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PIEDMONT NATURAL GAS CO INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our
unaudited condensed consolidated financial statements and related notes in this
Form 10-Q, as well as with our Form 10-K for the year ended October 31, 2015.
Results for interim periods presented are not necessarily indicative of the
results to be expected for the full fiscal year due to seasonal and other
factors.

Forward-Looking Statements

This report, as well as other documents we file with the Securities and Exchange
Commission (SEC), may contain forward-looking statements. In addition, our
senior management and other authorized spokespersons may make forward-looking
statements in print or orally to analysts, investors, the media and others.
These statements are based on management's current expectations from information
currently available and are believed to be reasonable and are made in good
faith. However, the forward-looking statements are subject to risks and
uncertainties that could cause actual results to differ materially from those
projected in the statements. On October 24, 2015, we entered into an Agreement
and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy)
and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke
Energy. The Merger Agreement provides for the merger of the Merger Sub with and
into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke
Energy (the Acquisition). Factors that may make the actual results differ from
anticipated results include, but are not limited to the following, as well as
those discussed in Part II. Item 1A. Risk Factors, including those related to
the Acquisition by Duke Energy that are more fully discussed in Note 2 to the
condensed consolidated financial statements in this Form 10-Q:


• Economic conditions in our markets.

• Wholesale price of natural gas.

• Availability of adequate interstate pipeline transportation capacity and

natural gas supply.

• Regulatory actions at the state level that impact our ability to earn a

reasonable rate of return and fully recover our operating costs on a timely

basis.

• Competition from other companies that supply energy.

• Changes in the regional economies, politics, regulations and weather

patterns of the three states in which our operations are concentrated.

• Costs of complying or effect of noncompliance with state and federal laws

and regulations that are applicable to us.

• Effect of climate change, carbon neutral or energy efficiency legislation

or regulations on costs and market opportunities.

• Weather conditions.

• Operational interruptions to our gas distribution and transmission activities.

•     Inability to complete necessary or desirable pipeline expansion or
      infrastructure development projects.

• Elevated levels of capital expenditures.

• Changes to our credit ratings.

• Availability and cost of capital.

• Federal and state fiscal, tax and monetary policies.

• Ability to generate sufficient cash flows to meet all our cash needs.

• Ability to satisfy all of our outstanding debt obligations.

• Ability of counterparties to meet their obligations to us.

• Costs of providing pension benefits.

• Earnings and losses from the joint venture businesses in which we invest.

• Ability to attract and retain professional and technical employees.

• Cybersecurity breaches or failure of technology systems.

• Ability to obtain and maintain sufficient insurance.

• Change in number of outstanding shares.

• Certain risks and uncertainties associated with the Acquisition, including,

      without limitation:


•            the possibility that the Acquisition does not close due to the
             failure to satisfy the closing conditions, including, but not
             limited to, a failure to obtain the required regulatory approvals;



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•            delays caused by the required regulatory approvals, which 

may delay

             the Acquisition or cause the companies to abandon the transaction;


•            uncertainties and disruptions caused by the Acquisition that make it
             more difficult to maintain our business and operational
             relationships as well as maintain our relationships with employees,
             suppliers or customers, and the risk that unexpected costs will be
             incurred during this process;

• the diversion of management time on Acquisition-related issues, and;

•            future shareholder suits could delay or prevent the closing of the
             Acquisition or otherwise adversely impact our business and
             operations.



Other factors may be described elsewhere in this report. All of these factors
are difficult to predict, and many of them are beyond our control. For these
reasons, you should not place undue reliance on these forward-looking statements
when making investment decisions. When used in our documents or oral
presentations, the words "expect," "believe," "project," "anticipate," "intend,"
"may," "should," "could," "assume," "estimate," "forecast," "future,"
"indicate," "outlook," "plan," "predict," "seek," "target," "would" and
variations of such words and similar expressions are intended to identify
forward-looking statements.

Forward-looking statements are based on information available to us as of the
date they are made, and we do not undertake any obligation to update publicly
any forward-looking statement either as a result of new information, future
events or otherwise except as required by applicable laws and regulations. Our
reports on Form 10-K, Form 10-Q and Form 8-K and amendments to these reports are
available at no cost on our website at www.piedmontng.com as soon as reasonably
practicable after the report is filed with or furnished to the SEC.

Overview

Piedmont Natural Gas Company, Inc., which began operations in 1951, is an energy
services company whose principal business is the distribution of natural gas to
over one million residential, commercial, industrial and power generation
customers in portions of North Carolina, South Carolina and Tennessee, including
customers served by municipalities who are our wholesale customers. We are
invested in joint venture, energy-related businesses, including unregulated
retail natural gas marketing, regulated interstate natural gas transportation
and storage and regulated intrastate natural gas transportation businesses.
Unless the context requires otherwise, references to "we," "us," "our," "the
Company" or "Piedmont" means consolidated Piedmont Natural Gas Company, Inc. and
its subsidiaries.

We operate with three reportable business segments, regulated utility, regulated
non-utility activities and unregulated non-utility activities, with the
regulated utility segment being the largest. Our utility operations are
regulated by the North Carolina Utilities Commission (NCUC), the Public Service
Commission of South Carolina (PSCSC) and the Tennessee Regulatory Authority
(TRA) as to rates, service area, adequacy of service, safety standards,
extensions and abandonment of facilities, accounting and depreciation. The NCUC
also regulates us as to the issuance of long-term debt and equity securities.
Factors critical to the success of the regulated utility segment include
operating a safe and reliable natural gas distribution system and the ability to
recover the costs and expenses of the business in the rates charged to
customers. The regulated non-utility activities segment consists of our equity
method investments in joint venture regulated energy-related pipeline and
storage businesses that are held by our wholly-owned subsidiaries. The
unregulated non-utility activities segment consists primarily of our equity
method investment in SouthStar Energy Services LLC (SouthStar) that is held by a
wholly-owned subsidiary. For further information on equity method investments
and business segments, see Note 13 and Note 15, respectively, to the condensed
consolidated financial statements in this Form 10-Q. The percentages of the
assets as of April 30, 2016 and earnings before taxes by segments for the six
months ended April 30, 2016 are presented below.
                                               Earnings
                                   Assets    Before Taxes
Regulated Utility                    96 %          91 %
Non-utility Activities:
Regulated non-utility activities      3 %           3 %
Unregulated non-utility activities    1 %           6 %
Total non-utility activities          4 %           9 %



We are also subject to various federal regulations that affect our utility and
non-utility operations. These federal regulations include regulations that are
particular to the natural gas industry, such as regulations of the Federal
Energy Regulatory Commission (FERC) that affect the certification and siting of
new interstate natural gas pipeline projects, the purchase and sale of, the
prices paid for, and the terms and conditions of service for the interstate
transportation and storage of natural gas,

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regulations of the U.S. Department of Transportation that affect the design,
construction, operation, maintenance, integrity, safety and security of natural
gas distribution and transmission systems, and regulations of the Environmental
Protection Agency relating to the environment, including proposed air emissions
regulations that would expand to include emissions of methane. In addition, we
are subject to numerous other regulations, such as those relating to employment
and benefit practices, which are generally applicable to companies doing
business in the United States of America.

Our regulatory commissions approve rates and tariffs that are designed to give
us the opportunity to recover the cost of natural gas we purchased for our
customers and our operating expenses and to earn a fair rate of return on
invested capital for our shareholders. The traditional utility rate design
provides for the collection of margin revenue largely based on volumetric
throughput which can be affected by customer consumption patterns, weather,
conservation, price levels for natural gas or general economic conditions. By
continually assessing alternative rate structures and cost recovery mechanisms
that are more appropriate to the changing energy economy and through requests
filed with our regulatory commissions, we have secured alternative rate
structures and cost recovery mechanisms designed to allow us to recover certain
costs through tracking mechanisms or riders without the need to file general
rate cases. Our ability to earn our authorized rates of return is based in part
on our ability to reduce or eliminate regulatory lag through rate stabilization
adjustment (RSA) filings, integrity management riders (IMRs) or similar
mechanisms and also by improved rate designs that decouple the recovery of our
approved margins from customer usage patterns impacted by seasonal weather
patterns and customer conservation. This allows a better alignment of the
interests of our shareholders and customers.

In North Carolina, we have a margin decoupling mechanism that provides for the
recovery of our approved margin from residential and commercial customers on an
annual basis independent of consumption patterns. The margin decoupling
mechanism provides for semi-annual rate adjustments to refund any
over-collection of margin or to recover any under-collection of margin. In South
Carolina, we operate under a RSA mechanism that achieves the objective of margin
decoupling for residential and commercial customers with a one year lag. Under
the RSA mechanism, we reset our rates based on updated costs and revenues on an
annual basis. We also have a weather normalization adjustment (WNA) mechanism
for residential and commercial customers in South Carolina for bills rendered
during the months of November through March and in Tennessee for bills rendered
during the months of October through April that partially offsets the impact of
colder- or warmer-than-normal winter weather on our margin collections. Our WNA
formulas calculate the actual weather variance from normal, using 30 years of
history, and increase margin revenues when weather is warmer than normal and
decrease margin revenues when weather is colder than normal. The WNA formulas do
not ensure full recovery of approved margin during periods when customer
consumption patterns vary from those used to establish the WNA factors and when
weather is significantly warmer or colder than normal. We have IMRs in North
Carolina and Tennessee that separately track and recover, outside of general
rate cases, certain costs associated with capital expenditures to comply with
pipeline safety and integrity requirements.

In all three states, the gas cost portion of our costs is recoverable through
purchased gas adjustment (PGA) procedures and is not affected by the margin
decoupling mechanism or the WNA mechanism. Through the use of various tariff
mechanisms and fixed-rate contracts, we are able to achieve a higher degree of
margin stabilization. For further information on state commission regulation,
see Note 3 to the consolidated financial statements in our Form 10-K for the
year ended October 31, 2015. The following table presents the breakdown of our
gas utility margin for the six months ended April 30, 2016 and 2015.
                                                                  2016      

2015

Fixed margin (from margin decoupling in North Carolina, facilities charges to our customers,

Tennessee and North Carolina IMRs and fixed-rate contracts) 75 %

73 % Semi-fixed margin (RSA in South Carolina and WNA in South Carolina and Tennessee)

                                              17 %        18 %
Volumetric or periodic renegotiation (including secondary
marketing activity)                                                   8 %         9 %
Total                                                               100 %       100 %



Our long-term strategic directives shape our annual business objectives and
focus on our customers, our communities, our employees and our shareholders.
They also reflect what we believe are the inherent advantages of natural gas
compared to other forms of energy. Our seven foundational strategic priorities
are as follows:


• Promote the benefits of natural gas,

• Expand our core natural gas and complementary energy-related businesses to

enhance shareholder value,

• Be the energy service provider of choice,

• Achieve excellence in customer service every time,

• Preserve financial strength and flexibility,

• Execute sustainable business practices, and

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• Enhance our healthy high performance culture.




With a continued focus on these priorities, we believe we will enhance long-term
shareholder value. For a full discussion of our strategy and focus areas, see
"Our Strategies" in Item 1. Business in our Form 10-K for the year ended
October 31, 2015.

Executive Summary
Financial Performance - Quarter Ended 2016 Compared with Quarter Ended 2015
The following tables provide a comparison of the components of comprehensive
income and statistical information for the three months ended April 30, 2016 as
compared with the three months ended April 30, 2015.
                             Comprehensive Income Statement Components

                                                        Three Months Ended April 30
In thousands, except per share amounts     2016           2015        Variance      Percent Change
Operating Revenues                     $  350,186     $  424,924     $ (74,738 )          (18 )%
Cost of Gas                               125,822        199,303       (73,481 )          (37 )%
Margin                                    224,364        225,621        (1,257 )           (1 )%
Operations and Maintenance                 75,508         71,424         4,084              6  %
Depreciation                               34,045         31,689         2,356              7  %
General Taxes                              10,882         10,976           (94 )           (1 )%
Utility Income Taxes                       32,089         36,409        (4,320 )          (12 )%
Total Operating Expenses                  152,524        150,498         2,026              1  %
Operating Income                           71,840         75,123        (3,283 )           (4 )%
Other Income (Expense), net of tax          8,176          9,360        (1,184 )          (13 )%
Utility Interest Charges                   16,584         18,081        (1,497 )           (8 )%
Net Income                             $   63,432     $   66,402     $  (2,970 )           (4 )%
Average Shares of Common Stock:
Basic                                      81,109         78,818         2,291              3  %
Diluted                                    81,388         79,115         2,273              3  %
Earnings Per Share of Common Stock:
Basic                                  $     0.78     $     0.84     $   (0.06 )           (7 )%
Diluted                                $     0.78     $     0.84     $   (0.06 )           (7 )%



                    Margin by Customer Class

                                Three Months Ended April 30
In thousands                     2016                 2015
Sales and Transportation:
Residential               $ 124,486     56 %   $ 121,181     54 %
Commercial                   56,461     25 %      55,775     25 %
Industrial                   13,483      6 %      12,855      6 %
Power Generation             19,186      9 %      19,363      8 %
For Resale                    3,065      1 %       2,522      1 %
Total                       216,681     97 %     211,696     94 %
Secondary Market Sales        4,702      2 %      10,397      5 %
Miscellaneous                 2,981      1 %       3,528      1 %
Total                     $ 224,364    100 %   $ 225,621    100 %



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             Gas Deliveries, Customers, Weather Statistics and Number of Employees

                                                     Three Months Ended April 30
                                          2016          2015       Variance     Percent Change
Deliveries in Dekatherms (in
thousands):
Residential                              17,705         22,813      (5,108 )          (22 )%
Commercial                               11,916         14,556      (2,640 )          (18 )%
Industrial                               25,196         25,360        (164 )           (1 )%
Power Generation                         79,965         60,005      19,960             33  %
For Resale                                1,977          2,398        (421 )          (18 )%
Throughput                              136,759        125,132      11,627              9  %
Secondary Market Volumes                 18,160          9,815       8,345             85  %

Customers Billed (at period end) 1,043,382 1,027,917 15,465

             2  %
Gross Residential, Commercial and
Industrial Customer Additions             4,001          3,611         390             11  %
Degree Days
Actual                                    1,008          1,322        (314 )          (24 )%
Normal                                    1,182          1,176           6              1  %

Percent (warmer) colder than normal (15 )% 12 % n/a

n/a

Number of Employees (at period end) 1,923 1,932 (9 )

            -  %


We closed our second quarter with a 4% decrease in net income. Margin decreased
1% due to lower margin sales from secondary market transactions and warmer
weather, partially offset by IMR rate adjustments and customer growth. The
margin earned from power generation customers is largely based on fixed monthly
demand charge contracts and does not vary significantly based on the volumes
transported. Operations and maintenance (O&M) expense increased 6% primarily due
to increases in payroll and contract labor, partially offset by a decrease in
employee benefits. Depreciation increased 7% primarily due to increases in plant
in service. Other Income (Expense) and utility interest charges decreased 13%
and 8%, respectively. Other Income (Expense) decreased due to a decline in
income from equity method investments. Utility interest charges decreased as a
result of recording interest income on net amounts due from customers compared
with interest expense in the prior year, partially offset by additional interest
from an increase in long-term debt outstanding.

Financial Performance - Six Months Ended 2016 Compared with Six Months Ended
2015
The following tables provide a comparison of the components of comprehensive
income and statistical information for the six months ended April 30, 2016 as
compared with the six months ended April 30, 2015.


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                               Comprehensive Income Statement Components
                                                          Six Months Ended April 30
In thousands, except per share amounts     2016           2015          Variance       Percent Change
Operating Revenues                     $  811,523     $ 1,032,196     $ (220,673 )           (21 )%
Cost of Gas                               300,910         536,505       (235,595 )           (44 )%
Margin                                    510,613         495,691         14,922               3  %
Operations and Maintenance                146,808         137,574          9,234               7  %
Depreciation                               67,730          63,583          4,147               7  %
General Taxes                              20,804          20,972           (168 )            (1 )%
Utility Income Taxes                       93,999          92,680          1,319               1  %
Total Operating Expenses                  329,341         314,809         14,532               5  %
Operating Income                          181,272         180,882            390               -  %
Other Income (Expense), net of tax         13,602          14,291           (689 )            (5 )%
Utility Interest Charges                   33,652          35,793         (2,141 )            (6 )%
Net Income                             $  161,222     $   159,380     $    1,842               1  %
Average Shares of Common Stock:
Basic                                      81,035          78,717          2,318               3  %
Diluted                                    81,324          79,048          2,276               3  %
Earnings Per Share of Common Stock:
Basic                                  $     1.99     $      2.02     $    (0.03 )            (1 )%
Diluted                                $     1.98     $      2.02     $    (0.04 )            (2 )%


                    Margin by Customer Class
                                 Six Months Ended April 30
In thousands                     2016                 2015
Sales and Transportation:
Residential               $ 292,446     57 %   $ 279,665     57 %
Commercial                  129,562     25 %     124,649     25 %
Industrial                   27,891      6 %      26,032      5 %
Power Generation             38,456      8 %      38,608      8 %
For Resale                    6,253      1 %       5,164      1 %
Total                       494,608     97 %     474,118     96 %
Secondary Market Sales       11,127      2 %      15,950      3 %
Miscellaneous                 4,878      1 %       5,623      1 %
Total                     $ 510,613    100 %   $ 495,691    100 %



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             Gas Deliveries, Customers, Weather Statistics and Number of Employees

                                                      Six Months Ended April 30
                                          2016          2015       Variance     Percent Change
Deliveries in Dekatherms (in
thousands):
Residential                              41,957         54,285     (12,328 )          (23 )%
Commercial                               27,145         32,945      (5,800 )          (18 )%
Industrial                               52,162         52,625        (463 )           (1 )%
Power Generation                        149,220        120,717      28,503             24  %
For Resale                                4,267          5,348      (1,081 )          (20 )%
Throughput                              274,751        265,920       8,831              3  %
Secondary Market Volumes                 34,690         20,984      13,706             65  %

Customers Billed (at period end) 1,043,382 1,027,917 15,465

             2  %
Gross Residential, Commercial and
Industrial Customer Additions             8,673          8,503         170              2  %
Degree Days
Actual                                    2,463          3,267        (804 )          (25 )%
Normal                                    3,023          3,015           8              -  %
Percent (warmer) colder than normal         (19 )%           8 %       n/a  

n/a

Number of Employees (at period end) 1,923 1,932 (9 )

            -  %


We closed the first half of fiscal year 2016 with a 1% increase in net income.
Margin increased 3% due to IMR rate adjustments and customer growth, partially
offset by lower margin sales from secondary market transactions and warmer
weather. O&M expenses and depreciation expense both increased 7%. The increase
in O&M expenses was related to increases in payroll and direct and indirect
Acquisition-related expenses. Depreciation was higher due to increases in plant
in service. Utility interest charges decreased 6% as a result of recording
interest income on net amounts due from customers compared with interest expense
in the prior year, partially offset by additional interest from an increase in
long-term debt outstanding.

Financial Strength and Flexibility - In order to prudently fund our investment
in growth and our ongoing capital needs, we continue to execute our financing
program to optimize and reduce our cost of capital, preserve our liquidity and
strong balance sheet and protect our high quality credit ratings with a goal of
maintaining a total debt to capital ratio between 50% and 60%. In January and
March 2016, we entered into forward sale agreements (FSAs) under our
at-the-market (ATM) equity sales program that was established in January 2015.
The timing and volume of sales under this program cannot be predicted with
certainty and may be affected by factors outside our control, but will not
exceed an aggregate of $170 million from January 2015 through the end of fiscal
2016. We continue to rely on our commercial paper (CP) program to meet our
short-term liquidity needs.

Managing Gas Supplies and Prices - Our gas supply acquisition strategy is
regularly reviewed and adjusted to ensure that we have adequate and reliable
supplies of competitively priced natural gas to meet the needs of our utility
customers. In order to provide additional diversification, reliability and gas
cost benefits to our customers, we have long-term supply and capacity contracts
to buy and transport more of our gas supplies from the Marcellus shale basin in
Pennsylvania for our markets in the Carolinas. These competitive long-term
sources of gas supply became available during the winter 2015 - 2016 season from
the Williams - Transco Leidy Southeast expansion project and its Virginia
Southside expansion project and replaced other sources of gas within our supply
portfolio, supporting our supply diversification strategy. Additional gas
supplies from diverse gas supply basins in central West Virginia are anticipated
to be available for the winter 2018 - 2019 season under a long-term pipeline
capacity firm transportation agreement with Atlantic Coast Pipeline, LLC (ACP)
upon completion of the project.


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Customer Growth - We continued to have solid customer growth in the second
quarter. Affordable and stable wholesale natural gas costs continue to favorably
position natural gas relative to other energy sources. Continued targeted
marketing programs on the benefits of natural gas should help us to sustain
growth comparable to prior years. Residential conversion growth has slowed
compared to demand for residential new home construction, impacting growth in
these markets during the current period as compared to the same prior period as
presented below.
                                                    Percent
                                   2016     2015     Change
Residential new home construction 6,352    5,915        7  %
Residential conversion            1,350    1,619      (17 )%
Commercial                          969      967        -  %
Industrial                            2        2        -  %
Total new customers               8,673    8,503        2  %


We forecast gross customer growth of approximately 1.6 - 2% for fiscal 2016. Overall, total net customers billed increased 1.5% for the six months ended April 30, 2016 as compared to the same period in 2015.

Capital Expenditures - We continued to execute our capital expansion and
improvement programs that will provide benefits to our customers through safe
and reliable natural gas service while providing our shareholders a fair and
reasonable return on invested capital. Our capital expenditures are driven by
pipeline integrity, safety and compliance programs, investments for customer
growth, system infrastructure and technology, including a comprehensive work and
asset management system.

With significant capital costs incurred under our ongoing system integrity
programs, we have IMR regulatory mechanisms in North Carolina and Tennessee to
separately track and recover certain costs associated with capital expenditures
incurred to comply with federal pipeline safety and integrity programs, as well
as additional state safety and integrity requirements in Tennessee. The IMR
orders by jurisdiction and the amount reflected in "Operating Revenues" in the
Condensed Consolidated Statements of Comprehensive Income is summarized below:
In millions                                         North Carolina          

Tennessee

Incremental annual margin revenue - 2014 IMR $ 1.0 (1)

   $        13.1
Incremental annual margin revenue - 2015 IMR                 24.4    (1)                6.5
Incremental annual margin revenue - 2016 IMR (2)             15.5                       1.7

Total cumulative incremental annual margin revenue as of April 30, 2016 (3)

                            $        40.9   (1  )   

$ 21.3

Amount recorded during three months ended April 30, 2016

                                                $        13.1             $         7.8
Amount recorded during six months ended April 30,
2016                                                         25.6                      15.9

(1) Amounts reflect incremental annual IMR margin revenue, as adjusted per audit by the NCUC
Public Staff under the approved IMR settlement agreement and procedural schedule, which may
differ from the amounts reflected in the filed and approved rate adjustments. For further
information on the current rate adjustment, see Note 3 to the condensed consolidated
financial statements in this Form 10-Q. For further information on the IMR settlement
agreement, see Note 3 to the consolidated financial statements in our Form 10-K for the year
ended October 31, 2015.
(2) In May 2016, the NCUC approved an additional $7.4 million in annual margin revenues
effective June 1, 2016.
(3) IMR recovery periods in both jurisdictions do not align with our fiscal year. For further
information on these periods, see Note 3 to the consolidated financial statements in our Form
10-K for the year ended October 31, 2015.



Sustainable Business Practices - Our ability to provide safe and reliable
natural gas service under any operating conditions is due to our ongoing
investments in our pipeline delivery system through our system expansion and
pipeline integrity management programs. Our review and implementation of our gas
supply acquisition strategy ensures that we have adequate and reliable supplies
to meet the peak day needs of our utility customers. We evaluate ongoing cold
weather conditions and the corresponding customer consumption patterns, as well
as historical winter weather over the past 40 years, in developing our peak day
requirements.

Equity Method Investments - Our investments in complementary energy-related
businesses continue to be an attractive way to generate earnings growth and
long-term shareholder returns. We are a member of two ventures that propose to
construct interstate natural gas pipelines, subject to the jurisdiction of the
FERC. We are a 24% equity member of Constitution Pipeline Company LLC
(Constitution) that plans to transport natural gas produced from the Marcellus
shale basin in Pennsylvania to

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northeast markets. We are a 10% equity member of ACP that plans to transport
diverse northeastern gas supplies into southeastern markets. The project would
also require us to expand our utility natural gas delivery system in eastern
North Carolina to provide redelivery of ACP volumes to retail natural gas
markets. Having a second major interstate pipeline in the state will enhance the
reliability and diversity of gas supplies to our Carolina market area. For
further information on our anticipated contributions for these project costs,
anticipated in-service dates, contributions made to date and project updates,
and our assessment of our investment in Constitution, see "Cash Flows from
Investing Activities" in this Form 10-Q. For further information on equity
method investments and business segments, see Note 13 and Note 15, respectively,
to the condensed consolidated financial statements in this Form 10-Q.

Proposed Acquisition by Duke Energy - In October 2015, we entered into a Merger
Agreement with Duke Energy. At the effective time of the Acquisition, subject to
receipt of required regulatory approvals and meeting specified customary closing
conditions, each share of Piedmont common stock issued and outstanding
immediately prior to the closing will be converted automatically into the right
to receive $60 in cash per share, without interest, less any applicable
withholding taxes. For further information on the Acquisition, see "Forward
Looking Statements" in Item 2 and Note 2, Note 3 and Note 13 to the condensed
consolidated financial statements in this Form 10-Q. In the Merger Agreement, we
agreed to covenants, none of which we expect to materially impact our financial
condition or results of operations, affecting the conduct of our business
between the date of the Merger Agreement and the effective date of the
Acquisition. We anticipate the Acquisition to close in 2016.

On November 6, 2015, Thomas E. Skains, Chairman, President and Chief Executive Officer of Piedmont, notified our Board of Directors and Duke Energy of his intent to terminate his employment and retire from Piedmont effective, and contingent, upon the closing of the Acquisition.

On December 18, 2015, Frank Yoho, our Senior Vice President - Commercial Operations, was designated by Duke Energy to lead its natural gas operations, including our gas operations, when the Acquisition is closed.

Several required conditions for completion of the Acquisition have been obtained. In December 2015, the Federal Trade Commission granted early termination of the 30-day waiting period for the Acquisition under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In January 2016, the Acquisition was approved by 66.8% of eligible outstanding shares of common stock held by our shareholders.

Required filings were made with our state regulatory commissions in January
2016. We and Duke Energy filed a joint application with the NCUC seeking
regulatory approval of the Acquisition. We and Duke Energy filed a joint
application seeking approval from the TRA to transfer our operating license to
Duke Energy. In March 2016, the TRA approved the transfer contingent upon NCUC
approval of the Acquisition. We and Duke Energy discussed the Acquisition of
Piedmont with the PSCSC.

In accordance with the SouthStar limited liability company agreement, upon the
announcement of the Acquisition, we delivered a notice of change of control to
Georgia Natural Gas Company (GNGC). On December 9, 2015, GNGC delivered to us a
written notice electing to purchase our entire 15% interest in SouthStar,
subject to and effective with the consummation of the Acquisition. On February
12, 2016, we entered into a letter agreement with GNGC for the purchase of our
interest for $160 million cash. The letter agreement provides that we and GNGC
will execute a definitive agreement for the purchase, which will include the
satisfaction of customary closing conditions and obtaining regulatory approvals
or consents necessary to consummate the purchase of our interest.

Additional information on operating results for the three months and six months ended April 30, 2016 follows.


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Operating Revenues

Changes in operating revenues for the three months and six months ended April 30, 2016 compared with the same periods in 2015 are presented below.

Changes in Operating Revenues - Increase (Decrease)

In millions                           Three Months     Six Months
Residential and commercial customers $      (71.0 )   $    (249.7 )
Industrial customers                         (2.2 )          (7.0 )
Power generation customers                   (0.4 )          (0.4 )
Secondary market                            (37.2 )         (55.6 )
Margin decoupling mechanism                  22.1            53.4
WNA mechanisms                                9.2            20.1
IMR mechanisms                                4.8            18.8
Other revenue                                   -            (0.3 )
Total                                $      (74.7 )   $    (220.7 )



• Residential and commercial customers - the decreases for the three months and

six months are due to lower consumption from warmer weather and lower

wholesale gas costs passed through to customers, slightly offset by customer

growth.

• Industrial customers - the decreases for the three months and six months are

due to lower wholesale gas costs passed through to customers and lower

volumes from warmer weather.

• Secondary market - the decreases for the three months and six months are due

to lower margin sales prices, slightly offset by increased volumes. Secondary

market transactions consist of off-system sales and capacity release and

asset management arrangements that are a part of our regulatory gas supply

management program with regulatory-approved sharing mechanisms between our

utility customers and our shareholders.

• Margin decoupling mechanism - the increases for the three months and six

months are primarily related to warmer weather in North Carolina as compared

to the prior periods. As discussed in "Overview," the margin decoupling

mechanism in North Carolina adjusts for variations in residential and

commercial use per customer, including those due to weather and conservation.

• WNA mechanisms - the increases for the three months and six months are

primarily related to warmer weather in South Carolina and Tennessee as

compared to the prior periods. As discussed in "Overview," the WNA mechanisms

partially offset the impact of colder- or warmer-than-normal weather on bills

rendered.

• IMR mechanisms - the increases for the three months and six months are due to

the IMR rate adjustments in Tennessee, effective in January 2015 and 2016,

and North Carolina, effective in February 2015 and December 2015.

Cost of Gas

Changes in cost of gas for the three months and six months ended April 30, 2016 compared with the same periods in 2015 are presented below.

                    Changes in Cost of Gas - Increase (Decrease)

In millions                                            Three Months     Six 

Months

Commodity gas costs passed through to sales customers $ (55.7 ) $ (149.9 ) Commodity gas costs in secondary market transactions (31.5 )

         (50.8 )
Pipeline demand charges                                        1.3          

-

Regulatory-approved gas cost mechanisms                       12.4           (34.9 )
Total                                                 $      (73.5 )   $    (235.6 )



• Commodity gas costs passed through to sales customers - the decreases for the

    three months and six months are primarily due to lower consumption from
    warmer weather and lower wholesale gas costs passed through to sales
    customers, slightly offset by customer growth.



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• Commodity gas costs in secondary market transactions - the decreases for the

three months and six months are primarily due to lower average wholesale gas

costs, slightly offset by increased volumes.

• Pipeline demand charges - the increase for the three months is due to

increased demand costs, slightly offset by increased capacity release

revenues and asset manager payments. The six month comparability is due to

increased demand costs offset by increased capacity release revenues and

asset manager payments.

• Regulatory-approved gas cost mechanisms - the increase for the three months

is primarily due to an increase in commodity gas cost true-ups and other

regulatory mechanisms, partially offset by demand true-ups. The decrease for

    the six months is primarily due to a decrease in commodity gas cost and
    demand true-ups, partially offset by other regulatory mechanisms.



In all three states, we are authorized to recover from customers all prudently
incurred gas costs. Charges to cost of gas are based on the amount recoverable
under approved rate schedules. The net of any over- or under-recoveries of gas
costs are reflected in a regulatory deferred account in current "Regulatory
assets" or current "Regulatory liabilities" in the Condensed Consolidated
Balance Sheets and are added to or deducted from cost of gas. For the amounts
included in "Amounts due from customers" or "Amounts due to customers," see Note
3 to the condensed consolidated financial statements in this Form 10-Q.


Margin


Margin, rather than revenues, is used by management to evaluate utility
operations due to the regulatory pass through of changes in wholesale commodity
gas costs. Our utility margin is defined as natural gas revenues less natural
gas commodity costs and fixed gas costs for transportation and storage capacity.
It is the component of our revenues that is established in general rate cases
and is designed to cover our utility operating expenses and our return of and on
our utility capital investments and related taxes. Our commodity gas costs
accounted for 27% of revenues for the six months ended April 30, 2016, and our
pipeline transportation and storage costs accounted for 8%.

In general rate proceedings, state regulatory commissions authorize us to
recover our margin in our monthly fixed demand charges and on each unit of gas
delivered under our generally applicable sales and transportation tariffs and
special service contracts. We negotiate special service contracts with some
industrial customers that may include the use of volumetric rates with minimum
margin commitments and fixed monthly demand charges. These individually
negotiated agreements are subject to review and approval by the applicable state
regulatory commission and allow us to make an economic extension or expansion of
natural gas service to larger industrial customers.

Our utility margin is also impacted by certain regulatory mechanisms as defined
elsewhere in this document. These regulatory mechanisms by jurisdiction are
presented below.
    Regulatory Mechanism           North Carolina       South Carolina         Tennessee
WNA mechanism (1)                                             X                    X
Margin decoupling mechanism
(1)                                      X
Natural gas rate
stabilization mechanism                                       X
Secondary market programs (2)            X                    X                    X
Incentive plan for gas supply
(2)                                                                                X
IMR mechanism                            X                                         X
Negotiated margin loss
treatment                                X                    X
Uncollectible gas cost
recovery                                 X                    X                    X

(1) Residential and
commercial customers only.
(2) In all jurisdictions, we retain 25% of secondary market margins generated through
off-system sales and capacity release activity, with 75% credited to customers. Our share of
net gains or losses in Tennessee is subject to an annual cap of $1.6 million.




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Changes in margin for the three months and six months ended April 30, 2016 compared with the same periods in 2015 are presented below.

             Changes in Margin - Increase (Decrease)

In millions                           Three Months     Six Months
Residential and commercial customers $       4.0      $     17.7
Industrial customers                         1.2             2.9
Power generation customers                  (0.2 )          (0.2 )
Secondary market activity                   (5.7 )          (4.8 )
Net gas cost adjustments                    (0.6 )          (0.7 )
Total                                $      (1.3 )    $     14.9



• Residential and commercial customers - the increases for the three months and

six months are primarily due to IMR rate adjustments in Tennessee, effective

in January 2015 and 2016, and North Carolina, effective in February 2015 and

December 2015, and customer growth in all three states, partially offset by

warmer weather in jurisdictions where our rates are not fully decoupled and

WNA does not perfectly adjust for variances from normal weather.

• Industrial customers - the increases for the three months and six months are

primarily due to IMR rate adjustments in Tennessee, effective in January 2015

and 2016, and North Carolina, effective in February 2015 and December 2015,

as well as increased margin recognized from special contracts.

• Secondary market activity - the decreases for the three months and six months

    are primarily due to lower margin sales, slightly offset by increased
    volumes.



Operations and Maintenance Expenses

Changes in O&M expenses for the three months and six months ended April 30, 2016 compared with the same periods in 2015 are presented below.

        Changes in Operations and Maintenance Expenses - Increase (Decrease)


In millions                                             Three Months     Six Months
Payroll                                                $      2.5       $     7.8
Acquisition-related integration expenses                      0.5             2.1
Contract labor                                                1.5             0.7
Employee benefits                                            (1.3 )          (0.9 )
Other                                                         0.9            (0.5 )
Total                                                  $      4.1       $     9.2




• Payroll - the increases for the three months and six months are primarily due

to higher equity incentive plan accruals, including $5.1 million incremental

expense from the accelerated vesting and payment of incentive awards under

provisions in the Merger Agreement during the six months, merit increases and

additional employees.

• Acquisition-related integration expenses - the increase for the six months is

due to integration costs paid to outside parties in 2016.

• Contract labor - the increase for the three months is primarily due to

increased legal expenses, location of underground pipeline for third parties

installing fiber optic cable, pipeline integrity maintenance and safety

programs and right-of-way maintenance.

• Employee benefits - the decrease for the three months is primarily due to

lower defined benefit plan accruals due to incorporating updated mortality

tables and a change in the methodology to calculate net periodic benefit cost

    and reduced group medical insurance expense from lower claims.




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Depreciation


Depreciation expense increased $2.4 million and $4.1 million for the three
months and six months ended April 30, 2016, respectively, compared with the same
periods in 2015 primarily due to increases in plant in service, particularly
related to major additions in system integrity investments, natural gas
infrastructure and new services.


Other Income (Expense)


Other Income (Expense) is comprised of income from equity method investments,
non-operating income, non-operating expense and income taxes related to these
items. Non-operating income includes non-regulated merchandising and service
work, home service warranty programs, subsidiary operations, interest income and
other miscellaneous income. Non-operating expense is comprised of charitable
contributions and miscellaneous expenses.

The primary change to Other Income (Expense) for the three months and six months
ended April 30, 2016 compared with the same periods in 2015 was a decrease in
income from equity method investments. Income from equity method investments
from SouthStar decreased $1.3 million and $1.2 million for the three months and
six months, respectively, primarily due to lower customer usage due to warmer
weather and lower value of hedged derivatives, partially offset by lower
operating expenses. For the six months, ACP contributed $.9 million in income
due to higher capitalized interest expense and lower outreach cost.


Utility Interest Charges

Changes in utility interest charges for the three months and six months ended April 30, 2016 compared with the same periods in 2015 are presented below.

Changes in Utility Interest Charges - Increase (Decrease)


In millions                                 Three Months     Six Months
Regulatory interest expense, net           $       (2.8 )   $     (4.6 )
Borrowed AFUDC                                     (0.5 )         (1.0 )
Interest expense on long-term debt                  1.4            2.7
Other                                               0.4            0.8
Total                                      $       (1.5 )   $     (2.1 )



• Regulatory interest expense, net - the changes for the three months and six

months are primarily due to interest income on net amounts due from customers

compared with interest expense in the prior year on net amounts due to

customers.

• Borrowed allowance for funds used during construction (AFUDC) - the change

for the six months is primarily due to increased capitalized interest from

higher capital expenditures.

• Interest expense on long-term debt - the increases for the three months and

six months are primarily due to higher amounts of long-term debt outstanding

    in the current periods.




Financial Condition and Liquidity


Our financial strategy has continued to focus on maintaining a strong balance
sheet, ensuring sufficient cash resources and daily liquidity, accessing capital
markets at favorable times when needed, managing critical business risks, and
maintaining a balanced capital structure through the issuance of equity or
long-term debt securities or the repurchase of our equity securities. The need
for long-term capital is driven by the level of and timing of capital
expenditures and long-term debt maturities. Our issuance of long-term debt and
equity securities is subject to regulation by the NCUC.

The Merger Agreement includes certain restrictions, limitations and prohibitions
as to actions we may or may not take in the period prior to completion of the
Acquisition. Among other restrictions, the Merger Agreement limits, beyond
previously budgeted and planned amounts and allowed exceptions, our total
capital spending and the extent to which we can obtain financing through
long-term debt and equity. It also caps our cash dividend to no more than the
current annual per share dividend plus an increase of not more than $.04 per
fiscal year, with record dates and payment dates consistent with our current
dividend practices but allows for a stub period dividend payment to holders of
record of our shares of common stock immediately prior to consummation of the
Acquisition. At this time, as a result of the Acquisition, we do not anticipate

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modifying our 2016 financing strategy discussed below and do not expect a significant impact on our cash requirements and sources of liquidity.


To meet our capital and liquidity requirements outside of the long-term capital
markets, we rely on certain resources, including cash flows from operating
activities, cash generated from our investments in joint ventures and short-term
debt. Operating activities primarily provide the liquidity to fund our working
capital, a portion of our capital expenditures and other cash needs. We rely on
short-term debt together with long-term capital markets to provide a significant
source of liquidity to meet operating requirements that are not satisfied by
internally generated cash flows. Currently, cash flows from operations are not
adequate to finance the full cost of planned investments in customer growth,
pipeline integrity programs, system infrastructure and contributions to our
joint ventures.

The level of short-term debt can vary significantly due to changes in the
wholesale cost of natural gas and the level of purchases of natural gas supplies
for storage to serve customer demand. We pay our suppliers for natural gas
purchases before we collect our costs from customers through their monthly
bills. If wholesale gas prices increase, we may incur more short-term debt for
natural gas inventory and other operating costs since collections from customers
could be slower and some customers may not be able to pay their gas bills on a
timely basis.

We believe that the capacity of short-term credit available to us under our
revolving syndicated credit facility and our CP program and the issuance of
long-term debt and equity securities, together with cash provided by operating
activities, will continue to allow us to meet our needs for working capital,
capital expenditures, investments in joint ventures, anticipated debt
redemptions, dividend payments, employee benefit plan contributions and other
cash needs. Our ability to satisfy all of these requirements is dependent upon
our future operating performance and other factors, some of which we are not
able to control. These factors include prevailing economic conditions,
regulatory changes, the price and demand for natural gas and operational risks,
among others. Liquidity has been enhanced by reduced tax payments due to the
generation of federal net operating loss (NOL) carryforwards resulting from
bonus depreciation, as well as the ability to recover and earn on investments in
infrastructure related to our pipeline integrity programs through IMRs in North
Carolina and Tennessee. For further information on bonus depreciation, see the
following discussion of "Cash Flows from Operating Activities" in this Form
10-Q.


Short-Term Debt


We have an $850 million five-year revolving syndicated credit facility that
expires in December 2020 that has an option to request an expansion of financing
commitments by an additional $200 million. We pay an annual fee of $35,000 plus
8.5 basis points for any unused amount up to $850 million. The five-year
revolving syndicated credit facility contains normal and customary financial
covenants and expressly permits the Acquisition by Duke Energy.

We have an $850 million unsecured CP program that is backstopped by the
revolving syndicated credit facility. The amounts outstanding under the
revolving syndicated credit facility and the CP program, either individually or
in the aggregate, cannot exceed $850 million. The notes issued under the CP
program may have maturities not to exceed 397 days from the date of issuance.
Any borrowings under the CP program rank equally with our other unsecured debt.

We did not have any borrowings under the revolving syndicated credit facility
for the three months ended April 30, 2016. Highlights for our short-term debt
under our CP program as of April 30, 2016 and for the quarter ended April 30,
2016 are presented below.

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In thousands
End of period (April 30, 2016):
Amount outstanding                                     $ 390,000
Weighted average interest rate                               .58 %

During the period (February 1, 2016 - April 30, 2016):
Average amount outstanding                             $ 430,200
Minimum amount outstanding                               375,000
Maximum amount outstanding                               490,000
Minimum interest rate                                        .52 %
Maximum interest rate                                        .62 %
Weighted average interest rate                               .58 %

Maximum amount outstanding:
February 2016$ 490,000
March 2016                                               465,000
April 2016                                               405,000



As of April 30, 2016, we had $10 million available for letters of credit under
our revolving syndicated credit facility, of which $1.7 million were issued and
outstanding. The letters of credit are used to guarantee claims from
self-insurance under our general and automobile liability policies. As of
April 30, 2016, unused lines of credit available under our revolving syndicated
credit facility, including the issuance of the letters of credit, totaled $458.3
million.


Cash Flows from Operating Activities


The natural gas business is seasonal in nature. Operating cash flows may
fluctuate significantly during the year and from year to year due to working
capital changes within our utility and non-utility operations. The major factors
that affect our working capital are weather, natural gas purchases and prices,
natural gas storage activity, collections from customers and deferred gas cost
recoveries. We rely on operating cash flows and short-term debt to meet seasonal
working capital needs. The level of short-term debt can vary significantly due
to changes as discussed above. During our first and second quarters, we
generally experience overall positive cash flows from the sale of flowing gas
and gas withdrawal from storage and the collection of amounts billed to
customers during the November through March winter heating season. Cash
requirements generally increase during the third and fourth quarters due to
increases in natural gas purchases injected into storage, construction activity
and decreases in receipts from customers.

During the winter heating season, our trade accounts payable increases to
reflect amounts due to our natural gas suppliers for commodity and pipeline
capacity. The cost of natural gas can vary significantly from period to period
due to changes in the price of natural gas, which is a function of market
fluctuations in the commodity cost of natural gas, along with our changing
requirements for storage volumes. Differences between natural gas costs that we
have paid to suppliers and amounts that we have collected from customers are
included in regulatory deferred accounts as amounts due to or from customers.
These natural gas costs can cause cash flows to vary significantly from period
to period along with variations in the timing of collections from customers
under our gas cost recovery mechanisms.

Cash flows from operations are impacted by weather, which affects gas purchases
and sales. Warmer weather can lead to lower revenues from fewer volumes of
natural gas sold or transported. Colder weather can increase volumes sold to
weather-sensitive customers but may lead to conservation by customers in order
to reduce their heating bills. Regulatory margin stabilizing and cost recovery
mechanisms, such as decoupled tariffs and those that allow us to recover the gas
cost portion of bad debt expense, mitigate the impact that customer conservation
and higher bad debt expense may have on our results of operations.
Warmer-than-normal weather can lead to reduced operating cash flows, thereby
increasing the need for short-term bank borrowings to meet current cash
requirements.

Net cash provided by operating activities was $255.7 million and $364.3 million
for the six months ended April 30, 2016 and 2015, respectively. Net cash
provided by operating activities reflects an increase of $1.8 million in net
income for 2016

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compared with 2015 primarily due to increased margin and a decrease in utility
interest charges, partially offset by increased operating expenses. The effect
of changes in cash provided by operating activities is described below.


• Trade accounts receivable and unbilled utility revenues increased $28.9

million from October 31, 2015 primarily due to amounts billed to customers,

slightly offset by a decrease in unbilled revenues.

• Net amounts due from customers increased $27.5 million in the current period

primarily due to an increase in margin decoupling revenues, partially offset

by deferred gas cost collections and refunds through rates.

• Gas in storage decreased $36.1 million in the current period primarily due to

the withdrawal of storage volumes to meet customer sales during the winter

heating season of 2015-2016 and a decrease in the weighted average cost of

gas purchased for injections.

• Prepaid gas costs decreased $15.9 million in the current period primarily due

to gas being made available for sale during the period. Under some gas supply

asset management contracts, prepaid gas costs incurred during the summer

months represent purchases of gas that are not available for sale, and

therefore not recorded in inventory, until the start of the winter heating

season.

• Trade accounts payable decreased $14.3 million in the current period

primarily due to lower prices for natural gas.




The Protecting Americans from Tax Hikes Act of 2015 (the Act), enacted in
December 2015, retroactively extended the 50% bonus depreciation that expired in
December 2014, extended 50% bonus depreciation for qualified property placed in
service through December 2017 and provided for 40% and 30% bonus depreciation
for property placed in service in 2018 and 2019, respectively. Under the Act, we
were entitled to additional tax depreciation deductions for 2015. These
additional depreciation deductions resulted in generating a federal NOL in 2015.
We anticipate we will generate a NOL in 2016 due to bonus depreciation
deductions and that we will generate future taxable income sufficient to utilize
NOL tax carryforwards prior to the expiration of the carryforward periods.

In April 2016, the Internal Revenue Service (IRS) completed their field audit of
our 2012 NOL carryback claim, providing their audit report. Accordingly, we
reclassified $26 million of noncurrent refundable income taxes to "Income taxes
receivable" in "Current Assets" in the Condensed Consolidated Balance Sheets.
Since then, the Congressional Joint Committee on Taxation supported the
conclusions in the IRS audit report.

Our three state regulatory commissions approve rates that are designed to give
us the opportunity to generate revenues to cover our gas costs, fixed and
variable non-gas costs and earn a fair return for our shareholders. We have WNA
mechanisms in South Carolina and Tennessee that partially offset the impact of
colder- or warmer-than-normal weather on bills rendered in November through
March for residential and commercial customers in South Carolina and in October
through April for residential and commercial customers in Tennessee. The WNA
mechanisms in South Carolina and Tennessee generated charges to customers of
$13.2 million and credits to customers of $6.9 million in the six months ended
April 30, 2016 and 2015, respectively. In Tennessee, adjustments are made
directly to individual customer monthly bills. In South Carolina, the
adjustments are calculated at the individual customer level but are recorded in
"Amounts due from customers" in "Regulatory Assets" or "Amounts due to
customers" in "Regulatory Liabilities," as presented in Note 3 to the condensed
consolidated financial statements in this Form 10-Q, for subsequent collection
from or refund to all customers in the class. The margin decoupling mechanism in
North Carolina provides for the collection of our approved margin from
residential and commercial customers independent of weather and consumption
patterns. The margin decoupling mechanism increased margin by $23 million and
decreased margin by $30.4 million in the six months ended April 30, 2016 and
2015, respectively. Our gas costs are recoverable through PGA procedures and are
not affected by the WNA or the margin decoupling mechanisms.

The financial condition of the natural gas marketers and pipelines that supply
and deliver natural gas to our distribution system can increase our exposure to
supply and price fluctuations. We believe our risk exposure to the financial
condition of the marketers and pipelines is not significant based on our receipt
of the products and services prior to payment and the availability of other
marketers of natural gas to meet our firm supply needs, if necessary. We have
regulatory commission approval in North Carolina, South Carolina and Tennessee
that places tighter credit requirements on the retail natural gas marketers that
schedule gas for transportation service on our system.

We face competition from other energy products, such as electricity and propane,
in the residential and commercial customer markets. The most significant product
competition is with electricity for space heating, water heating and cooking.
Competition for space heating and general household and small commercial energy
needs generally occurs at the initial installation phase when the customer or
builder makes decisions as to which types of equipment to install. Customers
generally use the chosen energy source for the life of the equipment. Numerous
factors can influence customer demand for natural gas, including price, value,
availability, environmental attributes, comfort, convenience, reliability and
energy efficiency. Increases in the price of natural gas can negatively impact
our competitive position by decreasing the price benefits of natural gas to the
consumer. This

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can impact our cash needs if customer growth slows, resulting in reduced capital
expenditures, or if customers conserve, resulting in reduced gas purchases and
customer billings.

In the industrial market, many of our customers are capable of burning a fuel
other than natural gas, with fuel oil being the most significant competing
energy alternative. Our ability to maintain industrial market share is largely
dependent on the relative prices of energy. The relationship between supply and
demand has the greatest impact on the price of natural gas. The price of oil
depends upon a number of factors beyond our control, including the relationship
between worldwide supply and demand and the policies of foreign and domestic
governments and organizations, as well as the value of the U.S. dollar versus
other currencies. Our liquidity could be impacted, either positively or
negatively, as a result of alternative fuel decisions made by industrial
customers.

In an effort to keep customer rates competitive and to maximize earnings, we
continue to implement business process improvement and O&M cost management
programs to capture operational efficiencies while improving customer service
and maintaining a safe and reliable system.

On March 17, 2016, the Pipeline and Hazardous Materials Safety Administration
(PHMSA), Department of Transportation, issued a Notice of Proposed Rulemaking
(NPRM) that proposes to revise the pipeline safety regulations applicable to the
safety of onshore gas transmission and gathering pipelines. If enacted as
proposed, this rulemaking could result in an increase to our O&M expenses. We
and the natural gas industry are preparing comments to this NPRM with comments
due to PHMSA on July 7, 2016.


Cash Flows from Investing Activities

Net cash used in investing activities was $263.5 million and $222 million for
the six months ended April 30, 2016 and 2015, respectively. Net cash used in
investing activities was primarily for utility capital expenditures. Gross
utility capital expenditures for the six months ended April 30, 2016 and 2015
were $254.1 million and $204.3 million, respectively, primarily for system
integrity projects, including natural gas infrastructure projects in 2016.

We have a substantial capital expansion program for construction of transmission
and distribution facilities, purchase of equipment and other general
improvements. Our program supports our system infrastructure, the growth in our
customer base and large amounts for pipeline integrity, safety and compliance
programs, including systems and technology infrastructure to enhance our
pipeline system and integrity through a comprehensive work and asset management
system. Significant utility construction expenditures are expected for growth
and system integrity and are part of our long-range forecasts that are prepared
at least annually and typically covering a forecast period of five years. We are
contractually obligated to expend capital as the work is completed.

Detail of our forecasted fiscal 2016 - 2018 capital expenditures, including an
allowance for funds used during construction, and our commitments to fund equity
method investments is presented below. We intend to fund capital expenditures in
a manner that maintains our targeted capitalization ratio of 50 - 60% in total
debt and 40 - 50% in common equity. A portion of the funding for capital
expenditures is derived from operations, including lower federal income tax
payments due to accelerated depreciation.

In millions                                                      2016     2017     2018
Customer growth and other                                       $ 310    $ 325    $ 385
System integrity                                                  260      275      195
Total forecasted utility capital expenditures                     570      600      580
Forecasted funding of construction in equity method investments    60       30      200
Total                                                           $ 630    $ 630    $ 780



In June 2014, we executed an agreement to construct approximately 1.5 miles of
natural gas transmission pipeline and associated compression to serve Duke
Energy's W.S. Lee power generation facility near Anderson, South Carolina. Our
total investment is estimated to be $38 million, with expenditures occurring
primarily in our fiscal year 2016, and is included in the table above in the
line "Customer growth and other." This agreement is supported by a long-term
natural gas service agreement with fixed monthly charges and has a target
in-service date of May 2017.

Also, in May 2015, we executed an agreement to construct a delivery station and
associated compression to provide additional service to Duke Energy's power
generation facility at their Sutton site near Wilmington, North Carolina. Our
total investment is

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estimated to be $13 million with expenditures occurring primarily in our fiscal
years 2016 and 2017, and is included in the table above in the line "Customer
growth and other." This agreement is supported by a long-term natural gas
service agreement with fixed monthly charges and has a target in-service date of
June 2017.

We are invested as equity members in two interstate natural gas pipeline
projects that are in the development stage. As a member of each of these limited
liability companies, we are committed to fund construction in proportion to our
ownership interests. For further information on these equity investments, see
Note 13 to the condensed consolidated financial statements in this Form 10-Q.
Details of the project costs for these investments are presented below.
                                                 Constitution               

ACP

In millions                                (24% ownership interest)       (10% ownership interest)
Our anticipated contributions for total
project costs                             $                   229.3     $                450 - 500
Anticipated in-service date                     second half of 2018                      late 2018
Our contributions:
 For the six months ended April 30, 2016  $                     9.7          $                10.4
 Over life of project to date             $                    82.4          $                21.0



In connection with the ACP project, we plan to make additional utility capital
investments in our natural gas delivery system, predominately in fiscal 2017 and
2018, of approximately $190 million in order to redeliver ACP gas supplies to
local North Carolina markets we serve. Of that amount, approximately $170
million will be supported by third-party contracts. These expenditures are
driving the increase in utility capital expenditures for fiscal 2018 for
customer growth as shown above in the schedule of forecasted capital
expenditures.


Assessment of Our Investment in Constitution

On April 22, 2016, the New York State Department of Environmental Conservation
(NYSDEC) denied Constitution's application for a necessary water quality
certification for the New York portion of the Constitution pipeline.
Constitution has filed legal actions in the U.S District Court for the Northern
District of New York and in the U.S Court of Appeals for the Second Circuit
challenging the legality and appropriateness of the NYSDEC's decision. Both
courts have granted Constitution's motions to expedite the schedules for the
legal actions.

Constitution has revised its target in-service date to the second half of 2018,
assuming that the challenge process is satisfactorily and promptly concluded.
Failure to ultimately win the legal actions as well as other efforts to obtain
the necessary permit would result in recording a non-cash impairment charge of
substantially all of our investment in the capitalized project costs. Our
investment totaled $94.8 million as of April 30, 2016, the write off of which
could materially adversely impact our earnings.

Based on the NYSDEC's actions, we evaluated our investment in the Constitution
project for other-than-temporary impairment (OTTI). We evaluate our equity
method investments for OTTI on a quarterly basis when events or changes in
circumstances indicate, in our management's judgment, that the carrying value of
such investments may have experienced an other-than-temporary decline in value.
When evidence of loss has occurred, we compare our estimate of fair value of the
investment to our carrying value and if our consideration of the decline in
value is deemed to be other-than-temporary, we would record a non-cash
impairment charge that would reduce income and our investment in the joint
venture. Generally, an income approach is used where significant judgments and
assumptions include future cash flows of the project and the appropriate
discount rate. If a comparable investment is available, a market approach could
be used to validate the income approach. Different assumptions could affect the
timing and amount of any charge recorded in a period.

Given the nature of the equity method investment, our impairment assessment used
a discounted cash flow income approach, including consideration of the severity
and duration of any decline in fair value of our investment in the project. Our
key inputs involve significant management judgments and estimates and included
projections of the project's cash flows, selection of a discount rate and
probability weighting of potential outcomes of legal and regulatory proceedings.
At this time, we believe we do not have an OTTI and have not recorded any
impairment charge to reduce the carrying value of our investment. Our evaluation
considered that the pending legal and regulatory proceedings are at very early
stages given the recent actions of the NYSDEC in late April 2016. Further, the
courts have granted Constitution's motions to expedite the schedules for the
legal actions. However, to the extent that the legal and regulatory proceedings
have unfavorable outcomes, or if Constitution concludes that the project is not
viable or does not go forward as legal and regulatory actions progress, our
conclusions with respect to OTTI could change and may require that we recognize
an impairment charge of up to our recorded investment in the

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project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period.

Qualitative factors that we considered in our OTTI analysis included, but are not limited to:

• The legal actions filed by Constitution and anticipated duration of the

proceedings,

• The commitment of the members to the project,

• The commitment of the customers/shippers to the project, one of whom is a

25% member,

• Prior FERC approval of the project,

•      The economic viability of the project to move extensive supplies of
       Marcellus gas into New England markets, considering the lack of

alternative capacity in the region, even considering potentially higher

costs resulting from delays in the project.

We believe that the denial of the certification and resulting delay in the project's in-service date will not have a material impact on the Acquisition by Duke Energy that is expected to close by the end of 2016.

With the project on hold, our funding of project costs is on hold until the
resolution of the legal actions. We are contractually obligated to provide
funding of required operating costs, including our ownership percentage of legal
expenses to obtain the necessary permitting for the project and including
project costs incurred prior to the denial of the water permit. Fiscal 2016
pre-tax earnings from our Constitution investment are expected to be
approximately $9 million less than previously forecast as a result of no
capitalized costs being recorded to income and additional legal expenses and
other O&M costs, and we expect significantly reduced earnings from the
Constitution investment to continue into 2017 until resolution of the legal and
regulatory actions. If the legal actions result in the most severe outcome where
the project is abandoned, Constitution is obligated under various contracts to
pay breakage fees that we would be obligated to fund up to our ownership
percentage of 24%, or potentially up to approximately $10 million for us.

Cash Flows from Financing Activities

Net cash provided by (used in) financing activities was $6.3 million and
$(138.6) million for the six months ended April 30, 2016 and 2015, respectively.
Funds are primarily provided from long-term debt securities, short-term
borrowings, and the issuance of common stock through our dividend reinvestment
and stock purchase plan (DRIP) and our employee stock purchase plan (ESPP). We
may sell common stock and long-term debt, when market and other conditions favor
such long-term financing to maintain our target capital structure of 50 - 60% in
total debt and 40 - 50% in common equity. Funds are primarily used to finance
capital expenditures, retire long-term debt maturities, pay down outstanding
short-term debt, repurchase common stock under the common stock repurchase
program when required to maintain target capital structure, pay quarterly
dividends on our common stock and for other general corporate purposes.

Outstanding debt under our CP program increased from $340 million as of
October 31, 2015 to $390 million as of April 30, 2016 primarily due to seasonal
requirements for utility capital expenditures, investments in our equity method
investments and dividend payments. For further information on short-term debt,
see Note 6 to the condensed consolidated financial statements in this Form 10-Q
and the previous discussion of "Short-Term Debt" in "Financial Condition and
Liquidity."

We have a combined debt and equity shelf registration statement with the SEC
that became effective on June 6, 2014. The NCUC approved debt and equity
issuances under this shelf registration up to $1 billion during its three-year
life. Unless otherwise specified at the time such securities are offered for
sale, the net proceeds from the sale of the securities will be used to finance
capital expenditures, to repay outstanding short-term, unsecured notes under our
CP program, to refinance other indebtedness, to repurchase our common stock, to
pay dividends and for general corporate purposes. Pending such use, we may
temporarily invest any net proceeds that are not applied to the purposes
mentioned above in investment-grade securities.

Under this shelf registration statement, we established an ATM equity sales
program, including a forward sale component, by entering into separate ATM
Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce,
Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP
Morgan), in their capacity as agents and/or principals (Agents). Under the terms
of the Sales Agreements, we may issue and sell, through either of the Agents,
shares of our common stock, up to an aggregate sales price of $170 million
(subject to certain exceptions) during the period that began in January 2015 and
ending October 31, 2016. Any such shares of our common stock would be offered
and sold under our shelf registration statement and related prospectuses.

Our ability to sell our common stock up to the specified $170 million limit will
depend on a variety of circumstances, including equity market conditions,
trading volume in our common stock and other factors outside our control. We
cannot predict the

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timing of any such sales or the aggregate amount of shares that may be sold
under the ATM program. In addition, the ATM program allows us, at our option, to
sell shares pursuant to FSAs with affiliates of our sales agents (forward
counterparties) under the related ATM program sales agreements. Shares sold
pursuant to FSAs settle on dates specified by us, which may be substantially
after the sales occur but not later than October 31, 2016, subject to certain
exceptions. As of April 30, 2016, all FSAs that have been settled were settled
in shares, and we intend to settle any current and future FSAs in shares. Under
the terms of the Merger Agreement, we would need to obtain Duke Energy's prior
consent to cash or net settle a FSA.

During the six months ended April 30, 2016, we sold 360,000 shares and 620,000
shares of our common stock under FSAs with JP Morgan and Merrill, respectively,
that must be settled by the date discussed above. Under the terms of the FSAs,
at our election, we may physically settle in shares, cash or net settle for all
or a portion of our obligation. We expect to settle the FSAs by delivering
shares prior to the closing of the Acquisition or October 31, 2016, whichever
occurs first. If we physically settle by issuing shares to the forward
counterparties, the forward counterparties will, at settlement, pay us the
proceeds less certain adjustments for its sale of the borrowed shares to the
underwriters, which is anticipated to be approximately $55.9 million as of
October 31, 2016. During the period ended April 30, 2016, we did not pay any
compensation to the sales agents.

Upon settlement, we will use the net proceeds from these equity transactions to
finance capital expenditures, repay outstanding notes under our unsecured CP
program and for general corporate purposes. We will not recognize the proceeds
from the forward sales nor record the issuance of such shares until the date of
settlement. As of April 30, 2016, we have approximately $56.2 million remaining
under the ATM program. For further information on our common stock and for more
details on equity issuance transactions, see Note 7 to the condensed
consolidated financial statements in this Form 10-Q.

As of April 30, 2016, we have $544.1 million remaining under the shelf
registration statement for debt and equity issuances as approved by the NCUC. We
plan to issue equity capital in our fiscal year 2016, at such amounts to support
our capital investment program and maintain our target capital structure as
discussed above. We continually monitor customer growth trends and investment
opportunities in our markets and the timing of any infrastructure investments
that would require the need for additional long-term debt. In addition to
issuing common stock under our DRIP and ESPP as described above, we expect to
continue to issue common stock under our ATM program as described above through
the end of the third quarter of fiscal 2016.

From time to time, we have repurchased shares of common stock under our Common
Stock Open Market Purchase Program as described in Part II, Item 2 in this Form
10-Q. We do not anticipate repurchasing any of our common stock in fiscal year
2016.

During the six months ended April 30, 2016 and 2015, we issued $11.9 million and $12.9 million, respectively, of common stock through DRIP and ESPP.

We have paid quarterly dividends on our common stock since 1956. Provisions
contained in certain note agreements under which certain long-term debt was
issued restrict the amount of cash dividends that may be paid. As of April 30,
2016, our ability to pay dividends was not restricted by these note agreements.
On June 7, 2016, the Board of Directors declared a quarterly dividend on common
stock of $.34 per share, payable July 15, 2016 to shareholders of record at the
close of business on June 24, 2016. For further information on long-term debt,
see Note 5 to the condensed consolidated financial statements in this Form 10-Q.

Our targeted capitalization ratio is 50 - 60% in total debt and 40 - 50% in
common equity. The components of our total debt outstanding (short-term debt and
gross long-term debt) to our total capitalization as of April 30, 2016 and 2015,
and October 31, 2015, are summarized in the table below.
                                  April 30                      October 31                      April 30
In thousands                2016         Percentage        2015         Percentage        2015         Percentage
Short-term debt         $   390,000           11 %     $   340,000           10 %     $   255,000            8 %
Current portion of
long-term debt               40,000            1 %          40,000            1 %               -            - %
Long-term debt,
principal                 1,535,000           44 %       1,535,000           46 %       1,425,000           46 %
Total debt                1,965,000           56 %       1,915,000           57 %       1,680,000           54 %
Common stockholders'
equity                    1,551,292           44 %       1,426,312           43 %       1,432,560           46 %
Total capitalization
(including short-term
debt)                   $ 3,516,292          100 %     $ 3,341,312          100 %     $ 3,112,560          100 %



Credit ratings impact our ability to obtain short-term and long-term financing
and the cost of such financings. The borrowing costs under our revolving
syndicated credit facility and our unsecured CP program are based on our credit
ratings, and consequently, any decrease in our credit ratings would increase our
borrowing costs. We believe our credit ratings will allow us to continue to have
access to the capital markets, as and when needed, at a reasonable cost of
funds.

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The lenders under our revolving syndicated credit facility and our unsecured CP
program are major financial institutions, all of which have investment-grade
credit ratings as of April 30, 2016. It is possible that one or more lending
commitments could be unavailable to us if the lender defaulted due to lack of
funds or insolvency. However, based on our current assessment of our lenders'
creditworthiness, we believe the risk of lender default is minimal.

As of April 30, 2016, all of our long-term debt was unsecured. Our long-term
debt is rated by two rating agencies, Standard & Poor's Ratings Services (S&P)
and Moody's Investors Service (Moody's). Our current debt ratings are all
considered investment grade and are as follows.
                           S&P   Moody's
Unsecured long-term debt    A      A2
Commercial paper           A1      P1



Subsequent to the announcement of the Acquisition, S&P affirmed our A rating for
our senior unsecured long-term debt but placed it on credit watch with negative
implications. Currently, Moody's has maintained its stable outlook for our
long-term
debt. Credit ratings and outlooks are opinions of the rating agencies and are
subject to their ongoing review. A significant decline in our operating
performance, a significant negative change in our capital structure, a change
from the constructive regulatory environments in which we operate, a significant
reduction in our liquidity or a methodological change at the rating agencies
themselves could trigger a negative change in our ratings outlook or even a
reduction in our credit ratings by the rating agencies. This would mean more
limited access to the private and public credit markets and an increase in the
costs of such borrowings. There is no guarantee that a rating will remain in
effect for any given period of time or that a rating will not be lowered or
withdrawn by a rating agency if, in its judgment, circumstances warrant a
change.

We are subject to default provisions related to our long-term debt and
short-term borrowings. Failure to satisfy any of the default provisions may
result in total outstanding issues of debt becoming due. There are cross-default
provisions in all of our debt agreements. As of April 30, 2016, there has been
no event of default giving rise to acceleration of our debt.

The Acquisition would constitute a change in control under the note agreements
under which our $160 million of 4.24% Senior Notes due 2021, $100 million of
3.47% Senior Notes due 2027 and $200 million of 3.57% Senior Notes due 2027 were
issued. While the Acquisition would not constitute an event of default, upon
closing of the Acquisition, we would be required to offer to prepay these notes
to the noteholders. Within fifteen business days after the change in control, we
must send to each noteholder an offer to prepay 100% of the notes, with a
prepayment date that is between twenty and thirty days after the date of the
offer. In order to accept the offer to prepay, the noteholder must provide a
notice of acceptance to us at least five business days prior to the proposed
prepayment date. We must prepay noteholders, who have properly accepted the
offer, at 100% of the principal amount of the notes, plus interest on the notes
accrued to the date of prepayment. A failure of a noteholder to accept the offer
to prepay will be deemed a rejection of the offer.

Estimated Future Contractual Obligations

During the three months ended April 30, 2016, there were no material changes to
our estimated future contractual obligations in Management's Discussion and
Analysis in this Form 10-Q compared to the disclosure provided in our Form 10-K
for the year ended October 31, 2015. Refer to the "Cash Flows from Investing
Activities" section of this Form 10-Q for an updated payments schedule of
capital contributions to joint ventures related to a shift in forecasted funding
for construction in the Constitution equity method investment.

Off-balance Sheet Arrangements

From time to time, we enter into letters of credit, surety bonds and operating
leases, as well as credit support arrangements on behalf of a wholly-owned
subsidiary that holds one of our equity-method investments. None of these
existing arrangements are material to our results of operations, cash flows or
financial position. The letters of credit and surety bonds are discussed in Note
6 and Note 10, respectively, to the condensed consolidated financial statements
in this Form 10-Q. The operating leases were discussed in Note 9 to the
consolidated financial statements in our Form 10-K for the year ended
October 31, 2015. The credit support arrangement and indemnification agreement
are discussed in Note 13 to the condensed consolidated financial statements in
this Form 10-Q.


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Critical Accounting Policies and Estimates

We prepare the consolidated financial statements in conformity with accounting
principles generally accepted in the United States of America. We make estimates
and assumptions that affect the reported amounts of assets and liabilities as of
the date of the financial statements and the reported amounts of revenues and
expenses during the periods reported. Actual results may differ significantly
from these estimates and assumptions. We base our estimates on historical
experience, where applicable, and other relevant factors that we believe are
reasonable under the circumstances. On an ongoing basis, we evaluate estimates
and assumptions and make adjustments in subsequent periods to reflect more
current information if we determine that modifications in assumptions and
estimates are warranted.

Management considers an accounting estimate to be critical if it requires
assumptions to be made that were uncertain at the time the estimate was made,
and changes in the estimate or a different estimate that could have been used,
would have had a material impact on our financial condition or results of
operations. We consider regulatory accounting, revenue recognition, and pension
and postretirement benefits to be our critical accounting estimates. Management
is responsible for the selection of these critical accounting estimates
presented in our Form 10-K for the year ended October 31, 2015 in Management's
Discussion and Analysis of Financial Condition and Results of Operations.
Management has discussed these critical accounting estimates with the Audit
Committee of the Board of Directors. There have been no changes in our critical
accounting policies and estimates discussed above since October 31, 2015, except
as discussed below.

As discussed in our Form 10-K for the year ended October 31, 2015 in
Management's Discussion and Analysis of Financial Condition and Results of
Operations, beginning in fiscal year 2016, we changed the methodology we use to
calculate the periodic net benefit cost for our defined benefit pension plan. We
replaced the zero-coupon spot rate yield curve as the basis to estimate the
service and interest cost components with a full yield curve methodology. This
methodology applies specific spot rates along the yield curve to determine the
benefit obligations of the relevant projected cash flows. This change improves
the correlation between projected benefit cash flows and the corresponding yield
curve spot rates and provides a more precise measurement of service and interest
costs. This change did not affect the measurement of our total benefit
obligations as the change in the service and interest costs is completely offset
by the actuarial (gain) loss reported. We accounted for this change as a change
in estimate and, accordingly, accounted for it prospectively beginning in 2016.

Effective in our first quarter 2016, we have long-dated, fixed quantity natural
gas supply contracts which are accounted for as derivatives. Our accounting of
derivatives and the related fair value of the derivatives is a critical
accounting estimate. We enter into both physical and financial contracts for the
purchase and sale of natural gas. Fixed quantity gas supply contracts, as well
as financial contracts that we purchase to hedge commodity price risks under our
hedging programs established under state regulatory authority, are derivative
instruments subject to fair value accounting and are recorded on the balance
sheet at fair value. We record the changes in the fair value of these derivative
instruments recoverable from or refundable to customers as regulatory assets or
liabilities. Accordingly, the operation of the hedging programs on the regulated
utility segment as a result of the use of these financial derivatives is
initially deferred as amounts due from customers included as "Regulatory Assets"
or amounts due to customers included as "Regulatory Liabilities" as presented in
Note 3 to the condensed consolidated financial statements in this Form 10-Q and
recognized in the Condensed Consolidated Statements of Comprehensive Income as a
component of "Cost of Gas" when the related costs are recovered through our
rates. For the gas supply derivatives, we record the change in fair value as
current and noncurrent regulatory assets or liabilities, the detail of which is
presented in Note 3 to the condensed consolidated financial statements in this
Form 10-Q, with corresponding current and noncurrent supply derivative
liabilities recognized in the Condensed Consolidated Balance Sheets.

Fair value is based on actively quoted market prices when they are available. In
the absence of actively quoted market prices, we seek indicative price
information from external sources, including broker quotes and industry
publications. If pricing information from external sources is not available,
internal models are used to estimate prices based on available historical and
near-term future price information and/or the use of statistical methods. These
inputs are used with industry standard valuation methodologies. See Note 1 and
Note 9 to the condensed consolidated financial statements in this Form 10-Q for
a discussion of our valuation methodologies.

Our judgment is required in determining the appropriate accounting treatment for
our derivative instruments. This judgment involves various factors, including
our ability to: (i) evaluate contracts and other activities as derivative
instruments subject to the accounting guidance; (ii) determine whether or not
our derivative instruments are recoverable from or refundable to customers in
future periods and (iii) derive the estimated fair value of our derivative
instruments.

As a result of the NYSDEC denying the water permit for the Constitution project
on April 22, 2016, which is currently on hold until the resolution of certain
legal actions, we evaluated our investment in the Constitution project for OTTI.
Our investment is accounted for under the equity method and is recorded at cost
plus post-acquisition contributions and earnings based on our

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ownership share less any distributions received from the joint venture
investment, and if applicable, less any impairment in value of the investment.
Given the nature of the equity method investment, our impairment assessment used
a discounted cash flow income approach, including the severity and duration of
any decline in fair value of our investment in the project. Our approach
involved significant management judgment and estimates in determining key inputs
to the fair value analysis, including projections of the project's cash flows,
selection of a discount rate and probability weighting of potential outcomes of
legal and regulatory proceedings. At this time, we believe we do not have an
impairment based on our assessment. Our evaluation considered that the pending
legal and regulatory proceedings are at very early stages given the recent
actions of the NYSDEC in late April 2016. Further, the courts have granted
Constitution's motions to expedite the schedules for the legal actions. However,
to the extent that the legal and regulatory proceedings have unfavorable
outcomes, or if Constitution concludes that the project is not viable or does
not go forward as legal and regulatory actions progress, our conclusions with
respect to OTTI could change and may require that we recognize an impairment
charge of up to our recorded investment in the project, net of any cash and
working capital returned. We will continue to monitor and update our OTTI
analysis as required. Different assumptions could affect the timing and amount
of any charge recorded in a period. For further information on this investment,
see Note 13 to the condensed consolidated financial statements in this Form
10-Q.


Accounting Guidance

For information regarding recently issued accounting guidance, see Note 1 to the condensed consolidated financial statements in this Form 10-Q.

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