LG-2013.12.31-10Q

 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-Q
[ X ]
QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended December 31, 2013
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 1-16681
 

THE LACLEDE GROUP, INC.
(Exact name of registrant as specified in its charter)
Missouri
(State of Incorporation)
74-2976504
(I.R.S. Employer Identification number)
720 Olive Street
St. Louis, MO  63101
(Address and zip code of principal executive offices)
 
314-342-0500
(Registrant’s telephone number, including area code)

Indicate by check mark if 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 report) and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [     ]

has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [     ]

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.

 
Large accelerated filer
[ X ]
 
Accelerated filer
[     ]
 
Non-accelerated filer
[     ]
 
Smaller reporting company
[     ]

is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [     ] No [ X ]

As of January 31, 2014, there were 32,758,189 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.
 
 
 
 
 


Table of Contents

TABLE OF CONTENTS
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2

Table of Contents

PART I. FINANCIAL INFORMATION

The interim financial statements included herein have been prepared by The Laclede Group, Inc. (Laclede Group or the Company), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Company’s Form 10-K for the fiscal year ended September 30, 2013.


3

Table of Contents

Item 1. Financial Statements

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED INCOME
(UNAUDITED)

 
Three Months Ended
 
December 31,
(Thousands, Except Per Share Amounts)
2013
 
2012
Operating Revenues:
 

 
 
Gas Utility
$
435,166

 
$
250,111

Gas Marketing
33,253

 
55,249

Other
191

 
1,643

Total Operating Revenues
468,610

 
307,003

Operating Expenses:
 
 
 
Gas Utility
 
 
 
Natural and propane gas
241,787

 
136,515

Other operation and maintenance expenses
62,322

 
39,651

Depreciation and amortization
20,026

 
10,965

Taxes, other than income taxes
28,589

 
14,806

Total Gas Utility Operating Expenses
352,724

 
201,937

Gas Marketing
51,782

 
57,382

Other
1,199

 
5,599

Total Operating Expenses
405,705

 
264,918

Operating Income
62,905

 
42,085

Other Income and (Income Deductions) – Net
1,647

 
1,084

Interest Charges:
 
 
 
Interest on long-term debt
9,694

 
5,438

Other interest charges
767

 
588

Total Interest Charges
10,461

 
6,026

Income Before Income Taxes
54,091

 
37,143

Income Tax Expense
18,499

 
11,575

Net Income
$
35,592

 
$
25,568

 
 
 
 
Weighted Average Number of Common Shares Outstanding:
 
 
 
Basic
32,570

 
22,372

Diluted
32,648

 
22,434

Basic Earnings Per Share of Common Stock
$
1.09

 
$
1.14

Diluted Earnings Per Share of Common Stock
$
1.09

 
$
1.14

Dividends Declared Per Share of Common Stock
$
0.440

 
$
0.425

 
 
 
 
 
 
 


4

Table of Contents

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(UNAUDITED)

 
Three Months Ended
 
December 31,
(Thousands)
2013
 
2012
Net Income
$
35,592

 
$
25,568

Other Comprehensive Income (Loss), Before Tax:
 
 
 
Net (losses) gains on cash flow hedging derivative instruments:
 
 
 
Net hedging (loss) gain arising during the period
(1,646
)
 
1,389

Reclassification adjustment for (gains) losses included in net income
(1,178
)
 
2,249

Net unrealized (losses) gains on cash flow hedging derivative instruments
(2,824
)
 
3,638

Amortization of actuarial loss included in net periodic pension and postretirement benefit cost
97

 
90

Other Comprehensive (Loss) Income, Before Tax
(2,727
)
 
3,728

Income Tax (Benefit) Expense Related to Items of Other Comprehensive Income
(1,035
)
 
1,450

Other Comprehensive (Loss) Income, Net of Tax
(1,692
)
 
2,278

Comprehensive Income
$
33,900

 
$
27,846

 
 
 
 
 
 
 


5

Table of Contents

THE LACLEDE GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

 
Dec. 31,
 
Sept. 30,
 
Dec. 31,
(Thousands)
2013
 
2013
 
2012
ASSETS
 
 
 
 
 
Utility Plant
$
2,295,248

 
$
2,271,189

 
$
1,508,770

Less:  Accumulated depreciation and amortization
507,457

 
494,559

 
470,840

Net Utility Plant
1,787,791

 
1,776,630

 
1,037,930

Non-utility property
5,249

 
7,694

 
5,788

Goodwill
235,814

 
247,078

 

Other investments
62,774

 
58,306

 
51,631

Other Property and Investments
303,837

 
313,078

 
57,419

Current Assets:
 
 
 
 
 
Cash and cash equivalents
34,518

 
52,981

 
46,563

Accounts receivable:
 
 
 
 
 
Utility
254,692

 
101,118

 
130,925

Non-utility
63,194

 
63,752

 
54,092

Other
21,801

 
14,451

 
17,822

Allowance for doubtful accounts
(10,847
)
 
(8,046
)
 
(7,055
)
Inventories:
 
 
 
 
 
Natural gas stored underground
153,305

 
182,035

 
88,342

Propane gas
6,022

 
8,962

 
10,200

Materials and supplies at average cost
8,581

 
8,154

 
4,257

Natural gas receivable
7,786

 
18,782

 
13,746

Derivative instrument assets
4,985

 
3,291

 
1,246

Unamortized purchased gas adjustments
9,903

 
17,533

 
30,492

Deferred income taxes
3,222

 

 

Prepayments and other
13,562

 
12,867

 
9,433

Total Current Assets
570,724

 
475,880

 
400,063

Deferred Charges:
 
 
 
 
 
Regulatory assets
530,963

 
545,947

 
440,880

Other
13,415

 
13,851

 
5,863

Total Deferred Charges
544,378

 
559,798

 
446,743

Total Assets
$
3,206,730

 
$
3,125,386

 
$
1,942,155


6

Table of Contents


THE LACLEDE GROUP, INC.
CONSOLIDATED BALANCE SHEETS (Continued)
(UNAUDITED)

 
Dec. 31,
 
Sept. 30,
 
Dec. 31,
(Thousands, except share amounts)
2013
 
2013
 
2012
CAPITALIZATION AND LIABILITIES
 
 
 
 
 
Capitalization:
 
 
 
 
 
  Common stock (70,000,000 shares authorized, 32,751,255,
    32,696,836, and 22,563,958 shares issued, respectively)
$
32,751

 
$
32,697

 
$
22,564

Paid-in capital
594,857

 
594,269

 
169,496

Retained earnings
441,259

 
420,103

 
430,556

Accumulated other comprehensive loss
(2,479
)
 
(787
)
 
(1,838
)
Total Common Stock Equity
1,066,388

 
1,046,282

 
620,778

Long-term debt (less current portion)
832,764

 
912,712

 
364,426

Total Capitalization
1,899,152

 
1,958,994

 
985,204

Current Liabilities:
 
 
 
 
 
Current portion of long-term debt
80,000

 

 

Notes payable
93,500

 
74,000

 
83,050

Accounts payable
160,750

 
140,234

 
100,994

Advance customer billings
16,011

 
23,736

 
15,950

Wages and compensation accrued
15,753

 
20,807

 
12,401

Dividends payable
15,142

 
14,556

 
9,931

Customer deposits
15,485

 
15,062

 
8,437

Interest accrued
9,755

 
8,335

 
5,034

Taxes accrued
36,274

 
32,896

 
13,196

Deferred income taxes

 
1,012

 
4,426

Other
35,054

 
22,540

 
21,651

Total Current Liabilities
477,724

 
353,178

 
275,070

Deferred Credits and Other Liabilities:
 
 
 
 
 
Deferred income taxes
389,557

 
379,114

 
350,738

Unamortized investment tax credits
2,847

 
2,900

 
3,060

Pension and postretirement benefit costs
229,313

 
228,653

 
195,259

Asset retirement obligations
72,459

 
74,554

 
40,936

Regulatory liabilities
90,795

 
82,560

 
56,776

Other
44,883

 
45,433

 
35,112

Total Deferred Credits and Other Liabilities
829,854

 
813,214

 
681,881

Commitments and Contingencies (Note 12)
 
 
 
 
 
Total Capitalization and Liabilities
$
3,206,730

 
$
3,125,386

 
$
1,942,155

 
 
 
 
 


7

Table of Contents

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(UNAUDITED) 
 
Three Months Ended
 
December 31,
(Thousands)
2013
 
2012
Operating Activities:
 
 
 
 Net Income
$
35,592

 
$
25,568

  Adjustments to reconcile net income to net cash provided by (used in)
      operating activities:
 
 
 
Depreciation, amortization, and accretion
20,212

 
11,314

Deferred income taxes and investment tax credits
(702
)
 
2,572

Other – net
(157
)
 
670

Changes in assets and liabilities:
 
 
 
Accounts receivable – net
(157,564
)
 
(61,942
)
Unamortized purchased gas adjustments
7,630

 
10,182

Deferred purchased gas costs
23,093

 
2,266

Accounts payable
25,153

 
12,004

Advance customer billings - net
(7,725
)
 
(9,196
)
Taxes accrued
3,379

 
1,877

Natural gas stored underground
28,730

 
4,387

Other assets and liabilities
6,648

 
4,213

Net cash (used in) provided by operating activities
(15,711
)
 
3,915

Investing Activities:
 
 
 
Capital expenditures
(34,641
)
 
(27,713
)
Other investments
(679
)
 
(990
)
Proceeds from sale of right to acquire NEG

11,000

 

Net cash used in investing activities
(24,320
)
 
(28,703
)
Financing Activities:
 
 
 
Issuance of long-term debt

 
25,000

Maturity of first mortgage bonds

 
(25,000
)
Issuance of short-term debt – net
19,500

 
42,950

Changes in book overdrafts
15,847

 
10,160

Issuance of common stock
742

 
761

Dividends paid
(13,876
)
 
(9,495
)
Employees’ taxes paid associated with restricted shares withheld upon vesting
(1,053
)
 
(723
)
Excess tax benefits from stock-based compensation
423

 
256

Other
(15
)
 
(15
)
Net cash provided by financing activities
21,568

 
43,894

Net (Decrease) Increase in Cash and Cash Equivalents
(18,463
)
 
19,106

Cash and Cash Equivalents at Beginning of Period
52,981

 
27,457

Cash and Cash Equivalents at End of Period
$
34,518

 
$
46,563

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Interest paid
$
8,850

 
$
9,585

Income taxes paid
(2,313
)
 
456

 
 
 

8

Table of Contents

THE LACLEDE GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These notes are an integral part of the accompanying unaudited consolidated financial statements of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. In the opinion of Laclede Group, this interim report includes all adjustments (consisting of only normal recurring accruals) necessary for the fair presentation of the results of operations for the periods presented. This Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements contained in the Company’s Fiscal Year 2013 Form 10-K.
The consolidated financial position, results of operations, and cash flows of Laclede Group are primarily derived from the financial position, results of operations, and cash flows of Laclede Gas Company (Laclede Gas or the Utility), a wholly owned subsidiary. The Utility is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. The Utility's recent acquisition of Missouri Gas Energy (MGE) is included in the results of operations for the three months ended December 31, 2013, impacting the comparability of the current year financial statements to prior years. For a further discussion of the acquisition, see Note 2, MGE Acquisition. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through MGE. The Company's primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services.
REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at December 31, 2013 and 2012, for the Utility, were $101.9 million and $39.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.
GROSS RECEIPTS TAXES - Gross receipts taxes associated with the Utility’s natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues for the three months ended December 31, 2013 and 2012 were $19.9 million and $10.3 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

2. MGE Acquisition
Effective September 1, 2013, the Utility completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, the Utility acquired MGE for a purchase price of $975 million.
On December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of Plaza Mass to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. This receipt of funds effectively reduced the Utility's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney Generals Motion.
The Utility is currently in negotiations with SUG regarding adjustments to the purchase price of MGE due to changes in the actual net assets transferred to the Utility at closing on August 31, 2013 from the level at September 30, 2012. The Utility plans to adjust cash and goodwill for any change upon final settlement.
The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.

9

Table of Contents

In the first quarter of fiscal 2014, the Utility updated the fair value estimates for assets acquired and liabilities assumed as of the acquisition date, including the sale of NEG to APUC which resulted in a decrease to goodwill of $11.0 million.

3. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans
The Utility has non-contributory, defined benefit, trusteed forms of pension plans covering substantially all employees. Plan assets consist primarily of corporate and U.S. government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments.
Pension costs for the three months ended December 31, 2013 and 2012 were $6.6 million and $4.2 million, respectively, including amounts charged to construction.
The net periodic pension costs include the following components:
 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Service cost – benefits earned during the period
$
2,428

 
$
2,311

Interest cost on projected benefit obligation
6,010

 
4,066

Expected return on plan assets
(6,645
)
 
(4,741
)
Amortization of prior service cost
124

 
136

Amortization of actuarial loss
1,772

 
2,839

Sub-total
3,689

 
4,611

Regulatory adjustment
2,890

 
(434
)
Net pension cost
$
6,579

 
$
4,177

Pursuant to the provisions of the Utility's pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. There were no lump-sum payments recognized as settlements during the three months ended December 31, 2013 and December 31, 2012, respectively.
Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plans is based on an annual allowance of $15.5 million effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 million effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Fiscal year 2014 contributions to the pension plans through December 31, 2013 were $3.8 million to the qualified trusts. There were no contributions to the non-qualified plans in the first quarter of fiscal 2014. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $24.0 million to the qualified trusts and $0.4 million to the non-qualified plans.
Postretirement Benefits
The Utility provides certain life insurance benefits at retirement. Under the Laclede Gas plans, medical insurance is currently available after early retirement until age 65. Under the MGE plans, medical insurance is currently available upon retirement until death. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs for both the three months ended December 31, 2013 and 2012 were $2.4 million, including amounts charged to construction.

10

Table of Contents

Net periodic postretirement benefit costs consisted of the following components:
 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Service cost – benefits earned during the period
$
2,804

 
$
2,533

Interest cost on accumulated postretirement benefit obligation
2,169

 
1,279

Expected return on plan assets
(1,709
)
 
(1,081
)
Amortization of transition obligation

 
23

Amortization of prior service cost (credit)
(1
)
 
1

Amortization of actuarial loss
1,505

 
1,325

Sub-total
4,768

 
4,080

Regulatory adjustment
(2,387
)
 
(1,699
)
Net postretirement benefit cost
$
2,381

 
$
2,381

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. The assets of VEBA and Rabbi trusts consist primarily of money market securities and mutual funds invested in stocks and bonds.
Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for the Utility’s postretirement benefit plans is based on an annual allowance of $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. There were no contributions to the postretirement plans in fiscal 2014 through December 31, 2013. Contributions to the postretirement plans for the remaining nine months of fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

4. STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2013 for descriptions of the plan.

Restricted Stock Awards
During the three months ended December 31, 2013, the Company granted 104,979 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $37.74 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. Most of these stock units have a performance period ending September 30, 2016. While the participants have no interim voting rights on these stock units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying stock units do not vest. The number of stock units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

11

Table of Contents

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the three months ended December 31, 2013 is presented below:
 
Restricted Stock/
Stock Units
 
Weighted
Average
Grant Date
Fair Value
Nonvested at September 30, 2013
242,268

 
$
34.15

Granted (maximum shares that can be earned)
104,979

 
$
37.74

Vested
(52,954
)
 
$
32.16

Forfeited
(22,022
)
 
$
29.35

Nonvested at December 31, 2013
272,271

 
$
36.31

During the three months ended December 31, 2013, the Company granted 51,943 shares of time-vested restricted stock and stock units to executive officers, key employees, and directors at a weighted average grant date fair value of $45.59 per share. Of the 51,943 shares, 12,168 shares vest on December 2, 2014 and 39,775 will vest on December 2, 2016. In the interim, participants receive full voting rights, which are not subject to forfeiture.    
Time-vested restricted stock and stock unit activity for the three months ended December 31, 2013 is presented below:
 
Restricted Stock/
Stock Units
 
Weighted
Average
Grant Date
Fair Value
Nonvested at September 30, 2013
119,404

 
$
38.64

Granted
51,943

 
$
45.59

Vested
(17,999
)
 
$
36.37

Forfeited
(7,200
)
 
$
38.53

Nonvested at December 31, 2013
146,148

 
$
41.40

During the three months ended December 31, 2013, 70,953 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010 and October 17, 2012 vested. The Company withheld 22,983 of the vested shares at a weighted average price of $45.83 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards
Stock option activity for the three months ended December 31, 2013 is presented below:
 
Stock
Options
 
Weighted
Average
Exercise
Price
 
Weighted
Average
Remaining
Contractual
Term
(Years)
 
Aggregate
Intrinsic
Value
($000)
Outstanding at September 30, 2013
133,500

 
$
31.87

 
 
 
 
Granted

 
$

 
 
 
 
Exercised
(12,750
)
 
$
29.36

 
 
 
 
Forfeited

 
$

 
 
 
 
Expired

 
$

 
 
 
 
Outstanding at December 31, 2013
120,750

 
$
32.14

 
1.7
 
$
1,618

Fully Vested and Expected to Vest at December 31, 2013
120,750

 
$
32.14

 
1.7
 
$
1,618

Exercisable at December 31, 2013
120,750

 
$
32.14

 
1.7
 
$
1,618

The closing price of the Company’s common stock was $45.54 at December 31, 2013.

12

Table of Contents

Equity Compensation Costs
The amounts of compensation cost recognized for share-based compensation arrangements are presented below:
 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Total equity compensation cost
$
533

 
$
622

Compensation cost capitalized
(149
)
 
(183
)
Compensation cost recognized
$
384

 
$
439

As of December 31, 2013, there was $9.2 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.4 years.

5. EARNINGS PER COMMON SHARE

 
Three Months Ended December 31,
(Thousands, Except Per Share Amounts)
2013
 
2012
Basic EPS:
 

 
 
Net Income
$
35,592

 
$
25,568

Less: Income allocated to participating securities
144

 
80

Net Income Available to Common Shareholders
$
35,448

 
$
25,488

Weighted Average Shares Outstanding
32,570

 
22,372

Earnings Per Share of Common Stock
$
1.09

 
$
1.14

Diluted EPS:
 

 
 

Net Income
$
35,592

 
$
25,568

Less: Income allocated to participating securities
144

 
80

Net Income Available to Common Shareholders
$
35,448

 
$
25,488

Weighted Average Shares Outstanding
32,570

 
22,372

Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units
78

 
62

Weighted Average Diluted Shares
32,648

 
22,434

Earnings Per Share of Common Stock
$
1.09

 
$
1.14

Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
 

 
 

Restricted stock and stock units subject to performance and/or market conditions
259

 
263



13

Table of Contents


6. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis are as follows:
 
 
 
 
 
Classification of Estimated Fair Value
(Thousands)
Carrying
Amount
 
Fair
Value
 
Quoted
Prices in Active Markets
(Level 1)
 
Significant Observable Inputs
(Level 2)
 
Significant Unobservable Inputs
(Level 3)
As of December 31, 2013
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
34,518

 
$
34,518

 
$
34,354

 
$
164

 
$

Short-term debt
93,500

 
93,500

 

 
93,500

 

Long-term debt, including current portion
912,764

 
936,478

 

 
936,478

 

 
 
 
 
 
 
 
 
 
 
As of September 30, 2013
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
52,981

 
$
52,981

 
$
52,824

 
$
157

 
$

Short-term debt
74,000

 
74,000

 

 
74,000

 

Long-term debt, including current portion
912,712

 
954,126

 

 
954,126

 

 
 
 
 
 
 
 
 
 
 
As of December 31, 2012
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
46,563

 
$
46,563

 
$
36,487

 
$
10,076

 
$

Short-term debt
83,050

 
83,050

 

 
83,050

 

Long-term debt, including current portion
364,426

 
456,235

 

 
456,235

 

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 7, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.


14

Table of Contents

7. FAIR VALUE MEASUREMENTS

The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.
(Thousands)
Quoted
Prices in
Active
Markets
(Level 1)
 
Significant
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Effects of Netting and Cash Margin Receivables
/Payables
 
Total
As of December 31, 2013
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
U. S. Stock/Bond Mutual Funds
$
15,003

 
$

 
$

 
$

 
$
15,003

NYMEX/ICE natural gas contracts
3,697

 
670

 

 
(3,839
)
 
528

OTCBB natural gas contracts

 
3,609

 

 
(913
)
 
2,696

NYMEX gasoline and heating oil contracts
163

 

 

 

 
163

Natural gas commodity contracts

 
3,044

 
29

 
(826
)
 
2,247

Total
$
18,863

 
$
7,323

 
$
29

 
$
(5,578
)
 
$
20,637

Liabilities
 
 
 
 
 
 
 
 
 
NYMEX/ICE natural gas contracts
$
2,013

 
$
265

 
$

 
$
(2,278
)
 
$

OTCBB natural gas contracts

 
913

 

 
(913
)
 

Natural gas commodity contracts

 
1,732

 
22

 
(826
)
 
928

Total
$
2,013

 
$
2,910

 
$
22

 
$
(4,017
)
 
$
928

As of September 30, 2013
 
 
 
 
 
 
 
 
 
Assets
 
 
 
 
 
 
 
 
 
U. S. Stock/Bond Mutual Funds
$
14,500

 
$

 
$

 
$

 
$
14,500

NYMEX/ICE natural gas contracts
4,333

 
330

 

 
(2,145
)
 
2,518

OTCBB natural gas contracts

 
232

 

 
(232
)
 

NYMEX gasoline and heating oil contracts
105

 

 

 
(105
)
 

Natural gas commodity contracts

 
1,129

 
150

 
(495
)
 
784

Total
$
18,938

 
$
1,691

 
$
150

 
$
(2,977
)
 
$
17,802

Liabilities
 
 
 
 
 
 
 
 
 
NYMEX/ICE natural gas contracts
$
3,687

 
$
321

 
$

 
$
(4,008
)
 
$

OTCBB natural gas contracts

 
5,443

 

 
(232
)
 
5,211

Natural gas commodity contracts

 
1,140

 
40

 
(495
)
 
685

Total
$
3,687

 
$
6,904

 
$
40

 
$
(4,735
)
 
$
5,896

As of December 31, 2012
 

 
 

 
 

 
 

 
 

Assets
 

 
 

 
 

 
 

 
 

U. S. Stock/Bond Mutual Funds
$
13,146

 
$

 
$

 
$

 
$
13,146

NYMEX/ICE natural gas contracts
2,497

 
749

 

 
(2,962
)
 
284

NYMEX gasoline and heating oil contracts
281

 

 

 
(281
)
 

Natural gas commodity contracts

 
1,228

 
77

 
(348
)
 
957

Total
$
15,924

 
$
1,977

 
$
77

 
$
(3,591
)
 
$
14,387

Liabilities
 

 
 

 
 

 
 

 
 

NYMEX/ICE natural gas contracts
$
6,650

 
$
749

 
$

 
$
(7,399
)
 
$

Natural gas commodity contracts

 
1,132

 
47

 
(348
)
 
831

Total
$
6,650

 
$
1,881

 
$
47

 
$
(7,747
)
 
$
831



15

Table of Contents

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:
 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Beginning of period
$
110

 
$
109

Net settlements
(108
)
 
(66
)
Net gains related to derivatives still held at end of period
5

 
(13
)
End of period
$
7

 
$
30

The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 8, Derivative Instruments and Hedging Activities.

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36 -month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its Purchased Gas Adjustment (PGA) Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.
From time to time, they Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At December 31, 2013, Laclede Gas held 0.8 million gallons of gasoline futures contracts at an average price of $2.66 per gallon. Most of these contracts, the longest of which extends to September 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

16

Table of Contents

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At December 31, 2013, the fair values of 72.2 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 57.3 million MMBtu will settle during fiscal year 2014, 13.5 million MMBtu will settle during fiscal year 2015, while the remaining 1.4 million MMBtu will settle during fiscal year 2016. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or Ice Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At December 31, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.
The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at December 31, 2013 were as follows:
 
Laclede Gas Company
 
Laclede Energy
Resources, Inc.
 
MMBtu
(millions)
 
Avg. Price
Per
MMBtu
 
MMBtu
(millions)
 
Avg. Price
Per
MMBtu
NYMEX/ICE Open short futures positions
 
 
 
 
 
 
 
Fiscal 2014

 
$

 
11.04

 
$
4.03

Fiscal 2015

 

 
0.49

 
4.19

Fiscal 2016

 

 
0.01

 
4.10

NYMEX/ICE Open long futures positions
 
 
 
 
 
 
 
Fiscal 2014
5.25

 
$
3.88

 
1.64

 
$
3.84

Fiscal 2015
0.94

 
3.84

 
0.39

 
4.00

Fiscal 2016

 

 
0.09

 
4.18

Fiscal 2017

 

 
0.02

 
4.28

ICE Open basis swap positions
 
 
 
 
 
 
 
Fiscal 2016

 

 
0.92

 
$
(0.80
)
Fiscal 2017

 

 
0.16

 
(0.80
)
OTCBB Open long futures positions
 
 
 
 
 
 
 
Fiscal 2014
14.03

 
$
3.99

 

 

Fiscal 2015
8.60

 
4.20

 

 

Fiscal 2016
0.11

 
4.15

 

 

At December 31, 2013, the Utility had 19.2 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.
Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at December 31, 2013, it is expected that approximately $0.8 million of pre-tax unrealized gains will be reclassified into the Statements of Consolidated Income during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.


17

Table of Contents

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
 
 
Three Months Ended
 
Location of Gain (Loss)
December 31,
(Thousands)
Recorded in Income
2013
 
2012
Derivatives in Cash Flow Hedging Relationships
 
 
 
Effective portion of gain (loss) recognized in OCI on derivatives:
 
 
 
NYMEX/ICE natural gas contracts
 
$
(1,655
)
 
$
1,332

NYMEX gasoline and heating oil contracts
 
9

 
57

Total
 
$
(1,646
)
 
$
1,389

Effective portion of gain (loss) reclassified from AOCI to income:
 
 
 
NYMEX/ICE natural gas contracts
Gas Marketing Operating Revenues
$
1,300

 
$
(1,962
)
 
Gas Marketing Operating Expenses
(180
)
 
(334
)
Sub-total
 
1,120

 
(2,296
)
NYMEX gasoline and heating oil contracts
Gas Utility Other Operations and Maintenance Expenses
58

 
47

Total
 
$
1,178

 
$
(2,249
)
Ineffective portion of gain (loss) on derivatives recognized in income:
 
 
 
NYMEX/ICE natural gas contracts
Gas Marketing Operating Revenues
$
(211
)
 
$
(325
)
 
Gas Marketing Operating Expenses
133

 
(85
)
Sub-total
 
(78
)
 
(410
)
NYMEX gasoline and heating oil contracts
Gas Utility Other Operations and Maintenance Expenses
120

 
(101
)
Total
 
$
42

 
$
(511
)
 
 
 
 
 
Derivatives Not Designated as Hedging Instruments *
 
 
 
Gain (loss) recognized in income on derivatives:
 
 
 
Natural gas commodity contracts
Gas Marketing Operating Revenues
$
(1,667
)
 
$
(970
)
 
Gas Marketing Operating Expenses

 

NYMEX/ICE natural gas contracts
Gas Marketing Operating Revenues
1,990

 
1,067

 
Gas Marketing Operating Expenses

 

NYMEX gasoline and heating oil contracts
Other Income and (Income Deductions) - Net
13

 
33

Total
 
$
336

 
$
130


*
Gains and losses on Laclede Gas’ natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Gas Utility Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.


18

Table of Contents

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 2013
 
Asset Derivatives*
 
Liability Derivatives*
(Thousands)
Balance Sheet Location
Fair
Value
 
Balance Sheet Location
Fair
 Value
Derivatives designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Derivative Instrument Assets
$
881

 
Derivative Instrument Assets
$
1,030

 
Other Deferred Charges
110

 
Other Deferred Charges
1

NYMEX gasoline and heating oil contracts
Accounts Receivable – Other
154

 
Accounts Receivable – Other

Sub-total
 
1,145

 
 
1,031

Derivatives not designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Derivative Instrument Assets
571

 
Derivative Instrument Assets
955

 
Accounts Receivable – Other
2,802

 
Accounts Receivable – Other
285

 
Other Deferred Charges
3

 
Other Deferred Charges
7

OTCBB natural gas contracts
Derivative Instrument Assets
3,386

 
Derivative Instrument Assets
636

 
Other Deferred Credits
223

 
Other Deferred Credits
278

Natural gas commodity contracts
Derivative Instrument Assets
1,915

 
Derivative Instrument Assets
272

 
Other Deferred Charges
641

 
Other Deferred Charges
37

 
Other Current Liabilities
333

 
Other Current Liabilities
1,283

 
Other Deferred Credits
183

 
Other Deferred Credits
161

NYMEX gasoline and heating oil contracts
Derivative Instrument Assets
9

 
Derivative Instrument Assets

Sub-total
 
10,066

 
 
3,914

Total derivatives
 
$
11,211

 
 
$
4,945

 
 
 
 
 
 
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
 
Asset Derivatives*
 
Liability Derivatives*
(Thousands)
Balance Sheet Location
Fair
Value
*
Balance Sheet Location
Fair
Value
Derivatives designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Derivative Instrument Assets
$
2,222

 
Accounts Receivable - Other
$
440

 
Other Deferred Charges
22

 
Other Deferred Charges
11

NYMEX gasoline and heating oil contracts
Accounts Receivable - Other
105

 
Accounts Receivable - Other

Sub-total
 
2,349

 
 
451

Derivatives not designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Derivative Instrument Assets
950

 
Derivative Instrument Assets
100

 
Accounts Receivable - Other
1,434

 
Accounts Receivable - Other
3,455

 
Other Deferred Charges
32

 
Other Deferred Charges

OTCBB natural gas contracts
Other Current Liabilities
228

 
Other Current Liabilities
4,045

 
Other Deferred Credits
4

 
Other Deferred Credits
1,398

Natural gas commodity contracts
Derivative Instrument Assets
991

 
Derivative Instrument Assets
90

 
Other Deferred Charges
20

 
Other Deferred Charges
137

 
Other Current Liabilities
247

 
Other Current Liabilities
830

 
Other Deferred Credits
21

 
Other Deferred Credits
123

Sub-total
 
3,927

 
 
10,178

Total derivatives
 
$
6,276

 
 
$
10,629


19

Table of Contents

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 2012
 
Asset Derivatives*
 
Liability Derivatives*
(Thousands)
Balance Sheet Location
Fair
Value
 
Balance Sheet Location
Fair
Value
Derivatives designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Derivative Instrument Assets
$
987

 
Derivative Instrument Assets
$
871

NYMEX gasoline and heating oil contracts
Accounts Receivable - Other
249

 
Accounts Receivable - Other

Sub-total
 
1,236

 
 
871

Derivatives not designated as hedging instruments
 
 
 
 
NYMEX/ICE natural gas contracts
Accounts Receivable - Other
533

 
Accounts Receivable - Other
366

 
Derivative Instrument Assets
1,726

 
Derivative Instrument Assets
6,162

Natural gas commodity contracts
Derivative Instrument Assets
1,197

 
Derivative Instrument Assets
240

 
Other Current Liabilities
108

 
Other Current Liabilities
939

NYMEX gasoline and heating oil contracts
Accounts Receivable - Other
32

 
Accounts Receivable - Other

Sub-total
 
3,596

 
 
7,707

Total derivatives
 
$
4,832

 
 
$
8,578


*
The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 7, Fair Value Measurements, for information on the valuation of derivative instruments.

Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:
(Thousands)
December 31, 2013
 
September 30, 2013
 
December 31, 2012
Fair value of asset derivatives presented above
$
11,211

 
$
6,276

 
$
4,832

Fair value of cash margin receivables offset with derivatives
956

 
1,765

 
4,186

Netting of assets and liabilities with the same counterparty
(6,533
)
 
(4,739
)
 
(7,778
)
Total
$
5,634

 
$
3,302

 
$
1,240

 
 
 
 
 
 
Derivative Instrument Assets, per Consolidated Balance Sheets:
 
 
 
 
 
Derivative instrument assets
$
4,985

 
$
3,291

 
$
1,246

Other deferred charges
649

 
11

 
(6
)
Total
$
5,634

 
$
3,302

 
$
1,240

 
 
 
 
 
 
Fair value of liability derivatives presented above
$
4,945

 
$
10,629

 
$
8,578

Fair value of cash margin payables offset with derivatives
2,516

 
6

 
31

Netting of assets and liabilities with the same counterparty
(6,533
)
 
(4,739
)
 
(7,778
)
Total
$
928

 
$
5,896

 
$
831

 
 
 
 
 
 
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
 
 
 
 
 
Other Current Liabilities
$
938

 
$
4,400

 
$
831

Other Deferred Credits
(10
)
 
1,496

 

Total
$
928

 
$
5,896

 
$
831

Additionally, at December 31, 2013, September 30, 2013, and December 31, 2012, the Company had $3.8 million, $3.2 million, and $4.4 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

20

Table of Contents

9. CONCENTRATIONS OF CREDIT RISK
A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $8.9 million at December 31, 2013. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $3.8 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $20.5 million of total accounts receivable at December 31, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $18.8 million. LER also has concentrations of credit risk with certain individually significant counterparties. At December 31, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $18.4 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $17.3 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

10. OTHER INCOME AND (INCOME DEDUCTIONS) - NET

 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Interest income
$
249

 
$
406

Net investment gain (loss)
746

 
(70
)
Other income
652

 
748

Other Income and (Income Deductions) – Net
$
1,647

 
$
1,084



21

Table of Contents


11. INFORMATION BY OPERATING SEGMENT
All of Laclede Group’s subsidiaries are wholly owned. The Gas Utility segment consists of the regulated operations of the Utility and is the core business segment of Laclede Group. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Gas Marketing segment includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, natural gas fueling stations, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes the Utility's non-regulated business activities, which are comprised of its propane storage and related services. Beginning July 1, 2013, propane-related services were included within Gas Utility operations pursuant to Laclede Gas' most recent rate case. Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from the Utility to LER, propane storage services provided by the Utility to Laclede Pipeline Company, sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility.
Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also excludes the after-tax impacts related to acquisition, divestiture, and restructuring activities.

22

Table of Contents

(Thousands)
Gas Utility
 
Gas Marketing
 
Other
 
Eliminations
 
Consolidated
Three Months Ended December 31, 2013
 

 
 

 
 

 
 

 
 

Revenues from external customers
$
435,166

 
$
33,253

 
$
191

 
$

 
$
468,610

Intersegment revenues
62

 
19,456

 
442

 
(19,960
)
 

Total Operating Revenues
435,228

 
52,709

 
633

 
(19,960
)
 
468,610

Operating Expenses
 
 
 
 
 
 
 
 
 
Gas Utility
 
 
 
 
 
 
 
 
 
Natural and Propane Gas
261,553

 

 

 
(19,766
)
 
241,787

Other Operation and Maintenance Expenses
62,516

 

 

 
(194
)
 
62,322

Depreciation and Amortization
20,026

 

 

 

 
20,026

Taxes, Other than Income Taxes
28,589

 

 

 

 
28,589

Total Gas Utility Operating Expenses
372,684

 

 

 
(19,960
)
 
352,724

Gas Marketing

 
51,782

 

 

 
51,782

Other

 

 
1,199

 

 
1,199

Total Operating Expenses
372,684

 
51,782

 
1,199

 
(19,960
)
 
405,705

Operating Income
62,544

 
927

 
(566
)
 

 
62,905

Net Economic Earnings (Losses)
35,778

 
822

 
(336
)
 

 
36,264

Total assets
3,084,134

 
157,239

 
126,890

 
(161,533
)
 
3,206,730

 
 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2012
 

 
 

 
 

 
 

 
 

Revenues from external customers
$
250,111

 
$
55,249

 
$
1,643

 
$

 
$
307,003

Intersegment revenues
680

 
6,906

 
259

 
(7,845
)
 

Total Operating Revenues
250,791

 
62,155

 
1,902

 
(7,845
)
 
307,003

Operating Expenses
 
 
 
 
 
 
 
 
 
Gas Utility
 
 
 
 
 
 
 
 
 
Natural and Propane Gas
144,333

 

 

 
(7,818
)
 
136,515

Other Operation and Maintenance Expenses
39,651

 

 

 

 
39,651

Depreciation and Amortization
10,965

 

 

 

 
10,965

Taxes, Other than Income Taxes
14,806

 

 

 

 
14,806

Total Gas Utility Operating Expenses
209,755

 

 

 
(7,818
)
 
201,937

Gas Marketing

 
57,382

 

 

 
57,382

Other

 

 
5,626

 
(27
)
 
5,599

Total Operating Expenses
209,755

 
57,382

 
5,626

 
(7,845
)
 
264,918

Operating Income
41,036

 
4,773

 
(3,724
)
 

 
42,085

Net Economic Earnings
25,341

 
3,281

 
(389
)
 

 
28,233

Total assets
1,809,722

 
188,603

 
124,967

 
(181,137
)
 
1,942,155


Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
 
Three Months Ended December 31,
(Thousands)
2013
 
2012
Net Income (GAAP)
$
35,592

 
$
25,568

Unrealized (gain) loss on energy-related derivative contracts
354

 
439

Lower of cost or market inventory adjustments
(62
)
 

Realized (gain) loss on economic hedges prior to sale of the physical commodity
(6
)
 
(31
)
Acquisition, divestiture, and restructuring activities
386

 
2,257

Net Economic Earnings (Non-GAAP)
$
36,264

 
$
28,233


23

Table of Contents

12. COMMITMENTS AND CONTINGENCIES

Commitments

The Utility and LER have entered into various contracts, expiring on dates through 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at December 31, 2013 are estimated at approximately $1,127 million . Additional contracts are generally entered into prior to or during the heating season. The Utility recovers its costs from customers in accordance with the PGA Clause.
Contingencies
The Utility owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs.
Similar to other natural gas utility companies, the Utility faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and MGE or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). MGE has enrolled all of its owned former manufactured gas plant sites in the BVCP.
With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, EPA Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.
One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources. The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability. The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.
Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion. Accordingly, Laclede Gas was able to enter into a cost sharing agreement for remedial investigation with other potentially responsible parties. Pending Missouri Department of Natural Resources approval, the remedial investigation of the site will probably begin in the Spring of 2014. 

24

Table of Contents

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.
MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold.
Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.
Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. The Utility anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of the Utility or the Company.
As discussed in Note 8, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of November 26, 2013, Laclede Gas and LER had $0.2 million and $0.1 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. As the Company has recovered 98% of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.
On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.
Laclede Group is involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

13. Subsequent Events
On January 6, 2014, the Utility redeemed in cash $80 million of 6.35% Series bonds due in 2038 and accrued interest of $0.3 million.
On January 17, 2014, Laclede Gas filed for a $7.4 million increase in Infrastructure System Replacement Surcharge (ISRS) revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous thirteen months. Any increase in rates in this proceeding must go into effect by at least May 17, 2014.

25

Table of Contents

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This section analyzes the financial condition and results of operations of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. It includes management’s view of factors that affect its business, explanations of past financial results including changes in earnings and costs from the prior year periods, and their effects on the Company's overall financial condition and liquidity.
Certain matters discussed in this report, excluding historical information, include forward-looking statements. Certain words, such as “may,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “seek,” and similar words and expressions identify forward-looking statements that involve uncertainties and risks. Future developments may not be in accordance with our current expectations or beliefs and the effect of future developments may not be those anticipated. Among the factors that may cause results to differ materially from those contemplated in any forward-looking statement are:
weather conditions and catastrophic events, particularly severe weather in the natural gas producing areas of the country;
volatility in gas prices, particularly sudden and sustained changes in natural gas prices, including the related impact on margin deposits associated with the use of natural gas derivative instruments;
the impact of changes and volatility in natural gas prices on our competitive position in relation to suppliers of alternative heating sources, such as electricity;
changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells, expiration of existing supply and transportation arrangements that are not replaced with contracts with similar terms and pricing, as well as other changes that impact supply for and access to the markets in which our subsidiaries transact business;
legislative, regulatory and judicial mandates and decisions, some of which may be retroactive, including those affecting
allowed rates of return
incentive regulation
industry structure
purchased gas adjustment provisions
rate design structure and implementation
regulatory assets
non-regulated and affiliate transactions
franchise renewals
environmental or safety matters, including the potential impact of legislative and regulatory actions related to climate change and pipeline safety
taxes
pension and other postretirement benefit liabilities and funding obligations
accounting standards;
the results of litigation;
retention of, ability to attract, ability to collect from, and conservation efforts of, customers;
capital and energy commodity market conditions, including the ability to obtain funds with reasonable terms for necessary capital expenditures and general operations and the terms and conditions imposed for obtaining sufficient gas supply;
discovery of material weakness in internal controls; and
employee workforce issues.
The Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s Consolidated Financial Statements and the Notes thereto.


26

Table of Contents

RESULTS OF OPERATIONS

Overview
Laclede Group’s earnings are primarily derived from its Gas Utility segment, which reflects the regulated activities of Laclede Gas Company (the Utility), Missouri’s largest natural gas distribution company. The Utility is regulated by the Missouri Public Service Commission (MoPSC) and serves the City of St. Louis and eastern Missouri through Laclede Gas and Kansas City and western Missouri through Missouri Gas Energy (MGE). The Utility delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The Utility’s earnings are primarily generated by the sale of heating energy. Laclede Gas' weather mitigation rate design and MGE's straight fixed variable rate design lessen the impact of weather volatility on its customers during cold winters and stabilizes the Utility’s earnings by recovering fixed costs more evenly during the heating season. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year.
Effective September 1, 2013, the Utility completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, the Utility acquired MGE for a purchase price of $975 million.
Also, on December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of NEG to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. This receipt of funds effectively reduced the Company's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney Generals Motion.
The Utility is currently in negotiations with SUG regarding adjustments in the purchase price of MGE due to changes in the actual net assets transferred to the Utility at closing on August 31, 2013 from the level at September 30, 2012. The Utility plans to adjust cash and goodwill for any change as a result of this process upon final settlement, which is anticipated to be in the second quarter of fiscal 2014.
The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.
Laclede Energy Resources, Inc. (LER) is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas to both on-system Utility transportation customers and customers outside of the Utility's traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LER entered into a 10 year contract for 1 Bcf for natural gas storage effective August 1, 2013 and has an additional 1 Bcf storage contracted through January 2016.


27

Table of Contents

EARNINGS
The Laclede Group reports net income and earnings per share determined in accordance with GAAP. Management also uses the non-GAAP measures of net economic earnings and net economic earnings per share when internally evaluating results of operations. These non-GAAP measures exclude from net income the after-tax impacts of fair value accounting and timing adjustments associated with energy-related transactions as well as acquisition, divestiture, and restructuring activities. These adjustments include timing differences where the accounting treatment differs from the economic substance of the underlying transaction, including the following:
Net unrealized gains and losses on energy-related derivatives that are required by GAAP fair value accounting associated with current changes in the fair value of financial and physical transactions prior to their completion and settlement. These unrealized gains and losses result primarily from two sources:

1)
changes in the fair values of physical and/or financial derivatives prior to the period of settlement; and,

2)
ineffective portions of accounting hedges, required to be recorded in earnings prior to settlement, due to differences in commodity price changes between the locations of the forecasted physical purchase or sale transactions and the locations of the underlying hedge instruments;

Lower of cost or market adjustments to the carrying value of commodity inventories resulting when the market price of the commodity falls below its original cost, to the extent that those commodities are economically hedged; and
Realized gains and losses resulting from the settlement of economic hedges prior to the sale of the physical commodity.
Acquisition, divestiture, and restructuring activities, when evaluating on-going performance.

These adjustments eliminate the impact of timing differences and the impact of current changes in the fair value of financial and physical transactions prior to their completion and settlement. Unrealized gains or losses are recorded in each period until being replaced with the actual gains or losses realized when the associated physical transaction(s) occur. While management uses these non-GAAP measures to evaluate both the Utility and LER, the net effect of adjustments on the Utility’s earnings is minimal because gains or losses on its natural gas derivative instruments are deferred pursuant to its PGA Clause, as authorized by the MoPSC.
Management believes that excluding the earnings volatility caused by recognizing changes in fair value prior to settlement and other timing differences associated with related purchase and sale transactions provides a useful representation of the economic effects of only the actual settled transactions and their effects on results of operations. In addition, management excludes the impact related to unique acquisition, divestiture, and restructuring activities, when evaluating on-going performance, and therefore excludes these impacts from net economic earnings. Management believes that this presentation provides a useful representation of operating performance by facilitating comparisons of year-over-year results. These internal non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income. Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided below.

28

Table of Contents


THREE MONTHS ENDED DECEMBER 31, 2013

Net Income and Net Economic Earnings
Reconciliation of Consolidated Net Economic Earnings (Non-GAAP) to Consolidated Net Income (GAAP)
(Millions, except per share amounts)
Gas Utility
 
Gas Marketing
 
 Other
 
 
Total
 
Per Share Amounts**
Three Months Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Net Income (Loss) (GAAP)
$
35.4

 
$
0.5

 
$
(0.3
)
 
$
35.6

 
$
1.09

 
Unrealized (gain) loss on energy-related
     derivatives*

 
0.4

 

 
0.4

 
0.01

 
Lower of cost or market inventory adjustments*

 
(0.1
)
 

 
(0.1
)
 

 
Acquisition, divestiture and restructuring activities*
0.4

 

 

 
0.4

 
0.01

 
Net Economic Earnings (Losses) (Non-GAAP)
$
35.8

 
$
0.8

 
$
(0.3
)
 
$
36.3

 
$
1.11

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
Net Income (Loss) (GAAP)
$
25.3

 
$
2.9

 
$
(2.6
)
 
$
25.6

 
$
1.14

 
Unrealized (gain) loss on energy-related
     derivatives*

 
0.4

 

 
0.4

 
0.01

 
Acquisition, divestiture and restructuring activities*

 

 
2.2

 
2.2

 
0.10

 
Net Economic Earnings (Losses) (Non-GAAP)
$
25.3

 
$
3.3

 
$
(0.4
)
 
$
28.2

 
$
1.25


*
Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the three months ended December 31, 2013 and 2012, the total net amount of income tax (benefit) expense included in the reconciling items above is ($0.4) million and ($1.6) million, respectively.

**
Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation.

Consolidated
Laclede Group’s net income was $35.6 million for the three months ended December 31, 2013, compared with $25.6 million for the three months ended December 31, 2012. Basic and diluted earnings per share for the three months ended December 31, 2013 were each $1.09, compared with basic and diluted earnings per share of $1.14, respectively, for the three months ended December 31, 2012. Net income increased compared to last year primarily due to improved results reported by Laclede Group's Gas Utility Segment, which included a full quarter's impact of MGE operations totaling $12.7 million. This increase was partially offset by lower earnings from the Gas Marketing Segment of $2.4 million. Acquisition-related costs, among other items, are excluded from net economic earnings, which were $36.3 million for the three months ended December 31, 2013, compared with $28.2 million for the same period last year. Net economic earnings per share were $1.11 for the three months ended December 31, 2013, compared with $1.25 for the three months ended December 31, 2012.

Gas Utility
Gas Utility net income and net economic earnings increased by $10.1 million and $10.5 million, respectively for the three months ended December 31, 2013, compared with the three months ended December 31, 2012. The increase was primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $57.2 million, which included a full quarter's impact of MGE operating margin totaling $51.3 million. These benefits were partially offset by an increase in other operating expenses of $35.9 million, which included a full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively, higher interest expense totaling $4.3 million, and increased income tax expenses of $7.0 million relating the Utility.




29

Table of Contents

Gas Marketing
The Gas Marketing segment reported GAAP earnings totaling $0.5 million, a decrease of $2.4 million compared with the same period last year. Net economic earnings for the three months ended December 31, 2013 decreased $2.5 million compared with the three months ended December 31, 2012. The decreases in net income and net economic earnings was primarily attributable to decreases in operating margin, as discussed below.
Other
The Other segment reported a lower net loss of $2.3 million as compared with the same period last year. The decrease in net loss was primarily due to prior year acquisition-related expenses of MGE and NEG from SUG totaling $2.2 million, net of tax, and other minor expenses during the three months ended December 31, 2012. Net economic losses for the three months ended December 31, 2013 decreased $0.1 million as compared with the prior year first quarter.
Operating Revenues and Operating Expenses
In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utility passes on (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause to their customers. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on operating income. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.
(Millions)
Gas Utility
 
Gas Marketing
 
Other
 
Eliminations
 
 
Total
Three Months Ended December 31, 2013
 
 
 
 
 
 
 
 
 
 
Operating Revenues
$
435.3

 
$
52.7

 
$
0.6

 
$
(20.0
)
 
$
468.6

 
Natural and propane gas expense
261.6

 
50.5

 

 
(19.8
)
 
292.3

 
Gross receipts tax expense
19.5

 

 

 

 
19.5

 
Operating margin (non-GAAP)
154.2

 
2.2

 
0.6

 
(0.2
)
 
156.8

 
Depreciation and amortization
20.0

 
0.1

 
0.1

 

 
20.2

 
Other operating expenses
71.6

 
1.2

 
1.1

 
(0.2
)
 
73.7

 
Operating income (GAAP)
$
62.6

 
$
0.9

 
$
(0.6
)
 
$

 
$
62.9

 
 
 
 
 
 
 
 
 
 
 
Three Months Ended December 31, 2012
 

 
 

 
 

 
 
 
 

 
Operating revenues
$
250.8

 
$
62.2

 
$
1.8

 
$
(7.8
)
 
$
307.0

 
Natural and propane gas expense
144.1

 
56.2

 
0.2

 
(7.8
)
 
192.7

 
Gross receipts tax expense
9.7

 

 

 

 
9.7

 
Operating margin (non-GAAP)
97.0

 
6.0

 
1.6

 

 
104.6

 
Depreciation and amortization
11.0

 
0.1

 
0.3

 

 
11.4

 
Other operating expenses
44.7

 
1.1

 
5.3

 

 
51.1

 
Operating income (GAAP)
$
41.3

 
$
4.8

 
$
(4.0
)
 
$

 
$
42.1

Consolidated
Laclede Group reported operating revenues of $468.6 million for the three months ended December 31, 2013 compared with $307.0 million for the same period last year. Laclede Group's operating margin increased $52.2 million for the three months ended December 31, 2013 compared with the same period last year primarily due to higher Gas Utility operating margin, partially offset by lower operating margin reported by the Gas Marketing segment as discussed below. Depreciation and amortization expenses were $20.2 million for the three months ended December 31, 2013, compared with $11.4 million for the same period last year. Other operating expenses were $73.7 million for the three months ended December 31, 2013, compared with $51.1 million for the same period last year. The increase was primarily due to full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively.

30

Table of Contents

Gas Utility
Operating Revenues - Gas Utility operating revenues for the three months ended December 31, 2013 were $435.3 million, or $184.5 million more than the same period last year. The increase in Gas Utility operating revenues was primarily attributable to the following factors:
(Millions)
 
New customer revenue from MGE
$
160.1

Higher system sales volumes and other variations
28.7

Lower wholesale gas costs passed on to Utility customers
(8.2
)
Optimization of assets
3.8

Total Variation
$
184.4

Temperatures experienced in the Utility’s service area during the three months ended December 31, 2013 were 18.1% colder than the same period last year, and 7.6% colder than normal. Total system therms sold and transported were 308.3 million for the three months ended December 31, 2013, compared with 261.1 million for the same period last year. Total off-system therms sold and transported were 62.3 million for the three months ended December 31, 2013, compared with 80.4 million for the same period last year.
Operating Margin - Gas Utility operating margin was $154.2 million for the three months ended December 31, 2013, a $57.2 million increase over the same period last year. The increase was primarily due to the impact of MGE's operating margin totaling $51.3 million, better optimization of assets totaling $4.2 million and higher usage of natural gas reflecting colder weather and modest customer growth totaling $1.7 million.
Operating Expenses - Other operating expenses for the three months ended December 31, 2013 increased $35.9 million from the same period last year. The increase was primarily due to full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively. The increase was also a result of higher employee-related expenses. Depreciation and amortization expense increased $1.4 million primarily due to additional depreciable property. Taxes, other than income taxes, increased $0.4 million, primarily due to higher real estate and property taxes.
Gas Marketing
Operating Revenues - Gas Marketing operating revenues during the three months ended December 31, 2013 decreased $9.5 million from the same period last year primarily due to lower volumes sold, partially offset by higher per unit gas sales prices.
Operating Margin - Gas Marketing operating margin during the three months ended December 31, 2013 decreased $3.8 million from the same period last year. The decrease in operating margin was primarily attributable to reduced sales margins, reflecting the expirations of favorable supply contracts.
Other
Operating Revenues and Operating Expenses - Other operating revenues and operating margin decreased by $1.2 million and $1.0 million, respectively, during the three months ended December 31, 2013 from the same period last year. The decrease was primarily due to prior year acquisition-related expenses related to the acquisition of MGE.
Other Income and (Income Deductions) - Net
Other Income and (Income Deductions) - Net increased $0.6 million primarily due to higher net investment gains.
Interest Charges
Interest charges during the three months ended December 31, 2013 increased $4.4 million from the same period last year. The increase was primarily due to the net effect of the December 2012, March 2013, and August 2013 issuances of additional long-term debt of $25 million, $100 million, and $450 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for both the three months ended December 31, 2013 and 2012. Average short-term borrowings were $93.2 million for the three months ended December 31, 2013, compared with $74.9 million for the three months ended December 31, 2012.
Income Taxes
Income taxes during the three months ended December 31, 2013 increased $6.9 million from the same period last year primarily due to higher pre-tax income.


31

Table of Contents

REGULATORY AND OTHER MATTERS
A petition was filed with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the Company's acquisition of NEG. In accordance with the February 11, 2013 agreement between Laclede Group and Algonquin Power Utilities Corporation (APUC) providing for the sale of the Company’s subsidiary, Plaza Mass, to Liberty Utilities, an APUC subsidiary, an amended petition was filed with DPU on February 19, 2013 requesting that the DPU authorize the sale of NEG to Liberty Utilities. Evidentiary hearings were held in June and August 2013. On December 13, 2013, the MDPU approved the sale of NEG to Liberty Utilities. On December 20, 2013, the Company closed the sale of Plaza Mass and received $11.0 million from APUC. This receipt of funds effectively reduced the Utility's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney General’s Motion.
On September 16, 2013, MGE filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $23.4 million, less the current annualized ISRS revenues of $6.3 million that were already being recovered from customers. Consistent with its normal practice, the MoPSC suspended implementation of the MGE proposed rates on September 17, 2013 and set the case for hearing in April 2014. On December 6, 2013, MGE filed for a $1.6 million increase in ISRS revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous nine months.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. Our critical accounting policies used in the preparation of our Consolidated Financial Statements are described in Item 7 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2013 and include the following:

Accounts receivable and allowance for doubtful accounts
Employee benefits and postretirement obligations
Regulated operations
Gas Marketing energy contracts

There were no significant changes to these critical accounting policies during the three months ended December 31, 2013.
For discussion of other significant accounting policies, see Note 1 of the Notes to Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2013.


32

Table of Contents

FINANCIAL CONDITION

CASH FLOWS
The Company’s short-term borrowing requirements typically peak during colder months when the Utility borrows money to cover the lag between when it purchases its natural gas and when its customers pay for that gas. Changes in the wholesale cost of natural gas (including cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments), variations in the timing of collections of gas cost under the Utility’s PGA Clause, the seasonality of accounts receivable balances, and the utilization of storage gas inventories cause short-term cash requirements to vary during the year and from year to year, and can cause significant variations in the Utility’s cash provided by or used in operating activities.
Net cash used in operating activities was $15.7 million for the three months ended December 31, 2013, compared with net cash provided by operating activities of $3.9 million for the three months ended December 31, 2012. The variation is primarily associated with the seasonality of the accounts receivable balances reflecting the inclusion of MGE's operations and higher operating revenues. This increase in cash used is partially offset by a higher sendout of natural gas stored underground, the timing of collections of gas cost under the Utility's PGA Clause, higher net income, and higher depreciation, amortization, and accretion as compared to the prior year first quarter.
Net cash used in investing activities for the three months ended December 31, 2013 was $24.3 million, compared with $28.7 million for the three months ended December 31, 2012. The decrease primarily reflects the receipt of $11.0 million associated with the sale of NEG to APUC, partially offset by additional capital expenditures this year for distribution plant investments.
Net cash provided by financing activities was $21.6 million for the three months ended December 31, 2013, compared with $43.9 million for the three months ended December 31, 2012. The variation primarily reflects a decrease in net issuances of short-term debt.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents
Laclede Group had no temporary cash investments at December 31, 2013. Due to lower yields available to Laclede Group on short-term investments, the Company elected to provide a portion of the Utility’s short-term funding through intercompany lending during the three months ended December 31, 2013.
Short-term Debt
As indicated in the discussion of cash flows above, the Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At December 31, 2013, the Utility had a syndicated line of credit in place of $450 million from nine banks, which is scheduled to expire in September 2018. The largest portion provided by a single bank is 15.6%. The Utility's line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 51% of total capitalization on December 31, 2013.
Short-term cash requirements outside of the Utility have generally been met with internally generated funds. Laclede Group also has a $150 million syndicated line of credit which expires in September 2018, to meet short-term liquidity needs of its subsidiaries. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 49% on December 31, 2013. Occasionally, Laclede Group’s line may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s line during the three months ended December 31, 2013.
On December 6, 2013, the Utility provided a notice of redemption to holders for the entire $80 million aggregate principal amount outstanding of its previously issued 6.35% Series bonds due in 2038. The redemption, which was for cash and included accrued interest, was effective January 6, 2014. In accordance with GAAP, the $80 million principle balance was recorded in Current portion of long-term debt in the Consolidated Balance Sheet as of December 31, 2013.

33

Table of Contents

Information about Laclede Group’s consolidated short-term borrowings (excluding the current portion of long-term debt and intercompany borrowings) as of and during the three months ended December 31, 2013, is presented below:
 
Commercial Paper Borrowings
Three Months Ended December 31, 2013
 
Weighted average borrowings outstanding
$93.2 million
Weighted average interest rate
0.3%
Range of borrowings outstanding
$70 - $116.2 million
 
 
As of December 31, 2013
 
Borrowings outstanding at end of period
$93.5 million
Weighted average interest rate
0.3%
Based on average short-term borrowings for the three months ended December 31, 2013, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.9 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.
Long-term Debt, Equity, and Shelf Registrations
The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization is effective through June 30, 2015. During the three months ended December 31, 2013, pursuant to this authority, the Utility sold 9 shares of its common stock to Laclede Group for $0.4 million. As of February 1, 2014, $370.5 million remains available under this authorization. Laclede Gas has a shelf registration on Form S-3 for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires August 6, 2016. First mortgage bonds in the amount of $450 million were issued under this registration during fiscal year 2013. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations.
At December 31, 2013, Laclede Group had fixed-rate long-term debt totaling $915 million, including the current portion. Of the $915 million long-term debt, $890 million is attributed to the Utility and $25 million is attributed to Laclede Group. The long-term debt issues are fixed-rate and are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Utility’s $890 million in long-term debt, $50 million have no call option, $410 million have make-whole call options, $350 million are callable at par three to six months prior to maturity, and $80 million are callable at par beginning in October 2013. Laclede Group's debt has a make-whole call option. None of the debt has any put options. On December 6, 2013, Laclede Gas gave notice that it would call the $80 million in callable bonds, which was completed on January 6, 2014.
Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 186,117 and 179,183 shares at December 31, 2013 and January 31, 2014, respectively, remaining available for issuance under its Form S-3. Laclede Group also has a shelf registration statement on Form S-3 for the issuance of equity and debt securities. No securities have been issued under that S-3. The amount, timing, and type of financing to be issued under this shelf registration will depend on cash requirements and market conditions.
Other
The Company’s and the Utility’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company and the Utility remain at investment grade, but are subject to review and change by the rating agencies.
Utility capital expenditures were $34.6 million for the three months ended December 31, 2013, compared with $27.7 million for the same period last year. The increase in capital expenditures, compared with the prior period, is primarily attributable to additional expenditures for distribution plant investments. Non-utility capital expenditures were negligible during the three months ended December 31, 2013 and 2012.
Consolidated capitalization at December 31, 2013 consisted of 56.2% common stock equity and 43.8% long-term debt.

34

Table of Contents

It is management’s view that the Company has adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.
The seasonal nature of the Utility's sales affects the comparison of certain balance sheet items at December 31, 2013 and at September 30, 2013, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets and Regulatory liabilities, and Advance customer billings. The Consolidated Balance Sheet at December 31, 2012 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

CONTRACTUAL OBLIGATIONS

As of December 31, 2013, Laclede Group had contractual obligations with payments due as summarized below (in millions):
 
 
Payments due by period
Contractual Obligations
Total
 
Remaining Fiscal Year
2014
 
Fiscal Years
2015-2016
 
Fiscal Years
2017-2018
 
Fiscal Years 2019 and
thereafter
Principal Payments on Long-Term Debt
$
915

 
$
80

 
$

 
$
100

 
$
735

Interest Payments on Long-Term Debt
687

 
32

 
81

 
81

 
493

Capital Leases (a)

 

 

 

 

Operating Leases (a)
11

 
5

 
5

 
1

 

Purchase Obligations – Natural Gas (b)
1,127

 
520

 
310

 
203

 
94

Purchase Obligations – Other (c)
73

 
21

 
20

 
19

 
13

Other Long-Term Liabilities
157

 
12

 
31

 
32

 
82

Total (d)
$
2,970

 
$
670

 
$
447

 
$
436

 
$
1,417


(a)
Lease obligations are primarily for office space, vehicles, and power operated equipment. Additional payments will be incurred if renewal options are exercised under the provisions of certain agreements.
(b)
These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Gas Utility and Gas Marketing segments. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using December 31, 2013 forward market prices. Laclede Gas recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA Clause, subject to prudence review by the MoPSC; however, variations in the timing of collections of gas costs from customers affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.
(c)
These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations.
(d)
Long-term liabilities associated with unrecognized tax benefits, totaling $2.8 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $16.1 million to the qualified trusts and $0.4 million to the non-qualified plans. With regard to the postretirement benefits, the Utility anticipates contributing $19.2 million to the qualified trusts and $0.3 million directly to participants from the Utility’s funds during the remaining nine months of fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements. The Spire facility capital lease is not included as there is no cash outlay.

35

Table of Contents

MARKET RISK

Commodity Price Risk
The Utility's commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of its PGA Clause. The PGA Clause allows the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. The Utility also has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see Note 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.
In the course of its business, Laclede Group’s gas marketing subsidiary, LER, enters into contracts to purchase and sell natural gas at fixed prices and natural gas index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments. In accordance with the risk management policy, LER manages the price risk associated with its fixed-price commitments. This risk is currently managed either by closely matching the offsetting physical purchase or sale of natural gas at fixed-prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. At December 31, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations.
As mentioned above, LER uses natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to manage the commodity price risk associated with its fixed-price natural gas purchase and sale commitments. These derivative instruments may be designated as cash flow hedges of forecasted purchases or sales. Such accounting treatment, if elected, generally permits a substantial portion of the gain or loss to be deferred from recognition in earnings until the period that the associated forecasted purchase or sale is recognized in earnings. To the extent a hedge is effective, gains or losses on the derivatives will be offset by changes in the value of the hedged forecasted transactions. Information about the fair values of LER’s exchange-traded/cleared natural gas derivative instruments is presented below:
(Thousands)
Derivative
Fair
Values
 
Cash
Margin
 
Derivatives
and Cash
Margin
Net balance of derivative (liabilities) assets at September 30, 2013
$
2,643

 
$
254

 
$
2,897

Changes in fair value
(3,723
)
 

 
(3,723
)
Settlements/purchases - net
229

 

 
229

Changes in cash margin

 
4,227

 
4,227

Net balance of derivative assets (liabilities) at December 31, 2013
$
(851
)
 
$
4,481

 
$
3,630


 
At December 31, 2013
 
Maturity by Fiscal Year
(Thousands)
Total
 
2014
 
2015
 
2016
 
2017
Fair values of exchange-traded/cleared natural gas derivatives - net
$
(926
)
 
$
(1,015
)
 
$
93

 
$
(2
)
 
$
(2
)
MMBtu – net (short) long futures/swap/option positions
(9,395
)
 
(9,398
)
 
(100
)
 
88

 
15

Fair values of basis swaps - net
$
75

 
$

 
$

 
$
64

 
$
11

MMBtu – net (short) long basis swap positions
1,070

 

 

 
915

 
155


36

Table of Contents

Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement. Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2015:
(Thousands)
 
Net balance of derivative assets at September 30, 2013
$
99

Changes in fair value
1,667

Settlements
(447
)
Net balance of derivative assets at December 31, 2013
$
1,319

For further details related to LER’s derivatives and hedging activities, see Note 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.
Counterparty Credit Risk
LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. Although not recorded on the consolidated balance sheets, LER is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales.
LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see Note 9, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.
Interest Rate Risk
The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the three months ended December 31, 2013, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $0.9 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At December 31, 2013, the Utility had fixed-rate long-term debt totaling $890 million, including the current portion. Additionally, Laclede Group had fixed-rate long-term debt totaling $25 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility’s regulated operations, losses or gains on early redemptions of its long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

ENVIRONMENTAL MATTERS
The Utility owns and operates natural gas distribution, transmission and storage facilities, the operations of which are subject to various environmental laws, regulations and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs. For information relative to environmental matters, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS
Laclede Group has no off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For this discussion, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk, on page 36 of this report.

37

Table of Contents

Item 4. Controls and Procedures

Disclosure Controls and Procedures
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.
Effective September 1, 2013, we acquired Missouri Gas Energy (MGE). As the acquisition occurred during the last 12 months, the scope of our assessment of the effectiveness of disclosure controls and procedures does not include MGE. This exclusion is in accordance with the SEC’s general guidance that an assessment of a recently acquired business may be omitted from our scope in the year following the acquisition.

Changes in Internal Control over Financial Reporting

As a result of the acquisition of MGE mentioned above, the Company is evaluating and implementing changes to processes, policies and other components of its internal control over financial reporting with respect to the consolidation of MGE’s operations into the Company’s financial statements. Management continues to be engaged in substantial efforts to evaluate the effectiveness of our internal control procedures and the design of those control procedures relating to MGE. Except for the activities described above, there were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.





38

Table of Contents

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Group, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 32 of this report.
Laclede Group and its subsidiaries are involved in litigation, claims and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome of these matters will not have a material effect on the consolidated financial position or results of operations reflected in the consolidated financial statements presented herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the quarter ended December 31, 2013, the only repurchases of our common stock were pursuant to elections by employees to have shares of stock withheld to cover employee tax withholding obligations upon the vesting of performance-based and time-vested restricted stock and stock units. The following table provides information on those repurchases.

Period
Total No. of Shares Purchases
Average Price Paid Per Share
Total No. of Shares Purchased as Part of Publicly Announced Plans
Maximum No. of Shares that May Yet be Purchased Under the Plans
October 1, 2013 –
October 31, 2013
649
$45.29
November 1, 2013 –
November 30, 2013
December 1, 2013 –
December 31, 2013
22,334
$45.85
Total
22,983

Item 6. Exhibits

(a)

39

Table of Contents

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 thereunto duly authorized.

 
 
 
The Laclede Group, Inc.
 
 
 
 
Dated:
February 4, 2014
 
By: 
/s/ Steven P. Rasche
 
 
 
 
Steven P. Rasche
 
 
 
 
Executive Vice President, Chief Financial Officer
 
 
 
 
(Authorized Signatory and Principal Accounting Officer)


40

Table of Contents

INDEX TO EXHIBITS
Exhibit No.
 
 
10.1
-
Lease Agreement between The Laclede Group, Inc., as Tenant, and Market 700, LLC, as Landlord, dated January 21, 2014; filed as Exhibit 10.1 to Laclede Group's Form 8-K dated January 27, 2014 and incorporated herein (File No. 1-16681).
-
Ratio of Earnings to Fixed Charges.
-
CEO and CFO Certifications under Exchange Act Rule 13a – 14(a).
-
CEO and CFO Section 1350 Certifications.
101.INS
-
XBRL Instance Document. (1)
101.SCH
-
XBRL Taxonomy Extension Schema. (1)
101.CAL
-
XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF
-
XBRL Taxonomy Definition Linkbase. (1)
101.LAB
-
XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE
-
XBRL Taxonomy Extension Presentation Linkbase. (1)

(1)
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) unaudited Statements of Consolidated Income for the three months ended December 31, 2013 and 2012; (iii) unaudited Statements of Consolidated Comprehensive Income for the three months ended December 31, 2013 and 2012; (iv) unaudited Consolidated Balance Sheets at December 31, 2013, September 30, 2013 and December 31, 2012; (v) unaudited Statements of Consolidated Cash Flows for the three months ended December 31, 2013 and 2012, and (vi) Notes to the unaudited Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report. 

41