10-Q


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended December 31, 2015
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                    
Commission File Number 1-10042
Atmos Energy Corporation
(Exact name of registrant as specified in its charter)
 
Texas and Virginia
 
75-1743247
(State or other jurisdiction of
incorporation or organization)
 
(IRS employer
identification no.)
 
 
Three Lincoln Centre, Suite 1800
5430 LBJ Freeway, Dallas, Texas
 
75240
(Zip code)
(Address of principal executive offices)
 
 
(972) 934-9227
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer  þ
  
Accelerated Filer  ¨
  
Non-Accelerated Filer  ¨
  
Smaller Reporting Company  ¨
(Do not check if a smaller reporting company)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)    Yes  ¨    No  þ
Number of shares outstanding of each of the issuer’s classes of common stock, as of January 29, 2016.
Class
  
Shares Outstanding
No Par Value
  
102,106,896



GLOSSARY OF KEY TERMS
 
 
 
AEC
Atmos Energy Corporation
AEH
Atmos Energy Holdings, Inc.
AEM
Atmos Energy Marketing, LLC
AOCI
Accumulated other comprehensive income
Bcf
Billion cubic feet
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings, Ltd.
GAAP
Generally Accepted Accounting Principles
GRIP
Gas Reliability Infrastructure Program
Mcf
Thousand cubic feet
MMcf
Million cubic feet
Moody’s
Moody’s Investors Services, Inc.
NYMEX
New York Mercantile Exchange, Inc.
PPA
Pension Protection Act of 2006
PRP
Pipeline Replacement Program
RRC
Railroad Commission of Texas
RRM
Rate Review Mechanism
S&P
Standard & Poor’s Corporation
SEC
United States Securities and Exchange Commission
WNA
Weather Normalization Adjustment

2


PART I. FINANCIAL INFORMATION
Item 1.
Financial Statements
ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
 
 
December 31,
2015
 
September 30,
2015
 
(Unaudited)
 
 
 
(In thousands, except
share data)
ASSETS
 
 
 
Property, plant and equipment
$
9,502,944

 
$
9,240,100

Less accumulated depreciation and amortization
1,849,657

 
1,809,520

Net property, plant and equipment
7,653,287

 
7,430,580

Current assets
 
 
 
Cash and cash equivalents
78,903

 
28,653

Accounts receivable, net
456,904

 
295,160

Gas stored underground
236,017

 
236,603

Other current assets
91,446

 
70,569

Total current assets
863,270

 
630,985

Goodwill
742,702

 
742,702

Deferred charges and other assets
295,394

 
288,678

 
$
9,554,653

 
$
9,092,945

CAPITALIZATION AND LIABILITIES
 
 
 
Shareholders’ equity
 
 
 
Common stock, no par value (stated at $.005 per share); 200,000,000 shares authorized; issued and outstanding: December 31, 2015 — 102,079,316 shares; September 30, 2015 — 101,478,818 shares
$
510

 
$
507

Additional paid-in capital
2,242,307

 
2,230,591

Accumulated other comprehensive loss
(102,962
)
 
(109,330
)
Retained earnings
1,132,254

 
1,073,029

Shareholders’ equity
3,272,109

 
3,194,797

Long-term debt
2,455,474

 
2,455,388

Total capitalization
5,727,583

 
5,650,185

Current liabilities
 
 
 
Accounts payable and accrued liabilities
280,487

 
238,942

Other current liabilities
471,333

 
457,954

Short-term debt
763,236

 
457,927

Total current liabilities
1,515,056

 
1,154,823

Deferred income taxes
1,441,325

 
1,411,315

Regulatory cost of removal obligation
425,555

 
427,553

Pension and postretirement liabilities
289,939

 
287,373

Deferred credits and other liabilities
155,195

 
161,696

 
$
9,554,653

 
$
9,092,945

See accompanying notes to condensed consolidated financial statements.

3


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
 
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(Unaudited)
(In thousands, except per
share data)
Operating revenues
 
 
 
Regulated distribution segment
$
638,602

 
$
846,772

Regulated pipeline segment
94,677

 
83,567

Nonregulated segment
272,524

 
462,288

Intersegment eliminations
(99,582
)
 
(133,862
)
 
906,221

 
1,258,765

Purchased gas cost
 
 
 
Regulated distribution segment
305,141

 
522,960

Regulated pipeline segment
—

 
—

Nonregulated segment
256,766

 
446,249

Intersegment eliminations
(99,449
)
 
(133,729
)
 
462,458

 
835,480

Gross profit
443,763

 
423,285

Operating expenses
 
 
 
Operation and maintenance
124,848

 
118,582

Depreciation and amortization
71,239

 
67,593

Taxes, other than income
51,471

 
49,385

Total operating expenses
247,558

 
235,560

Operating income
196,205

 
187,725

Miscellaneous expense
(1,209
)
 
(1,707
)
Interest charges
30,483

 
29,764

Income before income taxes
164,513

 
156,254

Income tax expense
61,652

 
58,659

Net income
$
102,861

 
$
97,595

Basic and diluted net income per share
$
1.00

 
$
0.96

Cash dividends per share
$
0.42

 
$
0.39

Basic and diluted weighted average shares outstanding
102,713

 
101,581

See accompanying notes to condensed consolidated financial statements.







 
 
 
 
 



4



ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
 
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(Unaudited)
(In thousands)
Net income
$
102,861

 
$
97,595

Other comprehensive income (loss), net of tax
 
 
 
Net unrealized holding losses on available-for-sale securities, net of tax of $442 and $613
(768
)
 
(1,067
)
Cash flow hedges:
 
 
 
Amortization and unrealized gain (loss) on interest rate agreements, net of tax of $2,749 and $(29,768)
4,783

 
(51,787
)
Net unrealized gains (losses) on commodity cash flow hedges, net of tax of $1,505 and $(18,696)
2,353

 
(28,952
)
Total other comprehensive income (loss)
6,368

 
(81,806
)
Total comprehensive income
$
109,229

 
$
15,789


See accompanying notes to condensed consolidated financial statements.

5


ATMOS ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(Unaudited)
(In thousands)
Cash Flows From Operating Activities
 
 
 
Net income
$
102,861

 
$
97,595

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization:
 
 
 
Charged to depreciation and amortization
71,239

 
67,593

Charged to other accounts
326

 
275

Deferred income taxes
59,299

 
55,418

Other
4,407

 
4,889

Net assets / liabilities from risk management activities
(7,495
)
 
(20,828
)
Net change in operating assets and liabilities
(160,144
)
 
(177,527
)
Net cash provided by operating activities
70,493

 
27,415

Cash Flows From Investing Activities
 
 
 
Capital expenditures
(291,674
)
 
(261,313
)
Other, net
1,029

 
(739
)
Net cash used in investing activities
(290,645
)
 
(262,052
)
Cash Flows From Financing Activities
 
 
 
Net increase in short-term debt
305,309

 
350,574

Net proceeds from issuance of long-term debt
—

 
493,538

Settlement of interest rate agreements
—

 
13,364

Repayment of long-term debt
—

 
(500,000
)
Cash dividends paid
(43,636
)
 
(39,592
)
Repurchase of equity awards
—

 
(7,985
)
Issuance of common stock
8,729

 
6,312

Net cash provided by financing activities
270,402

 
316,211

Net increase in cash and cash equivalents
50,250

 
81,574

Cash and cash equivalents at beginning of period
28,653

 
42,258

Cash and cash equivalents at end of period
$
78,903

 
$
123,832


See accompanying notes to condensed consolidated financial statements.

6


ATMOS ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
December 31, 2015
1.    Nature of Business
Atmos Energy Corporation (“Atmos Energy” or the “Company”) and our subsidiaries are engaged primarily in the regulated natural gas distribution and pipeline businesses as well as other nonregulated natural gas businesses. Historically, our regulated businesses have generated over 90 percent of our consolidated net income.
Through our regulated distribution business, we deliver natural gas through sales and transportation arrangements to approximately three million residential, commercial, public authority and industrial customers through our six regulated distribution divisions, which at December 31, 2015, covered service areas located in eight states. In addition, we transport natural gas for others through our distribution system. Our regulated businesses also include our regulated pipeline and storage operations, which include the transportation of natural gas to our North Texas distribution system and the management of our underground storage facilities. Our regulated businesses are subject to federal and state regulation and/or regulation by local authorities in each of the states in which our regulated distribution divisions operate.
Our nonregulated businesses operate primarily in the Midwest and Southeast through various wholly-owned subsidiaries of Atmos Energy Holdings, Inc. (AEH). AEH is wholly owned by the Company and based in Houston, Texas. Through AEH, we provide natural gas management and transportation services to municipalities, natural gas distribution companies, including certain divisions of Atmos Energy, and third parties.

2.    Unaudited Financial Information
These consolidated interim-period financial statements have been prepared in accordance with accounting principles generally accepted in the United States on the same basis as those used for the Company’s audited consolidated financial statements included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. In the opinion of management, all material adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been made to the unaudited consolidated interim-period financial statements. These consolidated interim-period financial statements are condensed as permitted by the instructions to Form 10-Q and should be read in conjunction with the audited consolidated financial statements of Atmos Energy Corporation included in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. Because of seasonal and other factors, the results of operations for the three-month period ended December 31, 2015 are not indicative of our results of operations for the full 2016 fiscal year, which ends September 30, 2016.
No events have occurred subsequent to the balance sheet date that would require recognition or disclosure in the condensed consolidated financial statements.

Significant accounting policies
Our accounting policies are described in Note 2 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015.
In May 2014, the Financial Accounting Standards Board (FASB) issued a comprehensive new revenue recognition standard that will supersede virtually all existing revenue recognition guidance under generally accepted accounting principles in the United States. Under the new standard, a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. The new standard is currently scheduled to become effective for us beginning on October 1, 2018 and can be applied either retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will select.
In April 2015, the FASB issued guidance to simplify the presentation of debt issuance costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The new standard will be effective for us beginning on October 1, 2016, and will be applied retrospectively. We are currently evaluating the impact this standard may have on our financial position, results of operations and cash flows.
In November 2015, the FASB issued guidance that requires all deferred income tax liabilities and assets to be presented as noncurrent in a classified balance sheet. Currently, entities are required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. The new standard will become effective for us beginning on October 1, 2017, with the option to early adopt, and can be applied either prospectively or retrospectively. The adoption of this

7


guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent will affect the presentation of our balance sheet.
Regulatory assets and liabilities
Accounting principles generally accepted in the United States require cost-based, rate-regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. As a result, certain costs are permitted to be capitalized rather than expensed because they can be recovered through rates. We record certain costs as regulatory assets when future recovery through customer rates is considered probable. Regulatory liabilities are recorded when it is probable that revenues will be reduced for amounts that will be credited to customers through the ratemaking process. Substantially all of our regulatory assets are recorded as a component of deferred charges and other assets and substantially all of our regulatory liabilities are recorded as a component of deferred credits and other liabilities. Deferred gas costs are recorded either in other current assets or liabilities and the regulatory cost of removal obligation is reported separately.
 
Significant regulatory assets and liabilities as of December 31, 2015 and September 30, 2015 included the following:
 
December 31,
2015
 
September 30,
2015
 
(In thousands)
Regulatory assets:
 
 
 
Pension and postretirement benefit costs(1)
$
116,485

 
$
121,183

Infrastructure mechanisms(2)
43,385

 
32,813

Deferred gas costs
16,310

 
9,715

Recoverable loss on reacquired debt
15,680

 
16,319

APT annual adjustment mechanism
—

 
1,002

Rate case costs
1,568

 
1,533

Other
11,878

 
9,774

 
$
205,306

 
$
192,339

Regulatory liabilities:
 
 
 
Regulatory cost of removal obligation
$
482,544

 
$
483,676

Deferred gas costs
32,895

 
28,100

Asset retirement obligation
9,063

 
9,063

APT annual adjustment mechanism
1,721

 
—

Other
3,415

 
3,693

 
$
529,638

 
$
524,532

 
(1) 
Includes $14.3 million and $16.6 million of pension and postretirement expense deferred pursuant to regulatory authorization.
(2) 
Infrastructure mechanisms in Texas and Louisiana allow for the deferral of all expenses associated with capital expenditures incurred pursuant to these rules, which primarily consists of interest, depreciation and other taxes, until the next rate proceeding (rate case or annual rate filing), at which time investment and costs would be recoverable through base rates.

3.    Segment Information
We operate the Company through the following three segments:
•
The regulated distribution segment, which includes our regulated natural gas distribution and related sales operations,
•
The regulated pipeline segment, which includes the regulated pipeline and storage operations of our Atmos Pipeline — Texas Division and
•
The nonregulated segment, which is comprised of our nonregulated natural gas management, nonregulated natural gas transmission, storage and other services.
 
Our determination of reportable segments considers the strategic operating units under which we manage sales of various products and services to customers in differing regulatory environments. Although our regulated distribution segment operations are geographically dispersed, they are reported as a single segment as each regulated distribution division has similar economic characteristics. The accounting policies of the segments are the same as those described in the summary of significant

8


accounting policies found in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. We evaluate performance based on net income or loss of the respective operating units.
Income statements for the three month periods ended December 31, 2015 and 2014 by segment are presented in the following tables:
 
Three Months Ended December 31, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
637,167

 
$
23,407

 
$
245,647

 
$
—

 
$
906,221

Intersegment revenues
1,435

 
71,270

 
26,877

 
(99,582
)
 
—

 
638,602

 
94,677

 
272,524

 
(99,582
)
 
906,221

Purchased gas cost
305,141

 
—

 
256,766

 
(99,449
)
 
462,458

Gross profit
333,461

 
94,677

 
15,758

 
(133
)
 
443,763

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
91,349

 
27,088

 
6,544

 
(133
)
 
124,848

Depreciation and amortization
57,334

 
12,770

 
1,135

 
—

 
71,239

Taxes, other than income
45,261

 
5,571

 
639

 
—

 
51,471

Total operating expenses
193,944

 
45,429

 
8,318

 
(133
)
 
247,558

Operating income
139,517

 
49,248

 
7,440

 
—

 
196,205

Miscellaneous income (expense)
(752
)
 
(429
)
 
379

 
(407
)
 
(1,209
)
Interest charges
20,705

 
9,147

 
1,038

 
(407
)
 
30,483

Income before income taxes
118,060

 
39,672

 
6,781

 
—

 
164,513

Income tax expense
44,805

 
14,086

 
2,761

 
—

 
61,652

Net income
$
73,255

 
$
25,586

 
$
4,020

 
$
—

 
$
102,861

Capital expenditures
$
166,544

 
$
125,283

 
$
(153
)
 
$
—

 
$
291,674

 
Three Months Ended December 31, 2014
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
Operating revenues from external parties
$
845,404

 
$
20,551

 
$
392,810

 
$
—

 
$
1,258,765

Intersegment revenues
1,368

 
63,016

 
69,478

 
(133,862
)
 
—

 
846,772

 
83,567

 
462,288

 
(133,862
)
 
1,258,765

Purchased gas cost
522,960

 
—

 
446,249

 
(133,729
)
 
835,480

Gross profit
323,812

 
83,567

 
16,039

 
(133
)
 
423,285

Operating expenses
 
 
 
 
 
 
 
 
 
Operation and maintenance
86,985

 
24,615

 
7,115

 
(133
)
 
118,582

Depreciation and amortization
55,086

 
11,382

 
1,125

 
—

 
67,593

Taxes, other than income
43,644

 
4,865

 
876

 
—

 
49,385

Total operating expenses
185,715

 
40,862

 
9,116

 
(133
)
 
235,560

Operating income
138,097

 
42,705

 
6,923

 
—

 
187,725

Miscellaneous income (expense)
(1,329
)
 
(252
)
 
300

 
(426
)
 
(1,707
)
Interest charges
21,640

 
8,324

 
226

 
(426
)
 
29,764

Income before income taxes
115,128

 
34,129

 
6,997

 
—

 
156,254

Income tax expense
43,741

 
12,094

 
2,824

 
—

 
58,659

Net income
$
71,387

 
$
22,035

 
$
4,173

 
$
—

 
$
97,595

Capital expenditures
$
166,247

 
$
94,754

 
$
312

 
$
—

 
$
261,313


9


 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance sheet information at December 31, 2015 and September 30, 2015 by segment is presented in the following tables:

 
December 31, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,779,479

 
$
1,821,114

 
$
52,694

 
$
—

 
$
7,653,287

Investment in subsidiaries
1,020,629

 
—

 
—

 
(1,020,629
)
 
—

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
57,691

 
—

 
21,212

 
—

 
78,903

Assets from risk management activities
716

 
—

 
18,229

 
—

 
18,945

Other current assets
589,257

 
20,008

 
420,897

 
(264,740
)
 
765,422

Intercompany receivables
943,005

 
—

 
—

 
(943,005
)
 
—

Total current assets
1,590,669

 
20,008

 
460,338

 
(1,207,745
)
 
863,270

Goodwill
575,449

 
132,542

 
34,711

 
—

 
742,702

Noncurrent assets from risk management activities
96

 
—

 
—

 
—

 
96

Deferred charges and other assets
277,662

 
17,095

 
541

 
—

 
295,298

 
$
9,243,984

 
$
1,990,759

 
$
548,284

 
$
(2,228,374
)
 
$
9,554,653

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,272,109

 
$
602,861

 
$
417,768

 
$
(1,020,629
)
 
$
3,272,109

Long-term debt
2,455,474

 
—

 
—

 
—

 
2,455,474

Total capitalization
5,727,583

 
602,861

 
417,768

 
(1,020,629
)
 
5,727,583

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
1,017,236

 
—

 
—

 
(254,000
)
 
763,236

Liabilities from risk management activities
6,738

 
—

 
—

 
—

 
6,738

Other current liabilities
625,055

 
28,197

 
102,570

 
(10,740
)
 
745,082

Intercompany payables
—

 
923,366

 
19,639

 
(943,005
)
 
—

Total current liabilities
1,649,029

 
951,563

 
122,209

 
(1,207,745
)
 
1,515,056

Deferred income taxes
1,008,353

 
434,497

 
(1,525
)
 
—

 
1,441,325

Noncurrent liabilities from risk management activities
103,337

 
—

 
—

 
—

 
103,337

Regulatory cost of removal obligation
425,555

 
—

 
—

 
—

 
425,555

Pension and postretirement liabilities
289,939

 
—

 
—

 
—

 
289,939

Deferred credits and other liabilities
40,188

 
1,838

 
9,832

 
—

 
51,858

 
$
9,243,984

 
$
1,990,759

 
$
548,284

 
$
(2,228,374
)
 
$
9,554,653


10




 
September 30, 2015
 
Regulated
Distribution
 
Regulated
Pipeline
 
Nonregulated
 
Eliminations
 
Consolidated
 
(In thousands)
ASSETS
 
 
 
 
 
 
 
 
 
Property, plant and equipment, net
$
5,670,306

 
$
1,706,449

 
$
53,825

 
$
—

 
$
7,430,580

Investment in subsidiaries
1,038,670

 
—

 
(2,096
)
 
(1,036,574
)
 
—

Current assets
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
23,863

 
—

 
4,790

 
—

 
28,653

Assets from risk management activities
378

 
—

 
8,854

 
—

 
9,232

Other current assets
426,270

 
24,628

 
480,503

 
(338,301
)
 
593,100

Intercompany receivables
887,713

 
—

 
—

 
(887,713
)
 
—

Total current assets
1,338,224

 
24,628

 
494,147

 
(1,226,014
)
 
630,985

Goodwill
575,449

 
132,542

 
34,711

 
—

 
742,702

Noncurrent assets from risk management activities
368

 
—

 
—

 
—

 
368

Deferred charges and other assets
265,693

 
17,288

 
5,329

 
—

 
288,310

 
$
8,888,710

 
$
1,880,907

 
$
585,916

 
$
(2,262,588
)
 
$
9,092,945

CAPITALIZATION AND LIABILITIES
 
 
 
 
 
 
 
 
 
Shareholders’ equity
$
3,194,797

 
$
577,275

 
$
461,395

 
$
(1,038,670
)
 
$
3,194,797

Long-term debt
2,455,388

 
—

 
—

 
—

 
2,455,388

Total capitalization
5,650,185

 
577,275

 
461,395

 
(1,038,670
)
 
5,650,185

Current liabilities
 
 
 
 
 
 
 
 
 
Short-term debt
782,927

 
—

 
—

 
(325,000
)
 
457,927

Liabilities from risk management activities
9,568

 
—

 
—

 
—

 
9,568

Other current liabilities
569,273

 
29,780

 
99,480

 
(11,205
)
 
687,328

Intercompany payables
—

 
867,409

 
20,304

 
(887,713
)
 
—

Total current liabilities
1,361,768

 
897,189

 
119,784

 
(1,223,918
)
 
1,154,823

Deferred income taxes
1,008,091

 
406,254

 
(3,030
)
 
—

 
1,411,315

Noncurrent liabilities from risk management activities
110,539

 
—

 
—

 
—

 
110,539

Regulatory cost of removal obligation
427,553

 
—

 
—

 
—

 
427,553

Pension and postretirement liabilities
287,373

 
—

 
—

 
—

 
287,373

Deferred credits and other liabilities
43,201

 
189

 
7,767

 
—

 
51,157

 
$
8,888,710

 
$
1,880,907

 
$
585,916

 
$
(2,262,588
)
 
$
9,092,945


11



4.    Earnings Per Share
We use the two-class method of computing earnings per share because we have participating securities in the form of non-vested restricted stock units with a nonforfeitable right to dividend equivalents, for which vesting is predicated solely on the passage of time. The calculation of earnings per share using the two-class method excludes income attributable to these participating securities from the numerator and excludes the dilutive impact of those shares from the denominator. Basic and diluted earnings per share for the three months ended December 31, 2015 and 2014 are calculated as follows:
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(In thousands, except per share amounts)
Basic and Diluted Earnings Per Share
 
 
 
Net income
$
102,861

 
$
97,595

Less: Income allocated to participating securities
172

 
216

Income available to common shareholders
$
102,689

 
$
97,379

Basic and diluted weighted average shares outstanding
102,713

 
101,581

Net income per share - Basic and Diluted
$
1.00

 
$
0.96

2011 Share Repurchase Program
We did not repurchase any shares during the three months ended December 31, 2015 and 2014 under our 2011 share repurchase program, which is scheduled to end on September 30, 2016.
5.    Debt
The nature and terms of our debt instruments and credit facilities are described in detail in Note 5 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. Except as noted below, there were no material changes in the terms of our debt instruments during the three months ended December 31, 2015.
Long-term debt
Long-term debt at December 31, 2015 and September 30, 2015 consisted of the following:
 
 
December 31, 2015
 
September 30, 2015
 
(In thousands)
Unsecured 6.35% Senior Notes, due June 2017
$
250,000

 
$
250,000

Unsecured 8.50% Senior Notes, due 2019
450,000

 
450,000

Unsecured 5.95% Senior Notes, due 2034
200,000

 
200,000

Unsecured 5.50% Senior Notes, due 2041
400,000

 
400,000

Unsecured 4.15% Senior Notes, due 2043
500,000

 
500,000

Unsecured 4.125% Senior Notes, due 2044
500,000

 
500,000

Medium-term note Series A, 1995-1, 6.67%, due 2025
10,000

 
10,000

Unsecured 6.75% Debentures, due 2028
150,000

 
150,000

Total long-term debt
2,460,000

 
2,460,000

Less:
 
 
 
Original issue discount on unsecured senior notes and debentures
4,526

 
4,612

 
$
2,455,474

 
$
2,455,388

 
On October 15, 2014, we issued $500 million of 4.125% 30-year unsecured senior notes, which replaced, on a long-term basis, our $500 million unsecured 4.95% senior notes. The effective rate of these notes is 4.086%, after giving effect to the offering costs and the settlement of the associated forward starting interest rate swaps. The net proceeds of approximately $494 million were used to repay our $500 million 4.95% senior unsecured notes at maturity on October 15, 2014.


12


Short-term debt
Our short-term debt is utilized to fund ongoing working capital needs, such as our seasonal requirements for gas supply, general corporate liquidity and capital expenditures. Our short-term borrowing requirements are affected primarily by the seasonal nature of the natural gas business. Changes in the price of natural gas and the amount of natural gas we need to supply our customers’ needs could significantly affect our borrowing requirements. Our short-term borrowings typically reach their highest levels in the winter months.
We currently finance our short-term borrowing requirements through a combination of a $1.25 billion commercial paper program, four committed revolving credit facilities and one uncommitted revolving credit facility with third-party lenders. These facilities provide approximately $1.3 billion of working capital funding. At December 31, 2015 and September 30, 2015 a total of $763.2 million and $457.9 million was outstanding under our commercial paper program.
Regulated Operations
We fund our regulated operations as needed, primarily through our commercial paper program and three committed revolving credit facilities with third-party lenders that provide approximately $1.3 billion of working capital funding, including a five-year $1.25 billion unsecured facility with an accordion feature, which, if utilized would increase the borrowing capacity to $1.5 billion, a $25 million unsecured facility and a $10 million unsecured revolving credit facility, which is used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under our $10 million revolving credit facility was $4.1 million at December 31, 2015.
In addition to these third-party facilities, our regulated operations have a $500 million intercompany revolving credit facility with AEH, which bears interest at the lower of (i) the Eurodollar rate under the five-year revolving credit facility or (ii) the lowest rate outstanding under the commercial paper program. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016.
Nonregulated Operations
Atmos Energy Marketing, LLC (AEM), which is wholly owned by AEH, has one uncommitted $25 million bilateral credit facility and one committed $15 million bilateral credit facility that were renewed and extended in December 2015. The uncommitted $25 million bilateral credit facility currently expires in March 2016 and the $15 million bilateral credit facility expires in September 2016. These facilities are used primarily to issue letters of credit. Due to outstanding letters of credit, the total amount available to us under these bilateral credit facilities was $36.2 million at December 31, 2015.
AEH has a $500 million intercompany demand credit facility with AEC. This facility bears interest at a rate equal to the one-month LIBOR rate plus 3.00 percent. Applicable state regulatory commissions have approved our use of this facility through December 31, 2016.
Shelf Registration

We filed a shelf registration statement with the Securities and Exchange Commission (SEC) on March 28, 2013 that originally permitted us to issue a total of $1.75 billion in common stock and/or debt securities. At December 31, 2015, $845 million of securities remain available for issuance under the shelf registration statement until March 28, 2016.
Debt Covenants
The availability of funds under our regulated credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in each of these facilities to maintain, at the end of each fiscal quarter, a ratio of total debt to total capitalization of no greater than 70 percent. At December 31, 2015, our total-debt-to-total-capitalization ratio, as defined in the agreements, was 51 percent. In addition, both the interest margin and the fee that we pay on unused amounts under certain of these facilities are subject to adjustment depending upon our credit ratings.
In addition to these financial covenants, our credit facilities and public indentures contain usual and customary covenants for our business, including covenants substantially limiting liens, substantial asset sales and mergers.
Additionally, our public debt indentures relating to our senior notes and debentures, as well as certain of our revolving credit agreements, each contain a default provision that is triggered if outstanding indebtedness arising out of any other credit agreements in amounts ranging from in excess of $15 million to in excess of $100 million becomes due by acceleration or is not paid at maturity.

13


We were in compliance with all of our debt covenants as of December 31, 2015. If we were unable to comply with our debt covenants, we would likely be required to repay our outstanding balances on demand, provide additional collateral or take other corrective actions.

6.     Interim Pension and Other Postretirement Benefit Plan Information
The components of our net periodic pension cost for our pension and other postretirement benefit plans for the three months ended December 31, 2015 and 2014 are presented in the following table. Most of these costs are recoverable through our gas distribution rates; however, a portion of these costs is capitalized into our gas distribution rate base. The remaining costs are recorded as a component of operation and maintenance expense.
 
Three Months Ended December 31
 
Pension Benefits
 
Other Benefits
 
2015
 
2014
 
2015
 
2014
 
(In thousands)
Components of net periodic pension cost:
 
 
 
 
 
 
 
Service cost
$
4,698

 
$
5,051

 
$
2,706

 
$
3,896

Interest cost
7,095

 
6,699

 
3,106

 
3,596

Expected return on assets
(6,881
)
 
(6,436
)
 
(1,566
)
 
(1,608
)
Amortization of transition obligation
—

 
—

 
21

 
68

Amortization of prior service credit
(57
)
 
(49
)
 
(411
)
 
(411
)
Amortization of actuarial loss
3,320

 
3,917

 
(542
)
 
—

Net periodic pension cost
$
8,175

 
$
9,182

 
$
3,314

 
$
5,541

 
 
 
 
 
 
 
 
The assumptions used to develop our net periodic pension cost for the three months ended December 31, 2015 and 2014 are as follows:
 
 
Pension Benefits
 
Other Benefits
 
 
2015
 
2014
 
2015
 
2014
Discount rate
 
4.55
%
 
4.43
%
 
4.55
%
 
4.43
%
Rate of compensation increase
 
3.50
%
 
3.50
%
 
N/A

 
N/A

Expected return on plan assets
 
7.00
%
 
7.25
%
 
4.45
%
 
4.60
%
The discount rate used to compute the present value of a plan’s liabilities generally is based on rates of high-grade corporate bonds with maturities similar to the average period over which the benefits will be paid. Generally, our funding policy has been to contribute annually an amount in accordance with the requirements of the Employee Retirement Income Security Act of 1974. In accordance with the Pension Protection Act of 2006 (PPA), we determined the funded status of our plans as of January 1, 2016. Based on that determination, we are not required to make a minimum contribution to our defined benefit plans during the first quarter of fiscal 2016, nor do we anticipate making a contribution during the remainder of the fiscal year.
We contributed $5.5 million to our other post-retirement benefit plans during the three months ended December 31, 2015. We expect to contribute between $15 million and $25 million to these plans during fiscal 2016.

7.    Commitments and Contingencies
Litigation and Environmental Matters
With respect to the specific litigation and environmental-related matters or claims that were disclosed in Note 10 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015, there were no material changes in the status of such litigation and environmental-related matters or claims during the three months ended December 31, 2015.
We are a party to various litigation and environmental-related matters or claims that have arisen in the ordinary course of our business. While the results of such litigation and response actions to such environmental-related matters or claims cannot be predicted with certainty, we continue to believe the final outcome of such litigation and matters or claims will not have a material adverse effect on our financial condition, results of operations or cash flows.

14


Purchase Commitments
Our regulated distribution divisions, except for our Mid-Tex Division, maintain supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated base gas volumes are established under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month in accordance with the terms of the individual contract.
Our Mid-Tex Division also maintains a limited number of long-term supply contracts to ensure a reliable source of gas for our customers in its service area which obligate it to purchase specified volumes at prices indexed to natural gas distribution hubs. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. There were no material changes to the purchase commitments for the three months ended December 31, 2015.
AEH has commitments to purchase physical quantities of natural gas under contracts indexed to the forward NYMEX strip or fixed price contracts. These purchase commitment contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. Except for purchases made in the normal course of business under these contracts, there were no material changes to the purchase commitments for the three months ended December 31, 2015.
Our nonregulated segment maintains long-term contracts related to storage and transportation. These estimated contractual demand fees for contracted storage and transportation under these contracts are detailed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. There were no material changes to the estimated storage and transportation fees for the three months ended December 31, 2015.
Regulatory Matters
Various regulatory agencies, including the SEC and the Commodities Futures Trading Commission, continue to adopt regulations implementing many of the provisions of the Dodd-Frank Act of 2010. We continue to enact new procedures and modify existing business practices and contractual arrangements to comply with such regulations.  Additional rulemakings are pending which we believe will result in new reporting and disclosure obligations. The costs associated with hedging certain risks inherent in our business may be further increased when these expected additional regulations are adopted.
As of December 31, 2015, rate cases were in progress in our Colorado, Kansas and Kentucky service areas and formula rate filing mechanisms were in progress in Colorado, Kansas, Louisiana and West Texas. These regulatory proceedings are discussed in further detail below in Management’s Discussion and Analysis — Recent Ratemaking Developments.
8.    Financial Instruments
We currently use financial instruments in our regulated distribution and nonregulated segments to mitigate commodity price risk and interest rate risk. The objectives and strategies for using financial instruments, which have been tailored to our regulated distribution and nonregulated segments, and the related accounting for these financial instruments are fully described in Notes 2 and 12 to the consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. During the three months ended December 31, 2015 there were no changes in our objectives, strategies and accounting for using financial instruments. Our financial instruments do not contain any credit-risk-related or other contingent features that could cause payments to be accelerated when our financial instruments are in net liability positions. The following summarizes those objectives and strategies.

Regulated Commodity Risk Management Activities
Our purchased gas cost adjustment mechanisms essentially insulate our regulated distribution segment from commodity price risk; however, our customers are exposed to the effects of volatile natural gas prices. We manage this exposure through a combination of physical storage, fixed-price forward contracts and financial instruments, primarily over-the-counter swap and option contracts, in an effort to minimize the impact of natural gas price volatility on our customers during the winter heating season.
We typically seek to hedge between 25 and 50 percent of anticipated heating season gas purchases using financial instruments. For the 2015-2016 heating season (generally October through March), in the jurisdictions where we are permitted to utilize financial instruments, we anticipate hedging approximately 33 percent, or 23.0 Bcf of the winter flowing gas requirements. We have not designated these financial instruments as hedges for accounting purposes.

Nonregulated Commodity Risk Management Activities
Our nonregulated segment is exposed to risks associated with changes in the market price of natural gas through the purchase, sale and delivery of natural gas to its customers at competitive prices. We manage our exposure to such risks through a combination of physical storage and financial instruments, including futures, over-the-counter and exchange-traded options and swap contracts with counterparties. Specifically, these operations use financial instruments in the following ways:

15


•
Gas delivery and related services - Certain financial instruments, designated as cash flow hedges of anticipated purchases and sales at index prices, are used to mitigate the commodity price risk associated with deliveries under fixed-priced forward contracts to either deliver gas to customers or purchase gas from suppliers. These financial instruments have maturity dates ranging from one to 58 months.
•
Transportation and storage services - Our nonregulated operations use storage swaps and futures to capture additional storage arbitrage opportunities that arise subsequent to the execution of the original fair value hedge associated with our physical natural gas inventory, basis swaps to insulate and protect the economic value of our fixed price and storage books and various over-the-counter and exchange-traded options. These financial instruments have not been designated as hedges for accounting purposes.
•
Aggregating and purchasing gas supply - Certain financial instruments, designated as fair value hedges, are used to hedge our natural gas inventory used in asset optimization activities.

Interest Rate Risk Management Activities
We periodically manage interest rate risk by entering into financial instruments to effectively fix the Treasury yield component of the interest cost associated with anticipated financings.
As of December 31, 2015, we had forward starting interest rate swaps to effectively fix the Treasury yield component associated with the anticipated issuance of $250 million and $450 million unsecured senior notes in fiscal 2017 and fiscal 2019, at 3.37% and 3.78%, which we designated as cash flow hedges at the time the swaps were executed. As of December 31, 2015, we had $18.6 million of net realized losses in accumulated other comprehensive income (AOCI) associated with the settlement of financial instruments used to fix the Treasury yield component of the interest cost of financing various issuances of long-term debt and senior notes, which will be recognized as a component of interest expense over the life of the associated notes from the date of settlement. The remaining amortization periods for these settled amounts extend through fiscal 2045.
 
Quantitative Disclosures Related to Financial Instruments
The following tables present detailed information concerning the impact of financial instruments on our condensed consolidated balance sheet and income statements.
As of December 31, 2015, our financial instruments were comprised of both long and short commodity positions. A long position is a contract to purchase the commodity, while a short position is a contract to sell the commodity. As of December 31, 2015, we had net long/(short) commodity contracts outstanding in the following quantities:
Contract Type
 
Hedge Designation
 
Regulated
Distribution
 
Nonregulated
 
 
 
 
Quantity (MMcf)
Commodity contracts
 
Fair Value
 
—

 
(23,528
)
 
 
Cash Flow
 
—

 
63,305

 
 
Not designated
 
11,792

 
51,663

 
 
 
 
11,792

 
91,440


16


Financial Instruments on the Balance Sheet
The following tables present the fair value and balance sheet classification of our financial instruments by operating segment as of December 31, 2015 and September 30, 2015. The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Balance Sheets to the extent that we have netting arrangements with the counterparties.
 
 
 
Regulated Distribution
 
Nonregulated
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
 (In thousands)
December 31, 2015
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$
—

 
$
—

 
$
24,704

 
$
(38,275
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
—

 
—

 
432

 
(8,821
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
—

 
(103,142
)
 
—

 
—

Total
 
 
—

 
(103,142
)
 
25,136

 
(47,096
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
716

 
(6,738
)
 
41,780

 
(42,232
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
96

 
(195
)
 
17,577

 
(16,184
)
Total
 
 
812

 
(6,933
)
 
59,357

 
(58,416
)
Gross Financial Instruments
 
 
812

 
(110,075
)
 
84,493

 
(105,512
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 
—

 
—

 
(84,493
)
 
84,493

Net Financial Instruments
 
 
812

 
(110,075
)
 
—

 
(21,019
)
Cash collateral
 
 
—

 
—

 
18,229

 
21,019

Net Assets/Liabilities from Risk Management Activities
 
 
$
812

 
$
(110,075
)
 
$
18,229

 
$
—

 
 

17


 
 
 
Regulated Distribution
 
Nonregulated
 
Balance Sheet Location
 
Assets
 
Liabilities
 
Assets
 
Liabilities
 
 
 
 (In thousands)
September 30, 2015
 
 
 
 
 
 
 
 
 
Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
$
—

 
$
—

 
$
11,680

 
$
(36,067
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
—

 
—

 
126

 
(9,918
)
Interest rate contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
—

 
(110,539
)
 
—

 
—

Total
 
 
—

 
(110,539
)
 
11,806

 
(45,985
)
Not Designated As Hedges:
 
 
 
 
 
 
 
 
 
Commodity contracts
Other current assets /
Other current liabilities
 
378

 
(9,568
)
 
65,239

 
(65,780
)
Commodity contracts
Deferred charges and other assets /
Deferred credits and other liabilities
 
368

 
—

 
14,318

 
(14,218
)
Total
 
 
746

 
(9,568
)
 
79,557

 
(79,998
)
Gross Financial Instruments
 
 
746

 
(120,107
)
 
91,363

 
(125,983
)
Gross Amounts Offset on Consolidated Balance Sheet:
 
 
 
 
 
 
 
 
 
Contract netting
 
 
—

 
—

 
(91,363
)
 
91,363

Net Financial Instruments
 
 
746

 
(120,107
)
 
—

 
(34,620
)
Cash collateral
 
 
—

 
—

 
8,854

 
34,620

Net Assets/Liabilities from Risk Management Activities
 
 
$
746

 
$
(120,107
)
 
$
8,854

 
$
—

 
Impact of Financial Instruments on the Income Statement
Hedge ineffectiveness for our nonregulated segment is recorded as a component of purchased gas cost and primarily results from differences in the location and timing of the derivative instrument and the hedged item. Hedge ineffectiveness could materially affect our results of operations for the reported period. For the three months ended December 31, 2015 and 2014 we recognized a gain (loss) arising from fair value and cash flow hedge ineffectiveness of $7.9 million and $(2.2) million. Additional information regarding ineffectiveness recognized in the income statement is included in the tables below.
 
Fair Value Hedges
The impact of our nonregulated commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three months ended December 31, 2015 and 2014 is presented below.
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(In thousands)
Commodity contracts
$
5,744

 
$
15,090

Fair value adjustment for natural gas inventory designated as the hedged item
2,161

 
(16,782
)
Total (increase) decrease in purchased gas cost
$
7,905

 
$
(1,692
)
The (increase) decrease in purchased gas cost is comprised of the following:
 
 
 
Basis ineffectiveness
$
1,289

 
$
986

Timing ineffectiveness
6,616

 
(2,678
)
 
$
7,905

 
$
(1,692
)
 
 
 
 

18


Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedge instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that the Company’s natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.

Cash Flow Hedges
The impact of cash flow hedges on our condensed consolidated income statements for the three months ended December 31, 2015 and 2014 is presented below. Note that this presentation does not reflect the financial impact arising from the hedged physical transaction. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
 
Three Months Ended December 31, 2015
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Loss reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
(22,965
)
 
$
(22,965
)
Loss arising from ineffective portion of commodity contracts
—

 
(43
)
 
(43
)
Total impact on purchased gas cost
—

 
(23,008
)
 
(23,008
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(137
)
 
—

 
(137
)
Total Impact from Cash Flow Hedges
$
(137
)
 
$
(23,008
)
 
$
(23,145
)
 
Three Months Ended December 31, 2014
 
Regulated Distribution
 
Nonregulated
 
Consolidated
 
(In thousands)
Gain reclassified from AOCI for effective portion of commodity contracts
$
—

 
$
344

 
$
344

Loss arising from ineffective portion of commodity contracts
—

 
(490
)
 
(490
)
Total impact on purchased gas cost
—

 
(146
)
 
(146
)
Net loss on settled interest rate agreements reclassified from AOCI into interest expense
(444
)
—

—

 
(444
)
Total Impact from Cash Flow Hedges
$
(444
)
 
$
(146
)
 
$
(590
)
 
 
 
 
 
 
 
 
 
 
 
 

19


The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss), net of taxes, for the three months ended December 31, 2015 and 2014. The amounts included in the table below exclude gains and losses arising from ineffectiveness because those amounts are immediately recognized in the income statement as incurred.
 
Three Months Ended 
 December 31
 
2015
 
2014
 
(In thousands)
Increase (decrease) in fair value:
 
 
 
Interest rate agreements
$
4,696

 
$
(52,069
)
Forward commodity contracts
(11,656
)
 
(28,742
)
Recognition of (gains) losses in earnings due to settlements:
 
 
 
Interest rate agreements
87

 
282

Forward commodity contracts
14,009

 
(210
)
Total other comprehensive income (loss) from hedging, net of tax(1)
$
7,136

 
$
(80,739
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
Deferred gains (losses) recorded in AOCI associated with our interest rate agreements are recognized in earnings as they are amortized over the terms of the underlying debt instruments, while deferred gains (losses) associated with commodity contracts are recognized in earnings upon settlement. The following amounts, net of deferred taxes, represent the expected recognition in earnings of the deferred gains (losses) recorded in AOCI associated with our financial instruments, based upon the fair values of these financial instruments as of December 31, 2015. However, the table below does not include the expected recognition in earnings of our outstanding interest rate agreements as those instruments have not yet settled.
 
Interest Rate
Agreements
 
Commodity
Contracts
 
Total
 
(In thousands)
Next twelve months
$
(347
)
 
$
(17,979
)
 
$
(18,326
)
Thereafter
(18,217
)
 
(5,105
)
 
(23,322
)
Total(1) 
$
(18,564
)
 
$
(23,084
)
 
$
(41,648
)
 
(1) 
Utilizing an income tax rate ranging from 37 percent to 39 percent based on the effective rates in each taxing jurisdiction.
 
Financial Instruments Not Designated as Hedges
The impact of financial instruments that have not been designated as hedges on our condensed consolidated income statements for the three months ended December 31, 2015 and 2014 was an (increase) decrease in purchased gas cost of $(2.2) million and $0.9 million. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled.
As discussed above, financial instruments used in our regulated distribution segment are not designated as hedges. However, there is no earnings impact on our regulated distribution segment as a result of the use of these financial instruments because the gains and losses arising from the use of these financial instruments are recognized in the consolidated statement of income as a component of purchased gas cost when the related costs are recovered through our rates and recognized in revenue. Accordingly, the impact of these financial instruments is excluded from this presentation.
9.    Accumulated Other Comprehensive Income
We record deferred gains (losses) in AOCI related to available-for-sale securities, interest rate agreement cash flow hedges and commodity contract cash flow hedges. Deferred gains (losses) for our available-for-sale securities and commodity contract cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate agreement cash flow hedges are recognized in earnings as they are amortized. The following tables provide the components of our accumulated other comprehensive income (loss) balances, net of the related tax effects allocated to each component of other comprehensive income.

20


 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2015
$
4,949

 
$
(88,842
)
 
$
(25,437
)
 
$
(109,330
)
Other comprehensive income (loss) before reclassifications
(768
)
 
4,696

 
(11,656
)
 
(7,728
)
Amounts reclassified from accumulated other comprehensive income
—

 
87

 
14,009

 
14,096

Net current-period other comprehensive income (loss)
(768
)
 
4,783

 
2,353

 
6,368

December 31, 2015
$
4,181

 
$
(84,059
)
 
$
(23,084
)
 
$
(102,962
)
 
 
Available-
for-Sale
Securities
 
Interest
Rate
Agreement
Cash Flow
Hedges
 
Commodity
Contracts
Cash Flow
Hedges
 
Total
 
(In thousands)
September 30, 2014
$
7,662

 
$
(18,381
)
 
$
(1,674
)
 
$
(12,393
)
Other comprehensive income (loss) before reclassifications
(1,063
)
 
(52,069
)
 
(28,742
)
 
(81,874
)
Amounts reclassified from accumulated other comprehensive income
(4
)
 
282

 
(210
)
 
68

Net current-period other comprehensive income (loss)
(1,067
)
 
(51,787
)
 
(28,952
)
 
(81,806
)
December 31, 2014
$
6,595

 
$
(70,168
)
 
$
(30,626
)
 
$
(94,199
)


The following tables detail reclassifications out of AOCI for the three months ended December 31, 2015 and 2014. Amounts in parentheses below indicate decreases to net income in the statement of income.
 
Three Months Ended December 31, 2015
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Cash flow hedges
 
 
 
Interest rate agreements
$
(137
)
 
Interest charges
Commodity contracts
(22,965
)
 
Purchased gas cost
 
(23,102
)
 
Total before tax
 
9,006

 
Tax benefit
Total reclassifications
$
(14,096
)
 
Net of tax

21


 
Three Months Ended December 31, 2014
Accumulated Other Comprehensive Income Components
Amount Reclassified from
Accumulated Other
Comprehensive Income      
 
Affected Line Item in the
Statement of Income
 
(In thousands)
 
 
Available-for-sale securities
$
6

 
Operation and maintenance expense
 
6

 
Total before tax
 
(2
)
 
Tax expense
 
$
4

 
Net of tax
Cash flow hedges
 
 
 
Interest rate agreements
$
(444
)
 
Interest charges
Commodity contracts
344

 
Purchased gas cost
 
(100
)
 
Total before tax
 
28

 
Tax benefit
 
$
(72
)
 
Net of tax
Total reclassifications
$
(68
)
 
Net of tax
 
 
 
 
 
 
 
 
10.    Fair Value Measurements
We report certain assets and liabilities at fair value, which is defined as 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). We record cash and cash equivalents, accounts receivable and accounts payable at carrying value, which substantially approximates fair value due to the short-term nature of these assets and liabilities. For other financial assets and liabilities, we primarily use quoted market prices and other observable market pricing information to minimize the use of unobservable pricing inputs in our measurements when determining fair value. The methods used to determine fair value for our assets and liabilities are fully described in Note 2 to the financial statements in our Annual Report on Form 10-K for the fiscal year ended September 30, 2015. During the three months ended December 31, 2015, there were no changes in these methods.
Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about fair value measurements of the assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 6 to the financial statements in our Annual Report on Form 10-K for the fiscal year ending September 30, 2015.
Quantitative Disclosures
Financial Instruments
The classification of our fair value measurements requires judgment regarding the degree to which market data is observable or corroborated by observable market data. Authoritative accounting literature establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1), with the lowest priority given to unobservable inputs (Level 3). The following tables summarize, by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 and September 30, 2015. Assets and liabilities are categorized in their entirety based on the lowest level of input that is significant to the fair value measurement.

22


 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(2)
 
December 31, 2015
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$
—

 
$
812

 
$
—

 
$
—

 
$
812

Nonregulated segment
—

 
84,493

 
—

 
(66,264
)
 
18,229

Total financial instruments
—

 
85,305

 
—

 
(66,264
)
 
19,041

Hedged portion of gas stored underground
53,347

 
—

 
—

 
—

 
53,347

Available-for-sale securities
 
 
 
 
 
 
 
 
 
Money market funds
—

 
72

 
—

 
—

 
72

Registered investment companies
41,978

 
—

 
—

 
—

 
41,978

Bonds
—

 
33,129

 
—

 
—

 
33,129

Total available-for-sale securities
41,978

 
33,201

 
—

 
—

 
75,179

Total assets
$
95,325

 
$
118,506

 
$
—

 
$
(66,264
)
 
$
147,567

Liabilities:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$
—

 
$
110,075

 
$
—

 
$
—

 
$
110,075

Nonregulated segment
—

 
105,512

 
—

 
(105,512
)
 
—

Total liabilities
$
—

 
$
215,587

 
$
—

 
$
(105,512
)
 
$
110,075

 
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)(1)
 
Significant
Other
Unobservable
Inputs
(Level 3)
 
Netting and
Cash
Collateral(3)
 
September 30, 2015
 
(In thousands)
Assets:
 
 
 
 
 
 
 
 
 
Financial instruments
 
 
 
 
 
 
 
 
 
Regulated distribution segment
$
—

 
$
746

 
$
—

 
$
—

 
$
746

Nonregulated segment
—

 
91,363