Item 2. 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.
|
|
|
•
|
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;
|
|
|
•
|
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.
|
|
|
|
|
|
|
|
Assets
|
|
Earnings
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,
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
|
|
|
•
|
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
|
%
|
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
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
%
|
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.
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.
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
Percent
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
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.
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.
|
|
|
•
|
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.
|
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.
|
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
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.
|
|
|
|
|
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
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
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
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
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
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.
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.
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
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.