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EX-32.2 - EXHIBIT 32.2 - DELTA NATURAL GAS CO INCdgas-20161231x10qxex322.htm
EX-32.1 - EXHIBIT 32.1 - DELTA NATURAL GAS CO INCdgas-20161231x10qxex321.htm
EX-31.2 - EXHIBIT 31.2 - DELTA NATURAL GAS CO INCdgas-20161231x10qxex312.htm
EX-31.1 - EXHIBIT 31.1 - DELTA NATURAL GAS CO INCdgas-20161231x10qxex311.htm

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC  20549
______________

FORM 10-Q

______________
(Mark one)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2016

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 No. 0-8788
______________

DELTA NATURAL GAS COMPANY, INC.
(Exact name of registrant as specified in its charter)
______________
Kentucky
61-0458329
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

3617 Lexington Road, Winchester, Kentucky
40391
(Address of principal executive offices)
(Zip code)

859-744-6171
(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or Section 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 Web site, 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 definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer     ¨
Accelerated filer     x
Non-accelerated filer   ¨ (Do not check if a smaller reporting company)
Smaller reporting company     ¨

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.

As of December 31, 2016, Delta Natural Gas Company, Inc. had 7,123,648 shares of Common Stock outstanding.
 
 




DELTA NATURAL GAS COMPANY, INC.

INDEX TO FORM 10-Q

PART I -
FINANCIAL INFORMATION
 
 
 
 
 
ITEM 1.
Financial Statements
 
 
 
 
 
 
Condensed Consolidated Statements of Income (Unaudited) for the three and six months ended December, 2016 and 2015
 
 
 
 
 
 
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended December 31, 2016 and 2015
 
 
 
 
 
 
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2016 and June 30, 2016
 
 
 
 
 
 
Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the six months ended December 31, 2016 and 2015
 
 
 
 
 
 
Notes to Condensed Consolidated Financial Statements (Unaudited)
 
 
 
 
 
ITEM 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
 
 
 
 
ITEM 3.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 
 
 
ITEM 4.
Controls and Procedures
 
 
 
 
 
PART II -
OTHER INFORMATION
 
 
 
 
 
ITEM 1.
Legal Proceedings
 
 
 
 
 
ITEM 1A.
Risk Factors
 
 
 
 
 
ITEM 2.
Unregistered Sales of Equity Securities and Use of Proceeds
 
 
 
 
 
ITEM 3.
Defaults Upon Senior Securities
 
 
 
 
 
ITEM 4.
Mine Safety Disclosures
 
 
 
 
 
ITEM 5.
Other Information
 
 
 
 
 
ITEM 6.
Exhibits
 
 
 
 
 
 
Signatures
 

2



PART I – FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS

DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
 
Three Months Ended
 
Six Months Ended
 
 
December 31,
 
December 31,
 
 
2016
 
2015
 
2016
 
2015
 
 

 

 
 
 
 
 
OPERATING REVENUES

 

 
 
 
 
 
Regulated revenues
$
12,045,394

 
$
10,873,770

 
$
17,888,475

 
$
16,707,695

 
Non-regulated revenues
6,891,449

 
5,799,577

 
11,556,565

 
10,359,075

 
Total operating revenues
$
18,936,843

 
$
16,673,347

 
$
29,445,040

 
$
27,066,770

 
 
 
 
 
 
 
 
 
 
OPERATING EXPENSES
 
 
 
 
 
 
 
 
Regulated natural gas
$
3,768,335

 
$
3,071,226

 
$
4,774,912

 
$
4,057,849

 
Non-regulated natural gas
4,963,733

 
4,389,391

 
8,709,423

 
8,044,307

 
Operation and maintenance
3,412,329

 
3,415,406

 
7,142,415

 
6,904,450

 
Depreciation and amortization
1,596,162

 
1,570,646

 
3,202,085

 
3,212,659

 
Taxes other than income taxes
662,528

 
748,199

 
1,342,843

 
1,501,575

 
Total operating expenses
$
14,403,087

 
$
13,194,868

 
$
25,171,678

 
$
23,720,840

 
 
 
 
 
 
 
 
 
 
OPERATING INCOME
$
4,533,756

 
$
3,478,479

 
$
4,273,362

 
$
3,345,930

 
 
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE)
12,280

 
44,247

 
70,319

 
(34,913
)
 
 
 
 
 
 
 
 
 
 
INTEREST CHARGES
622,677

 
639,936

 
1,247,409

 
1,281,871

 
 
 
 
 
 
 
 
 
 
NET INCOME BEFORE INCOME TAXES
$
3,923,359

 
$
2,882,790

 
$
3,096,272

 
$
2,029,146

 
 
 
 
 
 
 
 
 
 
INCOME TAX EXPENSE
1,479,756

 
1,079,439

 
1,110,653

 
750,252

 
 
 
 
 
 
 
 
 
 
NET INCOME
$
2,443,603

 
$
1,803,351

 
$
1,985,619

 
$
1,278,894

 
 
 
 
 
 
 
 
 
 
EARNINGS PER COMMON SHARE (Note 11)
 
 
 
 
 
 
 
 
Basic and Diluted
$
.34

 
$
.25

 
$
.28

 
$
.18

 
 
 
 
 
 
 
 
 
 
DIVIDENDS DECLARED PER COMMON SHARE
$
.2075

 
$
.205

 
$
.415

 
$
.41

 





The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

3



DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED) 
 
Six Months Ended
 
December 31,
 
2016
 
2015
 
 
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
1,985,619

 
$
1,278,894

Adjustments to reconcile net income to net cash from operating activities
 
 
 
Depreciation and amortization
3,317,085

 
3,330,959

Deferred income taxes and investment tax credits
1,244,073

 
762,097

Change in cash surrender value of officer's life insurance
(15,689
)
 
9,312

Share-based compensation
273,394

 
314,734

Excess tax benefit (deficiency) from share-based compensation
42,603

 
(5,508
)
Increase in assets
(9,120,847
)
 
(5,874,845
)
   Increase (decrease) in liabilities
1,008,543

 
(57,058
)
 
 
 
 
Net cash used in operating activities
$
(1,265,219
)
 
$
(241,415
)
 
 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
$
(4,130,279
)
 
$
(3,489,892
)
Proceeds from sale of property, plant and equipment
92,541

 
155,987

Other
(60,000
)
 
(60,000
)
 
 
 
 
Net cash used in investing activities
$
(4,097,738
)
 
$
(3,393,905
)
 
 
 
 
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Dividends on common shares
$
(2,954,565
)
 
$
(2,908,171
)
Issuance of common shares
334,088

 
344,865

     Payment of tax withholdings on share-based compensation
(266,005
)
 
(240,900
)
     Repayment of long-term debt
(1,500,000
)
 
(1,500,000
)
 
 
 
 
Net cash used in financing activities
$
(4,386,482
)
 
$
(4,304,206
)
 
 
 
 
NET DECREASE IN CASH AND CASH EQUIVALENTS
$
(9,749,439
)
 
$
(7,939,526
)
 
 
 
 
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD
18,606,567

 
16,924,278

 
 
 
 
CASH AND CASH EQUIVALENTS,
END OF PERIOD
$
8,857,128

 
$
8,984,752









The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

4



DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
  
 
December 31,
 
June 30,
 
2016
 
2016
ASSETS
 
 
 
 
 
 
 
CURRENT ASSETS
 
 
 
Cash and cash equivalents
$
8,857,128

 
$
18,606,567

  Accounts receivable, less accumulated allowances
 
 
 
     for doubtful accounts of $143,000 and $301,000, respectively
10,457,306

 
4,741,595

Natural gas in storage, at average cost
4,726,453

 
3,289,920

Deferred natural gas costs
2,065,988

 
674,077

Materials and supplies, at average cost
551,517

 
544,342

Prepayments
3,381,196

 
3,051,665

Total current assets
$
30,039,588

 
$
30,908,166

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT
$
245,190,342

 
$
241,833,771

Less-Accumulated provision for depreciation
(106,939,943
)
 
(104,192,898
)
Net property, plant and equipment
$
138,250,399

 
$
137,640,873

 
 
 
 
OTHER ASSETS
 
 
 
Cash surrender value of life insurance
$
430,674

 
$
414,985

Regulatory assets
19,226,014

 
18,881,126

Other non-current assets
1,133,957

 
1,033,979

Total other assets
$
20,790,645

 
$
20,330,090

 
 
 
 
Total assets
$
189,080,632

 
$
188,879,129


















The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

5



DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS (continued)
(UNAUDITED)
 
December 31,
 
June 30,
 
2016
 
2016
 
 
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
 
 
 
 
 
 
CURRENT LIABILITIES
 
 
 
Accounts payable
$
5,205,461

 
$
4,200,298

Current portion of long-term debt
1,500,000

 
1,500,000

Accrued taxes
2,193,080

 
1,584,675

Customers' deposits
735,201

 
618,137

Accrued interest on debt
108,092

 
111,825

Accrued vacation
642,445

 
756,138

Other current liabilities
640,171

 
585,342

Total current liabilities
$
11,024,450

 
$
9,356,415

 
 
 
 
LONG-TERM DEBT
$
48,925,996

 
$
50,422,796

 
 
 
 
LONG-TERM LIABILITIES
 
 
 
Deferred income taxes
$
44,681,084

 
$
43,405,098

Regulatory liabilities
1,126,567

 
1,138,141

Accrued pension
989,802

 
1,833,780

Asset retirement obligations
4,054,909

 
3,917,585

Other long-term liabilities
1,178,324

 
1,078,345

Total long-term liabilities
$
52,030,686

 
$
51,372,949

 
 
 
 
COMMITMENTS AND CONTINGENCIES (Note 8)
 
 
 
Total liabilities
$
111,981,132

 
$
111,152,160

 
 
 
 
SHAREHOLDERS' EQUITY
 
 
 
Common shares ($1.00 par value), 20,000,000 shares
 
 
 
authorized; 7,123,648 and 7,087,762 shares
 
 
 
outstanding at December 31, 2016 and June 30,
 
 
 
2016, respectively
$
7,123,648

 
$
7,087,762

Premium on common shares
49,778,133

 
49,472,542

Retained earnings
20,197,719

 
21,166,665

Total shareholders' equity
$
77,099,500

 
$
77,726,969

 
 
 
 
Total liabilities and shareholders' equity
$
189,080,632

 
$
188,879,129






The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

6



DELTA NATURAL GAS COMPANY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(UNAUDITED)
 
 
Six Months Ended December 31, 2016
 
Common Shares
 
Premium on Common Shares
 
Retained Earnings
 
Shareholders' Equity
 
 
 
 
 
 
 
 
Balance, beginning of period
$
7,087,762

 
$
49,472,542

 
$
21,166,665

 
$
77,726,969

Net income

 

 
1,985,619

 
1,985,619

Issuance of common shares
13,182

 
320,906

 

 
334,088

Issuance of common shares under the
 
 
 
 
 
 
 
     incentive compensation plan, net of cancellations
 
 
 
 
 
 
 
to satisfy tax withholding obligations
22,704

 
(288,709
)
 

 
(266,005
)
Share-based compensation expense

 
273,394

 

 
273,394

Dividends on common shares

 

 
(2,954,565
)
 
(2,954,565
)
 
 
 
 
 
 
 
 
Balance, end of period
$
7,123,648

 
$
49,778,133

 
$
20,197,719

 
$
77,099,500



 
Six Months Ended December 31, 2015
 
Common Shares
 
Premium on Common Shares
 
Retained Earnings
 
Shareholders' Equity
 
 
 
 
 
 
 
 
Balance, beginning of period
$
7,026,500

 
$
48,735,608

 
$
21,459,546

 
$
77,221,654

Net income

 

 
1,278,894

 
1,278,894

Issuance of common shares
16,670

 
328,195

 

 
344,865

Issuance of common shares under the
 
 
 
 
 
 
 
     incentive compensation plan, net of cancellations
 
 
 
 
 
 
 
to satisfy tax withholding obligations
31,210

 
(272,110
)
 

 
(240,900
)
Share-based compensation expense

 
314,734

 

 
314,734

Excess tax benefit from share-based compensation

 
(5,508
)
 

 
(5,508
)
Dividends on common shares

 

 
(2,908,171
)
 
(2,908,171
)
 
 
 
 
 
 
 
 
Balance, end of period
$
7,074,380

 
$
49,100,919

 
$
19,830,269

 
$
76,005,568












The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of these statements.

7



DELTA NATURAL GAS COMPANY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

(1)
Nature of Operations and Basis of Presentation

Delta Natural Gas Company, Inc. ("Delta" or "the Company") distributes or transports natural gas to approximately 36,000 customers.  Our distribution and transportation systems are located in central and southeastern Kentucky and we own and operate an underground storage field in southeastern Kentucky.  We transport natural gas to our industrial customers who purchase their natural gas in the open market.  We also transport natural gas on behalf of local producers and customers not on our distribution system and extract liquids from natural gas in our storage field and our pipeline systems that are sold at market prices.  We have three wholly-owned subsidiaries.  Delta Resources, Inc. ("Delta Resources") buys natural gas and resells it to industrial or other large use customers on Delta's system. Delgasco, Inc. ("Delgasco") buys natural gas and resells it to Delta Resources and to customers not on Delta's system.  Enpro, Inc. ("Enpro") owns and operates natural gas production properties and undeveloped acreage.

All subsidiaries of Delta are included in the condensed consolidated financial statements. Intercompany balances and transactions have been eliminated.  All adjustments necessary for a fair presentation of the unaudited results of operations for the three and six months ended December 31, 2016 and 2015 are included.  All such adjustments are accruals of a normal and recurring nature.

The results of operations for the period ended December 31, 2016 are not necessarily indicative of the results of operations to be expected for the full fiscal year.  Because of the seasonal nature of our sales, we generate the smallest proportion of cash from operations during the warmer months, when sales volumes decrease considerably. Most construction activity and natural gas storage injections take place during these warmer months.

The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the financial statements, and the notes thereto, included in our Annual Report on Form 10-K for the year ended June 30, 2016.


(2)    Accounting Pronouncements

Recently Issued Pronouncements

In May, 2014, the Financial Accounting Standards Board issued guidance revising the principles and standards for revenue recognition. The guidance creates a framework for recognizing revenue to improve comparability of revenue recognition practices across entities and industries focusing on when a customer obtains control of goods or services, rather than the current risks and rewards model of recognition. The core principle of the new standard is that an entity recognizes revenue when it transfers goods or services to its customers in an amount that reflects the consideration an entity expects to be entitled to for those goods or services. The new disclosure requirements include information intended to communicate the nature, amount, timing and any uncertainty of revenue and cash flows from applicable contracts, including any significant judgments. Entities will generally be required to make more estimates and use more judgment under the new standard. The guidance is effective for our quarter ending September 30, 2018.

As of December 31, 2016, we are evaluating our sources of revenue and are assessing the effect that the new guidance will have on our financial position, results of operations and cash flows. The conclusion of our assessment is contingent, in part, upon the completion of deliberations currently in progress by our industry, notably in connection with efforts to produce an accounting guide intended to be developed by the American Institute of Certified Public Accountants. In association with this undertaking, the American Institute of Certified Public Accountants formed a number of industry task forces, including a Power & Utilities Task Force.

Currently, the industry is working with the Task Force to address several items including 1) the evaluation of collectability from customers if a utility has regulatory mechanisms to help assure recovery of uncollected accounts from ratepayers; 2) the accounting for funds received from third parties to partially or fully reimburse the cost of construction of an asset and 3) the accounting for alternative revenue programs, such as performance-based ratemaking. Existing alternative revenue program guidance, though excluded by the Financial Accounting Standards Board in updating specific

8



guidance associated with revenue from contracts with customers, was continued without substantial modification. It will require separate presentation of such revenues (subject to the above-noted deliberations) in the statement of comprehensive income, effective at the same time that updated guidance associated with revenue from contracts with customers becomes effective.

Currently, a timeline for the resolution of these deliberations has not been established. Additionally, we are actively working with our peers in the rate-regulated natural gas industry to conclude on the accounting treatment for several other issues that are not expected to be addressed by the Power & Utilities Task Force. Given the uncertainty with respect to the conclusions that might arise from these deliberations, we are currently unable to determine the effect the new guidance will have on our financial position, results of operations, cash flows, business processes or the transition method we will utilize to adopt the new guidance.

In July, 2015, the Financial Accounting Standards Board issued guidance simplifying the measurement of inventory. The guidance requires inventory to be measured at the lower of cost or net realizable value. The guidance, effective for our quarter ending September 30, 2017, is not expected to have a material impact on our results of operations, financial position and cash flows.

In January, 2016, the Financial Accounting Standards Board issued guidance to improve the recognition, measurement, presentation and disclosure of financial instruments. The improvements include guidance on estimating fair value for financial instruments measured at amortized cost on the balance sheet, the classification of financial assets and liabilities on the balance sheet and reduced disclosure for the fair value of financial instruments recognized on the balance sheet at amortized cost. The guidance, effective for our quarter ending September 30, 2018, is not expected to have a material impact on our results of operations, financial position, cash flows and disclosures.

            In February, 2016, the Financial Accounting Standards Board issued guidance revising the principles and standards for recognizing leases. The guidance requires a lessee to recognize on the statement of financial position a liability for the lease payments and a right-of-use asset representing the lessee's right to use the underlying asset for the lease term. The recognition and measurement of lease expenses have not significantly changed from previous guidance. The guidance is effective for our quarter ending September 30, 2018 and we are evaluating the impact the guidance is expected to have on our results of operations, financial position and cash flows.

Recently Adopted Pronouncements

In March, 2016, the Financial Accounting Standards Board issued guidance simplifying the accounting and disclosure requirements for share-based compensation, including the income tax consequences, classification of the awards as equity or liability and classification on the statement of cash flows. The guidance is effective for our quarter ending September 30, 2017; however, we have elected early adoption.

The guidance changed the accounting for excess tax benefits and deficiencies, where previously the difference in compensation cost recognized for financial reporting purposes versus the deduction on the corporate tax return was recognized as additional paid-in capital to the extent the cumulative tax benefits exceeded tax deficiencies. Effective July 1, 2016, on a prospective basis, we recognize the effect of vested awards as discrete items in the period in which they occur with excess tax benefits and deficiencies recognized in the Condensed Consolidated Statements of Income as an adjustment to income tax expense. We do not have any previously unrecognized excess tax benefits which require a cumulative effect adjustment upon adoption. The guidance also requires the classification of excess tax benefits and deficiencies as an operating activity on the Condensed Consolidated Statements of Cash Flows, which has been adopted retrospectively and resulted in an immaterial reclassification between financing activities and operating activities on the Condensed Consolidated Statements of Cash Flows.

Entities may elect an accounting policy for forfeitures where they can either continue the current method of recognizing forfeitures based on the number of awards expected to vest or as forfeitures occur. We have elected to recognize forfeitures as they occur. The adoption of this accounting policy did not result in a cumulative effect adjustment.

The threshold increased for an award to qualify for equity classification where shares are redeemed to meet statutory withholding obligations. Shares can now be redeemed up to the maximum statutory tax rates in the applicable jurisdiction, rather than the minimum statutory tax rates. The adoption of this guidance did not result in a change in classification of the award requiring a cumulative effect adjustment.
               

9



(3)
Fair Value Measurements

Our financial assets measured at fair value on a recurring basis consist of the assets of our supplemental retirement benefit trust, which are included in other non-current assets on the Condensed Consolidated Balance Sheets. Contributions to the trust are presented in other investing activities on the Condensed Consolidated Statements of Cash Flows. The assets of the trust are recorded at fair value and consist of exchange traded securities and exchange traded mutual funds. The securities and mutual funds are recorded at fair value using observable market prices from active markets, which are categorized as Level 1 in the fair value hierarchy.  The fair value of the trust assets are as follows:
 
December 31,
 
June 30,
($000)
2016
 
2016
 
 
 
 
Trust assets
 
 
 
Money market
125

 
44

U.S. equity securities
449

 
435

Foreign equity funds
170

 
168

U.S. fixed income funds
223

 
223

Foreign fixed income funds
20

 
19

Absolute return strategy mutual funds
147

 
145

        Total trust assets
1,134

 
1,034


The carrying amounts of our other financial instruments including cash equivalents, accounts receivable, notes receivable and accounts payable approximate their fair value.

Our Series A Notes, presented as long-term debt as well as the current portion of long-term debt on the Condensed Consolidated Balance Sheets, are stated at historical cost, net of unamortized debt issuance costs. The fair value of our long-term debt is based on the expected future cash flows of the debt discounted using a credit adjusted risk-free rate.  The credit adjusted risk-free rate for our 4.26% Series A Notes is the estimated cost to borrow a debt instrument with the same terms from a private lender at the measurement date.  The fair value of our long-term debt is categorized as Level 3 in the fair value hierarchy.
 
December 31,
 
June 30,
 
2016
 
2016
 
Carrying
 
Fair
 
Carrying
 
Fair
($000)
Amount
 
Value
 
Amount
 
Value
 
 
 
 
 
 
 
 
4.26% Series A Notes
50,426

 
51,462

 
51,923

 
55,324


(4)
Risk Management and Derivative Instruments

To varying degrees, our regulated and non-regulated segments are exposed to commodity price risk.  We purchase our natural gas supply through a combination of requirements contracts with no minimum purchase obligations, monthly spot purchase contracts and forward purchase contracts.  We mitigate price risk related to the sale of natural gas by efforts to balance supply and demand. For our regulated segment, we utilize requirements contracts, spot purchase contracts and our underground storage to meet our regulated customers' natural gas requirements, all of which have minimal price risk because we are permitted to pass these natural gas costs on to our regulated customers through our natural gas cost recovery tariff.  None of our natural gas contracts are accounted for using the fair value method of accounting.  While some of our natural gas purchase contracts and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.


10



(5)
Unbilled Revenue
 
We bill our regulated sales of natural gas at tariff rates approved by the Kentucky Public Service Commission. Our customers are billed on a monthly basis; however, the billing cycle for certain classes of customers do not necessarily coincide with the calendar month-end. For these customers, we apply the unbilled method of accounting, where we estimate and accrue revenues applicable to customers but not yet billed. The related natural gas costs are charged to expense. At the end of each month, natural gas service which has been rendered from the date the customer's meter was last read to the month-end is unbilled. Unbilled revenues are included in regulated revenues and unbilled natural gas costs are included in regulated natural gas on the accompanying Condensed Consolidated Statements of Income. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. As of December 31, 2016 and June 30, 2016, unbilled natural gas costs are included in deferred natural gas costs on the accompanying Condensed Consolidated Balance Sheets. Unbilled amounts include the following:
 
December 31,
 
June 30,
(000)
2016
 
2016
 
 
 
 
Unbilled revenues ($)
5,057

 
1,452
Unbilled natural gas costs ($)
2,103

 
319
Unbilled volumes (Mcf)
480

 
63

(6)    Defined Benefit Retirement Plan

Net periodic benefit costs for our trusteed, noncontributory defined benefit retirement plan for the periods ended December 31, 2016 and 2015, include the following:
 
 
Three Months Ended
 
Six Months Ended
 
December 31,
 
December 31,
($000)
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
Service cost
255

 
251

 
510

 
502

Interest cost
263

 
289

 
526

 
578

Expected return on plan assets
(406
)
 
(409
)
 
(812
)
 
(818
)
Amortization of unrecognized net loss
237

 
94

 
474

 
188

Amortization of prior service cost
(21
)
 
(22
)
 
(42
)
 
(44
)
Net periodic benefit cost
328

 
203

 
656

 
406


In August, 2016 and October, 2016 discretionary contributions of $1,000,000 and $500,000 were made, respectively, to the defined benefit retirement plan.     

(7)
Debt Instruments

Notes Payable

The current bank line of credit with Branch Banking and Trust Company permits borrowings up to $40,000,000, all of which was available as of December 31, 2016 and June 30, 2016.  The bank line of credit extends through June 30, 2017 and we anticipate renewal of this line by June 30, 2017. The interest rate on the used bank line of credit is the London Interbank Offered Rate plus 1.075%. The annual cost of the unused bank line of credit is 0.125%.


11



Long-Term Debt

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum, which is payable quarterly, and mature on December 20, 2031.  We are required to make an annual $1,500,000 principal payment on the Series A Notes each December.  The following table summarizes the remaining contractual maturities of our Series A Notes by fiscal year:
($000)
 
2017

2018
1,500

2019
1,500

2020
1,500

2021
1,500

Thereafter
44,500

    Total long-term debt
50,500


Any additional payment of principal by the Company is subject to a prepayment premium which varies depending on the yields of United States Treasury securities with a maturity equal to the remaining average life of the Series A Notes.

With our bank line of credit and Series A Notes, we have agreed to certain financial and other covenants. Noncompliance with these covenants can make the obligations immediately due and payable. We were in compliance with the financial covenants under our bank line of credit and our 4.26% Series A Notes for all periods presented in the condensed consolidated financial statements.

(8)
Commitments and Contingencies

We have entered into an employment agreement with our Chairman of the Board, President and Chief Executive Officer and change in control agreements with our other four officers.  The agreements expire or may be terminated at various times.  The agreements provide for continuing monthly payments or lump sum payments and the continuation of specified benefits over varying periods in certain cases following defined changes in ownership of the Company.  In the event all of these agreements were exercised in the form of lump sum payments, approximately $4.7 million of wages would be paid in addition to continuation of specified benefits for up to five years. Additionally, the agreements provide for a reimbursement of excise taxes levied on such payments and a gross-up of income taxes attributable to the reimbursement. If all agreements were exercised by the officers, approximately $15.3 million would be paid, which includes wages, benefits, unvested shares awarded under our Incentive Compensation Plan and any tax gross-ups.

We are not a party to any material pending legal proceedings.

As of December 31, 2016, we have entered into forward purchase agreements for a portion of our non-regulated segment's natural gas purchases through December, 2017.  The agreements require us to purchase minimum amounts of natural gas throughout the term of the agreements.  The agreements are established in the normal course of business to ensure adequate natural gas supply to meet our non-regulated customers' natural gas requirements.  The agreements have aggregate minimum purchase obligations of $397,000 and $151,000 for our fiscal years ending June 30, 2017 and June 30, 2018, respectively.


12



(9)
Regulatory Matters

The Kentucky Public Service Commission exercises regulatory authority over our retail natural gas distribution and transportation services, which includes approval of our rates and tariffs.  Their regulation of our business includes setting the rates we are permitted to charge our regulated customers.  We monitor our need to file requests with them for a general rate increase for our natural gas distribution and transportation services.  The Kentucky Public Service Commission has historically utilized cost-of-service ratemaking where our base rates are established to recover normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. Rate base consists primarily of our regulated segment's property plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes.  Our regulated rates were most recently adjusted in our 2010 rate case and became effective in October, 2010. We do not currently have any matters before the Kentucky Public Service Commission which would have a material impact on our results of operations, financial position and cash flows.


(10)
Operating Segments

Our Company has two reportable segments:  a regulated segment and a non-regulated segment. Our regulated segment includes our natural gas distribution and transportation services, which are regulated by the Kentucky Public Service Commission. Our non-regulated segment includes our natural gas marketing activities and the sales of natural gas liquids. The non-regulated segment produces a portion of the natural gas it markets to its customers. The division of these segments into separate revenue generating components is based upon regulation, products and services. Both segments operate in the single geographic area of central and southeastern Kentucky. Our chief operating decision maker is our Chief Executive Officer. We evaluate performance based on net income of the respective segment.

The reportable segments follow the same accounting policies as described in the Summary of Significant Accounting Policies in Note 1 of the Notes to Consolidated Financial Statements that are included in our Annual Report on Form 10-K for the year ended June 30, 2016.  Intersegment revenues and expenses represent the natural gas transportation costs from the regulated segment to the non-regulated segment at our tariff rates.  Operating expenses, taxes and interest are allocated to the non-regulated segment.
 
Segment information is shown in the following table:
 
Three Months Ended
 
Six Months Ended
 
 
December 31,
 
December 31,
 
($000)
2016
 
2015
 
2016
 
2015
 
Operating Revenues
 
 
 
 
 
 
 
 
Regulated
 
 
 
 
 
 
 
 
External customers
12,046

 
10,873

 
17,888

 
16,708

 
Intersegment
919

 
918

 
1,572

 
1,590

 
Total regulated
12,965

 
11,791

 
19,460

 
18,298

 
Non-regulated

 

 
 
 
 
 
External customers
6,891

 
5,800

 
11,557

 
10,359

 
 
 
 
 
 
 
 
 
 
Eliminations for intersegment
(919
)
 
(918
)
 
(1,572
)
 
(1,590
)
 
Consolidated operating revenues
18,937

 
16,673

 
29,445

 
27,067

 
 

 

 
 
 
 
 
Net Income

 

 
 
 
 
 
Regulated
1,965

 
1,702

 
1,466

 
1,185

 
Non-regulated
479

 
101

 
520

 
94

 
Consolidated net income
2,444

 
1,803

 
1,986

 
1,279

 


13



(11)          Earnings per Common Share

The following table sets forth the computation of basic and diluted earnings per common share:
 
Three Months Ended
 
Six Months Ended
 
 
December 31,
 
December 31,
 
 
2016
 
2015
 
2016
 
2015
 
             Numerator - Basic and Diluted ($000)
 
 
 
 
 
 
 
 
              Net income
2,444

 
1,803

 
1,986

 
1,279

 
              Dividends paid
(1,478
)
 
(1,455
)
 
(2,955
)
 
(2,908
)
 
              Undistributed earnings (loss) (a)
966

 
348

 
(969
)
 
(1,629
)
 
 
 
 
 
 
 
 
 
 
Allocated to common shares:
 
 
 
 
 
 
 
 
Undistributed earnings (loss) (a)
965

 
347

 
(969
)
 
(1,629
)
 
              Dividends paid (b)
1,477

 
1,449

 
2,953

 
2,896

 
               Earnings allocated to common shares
2,442

 
1,796

 
1,984

 
1,266

 
 
 
 
 
 
 
 
 
 
             Denominator - Basic and Diluted
                   Weighted average common shares (c)
7,119,169

 
7,067,864

 
7,109,666

 
7,054,910

 
 
 
 
 
 
 
 
 
 
             Earnings per Common Share - Basic and Diluted ($)
.34

 
.25

 
.28

 
.18

 
 
 
 
 
 
 
 
 
 
        (a) Percentage allocated to common shares:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
          Weighted average:
 
 
 
 
 
 
 
 
               Common shares outstanding
7,119,169

 
7,067,864

 
7,109,666

 
7,054,910

 
               Unvested participating shares outstanding (d)
3,999

 
30,300

 

 

 
                Total
7,123,168

 
7,098,164

 
7,109,666

 
7,054,910

 
 
 
 
 
 
 
 
 
 
    Percentage allocated to common shares
99.9
%
 
99.6
%
 
100.0
%
 
100.0
%
 
 
 
 
 
 
 
 
 
 
Undistributed earnings (loss) ($000)
966

 
348

 
(969
)
 
(1,629
)
 
 
 
 
 
 
 
 
 
 
                        Allocated to common shares
965

 
347

 
(969
)
 
(1,629
)
 
 
 
 
 
 
 
 
 
 

(b) Represents dividends paid on common shares, exclusive of unvested participating shares.

(c) Under our Incentive Compensation Plan, recipients of performance share awards receive unvested non-participating shares, as further discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements. Unvested non-participating shares become dilutive in the interim quarter-end in which the performance objective is met. If the performance objective continues to be met through the end of the performance period, these shares become unvested participating shares as of the fiscal year-end, as further discussed below in Note (d). The weighted average number of unvested non-participating shares outstanding during a period is included in the diluted earnings per common share calculation using the treasury stock method, unless the effect of including such shares would be antidilutive. As of December 31, 2016, and 2015 there were 41,000 and 39,000 unvested non-participating shares outstanding, respectively, which were not dilutive as the underlying performance conditions have not been met.

14




(d) Certain awards under our shareholder approved incentive compensation plan, as further discussed in Note 12 of the Notes to Condensed Consolidated Financial Statements, provide recipients of the awards all the rights of a shareholder of Delta including the right to dividends declared on common shares. Any unvested shares which are participating in dividends are considered participating securities and are included in our computation of basic and diluted earnings per share using the two-class method unless the effect of including such shares would be antidilutive. As of December 31, 2016 and 2015 there were 4,000 and 30,300 unvested participating shares outstanding, respectively, which were excluded from the computation of earnings allocated to common shares, as the holders of the unvested participating shares do not have a contractual obligation to share in losses.


(12)         
Share-Based Compensation

We have a shareholder approved incentive compensation plan (the "Plan"), that provides for compensation payable in shares of our common stock.  The Plan is administered by our Corporate Governance and Compensation Committee of our Board of Directors, which has complete discretion in determining our employees, officers and outside directors who shall be eligible to participate in the Plan, as well as the type, amount, terms and conditions of each award, subject to the limitations of the Plan.

The number of shares of our common stock that may be issued pursuant to the Plan may not exceed in the aggregate 1,000,000 shares.  As of December 31, 2016, approximately 751,000 shares of common stock were available for issuance under the Plan, subject to the limitations imposed by our Corporate Governance Guidelines.  Shares of common stock may be available from authorized but unissued shares, shares reacquired by us or shares that we purchase in the open market. Upon vesting, the Plan allows for withholding a number of shares equal in fair value to the taxes required to satisfy statutory withholding requirements.

Compensation expense for share-based compensation is recorded in operation and maintenance expense in the Condensed Consolidated Statements of Income based on the fair value of the awards at the grant date and is amortized over the requisite service period.  Fair value is the closing price of our common shares at the grant date.  The grant date is the date at which our commitment to issue the share-based awards arises, which is generally when the award is approved and the terms of the awards are communicated to the employee or director.  We initially recognize expense for our performance shares when it is probable that any stipulated performance criteria will be met. Forfeitures of awards are recognized as they occur. For the three months ended December 31, 2016 and 2015, share-based compensation expense was $9,000 and $69,000, respectively. For the six months ended December 31, 2016 and 2015, share-based compensation expense was $273,000 and $315,000, respectively.

Stock Awards

For the six months ended December 31, 2016, common stock was awarded to Delta's eight outside directors having a grant date fair value of $247,000 (9,600 shares).  The recipients vested in the awards shortly after the awards were granted, but during the time between the vesting dates and the grant dates the shares awarded were not transferable by the holders. Once the shares were vested, the shares received under the stock awards were immediately transferable.

15




Performance Shares

For the six months ended December 31, 2016 and 2015, performance shares were awarded to the Company's executive officers having grant date fair values of $1,056,000 (41,000 shares) and $787,000 (39,000 shares), respectively. The performance shares vest only if the performance objectives of the awards are met, which are based on the Company's earnings per common share for the fiscal year in which the performance shares are awarded, before any cash bonuses or share-based compensation.  Upon satisfaction of the performance objectives, unvested shares are issued to the recipients and vest in one-third increments each August 31 subsequent to achieving the performance objectives as long as the recipients are employees throughout each such service period.  Unvested shares of executive officers while still employed by the Company will fully vest upon them attaining the age of sixty-seven. The recipients of the awards also become vested as a result of certain events such as death or disability of the holders or a change in control. The unvested shares have both dividend participation rights and voting rights during the remaining terms of the awards.  Holders of performance shares may not sell, transfer or pledge their shares until the shares vest.  As of December 31, 2016 and 2015, there were 4,000 and 30,300 unvested performance shares outstanding, respectively, for which the performance objectives have been satisfied.

Our performance shares have graded vesting schedules, and each separate annual vesting tranche is treated as a separate award for expense recognition.  Compensation expense is amortized over the vesting period of the individual awards based on the probable outcome of meeting the performance objectives. For the three months ended December 31, 2016 and 2015, compensation expense related to the performance shares was $9,000 and $69,000, respectively. For the six months ended December 31, 2016 and 2015, compensation expense related to the performance shares was $26,000 and $145,000, respectively.


ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

YEAR TO DATE DECEMBER 31, 2016 OVERVIEW AND FUTURE OUTLOOK

The following is a discussion of the segments we operate, our corporate strategy for the conduct of our business within these segments and significant events that have occurred during the six months ended December 31, 2016. Our Company has two segments, a regulated segment and a non-regulated segment. Our regulated segment includes our natural gas distribution and transportation services, which are regulated by the Kentucky Public Service Commission. Our non-regulated segment includes our natural gas marketing and production activities and sales of natural gas liquids.

Earnings from the regulated segment are primarily influenced by sales and transportation volumes, the rates we charge our customers and the expenses we incur. In order for us to achieve our strategy of maintaining reasonable long-term earnings, cash flow and stock value, we must successfully manage each of these factors.  Regulated sales volumes are temperature-sensitive and in any period reflect the impact of weather, with colder temperatures generally resulting in increased sales volumes.  The impact of winter temperatures on our revenues is partially reduced by our ability to adjust our winter rates for residential and small non-residential customers based on the degree to which actual winter temperatures deviate from historical average temperatures.

Our non-regulated segment markets natural gas to large-volume customers.  We endeavor to enter sales agreements matching supply with estimated demand while providing an acceptable gross margin.  The non-regulated segment produces a portion of its natural gas supply, which is sold when market conditions are favorable. The non-regulated segment also sells liquids extracted from natural gas.

Consolidated earnings per common share for the six months ended December 31, 2016 of $.28 increased, as compared to $.18 in the prior year due to increased revenues, net of gas costs, from both our non-regulated and regulated segments (as further discussed in Results of Operations). Our non-regulated segment experienced increased revenues, net of gas costs, due to the sale of a portion of our non-regulated segment’s production inventory and increased sales prices, net of increased natural gas costs. Our regulated segment experienced increased revenues, net of gas costs, due to increased volumes sold due to weather that was colder than the prior year and due to increased billings under our pipe replacement program tariff. The results of operations for the period ended December 31, 2016 are not necessarily indicative of the results of operations to be expected for the full fiscal year.  Because of the seasonal nature of our sales, we generate a significant proportion of our operating revenues during the heating months (December – April) when our sales volumes increase considerably.

16




Future profitability of the regulated segment is contingent on the adequate and timely adjustment of the rates we charge our regulated customers.  The Kentucky Public Service Commission sets these rates. We monitor our need to file for a general rate increase for our regulated services with the Kentucky Public Service Commission, which has historically utilized cost-of-service rate making where our base rates are established to recover normal operating expenses, exclusive of natural gas costs, and a reasonable rate of return on our rate base. Rate base consists primarily of our regulated segment's property, plant and equipment, natural gas in storage and unamortized debt expense offset by accumulated depreciation and certain deferred income taxes. The regulated segment's largest expense is natural gas, which we are permitted to pass through to our customers. We manage remaining expenses through budgeting, approval and review.

Future profitability of the non-regulated segment is dependent on the business plans of some of our industrial and other large-volume customers and the market prices of natural gas and natural gas liquids, all of which are beyond our control.  We anticipate our non-regulated segment will continue to contribute to our consolidated net income for the remainder of fiscal 2017. If natural gas prices increase, we would expect to experience a corresponding increase in our non-regulated gross margins related to our natural gas marketing activities.  However, if natural gas prices decrease, we would expect a decrease in our non-regulated gross margins related to our natural gas marketing activities.  We process a portion of the natural gas in our distribution, transmission and storage system to extract liquids, enhancing the reliability and efficiency of our system. The profitability from the sales of the natural gas liquids is dependent on the amount of liquids extracted and the prices for any such liquids as determined by a national non-regulated market.

LIQUIDITY AND CAPITAL RESOURCES

Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciation, amortization, deferred income taxes, share-based compensation and changes in working capital. Our sales and cash requirements are seasonal.  The largest portion of our sales occur during the heating months (December - April), whereas significant cash requirements for the purchase of natural gas for injection into our storage field and capital expenditures occur during non-heating months.  Therefore, when cash provided by operating activities is not sufficient to meet our capital requirements, our ability to maintain liquidity depends on our bank line of credit.  The current bank line of credit with Branch Banking and Trust Company extends through June 30, 2017 and permits borrowings up to $40,000,000. We anticipate renewal of the line by June 30, 2017. There were no borrowings outstanding on the bank line of credit as of December 31, 2016 or June 30, 2016.

Cash and cash equivalents were $8,857,000 at December 31, 2016, as compared with $18,607,000 at June 30, 2016.  The changes in cash and cash equivalents are summarized in the following table:
 
Six Months Ended
 
December 31,
($000)
2016
 
2015
 
 
 
 
Used in operating activities
(1,265
)
 
(241
)
Used in investing activities
(4,098
)
 
(3,394
)
Used in financing activities
(4,386
)
 
(4,304
)
Decrease in cash and cash equivalents
(9,749
)
 
(7,939
)

                For the six months ended December 31, 2016, cash used in operating activities increased $1,024,000 (425%) due to increased contributions to our defined benefit retirement plan.

Changes in cash used in investing activities results primarily from changes in the level of capital expenditures between years.

For the six months ended December 31, 2016, there were no significant changes in cash used in financing activities, as compared to the same period in the prior year.


17



Cash Requirements

Our capital expenditures result in a continued need for cash. These capital expenditures are being made for system extensions and for the replacement and improvement of existing transmission, distribution, gathering, storage and general facilities. We expect our capital expenditures for fiscal 2017 to be approximately $8.5 million.

Sufficiency of Future Cash Flows

Our ability to maintain liquidity, finance capital expenditures and pay dividends is contingent on the adequate and timely adjustment of the regulated rates we charge our customers.  The Kentucky Public Service Commission sets these rates and we monitor our need to file for rate increases for our regulated segment.  Our regulated base rates were most recently adjusted in our 2010 rate case and became effective in October, 2010.  We expect that cash provided by operations combined with our bank line of credit will be sufficient to satisfy our operating and normal capital expenditure requirements and to pay dividends for the next twelve months.

Our Series A Notes are unsecured, bear interest at a rate of 4.26% per annum which is payable quarterly, and mature on December 20, 2031.  We are required to make an annual $1,500,000 principal payment on the Series A Notes each December.  Any refinance of the Series A Notes, or any additional prepayments of principal, may be subject to a prepayment penalty.

With our bank line of credit and Series A Notes, we have agreed to certain financial covenants.  Noncompliance with these covenants can make the obligation immediately due and payable, as further discussed in our Annual Report on Form 10-K for the year ended June 30, 2016.  A default on the performance of any single obligation incurred in connection with our borrowings simultaneously creates an event of default with our bank line of credit and the Series A Notes.  We were in compliance with the covenants under our bank line of credit and Series A Notes for all periods presented in the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Operating Revenues and Purchased Natural Gas

Our operating revenues are derived primarily from the sale of natural gas, the sale of natural gas liquids and the provision of natural gas transportation services. Our operating revenues are significantly impacted by the price we pay for natural gas. Therefore, we view gross margins as an important performance measure of the core profitability of our operations and believe that investors benefit from having access to the same financial measures that our management uses. We define "gross margins" as natural gas sales less the corresponding natural gas expenses, plus transportation, natural gas liquids and other revenues. Gross margins can be derived directly from our Condensed Consolidated Statements of Income, included in Item 1. Financial Statements, as follows:
 
Three Months Ended
 
Six Months Ended
 
 
December 31,
 
December 31,
 
($000)
2016
 
2015
 
2016
 
2015
 
 
 
 
 
 
 
 
 
 
Operating revenues
18,937

 
16,673

 
29,445

 
27,067

 
Regulated natural gas
(3,768
)
 
(3,071
)
 
(4,775
)
 
(4,058
)
 
Non-regulated natural gas
(4,964
)
 
(4,389
)
 
(8,709
)
 
(8,044
)
 
 
 
 
 
 
 
 
 
 
Consolidated gross margins
10,205

 
9,213

 
15,961

 
14,965

 

Operating Income, as presented in the Condensed Consolidated Statements of Income, is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States ("GAAP").  Gross margin is a "non-GAAP financial measure", as defined in accordance with SEC rules.

Natural gas prices are determined by a non-regulated national market. Therefore, the prices that we pay for natural gas fluctuate with national supply and demand. See Item 3. Quantitative and Qualitative Disclosures About Market Risk for discussion of our forward contracts.

18



In the following table we set forth significant variations in our gross margins for the six months ended December 31, 2016, compared with the same periods in the preceding year. The variation amounts and percentages presented in the following table include intersegment transactions. These intersegment revenues and expenses are eliminated in the Condensed Consolidated Statements of Income.
 
2016 compared to 2015
 
Three Months Ended
 
Six Months Ended
($000)
December 31,
 
December 31,
 
 
 
 
Increase (decrease) in gross margins:
 
 
 
Regulated segment
 
 
 
Natural gas sales
376

 
426

Natural gas transportation
97

 
20

Other
4

 
(1
)
Intersegment elimination (a)
(1
)
 
18

Total
476

 
463

 
 
 
 
Non-regulated segment
 
 
 
Natural gas sales
446

 
431

Natural gas liquids
52

 
110

Other
17

 
10

Intersegment elimination (a)
1

 
(18
)
Total
516

 
533

 
 
 
 
Increase in consolidated gross margins
992

 
996

 
 
 
 
Percentage increase (decrease) in volumes:
 
 
 
  Regulated segment
 
 
 
    Natural gas sales (Mcf)
29

 
25

    Natural gas transportation (Mcf)
6

 
2

 
 
 
 
  Non-regulated segment
 
 
 
    Natural gas sales (Mcf)
(b)

 
(b)

    Natural gas liquids (gallons)
(21
)
 
1


(a)
Intersegment eliminations represent the natural gas transportation costs from the regulated segment to the non-regulated segment.

(b)
Represents less than a 1% change in volumes for the period presented.

Heating degree days were 83% and 82% of the normal temperatures for the three and six months ended December 31, 2016, respectively, as compared with 68% and 67% of normal temperatures in the 2015 periods. A heating degree day is each degree that the average of the high and the low temperatures for a day is below 65 degrees in a specific geographic location. Heating degree days are used in the natural gas industry to measure the relative coldness of weather and to estimate the demand for natural gas.  Normal temperatures are based on historical thirty-year average heating degree days, as calculated from data provided by the National Weather Service for the same geographic location.
    
For the three months ended December 31, 2016, consolidated gross margins increased $992,000 (11%), as compared to the same period in the prior year, due to increased non-regulated and regulated gross margins of $516,000 and $476,000, respectively. Non-regulated gross margins increased as a result of increased gross margins on natural gas sales due to the sale of non-regulated production inventory and increased sales prices partially offset by increased natural gas prices. Regulated gross margins increased due to increased volumes of natural gas sold due to weather that was 22% colder than the prior year and increased rates billed through our pipe replacement program tariff.

19




For the six months ended December 31, 2016, consolidated gross margins increased $996,000 (7%), as compared to the same period in the prior year, due to increased non-regulated and regulated gross margins of $533,000 and $463,000, respectively. Non-regulated gross margins increased as a result of increased gross margins on natural gas sales due to the sale of non-regulated production inventory and increased sales prices partially offset by increased natural gas prices. Regulated gross margins increased due to increased volumes of natural gas sold due to weather which was 22% colder than the prior year and increased rates billed through our pipe replacement program tariff.
    
Operating Expenses

For the three and six months ended December 31, 2016, there were no significant changes in operation and maintenance expenses, depreciation and amortization and interest charges, as compared to the same periods in the prior year.

For the three months ended December 31, 2016, there were no significant changes in taxes other than income taxes, as compared to the same period in the prior year. For the six months ended December 31, 2016, taxes other than income taxes decreased $159,000 (11%), due to a decrease in the assessed value of our property.

Other Income (Expense)

For the three months ended December 31, 2016, there were no significant change in other income (expense), as compared to the same period in the prior year. For the six months ended December 31, 2016, other income (expense) increased $105,000 (301%), as compared to the same period in the prior year due to an increase in earnings from the supplemental retirement trust. The increase in earnings from the supplemental retirement trust was offset by an increase in operating expense resulting from a corresponding change in the liability of the trust.

Income Tax Expense

For the three and six months ended December 31, 2016, income tax expense increased $401,000 (37%) and $361,000 (48%), respectively, as compared to the same period in the prior year due to increases in our net income before income taxes. For the three and six months ended December 31, 2016, our effective tax rate was impacted by the vesting of shares issued under our Incentive Compensation Plan, as the deduction for income tax purposes exceeded the compensation expense recognized for financial reporting purposes.

Basic and Diluted Earnings Per Common Share

For the six months ended December 31, 2016, our basic and diluted earnings per common share changed, as compared to the same period in the prior year, as a result of the change in our net income and an increase in the number of our common shares outstanding.  We increased our number of common shares outstanding as a result of shares issued through our Dividend Reinvestment and Stock Purchase Plan as well as those shares awarded through our Incentive Compensation Plan. Our computation of basic and diluted earnings per common share is set forth in Note 11 of the Notes to Condensed Consolidated Financial Statements.



ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We purchase our natural gas supply primarily through a combination of requirements contracts with no minimum purchase obligation, monthly spot purchase contracts and forward purchase contracts. The price we pay for natural gas acquired under forward purchase contracts is fixed prior to the delivery of the natural gas.  Additionally, we inject some of our natural gas purchases into our underground natural gas storage facility in the non-heating months and withdraw this natural gas from storage for delivery to customers during the heating months.  For our regulated segment, we utilize requirements contracts, spot purchase contracts and our underground storage to meet our regulated customers' natural gas requirements, all of which have minimal price risk because we are permitted to pass these natural gas costs on to our regulated customers through our natural gas cost recovery tariff.

Price risk for our non-regulated segment is mitigated by efforts to balance supply and demand.  However, there are greater risks in the non-regulated segment because of the practical limitations on the ability to perfectly predict demand.  In addition, we are exposed to changes in the market price of natural gas on uncommitted natural gas inventory of our non-regulated segment. The pricing of the natural gas liquids sold by our non-regulated segment is determined in the national non-regulated market.


20



None of our natural gas contracts are accounted for using the fair value method of accounting.  While some of our natural gas purchase and natural gas sales contracts meet the definition of a derivative, we have designated these contracts as normal purchases and normal sales.  As of December 31, 2016, we had forward purchase contracts through December, 2017 totaling $548,000, which are at fixed prices and thus are not impacted by changes in the market price of natural gas.

When we have a balance outstanding on our variable rate bank line of credit, we are exposed to risk resulting from changes in interest rates.  The interest rate on our bank line of credit with Branch Banking and Trust Company is benchmarked to the monthly London Interbank Offered Rate.  There were no borrowings outstanding on our bank line of credit as of December 31, 2016 or June 30, 2016, nor did we have any borrowings on our bank line of credit during the six months ended December, 2016.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Disclosure controls and procedures are our controls and other procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of December 31, 2016 and based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance of compliance.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we have evaluated any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended December 31, 2016 and found no change that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles.



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PART II – OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

We are not a party to any legal proceedings that are expected to have a materially adverse impact on our liquidity, financial position or results of operations.

ITEM 1A.
RISK FACTORS

No material changes.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.
MINE SAFETY DISCLOSURES

None.

ITEM 5.
OTHER INFORMATION

None.

ITEM 6.
EXHIBITS
31.1
 
 
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
 
 
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
 
 
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
 
 
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101
 
 
Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL):
 
 
(i)
Document and Entity Information;
 
 
(ii)
Condensed Consolidated Statements of Income (Loss) (Unaudited) for the three and six months ended December 31, 2016 and 2015;
 
 
(iii)
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended December 31, 2016 and 2015;
 
 
(iv)
Condensed Consolidated Balance Sheets (Unaudited) as of December 31, 2016 and June 30, 2016;
 
 
(v)
Condensed Consolidated Statements of Changes in Shareholders' Equity (Unaudited) for the six months ended December 31, 2016 and 2015; and
 
 
(vi)
Notes to Condensed Consolidated Financial Statements (Unaudited).

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


DATE:  February 3, 2017
/s/Glenn R. Jennings
 
Glenn R. Jennings
Chairman of the Board, President and Chief Executive Officer
(Duly Authorized Officer)
 
 
 
/s/John B. Brown
 
John B. Brown
Chief Operating Officer, Treasurer and Secretary
(Principal Financial Officer)

 


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