audits by the IRS or any state have either concluded, or the statute of limitations has expired with respect to income tax examinations, for periods prior to 2012.

28

5. FINANCING

The following table provides maturity dates, year-to-date weighted average interest rates, and amounts outstanding for various debt securities and facilities that are included in the balance sheets.
 	 	 	 	 	December 31, 2016	 	 	December 31, 2015	 	
Dollars in thousands	 	Year(s) due	 	 	Weighted average
interest rate	 	 	Outstanding	 	 	Weighted average
interest rate	 	 	Outstanding	 	
Gas facility revenue bonds	 	 	2022-2033	 	 	 	1.3	%	 	$	180,100	 	 	 	0.9	%	 	$	180,100	 	
Affiliate promissory note	 	 	2034	 	 	 	7.2	 	 	 	167,528	 	 	 	10.0	 	 	 	115,830	 	
Total principal long-term debt	 	 	 	 	 	 	4.1	%	 	$	347,628	 	 	$	4.5	 %	 	 	295,930	 	
Unamortized debt issuance costs	 	 	 	 	 	 	n/a	 	 	$	(749	)	 	$	n/a	 	 	 	(816	)	
Total debt	 	 	 	 	 	 	n/a	 	 	$	346,879	 	 	$	n/a	 	 	 	295,114	 	

Gas Facility Revenue Bonds

The Company is party to a series of loan agreements with the New Jersey Economic Development Authority under which, a series of gas facility revenue bonds have been issued. These revenue bonds are issued by state agencies to investors, and proceeds from each issuance then are loaned to the Company. Southern Company Gas fully and unconditionally guarantees all of the Company’s gas facility revenue bonds.

Affiliate Promissory Note

Pivotal Utility entered into a promissory note with Southern Company Gas (Affiliate Promissory Note) for the purpose of refinancing its short-term debt and recapitalizing the capital structure of Pivotal Utility and those of its utility operating divisions including the Company’s, in accordance with the target capitalization of 45% and with authorization of the New Jersey BPU. The Affiliate Promissory Note is adjusted periodically to maintain the appropriate targeted capitalization percentages. During 2016, $67.2 million was converted from the Affiliate Promissory Note to equity in order to maintain the target capitalization ratio. The Affiliate Promissory Note is due December 31, 2034 and had an initial interest rate at December 31, 2004 of 6.3%, which adjusts on a periodic basis based upon weighted average costs and expenses of borrowing the then-outstanding long-term debt of both Southern Company Gas and Southern Company Gas Capital Corporation, a 100%-owned financing subsidiary of Southern Company Gas. As of December 31, 2016, the effective interest rate on this note was 7.2% which consists of two components. The first is incurred equal to the weighted average costs that is applied to the principal amount of the Affiliate Promissory Note. The second component is an adjustment to increase the effective interest incurred on long-term debt other than the Affiliate Promissory Note to the weighted average cost applicable to the Affiliate Promissory Note.

6. COMMITMENTS

Pipeline Charges, Storage Capacity, and Gas Supply

Pipeline charges, storage capacity, and gas supply include charges recoverable through a natural gas cost recovery mechanism, or alternatively, billed to marketers of natural gas as well as demand charges associated with Sequent Energy Management, L.P. (Sequent), a wholly-owned subsidiary of Southern Company Gas that engages in wholesale marketing of natural gas supply services.

29

Contractual Obligations

Contractual obligations at December 31, 2016 were as follows:
 	 	2017	 	 	 	2018-2019	 	 	 	2020-2021	 	 	After 2021	 	 	Total	 	
 	 	(in thousands)	 	
Long-term debt(a) _	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Principal	 	$	—	 	 	$	—	 	 	$	—	 	 	$	346,879	 	 	 	346,879	 	
Interest	 	 	2,313	 	 	 	4,625	 	 	 	4,625	 	 	 	16,969	 	 	 	28,532	 	
Pipeline charges, storage capacity, and gas supply (b)	 	 	50,341	 	 	 	86,810	 	 	 	71,549	 	 	 	256,587	 	 	 	465,287	 	
Operating leases(c)	 	 	4,082	 	 	 	7,946	 	 	 	8,269	 	 	 	1,394	 	 	 	21,691	 	
Asset management agreements(d)	 	 	4,250	 	 	 	6,375	 	 	 	—	 	 	 	—	 	 	 	10,625	 	
Standby letters of credit and performance/surety bonds (e)	 	 	576	 	 	 	116	 	 	 	—	 	 	 	—	 	 	 	692	 	
Other purchase commitments(f)	 	 	28,875	 	 	 	1,000	 	 	 	—	 	 	 	—	 	 	 	29,875	 	
Total	 	$	90,437	 	 	$	106,872	 	 	$	84,443	 	 	$	621,829	 	 	$	903,581	 	

(a)	Amounts are reflected based on final maturity dates. The Company plans to continue, when economically feasible, to retire higher-cost securities and replace these obligations with lower-cost capital if market conditions permit. Variable rate interest obligations are estimated based on rates at January 1, 2017 and do not include interest on the affiliated promissory note.	

(b)	Includes charges recoverable through a natural gas cost recovery mechanism, subject to review by the New Jersey BPU.	

(c)	Certain operating leases have provisions for step rent or escalation payments and certain lease concessions are accounted for by recognizing the future minimum lease payments on a straight-line basis over the respective minimum lease terms. However, this accounting treatment does not affect the future annual operating lease cash obligations as shown herein. The Company’s operating leases are primarily related to equipment purchases and real estate licenses.	

(d)	Represent fixed-fee minimum payments for Sequent’s affiliated asset management agreements.	

(e)	Guarantees are provided to certain municipalities and other agencies in support of payment obligations.	

(f)	Primarily consists of contractual environmental remediation liabilities that are generally recoverable through base rates or rate rider mechanisms.	

Indemnities

In certain instances, the Company has undertaken to indemnify current property owners and others against costs associated with the effects and/or remediation of contaminated sites for which it may be responsible under applicable federal or state environmental laws, generally with no limitation as to the amount. These indemnifications relate primarily to ongoing coal tar cleanup. See Note 3 under “Environmental Matters” for additional information. The Company believes that the likelihood of payment under its other environmental indemnifications is remote. No liability has been recorded for such indemnifications as the fair value was inconsequential at inception.

7. FAIR VALUE MEASUREMENTS

Fair value measurements are based on inputs of observable and unobservable market data that a market participant would use in pricing the asset or liability. The use of observable inputs is maximized where available and the use of unobservable inputs is minimized for fair value measurement and reflects a three-tier fair value hierarchy that prioritizes inputs to valuation techniques used for fair value measurement. See Note 1 for additional information.

As of December 31, 2016, assets measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)	 	 	Significant
Other
Observable
Inputs
(Level 2)	 	 	Significant
Unobservable
Inputs
(Level 3)	 	 	Net Asset
Value as a
Practical
Expedient
(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives	 	$	—	 	 	$	8,385	 	 	$	—	 	 	$	—	 	 	$	8,385	 	

30

As of December 31, 2015, liabilities measured at fair value on a recurring basis during the period, together with their associated level of the fair value hierarchy, were as follows:
 	 	Fair Value Measurements Using	 	 	 	 	
 	 	Quoted Prices
in Active
Markets for
Identical Assets
(Level 1)	 	 	Significant
Other
Observable
Inputs
(Level 2)	 	 	Significant
Unobservable
Inputs
(Level 3)	 	 	Net Asset
Value as a
Practical
Expedient
(NAV)	 	 	Total	 	
 	 	(in thousands)	 	
Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives	 	$	—	 	 	$	13,858	 	 	$	—	 	 	$	—	 	 	$	13,858	 	

Valuation Methodologies

The energy-related derivatives primarily consist of exchange-traded and non-exchange-traded derivatives such as over-the-counter forwards and options. These are standard products used within the energy industry and are valued using the market approach. The inputs used are mainly from observable market sources, such as forward natural gas prices and implied volatility. See Note 8 for additional information on how these derivatives are used.

8. DERIVATIVES

The Company is exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. To manage the volatility attributable to these exposures, the Company nets its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to the Company’s policies in areas such as counterparty exposure and risk management practices. The Company’s policy is that derivatives are to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions are monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and are presented on a net basis. See Note 7 for additional information. In the statements of cash flows, the cash impacts of settled energy-related are recorded as operating activities.

Energy-Related Derivatives

The Company enters into energy-related derivatives to hedge exposures to natural gas and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, The Company has limited exposure to market volatility in prices of natural gas. The Company manages fuel-hedging programs, implemented per the guidelines of the New Jersey BPU, through the use of financial derivative contracts, which is expected to continue to mitigate price volatility.

Energy-related derivative contracts are accounted for under one of three methods:

 	•	Regulatory Hedges - Energy-related derivative contracts which are designated as regulatory hedges relate primarily to the Company’s fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then are included in the cost of natural gas as the underlying natural gas is used in operations and ultimately recovered through cost recovery clauses.	

 	•	Cash Flow Hedges - Gains and losses on energy-related derivatives designated as cash flow hedges (which are mainly used to hedge anticipated purchases and sales) are initially deferred in OCI before being recognized in the statements of income in the same period as the hedged transactions are reflected in earnings.	

 	•	Not Designated - Gains and losses on energy-related derivative contracts that are not designated or fail to qualify as hedges are recognized in the statements of income in the period of change.	

At December 31, 2016, the net volume of energy-related derivative contracts for natural gas positions totaled 18 billion cubic feet for the Company, together with the longest hedge date of 2018 over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions.

31

Derivative Financial Statement Presentation and Amounts

The Company’s derivative contracts are subject to master netting arrangements or similar agreements and are reported net on its financial statements. Some of these energy-related derivative contracts may contain certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements. At December 31, 2016 and 2015, the fair value of energy-related derivatives was reflected in the balance sheets as follows:
 	  	 	Asset Derivatives	 	 	 	Liability Derivatives	 	
Derivative
Category	Balance Sheet Location	 	December 31,
2016	 	 	December 31,
2015	 	Balance Sheet
Location	 	December 31,
2016	 	 	December 31,
2015	 	
 	  	 	(in thousands)	 	 	(in thousands)	 	
Derivatives designated as hedging instruments for regulatory purposes	 	 	 	 	 	 	 	 	 	 	 	 	 	
Energy-related derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets from risk management activities – current	 	$	7,473	 	 	$	—	 	Liabilities from risk management activities – current	 	$	—	 	 	$	12,291	 	
Assets from risk management activities – deferred	 	 	912 	 	 	 	— 	 	Liabilities from risk management activities – deferred	 	 	—	 	 	 	1,567	 	
Total derivatives designated as hedging instruments for regulatory purposes	 	$	8,385	 	 	$	—	 	 	 	$	—	 	 	$	13,858	 	
Gross amounts of recognized assets and liabilities (a)	 	$	8,385	 	 	$	—	 	 	 	$	—	 	 	$	13,858	 	
Gross amounts offset in the balance sheet	 	$	—	 	 	$	—	 	 	 	$	—	 	 	$	—	 	
Net amounts of derivatives assets and liabilities, presented in the balance sheet (b)	 	$	8,385	 	 	$	—	 	 	 	$	—	 	 	$	13,858	 	

(a) The gross amounts of recognized assets and liabilities are netted on the balance sheets to the extent that there were netting arrangements with the counterparties.

(b) As of December 31, 2016 and 2015, letters of credit from counterparties offset an immaterial portion of these assets under master netting arrangements.

At December 31, 2016 and 2015, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
 	  	 	Unrealized Losses	 	 	 	Unrealized Gains	 	
Derivative
Category	Balance Sheet
Location	 	December 31,
2016	 	 	December 31,
2015	 	Balance Sheet
Location	 	December 31,
2016	 	 	December 31,
2015	 	
 	 	(in thousands) 	 	 	 	(in thousands) 	 	
Energy-related derivatives:	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other regulatory assets, current	 	$	—	 	 	$	(12,291	)	Other regulatory liabilities, current	 	$	7,473	 	 	$	—	 	
Other regulatory assets, deferred	 	 	—	 	 	 	(1,567	)	Other regulatory liabilities, deferred	 	 	912	 	 	 	—	 	
Total energy-related derivative gains (losses)	 	$	—	 	 	$	(13,858	)	 	 	$	8,385	 	 	$	—	 	

Contingent Features

The Company does not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There are certain derivatives that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. At December 31, 2016, the Company had no collateral posted with derivative counterparties to satisfy these arrangements.

At December 31, 2016, the fair value of derivative liabilities with contingent features and the maximum potential collateral requirements arising from the credit-risk-related contingent features were immaterial.

32

Generally, collateral may be provided by a guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against fair value amounts recognized for derivatives executed with the same counterparty.

The Company is exposed to losses related to financial instruments in the event of counterparties’ nonperformance. The Company only enters into agreements and material transactions with counterparties that have investment grade credit ratings by Moody’s Investors Service Inc. and S&P Global Ratings or with counterparties who have posted collateral to cover potential credit exposure. The Company has also established risk management policies and controls to determine and monitor the creditworthiness of counterparties in order to mitigate its exposure to counterparty credit risk.

The Company also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When the Company is engaged in more than one outstanding derivative transaction with the same counterparty and it also has a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of the Company’s credit risk. The Company also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable the Company to net certain assets and liabilities by counterparty. The Company also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. The Company may require counterparties to pledge additional collateral when deemed necessary. Therefore, the Company does not anticipate a material adverse effect on the financial statements as a result of counterparty nonperformance.

9. AFFILIATE TRANSACTIONS

The Company has agreements with Sequent for transportation and storage capacity to meet natural gas demands. The following table provides additional information on the Company’s asset management agreements with Sequent.
 	 	 	 	 	 	Profit sharing / fees payments	 	
Expiration date	Type of fee structure	 	Annual fee	 	 	2016	 	 	2015	 	
 	 	 	 	 	 	(in thousands)	 	
March 2019	Tiered	 	 	 	(*) 	 	$	15,043	 	 	$	28,617	 	

(*)	In March 2014, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent for five years. This renewed agreement began on April 1, 2014 and requires Sequent to pay minimum annual fees of $4.25 million to Elizabethtown Gas and includes tiered margin sharing levels between Elizabethtown Gas and Sequent.	

Amounts Due to Affiliates

The Company had $55.2 million and $50.0 million in payable at December 31, 2016 and 2015, respectively, which was due to Southern Company Gas, primarily related to the participation in the Southern Company Gas money pool. The Company also had $167.5 million and $115.8 million outstanding at December 31, 2016 and 2015, respectively, related to a promissory note with Southern Company Gas. See Note 5 for additional information on the Affiliate Promissory Note.

The Company also engages in transactions with Southern Company Gas’ affiliates consistent with its services and tax allocation agreements.

10. SUBSEQUENT EVENTS

Management evaluated subsequent events for potential recognition and disclosure through March 31, 2017, the date these financial statements were available to be issued, and determined that no significant events have occurred subsequent to period end.

33

Exhibit 99.3
 
Elizabethtown Gas
 
(A former division of Pivotal Utility Holdings, Inc., a formerly wholly-owned subsidiary of Southern Company Gas)

Condensed Financial Statements as of June 30, 2018 and December 31, 2017 and for the Six Months Ended June 30, 2018 and 2017 (Unaudited)

INDEX TO THE CONDENSED FINANCIAL STATEMENTS
 	 	 	Page Number	
Condensed Financial Statements (Unaudited)	 	
 	Condensed Statements of Income	3	
 	Condensed Statements of Comprehensive Income	3	
 	Condensed Statements of Cash Flows	4	
 	Condensed Balance Sheets	5	
Notes to Condensed Financial Statements (Unaudited)	 	
 	A	Introduction	7	
 	B	Contingencies and Regulatory Matters	8	
 	C	Revenue From Contracts With Customers	9	
 	D	Stockholder's Equity	10	
 	E	Financing	10	
 	F	Retirement Benefits	11	
 	G	Income Taxes	12	
 	H	Derivatives	12	
 	I	Disposition	14	
 	J	Affiliate Transactions	15	
 	K	Subsequent Events	16	
 
2

ELIZABETHTOWN GAS
 
CONDENSED STATEMENTS OF INCOME (UNAUDITED)
 
 	 	For The Six Months Ended June 30,	 	
 	 	2018	 	 	2017	 	
 	 	(in thousands)	 	
Operating Revenues:	 	 	 	 	 	 	
Natural gas revenues	 	$	190,655	 	 	$	169,441	 	
Alternative revenue programs	 	 	(6,337	)	 	 	4,667	 	
Total operating revenues	 	 	184,318	 	 	 	174,108	 	
Operating Expenses:	 	 	 	 	 	 	 	 	
Cost of natural gas	 	 	87,472	 	 	 	79,922	 	
Other operations and maintenance	 	 	35,464	 	 	 	32,722	 	
Depreciation and amortization	 	 	13,826	 	 	 	13,249	 	
Taxes other than income taxes	 	 	1,713	 	 	 	3,177	 	
Total operating expenses	 	 	138,475	 	 	 	129,070	 	
Operating Income	 	 	45,843	 	 	 	45,038	 	
Other Income and (Expense):	 	 	 	 	 	 	 	 	
Interest expense, net of amounts capitalized	 	 	(10,165	)	 	 	(7,738	)	
Other income (expense), net	 	 	348	 	 	 	1,785	 	
Total other income and (expense)	 	 	(9,817	)	 	 	(5,953	)	
Earnings Before Income Taxes	 	 	36,026	 	 	 	39,085	 	
Income taxes	 	 	10,586	 	 	 	16,481	 	
Net Income	 	$	25,440	 	 	$	22,604	 	

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
 	 	For The Six Months Ended June 30,	 	
 	 	2018	 	 	2017	 	
 	 	(in thousands)	 	
Net Income	 	$	25,440	 	 	$	22,604	 	
Other comprehensive income, net of tax	 	 	—	 	 	 	—	 	
Comprehensive Income	 	$	25,440	 	 	$	22,604	 	

The accompanying notes are an integral part of these condensed financial statements.
 
3

ELIZABETHTOWN GAS

CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED)
 	 	For The Six Months Ended June 30,	 	
 	 	2018	 	 	2017	 	
 	 	(in thousands)	 	
Operating Activities:	 	 	 	 	 	 	
Net income	 	$	25,440	 	 	$	22,604	 	
Adjustments to reconcile net income to net cash provided from operating activities —	 	 	 	 	 	 	 	 	
Depreciation and amortization, total	 	 	13,826	 	 	 	13,249	 	
Deferred income taxes	 	 	1,077	 	 	 	8,215	 	
Mark-to-market adjustments	 	 	(2,006	)	 	 	7,665	 	
Other, net	 	 	1,634	 	 	 	(17,046	)	
Changes in certain current assets and liabilities —	 	 	 	 	 	 	 	 	
—Receivables	 	 	25,680	 	 	 	22,944	 	
—Natural gas for sale	 	 	(515	)	 	 	(816	)	
—Prepaid taxes	 	 	1,486	 	 	 	348	 	
—Other current assets	 	 	2,311	 	 	 	(4,737	)	
—Accounts payable	 	 	198,293	 	 	 	38,200	 	
—Accrued compensation	 	 	848	 	 	 	56	 	
—Other current liabilities	 	 	6,925	 	 	 	(7,344	)	
Net cash provided from operating activities	 	 	274,999	 	 	 	83,338	 	
Investing Activities:	 	 	 	 	 	 	 	 	
Property additions	 	 	(62,990	)	 	 	(52,988	)	
Cost of removal, net of salvage	 	 	(3,577	)	 	 	(732	)	
Change in construction payables, net	 	 	396	 	 	 	(4,656	)	
Other investing activities	 	 	—	 	 	 	228	 	
Net cash used for investing activities	 	 	(66,171	)	 	 	(58,148	)	
Financing Activities:	 	 	 	 	 	 	 	 	
Redemptions - gas facility revenue bonds	 	 	(180,100	)	 	 	—	 	
Dividends to parent	 	 	(28,722	)	 	 	(25,190	)	
Other	 	 	(6	)	 	 	—	 	
Net cash used for financing activities	 	 	(208,828	)	 	 	(25,190	)	
Net Change in Cash and Cash Equivalents	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at Beginning of Period	 	 	—	 	 	 	—	 	
Cash and Cash Equivalents at End of Period	 	$	—	 	 	$	—	 	
Supplemental Cash Flow Information:	 	 	 	 	 	 	 	 	
Cash paid during the period for —	 	 	 	 	 	 	 	 	
Interest (net of $219 and $200 capitalized for 2018 and 2017, respectively)	 	$	7,684	 	 	$	4,628	 	
Income taxes, net	 	 	694	 	 	 	1,062	 	
Noncash Transactions — Accrued property additions at end of period	 	 	7,512	 	 	 	5,395	 	

The accompanying notes are an integral part of these condensed financial statements.
 
4

ELIZABETHTOWN GAS

CONDENSED BALANCE SHEETS (UNAUDITED)
Assets	 	At June 30, 2018	 	 	At December 31, 2017	 	
 	 	(in thousands)	 	
Receivables —	 	 	 	
Customer accounts receivable	 	$	30,089	 	 	$	29,078	 	
Unbilled revenues	 	 	4,992	 	 	 	35,209	 	
Other accounts and notes receivable	 	 	10,185	 	 	 	6,659	 	
Accumulated provision for uncollectible accounts	 	 	(6,441	)	 	 	(4,904	)	
Materials and supplies	 	 	321	 	 	 	307	 	
Natural gas for sale	 	 	21,428	 	 	 	20,913	 	
Prepaid taxes	 	 	23,460	 	 	 	21,544	 	
Regulatory assets, current	 	 	8,845	 	 	 	7,922	 	
Other current assets	 	 	241	 	 	 	141	 	
Total current assets	 	 	93,120	 	 	 	116,869	 	
Property, Plant, and Equipment:	 	 	 	 	 	 	 	 	
In service	 	 	1,338,589	 	 	 	1,290,302	 	
Less: Accumulated depreciation	 	 	266,030	 	 	 	267,019	 	
Plant in service, net of depreciation	 	 	1,072,559	 	 	 	1,023,283	 	
Construction work in progress	 	 	27,889	 	 	 	32,052	 	
Total property, plant, and equipment	 	 	1,100,448	 	 	 	1,055,335	 	
Other Property and Investments:	 	 	 	 	 	 	 	 	
Goodwill	 	 	126,020	 	 	 	126,020	 	
Deferred Charges and Other Assets:	 	 	 	 	 	 	 	 	
Regulatory assets, deferred	 	 	119,954	 	 	 	131,590	 	
Other deferred charges and assets	 	 	40	 	 	 	40	 	
Total deferred charges and other assets	 	 	119,994	 	 	 	131,630	 	
Total Assets	 	$	1,439,582	 	 	$	1,429,854	 	

The accompanying notes are an integral part of these condensed financial statements.
 
5

ELIZABETHTOWN GAS

CONDENSED BALANCE SHEETS (UNAUDITED)
Liabilities and Stockholder's Equity	 	At June 30, 2018	 	 	At December 31, 2017	 	
 	 	(in thousands)	 	
Current Liabilities:	 	 	 	 	 	 	
Due to affiliates	 	$	280,911	 	 	$	81,903	 	
Accounts payable	 	 	13,282	 	 	 	12,751	 	
Customer deposits	 	 	5,233	 	 	 	7,299	 	
Accrued taxes —	 	 	 	 	 	 	 	 	
Other accrued taxes	 	 	3,542	 	 	 	140	 	
Accrued compensation	 	 	4,294	 	 	 	3,445	 	
Regulatory liabilities, current	 	 	17,898	 	 	 	10,197	 	
Accrued environmental remediation, current	 	 	7,100	 	 	 	9,700	 	
Other current liabilities	 	 	1,697	 	 	 	3,200	 	
Total current liabilities	 	 	333,957	 	 	 	128,635	 	
Long-term Debt (See notes)	 	 	268,406	 	 	 	447,825	 	
Deferred Credits and Other Liabilities:	 	 	 	 	 	 	 	 	
Accumulated deferred income taxes	 	 	133,460	 	 	 	130,889	 	
Deferred credits related to income tax	 	 	119,572	 	 	 	121,041	 	
Other cost of removal obligations	 	 	50,391	 	 	 	57,819	 	
Accrued environmental remediation, deferred	 	 	70,191	 	 	 	75,437	 	
Employee benefit obligations	 	 	18,177	 	 	 	18,909	 	
Other deferred credits and liabilities	 	 	1,310	 	 	 	1,894	 	
Total deferred credits and other liabilities	 	 	393,101	 	 	 	405,989	 	
Total Liabilities	 	 	995,464	 	 	 	982,449	 	
Stockholder's Equity:	 	 	 	 	 	 	 	 	
Common stock, no par value; 12,807,111 shares authorized, issued, and outstanding	 	 	—	 	 	 	—	 	
Paid-in capital	 	 	166,372	 	 	 	166,377	 	
Retained earnings	 	 	277,746	 	 	 	281,028	 	
Total Stockholder's Equity	 	 	444,118	 	 	 	447,405	 	
Total Liabilities and Stockholder's Equity	 	$	1,439,582	 	 	$	1,429,854	 	

The accompanying notes are an integral part of these condensed financial statements.
 
6

ELIZABETHTOWN GAS

NOTES TO THE CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

(A)	INTRODUCTION	

General

Elizabethtown Gas is a former division of Pivotal Utility Holdings, Inc. (Pivotal Utility) that is engaged in the sale and distribution of natural gas to approximately 291 thousand customers in New Jersey. On July 1, 2018, Pivotal Utility completed the sale of substantially all of the Elizabethtown Gas assets to South Jersey Industries, Inc. (SJI), who continues to use these assets for the same purpose. See Note (I) for additional information. Until July 29, 2018, Pivotal Utility was a wholly-owned subsidiary of Southern Company Gas. The assets from Elizabethtown Gas that were not sold to SJI were retained by Southern Company Gas.

Elizabethtown Gas is subject to regulation by the New Jersey Board of Public Utilities (New Jersey BPU). As such, Elizabethtown Gas' financial statements reflect the effects of rate regulation in accordance with accounting principles generally accepted in the United States of America (GAAP) and comply with the accounting policies and practices prescribed by the New Jersey BPU. The preparation of financial statements in conformity with GAAP requires the use of estimates, and the actual results may differ from those estimates.

The financial statements have been prepared without audit. The Condensed Balance Sheet as of December 31, 2017 has been derived from the audited financial statements of Elizabethtown Gas (2017 Financial Statements). In the opinion of management, the information furnished herein reflects all adjustments, which, except as otherwise disclosed, are of a normal recurring nature, necessary to present fairly the results of operations for the six months ended June 30, 2018 and 2017. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations, although Elizabethtown Gas believes that the disclosures are adequate to make the information presented not misleading. Disclosures which would substantially duplicate the disclosures in the 2017 Financial Statements and details which have not changed significantly in amount or composition since the issuance of the 2017 Financial Statements are generally omitted from these condensed financial statements unless specifically required by GAAP. Therefore, these condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in the 2017 Financial Statements. Due to the seasonal variations in the demand for natural gas, operating results for the periods presented are not necessarily indicative of the operating results to be expected for the full year.

Certain prior year data in the financial statements has been reclassified to conform to the current year presentation.

Recently Issued Accounting Standards

See Note 1 to the 2017 Financial Statements under "Recently Issued Accounting Standards" for information regarding ASU 2016-02,  Leases (Topic 842) .

Revenue

In 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) 606, Revenue from Contracts with Customers  (ASC 606) ,  replacing the existing accounting standard and industry-specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The underlying principle of the standard is to recognize revenue to depict the transfer of goods or services to customers at the amount expected to be collected. ASC 606 became effective on January 1, 2018 and Elizabethtown Gas adopted it using the modified retrospective method applied to open contracts and only to the version of the contracts in effect as of January 1, 2018. In accordance with the modified retrospective method, Elizabethtown Gas' previously issued financial statements have not been restated to comply with ASC 606. Elizabethtown Gas did not have a cumulative-effect adjustment to retained earnings. The adoption of ASC 606 had no significant impact on the timing of revenue recognition compared to previously reported results; however, it requires enhanced disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows arising from contracts with customers.
 
7

The application of ASC 606 to revenues from contracts with customers did not result in changes to the financial statements of Elizabethtown Gas as of and for the six months ended June 30, 2018 compared to previously recognized guidance. See Note (C) for additional information.

Other

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost  (ASU 2017-07). ASU 2017-07 requires that an employer report the service cost component in the same line item or items as other compensation costs and requires the other components of net periodic pension and postretirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component is eligible for capitalization, when applicable. Elizabethtown Gas adopted ASU 2017-07 effective January 1, 2018 with no material impact on its financial statements. ASU 2017-07 has been applied retrospectively for the presentation of the service cost component and the other components of net periodic benefit costs in the statements of income for Elizabethtown Gas. The requirement to limit capitalization to the service cost component of net periodic benefit costs has been applied on a prospective basis from the date of adoption. The presentation changes resulted in an increase in operating income and a decrease in other income for the six months ended June 30, 2018 and a decrease in operating income and an increase in other income for the six months ended June 30, 2017.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities  (ASU 2017-12). ASU 2017-12 makes more financial and non-financial hedging strategies eligible for hedge accounting, amends the related presentation and disclosure requirements, and simplifies hedge effectiveness assessment requirements. ASU 2017-12 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. Elizabethtown Gas adopted ASU 2017-12 effective January 1, 2018 with no material impact on its financial statements. See Note (H) for disclosures required by ASU 2017-12.

(B)	CONTINGENCIES AND REGULATORY MATTERS	

See Note 3 to the 2017 Financial Statements for information relating to various lawsuits, other contingencies, and regulatory matters.

General Litigation Matters

Elizabethtown Gas is assessing its alleged involvement in an incident that occurred in its service territory that resulted in several deaths, injuries, and property damage. Elizabethtown Gas has been named as one of the defendants in several lawsuits related to this incident. At June 30, 2018 and December 31, 2017, Elizabethtown Gas had reserved for all of its potential exposure from this incident. Subsequent to June 30, 2018, all but one of the lawsuits were settled. The ultimate outcome of the remaining lawsuit cannot be determined at this time.

Elizabethtown Gas is subject to certain claims and legal actions arising in the ordinary course of business. The ultimate outcome of such pending or potential litigation against Elizabethtown Gas cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Elizabethtown Gas' financial statements.
 
8

Environmental Remediation

Elizabethtown Gas must comply with environmental laws and regulations that cover the handling and disposal of waste and releases of hazardous substances. Under these various laws and regulations, Elizabethtown Gas could incur substantial costs to clean up affected sites. Elizabethtown Gas has received authority from the New Jersey BPU to recover approved environmental compliance costs through regulatory mechanisms. These regulatory mechanisms are adjusted annually or as necessary within limits approved by the New Jersey BPU.

Elizabethtown Gas' environmental remediation liability was $77.3 million and $85.1 million as of June 30, 2018 and December 31, 2017, respectively, based on the estimated cost of environmental investigation and remediation associated with six former manufactured gas plant operating sites. These environmental remediation expenditures are recoverable from customers through rate mechanisms approved by the New Jersey BPU.

The ultimate outcome of these matters cannot be determined at this time; however, as a result of the regulatory treatment for environmental remediation expenses described above, the final disposition of these matters is not expected to have a material impact on Elizabethtown Gas' financial statements.

In June 2018, Pivotal Utility reached insurance settlements for environmental claims relating to potential contamination at its MGP sites. In conjunction with the sale of the Elizabethtown Gas assets to SJI, SJI has the right to receive $9.2 million of the proceeds from the settlements that is assigned to Elizabethtown Gas, which it will share with its customers through rates.

Regulatory Matters

Tax Reform Legislation

The New Jersey BPU issued an order effective January 1, 2018 that requires Elizabethtown Gas to defer as a regulatory liability the impact of the Tax Reform Legislation, including the reduction in the corporate income tax rate to 21% and the impact of excess deferred income taxes. On June 22, 2018, the New Jersey BPU approved a $12 million reduction in Elizabethtown Gas' annual base rate revenues. At June 30, 2018, Elizabethtown Gas had $5.4 million in regulatory liabilities associated with the impact of the Tax Reform Legislation prior to the implementation of the final approved rate, which will be refunded to customers in the third quarter 2018.

(C)	REVENUE FROM CONTRACTS WITH CUSTOMERS	

Elizabethtown Gas generates revenues from a variety of sources, some of which are excluded from the scope of ASC 606, such as leases and derivatives. See Note (A) under "Recently Adopted Accounting Standards – Revenue" for additional information on the adoption of ASC 606 for revenue from contracts with customers.

The majority of the revenues of Elizabethtown Gas are generated from contracts with natural gas distribution customers. Revenues from this integrated service to deliver natural gas when and if called upon by the customer is recognized as a single performance obligation satisfied over time and is recognized at a tariff rate as natural gas is delivered to the customer during the month. Elizabethtown Gas excludes taxes imposed on the customer and collected on behalf of governmental agencies to be remitted to these agencies from the transaction price in determining the revenue related to contracts with a customer.

Elizabethtown Gas generally has a right to consideration in an amount that corresponds directly with the value to the customer of the entity's performance completed to date and may recognize revenue in the amount to which the entity has a right to invoice and has elected to recognize revenue for its sales of natural gas using the invoice practical expedient. In addition, payment for goods and services rendered is typically due in the subsequent month following satisfaction of Elizabethtown Gas' performance obligation.
 
9

The following table disaggregates revenue sources for the six months ended June 30, 2018:
 	 	For the Six Months
Ended June 30, 2018	 	
 	 	(in thousands)	 	
Operating revenues	 	 	 	
Natural gas distribution revenues	 	 	 	
Residential	 	$	130,841	 	
Commercial	 	 	37,033	 	
Transportation	 	 	22,022	 	
Industrial	 	 	1,647	 	
Other(a)	 	 	(888	)	
Alternative revenue programs(b)	 	 	(6,337	)	
Total operating revenues	 	$	184,318	 	

(a)	Other operating revenues include $312 thousand of revenues not accounted for under ASC 606.	

(b)	See Note 1 to the 2017 Financial Statements under "Revenues" for additional information on Elizabethtown Gas' alternative revenue programs	

(D)	STOCKHOLDER'S EQUITY	

The following table presents year-to-date changes in stockholder's equity of Elizabethtown Gas:
 	 	Number of Common
Shares Issued	 	 	Total Stockholder's
Equity	 	
 	 	(in thousands)	 	 	(in thousands)	 	
Balance at December 31, 2017	 	 	12,807	 	 	$	447,405	 	
Net income	 	 	—	 	 	 	25,440	 	
Dividends to parent	 	 	—	 	 	 	(28,722	)	
Stock-based compensation	 	 	—	 	 	 	(5	)	
Balance at June 30, 2018	 	 	12,807	 	 	$	444,118	 	
Balance at December 31, 2016	 	 	12,807	 	 	$	404,459	 	
Net income	 	 	—	 	 	 	22,604	 	
Dividends to parent	 	 	—	 	 	 	(25,190	)	
Balance at June 30, 2017	 	 	12,807	 	 	$	401,873	 	

(E)	FINANCING	

See Note 5 to the 2017 Financial Statements under "Gas Facility Revenue Bonds and "Affiliate Promissory Note" for additional financing information.

Gas Facility Revenue Bonds

Elizabethtown Gas was party to a series of loan agreements with the New Jersey Economic Development Authority under which, a series of gas facility revenue bonds have been issued. These revenue bonds were issued by state agencies to investors, and proceeds from each issuance then were loaned to Elizabethtown Gas. Southern Company Gas fully and unconditionally guaranteed all of Elizabethtown Gas' gas facility revenue bonds.

In the second quarter 2018, the full $180 million aggregate principal amount of gas facility revenue bonds were redeemed using proceeds from borrowings under Southern Company Gas' utility money pool.
 
10

Affiliate Promissory Note

Pivotal Utility entered into a promissory note with Southern Company Gas (Affiliate Promissory Note) for the purpose of refinancing its short-term debt and recapitalizing the capital structure of Pivotal Utility and those of its utility operating divisions including Elizabethtown Gas, in accordance with the target capitalization of 47% and with authorization of the New Jersey BPU. The Affiliate Promissory Note was adjusted annually to maintain the appropriate targeted capitalization percentages. The Affiliate Promissory Note was due December 31, 2034 and had an initial interest rate at December 31, 2004 of 6.3%, which adjusted on a periodic basis based upon weighted average costs and expenses of borrowing the then-outstanding long-term debt of both Southern Company Gas and Southern Company Gas Capital Corporation, a 100%-owned financing subsidiary of Southern Company Gas. As of June 30, 2018, $268.4 million was outstanding under the Affiliate Promissory Note with an effective interest rate of 2.7% that equaled the weighted average costs that is applied to the principal amount of the Affiliate Promissory Note. Subsequent to June 30, 2018, the Affiliate Promissory Note was fully repaid.

(F)	RETIREMENT BENEFITS	

Prior to the sale of the Elizabethtown Gas assets to SJI, Elizabethtown Gas participated in the Southern Company Gas qualified defined benefit, trusteed, pension plan. On January 1, 2018, this plan was merged into the qualified defined benefit pension plan of Southern Company and reopened to all non-union employees of Elizabethtown Gas. The Southern Company qualified defined benefit pension plan is funded in accordance with requirements of the Employee Retirement Income Security Act of 1974, as amended. During 2018, prior to the sale of the Elizabethtown Gas assets to SJI, there were no contributions to the Southern Company qualified defined benefit pension plan. Elizabethtown Gas also participated in the Southern Company Gas postretirement benefit plan, which provides certain medical care and life insurance benefits for eligible retired employees, through a postretirement benefit plan. See Note 2 to the 2017 Financial Statements for additional information.

In conjunction with the sale of the Elizabethtown Gas assets to SJI, postretirement benefit obligations of these plans associated with all of the Elizabethtown Gas participants transferred to SJI along with the plan assets equaling the obligations. Under the terms of the asset purchase agreement, employees of Elizabethtown Gas are eligible to participate in a defined benefit pension plan of SJI that offers benefits and other terms and conditions equivalent to those provided by the retirement benefit plans of Southern Company Gas.

Elizabethtown Gas' pro rata components of Southern Company Gas' net periodic pension costs for the periods presented were as follows:
 
 	 	Six Months Ended June 30,	 	
 	 	2018	 	 	2017	 	
 	 	(in thousands)	 	
Service cost	 	$	916	 	 	$	696	 	
Interest cost	 	 	1,803	 	 	 	2,192	 	
Expected return on plan assets	 	 	(2,849	)	 	 	(3,335	)	
Amortization:	 	 	 	 	 	 	 	 	
Regulatory asset	 	 	1,345	 	 	 	—	 	
Prior service costs	 	 	(5	)	 	 	(424	)	
Net (gain) loss	 	 	(7	)	 	 	1,006	 	
Net periodic pension cost	 	$	1,203	 	 	$	135	 	
 
11

Elizabethtown Gas' pro rata components of Southern Company Gas' other postretirement benefit plans' net periodic cost for the periods presented were as follows:
 	 	Six Months Ended June 30,	 	
 	 	2018	 	 	2017	 	
 	 	(in thousands)	 	
Service cost	 	$	58	 	 	$	50	 	
Interest cost	 	 	213	 	 	 	208	 	
Expected return on plan assets	 	 	(374	)	 	 	(327	)	
Amortization:	 	 	 	 	 	 	 	 	
Regulatory asset	 	 	279	 	 	 	—	 	
Prior service costs	 	 	25	 	 	 	—	 	
Net (gain) loss	 	 	(5	)	 	 	88	 	
Net periodic postretirement benefit cost	 	$	196	 	 	$	19	 	
 
(G)	INCOME TAXES	

See Note 4 to the 2017 Financial Statements for additional tax information.

Federal Tax Reform Legislation

Following the enactment of the Tax Reform Legislation, the Securities and Exchange Commission staff issued Staff Accounting Bulletin 118 - "Income Tax Accounting Implications of the Tax Cuts and Jobs Act" (SAB 118), which provides for a measurement period of up to one year from the enactment date to complete accounting under GAAP for the tax effects of the legislation. Due to the complex and comprehensive nature of the enacted tax law changes, and their application under GAAP, Elizabethtown Gas considers all amounts recorded in the financial statements as a result of the Tax Reform Legislation to be "provisional" as discussed in SAB 118 and subject to revision. Elizabethtown Gas is awaiting additional guidance from industry and income tax authorities in order to finalize its accounting. The ultimate impact of the Tax Reform Legislation on deferred income tax assets and liabilities and the related regulatory assets and liabilities cannot be determined at this time. See Note (B) under "Regulatory Matters - Tax Reform Legislation" for additional information.

Effective Tax Rate

Elizabethtown Gas' effective tax rate was 29.4% for the six months ended June 30, 2018 compared to 42.2% for the six months ended June 30, 2017. This decrease was primarily related to the reduction in the federal corporate income tax rate and the benefit from the flowback of excess deferred income taxes as a result of the Tax Reform Legislation. See Note (B) under "Regulatory Matters - Tax Reform Legislation" for additional information.

(H)	DERIVATIVES	

Elizabethtown Gas was exposed to market risks, primarily commodity price risk, interest rate risk, and weather risk. To manage the volatility attributable to these exposures, Elizabethtown Gas netted its exposures, where possible, to take advantage of natural offsets and enters into various derivative transactions for the remaining exposures pursuant to Elizabethtown Gas' policies in areas such as counterparty exposure and risk management practices. Elizabethtown Gas' policy was that derivatives were to be used primarily for hedging purposes and mandates strict adherence to all applicable risk management policies. Derivative positions were monitored using techniques including, but not limited to, market valuation, value at risk, stress testing, and sensitivity analysis. Derivative instruments are recognized at fair value in the balance sheets as either assets or liabilities and were presented on a net basis. In the statements of cash flows, the cash impacts of settled energy-related are recorded as operating activities.
 
12

Energy-Related Derivatives

Elizabethtown Gas entered into energy-related derivatives to hedge exposures to natural gas and other fuel price changes. However, due to cost-based rate regulations and other various cost recovery mechanisms, Elizabethtown Gas had limited exposure to market volatility in prices of natural gas. Elizabethtown Gas managed fuel-hedging programs, implemented per the guidance of the New Jersey BPU, through the use of financial derivative contracts, which was expected to mitigate price volatility.

Energy-related derivative contracts were accounted for under one of three methods:

 	•	Regulatory Hedges - Energy-related derivative contracts which were designated as regulatory hedges related primarily to Elizabethtown Gas' fuel-hedging programs, where gains and losses are initially recorded as regulatory liabilities and assets, respectively, and then included in the cost of natural gas as the underlying natural gas was used in operations and ultimately recovered through cost recovery clauses.	

 	•	Cash Flow Hedges - Gains and losses on energy-related derivatives designated as cash flow hedges (which were mainly used to hedge anticipated purchases and sales) are initially deferred in other comprehensive income (OCI) before being recognized in the statements of income in the same period and in the same income statement line item as the earnings effect of the hedged transactions.	

 	•	Not Designated - Gains and losses on energy-related derivative contracts that were not designated or fail to qualify as hedges were recognized in the statements of income as incurred.	

Derivative Financial Statement Presentation and Amounts

The derivative contracts of Elizabethtown Gas were subject to master netting arrangements or similar agreements and reported net on its financial statements. Some of these energy-related derivative contracts contained certain provisions that permit intra-contract netting of derivative receivables and payables for routine billing and offsets related to events of default and settlements.

On June 28, 2018, Pivotal Utility terminated all derivative contracts at Elizabethtown Gas in advance of the sale of the Elizabethtown Gas assets to SJI. At June 30, 2018, there were no derivative assets or liabilities on the balance sheet of Elizabethtown Gas. At December 31, 2017, the fair value of energy-related derivatives was reflected in the balance sheet as follows:
 	  	 	As of December 31, 2017	 	
Derivative
Category	Balance Sheet Location	 	Assets	 	 	Liabilities	 	
 	  	 	(in thousands)	 	
Derivatives designated as hedging instruments for regulatory purposes	 	 	 	 	 	 	
Energy-related derivatives:	 	 	 	 	 	 	
Assets from risk management activities/Liabilities from risk management activities – current	 	$	—	 	 	$	1,694	 	
Other deferred charges and assets/Other deferred credits and liabilities	 	 	—	 	 	 	312	 	
Total derivatives designated as hedging instruments for regulatory purposes	 	$	—	 	 	$	2,006	 	
Gross amounts of recognized	 	$	—	 	 	$	2,006	 	
Gross amounts offset	 	$	—	 	 	$	—	 	
Net amounts recognized in the Balance Sheets	 	$	—	 	 	$	2,006	 	
 
13

At June 30, 2018, there were no pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments. At December 31, 2017, the pre-tax effects of unrealized derivative gains (losses) arising from energy-related derivative instruments designated as regulatory hedging instruments and deferred were as follows:
 	  	Unrealized Losses	 	 	 	Unrealized Gains	 	
Derivative Category	Balance Sheet Location	December 31, 2017	 	Balance Sheet Location	 	December 31, 2017	 	
 	  	(in thousands)	 	 	 	(in thousands)	 	
Energy-related derivatives:	 	 	 	 	 	 	 	
 	Regulatory assets, current	$	(1,694	)	Regulatory liabilities, current	 	$	—	 	
 	Regulatory assets, deferred	 	(312	)	Other deferred credits and liabilities	 	 	—	 	
Total energy-related derivative gains (losses)	 	$	(2,006	)	 	 	$	—	 	
 
Contingent Features

Elizabethtown Gas did not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit rating downgrade. There were certain derivatives that could require collateral, but not accelerated payment, in the event of a credit rating change below BBB- and/or Baa3. At June 30, 2018 Elizabethtown Gas had no collateral posted with derivative counterparties to satisfy these arrangements.

Elizabethtown Gas also utilized master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Elizabethtown Gas was engaged in more than one outstanding derivative transaction with the same counterparty and it also had a legally enforceable netting agreement with that counterparty, the "net" mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of Elizabethtown Gas' credit risk. Elizabethtown Gas also used other netting agreements with certain counterparties with whom it conducted significant transactions. Master netting agreements enabled Elizabethtown Gas to net certain assets and liabilities by counterparty. Elizabethtown Gas also netted across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. Elizabethtown Gas may require counterparties to pledge additional collateral when deemed necessary. Therefore, Elizabethtown Gas did not have a material adverse effect on the financial statements as a result of counterparty nonperformance.

(I)	DISPOSITION	

On July 1, 2018, Pivotal Utility completed the sale of substantially all of the Elizabethtown Gas assets to SJI for a total cash purchase price of $1.7 billion and an additional $40 million for working capital, which is subject to a final working capital adjustment. Transaction costs related to this sale are not reflected in Elizabethtown Gas’ financial statements.
 
14

The following table provides the major classes of the Elizabethtown Gas assets and liabilities at June 30, 2018 that were sold to SJI on July 1, 2018:
 	 	At June 30, 2018	 	
 	 	(in thousands)	 	
Current assets	 	$	69,566	 	
Total property, plant, and equipment	 	 	1,100,448	 	
Goodwill	 	 	126,020	 	
Other non-current assets	 	 	119,994	 	
Total assets sold to SJI	 	$	1,416,028	 	
 	 	 	 	 	
Current liabilities	 	$	47,219	 	
Non-current liabilities	 	 	259,641	 	
Total liabilities sold to SJI	 	$	306,860	 	

(J)	AFFILIATE TRANSACTIONS	

In the ordinary course of business, in accordance with the terms authorized under the New Jersey BPU, Elizabethtown Gas entered into transactions with its affiliates. The charges for these transactions were cost-based, market-based, or at a prevailing price.

Asset Management Agreement

Elizabethtown Gas had agreements with Sequent Energy Management, L.P. (Sequent) for transportation and storage capacity to meet natural gas demands. The following table provides additional information on Elizabethtown Gas' asset management agreements with Sequent.
 
 	 	 	 	 	 	Profit sharing / fees payments	 	
Expiration date	Type of fee
structure	 	Annual fee	 	 	June 30, 2018	 	 	December 31, 2017	 	
 	 	 	 	 	 	(in thousands)	 	
March 2019	Tiered	 	 	(*)	 	 	$	2,125	 	 	$	11,195	 	

(*)	In March 2014, the New Jersey BPU authorized the renewal of the asset management agreement between Elizabethtown Gas and Sequent for five years. This renewed agreement began on April 1, 2014 and requires Sequent to pay minimum annual fees of $4.25 million to Elizabethtown Gas and includes tiered margin sharing levels between Elizabethtown Gas and Sequent.	

In conjunction with the sale of the Elizabethtown Gas assets to SJI, the asset management agreements were assumed by an affiliate of SJI.

Amounts Due to Affiliates

Elizabethtown Gas had $280.9 million and $81.9 million in payable at June 30, 2018 and December 31, 2017, respectively, that was due to Southern Company Gas related to its participation in the Southern Company Gas utility money pool. The increase at June 30, 2018 was primarily due to borrowings to redeem the gas facility revenue bonds. Elizabethtown Gas also had $268.4 million outstanding at each of June 30, 2018 and December 31, 2017 related to a promissory note with Southern Company Gas. Subsequent to June 30, 2018, these amounts due to Southern Company Gas were fully repaid. See Note (E) for additional information.

Elizabethtown Gas was covered by Southern Company Gas' agreement with Southern Company Services, Inc. under which various services were being rendered to Elizabethtown Gas as direct or allocated cost. Additionally, Elizabethtown Gas engaged in transactions with Southern Company Gas’ affiliates consistent with its services and tax allocation agreements.
 
15

(K)	SUBSEQUENT EVENTS	

Management evaluated subsequent events for potential recognition and disclosure through September 12, 2018, the date these financial statements were available to be issued, and determined that, except for the settlement of lawsuits as discussed in Note (B), the repayment of the Affiliate Promissory Note and the amounts due to Southern Company Gas for Elizabethtown Gas' participation in the money pool as discussed in Notes (E) and (J), respectively, and the consummation of the asset purchase agreement as discussed in Note (I), no significant events have occurred subsequent to period end.

16

Exhibit 99.4
 
Unaudited Pro Forma Condensed Combined Financial Data of the Company and the Elizabethtown Business

On July 1, 2018, South Jersey Industries, Inc. (“SJI” or the “Company”) completed its previously announced acquisition of the Elizabethtown Gas operating division (the ‘‘Elizabethtown Business’’ or ‘‘ETG’’) of Pivotal Utility Holdings, Inc., a New Jersey corporation, pursuant to the terms of the asset purchase agreement (“Purchase Agreement”), executed on October 15, 2017 (the “ETG Acquisition”).

The unaudited pro forma condensed combined financial statements and the accompanying notes to the pro forma financial statements (the “pro forma financial statements”) present how the consolidated financial statements of the Company may have appeared had the Transactions (as defined below) occurred at earlier dates. The unaudited pro forma condensed combined statements of income for the year ended December 31, 2017 and for the six months ended June 30, 2018 combines the historical consolidated statements of income of the Company and the historical statements of income of ETG, after giving effect to the Transactions (as defined below) as if they had occurred on January 1, 2017, and after applying the assumptions, reclassifications and adjustments described in the accompanying notes. The unaudited pro forma condensed combined balance sheet combines the historical consolidated balance sheet of the Company and the historical balance sheet of the Elizabethtown Business as of June 30, 2018, the latest interim period presented in the pro forma financial statements, after giving effect to the Transactions (as defined below), as if they had occurred on June 30, 2018.

The following pro forma financial statements present the combination of the historical financial information of the Company and the Elizabethtown Business adjusted to give effect to the ETG Acquisition, pursuant to the terms and conditions of the Purchase Agreement for an aggregate purchase price equal to $1.72 billion in cash, inclusive of $26.7 million of certain adjustments for the net working capital of the Elizabethtown Business as set forth in the Purchase Agreement.

The Company financed the ETG Acquisition using cash on hand, net proceeds of $434.9 million from the issuance of its common stock (the “Common Stock Issuance”) and the concurrent issuance of Equity Units (the “Equity Unit Issuance”) and through debt, net of cash paid for fees of $4.3 million, of $530.0 million in aggregate principal amount of a new term loan facility (the “Term Facility”), $250.0 million in aggregate principal amount of new senior unsecured notes (the “Senior Unsecured Notes”), $475.0 million in aggregate principal amount of new floating rate senior notes (“Floating Rate Notes”), and drawdowns of $31.1 million in aggregate principal amount from our existing syndicated revolving credit facility (the “Revolver”, together with the “ETG Acquisition”, “Common Stock Issuance”, “Equity Unit Issuance”, “Term Facility”, “Senior Unsecured Notes”, and “Floating Rate Notes”, the “Transactions”). Prior to the aforementioned Transactions, the Company had entered into a $2.6 billion bridge loan commitment (“Bridge Loan”) to finance the ETG Acquisition to the extent the Company raised less proceeds than expected. As a result of the successful completion of the Transactions, the Bridge Loan was not utilized and terminated as of June 30, 2018. Additionally, the pro forma financial statements do not reflect any potential asset dispositions.

The accompanying pro forma financial statements have been prepared in accordance with Article 11 of SEC Regulation S-X, and certain financial statement line items included in the Company’s and the Elizabethtown Business’s historical presentation have been condensed. The historical combined financial information has been adjusted to give effect to pro forma events that are (1) directly attributable to the Transactions, (2) factually supportable, and (3) with respect to the statement of income, expected to have a continuing impact on the combined results. The unaudited pro forma condensed combined financial statements should be read in conjunction with the accompanying notes to the pro forma financial statements. In addition, the pro forma financial statements were based on and should be read in conjunction with:

 	·	the audited consolidated financial statements of the Company as of and for the year ended December 31, 2017 and the related notes, included in the Company’s Annual Report on Form 10-K/A filed with the SEC on March 1, 2018;	

 	·	the unaudited consolidated financial statements of the Company as of and for the six months ended June 30, 2018 and the related notes, included in the Company’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2018;	

 	·	the audited financial statements of the Elizabethtown Business as of and for the year ended December 31, 2017 and the related notes, which are included in the Company’s Amended Current Report on Form 8-K filed with the SEC on April 17, 2018;	

 	·	The unaudited financial statements of the Elizabethtown Business as of and for the six months ended June 30, 2018 and the related notes, which are included within this filing.	

The pro forma financial statements do not reflect the costs of any integration activities, possible or pending asset dispositions, the benefits that may result from realization of future cost savings from operating efficiencies or revenue synergies that may result from the Transactions. Further, the pro forma financial statements do not reflect the effect of the $11.0 million aggregate cash purchase of Elkton Gas operating division, which is considered to be immaterial for purposes of the pro forma financial statements.

The pro forma financial statements are presented for informational purposes only and do not purport to represent what the results of operations or financial condition would have been had the Transactions actually occurred on the dates indicated, nor do they purport to project the results of operations or financial condition of the combined company for any future period or as of any future date.

The unaudited pro forma condensed combined financial data has been prepared using the acquisition method of accounting under existing U.S. generally accepted accounting principles, or ‘‘GAAP’’ standards, which are subject to change and interpretation. The acquisition accounting is dependent upon certain valuations and other studies. Accordingly, the pro forma adjustments are preliminary and have been made solely for the purpose of providing unaudited pro forma condensed combined financial data. Differences between these preliminary estimates and the final acquisition accounting will occur and these differences could have a material impact on the accompanying unaudited pro forma condensed combined financial data and the combined company’s future results of operations and financial position.

Unaudited Pro Forma Condensed Combined Balance Sheet
As of June 30, 2018
(in thousands)
 	 	Historical
SJI	 	 	Historical
ETG	 	 	ETG
 Acquisition
Adjustments	 	 	 	Financing &
Other
Adjustments	 	 	 	Pro Forma	 	
 	 	(Note 3)	 	 	(Note 3)	 	 	(Note 4)	 	 	 	(Note 5)	 	 	 	 	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Property, Plant and Equipment:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Utility Plant, at original cost	 	$	2,748,076	 	 	$	1,366,478	 	 	$	(36,385	)	(i)	 	$	-	 	 	 	$	4,078,169	 	
Accumulated Depreciation	 	 	(509,797	)	 	 	(266,030	)	 	 	12,728	 	(i)	 	 	-	 	 	 	 	(763,099	)	
Nonutility Property and Equipment, net	 	 	123,029	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	123,029	 	
Property, Plant and Equipment — Net	 	 	2,361,308	 	 	 	1,100,448	 	 	 	(23,657	)	 	 	 	-	 	 	 	 	3,438,099	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Investments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Investments	 	 	83,126	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	83,126	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash and Cash Equivalents	 	 	22,420	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	22,420	 	
Restricted Cash	 	 	1,740,380	 	 	 	-	 	 	 	(1,716,700	)	(a)	 	 	-	 	 	 	 	23,680	 	
Accounts Receivable, net	 	 	209,989	 	 	 	38,825	 	 	 	(378	)	(k)	 	 	-	 	 	 	 	248,436	 	
Natural Gas in Storage, average cost	 	 	44,086	 	 	 	21,428	 	 	 	-	 	 	 	 	-	 	 	 	 	65,514	 	
Materials and Supplies, average cost	 	 	4,200	 	 	 	321	 	 	 	-	 	 	 	 	-	 	 	 	 	4,521	 	
Assets Held for Sale	 	 	329,622	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	329,622	 	
Other Prepayments and Current Assets	 	 	73,839	 	 	 	32,546	 	 	 	(23,542	)	(h)	 	 	-	 	 	 	 	82,843	 	
Total Current Assets	 	 	2,424,536	 	 	 	93,120	 	 	 	(1,740,620	)	 	 	 	-	 	 	 	 	777,036	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory and Other Noncurrent Assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulatory Assets	 	 	476,635	 	 	 	119,954	 	 	 	11,935	 	(j)	 	 	-	 	 	 	 	608,524	 	
Goodwill and Identifiable Intangible Assets	 	 	15,578	 	 	 	126,020	 	 	 	620,040	 	(b)	 	 	-	 	 	 	 	761,638	 	
Other	 	 	148,314	 	 	 	40	 	 	 	-	 	 	 	 	-	 	 	 	 	148,354	 	
Total Regulatory and Other Noncurrent Assets	 	 	640,527	 	 	 	246,014	 	 	 	631,975	 	 	 	 	-	 	 	 	 	1,518,516	 	
Total Assets	 	$	5,509,497	 	 	$	1,439,582	 	 	$	(1,132,302	)	 	 	$	-	 	 	 	$	5,816,777	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capitalization and Liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Equity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Common Stock	 	$	106,882	 	 	$	-	 	 	$	-	 	 	 	$	-	 	 	 	$	106,882	 	
Premium on Common Stock	 	 	842,327	 	 	 	166,372	 	 	 	(166,372	)	(e)	 	 	-	 	 	 	 	842,327	 	
Treasury Stock (at par)	 	 	(282	)	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	(282	)	
Accumulated Other Comprehensive Loss	 	 	(36,748	)	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	(36,748	)	
Retained Earnings	 	 	391,538	 	 	 	277,746	 	 	 	(277,746	)	(e)	 	 	(15,000	)	(c)	 	 	376,538	 	
Total Equity	 	 	1,303,717	 	 	 	444,118	 	 	 	(444,118	)	 	 	 	(15,000	)	 	 	 	1,288,717	 	
Long—Term Debt	 	 	1,403,802	 	 	 	268,406	 	 	 	(268,406	)	(d)	 	 	-	 	 	 	 	1,403,802	 	
Total Capitalization	 	 	2,707,519	 	 	 	712,524	 	 	 	(712,524	)	 	 	 	(15,000	)	 	 	 	2,692,519	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Notes Payable	 	 	336,400	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	336,400	 	
Current Portion of Long—Term Debt	 	 	1,368,809	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	1,368,809	 	
Accounts Payable	 	 	262,090	 	 	 	294,193	 	 	 	(271,902	)	(c)	 	 	-	 	 	 	 	284,381	 	
Other Current Liabilities	 	 	147,519	 	 	 	39,764	 	 	 	(6,309	)	(l)	 	 	15,000	 	(c)	 	 	195,974	 	
Total Current Liabilities	 	 	2,114,818	 	 	 	333,957	 	 	 	(278,211	)	 	 	 	15,000	 	 	 	 	2,185,564	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred Credits and Other Noncurrent Liabilities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Deferred Income Taxes – Net	 	 	91,690	 	 	 	133,460	 	 	 	(133,460	)	(h)	 	 	-	 	 	 	 	91,690	 	
Regulatory Liabilities	 	 	299,382	 	 	 	119,572	 	 	 	-	 	 	 	 	-	 	 	 	 	418,954	 	
Other	 	 	296,088	 	 	 	140,069	 	 	 	(8,107	)	(j)	 	 	-	 	 	 	 	428,050	 	
Total Deferred Credits and Other Noncurrent Liabilities	 	 	687,160	 	 	 	393,101	 	 	 	(141,567	)	 	 	 	-	 	 	 	 	938,694	 	
Total Capitalization and Liabilities	 	$	5,509,497	 	 	$	1,439,582	 	 	$	(1,132,302	)	 	 	$	-	 	 	 	$	5,816,777	 	

Unaudited Pro Forma Condensed Consolidated Statement of Income
For the Six Months Ended June 30, 2018
(in thousands, except per share amounts)
 	 	Historical
SJI	 	 	Historical
ETG	 	 	ETG
 Acquisition
Adjustments	 	 	 	Financing &
Other
Adjustments	 	 	 	Pro Forma	 	
 	 	(Note 3)	 	 	(Note 3)	 	 	(Note 4)	 	 	 	(Note 5)	 	 	 	 	 	
Operating Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Utility	 	$	307,371	 	 	$	184,318	 	 	$	-	 	 	 	$	-	 	 	 	$	491,689	 	
Nonutility	 	 	441,904	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	441,904	 	
Total Operating Revenues	 	 	749,275	 	 	 	184,318	 	 	 	-	 	 	 	 	-	 	 	 	 	933,593	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of Sales – (Excluding depreciation)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
— Utility	 	 	105,298	 	 	 	87,472	 	 	 	-	 	 	 	 	-	 	 	 	 	192,770	 	
— Nonutility	 	 	323,566	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	323,566	 	
Operations	 	 	105,051	 	 	 	30,957	 	 	 	(13,206	)	(g)	 	 	-	 	 	 	 	122,802	 	
Impairment Charges	 	 	99,233	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	99,233	 	
Maintenance	 	 	13,674	 	 	 	4,507	 	 	 	-	 	 	 	 	-	 	 	 	 	18,181	 	
Depreciation	 	 	49,433	 	 	 	13,826	 	 	 	(2,209	)	(i)	 	 	-	 	 	 	 	61,050	 	
Energy and Other Taxes	 	 	3,682	 	 	 	1,713	 	 	 	-	 	 	 	 	-	 	 	 	 	5,395	 	
Total Operating Expenses	 	 	699,937	 	 	 	138,475	 	 	 	(15,415	)	 	 	 	-	 	 	 	 	822,997	 	
Operating Income	 	 	49,338	 	 	 	45,843	 	 	 	15,415	 	 	 	 	-	 	 	 	 	110,596	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income and Expense	 	 	3,735	 	 	 	348	 	 	 	-	 	 	 	 	-	 	 	 	 	4,083	 	
Interest Charges	 	 	(33,533	)	 	 	(10,165	)	 	 	10,178	 	(c),(d)	 	 	1,179	 	(a)	 	 	(32,341	)	
Income Before Income Taxes	 	 	19,540	 	 	 	36,026	 	 	 	25,593	 	 	 	 	1,179	 	 	 	 	82,338	 	
Income Taxes	 	 	(4,443	)	 	 	(10,586	)	 	 	(6,398	)	(f)	 	 	(295	)	(b)	 	 	(21,722	)	
Equity in Earnings of Affiliates	 	 	2,416	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	2,416	 	
Income from Continuing Operations	 	$	17,513	 	 	$	25,440	 	 	$	19,195	 	 	 	$	884	 	 	 	$	63,032	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic Earnings Per Common Share: (Note 6)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	$	0.21	 	 	$	-	 	 	 	 	 	 	 	 	 	 	 	 	$	0.74	 	
Basic Earnings Per Common Share	 	$	0.21	 	 	$	-	 	 	 	 	 	 	 	 	 	 	 	 	$	0.74	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Shares of Common Stock Outstanding – Basic (Note 6)	 	 	81,850	 	 	 	-	 	 	 	 	 	 	 	 	 	 	 	 	 	85,472	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted Earnings Per Common Share: (Note 6)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	$	0.21	 	 	$	-	 	 	 	 	 	 	 	 	 	 	 	 	$	0.73	 	
Diluted Earnings Per Common Share	 	$	0.21	 	 	$	-	 	 	 	 	 	 	 	 	 	 	 	 	$	0.73	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Shares of Common Stock Outstanding – Diluted (Note 6)	 	 	82,302	 	 	 	-	 	 	 	 	 	 	 	 	 	 	 	 	 	86,030	 	

Unaudited Pro Forma Condensed Consolidated Statement of Income
For the Year Ended December 31, 2017
(in thousands, except per share amounts)
 	 	Historical
SJI	 	 	Historical
ETG	 	 	ETG
Acquisition
Adjustments	 	 	 	Financing &
Other
Adjustments	 	 	 	Pro Forma	 	
 	 	(Note 3)	 	 	(Note 3)	 	 	(Note 4)	 	 	 	(Note 5)	 	 	 	 	 	
Operating Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Utility	 	$	512,482	 	 	$	304,747	 	 	$	-	 	 	 	$	-	 	 	 	$	817,229	 	
Nonutility	 	 	730,586	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	730,586	 	
Total Operating Revenues	 	 	1,243,068	 	 	 	304,747	 	 	 	-	 	 	 	 	-	 	 	 	 	1,547,815	 	
Operating Expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cost of Sales – (Excluding depreciation)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
— Utility	 	 	199,660	 	 	 	135,850	 	 	 	-	 	 	 	 	-	 	 	 	 	335,510	 	
— Nonutility	 	 	646,567	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	646,567	 	
Operations	 	 	174,200	 	 	 	58,326	 	 	 	(14,481	)	(g)	 	 	-	 	 	 	 	218,045	 	
Impairment Charges	 	 	91,299	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	91,299	 	
Maintenance	 	 	19,727	 	 	 	8,248	 	 	 	-	 	 	 	 	-	 	 	 	 	27,975	 	
Depreciation	 	 	100,718	 	 	 	27,163	 	 	 	(4,653	)	(i)	 	 	-	 	 	 	 	123,228	 	
Energy and Other Taxes	 	 	6,487	 	 	 	4,917	 	 	 	-	 	 	 	 	-	 	 	 	 	11,404	 	
Total Operating Expenses	 	 	1,238,658	 	 	 	234,504	 	 	 	(19,134	)	 	 	 	-	 	 	 	 	1,454,028	 	
Operating Income	 	 	4,410	 	 	 	70,243	 	 	 	19,134	 	 	 	 	-	 	 	 	 	93,787	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other Income and Expense	 	 	15,474	 	 	 	1,460	 	 	 	-	 	 	 	 	-	 	 	 	 	16,934	 	
Interest Charges	 	 	(54,019	)	 	 	(15,960	)	 	 	16,097	 	(c),(d)	 	 	(52,308	)	(a)	 	 	(106,190	)	
(Loss) income Before Income Taxes	 	 	(34,135	)	 	 	55,743	 	 	 	35,231	 	 	 	 	(52,308	)	 	 	 	4,531	 	
Income Taxes	 	 	24,937	 	 	 	(21,926	)	 	 	(13,564	)	(f)	 	 	20,139	 	(b)	 	 	9,586	 	
Equity in Earnings of Affiliates	 	 	5,794	 	 	 	-	 	 	 	-	 	 	 	 	-	 	 	 	 	5,794	 	
(Loss) Income from Continuing Operations	 	$	(3,404	)	 	$	33,817	 	 	$	21,667	 	 	 	$	(32,169	)	 	 	$	19,911	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic Earnings Per Common Share: (Note 6)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	$	(0.04	)	 	$	-	 	 	 	 	 	 	 	 	 	 	    	 	$	0.23	 	
Basic Earnings Per Common Share	 	$	(0.04	)	 	$	-	 	 	 	 	 	 	 	 	 	 	    	 	$	0.23	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Shares of Common Stock Outstanding – Basic (Note 6)	 	 	79,541	 	 	 	-	 	 	 	 	 	 	 	 	 	 	 	 	 	85,431	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted Earnings Per Common Share: (Note 6)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Continuing Operations	 	$	(0.04	)	 	$	-	 	 	 	 	 	 	 	 	 	 	    	 	$	0.23	 	
Diluted Earnings Per Common Share	 	$	(0.04	)	 	$	-	 	 	 	 	 	 	 	 	 	 	    	 	$	0.23	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Shares of Common Stock Outstanding – Diluted (Note 6)	 	 	79,541	 	 	 	-	 	 	 	 	 	 	 	 	 	 	 	 	 	85,431	 	

NOTES TO THE UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

 	1.	Basis of Presentation	

The pro forma financial statements present the pro forma condensed combined financial position and results of operations based upon the historical financial statements of SJI and ETG, after giving effect to the Transactions and are intended to reflect the impact of such on SJI’s consolidated financial statements. Certain reclassifications have been included in the pro forma financial statements in order to align the historical financial statement presentation of SJI and ETG. See note “3. Reclassifications” herein for additional information on the reclassifications.

The ETG Acquisition is considered a business combination, and therefore will be accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board’s Accounting Standards Codification Topic 805 Business Combinations (‘‘ASC 805’’). Under the acquisition method of accounting for purposes of these pro forma financial statements, the total estimated purchase price of an acquisition is allocated to the net tangible and intangible assets based on their estimated fair values. Such valuations are based on available information and certain assumptions that management believes are reasonable. The preliminary allocation of the estimated purchase price to the net tangible and intangible assets acquired and liabilities assumed, as described in note “2. Purchase Price and Preliminary Purchase Price Allocation” to these pro forma financial statements, is based on various preliminary estimates. Accordingly, the pro forma adjustments are preliminary and have been made solely for the purpose of providing these pro forma financial statements. The final allocation of the purchase price to the net tangible and intangible assets acquired and liabilities assumed could differ materially from the preliminary purchase price allocation as more detailed information becomes available and such differences could be material. The differences, if any, could have a material impact on the accompanying pro forma financial statements and SJI’s future results of operations and financial position.

The ETG Acquisition was financed with cash on hand, proceeds from the Common Stock Issuance, Equity Unit Issuance, Senior Unsecured Notes, Floating Rate Notes, Term Facility (together with Senior Unsecured Notes and Floating Rate Notes, the “Notes and Facilities”), and Revolver. The Senior Unsecured Notes are comprised of a 3.18% $90.0 million tranche due 2021, a 3.82% $80.0 million tranche due 2028 and a 3.92% $80.0 million tranche due 2030. The Floating Rate Notes are comprised of a $475.0 million in aggregate principal Series 2018D notes, due 2019 on the one-year anniversary of the date of initial issuance, which, at the Company’s option, bears interest at a variable base rate or a variable LIBOR. The Term Facility is comprised of a $530.0 million, 364-day-term loan credit agreement, which, at the election of the Company, bears interest at a variable base rate or a variable LIBOR. The Revolver is comprised of a five year, unsecured $400.0 million revolving credit agreement that is syndicated among several banks. As of June 30, 2018, $183.9 million remained undrawn and our weighted average interest rate on outstanding borrowings, which changes daily, was 3.07%. The drawdown of $31.1 million as part of the financing for the ETG Acquisition is included within the $216.1 million usage of the Revolver as of June 30, 2018. The gross proceeds of the Equity Unit issuance was $287.5 million. Each Equity Unit has a stated amount of $50.0 and will initially be in the form of a corporate unit consisting of a contract to purchase SJI common stock and a 1/20 or 5% undivided beneficial ownership interest in a $1,000 principal amount of our remarketable junior subordinated notes due 2031 (“RSNs”). The stock purchase contracts obligate the holders to purchase shares of SJI’s common stock at a future settlement date of approximately three years from the issuance date, subject to earlier termination or settlement. The RSNs are pledged as collateral to secure the purchase of common stock under the stock purchase contracts. The net proceeds from the sale of the Equity Units were allocated between the purchase contracts and the RSNs in proportion to their respective fair market values at the time of issuance. The RSNs are classified as long-term debt. The present value of the contract adjustment payments has been initially charged to shareholders’ equity, with an offsetting credit to liabilities. This liability is accreted over the life of the purchase contract by interest charges to the income statement based on a constant rate calculation. Subsequent contract adjustment payments reduce this liability. For purposes of the pro forma financial statements, SJI has assumed (x) it will make quarterly payments on the RSN’s and quarterly contract adjustment payments on the stock purchase contracts each at a rate of 3.55% and (y) the underwriters exercised the over-allotment option to purchase additional Equity Units in the Equity Units Issuance.

As previously discussed, SJI utilized $475.0 million of the Floating Rate Notes to fund a portion of the ETG Acquisition. The Floating Rate Notes are due in full in June 2019, which will be partially repaid with proceeds from the sale of the Company’s solar energy assets (the “Solar Asset Sale”). In the event Solar Asset Sale proceeds are not received in a timely manner or the proceeds received are less than anticipated, SJI will refinance these Floating Rate Notes into longer-dated long term debt prior to the maturity of the Floating Rate Notes in June 2019.

As previously discussed, the Company entered into the $530.0 million Term Facility to fund a portion of the ETG Acquisition. The Term Facility is due in June 2018, which is due 364 days from the closing date of the Term Facility. As required by the New Jersey Board of Public Utilities, the Company will arrange for the refinancing of the Term Facility via a private placement of First Mortgage Bonds secured by a mortgage on ETG's assets during the third quarter of 2018.

The pro forma financial statements do not reflect the restructuring or integration activities that have yet to be determined or other costs that may be incurred to achieve cost or growth synergies subsequent to the closing of the Transactions. As no assurance can be made that the costs will be incurred or the cost or growth synergies will be achieved, no adjustment has been made. Further, the pro forma financial statements do not reflect the effect of the $11.0 million aggregate cash purchase of Elkton or Elkton’s assets, liabilities or results, which are considered immaterial for purposes of the pro forma financial statements.

 	2.	Purchase Price and Preliminary Purchase Price Allocation	

The pro forma adjustments include a preliminary allocation of the estimated purchase price of ETG to the estimated fair values of assets acquired and liabilities assumed at the acquisition date. The final allocation of the purchase price could differ materially from the preliminary allocation as more detailed information becomes available until completion of the fair value assessment. Generally, changes to the initial estimates of the fair value of the assets acquired and liabilities assumed will be recorded as adjustments to those assets and liabilities and residual amounts will be allocated to goodwill. As part of the acquisition, SJI will not acquire any cash or cash equivalent assets of ETG at the time of close. Therefore, the estimated purchase price used in the preliminary purchase price allocation is $1.72 billion, inclusive of the customary post-closing adjustments for the net working capital of ETG.

Preliminary purchase price allocation

ETG’s regulated natural gas distribution operations are subject to the retail rate-setting authority of the New Jersey Board of Public Utilities, which includes provisions in place that provide revenues to recover costs of service, including a carrying charge on most net assets and liabilities. The historical book value of the assets acquired and liabilities assumed approximates fair value given the regulatory environment under which ETG operates.

The following is a summary of the preliminary purchase price allocation giving effect to the ETG Acquisition as if it had been consummated on June 30, 2018:
(In thousands)	 	 	 	
Property, plant and equipment	 	$	1,076,791	 	
Accounts Receivable, net	 	 	38,447	 	
Natural Gas in Storage	 	 	21,428	 	
Materials and Supplies	 	 	321	 	
Other Prepayments and Current Assets	 	 	9,044	 	
Regulatory Assets	 	 	131,889	 	
Goodwill	 	 	746,060	 	
Total assets acquired	 	 	2,023,980	 	
Accounts Payable	 	 	22,291	 	
Other Current Liabilities	 	 	33,455	 	
Regulatory Liabilities	 	 	119,572	 	
Other	 	 	131,962	 	
Total liabilities assumed	 	 	307,280	 	
Net assets acquired	 	$	1,716,700	 	

 	3.	Reclassifications	

Certain reclassifications have been made to amounts in the historical consolidated financial information of SJI and ETG to conform the financial statement presentation, including reclassifying the following:

ETG reclassifications in the unaudited pro forma condensed combined statement of income for the six months ended June 30, 2018
 
(In Thousands)	  	Before
Reclassification	  	  	 
Reclassification	  	   	  	After
Reclassification	  	
Operating revenues	 	 	184,318	 	 	 	(184,318	)	(a)	 	 	—	 	
Operating Revenues - Utility	 	 	—	 	 	 	184,318	 	(a)	 	 	184,318	 	
Cost of natural gas	 	 	87,472	 	 	 	(87,472	)	(b)	 	 	—	 	
Cost of Sales — Utility	 	 	—	 	 	 	87,472	 	(b)	 	 	87,472	 	
Other operations and maintenance	 	 	35,464	 	 	 	(35,464	)	(c)	 	 	—	 	
Operating Expenses - Operations	 	 	—	 	 	 	30,957	 	(c)	 	 	30,957	 	
Operating Expenses - Maintenance	 	 	—	 	 	 	4,507	 	(c)	 	 	4,507	 	
Depreciation and amortization	 	 	13,826	 	 	 	(13,826	)	(d)	 	 	—	 	
Operating Expenses - Depreciation	 	 	—	 	 	 	13,826	 	(d)	 	 	13,826	 	
Taxes other than income taxes	 	 	1,713	 	 	 	(1,713	)	(e)	 	 	—	 	
Operating Expenses Energy and Other Taxes	 	 	—	 	 	 	1,713	 	(e)	 	 	1,713	 	
Other income, net	 	 	348	 	 	 	(348	)	(f)	 	 	—	 	
Other Income and Expense	 	 	—	 	 	 	348	 	(f)	 	 	348	 	
Interest expense, net of amounts capitalized	 	 	10,165	 	 	 	(10,165	)	(g)	 	 	—	 	
Interest Charges	 	 	—	 	 	 	10,165	 	(g)	 	 	10,165	 	
 
 	(a)	Represents the reclassification of Operating revenues on ETG’s statement of income into Operating Revenues - Utility to conform to SJI’s statement of income presentation.	
 
 	(b)	Represents the reclassification of Cost of natural gas on ETG’s statement of income into Cost of Sales — Utility to conform to SJI’s statement of income presentation.	
 
 	(c)	Represents the reclassification of Other operations and maintenance on ETG’s statement of income into Operating Expenses - Operations and Operating Expenses - Maintenance to conform to SJI’s statement of income presentation.	
 
 	(d)	Represents the reclassification of Depreciation and amortization on ETG’s statement of income into Operating Expenses - Depreciation to conform to SJI’s statement of income presentation.	
 
 	(e)	Represents the reclassification of Taxes other than income taxes on ETG’s statement of income into Operating Expenses - Energy and Other Taxes to conform to SJI’s statement of income presentation.	
 
 	(f)	Represents the reclassification of Other income, net on ETG’s statement of income into Other Income and Expense to conform to SJI’s statement of income presentation.	
 
 	(g)	Represents the reclassification of Interest expense, net of amounts capitalized on ETG’s statement of income into Interest Charges to conform to SJI’s statement of income presentation.	

ETG reclassifications in the unaudited pro forma condensed combined statement of income for the year ended December 31, 2017
 
(In Thousands)	  	Before
Reclassification	  	  	 
Reclassification	  	   	  	After
Reclassification	  	
Operating revenues	 	 	304,747	 	 	 	(304,747	)	(a)	 	 	—	 	
Operating Revenues - Utility	 	 	—	 	 	 	304,747	 	(a)	 	 	304,747	 	
Cost of natural gas	 	 	135,850	 	 	 	(135,850	)	(b)	 	 	—	 	
Cost of Sales — Utility	 	 	—	 	 	 	135,850	 	(b)	 	 	135,850	 	
Other operations and maintenance	 	 	66,574	 	 	 	(66,574	)	(c)	 	 	—	 	
Operating Expenses - Operations	 	 	—	 	 	 	58,326	 	(c)	 	 	58,326	 	
Operating Expenses - Maintenance	 	 	—	 	 	 	8,248	 	(c)	 	 	8,248	 	
Depreciation and amortization	 	 	27,163	 	 	 	(27,163	)	(d)	 	 	—	 	
Operating Expenses - Depreciation	 	 	—	 	 	 	27,163	 	(d)	 	 	27,163	 	
Taxes other than income taxes	 	 	4,917	 	 	 	(4,917	)	(e)	 	 	—	 	
Operating Expenses - Energy and Other Taxes	 	 	—	 	 	 	4,917	 	(e)	 	 	4,917	 	
Other income, net	 	 	1,460	 	 	 	(1,460	)	(f)	 	 	—	 	
Other Income and Expense	 	 	—	 	 	 	1,460	 	(f)	 	 	1,460	 	
Interest expense, net of amounts capitalized	 	 	15,960	 	 	 	(15,960	)	(g)	 	 	—	 	
Interest Charges	 	 	—	 	 	 	15,960	 	(g)	 	 	15,960	 	
 
 	(a)	Represents the reclassification of Operating revenues on ETG’s statement of income into Operating Revenues - Utility to conform to SJI’s statement of income presentation.	
 
 	(b)	Represents the reclassification of Cost of natural gas on ETG’s statement of income into Cost of Sales — Utility to conform to SJI’s statement of income presentation.	
 
 	(c)	Represents the reclassification of Other operations and maintenance on ETG’s statement of income into Operating Expenses - Operations and Operating Expenses - Maintenance to conform to SJI’s statement of income presentation.	
 
 	(d)	Represents the reclassification of Depreciation and amortization on ETG’s statement of income into Operating Expenses - Depreciation to conform to SJI’s statement of income presentation.	
 
 	(e)	Represents the reclassification of Taxes other than income taxes on ETG’s statement of income into Operating Expenses - Energy and Other Taxes to conform to SJI’s statement of income presentation.	
 
 	(f)	Represents the reclassification of Other income, net on ETG’s statement of income into Other Income and Expense to conform to SJI’s statement of income presentation.	
 
 	(g)	Represents the reclassification of Interest expense, net of amounts capitalized on ETG’s statement of income into Interest Charges to conform to SJI’s statement of income presentation.	

ETG reclassifications in the unaudited pro forma condensed combined balance sheet as of June 30, 2018
 
(In Thousands)	  	Before
Reclassification	  	  	 
Reclassification	  	   	  	After
Reclassification	  	
Customer accounts receivable	 	 	30,089	 	 	 	(30,089	)	(h)	 	 	—	 	
Unbilled revenues	 	 	4,992	 	 	 	(4,992	)	(h)	 	 	—	 	
Other accounts and notes receivable	 	 	10,185	 	 	 	(10,185	)	(h)	 	 	—	 	
Accumulated provision for uncollectible accounts	 	 	(6,441	)	 	 	6,441	 	(h)	 	 	—	 	
Accounts Receivable, net	 	 	—	 	 	 	38,825	 	(h)	 	 	38,825	 	
Materials and supplies	 	 	321	 	 	 	(321	)	(i)	 	 	—	 	
Materials and Supplies, average cost	 	 	—	 	 	 	321	 	(i)	 	 	321	 	
Natural gas for sale	 	 	21,428	 	 	 	(21,428	)	(j)	 	 	—	 	
Natural Gas in Storage, average cost	 	 	—	 	 	 	21,428	 	(j)	 	 	21,428	 	
Prepaid taxes	 	 	23,460	 	 	 	(23,460	)	(k)	 	 	—	 	
Regulatory assets, current	 	 	8,845	 	 	 	(8,845	)	(k)	 	 	—	 	
Other current assets	 	 	241	 	 	 	(241	)	(k)	 	 	—	 	
Other Prepayments and Current Assets	 	 	—	 	 	 	32,546	 	(k)	 	 	32,546	 	
In service	 	 	1,338,589	 	 	 	(1,338,589	)	(l)	 	 	—	 	
Construction work in progress	 	 	27,889	 	 	 	(27,889	)	(l)	 	 	—	 	
Utility Plant, at original cost	 	 	—	 	 	 	1,366,478	 	(l)	 	 	1,366,478	 	
Accumulated depreciation	 	 	(266,030	)	 	 	266,030	 	(m)	 	 	—	 	
Accumulated Depreciation — Utility Plant	 	 	—	 	 	 	(266,030	)	(m)	 	 	(266,030	)	
Goodwill	 	 	126,020	 	 	 	(126,020	)	(n)	 	 	—	 	
Goodwill and Identifiable Intangible Assets	 	 	—	 	 	 	126,020	 	(n)	 	 	126,020	 	
Regulatory assets, deferred	 	 	119,954	 	 	 	(119,954	)	(o)	 	 	—	 	
Regulatory Assets	 	 	—	 	 	 	119,954	 	(o)	 	 	119,954	 	
Other deferred charges and assets	 	 	40	 	 	 	(40	)	(p)	 	 	—	 	
Other	 	 	—	 	 	 	40	 	(p)	 	 	40	 	
Due to affiliates	 	 	280,911	 	 	 	(280,911	)	(q)	 	 	—	 	
Accounts payable	 	 	13,282	 	 	 	(13,282	)	(q)	 	 	—	 	
Accounts Payable	 	 	—	 	 	 	294,193	 	(q)	 	 	294,193	 	
Customer deposits	 	 	5,233	 	 	 	(5,233	)	(r)	 	 	—	 	
Other accrued taxes	 	 	3,542	 	 	 	(3,542	)	(r)	 	 	—	 	
Accrued environmental remediation, current	 	 	7,100	 	 	 	(7,100	)	(r)	 	 	—	 	
Accrued compensation	 	 	4,294	 	 	 	(4,294	)	(r)	 	 	—	 	
Regulatory liabilities, current	 	 	17,898	 	 	 	(17,898	)	(r)	 	 	—	 	
Other current liabilities	 	 	1,697	 	 	 	(1,697	)	(r)	 	 	—	 	
Other Current Liabilities	 	 	—	 	 	 	39,764	 	(r)	 	 	39,764	 	
Accumulated deferred income taxes	 	 	133,460	 	 	 	(133,460	)	(s)	 	 	—	 	
Deferred Income Taxes — Net	 	 	—	 	 	 	133,460	 	(s)	 	 	133,460	 	
Deferred credits related to income tax	 	 	119,572	 	 	 	(119,572	)	(t)	 	 	—	 	
Regulatory Liabilities	 	 	—	 	 	 	119,572	 	(t)	 	 	119,572	 	
Employee benefit obligations	 	 	18,177	 	 	 	(18,177	)	(u)	 	 	—	 	
Other cost of removal obligations	 	 	50,391	 	 	 	(50,391	)	(u)	 	 	—	 	
Accrued environmental remediation, deferred	 	 	70,191	 	 	 	(70,191	)	(u)	 	 	—	 	
Other deferred credits and liabilities	 	 	1,310	 	 	 	(1,310	)	(u)	 	 	—	 	
Other	 	 	—	 	 	 	140,069	 	(u)	 	 	140,069	 	
Paid—in capital	 	 	166,372	 	 	 	(166,372	)	(v)	 	 	—	 	
Premium on Common Stock	 	 	—	 	 	 	166,372	 	(v)	 	 	166,372	 	

 	(h)	Represents the reclassification of Customer accounts receivable, Unbilled revenues, Other accounts and notes receivable, and Accumulated provision for uncollectible accounts on ETG’s balance sheet into Accounts Receivable, net to conform to SJI’s balance sheet presentation.	
 
 	(i)	Represents the reclassification of Materials and supplies on ETG’s balance sheet into Materials and Supplies, average cost to conform to SJI’s balance sheet presentation.	
 
 	(j)	Represents the reclassification of Natural gas for sale on ETG’s balance sheet into Natural Gas in Storage, average cost to conform to SJI’s balance sheet presentation.	

 	(k)	Represents the reclassification of Prepaid taxes, Regulatory assets, current, and Other current assets on ETG’s balance sheet into Other Prepayments and Current Assets to conform to SJI’s balance sheet presentation.	
 
 	(l)	Represents the reclassification of Property, Plant, and Equipment: In service and Construction work in progress on ETG’s balance sheet into Utility Plant, at original cost to conform to SJI’s balance sheet presentation.	
 
 	(m)	Represents the reclassification of Property, Plant, and Equipment: Less accumulated depreciation on ETG’s balance sheet into Accumulated Depreciation — Utility Plant to conform to SJI’s balance sheet presentation.	
 
 	(n)	Represents the reclassification of Goodwill on ETG’s balance sheet into Goodwill and Identifiable Intangible Assets to conform to SJI’s balance sheet presentation.	
 
 	(o)	Represents the reclassification of Regulatory assets, deferred on ETG’s balance sheet into Regulatory Assets to conform to SJI’s balance sheet presentation.	
 
 	(p)	Represents the reclassification of Other deferred charges and assets on ETG’s balance sheet into Other to conform to SJI’s balance sheet presentation.	
 
 	(q)	Represents the reclassification of Due to affiliates and Accounts payable on ETG’s balance sheet into Accounts Payable to conform to SJI’s balance sheet presentation.	
 
 	(r)	Represents the reclassification of Customer deposits, Other accrued taxes, Accrued environmental remediation, current, Accrued compensation, Regulatory liabilities, current, and Other current liabilities on ETG’s balance sheet into Other Current Liabilities to conform to SJI’s balance sheet presentation.	
 
 	(s)	Represents the reclassification of Accumulated deferred income taxes on ETG’s balance sheet into Deferred Income Taxes — Net to conform to SJI’s balance sheet presentation.	
 
 	(t)	Represents the reclassification of Deferred credits related to income tax on ETG’s balance sheet into Regulatory Liabilities to conform to SJI’s balance sheet presentation.	
 
 	(u)	Represents the reclassification of Employee benefit obligations, Other cost of removal obligations, Accrued environmental remediation, deferred, and Other deferred credits and liabilities on ETG’s balance sheet into Other to conform to SJI’s balance sheet presentation.	
 
 	(v)	Represents the reclassification of Paid—in capital on ETG’s balance sheet into Premium on Common Stock to conform to SJI’s balance sheet presentation.	

 	4.	ETG Acquisition Related Pro Forma Adjustments	

The pro forma financial statements reflect the following adjustments related to the ETG Acquisition:

(a)
(In Thousands)	 	As of
June 30, 2018	  	
Purchase Price	 	$	1,690,000	 	
Working Capital Adjustment	 	 	26,700	 	
Total adjustment to Restricted Cash	 	$	1,716,700	 	

 	(b)	Adjustment to eliminate ETG’s historical goodwill of $126.0 million and to recognize goodwill related to the proposed ETG Acquisition of $746.0 million. Goodwill is calculated as the difference between the estimated purchase price and the fair value of identifiable tangible and intangible assets acquired net of liabilities assumed. The adjustment is preliminary and subject to change based upon final determination of the fair value of assets acquired and liabilities assumed and finalization of the purchase price.	

 	(c)	Adjustment to eliminate ETG’s amounts due to affiliates of $271.9 million that will not be assumed by SJI as part of the ETG Acquisition as of June 30, 2018, as well as $8.2 million and $13.4 million of intercompany interest that will not be assumed by SJI as part of the ETG Acquisition for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively.	

 	(d)	Adjustment to eliminate $268.4 million of ETG’s long—term debt, and $2.0 million and $2.7 million of related interest expense that will not be assumed by SJI as part of the ETG Acquisition for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively.	

 	(e)	Adjustment to eliminate ETG’s historical stockholder’s equity of $444.1 million.	

 	(f)	Adjustment to record the income tax impacts of the pro forma adjustments using blended statutory tax rates of 25.0% and 38.5% for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively. This rate does not reflect SJI’s effective tax rate, which includes other items and may be significantly different than the rates assumed for purposes of preparing these statements for a variety of reasons.	

 	(g)	Adjustment to eliminate $13.2 million and $14.5 million of non-recurring transaction costs incurred by SJI that are directly attributable to the ETG Acquisition for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively.	

 	(h)	Adjustment to eliminate $23.5 million of ETG’s prepaid taxes and $133.5 million of ETG’s accumulated deferred income taxes that will not be assumed by SJI as part of the ETG Acquisition.	

 	(i)	Adjustment to eliminate $36.4 million of ETG’s IT assets and $12.7 million of ETG’s related accumulated depreciation as of June 30, 2018, as well as $2.2 million and $4.7 million of depreciation expense that will not be assumed by SJI as part of the ETG Acquisition for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively.	

 	(j)	Adjustment to record $11.9 million of ETG’s recoverable postretirement benefits assumed by SJI as part of the ETG Acquisition, eliminate $18.2 million of ETG’s accrued pension costs and accrued postretirement benefits that will not be assumed by SJI as part of the ETG Acquisition, and to record a $10.1 million pension benefit obligation assumed by SJI as part of the ETG Acquisition.	
 
 	(k)	Adjustment to eliminate $0.4 million of ETG receivables that will not be assumed by SJI as part of the ETG Acquisition as of June 30, 2018.	

 	(l)	Adjustment to eliminate $3.5 million of ETG’s other accrued taxes, $1.2 million of accrued compensation, and $1.6 million of other current liabilities primarily related to unclaimed property and escheatment liability that will not be assumed by SJI as part of the ETG Acquisition as of June 30, 2018.	

 	5.	Financing and Other Related Pro Forma Adjustments	

The pro forma financial statements reflect the following adjustments related to the financing, the proceeds of which were used to fund the ETG Acquisition, as well as other pro forma adjustments related to the ETG Acquisition.

 	(a)	Adjustment to interest expense consists of the following:	

(In Thousands)	  	Year ended
December 31, 2017	  	  	Six months
 ended
June 30, 2018	  	
Interest expense related to new debt borrowings(1)	 	$	41,742	 	 	$	4,527	 	
Interest expense related to equity units(2)	 	 	11,548	 	 	 	5,614	 	
Interest expense related to draw down from revolver(3)	 	 	954	 	 	 	477	 	
Amortization of deferred financing fees(4)	 	 	3,148	 	 	 	460	 	
Add back: amortization of deferred financing fees and ticking fees related the Bridge Facility (5)	 	 	(5,084	)	 	 	(9,504	)	
Add back: actual interest/amortization expense incurred for the period ended June 30, 2018 (6)	 	 	-	 	 	 	(2,753	)	
Pro forma adjustment to Interest Charges	 	$	52,308	 	 	$	(1,179	)	

(1) Comprised of interest expense related to the Notes and Facilities.
(2) Comprised of interest expense related to the RSNs and accretion of the contract adjustment liability over the life of the purchase contract for the corporate units.
(3) Comprised of interest expense related to the Revolver.
(4) Represents fees paid to the initial purchasers for their services in arranging and structuring the financing as well as other debt issuance costs. Deferred financing fees are amortized using the effective interest method.
(5) Represents fees paid to the initial purchasers for their services in arranging and structuring the financing as well as other debt issuance costs related to Bridge Facility. As there is no continuing impact of the Bridge Facility on SJI’s results, the related expense is not included in the unaudited pro forma condensed combined statement of income for the six months ended June 30, 2018.
(6) Represents actual interest expense and amortization of deferred financing fees incurred and included in the historical results of the Company for the period ended June 30, 2018 related to the Notes and Facilities issued in the second quarter of 2018. These amounts were added back in order to reflect the net effect of the Transactions as if they had occurred on January 1, 2017.

The adjustment to interest expense assumes the principal, stated amount, assumed rates on the Equity Units, stated rates on the Senior Unsecured Notes, and the pro forma weighted average shares outstanding do not change from those assumed as described herein, however, a 0.125% change in the respective variable interest rate of the Floating Rate Notes and Term Facility would result in an increase or decrease in pro forma annual interest expense of approximately $1.3 million for the year ended December 31, 2017. There would be no increase or decrease in pro forma annual interest expense for the year ended June 30, 2018. Additionally, the increase or decrease in pro forma annual interest expense would increase or decrease pro forma annual earnings per share (basic and diluted) by approximately $0.01 per share for the year ended December 31, 2017. There would be no increase or decrease in pro forma annual earnings per share (basic and diluted) for the year ended June 30, 2018.

 	(b)	Adjustment to record the income tax impacts of the pro forma adjustments using blended statutory tax rates of 25.0% and 38.5% for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively. This rate does not reflect SJI’s effective tax rate, which includes other items and may be significantly different than the rates assumed for purposes of preparing these statements for a variety of reasons.	

 	(c)	Adjustment to record a $15.0 million liability for a one-time rate payout to ETG customers mandated by the New Jersey Board of Public Utilities as part of the regulatory approval process for the ETG Acquisition.	

 	6.	Pro Forma Earnings Per Share	

The unaudited pro forma combined basic and diluted earnings per share (“EPS”) for the six months ended June 30, 2018 and for the year ended December 31, 2017 are based on pro forma income from continuing operations reflecting the adjustments discussed above divided by the basic and diluted pro forma weighted-average number of common shares outstanding. The unaudited pro forma basic EPS calculation gives effect to the issuance of 5.9 million shares of common stock related to the Common Stock Issuance as if they were issued and outstanding as of January 1, 2017, such that the total average of weighted shares outstanding would be 85.5 million and 85.4 million for the six months ended June 30, 2018 and for the year ended December 31, 2017, respectively, on a pro forma combined basis. The unaudited pro forma diluted EPS calculation should give effect to all potentially dilutive shares following the close of the Transactions, including: (i) shares issuable pursuant to the share purchase contracts as part of the issuance of the Equity Units, based on the application of the treasury stock method, and (ii) shares issuable pursuant to the forward sale agreement as part of the issuance of common stock, based on the application of the treasury stock method. For purposes of calculating unaudited pro forma diluted EPS, the exercise of the share purchase contracts and exercise of the forward sale agreement is assumed to have occurred at the beginning of the period. The shares issuable pursuant to the exercise of the share purchase contracts and the exercise of the forward sale have been excluded from the calculation of unaudited pro forma diluted EPS because the effect would have been anti-dilutive for the year ended December 31, 2017. The dilutive impact of the forward sale agreement did not impact the unaudited pro forma diluted EPS calculation for the year ended June 30, 2018.

The unaudited pro forma basic and diluted EPS are calculated as follows:
 
(In Thousands Except Share and Per Share Data)	  	Year ended
December 31, 2017	  	  	Six months
ended
June 30, 2018	  	
Pro Forma Basic EPS	 	 	 	 	 	 	
Pro forma income from continuing operations	 	$	19,911	 	 	$	63,032	 	
Pro forma basic weighted—average common stock outstanding	 	 	85,431	 	 	 	85,472	 	
Pro forma basic EPS	 	$	0.23	 	 	$	0.74	 	
 	 	 	 	 	 	 	 	 	
Pro Forma Diluted EPS	 	 	 	 	 	 	 	 	
Pro forma income from continuing operations	 	$	19,911	 	 	$	63,032	 	
Pro forma diluted weighted—average common shares outstanding	 	 	85,431	 	 	 	86,030	 	
Pro forma diluted EPS	 	$	0.23	 	 	$	0.73