Gas Natural 10-Q 2012 Q3 Quarterly report

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 quarterly period ended September 30, 2012

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 001-34585

GAS NATURAL INC.

(Exact name of registrant as specified in its charter)

Ohio	27-3003768
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1 First Avenue South Great Falls, Montana	59401
(Address of principal executive office)	(Zip Code)

Registrant’s telephone number, including area code: (800) 570-5688

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller Reporting Company	x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The number of shares outstanding of the registrant’s common stock as of October 17, 2012 was 8,368,627 shares.

As used in this Form 10-Q, the terms “Company,” “Gas Natural,” “Registrant,” “we,” “us” and “our” mean Gas Natural Inc. and its consolidated subsidiaries as a whole, unless the context indicates otherwise. Except as otherwise stated, the information is this Form 10-Q is as of September 30, 2012.

GLOSSARY OF TERMS

Unless otherwise stated or the context requires otherwise, references to “we,” “us,” the “Company” and “Gas Natural” refer to Gas Natural Inc. and its consolidated subsidiaries. In addition, this glossary contains terms and acronyms that are relevant to natural gas distribution, natural gas marketing and natural gas pipeline operations and that are used in this Form 10-Q.

AECO. Alberta Energy Company Limited (used in reference to the AECO natural gas price index).

ASC. FASB Accounting Standards Certification, standards issued by FASB with respect to GAAP.

ASU. Accounting Standards Update.

Bangor Gas Company. Bangor Gas Company, LLC.

Brainard. Brainard Gas Corp.

Bcf. One billion cubic feet, used in reference to natural gas.

CIG. Colorado Interstate Gas (used in reference to the Colorado Interstate Gas Index).

Citizens.Citizens Bank of Michigan.

Clarion River. Clarion River Gas Company.

Cut Bank Gas. Cut Bank Gas Company.

Dekatherm.One million British thermal units, used in reference to natural gas. Abbreviated as Dkt.

EPA. The United States Environmental Protection Agency.

EWR. Energy West Resources, Inc.

Energy West. Energy West, Incorporated.

Energy West Development. Energy West Development, Inc.

Exchange Act. The Securities Exchange Act of 1934, as amended.

FASB. Financial Accounting Standards Board.

FERC. The Federal Energy Regulatory Commission.

Frontier Natural Gas. Frontier Natural Gas, LLC.

Frontier Utilities. Frontier Utilities of North Carolina, Inc.

GAAP. Generally accepted accounting principles in the United States of America

GNSC. Gas Natural Service Company, LLC

GPL. Great Plains Land Development Co., Ltd.

Great Plains. Great Plains Natural Gas Company.

Independence. Independence Oil, LLC.

IFRS. International Financial Reporting Standards.

KPSC. Kentucky Public Service Commission.

Kykuit. Kykuit Resources, LLC.

Lightning Pipeline. Lightning Pipeline Company, Inc.

LNG.Liquified Natural Gas.

MMcf. One million cubic feet, used in reference to natural gas.

MPSC. The Montana Public Service Commission.

MPUC. The Maine Public Utilities Commission.

NCUC. The North Carolina Utilities Commission.

NEO. Northeast Ohio Natural Gas Corp.

NGA. The Natural Gas Act.

Orwell. Orwell Natural Gas Company.

Osborne Trust. The Richard M. Osborne Trust, dated February 24, 2012.

PaPUC. The Pennsylvania Public Utility Commission.

PGC. Public Gas Company, Inc.

PUCO. The Public Utilities Commission of Ohio.

Penobscot Natural Gas. Penobscot Natural Gas Company, Inc.

SEC. The United States Securities and Exchange Commission.

Spelman.Spelman Pipeline Holdings, LLC.

SunLife.SunLife Assurance Company of Canada

Walker Gas. Walker Gas & Oil Company, Inc.

WPSC. The Wyoming Public Service Commission.

GAS NATURAL INC.

INDEX TO FORM 10-Q

	Page No.
Part I - Financial Information
Item 1 – Financial Statements
Condensed Consolidated Balance Sheets September 30, 2012 and December 31, 2011 (Unaudited)		F-1
Condensed Consolidated Statements of Income and Comprehensive Income Three and Nine months ended September 30, 2012 and 2011 (Unaudited)		F-3
Condensed Consolidated Statements of Changes in Stockholders’ Equity Nine months ended September 30, 2012 and 2011 (Unaudited)		F-4
Condensed Consolidated Statements of Cash Flows Nine months ended September  30, 2012 and 2011 (Unaudited)		F-5
Notes to Unaudited Condensed Consolidated Financial Statements		F-7
Item  2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations		3
Item 3 – Quantitative and Qualitative Disclosures About Market Risk		20
Item 4 – Controls and Procedures		20
Part II – Other Information
Item 1 - Legal Proceedings		21
Item 6 - Exhibits		22
Signatures

2

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

September 30, 2012 and December 31, 2011 (Unaudited)

	September 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,492,279	$	10,504,845
Marketable securities		351,000		367,875
Accounts receivable
Trade, less allowance for doubtful accounts of $787,933 and $630,632, respectively		5,718,241		9,381,625
Related parties		565,608		519,084
Unbilled gas		1,388,951		4,232,854
Note receivable - related parties, current portion		10,807		10,256
Inventory
Natural gas and propane		6,035,830		6,967,739
Materials and supplies		2,497,148		1,958,858
Prepaid income taxes		1,064,448		1,584,869
Prepayments and other		2,302,544		741,101
Recoverable cost of gas purchases		2,915,817		2,627,416
Deferred tax asset		1,046,874		1,061,314
Total current assets		25,389,547		39,957,836
PROPERTY, PLANT AND EQUIPMENT, net		107,871,413		97,612,257
OTHER ASSETS
Notes receivable - related parties, less current portion		27,233		35,408
Regulatory assets
Property taxes		378,415		590,464
Income taxes		452,645		452,645
Rate case costs		211,871		205,714
Debt issuance costs, net		1,766,671		869,593
Goodwill		14,750,924		14,607,952
Customer relationships		622,208		639,333
Investment in unconsolidated affiliate		321,883		330,351
Restricted cash		1,710,155		949,907
Other assets		4,615,845		159,954
Total other assets		24,857,850		18,841,321
TOTAL ASSETS	$	158,118,810	$	156,411,414

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

F-1

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

September 30, 2012 and December 31, 2011 (Unaudited)

	September 30, 2012		December 31, 2011
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Checks in excess of amounts on deposit	$	862,191	$	1,027,376
Lines of credit		18,420,755		23,160,000
Accounts payable
Trade		5,039,778		8,755,623
Related parties		179,441		191,763
Notes payable, current portion		508,387		7,885
Accrued liabilities
Taxes other than income		2,313,134		3,018,964
Vacation		106,092		115,940
Employee benefit plans		85,884		140,149
Interest		363,980		30,688
Deferred payments received from levelized billing		2,936,980		2,948,188
Customer deposits		731,472		707,062
Property tax settlement, current portion		242,128		242,128
Related parties		279,063		635,192
Other current liabilities		829,427		1,280,670
Overrecovered gas purchases		1,733,735		2,237,827
Total current liabilities		34,632,447		44,499,455
LONG-TERM LIABILITIES
Deferred investment tax credits		160,583		176,379
Deferred tax liability		3,901,483		2,908,167
Asset retirement obligation		1,808,069		1,689,081
Customer advances for construction		1,033,680		880,851
Regulatory liability for income taxes		83,161		83,161
Regulatory liability for gas costs		35,342		57,570
Total long-term liabilities		7,022,318		5,795,209
NOTES PAYABLE, less current portion		40,838,375		31,344,723
COMMITMENTS AND CONTINGENCIES (see Note 11)
STOCKHOLDERS’ EQUITY
Preferred stock; $0.15 par value, 1,500,000 shares authorized, no shares issued or outstanding		—		—
Common stock; $0.15 par value, 15,000,000 shares authorized, 8,368,627 and 8,154,301 shares issued and outstanding, respectively		1,255,238		1,223,145
Capital in excess of par value		44,236,216		41,978,799
Accumulated other comprehensive income		69,853		80,405
Retained earnings		30,064,363		31,489,678
Total stockholders’ equity		75,625,670		74,772,027
TOTAL CAPITALIZATION		116,464,045		106,116,750
TOTAL LIABILITIES AND CAPITALIZATION	$	158,118,810	$	156,411,414

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

F-2

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Statements of Income and Comprehensive Income

For the Three and Nine Months Ended September 30, 2012 and 2011 (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES
Natural gas operations	$	10,458,202		$	10,348,819		$	53,107,834		$	65,663,664
Marketing and production		1,809,832			855,715			4,757,280			4,156,882
Pipeline operations		95,162			106,351			305,039			314,736
Propane operations		605,262			1,009,844			3,075,972			1,009,844
Total revenues		12,968,458			12,320,729			61,246,125			71,145,126
COST OF SALES
Natural gas purchased		4,164,358			4,548,224			26,848,575			38,840,724
Marketing and production		1,560,762			585,810			3,806,489			3,193,596
Propane purchased		448,672			875,305			2,298,423			875,305
Total cost of sales		6,173,792			6,009,339			32,953,487			42,909,625
GROSS MARGIN		6,794,666			6,311,390			28,292,638			28,235,501
OPERATING EXPENSES
Distribution, general, and administrative		4,899,620			4,635,388			15,349,052			13,922,684
Maintenance		316,491			235,635			929,448			792,827
Depreciation and amortization		1,327,095			1,153,430			3,874,911			3,256,977
Accretion		41,354			35,849			118,988			105,262
Taxes other than income		923,594			842,786			2,741,390			2,589,732
Total operating expenses		7,508,154			6,903,088			23,013,789			20,667,482
OPERATING INCOME (LOSS)		(713,488	)		(591,698	)		5,278,849			7,568,019
LOSS FROM UNCONSOLIDATED AFFILIATE		(3,693	)		(2,024	)		(8,468	)		(85,174	)
OTHER INCOME (EXPENSE), net		151,884			(229,805	)		502,599			103,639
GAIN ON BARGAIN PURCHASE		—			1,054,861			—			1,054,861
ACQUISITION EXPENSE		(209,491	)		(31,820	)		(825,967	)		(87,354	)
STOCK SALE EXPENSE		(19,114	)		—			(274,393	)		(46,123	)
INTEREST EXPENSE		(637,366	)		(552,341	)		(1,927,232	)		(1,458,194	)
INCOME (LOSS) BEFORE INCOME TAXES		(1,431,268	)		(352,827	)		2,745,388			7,049,674
INCOME TAX BENEFIT (EXPENSE)		760,047			482,353			(857,954	)		(2,285,056	)
NET INCOME (LOSS)		(671,221	)		129,526			1,887,434			4,764,618
OTHER COMPREHENSIVE INCOME (LOSS)
Unrealized gain (loss) on available for sale securities, net of tax		(4,221	)		30,076			(10,552	)		49,697
COMPREHENSIVE INCOME (LOSS)	$	(675,442	)	$	159,602		$	1,876,882		$	4,814,315
EARNINGS (LOSS) PER SHARE - BASIC AND DILUTED	$	(0.08	)	$	0.02		$	0.23		$	0.58
WEIGHTED AVERAGE DIVIDENDS DECLARED PER COMMON SHARE	$	0.182		$	0.135		$	0.452		$	0.405
WEIGHTED AVERAGE SHARES OUTSTANDING - BASIC		8,186,791			8,152,487			8,165,874			8,151,370
WEIGHTED AVERAGE SHARES OUTSTANDING - DILUTED		8,186,791			8,160,048			8,172,423			8,159,326

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

F-3

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Stockholders’ Equity

For the Nine Months Ended September 30, 2012 and 2011 (Unaudited)

	Common Shares		Common Stock		Capital In Excess Of Par Value		Accumulated Other Comprehensive Income			Retained Earnings			Total
BALANCE AT DECEMBER 31, 2010		8,149,801	$	1,222,470	$	41,910,067	$	46,590		$	30,522,375		$	73,701,502
Net income		—		—		—		—			4,764,618			4,764,618
Net unrealized gain on available for sale securities		—		—		—		49,697			—			49,697
Stock issued for services		3,375		506		37,298		—			—			37,804
Stock option expense		—		—		14,389		—			—			14,389
Dividends declared		—		—		—		—			(3,301,433	)		(3,301,433	)
BALANCE AT SEPTEMBER 30, 2011		8,153,176	$	1,222,976	$	41,961,754	$	96,287		$	31,985,560		$	75,266,577
BALANCE AT DECEMBER 31, 2011		8,154,301	$	1,223,145	$	41,978,799	$	80,405		$	31,489,678		$	74,772,027
Net income		—		—		—		—			1,887,434			1,887,434
Net unrealized loss on available for sale securities		—		—		—		(10,552	)		—			(10,552	)
Stock issued for services		3,375		450		32,002		—			—			32,452
Stock option expense		—		—		7,054		—			—			7,054
Purchase of Loring Pipeline		210,951		31,643		2,218,361		—			—			2,250,004
Dividends declared		—		—		—		—			(3,312,749	)		(3,312,749	)
BALANCE AT SEPTEMBER 30, 2012		8,368,627	$	1,255,238	$	44,236,216	$	69,853		$	30,064,363		$	75,625,670

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

F-4

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended September 30, 2012 and 2011 (Unaudited)

	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,887,434		$	4,764,618
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		3,874,911			3,256,977
Accretion		118,988			105,262
Amortization of debt issuance costs		177,379			106,748
Stock based compensation		39,506			52,193
Loss on sale of assets		35,929			30,916
Loss from unconsolidated affiliate		8,468			85,174
Gain on bargain purchase		—			(1,054,861	)
Investment tax credit		(15,797	)		(15,796	)
Deferred income taxes		879,660			2,981,256
Changes in assets and liabilities
Accounts receivable, including related parties		3,685,991			5,511,774
Unbilled gas		2,843,903			4,479,284
Natural gas and propane inventory		931,909			(1,853,006	)
Accounts payable, including related parties		(3,480,190	)		(4,083,198	)
Recoverable/refundable cost of gas purchases		(792,493	)		1,064,287
Prepayments and other		(1,561,443	)		(371,745	)
Other assets		(76,837	)		(1,520,188	)
Other liabilities		(1,154,472	)		(993,626	)
Net cash provided by operating activities		7,402,846			12,546,069
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(13,081,990	)		(14,968,603	)
Proceeds from sale of fixed assets		59,092			43,522
Purchase of marketable securities		—			(13,304	)
Proceeds from related party note receivable		7,624			7,111
Cash acquired in acquisition		502			—
Purchase of Public Gas Company, Inc.		(1,551,478	)		—
Purchase of Loring Pipeline		(2,250,000	)		—
Purchase of Independence Oil & LP Gas, Inc.		—			(1,275,656	)
Restricted cash		—			(1,807,425	)
Investment in unconsolidated affiliate		—			(303,600	)
Customer advances for construction		152,829			60,720
Contributions in aid of construction		130,908			2,725
Net cash used in investing activities		(16,532,513	)		(18,254,510	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from lines of credit		45,951,755			25,200,000
Repayment on lines of credit		(50,691,000	)		(25,749,999	)
Proceeds from notes payable		10,000,000			18,355,215
Repayments of notes payable		(5,846	)		(9,870,240	)
Repayments of related party notes payable		—			(49,361	)
Debt issuance costs		(1,074,456	)		(462,944	)
Restricted cash		(760,248	)		(949,432	)
Dividends paid		(3,303,104	)		(3,301,280	)
Net cash provided by financing activities		117,101			3,171,959
NET DECREASE IN CASH AND CASH EQUIVALENTS		(9,012,566	)		(2,536,482	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		10,504,845			13,026,585
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	1,492,279		$	10,490,103

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

F-5

Gas Natural Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended September 30, 2012 and 2011 (Unaudited)

	2012			2011
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash paid for interest	$	1,416,562		$	1,164,165
Cash paid (refunded) for income taxes		(524,521	)		91,303
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
Shares issued to purchase Loring Pipeline	$	2,250,004		$	—
Capital expenditures included in accounts payable		804,301			622,642
Capitalized interest		6,218			6,342
Accrued dividends		376,588			366,893

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

F-6

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Summary of Business and Significant Accounting Policies

Nature of Business

Gas Natural Inc. is the parent company of Brainard, Energy West, GNSC, Great Plains, Independence, Lightning Pipeline and PGC. Brainard is a natural gas utility company with operations in Ohio. Energy West is the parent company of multiple entities that are natural gas utility companies with regulated operations in Maine, Montana, North Carolina and Wyoming as well as non-regulated operations in Maine, Montana and Wyoming. GNSC manages gas procurement, transportation, and storage for Brainard and subsidiaries of Lightning Pipeline and Great Plains. Lightning Pipeline is the parent company of multiple entities that are regulated natural gas utility companies with operations in Ohio and Pennsylvania. Great Plains is the parent company of an entity that is a regulated natural gas utility company with operations in Ohio. Independence is a non-regulated subsidiary that delivers liquid propane, heating oil, and kerosene to customers in North Carolina and Virginia. On April 1, 2012, the Company acquired PGC, which is a regulated natural gas distribution company in Kentucky. The Company currently has five reporting segments:

•	Natural Gas Operations	Annually distribute approximately 32 billion cubic feet of natural gas to approximately 70,000 customers through regulated utilities operating in Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania and Wyoming.
•	Marketing and Production Operations	Annually market approximately 1.2 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities through the subsidiary, EWR. EWR owns an average 51% gross working interest (an average 43% net revenue interest) in 160 natural gas producing wells and gas gathering assets in Glacier and Toole Counties in Montana.
•	Pipeline Operations	The Shoshone interstate and Glacier gathering natural gas pipelines located in Montana and Wyoming are owned through the subsidiary, EWD. Certain natural gas producing wells owned by EWD are being managed and reported under the marketing and production operations.
•	Propane Operations	The operations were acquired in August 2011 and delivers liquid propane, heating oil and kerosene to approximately 4,300 residential, commercial and agricultural customers in North Carolina and Virginia through the subsidiary, Independence.
•	Corporate and Other	Corporate and other encompasses the results of corporate acquisitions and other equity transactions. Included in corporate and other are costs associated with business development and acquisitions, dividend income and recognized gains from the sale of marketable securities.

Basis of Presentation

The accompanying condensed consolidated balance sheet as of December 31, 2011, which has been derived from audited financial statements, and the unaudited interim condensed consolidated financial statements of Gas Natural Inc. and its subsidiaries (collectively, the “Company”) have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 8-03 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments considered necessary for a fair presentation have been included and are of a normal and recurring nature.

F-7

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Operating results for the three and nine month period ended September 30, 2012 are not necessarily indicative of the results that may be expected for future fiscal periods. Events occurring subsequent to September 30, 2012 have been evaluated as to their potential impact to the financial statements through the date of issuance. These financial statements should be read in conjunction with the audited consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2011.

Effects of Regulation

The Company follows the provisions of ASC 980, Regulated Operations, and the accompanying financial statements reflect the effects of the different rate-making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been, or are expected to be, allowed in the rate-making process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers which are recorded as liabilities in the balance sheet (regulatory liabilities).

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the various public service commissions with jurisdiction over the Company. Estimates are also used in development of the allowances for doubtful accounts, unbilled gas, asset retirement obligations, and determination of depreciable lives of utility plant. The deferred tax asset and valuation allowance require a significant amount of judgment and are significant estimates. The estimates are based on projected future tax deductions, future taxable income, estimated limitations under the Internal Revenue Code, and other assumptions.

Such estimates could change in the near term and could significantly impact the Company’s results of operations and financial position.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less, at the date of acquisition, to be cash equivalents. The Company maintains, at various financial institutions, cash and cash equivalents which may exceed federally insurable limits and which may, at times, significantly exceed balance sheet amounts.

Receivables

The accounts receivable are generated from sales and delivery of natural gas and propane as measured by inputs from meter reading devices. Trade accounts receivable are carried at the expected net realizable value. There is credit risk associated with the collection of these receivables. As such, a provision is recorded for the receivables considered to be uncollectible. The provision is based on management’s assessment of the collectability of specific customer accounts, the aging of the accounts receivable and historical write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a negative material impact to the income statement and working capital.

Included in the accounts receivable, trade line item on the accompanying condensed consolidated balance sheet are $937,787 and $187,793 at September 30, 2012 and December 31, 2011 respectively for amounts due to the Company by a large industrial customer that is currently under Chapter 11 bankruptcy protection. The amounts were incurred after the customer’s petition for bankruptcy was filed and the Company believes it will ultimately receive payment as the customer emerges from bankruptcy protection.

Two of the Company’s utilities in Ohio, Orwell and NEO, collect from their customers, through rates, an amount to provide an allowance for doubtful accounts. As accounts are identified as uncollectible, they are written off against this allowance for doubtful accounts with no income statement impact. In effect, all bad debt expense is funded by the customer base. The total amount collected from customers and the amounts written off are reviewed annually by the PUCO and the rate per Mcf is adjusted as necessary.

The Company’s bad debt expense for the three and nine months ended September 30, 2012 was $42,874 and $230,759, respectively. Bad debt expense for the three and nine months ended September 30, 2011 was $10,079 and $89,256, respectively.

F-8

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Recoverable/Refundable Costs of Gas Purchases

The Company accounts for purchased gas costs in accordance with procedures authorized by the utility commissions in the states in which it operates. Purchased gas costs that are different from those provided for in present rates, and approved by the respective commission, are accumulated and recovered or credited through future rate changes. The gas cost recoveries are monitored closely by the regulatory commissions in all of the states in which the Company operates and are subject to periodic audits or other review processes.

During the year ended December 31, 2010, the PUCO conducted audits of NEO and Orwell’s rates as filed from September 2007 through August 2009 and January 2008 through June 2010, respectively. The PUCO provided the primary audit findings during the fourth quarter of 2010, taking the position that NEO had not included approximately $1,050,000 of costs and Orwell included an excess of approximately $1,100,000 of costs in the filings under audit. On October 26, 2011, the PUCO adopted and approved a Joint Stipulation that finalizes the adjustments for NEO and Orwell to approximately $1,100,000 and ($964,000), respectively. However, the Joint Stipulation modified the refund period for Orwell to one year as compared to two years as originally identified. The Company considered the modification to be material and sought rehearing. On December 22, 2011, the PUCO affirmed its Finding and Order requiring Orwell’s refund to be completed over twelve months.

During the year ended December 31, 2011, the PUCO conducted an audit of Brainard’s rates as filed from July 2009 through June 2011. The Staff of the PUCO recommended a finding that Brainard collected excess gas costs of approximately $104,000. The Company agreed that excess gas costs were collected, but only in the amount of approximately $48,000. An evidentiary hearing was convened on November 3, 2011, resumed on March 27, 2012 and concluded on April 12, 2012. On August 8, 2012 the PUCO issued its order requiring that Brainard refund approximately $104,000 with interest over twelve months. The Company filed an application for rehearing on September 26, 2012 which was denied by entry on rehearing issued on September 26, 2012. The Company initiated the refund commencing in October 2012.

Regulatory Assets and Liabilities

The regulatory asset for property tax is recovered in rates over a ten-year period starting January 1, 2004. The recoverable income taxes earn a return equal to that of the Company’s rate base. The rate case costs do not earn a return. Regulatory assets will be recovered over a period of approximately three to twenty years. Regulatory liabilities will be refunded over a period of approximately five to twenty years.

Debt Issuance Costs

Debt issuance costs are fees and other direct incremental costs incurred by the Company in obtaining debt financing and are recognized as assets and are amortized as interest expense over the term of the related debt. Amortization expense was $37,990 and $177,379 for the three and nine months ended September 30, 2012, respectively. Amortization expense was $38,081 and $106,748 for the three and nine months ended September 30, 2011, respectively. The Company has incurred $1,074,456 during 2012 related to the current bank refinancing opportunities and has included them as debt issuance costs at September 30, 2012. Amortization of these costs began in October 2012.

Asset Retirement Obligations

The Company records the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it was incurred or acquired. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in “Property, plant and equipment, net” in the accompanying balance sheets. The Company amortizes the amount added to property, plant, and equipment, net. The accretion of the asset retirement liability is allocated to operating expense using a systematic and rational method. As of September 30, 2012 and December 31, 2011, the Company has recorded a net asset of $174,416 and $227,216, and a related liability of $1,808,069 and $1,689,081, respectively.

The Company, excluding Orwell and Brainard, has identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.

F-9

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As a result of regulatory action by the PUCO related to prior audits, Orwell and Brainard accrue an estimated liability for removing gas mains, meter and regulator station equipment and service lines at the end of their useful lives. The liability is equal to a percent of the asset cost according to the following table:

	Percent of Asset Cost
	Orwell			Brainard
Mains		15	%		20	%
Meter/regulator stations		15	%		10	%
Service lines		15	%		75	%

The Company has no assets legally restricted for purposes of settling its asset retirement obligations. The schedule below is a reconciliation of the Company’s liability for the nine months ended September 30:

	2012		2011
Balance, beginning of period	$	1,689,081	$	1,546,867
Accretion expense		118,988		105,262
Balance, end of period	$	1,808,069	$	1,652,129

Revenue Recognition

Revenues are recognized in the period that services are provided or products are delivered. The Company records gas distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The Company periodically collects revenues subject to possible refunds pending final orders from regulatory agencies. When this occurs, appropriate liabilities for such revenues collected subject to refund are established.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which for the Company is primarily comprised of unrealized holding gains or losses on available-for-sale securities that are excluded from the statement of income and comprehensive income in computing net income (loss) and reported separately in shareholders’ equity.

Other comprehensive income (loss) for the three and nine months ended September 30, 2012 is reported net of income tax of ($2,530) and ($6,325), respectively. Other comprehensive income for the three and nine months ended September 30, 2011 is reported net of tax of $17,883 and $29,550, respectively.

Earnings Per Share

Earnings per common share is computed by both the basic method, which uses the weighted average number of common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options and other dilutive securities, as calculated using the treasury stock method.

F-10

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012		2011
Numerator:
Net income (loss)	$	(671,221	)	$	129,526	$	1,887,434	$	4,764,618
Denominator:
Basic weighted average common shares outstanding		8,186,791			8,152,487		8,165,874		8,151,370
Dilutive effect of stock options		—			7,561		6,549		7,956
Diluted weighted average common shares outstanding		8,186,791			8,160,048		8,172,423		8,159,326

The Company excludes outstanding stock options with exercise prices that are greater than the average market price from the calculation of diluted earnings per share because their effect would be anti-dilutive. The Company reported a net loss from continuing operations for the three months ended September 30, 2012 and therefore, the 35,000 stock options outstanding are anti-dilutive. There were no stock options that were anti-dilutive for the three months ended September 30, 2011. There were no stock options that were anti-dilutive for the nine months ended September 30, 2012 and 2011, respectively.

Reclassifications

Certain reclassifications of prior year reported amounts have been made for comparative purposes. Such reclassifications had no effect on income (loss).

Recently Adopted Accounting Pronouncements

ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurements and Disclosure Requirements in US GAAP and IFRSs”

In May 2011, the FASB issued ASU 2011-04, which changes the wording used to describe many of the requirements in US GAAP for measuring fair value and for disclosing information about fair value measurements in order to conform with IFRS. The adoption of this guidance did not have a material impact on the accompanying financial statements.

ASU No. 2011-05, “Presentation of Comprehensive Income”

In June 2011, the FASB issued ASU 2011-05, which is intended to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. To increase the prominence of items reported in other comprehensive income and to facilitate convergence of GAAP and IFRS, the FASB eliminated the option to present components of other comprehensive income as part of the statement of changes in stockholders’ equity. The ASU requires all non-owner changes in stockholders’ equity be presented either in a single continuous statement of income and comprehensive income or in two separate but consecutive statements. This ASU changed the presentation of other comprehensive income in the accompanying financial statements. However, this ASU did not change the calculation of the other comprehensive income. The adoption of this guidance did not have a material impact on the accompanying financial statements.

Note 2 – Acquisitions

Acquisition of Spelman Pipeline

On April 8, 2011 the Company’s indirect subsidiary, Spelman Pipeline Holdings, LLC (“Spelman”), a subsidiary of Lightning Pipeline, completed the acquisition of dormant refined products pipeline assets from Marathon Petroleum Company LP. The cash purchase price for the assets was $3.34 million.

The acquired assets include pipelines and rights-of-way located in Ohio and Kentucky. In Ohio, the assets include more than 140 miles of pipeline spanning almost a third of the state from Marion to Youngstown. Other Ohio assets are located in metropolitan and south suburban Cleveland. The Kentucky assets include more than 60 miles of right-of-way to the south of Louisville.

Spelman has reconditioned a portion of the Ohio pipeline, has been authorized by the PUCO to operate as an intrastate pipeline, and in August 2012, initiated transportation service pursuant to its tariff.

F-11

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Future plans include extending the lines to participate in the transportation of Utica and Marcellus Shale production. The Company does not currently have definitive plans for the Kentucky assets.

Acquisition of Independence Oil & LP Gas, Inc.

On August 1, 2011 the Company purchased certain assets and assumed certain liabilities of Independence Oil & LP Gas, Inc. for the original price of $1.6 million, of which $200,000 was held back for 90 days. Independence Oil & LP Gas, Inc. delivered liquid propane, heating oil, and kerosene to approximately 4,500 customers from its facilities in West Jefferson, North Carolina and Independence, Virginia. The Company created a new subsidiary named Independence Oil, LLC and is continuing to service the current customers with the intention to expand to other customers in each of the regions. The costs related to the transaction were $13,526 and were expensed during the year ended December 31, 2011.

In accordance with GAAP, the Company determined the purchase of the assets acquired and liabilities assumed to be a business combination. Therefore, the Company applied the acquisition method and valued each of the assets acquired (cash, accounts receivable, inventory, and property, plant and equipment) and liabilities assumed (accounts payable) at fair value as of the acquisition date. The cash, accounts receivable and accounts payable were deemed to be at fair value as of the acquisition date. The Company valued the fair value of inventory and property, plant and equipment by performing fair value research of the items acquired. This process resulted in the fair value of the assets acquired, reduced by the liabilities assumed, to be greater than the purchase price. The difference is a gain from bargain purchase and is included as a separate line item in the Consolidated Statement of Income and Comprehensive Income for the quarter ended September 30, 2011 and the Consolidated Statement of Income for the year ended December 31, 2011. The Company completed the transaction as it provided the opportunity to strengthen its presence in North Carolina, while extending into Virginia, two markets with favorable competitive conditions targeted for growth.

The estimated fair value of the assets acquired and liabilities assumed is reflected in the following table at the date of acquisition.

Current assets	$	429,576
Property and equipment		1,958,717
Total assets acquired		2,388,293
Current liabilities		57,777
Total liabilities assumed		57,777
Net assets acquired	$	2,330,516

The asset purchase agreement included a settlement date 90 days after the acquisition date, determined to be October 31, 2011 by both parties. As a result of this settlement, the Company paid $125,000 of the $200,000 that was held back at the acquisition date on November 1, 2011. The remaining $75,000 was held back to complete an environmental remediation project that was agreed upon at the time of closing. The environmental remediation was completed in December 2011 and the $75,000 was paid for the remediation project and therefore no funds were remaining to provide to the seller. In addition, there was approximately $50,000 of net working capital adjustments made during this settlement. The effects of this settlement were recorded during December 2011 and are reflected in the accompanying condensed consolidated financial statements.

Acquisition of Public Gas Company, Inc.

On April 1, 2012 the Company purchased 100% of the stock of PGC from Kentucky Energy Development, LLC for the original price of $1.6 million, of which $48,522 was held back and a portion is to be settled 45 days from closing and the remainder is to be settled 180 days from closing. PGC is a regulated natural gas distribution company serving approximately 1,600 customers in the State of Kentucky in the counties of Breathitt, Jackson, Johnson, Lawrence, Lee, Magoffin, Morgan and Wolf. The costs related to the transaction were $51,187 and were expensed during the nine months ended September 30, 2012. The Company completed the transaction as it provided the opportunity to expand its presence into Kentucky.

The Company applied the acquisition method to the business combination and valued each of the assets acquired (cash, accounts receivable, and property, plant and equipment) and liabilities assumed (accounts payable) at fair value as of the acquisition date. The cash, accounts receivable and accounts payable were deemed to be recorded at fair value as of the acquisition date. The Company determined the fair value of property, plant and equipment to be historical book value which is the rate base as PGC is a regulated

F-12

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

natural gas distribution company and is required to report to the KPSC. The Company also recorded deferred taxes based on the timing difference related to depreciation. As a result of the purchase, $142,971 was allocated to goodwill, is reported in the natural gas operations segment and is unchanged since the acquisition. The Company expects none of the goodwill to be deductible for tax purposes.

The estimated fair value of the assets acquired and liabilities assumed is reflected in the following table at the date of acquisition.

Current assets	$	69,634
Property and equipment		1,577,593
Goodwill		142,971
Total assets acquired		1,790,198
Current liabilities		103,828
Long-term liabilities		134,892
Total liabilities assumed		238,720
Net assets acquired	$	1,551,478

As part of the final settlement due 180 days from closing, both parties have agreed that the Company will pay $1,029 as final settlement of the purchase agreement.

Acquisition of Loring Pipeline lease and related property

On April 17, 2012, the Company entered into an agreement with United States Power Fund, L.P. (“USPF”) to place a bid at a public auction on certain assets that were being foreclosed upon by USPF (the “Agreement”). Those assets included various parcels of land as well as a leasehold interest in a pipeline corridor easement running from Searsport to Limestone, Maine. The assets were owned by Loring BioEnergy, LLC (“LBE”) and were being foreclosed upon by USPF due to LBE’s default on a loan that it had obtained from USPF. On June 4, 2012 the Company attended the public foreclosure auction and was the successful bidder with a bid of $4,500,000. The transaction closed on September 25, 2012. At that time, the Company issued 210,951 shares of common stock in addition to transferring the $2,250,000 of cash it had placed into escrow prior to the auction, to USPF. The lease agreement calls for lease payments of $300,000 per year for the next ten years, an annual service fee of $120,000 and a charge of $0.0125 per Mcf moved on the pipeline. Due to the timing of the closing of the transaction, the Company has been unable to gather the necessary information to determine the appropriate accounting treatment for this transaction. Therefore, at September 30, 2012, the Company has recorded $4,534,866 as a non-current asset on the other assets line item and increased the common stock and paid in capital line items by $31,643 and $2,218,361, respectively, on the accompanying condensed consolidated balance sheet to reflect the cash paid and the fair value of stock issued.

Note 3 – Marketable Securities

Securities investments that the Company has the positive intent and ability to hold to maturity are classified as held-to-maturity securities and recorded at amortized cost. Securities investments bought expressly for the purpose of selling in the near term are classified as trading securities and are measured at fair value with unrealized gains and losses reported in earnings. Securities investments not classified as either held-to-maturity or trading securities are classified as available-for-sale securities. Available-for-sale securities are recorded at fair value in marketable securities in the accompanying balance sheets, with the change in fair value during the period excluded from earnings and recorded net of tax as a component of other comprehensive income. Realized gains and losses, and declines in value judged to be other than temporary, are reported in the accompanying statements of income. The Company did not hold any held-to-maturity or trading securities as of September 30, 2012 or December 31, 2011.

F-13

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following is a summary of available-for-sale securities at:

	September 30, 2012
	Investment at cost		Unrealized Gains		Estimated Fair Value
Common stock	$	238,504	$	112,496	$	351,000
	December 31, 2011
	Investment at cost		Unrealized Gains		Estimated Fair Value
Common stock	$	238,504	$	129,371	$	367,875

Unrealized gains on available-for-sale securities of $69,853 and $96,287, respectively (net of $42,643 and $58,409 in taxes) was included in accumulated other comprehensive income in the accompanying balance sheets at September 30, 2012 and December 31, 2011, respectively.

The Company did not sell any available-for-sale securities during the three and nine months ended September 30, 2012 and 2011.

As of September 30, 2012 and December 31, 2011, the Company did not hold any securities in an unrealized loss position.

Note 4 – Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs.

Valuation Hierarchy

A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs).

The following tables represent the Company’s fair value hierarchy for its financial assets measured at fair value on a recurring basis as of:

	September 30, 2012
	Level 1		Level 2		Level 3		TOTAL
Available-for-sale securities	$	351,000		—		—	$	351,000
	December 31, 2011
	Level 1		Level 2		Level 3		TOTAL
Available-for-sale securities	$	367,875		—		—	$	367,875

The fair value of financial instruments including cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair values of marketable securities are estimated based on closing share price on the quoted market price for those investments. Cost basis is determined by specific identification of securities sold. Under the fair value hierarchy, the fair value of cash and cash equivalents is classified as a Level 1 measurement and the fair value of notes payable are classified as Level 2 measurements.

F-14

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 5 – Credit Facilities and Long-Term Debt

Bank of America

On September 20, 2012, the Company’s subsidiary, Energy West, entered into an Amended and Restated Credit Agreement (the “Credit Agreement”), with the Bank of America, N.A. (“Bank of America”) which modifies the original credit agreement entered into on June 29, 2007, as amended from time to time. The Credit Agreement renewed the $30.0 million revolving credit facility available to Energy West and provides for a maturity date of April 1, 2017. In addition, Energy West entered into a $10.0 million term loan with Bank of America with a maturity date of April 1, 2017 (the “Term Loan”). Pursuant to the terms of the Credit Agreement, Energy West issued a second amended and substitute note to Bank of America in the amount of $30.0 million for the revolving credit facility and another note in the original principal amount of $10.0 million for the Term Loan.

The Credit Agreement includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the Credit Agreement and interest on the amounts outstanding at the London Interbank Offered Rate (“LIBOR”) rate plus 175 to 225 basis points. The Term Loan has an interest rate of LIBOR plus 175 to 225 basis points with an interest rate swap provision that allows for the interest rate to be fixed in the future. The Term Loan will be amortized at a rate of $125,000 per quarter, with the first principal payment being due on December 31, 2012.

For the three months ended September 30, 2012 and 2011, the weighted average interest rate on the existing and renewed revolving credit facility was 3.14% and 1.56%, respectively, resulting in $141,780 and $55,355 of interest expense, respectively. For the nine months ended September 30, 2012 and 2011, the weighted average interest rate on the facility was 3.26% and 1.67%, respectively, resulting in $373,835 and $156,602 of interest expense, respectively. The balance on the revolving credit facility was $18,020,000 and $23,160,000 at September 30, 2012 and December 31, 2011, respectively. The $18.0 million of borrowings as of September 30, 2012, leaves the remaining borrowing capacity on the line of credit at $12.0 million.

The balance outstanding on the Bank of America term loan at September 30, 2012 was $10,000,000. The weighted average interest rate for the three and nine months ended September 30, 2012 was 2.22%, resulting in interest expense of $6,163.

Senior Unsecured Notes

On June 29, 2007, Energy West authorized the sale of $13,000,000 aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017 (the “Senior Unsecured Notes”). The proceeds of these notes were used to refinance existing notes. Approximately $463,000 was incurred related to the debt issuance which was capitalized and is being amortized over the life of the notes.

Interest expense was $200,200 and $600,600 for the three and nine months ended September 30, 2012 and $200,200 and $600,600 for the three and nine months ended September 30, 2011, respectively.

Citizens Bank

In connection with the acquisition of the Ohio subsidiaries, NEO and Great Plains each entered modifications/amendments to its credit facility with Citizens Bank (the “Citizens Credit Facility”). The Citizens Credit Facility consisted of a revolving line of credit and term loan to NEO, and two other term loans to Great Plains respectively. Each amendment/modification was initially effective as of December 1, 2009, but was later modified to be effective as of January 5, 2010. Gas Natural guaranteed each loan. Mr. Osborne, our Chief Executive Officer of the Company, guaranteed each loan both individually and as trustee of the Osborne Trust, and Great Plains guaranteed NEO’s revolving line of credit and term loans.

The Ohio subsidiaries had term loans with Citizens Bank in the aggregate amount of $11.3 million. Each term note had a maturity date of July 1, 2013 and bore interest at an annual rate of 30-day LIBOR plus 400 basis points with an interest rate floor of 5.00% per annum. For the three and nine months ended September 30, 2011, the weighted average interest rate on the term loans was 5.00%, resulting in $0 and $156,022 of interest expense, respectively. The term loans were paid off on May 3, 2011.

F-15

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SunLife Assurance Company of Canada

On May 2, 2011, the Company and its Ohio subsidiaries, NEO, Orwell and Brainard (together the “Issuers”), issued $15.3 million of 5.38% Senior Secured Guaranteed Fixed Rate Notes due June 1, 2017 (“Fixed Rate Note”). Additionally, Great Plains issued $3.0 million of Senior Secured Guaranteed Floating Rate Notes due May 3, 2014 (“Floating Rate Note”). Both notes were placed with SunLife. Approximately $615,000 was incurred related to the debt issuance which was capitalized and is being amortized over the life of the notes.

The Fixed Rate Note, in the amount of $15.3 million, is a joint obligation of the Issuers, and is guaranteed by the Company, Lightning Pipeline and Great Plains (together with the Issuers, “the Fixed Rate Obligors”). This note received approval from the PUCO on March 30, 2011. The note is governed by a Note Purchase Agreement (“NPA”). Concurrent with the funding and closing of this transaction, which occurred on May 3, 2011, the Fixed Rate Obligors signed an amended NPA that is substantially the same as the NPA released on November 2, 2010. Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium.

The Floating Rate Note, in the amount of $3.0 million, is an obligation of Great Plains and is guaranteed by the Company (together, “the Floating Rate Obligors”). The note is priced at a fixed spread of 385 basis points over three month Libor. Pricing for this note will reset on a quarterly basis to the then current yield of three month Libor. The note is governed by a NPA. Concurrent with the funding of this transaction, which occurred on May 3, 2011, the Floating Rate Obligors signed an amended NPA that is substantially the same as the NPA released on November 2, 2010. Prepayment of this note prior to maturity is at par.

The use of proceeds for both notes extinguished existing amortizing bank debt and other existing indebtedness, funded $3.4 million for the 2011 capital program for Orwell and NEO, established two debt service reserve accounts, and replenished the Company’s treasuries for prior repayment of maturing bank debt and transaction expenses. The capital program funds and debt service reserve accounts are in interest bearing accounts and included in restricted cash.

For the year ended December 31, 2011, the Company breached a financial covenant under the Fixed Rate Note and Floating Rate Note when the Obligors made restricted payments in the form of dividends to the holding company in excess of the amounts permissible. In addition, the Company did not timely notify Sun Life of certain newly-formed subsidiaries which were required to be obligors under the Fixed Rate Note and Floating Rate Note. The failure to timely notify Sun Life constituted a breach of the Fixed Rate Note and Floating Rate Note. The Company requested that Sun Life waive these breaches and amend the financial covenants.

Sun Life required debt service reserve accounts to be created for $950,000 to cover approximately one year of interest payments. The Company is not able to use these funds in the debt service reserve accounts for operational cash purposes.

Payments for both notes prior to maturity are interest-only.

For the three and nine months ended September 30, 2012, the weighted average interest rate on the Fixed Rate Note was 5.38%, resulting in $206,242 and $618,727 of interest expense, respectively. For the three and nine months ended September 30, 2011, the weighted average interest rate on the Fixed Rate Note was 5.38%, resulting in $206,242 and $343,737 of interest expense, respectively.

For the three and nine months ended September 30, 2012, the weighted average interest rate on the Floating Rate Note was 4.31% and 4.39% resulting in $32,300 and $97,650 of interest expense, respectively. For the three and nine months ended September 30, 2011, the weighted average interest rate on the Floating Rate Note 4.11% resulting in $51,450 of interest expense.

On April 9, 2012, the Company entered into a waiver and amendment of the Fixed Rate Note and Floating Rate Note. Pursuant to the amendments, Sun Life waived its rights and remedies of the breaches of the covenants described above.

The amendments also provide that any cash dividends, distributions, redemptions or repurchases of common stock may be made by the obligors to the holding company only if (i) the aggregate amount of all such dividends, distributions, redemptions and repurchases for the fiscal year do not exceed 70% of net income of the obligors for the four fiscal quarters then ending determined as of the end of each fiscal quarter for the four fiscal quarters then ending, and (ii) there exists no other event of default at the time the dividend, distribution, redemption or repurchase is made. Currently, the Company does not expect the obligors to be able to pay a dividend to the holding company until the first quarter of 2013. The inability of the obligors to pay a dividend to the holding company may impact the Company’s ability to pay a dividend to shareholders. In addition, the Company agreed to deliver an irrevocable standby letter of credit to Sun Life in the amount of $750,000 to be drawn upon by Sun Life if and when any event of default has occurred and is continuing. After discussion with Sun Life, the parties agreed to change the letter of credit requirement to depositing cash into a reserve account whereas Sun Life is the beneficiary. The terms allow the Company to withdraw that money if a letter of credit is received to replace the restricted cash.

F-16

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Fixed Rate Note and Floating Rate Note require, on a consolidated basis, an interest coverage ratio of at least 2.0 to 1.0, measured quarterly on a trailing four quarter basis. The notes generally define the interest coverage ratio as the ratio of EBITDA to gross interest expense. The notes defines EBITDA as net income plus the sum of interest expense, any provision for federal, state, and local taxes, depreciation, and amortization determined on a consolidated basis in accordance with GAAP, but excluding any extraordinary non-operating income or loss from non-operating transactions. The interest coverage ratio is measured with respect to the Obligors on a consolidated basis and also with respect to the Company and all of its subsidiaries, on a consolidated basis. The notes also require that the Company does not permit indebtedness to exceed 60% of capitalization at any time. Like the interest coverage ratio, the ratio of debt to capitalization is measured on a consolidated basis for the Obligors, and again on a consolidated basis with respect to the Company and all of its subsidiaries.

Yadkin Valley Bank

On February 13, 2012, Independence entered into a one year, $500,000 revolving credit facility with Yadkin Valley Bank with an interest rate based on the prime rate, with a floor of 4.5% per annum and a maximum of 16% per annum. For the three and nine months ended September 30, 2012, the weighted average interest rate on the facility was 4.5% and 4.5%, respectively, resulting in $4,612 and $8,293 of interest expense, respectively. The balance on the facility was $401,000 at September 30, 2012. The $401,000 of borrowings as of September 30, 2012, leaves the remaining borrowing capacity on the line of credit at $99,000.

Debt Covenants

The Bank of America Credit Agreement contains various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 80% of Energy West’s aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios.

The Senior Unsecured Notes contain similar convenants, and include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 100% of Energy West’s aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios.

The Fixed Rate Note and the Floating Rate Note carry a 60% debt-to-capitalization financial covenant on a consolidated basis for Ohio, as well as, a 2.0x interest coverage test based on a trailing twelve-month basis. Additional covenants customary for asset sales and purchases, additional indebtedness, dividends, change of control and other matters are also included.

The Company believes it is in compliance with the financial covenants under its debt agreements or has received waivers for any defaults.

The following table shows the future minimum payments on the credit facilities and long-term debt for the years ended September 30:

2013	$	508,387
2014		3,504,375
2015		500,000
2016		500,000
2017		36,334,000
Thereafter		—
Total	$	41,346,762

F-17

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 6 – Stockholders’ Equity

2002 Stock Option Plan

The Energy West Incorporated 2002 Stock Option Plan (the “Option Plan”) expired on October 4, 2012 and provided for the issuance of up to 300,000 options to purchase the Company’s common stock to be issued to certain key employees. As of September 30, 2012 and December 31, 2011, there were 35,000 and 35,000 options outstanding, respectively. Under the Option Plan, the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 110% of the fair market value if the employee owns more than 10% of the outstanding common stock). Pursuant to the Option Plan, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance.

The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model.

A summary of the status of the stock option plans as follows:

	Number of Shares			Weighted Average Exercise Price		Aggregate Intrinsic Value
Outstanding December 31, 2010		39,500		$	8.40
Granted		—		$	—
Exercised		—		$	—
Expired		(4,500	)	$	6.35
Outstanding September 30, 2011		35,000		$	8.66	$	51,538
Exerciseable September 30, 2011		18,750		$	8.24	$	81,450
	Number of Shares			Weighted Average Exercise Price		Aggregate Intrinsic Value
Outstanding December 31, 2011		35,000		$	8.66
Granted		—		$	—
Exercised		—		$	—
Expired		—		$	—
Outstanding September 30, 2012		35,000		$	8.66	$	50,300
Exerciseable September 30, 2012		27,500		$	8.38	$	47,425

As of September 30, 2012 and December 31, 2011, there was $5,583 and $12,637 of total unrecognized compensation cost related to stock-based compensation, respectively. That cost is expected to be recognized over a period of three years.

F-18

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The following information applies to options outstanding at September 30, 2012:

Grant Date	Exercise Price		Number Outstanding		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)	Number Exercisable		Weighted Average Exercise Price
12/1/2008	$	7.10		10,000	$	7.10	6.17		10,000	$	7.10
6/3/2009	$	8.44		5,000	$	8.44	1.67		5,000	$	8.44
12/1/2009	$	8.85		10,000	$	8.85	7.17		7,500	$	8.85
12/1/2010	$	10.15		10,000	$	10.15	8.17		5,000	$	10.15
				35,000					27,500

During the three and nine months ended September 30, 2012, the Company recorded $2,351 and $7,055, respectively ($1,458 and $4,374, respectively, net of related tax effects), of compensation expense for stock options granted after July 1, 2005, and for the unvested portion of previously granted stock options that remained outstanding as of July 1, 2005. During the three and nine months ended September 30, 2011, the Company recorded $4,796 and $14,389, respectively ($2,998 and $8,995, respectively, net of related tax effects), of compensation expense for stock options granted after July 1, 2005, and for the unvested portion of previously granted stock options that remained outstanding as of July 1, 2005.

Note 7 – Employee Benefit Plans

The Company has a defined contribution plan (the “401k Plan”) which covers substantially all of its employees. The plan provides for an annual contribution of 3% of salaries, with a discretionary contribution of up to an additional 3%. The expense related to the 401k Plan for the three and nine months ended September 30, 2012, was $92,511 and $329,271, respectively. The expense related to the 401k Plan for the three and nine months ended September 30, 2011, was $70,420 and $281,861, respectively.

The Company makes matching contributions in the form of Company common stock equal to 10% of each participant’s elective deferrals in the 401k Plan. The Company contributed shares of common stock valued at $12,039 and $39,235 for the three and nine months ended September 30, 2012, respectively. The Company contributed shares of common stock valued at $3,133 and $26,338 for the three and nine months ended September 30, 2011, respectively. In addition, a portion of the 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most employees. The ESOP receives contributions of common stock from the Company each year as determined by the Board of Directors. The contribution is recorded based on the current market price of the Company’s common stock. The Company made no contributions of common stock for the three months ended September 30, 2012 and 2011.

The Company has sponsored a defined benefit postretirement of common stock health plan (the “Retiree Health Plan”) providing health and life insurance benefits to eligible retirees. The Retiree Health Plan pays eligible retirees (post-65 years of age) up to $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. In addition, the Retiree Health Plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage. The amounts paid in excess of the current COBRA rate is held in a VEBA trust account, and benefits for this plan are paid from assets held in the VEBA Trust account. The Company discontinued contributions in 2006 and is no longer required to fund the Retiree Health Plan. As of September 30, 2012 and December 31, 2011, the value of plan assets was $163,455 and $182,931, respectively. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.

F-19

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8 – Income Taxes

Income tax position differs from the amount computed by applying the federal statutory rate to pre-tax income or loss as demonstrated in the table below:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Income tax from continuing operations:
Tax expense (benefit) at statutory rate of 34%	$	(486,631	)	$	(119,961	)	$	933,432		$	2,396,889
State income tax, net of federal tax exp (benefit)		(64,391	)		(12,089	)		133,547			241,543
Amortization of deferred investment tax credits		(5,266	)		(5,266	)		(15,797	)		(15,798	)
Adjustment to tax return filed		(193,228	)		(319,784	)		(193,228	)		(319,784	)
Other		(10,531	)		(25,253	)		—			(17,794	)
Total income tax expense (benefit)	$	(760,047	)	$	(482,353	)	$	857,954		$	2,285,056

The “Adjustment to tax return filed” line above for the three and nine months ended September 30, 2012 includes an income tax benefit of $198,974 related to the correction of certain deferred tax balance sheet items related to 2011 recorded during the three months ended September 30, 2012.

The Company recognizes interest accrued related to unrecognized tax positions in interest expense and penalties in operating expense. No interest and penalties related to unrecognized tax positions were accrued at September 30, 2012 and December 31, 2011.

The tax years after 2007 remain open to examination by the major taxing jurisdictions in which the Company operates. No material changes to unrecognized tax positions are expected within the next twelve months.

Note 9 – Related Party Transactions

The Company is party to certain agreements and transactions with Mr. Osborne, or companies owned or controlled by Mr. Osborne.

Notes Payable

The Company had two notes payable to Mr. Osborne. The first note was payable on demand and bore interest at a rate equal to the prime rate as published by Key Bank. On December 1, 2010, the Company repaid the first note in full, including all interest accrued to date. The second note had a maturity date of January 3, 2014 and bore interest at 6.0% annually. On May 3, 2011, the Company repaid the second note in full, including all interest accrued to date, using the SunLife proceeds. Interest expense incurred related to both loans was $0 and $529 for the three and nine months ended September 30, 2011, respectively.

Note Receivable

The Company has a note receivable from John D. Oil and Gas Marketing, a company controlled by Mr. Osborne, with a maturity date of December 31, 2016 and an annual interest rate of 7.0% relating to funds loaned to John D. Oil and Gas Marketing to finance the acquisition of a gas pipeline. The balance due from John D. Oil and Gas Marketing was $38,040 and $45,664 (of which, $10,807 and $10,256 is due within one year) as of September 30, 2012 and December 31, 2011, respectively. The Company has a corresponding agreement to lease the pipeline from John D. Oil and Gas Marketing through December 31, 2016. Lease expense resulting from this agreement was $3,300 and $9,900 for the three and nine months ended September 30, 2012, respectively, which is included in the Natural Gas Purchased column below. Lease expense resulting from this agreement was $3,300 and $9,900 for the three and nine months ended September 30, 2011 which is included in the Natural Gas Purchased column below. There was no balance due at September 30, 2012 or December 31, 2011 to John D. Oil and Gas Marketing related to these lease payments.

F-20

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Accounts Receivable and Accounts Payable

The table below details amounts due from and due to related parties, including companies owned or controlled by Mr. Osborne, at September 30, 2012 and December 31, 2011, respectively:

	Accounts Receivable				Accounts Payable
	September 30, 2012		December 31, 2011		September 30, 2012		December 31, 2011
John D. Oil and Gas Marketing	$	7,658	$	3,282	$	8,011	$	126,051
Cobra Pipeline		23,308		448		7,509		1,312
Orwell Trumbell Pipeline		130,948		128,012		12,366		1,043
Great Plains Exploration		140,689		133,928		9		9
Big Oats Pipeline Supply		1,135		432		151,546		53,348
Kykuit Resources		98,037		98,037		—		—
Sleepy Hollow		143,697		138,611		—		—
Other		20,136		16,334		—		10,000
Total	$	565,608	$	519,084	$	179,441	$	191,763

The table below details transactions with related parties, including companies owned or controlled by Mr. Osborne, for the three months ended September 30, 2012:

	Three Months Ended September 30, 2012
	Natural Gas Purchases		Pipeline and Construction Purchases		Rent, Supplies, Consulting, and Other Purchases		Natural Gas Sales		Management and Other Sales
John D. Oil and Gas Marketing	$	434,092	$	—	$	3,856	$	3,282	$	—
Cobra Pipeline		22,793		—		2,176		—		3,558
Orwell Trumbell Pipeline		50,535		—		—		128		—
Great Plains Exploration		81,535		—		—		486		1,773
Big Oats Pipeline Supply		—		215,629		69,823		29		187
Sleepy Hollow		—		—		—		—		—
John D. Oil and Gas Company		90,270		—		—		144		—
OsAir		43,029		—		—		144		—
Other		18,368		—		30,000		1,677		47
Total	$	740,622	$	215,629	$	105,855	$	5,890	$	5,565

F-21

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The table below details transactions with related parties, including companies owned or controlled by Mr. Osborne, for the three months ended September 30, 2011:

	Three Months Ended September 30, 2011
	Natural Gas Purchases		Pipeline and Construction Purchases		Rent, Supplies, Consulting, and Other Purchases		Natural Gas Sales		Management and Other Sales
John D. Oil and Gas Marketing	$	763,371	$	45,450	$	5,340	$	—	$	3,282
Cobra Pipeline		17,873		1,282		319		—		6,090
Orwell Trumbell Pipeline		26,270		10,677		49,019		148		1,914
Great Plains Exploration		380,260		229,916		455		96		7,678
Big Oats Pipeline Supply		—		249,663		70,217		29		—
Kykuit Resources		—		—		—		—		—
Sleepy Hollow		—		—		—		—		11,074
Other		—		—		48,170		2,066		384
Total	$	1,187,774	$	536,988	$	173,520	$	2,339	$	30,422

The table below details transactions with related parties, including companies owned or controlled by Mr. Osborne, for the nine months ended September 30, 2012:

	Nine Months Ended September 30, 2012
	Natural Gas Purchases		Pipeline and Construction Purchases		Rent, Supplies, Consulting, and Other Purchases		Natural Gas Sales		Management and Other Sales
John D. Oil and Gas Marketing	$	1,843,487	$	9,870	$	5,988	$	3,282	$	6,564
Cobra Pipeline		305,311		890		2,667		—		23,012
Orwell Trumbell Pipeline		348,191		—		19,429		1,062		2,898
Great Plains Exploration		335,571		—		—		5,372		9,143
Big Oats Pipeline Supply		—		687,091		194,854		1,454		6,951
Sleepy Hollow		—		—		—		—		5,113
John D. Oil and Gas Company		462,343		—		—		—		—
OsAir		191,160		—		14,181		—		—
Other		98,733		—		97,171		23,920		718
Total	$	3,584,796	$	697,851	$	334,290	$	35,090	$	54,399

F-22

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The table below details transactions with related parties, including companies owned or controlled by Mr. Osborne, for the nine months ended September 30, 2011:

	Nine Months Ended September 30, 2011
	Natural Gas Purchases		Pipeline and Construction Purchases		Rent, Supplies, Consulting, and Other Purchases		Natural Gas Sales		Management and Other Sales
John D. Oil and Gas Marketing	$	3,190,095	$	45,450	$	7,112	$	—	$	9,846
Cobra Pipeline		261,652		70,048		771		—		7,146
Orwell Trumbell Pipeline		302,443		10,677		98,737		1,905		7,479
Great Plains Exploration		954,131		427,346		605		2,580		20,514
Big Oats Pipeline Supply		—		506,330		479,229		2,740		1,000
Kykuit Resources		—		—		39,600		—		110
Sleepy Hollow		—		—		—		—		22,597
Other		—		—		146,043		52,379		3,441
Total	$	4,708,321	$	1,059,851	$	772,097	$	59,604	$	72,133

The Company also accrued a liability of $279,063 and $635,192, respectively, due to companies controlled by Mr. Osborne for natural gas used through September 30, 2012 and December 31, 2011 that is not yet invoiced. The related expense is included in the gas purchased line item in the accompanying statements of income and comprehensive income. These amounts will be trued up to the actual invoices when received in future periods.

In connection with the common shares of stock sold by Mr. Osborne, the Company incurred expenses of $19,114 and $274,393 during the three and nine months ended September 30, 2012, respectively. The Company incurred expenses of $0 and $46,123 during the three and nine months ended September 30, 2011, respectively. These expenses are recorded in the accompanying income statement as stock sale expense.

On December 20, 2011, the Company consummated a real estate transaction with Black Bear, an Ohio limited liability company owned and controlled by Mr. Osborne, whereby Black Bear sold to the Company approximately 9.24 acres of real estate Black Bear owned in Violet Township, Fairfield County, Ohio for $600,000.

Note 10 – Segments of Operations

The following tables set forth summarized financial information for the Company’s natural gas, marketing and production, pipeline, propane, and corporate and other operations. The Company classifies its segments to provide investors with a view of the business through management’s eyes. The Company primarily separates its state regulated utility businesses from the non-regulated marketing and production business, propane business and from the federally regulated pipeline business. The Company has regulated utility businesses in the states of Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania and Wyoming and these businesses are aggregated together to form the natural gas operations. Transactions between reportable segments are accounted for on the accrual basis, and eliminated prior to external financial reporting. Inter-company eliminations between segments consist primarily of gas sales from the marketing and production operations to the natural gas operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment:

F-23

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Three Months Ended September 30, 2012

	Natural Gas Operations			Marketing and Production			Pipeline Operations		Propane Operations			Corporate and Other			Consolidated
OPERATING REVENUES	$	10,535,653		$	2,966,366		$	95,162	$	605,262		$	—		$	14,202,443
Intersegment eliminations		(77,451	)		(1,156,534	)		—		—			—			(1,233,985	)
Total operating revenue		10,458,202			1,809,832			95,162		605,262			—			12,968,458
COST OF SALES		4,241,809			2,717,296			—		448,672			—			7,407,777
Intersegment eliminations		(77,451	)		(1,156,534	)		—		—			—			(1,233,985	)
Total cost of sales		4,164,358			1,560,762			—		448,672			—			6,173,792
GROSS MARGIN	$	6,293,844		$	249,070		$	95,162	$	156,590		$	—		$	6,794,666
OPERATING EXPENSES		6,731,563			181,982			39,302		449,716			105,591			7,508,154
OPERATING INCOME (LOSS)	$	(437,719	)	$	67,088		$	55,860	$	(293,126	)	$	(105,591	)	$	(713,488	)
NET INCOME (LOSS)	$	(581,901	)	$	326,688		$	99,285	$	(217,634	)	$	(297,659	)	$	(671,221	)

Three Months Ended September 30, 2011

	Natural Gas Operations			Marketing and Production			Pipeline Operations		Propane Operations			Corporate and Other			Consolidated
OPERATING REVENUES	$	10,426,451		$	2,407,303		$	106,351	$	1,009,844		$	—		$	13,949,949
Intersegment eliminations		(77,632	)		(1,551,588	)		—		—			—			(1,629,220	)
Total operating revenue		10,348,819			855,715			106,351		1,009,844			—			12,320,729
COST OF SALES		4,625,856			2,137,398			—		875,305			—			7,638,559
Intersegment eliminations		(77,632	)		(1,551,588	)		—		—			—			(1,629,220	)
Total cost of sales		4,548,224			585,810			—		875,305			—			6,009,339
GROSS MARGIN	$	5,800,595		$	269,905		$	106,351	$	134,539		$	—		$	6,311,390
OPERATING EXPENSES		6,334,711			187,723			29,758		289,466			61,430			6,903,088
OPERATING INCOME (LOSS)	$	(534,116	)	$	82,182		$	76,593	$	(154,927	)	$	(61,430	)	$	(591,698	)
NET INCOME (LOSS)	$	(463,484	)	$	48,712		$	47,540	$	561,986		$	(65,228	)	$	129,526

F-24

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Nine Months Ended September 30, 2012

	Natural Gas Operations			Marketing and Production			Pipeline Operations			Propane Operations			Corporate and Other			Consolidated
OPERATING REVENUES	$	53,349,493		$	8,743,756		$	305,039		$	3,075,972		$	—		$	65,474,260
Intersegment eliminations		(241,659	)		(3,986,476	)		—			—			—			(4,228,135	)
Total operating revenue		53,107,834			4,757,280			305,039			3,075,972			—			61,246,125
COST OF SALES		27,090,234			7,792,965			—			2,298,423			—			37,181,622
Intersegment eliminations		(241,659	)		(3,986,476	)		—			—			—			(4,228,135	)
Total cost of sales		26,848,575			3,806,489			—			2,298,423			—			32,953,487
GROSS MARGIN	$	26,259,259		$	950,791		$	305,039		$	777,549		$	—		$	28,292,638
OPERATING EXPENSES		20,452,543			733,384			139,691			1,447,668			240,503			23,013,789
OPERATING INCOME (LOSS)	$	5,806,716		$	217,407		$	165,348		$	(670,119	)	$	(240,503	)	$	5,278,849
NET INCOME (LOSS)	$	2,729,686		$	386,429		$	160,542		$	(468,712	)	$	(920,511	)	$	1,887,434
As of September 30, 2012
Goodwill	$	14,750,924		$	—		$	—		$	—		$	—		$	14,750,924
Investment in unconsolidated affiliate	$	—		$	321,883		$	—		$	—		$	—		$	321,883
Total assets	$	156,931,213		$	8,392,069		$	820,834		$	2,801,616		$	65,257,002		$	234,202,734
Intersegment eliminations		(17,941,337	)		(247,424	)		(19,422	)		(300,492	)		(57,575,249	)		(76,083,924	)
Total assets	$	138,989,876		$	8,144,645		$	801,412		$	2,501,124		$	7,681,753		$	158,118,810

Nine Months Ended September 30, 2011

	Natural Gas Operations			Marketing and Production			Pipeline Operations			Propane Operations			Corporate and Other			Consolidated
OPERATING REVENUES	$	65,912,371		$	9,957,521		$	314,736		$	1,009,844		$	—		$	77,194,472
Intersegment eliminations		(248,707	)		(5,800,639	)		—			—			—			(6,049,346	)
Total operating revenue		65,663,664			4,156,882			314,736			1,009,844			—			71,145,126
COST OF SALES		39,089,431			8,994,235			—			875,305			—			48,958,971
Intersegment eliminations		(248,707	)		(5,800,639	)		—			—			—			(6,049,346	)
Total cost of sales		38,840,724			3,193,596			—			875,305			—			42,909,625
GROSS MARGIN	$	26,822,940		$	963,286		$	314,736		$	134,539		$	—		$	28,235,501
OPERATING EXPENSES		19,568,006			574,879			125,747			289,466			109,384			20,667,482
OPERATING INCOME (LOSS)	$	7,254,934		$	388,407		$	188,989		$	(154,927	)	$	(109,384	)	$	7,568,019
NET INCOME (LOSS)	$	4,155,383		$	158,119		$	112,094		$	561,986		$	(222,964	)	$	4,764,618
As of September 30, 2011
Goodwill	$	14,607,952		$	—		$	—		$	—		$	—		$	14,607,952
Investment in unconsolidated affiliate	$	—		$	645,042		$	—		$	—		$	—		$	645,042
Total assets	$	127,911,870		$	5,283,146		$	847,311		$	2,957,575		$	64,388,348		$	201,388,250
Intersegment eliminations		(6,394,130	)		(494,121	)		(28,100	)		—			(49,829,951	)	$	(56,746,302	)
Total assets	$	121,517,740		$	4,789,025		$	819,211		$	2,957,575		$	14,558,397		$	144,641,948

F-25

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 11 – Commitments and Contingencies

Legal Proceedings

From time to time, the Company is involved in lawsuits that have arisen in the ordinary course of business. The Company is contesting each of these lawsuits vigorously and believes it has defenses to the allegations that have been made.

On June 20, 2012, the Company was named as a defendant in a lawsuit captioned RBS Citizens N.A., dba Charter One v. Richard M. Osborne, Gas Natural Inc. (f/k/a Energy, Inc.) and the Richard M. Osborne Trust, Case No. CV-12-784656, which was filed in the Cuyahoga County Court of Common Pleas in Ohio. In an effort to collect on judgments obtained against Richard M. Osborne, Chairman and Chief Executive Officer of the Company, the complaint seeks (1) an order requiring the Company to pay over to RBS Citizens any distributions due to Mr. Osborne by virtue of his ownership in Gas Natural as well as any proceeds payable to him as part of the previously announced proposed acquisition of John D. Oil and Gas Marketing, (2) the imposition of a constructive trust on dividends or assets that Mr. Osborne might receive as part of the acquisition of John D. Oil and Gas Marketing and (3) an injunction preventing the acquisition of John D. Oil and Gas Marketing. On August 29, 2012, the Company filed a motion for summary judgment. RBS Citizens filed an opposition brief on October 26, 2012 and a revised version of its brief on October 31, 2012. On October 31, 2012, the Company moved to strike RBS Citizens’ brief as untimely because it was filed approximately one month late. The Company filed a reply brief in support of its motion for summary judgment. It is unclear whether the court will rule on these motions before the end of the year.

In 2010, Bangor Gas Company, the Company’s Maine utility, asserted a claim against H.Q. Energy Services (US), Inc. (“HQ”) for a breach of a firm gas transportation service agreement between the parties. HQ filed a counterclaim against the Company for reimbursement of certain transportation charges that HQ paid to a third party. The parties agreed to arbitration and on September 1, 2011, the arbitrators awarded HQ the sum of approximately $280,000 for past transportation charges that HQ paid to the Company. The arbitrators also ordered the Company to pay future transportation charges that will be incurred during the remaining term of the agreement while HQ was ordered to pay the Company for future fuel reimbursements for the remaining term of the agreement. On September 23, 2011, the arbitrators clarified their initial order to require HQ to reimburse the Company for the past transportation charges awarded by the arbitrators if the FERC determined that our payment of the transportation charges was not consistent with FERC policy. On November 10, 2011, the FERC’s Office of General Counsel issued a no-action letter indicating that the FERC staff could not assure the Company that the FERC would not recommend enforcement action if the Company made the payments to HQ required by the arbitration award. As a result, on November 30, 2011, the Company filed an action in the United States District Court, District of Maine against HQ seeking to vacate the arbitration award against the Company and confirm that portion of the award requiring HQ to return the transportation payments to the Company and obtain an award of past fuel reimbursements in addition to the prospective award made by the arbitrators. On March 1, 2012, the court issued an order confirming the arbitration award against the Company, rejecting the Company’s claim for past fuel costs, and denying the Company’s claim for reimbursement of transportation charges on the grounds that the FERC no-action letter was not a final, binding finding by the FERC of the consistency of the payments with FERC policy. On March 30, 2012, the Company filed an action with the United States Court of Appeals for the First Circuit appealing the district court’s decision in its entirety. The appeal has been briefed; oral arguments have been heard; and the parties are awaiting the Court’s decision.

Additionally, the Company also made a claim against HQ for personal property and real estate tax reimbursements which the Company claimed were due under the transportation contract with HQ. The parties participated in an arbitration hearing in connection with this matter on August 14 and 15, 2012, and on October 30, 2012, the arbitrators ruled that no reimbursements were due from HQ under the contract.

F-26

GAS NATURAL INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In the Company’s opinion, the outcome of these legal actions will not have a material adverse effect on the financial condition, cash flows or results of operations of the Company.

Note 12 – Financial Instruments and Risk Management

Management of Risks Related to Fixed Contracts

The Company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee comprised of Company officers and management to oversee the risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counterparty credit risks, and other risks related to the energy commodity business.

In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas, from time to time the Company and its subsidiaries have entered into fixed contracts. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.

The Company accounts for these contracts in accordance with ASC 815, Derivatives and Hedging. In accordance with ASC 815, such contracts are reflected in the balance sheet as assets or liabilities and valued at “fair value,” determined as of the balance sheet date. Fair value accounting treatment is also referred to as “mark-to-market” accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow. The changes in the derivative values are reported in the income statement as an increase or (decrease) in revenues without regard to whether any cash payments have been made between the parties to the contract. ASC 815 specifies that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a “normal purchase or normal sale.”

At September 30, 2012 and December 31, 2011, all of the Company’s fixed contracts for purchase or sale at fixed prices and volumes qualified for treatment as a “normal purchase or normal sale.”

Note 13 – Subsequent Events

The Company declared a dividend of $0.045 per share on September 26, 2012 that is payable to shareholders of record as of October 13, 2012. There were 8,368,627 shares outstanding on October 13, 2012 resulting in a total dividend of $376,588 which was paid to shareholders on October 31, 2012.

On October 24, 2012, the Ohio utility subsidiaries of the Company, Orwell, NEO, and Brainard, (together, the “Ohio Utilities”), issued a Senior Secured Guaranteed Note in the amount of $2.989 million (the “Note”). The Note was placed with SunLife pursuant to a third amendment to the original Note Purchase Agreement dated as of November 1, 2010, by and among the Ohio Utilities, Great Plains Natural, Lightning Pipeline, Gas Natural and SunLife. The Note will bear an interest rate of 4.15%, compounded semi-annually, and it matures on June 1, 2017.

The Note is a joint obligation of the Ohio Utilities and is guaranteed by Gas Natural’s non-regulated Ohio and North Carolina subsidiaries. The Note is subject to other customary loan covenants and default provisions. An event of default, if not cured, would require the Company to immediately pay the outstanding principal balance of the Note as well as any and all interest and other payments due. An event of default would also entitle SunLife to exercise certain rights with respect to the collateral that secures the indebtedness incurred under the Note.

F-27

ITEM 2. MANAGEMENT’S DISCUSSIONAND ANALYSISOF FINANCIAL CONDITIONAND RESULTSOF OPERATIONS

This quarterly report on Form 10-Q contains various “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act), which represent our expectations or beliefs concerning future events. Forward-looking statements generally include words such as “anticipates,” “believes,” “expects,” “planned,” “scheduled” or similar expressions and statements concerning our operating capital requirements, utilization of tax benefits, recovery of property tax payments, our environmental remediation plans, and similar statements that are not historical are forward-looking statements that involve risks and uncertainties. Although we believe these forward-looking statements are based on reasonable assumptions, statements made regarding future results are subject to a number of assumptions, uncertainties and risks that could cause future results to be materially different from the results stated or implied in this document.

Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of us from time to time, including statements contained in filings with the Securities and Exchange Commission (“SEC”) and our reports to shareholders, involve known and unknown risks and other factors that may cause our company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. See “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011 filed with the SEC. Any such forward looking statement is qualified by reference to these risk factors. We caution that these risk factors are not exclusive. We do not undertake to update any forward looking statements that may be made from time to time by or on behalf of us except as required by law.

OVERVIEW

Gas Natural is a natural gas company, primarily operating local distribution companies in seven states and serving approximately 70,000 customers. Our natural gas utility subsidiaries are Bangor Gas Company (Maine), Brainard Gas Corp. (Ohio), Cut Bank Gas Company (Montana), Energy West, Incorporated (Montana and Wyoming), Frontier Natural Gas (North Carolina), Northeast Ohio Natural Gas Corporation (Ohio), Orwell Natural Gas Company (Ohio and Pennsylvania) and Public Gas Company (Kentucky). Our operations also include production and marketing of natural gas, gas pipeline transmission and gathering and propane operations. Approximately 81% and 87% of our revenues in the three and nine months ended September 30, 2012 respectively were derived from our natural gas utility operations.

The following summarizes the critical events that impacted our results of operations during the three months ended September 30, 2012:

• Customer growth in our Maine and North Carolina markets and in our marketing and production operation caused revenues and gross margin to increase as compared to the comparable period for the prior year.

• Our propane operations returned a net loss for the current quarter.

• The 2011 period included the pre-tax gain of $1,055,000 on the bargain purchase of the assets of Independence Oil & LP Gas, Inc.

• The average balance on our Bank of America line of credit was higher during the current period, causing an increase in interest expense.

• We incurred increased costs related to completed and potential acquisitions in our corporate and other segment.

The following summarizes the critical events that impacted our results of operations during the nine months ended September 30, 2012:

• Warm weather in our weather sensitive service territories caused gross margin and net income from natural gas operations to decrease as compared to the comparable periods for the prior year.

• Our propane operations returned a net loss for the current nine month period.

• The 2011 period included the pre-tax gain of $1,055,000 on the bargain purchase of the assets of Independence Oil & LP Gas, Inc.

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• Our interest expense increased as the result of our Ohio subsidiaries refinancing their debt in May 2011. There were loans paid off in preparation of the refinancing in 2011 and therefore a lower amount of debt was outstanding. In addition, the average balance on our Bank of America line of credit was higher during the current period.

• We incurred increased costs related to completed and potential acquisitions in our corporate and other segment.

Our historical financial statements reflect the following reportable business segments: Natural Gas Operations, Marketing and Production Operations, Pipeline Operations, Propane Operations and Corporate and Other.

RESULTS OF CONSOLIDATED OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with the unaudited Condensed Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this report and our Annual Report on Form 10-K for the period ended December 31, 2011. The following gives effect to the unaudited Condensed Consolidated Financial Statements as of September 30, 2012 and for the three and nine month periods ended September 30, 2012. Results of operations for interim periods are not necessarily indicative of results to be attained for any future period.

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Net Income (Loss) — Net loss for the three months ended September 30, 2012 was $671,000, or $.08 per diluted share, compared to a net income of $130,000, or $0.02 per diluted share for the three months ended September 30, 2011, a decrease of $801,000. Net loss from our natural gas operations increased by $119,000. Net income from our gas marketing and production operations increased by $278,000. Net income from our pipeline operations increased by $52,000. Net income from our propane operations decreased by $779,000 to a loss of $217,000 in the 2012 period from net income of $562,000 in the 2011 period. The 2011 period included the pre-tax gain on the bargain purchase of the assets of Independence Oil & LP Gas, Inc. of $1,055,000. Net loss from our corporate and other segment increased by $233,000 to a loss of $298,000.

Revenues — Revenues increased by $647,000 to $12,968,000 for the three months ended September 30, 2012 compared to $12,321,000 for the same period in 2011. The increase was primarily attributable to a natural gas revenue increase of $109,000 due to increased sales volumes in our Maine and North Carolina markets, partially offset by lower natural gas prices passed through to customers in all of our service territories, an increase of $954,000 in the revenue from our marketing and production operation primarily due to sales from our newly formed liquefied natural gas (LNG) line of business, offset by a decrease in revenue from our propane operations segment of $405,000.

Gross Margin — Gross margin increased by $484,000 to $6,795,000 for the three months ended September 30, 2012 compared to $6,311,000 for the same period in 2011. Our natural gas operation’s margins increased $493,000, due primarily to customer growth in our Maine and North Carolina markets. Gross margin from our marketing and production operations decreased $21,000. Gross margin from our propane operations increased by $22,000.

Operating Expenses — Operating expenses, other than cost of sales, increased by $605,000 to $7,508,000 for the three months ended September 30, 2012 compared to $6,903,000 for the same period in 2011. Expenses related to the propane operations segment increased by $160,000 and the newly acquired PGC accounted for $105,000 of the increase. Increases in depreciation due to increased capital expenditures in the natural gas segment totaled $129,000. The remainder is primarily the result of increases in maintenance expenses, taxes other than income taxes and professional services.

Other Income (Expense), net — Other income (expense) increased by $382,000 to income of $152,000 for the three months ended September 30, 2012 compared to a loss of $230,000 for the same period in 2011. The 2011 period included $300,000 of expense related to conclusion of an arbitration case in a contract dispute.

Acquisition Expense — Acquisition expense increased by $177,000 to $209,000 for the three months ended September 30, 2012 compared to $32,000 for the same period in 2011. The increase is primarily the result of the cost related to various growth opportunities including $109,000 for potential expansion of natural gas into a new state and $48,000 related to the proposed acquisition of John D. Oil and Gas Marketing.

Stock Sale Expense — Stock sale expense increased by $19,000 to $19,000 for the three months ended September 30, 2012 compared to $0 for the same period in 2011. The increase is due to the expenses paid in connection with our CEO’s stock sale which was mainly completed during the three months ended June 30, 2012.

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Interest Expense — Interest expense increased by $85,000 to $637,000 for the three months ended September 30, 2012 compared to $552,000 for the same period in 2011. The balance on our Bank of America line of credit averaged $22,899,000 during the three months ended September 30, 2012, compared to $14,238,000 during the 2011 period, causing additional interest expense.

Gain on Bargain Purchase — The gain on bargain purchase in 2011 is the result of the pre-tax gain of $1,055,000 due to the purchase of the assets of Independence Oil & LP Gas, Inc.

Income Tax Benefit (Expense) — Income tax benefit increased by $278,000 to a benefit of $760,000 for the three months ended September 30, 2012 compared to a benefit of $482,000 for the same period in 2011. The 2012 and 2011 periods each included a tax benefit from the true-up to the prior year’s tax return of $193,000 and $326,000 for an increase in expense of $133,000. This is offset by the income tax benefit due to the increase in the pre-tax loss in 2012 compared to 2011.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Net Income — Net income for the nine months ended September 30, 2012 was $1,887,000, or $0.23 per diluted share, compared to a net income of $4,765,000, or $0.58 per diluted share for the nine months ended September 30, 2011, a decrease of $2,878,000. Net income from our natural gas operations decreased by $1,425,000 due primarily to warm weather in our weather sensitive service territories. Net income from our gas marketing and production operations increased by $228,000. Net income from our pipeline operations increased by $48,000. Our propane operations incurred a net loss of $469,000 in the 2012 period, compared to income of $562,000 in the 2011 period, a decrease of $1,031,000. The 2011 period included the pre-tax gain on the bargain purchase of the assets of Independence Oil & LP Gas, Inc. of $1,055,000. Net loss from our corporate and other segment increased by $698,000.

Revenues — Revenues decreased by $9,899,000 to $61,246,000 for the nine months ended September 30, 2012 compared to $71,145,000 for the same period in 2011. The decrease was primarily attributable to a natural gas revenue decrease of $12,556,000 due to warm weather in all of our weather sensitive service territories, offset by an increase of $600,000 in the revenue from our marketing and production operation primarily due to sales from our newly formed LNG business, and an increase in revenue from our propane operations segment of $2,066,000. Propane operations commenced August 1, 2011 and thus the 2011 period includes two months of results.

Gross Margin — Gross margin increased by $57,000 to $28,293,000 for the nine months ended September 30, 2012 compared to $28,236,000 for the same period in 2011. Our natural gas operation’s margins decreased $564,000 due to the warm weather and offset somewhat by increased margin from customer growth in our Maine and North Carolina markets. Gross margin from our propane operations increased by $643,000 as the 2011 period included only two months of results. Margin from our marketing and production operations decreased by $12,000.

Operating Expenses — Operating expenses, other than cost of sales, increased by $2,347,000 to $23,014,000 for the nine months ended September 30, 2012 compared to $20,667,000 for the same period in 2011. The propane operations segment contributed $1,158,000 of the increase as the 2011 period included only two months of results and the newly acquired PGC accounted for $212,000. Increases in depreciation due to increased capital expenditures in the natural gas segment totaled $380,000. The remainder is due to increases in maintenance expense, taxes other than income taxes, professional services and expense due to the additional estimate for uncollectible accounts.

Other Income (Expense), net — Other income (expense) increased by $399,000 to $503,000 for the nine months ended September 30, 2012 compared to $104,000 for the same period in 2011. The 2011 period included $300,000 of expense related to conclusion of an arbitration case in a contract dispute. The remaining increase is primarily due to increased service sales in our natural gas operations.

Acquisition Expense — Acquisition expense increased by $738,000 to $826,000 for the three months ended September 30, 2012 compared to $88,000 for the same period in 2011. The increase is primarily the result of the cost related to various growth opportunities including $337,000 for potential expansion of natural gas into a new states and $306,000 related to the proposed acquisition of John D. Oil and Gas Marketing.

Stock Sale Expense — Stock sale expense increased by $228,000 to $274,000 for the three months ended September 30, 2012 compared to $46,000 for the same period in 2011. The increase is due to the expenses paid in connection with our CEO’s stock sale which was mainly completed during the three months ended June 30, 2012.

Interest Expense — Interest expense increased by $469,000 to $1,927,000 for the nine months ended September 30, 2012 compared to $1,458,000 for the same period in 2011. The increase is primarily the result of our Ohio subsidiaries refinancing their

5

debt in May 2011. There were loans paid off in preparation of the refinancing and therefore a lower amount of average debt was outstanding during the nine months ended September 30, 2011. In addition, the balance on our Bank of America line of credit averaged $19,991,000 during the nine months ended September 30, 2012, compared to $12,752,000 during the 2011 period, causing additional interest expense.

Gain on Bargain Purchase — The gain on bargain purchase in 2011 is the result of the pre-tax gain of $1,055,000 due to the purchase of Independence Oil & LP Gas, Inc.

Income Tax Expense — Income tax expense decreased by $1,427,000 to $858,000 for the nine months ended September 30, 2012 compared to $2,285,000 for the same period in 2011. The decrease is primarily due to the reduction in pre-tax income. In addition, the 2012 and 2011 periods each included a tax benefit from the true-up to the prior year’s tax return of $193,000 and $326,000, respectively, causing an offsetting increase in expense of $133,000.

Net Income (Loss) by Segment and Service Area

The components of net income (loss) for the three and nine months ended September 30, 2012 and 2011 are:

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in thousands)	2012			2011			2012			2011
Natural Gas Operations
Energy West Montana (MT)	$	345		$	(79	)	$	1,003		$	1,067
Energy West Wyoming (WY)		(70	)		(79	)		90			234
Frontier Natural Gas (NC)		167			306			1,039			1,231
Bangor Gas (ME)		329			(153	)		1,439			989
Ohio Companies (OH)		(1,313	)		(458	)		(768	)		634
Public Gas Company (KY)		(40	)		—			(73	)		—
Total Natural Gas Operations	$	(582	)	$	(463	)	$	2,730		$	4,155
Marketing & Production Operations		327			49			386			158
Pipeline Operations		99			47			161			112
Propane Operations		(217	)		562			(469	)		562
		(373	)		195			2,808			4,987
Corporate & Other		(298	)		(65	)		(921	)		(222	)
Consolidated Net Income (Loss)	$	(671	)	$	130		$	1,887		$	4,765

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The following highlights our results by operating segments:

NATURAL GAS OPERATIONS

Income Statement

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in thousands)	2012			2011			2012			2011
Natural Gas Operations
Operating revenues	$	10,458		$	10,349		$	53,108		$	65,664
Gas Purchased		4,164			4,548			26,849			38,841
Gross Margin		6,294			5,801			26,259			26,823
Operating expenses		6,732			6,335			20,452			19,569
Operating income (loss)		(438	)		(534	)		5,807			7,254
Other income (loss)		183			(230	)		591			97
Income (loss) before interest and taxes		(255	)		(764	)		6,398			7,351
Interest expense		(601	)		(526	)		(1,831	)		(1,379	)
Income (loss) before income taxes		(856	)		(1,290	)		4,567			5,972
Income tax benefit (expense)		274			827			(1,837	)		(1,817	)
Net Income (Loss)	$	(582	)	$	(463	)	$	2,730		$	4,155

Operating Revenues

	Three Months Ended September 30,				Nine Months Ended September 30,
($ in thousands)	2012		2011		2012		2011
Full Service Distribution Revenues
Residential	$	3,491	$	3,487	$	22,025	$	29,300
Commercial		4,493		4,602		22,461		27,913
Industrial		222		231		620		718
Other		9		43		79		122
Total full service distribution		8,215		8,363		45,185		58,053
Transportation		1,955		1,698		7,060		6,748
Bucksport		288		288		863		863
Total operating revenues	$	10,458	$	10,349	$	53,108	$	65,664

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Utility Throughput

	Three Months Ended September 30,				Nine Months Ended September 30,
(in million cubic feet (MMcf))	2012		2011		2012		2011
Full Service Distribution
Residential		316		281		2,696		3,184
Commercial		548		555		2,924		3,384
Industrial		50		37		134		121
Total full service		914		873		5,754		6,689
Transportation		2,107		1,884		7,441		6,452
Bucksport		3,598		3,604		10,512		10,393
Total Volumes		6,619		6,361		23,707		23,534

Heating Degree Days

A heating degree day is a measure designed to reflect the demand for energy needed for heating, based on the extent to which the daily average temperature falls below a reference temperature which no heating is required, usually 65 degrees Fahrenheit.

			Three Months Ended September 30,				Percent (Warmer) Colder 2012 Compared to
	Normal		2012		2011		Normal			2011
Great Falls, MT		366		177		176		(51.64	%)		0.57	%
Cody, WY		257		100		112		(61.09	%)		(10.71	%)
Bangor, ME		239		231		134		(3.35	%)		72.39	%
Elkin, NC		30		72		60		140.00	%		20.00	%
Youngstown, OH		183		190		121		3.83	%		57.02	%
			Nine Months Ended September 30,				Percent (Warmer) Colder 2012 Compared to
	Normal		2012		2011		Normal			2011
Great Falls, MT		4,758		4,181		5,336		(12.13	%)		(21.65	%)
Cody, WY		4,359		3,743		4,797		(14.13	%)		(21.97	%)
Bangor, ME		5,046		4,456		4,994		(11.69	%)		(10.77	%)
Elkin, NC		2,484		2,049		2,474		(17.51	%)		(17.18	%)
Youngstown, OH		4,126		3,272		4,140		(20.70	%)		(20.97	%)

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Revenues and Gross Margin

Revenues increased by $109,000 to $10,458,000 for the three months ended September 30, 2012 compared to $10,349,000 for the same period in 2011. This increase is the result of the following factors:

1) Revenue from our Montana and Wyoming markets decreased $611,000 on a volume increase of 12 MMcf in the three months ended September 30, 2012 compared to the three months ended September 30, 2011, as a result of lower prices for natural gas passed through to customers.

2) Revenue from our Maine and North Carolina markets increased by $516,000 on a volume increase from full service and transportation customers of 278 MMcf in the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

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3) Revenues from our Ohio market increased $120,000. Revenue to full service customers increased $71,000 on a volume increase of 32 MMcf in the three months ended September 30, 2012 compared to the three months ended September 30, 2011.

4) The recently acquired PGC accounted for $84,000 of additional revenue.

Gas purchased decreased by $384,000 to $4,164,000 for the three months ended September 30, 2012 compared to $4,548,000 for the same period in 2011. The decrease is due primarily to the decrease in the price of natural gas in the 2012 period compared to the 2011 period. Our gas costs are passed on dollar for dollar to our customers under tariffs regulated by the various commissions in the jurisdictions in which we operate. Our gas costs are subject to periodic audits and prudency reviews in all of these jurisdictions. The recent audit of Brainard in Ohio resulted in an increase in gas costs of $104,000, which is included in the results for the three months ended September 30, 2012.

Gross margin increased by $493,000 to $6,294,000 for the three months ended September 30, 2012 compared to $5,801,000 for the same period in 2011. Customer growth in our Maine and North Carolina markets is the primary driver of the increase in gross margin, resulting in a $561,000 increase in gross margin. Montana and Wyoming increased by $112,000, and PGC returned margin of $41,000. These are offset by a decrease in gross margin in our Ohio market of $221,000, due primarily to the increase in gas costs for Brainard, discussed above.

Earnings

The Natural Gas Operations segment’s loss for the three months ended September 30, 2012 was $582,000, or $0.071 per diluted share, compared to earnings of $463,000, or $0.057 per diluted share for the three months ended September 30, 2011.

Operating expenses increased by $397,000 to $6,732,000 for the three months ended September 30, 2012 compared to $6,335,000 for the same period in 2011. Depreciation increased by $129,000 due to increased capital expenditures and operating expenses from the newly acquired PGC accounted for $105,000 of additional expenses. The remainder is due to increases in maintenance expenses, taxes other than income taxes, and professional services.

Other income increased by $413,000 to $183,000 for the three months ended September 30, 2012 compared to a loss of $230,000 for the same period in 2011. The 2011 period included $300,000 of expense related to conclusion of an arbitration case in a contract dispute.

Interest expense increased by $75,000 to $601,000 for the three months ended September 30, 2012 compared to $526,000 for the same period in 2011. The balance on our Bank of America line of credit averaged $22,899,000 during the three months ended September 30, 2012, compared to $14,238,000 during the 2011 period, causing additional interest expense.

Income tax benefit decreased by $553,000 to $274,000 for the three months ended September 30, 2012 compared to $827,000 for the same period in 2011. The 2012 period included expense of $87,000 related to the true-up of the prior year’s tax return, while the 2011 period included a tax benefit of $333,000, for a difference of $420,000. The remaining difference is due to the decrease in the pre-tax loss in 2012 compared to 2011.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Revenues and Gross Margin

Revenues decreased by $12,556,000 to $53,108,000 for the nine months ended September 30, 2012 compared to $65,664,000 for the same period in 2011. This decrease is the result of the following factors:

1) Revenue from our Montana and Wyoming markets decreased $6,979,000 on a volume decrease of 612 MMcf in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

2) Revenues from our Ohio market decreased $6,539,000. Revenue to full service customers decreased $6,598,000 on a volume decrease of 451 MMcf in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

3) Revenue from our Maine and North Carolina markets increased by $777,000 on a volume increase from full service and transportation customers of 513 MMcf in the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

4) The recently acquired PGC accounted for $185,000 of additional revenue.

9

Gas purchased decreased by $11,992,000 to $26,849,000 for the nine months ended September 30, 2012 compared to $38,841,000 for the same period in 2011. The decrease is due primarily to the decrease in sales volumes. Our gas costs are passed on dollar for dollar to our customers under tariffs regulated by the various commissions in the jurisdictions in which we operate. Our gas costs are subject to periodic audits and prudency reviews in all of these jurisdictions.

Gross margin decreased by $564,000 to $26,259,000 for the nine months ended September 30, 2012 compared to $26,823,000 for the same period in 2011. Warmer weather in 2012, both compared to normal and compared to 2011, is the primary driver of the decrease in gross margin. The decrease is offset somewhat by increased gross margin due to customer growth in our Maine and North Carolina markets. Our Ohio market accounted for $1,254,000 of the decrease, and Montana and Wyoming for $744,000, offset by an increase in Maine and North Carolina of $1,342,000 and the gross margin from PGC of $92,000.

Earnings

The Natural Gas Operations segment’s income for the nine months ended September 30, 2012 was $2,730,000, or $0.334 per diluted share, compared to $4,155,000, or $0.509 per diluted share for the nine months ended September 30, 2011.

Operating expenses increased by $883,000 to $20,452,000 for the nine months ended September 30, 2012 compared to $19,569,000 for the same period in 2011. Depreciation increased by $380,000 due to increased capital expenditures and operating expenses from the newly acquired PGC accounted for $212,000 of additional expenses. The remainder is due primarily to increases in maintenance expenses, taxes other than income taxes and professional services.

Other income increased by $494,000 to $591,000 for the nine months ended September 30, 2012 compared to $97,000 for the same period in 2011. The 2011 period included $300,000 of expense related to conclusion of an arbitration case in a contract dispute. The remaining increase is primarily due to increased service sales.

Interest expense increased by $452,000 to $1,831,000 for the nine months ended September 30, 2012 compared to $1,379,000 for the same period in 2011. The increase is primarily the result of our Ohio subsidiaries refinancing their debt in May 2011. There were loans paid off in preparation of the refinancing and therefore a lower amount of average debt was outstanding during the nine months ended September 30, 2011. In addition, the balance on our Bank of America line of credit averaged $19,991,000 during the nine months ended September 30, 2012, compared to $12,752,000 during the 2011 period, causing additional interest expense.

Income tax expense increased by $20,000 to $1,837,000 for the nine months ended September 30, 2012 compared to $1,817,000 for the same period in 2011. The 2012 period included expense of $87,000 related to the true-up of the prior year’s tax return, while the 2011 period included a tax benefit of $333,000, for an increase in expense of $420,000. This is offset by the income tax benefit related to the decrease in pre-tax income in 2012 compared to 2011.

MARKETING AND PRODUCTION OPERATIONS

Income Statement

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in thousands)	2012			2011			2012			2011
Marketing and Production Operations
Operating revenues	$	1,810		$	856		$	4,757		$	4,157
Gas Purchased		1,561			586			3,806			3,194
Gross Margin		249			270			951			963
Operating expenses		182			188			734			575
Operating income		67			82			217			388
Other expense		(3	)		(2	)		(6	)		(85	)
Income before interest and taxes		64			80			211			303
Interest expense		(33	)		(23	)		(80	)		(68	)
Income before income taxes		31			57			131			235
Income tax benefit (expense)		296			(8	)		255			(77	)
Net Income (Loss)	$	327		$	49		$	386		$	158

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Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Revenues and Gross Margin

Revenues increased by $954,000 to $1,810,000 for the three months ended September 30, 2012 compared to $856,000 for the same period in 2011. Revenue from our new LNG business accounted for $722,000 of the increase, $365,000 is due to higher sales volumes in our marketing operation, offset by a $133,000 decrease in production revenues due to lower prices received for volumes produced. Our LNG business procures and delivers liquefied natural gas to customers who are not located near a natural gas pipeline.

Gross margin decreased by $21,000 to $249,000 for the three months ended September 30, 2012 compared to $270,000 for the same period in 2011. Gross margin from our production operation decreased by $124,000 due primarily to the lower prices received for volumes produced. Offsetting this is the gross margin received from our new LNG business of $89,000, and an increase in gross margin from our gas marketing operation of $14,000.

Earnings

The Marketing and Production segment’s income for the three months ended September 30, 2012 was $327,000, or $0.04 per diluted share, compared to earnings of $49,000, or $0.006 per diluted share for the three months ended September 30, 2011.

Operating expenses decreased by $6,000 to $182,000 for the three months ended September 30, 2012 compared to $188,000 for the same period in 2011.

Income tax expense decreased by $304,000 to a benefit of $296,000 for the three months ended September 30, 2012 compared to an expense of $8,000 for the same period in 2011. The 2012 and 2011 periods each included a tax benefit from the true-up to the prior year’s tax return of $306,000 and $9,000 respectively, accounting for the decrease in expense.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Revenues and Gross Margin

Revenues increased by $600,000 to $4,757,000 for the nine months ended September 30, 2012 compared to $4,157,000 for the same period in 2011. Revenue from our new LNG business accounted for $722,000 of the increase, $165,000 is due to higher sales volumes in our marketing operation with an offset due to lower sales prices received, offset by a $287,000 decrease in production revenues due to lower prices received for volumes produced.

Gross margin decreased by $12,000 to $951,000 for the nine months ended September 30, 2012 compared to $963,000 for the same period in 2011. Gross margin from our production operation decreased by $282,000 due to the lower prices received for volumes produced. Offsetting this is the gross margin received from our new LNG business of $89,000, and an increase in gross margin from our gas marketing operation of $181,000.

Earnings

The Marketing and Production segment’s earnings for the nine months ended September 30, 2012 were $386,000, or $0.047 per diluted share, compared to earnings of $158,000, or $0.019 per diluted share for the nine months ended September 30, 2011.

Operating expenses increased by $159,000 to $734,000 for the nine months ended September 30, 2012 compared to $575,000 for the same period in 2011. The increase is primarily due to the additional estimate for uncollectible accounts.

Other expense decreased by $79,000 to $6,000 for the nine months ended September 30, 2012 compared to $85,000 for the same period in 2011. The decrease is primarily due to the reduction in the loss from unconsolidated affiliate of $77,000.

Income tax expense decreased by $332,000 to a benefit of $255,000 for the nine months ended September 30, 2012 compared to an expense of $77,000 for the same period in 2011. The 2012 and 2011 periods each included a tax benefit from the true-up to the prior year’s tax return of $306,000 and $9,000 respectively, accounting for $297,000 of the decrease. The remaining difference is due to the decrease in pre-tax income in 2012 compared to 2011.

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PIPELINE OPERATIONS

Income Statement

	Three Months Ended September 30,					Nine Months Ended September 30,
($ in thousands)	2012		2011			2012			2011
Pipeline Operations
Operating revenues	$	95	$	106		$	305		$	315
Gas Purchased		—		—			—			—
Gross Margin		95		106			305			315
Operating expenses		39		30			140			126
Operating income		56		76			165			189
Other expense		—		—			—			—
Income before interest and taxes		56		76			165			189
Interest expense		—		(2	)		(6	)		(9	)
Income before income taxes		56		74			159			180
Income tax benefit (expense)		43		(27	)		1			(68	)
Net Income	$	99	$	47		$	160		$	112

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Net income increased by $52,000 to $99,000 for the three months ended September 30, 2012 compared to $47,000 for the same period in 2011. The overall impact of the results of our pipeline operations was not material to our results of consolidated operations.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Net income increased by $48,000 to $160,000 for the nine months ended September 30, 2012 compared to $112,000 for the same period in 2011. The overall impact of the results of our pipeline operations was not material to our results of consolidated operations.

PROPANE OPERATIONS

Income Statement

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in thousands)	2012			2011			2012			2011
Propane Operations
Operating revenues	$	605		$	1,010		$	3,076		$	1,010
Gas Purchased		448			875			2,298			875
Gross Margin		157			135			778			135
Operating expenses		450			290			1,448			290
Operating loss		(293	)		(155	)		(670	)		(155	)
Other income		35			1,056			13			1,056
Income (loss) before interest and taxes		(258	)		901			(657	)		901
Interest expense		(4	)		—			(10	)		—
Income (loss) before income taxes		(262	)		901			(667	)		901
Income tax benefit (expense)		45			(339	)		198			(339	)
Net Income (Loss)	$	(217	)	$	562		$	(469	)	$	562

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Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Revenues and Gross Margin

Revenues decreased by $405,000 to $605,000 for the three months ended September 30, 2012 compared to $1,010,000 for the same period in 2011. The decrease is the result of lower sales of diesel fuel in the 2012 period due to the loss of a large customer. The 2011 period included only two months of operations as the acquisition of the assets of Independence Oil & LP Gas, Inc. took place on August 1, 2011.

Gross margin increased by $22,000 to $157,000 for the three months ended September 30, 2012 compared to $135,000 for the same period in 2011. As explained above, the 2011 period included only two months of operations.

Earnings

The Propane Operations segment’s loss for the three months ended September 30, 2012 was $217,000, or $0.027 per diluted share, compared to earnings of $562,000, or $0.07 per diluted share for the three months ended September 30, 2011.

Operating expenses increased by $160,000 to $450,000 for the three months ended September 30, 2012 compared to $290,000 for the same period in 2011. The 2011 period included only two months of operations.

Other income decreased by $1,021,000 to $35,000 for the three months ended September 30, 2012 compared to $1,056,000 for the same period in 2011. The 2011 period included the pre-tax gain on the bargain purchase of the assets of Independence Oil & LP Gas, Inc. of $1,055,000.

Income tax expense decreased by $384,000 to a benefit of $45,000 for the three months ended September 30, 2012 compared to an expense of $339,000 for the same period in 2011. The decrease is primarily due to the pre-tax loss in the 2012 period, compared to pre-tax income in the 2011 period.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Revenues and Gross Margin

Revenues increased by $2,066,000 to $3,076,000 for the nine months ended September 30, 2012 compared to $1,010,000 for the same period in 2011. The 2011 period included only two months of operations as the acquisition of the assets of Independence Oil & LP Gas, Inc. took place on August 1, 2011.

Gross margin increased by $643,000 to $778,000 for the nine months ended September 30, 2012 compared to $135,000 for the same period in 2011. As explained above, the 2011 period included only two months of operations.

Earnings

The Propane Operations segment’s loss for the nine months ended September 30, 2012 was $469,000, or $0.057 per diluted share, compared to earnings of $562,000, or $0.07 per diluted share for the nine months ended September 30, 2011.

Operating expenses increased by $1,158,000 to $1,448,000 for the nine months ended September 30, 2012 compared to $290,000 for the same period in 2011, as the 2011 period included only two months of operations.

Other income decreased by $1,043,000 to $13,000 for the nine months ended September 30, 2012 compared to $1,056,000 for the same period in 2011. The 2011 period included the pre-tax gain on the bargain purchase of the assets of Independence Oil & LP Gas, Inc. of $1,055,000.

Income tax expense decreased by $537,000 to a benefit of $198,000 for the nine months ended September 30, 2012 compared to an expense of $339,000 for the same period in 2011. The decrease is primarily due to the pre-tax loss in the 2012 period, compared to pre-tax income in the 2011 period.

CORPORATE AND OTHER OPERATIONS

Our Corporate and Other reporting segment is intended primarily to encompass the results of corporate acquisitions and other equity transactions, as well as certain other income and expense items associated with Gas Natural’s holding company functions. Therefore, it does not have standard revenues, gas purchase costs, or gross margin.

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Income Statement

	Three Months Ended September 30,						Nine Months Ended September 30,
($ in thousands)	2012			2011			2012			2011
Corporate and Other Operations
Operating revenues	$	—		$	—		$	—		$	—
Gas Purchased		—			—			—			—
Gross Margin		—			—			—			—
Operating expenses		106			61			240			109
Operating loss		(106	)		(61	)		(240	)		(109	)
Other expense		(295	)		(33	)		(1,204	)		(128	)
Loss before interest and taxes		(401	)		(94	)		(1,444	)		(237	)
Interest expense		—			(1	)		—			(1	)
Loss before income taxes		(401	)		(95	)		(1,444	)		(238	)
Income tax benefit		103			30			524			16
Net Loss	$	(298	)	$	(65	)	$	(920	)	$	(222	)

Three Months Ended September 30, 2012 Compared with Three Months Ended September 30, 2011

Results of corporate and other operations for the three months ended September 30, 2012 include acquisition activities of $210,000, costs related to expenses for our CEO’s stock sale of $19,000, corporate expenses of $69,000, administrative costs of $106,000, offset by an income tax benefit of $103,000 and interest income of $3,000, for a net loss of $298,000.

Results of corporate and other operations for the three months ended September 30, 2011 include administrative costs of $61,000, costs related to acquisition activities of $32,000, corporate expenses of $3,000, interest expense of $1,000, offset by interest income of $2,000 and income tax benefit of $30,000, for a net loss of $65,000.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011

Results of corporate and other operations for the nine months ended September 30, 2012 include administrative costs of $240,000, costs related to expenses for our CEO’s stock sale of $274,000, acquisition activities of $827,000, corporate expenses of $112,000, offset by interest income of $9,000, and income tax benefit of $524,000 and for a net loss of $920,000.

Results of corporate and other operations for the nine months ended September 30, 2011 include administrative costs of $109,000, costs related to expenses for our CEO’s stock sale of $46,000, costs related to acquisition activities of $87,000, corporate expenses of $3,000, interest expense of $1,000, offset by interest income of $8,000 and income tax benefit of $16,000, for a net loss of $222,000.

Sources and Uses of Cash

Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciations, depletion, amortization, deferred income taxes, and changes in working capital.

Our ability to maintain liquidity depends upon our credit facilities with Bank of America and Yadkin Valley Bank, shown as lines of credit on the accompanying balance sheets. Our use of the revolving lines of credit was $18.4 million and $23.2 million at September 30, 2012 and December 31, 2011, respectively.

We made capital expenditures for continuing operations of $13.1 million and $15.0 million for the nine months ended September 30, 2012 and 2011, respectively, including $3.3 million related to the Spelman acquisition in April 2011. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the revolving lines of credit.

We were the successful bidder at a public foreclosure auction for the Loring Pipeline lease and related property with a bid of $4,500,000. The transaction closed on September 25, 2012 and we funded the purchase price with the transfer to the seller of $2,250,000 of cash placed into escrow earlier in 2012, prior to the auction, and by issuing 210,951 shares of the Company’s common

14

stock to the seller. Due to the timing of the closing of the transaction, we have been unable to gather the necessary information to determine the appropriate accounting treatment for this transaction. Therefore, the cash portion of the transaction is recorded in the cash flows from investing activities section on a separate line and the stock issuance portion is recorded in the supplemental schedule of noncash investing and financing activities of the accompanying condensed consolidated statement of cash flows for the nine months ended September 30, 2012.

We periodically repay our short-term borrowings under the revolving lines of credit by using the net proceeds from the sale of long-term debt and equity securities. Long-term debt was $41.3 and $31.4 million at September 30, 2012 and December 31, 2011, respectively, including the amount due within one year.

Cash, excluding restricted cash, decreased to $1.5 million at September 30, 2012, compared to $10.5 million at December 31, 2011.

	Nine Months Ended September 30,
	2012			2011
Cash provided by operating activities	$	7,403,000		$	12,546,000
Cash used in investing activities		(16,533,000	)		(18,255,000	)
Cash provided by financing activities		117,000			3,172,000
Decrease in cash	$	(9,013,000	)	$	(2,537,000	)

OPERATING CASH FLOW

For the nine months ended September 30, 2012, cash provided by operating activities decreased by $5.1 million as compared to the nine months ended September 30, 2011. Major items affecting operating cash included a $2.9 million decrease in net income, a $2.8 million decrease in cash paid for inventory, a $2.1 million decrease in deferred tax expense, a $1.9 million decrease in collections of recoverable costs of gas, a $1.8 million decrease in accounts receivable receipts, a $1.6 million decrease in unbilled revenue, a $1.4 million decrease in purchases of other assets, and an increase in prepayments of $1.2 million.

INVESTING CASH FLOW

For the nine months ended September 30, 2012, cash used in investing activities decreased by $1.7 million as compared to the nine months ended September 30, 2011. The decrease is primarily attributable to an increase of $2.6 million in cash paid for acquisitions , a $1.9 million decrease in cash paid for capital expenditures, a $1.8 million reduction in the use of restricted cash, and a $300,000 reduction of cash invested in our unconsolidated affiliate.

Capital Expenditures

Our capital expenditures for continuing operations totaled $13.1 million and $15.0 million for the nine months ended September 30, 2012 and 2011, respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the Bank of America and Yadkin Valley Bank revolving lines of credit.

The majority of our capital spending is focused on the growth of our Natural Gas Operations segment. We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. We are actively expanding our systems in North Carolina and Maine to meet the high customer interest in natural gas service in those two service areas.

Expenditures for the purchase of the Loring pipeline lease and related property are not included in the capital expenditure totals above or in the table below and are included in the other asset line item of the accompanying September 30, 2012 condensed consolidated balance sheet.

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Estimated Capital Expenditures

The table below details our capital expenditures for the nine months ended September 30, 2012 and 2011 and provides an estimate of future cash requirements for capital expenditures:

	Nine Months Ended September 30,				Remaining Cash Requirements through
($ in thousands)	2012		2011		December 31, 2012
Natural Gas Operations	$	10,390	$	14,961	$	2,408
Marketing and Production Operations		1,763		—		837
Pipeline Operations		23		—		46
Propane Operations		84		—		866
Corporate and Other Operations		822		7		649
Total Capital Expenditures	$	13,082	$	14,968	$	4,806

We expect to fund our future cash requirements for capital expenditures through December 31, 2012 from cash provided by operating activities.

FINANCING CASH FLOW

For the nine months ended September 30, 2012, cash provided by financing activities decreased by $3.1 million as compared with the nine months ended September 30, 2011. The primary change is due to $4.1 million in additional net payments on our lines of credit, offset by a $1.4 million increase in net long-term borrowings and a $600,000 increase in payments for debt issuance costs.

We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures, we have used our working capital line of credit. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months. Our ability to maintain liquidity depends upon our credit facilities with Bank of America and Yadkin Valley Bank, shown as lines of credit on the accompanying balance sheets. Our use of the revolving lines of credit was $18.4 million and $23.2 million at September 30, 2012 and December 31, 2011, respectively. We periodically repay our short-term borrowings under the revolving lines of credit by using the net proceeds from the sale of long-term debt and equity securities. Long-term debt was $41.3 and $31.4 million at September 30, 2012, and December 31, 2011, respectively, including the amount due within one year.

Citizens Bank

In connection with the acquisition of the Ohio subsidiaries, NEO and Great Plains each entered modifications/amendments to its credit facility with Citizens Bank (the “Citizens Credit Facility”). The Citizens Credit Facility consisted of a revolving line of credit and term loan to NEO, and two other term loans to Great Plains respectively. Each amendment/modification was initially effective as of December 1, 2009, but was later modified to be effective as of January 5, 2010. Gas Natural guaranteed each loan. Mr. Osborne guaranteed each loan both individually and as trustee of the Osborne Trust, and Great Plains guaranteed NEO’s revolving line of credit and term loans.

The Ohio subsidiaries had term loans with Citizens Bank in the aggregate amount of $11.3 million. Each term note had a maturity date of July 1, 2013 and bore interest at an annual rate of 30-day LIBOR plus 400 basis points with an interest rate floor of 5.00% per annum. For the three and nine months ended September 30, 2011, the weighted average interest rate on the term loans was 5.00%, resulting in $0 and $156,022 of interest expense, respectively. The term loans were paid off on May 3, 2011.

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The following discussion describes our credit facilities as of September 30, 2012.

SunLife Assurance Company of Canada

On May 2, 2011, Gas Natural and our Ohio subsidiaries, NEO, Orwell and Brainard (together the issuers), issued $15.3 million of 5.38% Senior Secured Guaranteed Fixed Rate Notes due June 1, 2017 (the fixed rate note). Additionally, Great Plains issued $3.0 million of Senior Secured Guaranteed Floating Rate Notes due May 3, 2014 (the floating rate note). Both notes were placed with SunLife. Approximately $615,000 was incurred related to the debt issuance which was capitalized and is being amortized over the life of the notes.

The fixed rate note, in the amount of $15.3 million, is a joint obligation of the issuers, and is guaranteed by Gas Natural, Lightning Pipeline and Great Plains (together with the issuers, the fixed rate obligors). The note is governed by a Note Purchase Agreement (the NPA). Concurrent with the funding and closing of this transaction, which occurred on May 3, 2011, the fixed rate obligors signed an amended NPA that is substantially the same as the NPA released on November 2, 2010. Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium.

The floating rate note, in the amount of $3.0 million, is an obligation of Great Plains and is guaranteed by Gas Natural (together, the floating rate obligors). The note is priced at a fixed spread of 385 basis points over three month LIBOR. Pricing for this note will reset on a quarterly basis to the then current yield of three month LIBOR. The note is governed by a NPA. Concurrent with the funding of this transaction, which occurred on May 3, 2011, the floating rate obligors signed an amended NPA that is substantially the same as the NPA released on November 2, 2010. Prepayment of this note prior to maturity is at par.

The use of proceeds for both notes extinguished existing amortizing bank debt and other existing indebtedness, funded $3.4 million for the 2011 capital program for Orwell and NEO, established two debt service reserve accounts, and replenished our treasuries for prior repayment of maturing bank debt and transaction expenses. The capital program funds and debt service reserve accounts are in interest bearing accounts and included in restricted cash. Payments for both notes prior to maturity are interest-only.

For the three and nine months ended September 30, 2012, the weighted average interest rate on the fixed rate note was 5.38%, resulting in $206,242 and $618,727 of interest expense, respectively. For the three and nine months ended September 30, 2011, the weighted average interest rate on the fixed rate note was 5.38%, resulting in $206,242 and $343,737 of interest expense, respectively.

For the three and nine months ended September 30, 2012, the weighted average interest rate on the floating rate note was 4.31% and 4.39% resulting in $32,300 and $97,650 of interest expense, respectively. For the three and nine months ended September 30, 2011, the weighted average interest rate on the floating rate note was 4.11% resulting in $51,450 of interest expense.

On October 24, 2012, Orwell, NEO, and Brainard issued a Senior Secured Guaranteed Note in the amount of $2.989 million. The note was placed with SunLife pursuant to a third amendment to the NPA. The note bears interest at a rate of 4.15%, compounded semi-annually, and matures on June 1, 2017. The note is a joint obligation of Orwell, NEO and Brainard and is guaranteed by our non-regulated Ohio and North Carolina subsidiaries.

For the year ended December 31, 2011, we breached a financial covenant under the fixed rate note and floating rate note when the obligors made restricted payments in the form of dividends to the holding company in excess of the amounts permissible. In addition, we did not timely notify SunLife of certain newly-formed subsidiaries which were required to be obligors under the fixed rate note and floating rate note. The failure to timely notify SunLife constituted a breach of the fixed rate note and floating rate note. We requested that SunLife waive these breaches and amend the financial covenants. SunLife required debt service reserve accounts to be created for $950,000 to cover approximately one year of interest payments. We are not able to use these funds in the debt service reserve accounts for operational cash purposes.

On April 9, 2012, we entered into a waiver and amendment of the fixed rate note and floating rate note. Pursuant to the amendments, SunLife waived its rights and remedies of the breaches of the covenants described above.

The amendments to the notes also provide that any cash dividends, distributions, redemptions or repurchases of common stock may be made by the obligors to the holding company only if (i) the aggregate amount of all such dividends, distributions, redemptions and repurchases for the fiscal year do not exceed 70% of net income of the obligors for the four fiscal quarters then ending determined as of the end of each fiscal quarter for the four fiscal quarters then ending, and (ii) there exists no other event of default at the time the dividend, distribution, redemption or repurchase is made. Currently, we do not expect the obligors to be able to pay a dividend to holding company until the first quarter of 2013. The inability of the obligors to pay a dividend to the holding company may impact our ability to pay a dividend to shareholders. In addition, we agreed to deliver an irrevocable standby letter of credit to SunLife in the amount of $750,000 to be drawn upon by SunLife if and when any event of default has occurred and is continuing. After discussion with SunLife, the parties agreed to change the letter of credit requirement to depositing cash into a reserve account whereas SunLife is the beneficiary. The terms allow us to withdraw that money if a letter of credit is received to replace the restricted cash.

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The notes require, on a consolidated basis, an interest coverage ratio of at least 2.0 to 1.0, measured quarterly on a trailing four quarter basis. The notes generally define the interest coverage ratio as the ratio of EBITDA to gross interest expense, determined in accordance with GAAP. The interest coverage ratio is measured with respect to the obligors on a consolidated basis and also with respect to Gas Natural and all of our subsidiaries, on a consolidated basis. The notes also require that we do not permit indebtedness to exceed 60% of capitalization at any time. Like the interest coverage ratio, the ratio of debt to capitalization is measured on a consolidated basis for the obligors, and again on a consolidated basis with respect to Gas Natural and all of our subsidiaries.

We are prohibited from creating, assuming or incurring additional indebtedness except for (i) obligations under certain financing agreements, (ii) indebtedness incurred under certain capitalized leases and purchase money obligations not to exceed $500,000 at any one time outstanding, (iii) indebtedness outstanding as of March 31, 2011, (iv) certain unsecured intercompany indebtedness and (v) certain other indebtedness permitted under the notes.

The notes prohibit us from selling or otherwise transferring assets except in the ordinary course of business and to the extent such sales or transfers, in the aggregate, over each rolling twelve month period, do not exceed 1% of our total assets. Generally, we may consummate a merger or consolidation if there is no event of default and the provisions of the notes are assumed by the surviving or continuing corporation. We are also generally limited in making acquisitions in excess of 10% of our total assets.

Bank of America

On September 20, 2012, the Company’s subsidiary, Energy West, entered into an Amended and Restated Credit Agreement (the “Credit Agreement”), with the Bank of America, N.A. (“Bank of America”) which modifies the original credit agreement entered into on June 29, 2007, as amended from time to time. The Credit Agreement renewed the $30.0 million revolving credit facility available to Energy West and provides for a maturity date of April 1, 2017. In addition, Energy West entered into a $10.0 million term loan with Bank of America with a maturity date of April 1, 2017 (the “Term Loan”). Pursuant to the terms of the Credit Agreement, Energy West issued a second amended and substitute note to Bank of America in the amount of $30.0 million for the revolving credit facility and another note in the original principal amount of $10.0 million for the Term Loan.

The Credit Agreement includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the Credit Agreement and interest on the amounts outstanding at the London Interbank Offered Rate (“LIBOR”) rate plus 175 to 225 basis points. The Term Loan has an interest rate of LIBOR plus 175 to 225 basis points with an interest rate swap provision that allows for the interest rate to be fixed in the future. The Term Loan will be amortized at a rate of $125,000 per quarter, with the first principal payment being due on December 31, 2012.

For the three months ended September 30, 2012 and 2011, the weighted average interest rate on the facility was 3.14% and 1.56%, respectively, resulting in $141,780 and $55,355 of interest expense, respectively. For the nine months ended September 30, 2012 and 2011, the weighted average interest rate on the facility was 3.26% and 1.67%, respectively, resulting in $373,835 and $156,602 of interest expense, respectively. The balance on the revolving credit facility was $18,020,000 and $23,160,000 at September 30, 2012 and December 31, 2011, respectively. The $18.0 million of borrowings as of September 30, 2012, leaves the remaining borrowing capacity on the line of credit at $12.0 million.

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The following tables represent borrowings under the Bank of America revolving line of credit for each of the three and nine months ended September 30, 2012 and 2011.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Minimum borrowing	$	18,020,000	$	10,140,000	$	15,100,000	$	8,390,000
Maximum borrowing	$	26,966,000	$	17,600,000	$	26,966,000	$	18,400,000
Average borrowing	$	22,899,000	$	14,238,000	$	19,991,000	$	12,752,000

The credit facility requires that Energy West and its subsidiaries maintain compliance with a number of financial covenants, including a limitation on investments in another entity by acquisition of any debt or equity securities or assets or by making loans or advances to such entity. In addition, Energy West must maintain a total debt to total capital ratio of not more than .55-to-1.00 and an interest coverage ratio of no less than 2.0-to-1.0. The credit facility restricts Energy West’s ability to create, incur or assume indebtedness except (i) indebtedness under the credit facility (ii) indebtedness incurred under certain capitalized leases and purchase money obligations not to exceed $500,000, (iii) certain indebtedness of Energy West’s subsidiaries, (iv) certain subordinated indebtedness, (v) certain hedging obligations and (vi) other indebtedness not to exceed $1.0 million.

The credit facility also restricts Energy West’s ability to pay dividends and make distributions, redemptions and repurchases of stock during any 60-month period to 80% of its net income over that period. In addition, no event of default may exist at the time such dividend, distribution, redemption or repurchase is made. Energy West is also prohibited from consummating a merger or consolidation or selling all or substantially all of its assets or stock except for (i) any merger consolidation or sale by or with certain of its subsidiaries, (ii) any such purchase or other acquisition by Energy West or certain of its subsidiaries and (iii) sales and dispositions of assets for at least fair market value so long as the net book value of all assets sold or otherwise disposed of in any fiscal year does not exceed 5% of the net book value of Energy West’s assets as of the last day of the preceding fiscal year.

Senior Unsecured Notes

On June 29, 2007, Energy West authorized the sale of $13,000,000 aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017 (the “Senior Unsecured Notes”). The proceeds of these notes were used to refinance existing notes. Approximately $463,000 was incurred related to the debt issuance which was capitalized and is being amortized over the life of the notes.

Interest expense was $200,200 and $600,600 for the three and nine months ended September 30, 2012 and $200,200 and $600,600 for the three and nine months ended September 30, 2011, respectively.

The notes contain various covenants, including a limitation on Energy West’s total dividends and distributions made in the immediately preceding 60-month period to 100% of aggregate consolidated net income for such period. The notes restrict Energy West from incurring additional senior indebtedness in excess of 60% of capitalization at any time and require Energy West to maintain an interest coverage ratio of not more than 150% of the pro forma annual interest charges on a consolidated basis in two of the three preceding fiscal years.

Energy West is prohibited from selling or otherwise disposing of any of its property or assets except (i) in the ordinary course of business, (ii) property or assets that are no longer usable in its business or (iii) property or assets transferred between Energy West and its subsidiaries if the aggregate net book value of all properties and assets so disposed of during the twelve month period next preceding the date of such sale or disposition would constitute more than 15% of the aggregate book value of all Energy West’s tangible assets. In addition, Energy West may only consummate a merger or consolidation, dissolve or otherwise dispose of all or substantially all of its assets (i) if there is no event of default, (ii) the provisions of the notes are assumed by the surviving or continuing corporation and such entity further agrees that it will continue to operate its facilities as part of a system comprising a public utility regulated by the Public Service Commission of Montana or another federal or state agency or authority and (iii) the surviving or continuing corporation has a net worth immediately subsequent to such acquisition, consolidation or merger equal to or greater than $10 million.

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Yadkin Valley Bank

On February 13, 2012, Independence entered into a one year, $500,000 revolving credit facility with Yadkin Valley Bank with an interest rate based on the prime rate, with a floor of 4.5% per annum and a maximum of 16% per annum. For the three and nine months ended September 30, 2012, the weighted average interest rate on the facility was 4.5% and 4.5%, respectively, resulting in $4,612 and $8,293 of interest expense, respectively. The balance on the facility was $401,000 at September 30, 2012. The $401,000 of borrowings as of September 30, 2012, leaves the remaining borrowing capacity on the line of credit at $99,000.

The cash flow from our business is seasonal and the line of credit balance in December normally represents the high point of borrowings in our annual cash flow cycle. Our cash flow increases and our borrowings decrease, beginning in January, as monthly heating bills are paid and the gas we paid for and placed in storage in the summer months is used to supply our customers. The total amount outstanding under all of our long term debt obligations was approximately $41.3 million at September 30, 2012, with $508,000 being due within one year.

The provisions in our debt agreements limit the amount of indebtedness we can obtain or issue, which could impact our ability to finance our operations and fund growth.

We believe we are in compliance with the financial covenants under our debt agreements or have received waivers for any defaults.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance-sheet arrangements, other than those currently disclosed that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

We are subject to certain market risks, including commodity price risk (i.e., natural gas prices). The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the Notes to our Condensed Consolidated Financial Statements for a description of our accounting policies and other information related to these financial instruments.

Commodity Price Risk

We seek to protect against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage such open positions with policies that are designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our risk management committee has limited the types of contracts we will consider to those related to physical natural gas deliveries. Therefore, management believes that although revenues and cost of sales are impacted by changes in natural gas prices, our margin is not significantly impacted by these changes.

Credit Risk

Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with us. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counter-party may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. We seek to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of September 30, 2012, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended. The evaluation was carried out under the supervision of and with the participation of our management, including our principal executive officer and principal financial officer. Based upon this evaluation, our chief executive officer and chief financial officer each concluded that our disclosure controls and procedures were effective as of September 30, 2012.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are involved in lawsuits that have arisen in the ordinary course of business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.

On June 20, 2012, the Company was named as a defendant in a lawsuit captioned RBS Citizens N.A., dba Charter One v. Richard M. Osborne, Gas Natural Inc. (f/k/a Energy, Inc.) and the Richard M. Osborne Trust, Case No. CV-12-784656, which was filed in the Cuyahoga County Court of Common Pleas in Ohio. In an effort to collect on judgments obtained against Richard M. Osborne, Chairman and Chief Executive Officer of the Company, the complaint seeks (1) an order requiring the Company to pay over to RBS Citizens any distributions due to Mr. Osborne by virtue of his ownership in Gas Natural as well as any proceeds payable to him as part of the previously announced proposed acquisition of John D. Oil and Gas Marketing , (2) the imposition of a constructive trust on dividends or assets that Mr. Osborne might receive as part of the acquisition of John D. Oil and Gas Marketing and (3) an injunction preventing the acquisition of John D. Oil and Gas Marketing. On August 29, 2012, the Company filed a motion for summary judgment. RBS Citizens filed an opposition brief on October 26, 2012 and a revised version of its brief on October 31, 2012. On October 31, 2012, the Company moved to strike RBS Citizens’ brief as untimely because it was filed approximately one month late. The Company has filed a reply brief in support of its motion for summary judgment no later than November 12, 2012. It is unclear whether the court will rule on these motions before the end of the year.

In 2010, Bangor Gas Company, the Company’s Maine utility, asserted a claim against H.Q. Energy Services (US), Inc. (“HQ”) for a breach of a firm gas transportation service agreement between the parties. HQ filed a counterclaim against the Company for reimbursement of certain transportation charges that HQ paid to a third party. The parties agreed to arbitration and on September 1, 2011, the arbitrators awarded HQ the sum of approximately $280,000 for past transportation charges that HQ paid to the Company. The arbitrators also ordered the Company to pay future transportation charges that will be incurred during the remaining term of the agreement while HQ was ordered to pay the Company for future fuel reimbursements for the remaining term of the agreement. On September 23, 2011, the arbitrators clarified their initial order to require HQ to reimburse the Company for the past transportation charges awarded by the arbitrators if the FERC determined that our payment of the transportation charges was not consistent with FERC policy. On November 10, 2011, the FERC’s Office of General Counsel issued a no-action letter indicating that the FERC staff could not assure the Company that the FERC would not recommend enforcement action if the Company made the payments to HQ required by the arbitration award. As a result, on November 30, 2011, the Company filed an action in the United States District Court, District of Maine against HQ seeking to vacate the arbitration award against the Company and confirm that portion of the award requiring HQ to return the transportation payments to the Company and obtain an award of past fuel reimbursements in addition to the prospective award made by the arbitrators. On March 1, 2012, the court issued an order confirming the arbitration award against the Company, rejecting the Company’s claim for past fuel costs, and denying the Company’s claim for reimbursement of transportation charges on the grounds that the FERC no-action letter was not a final, binding finding by the FERC of the consistency of the payments with FERC policy. On March 30, 2012, the Company filed an action with the United States Court of Appeals for the First Circuit appealing the district court’s decision in its entirety. The appeal has been briefed; oral arguments have been heard; and the parties are awaiting the Court’s decision.

Additionally, the Company also made a claim against HQ for personal property and real estate tax reimbursements which the Company claimed were due under the transportation contract with HQ. The parties participated in an arbitration hearing in connection with this matter on August 14 and 15, 2012, and on October 30, 2012, the arbitrators ruled that no reimbursements were due from HQ under the contract.

In the Company’s opinion, the outcome of these legal actions will not have a material adverse effect on the financial condition, cash flows or results of operations of the Company.

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ITEM 6. EXHIBITS

Exhibit Number	Description
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase

* Furnished herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) 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.

	Gas Natural Inc.
	/s/Thomas J. Smith
	Thomas J. Smith
November 13, 2012	Chief Financial Officer
	(principal financial officer
	and principal accounting officer)