UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark One)
|
|
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the fiscal year ended October 31, 2010
or
|
|
|
|
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
For the transition period from
to
Commission file number 1-6196
Piedmont Natural Gas Company, Inc.
(Exact name of registrant as specified in its charter)
|
|
|
|
|
North Carolina
|
|
56-0556998
|
|
|
|
|
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
|
|
|
|
|
4720 Piedmont Row Drive, Charlotte, North Carolina
|
|
28210
|
|
|
|
|
|
(Address of principal executive offices)
|
|
(Zip Code)
|
Registrant’s telephone number, including area code (704) 364-3120
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
|
|
|
|
|
Title of each class
|
|
Name of each exchange on which registered
|
|
|
|
|
|
Common Stock, no par value
|
|
New York Stock Exchange
|
Indicate by check mark if the registrant is a well-known seasoned issuer as defined in
Rule 405 of the Securities Act. Yes
þ
No
o
Indicate by check mark if the registrant is not required to file reports pursuant to section
13 or 15 (d) of the Act. Yes
o
No
þ
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
þ
No
o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Website, if any, every Interactive Data file required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or such
shorter period that the registrant was required to submit and post such files). Yes
þ
No
o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.
þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a
smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”
and “smaller reporting company” in
Rule 12b-2 of the Exchange Act.
|
|
|
|
|
|
|
|
|
Large accelerated filer
þ
|
|
Accelerated filer
o
|
|
Non-accelerated filer
o
(Do not check if a smaller reporting company)
|
|
Smaller reporting company
o
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes
o
No
þ
State the aggregate market value of the voting common equity held by non-affiliates of
the registrant as of April 30, 2010.
Common Stock, no par value — $1,952,780,258
Indicate the number of shares outstanding of each of the registrant’s classes of common stock,
as of the latest practicable date.
|
|
|
|
|
Class
|
|
Outstanding at December 17, 2010
|
|
|
|
|
|
Common Stock, no par value
|
|
72,310,563
|
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Shareholders on March 4, 2011, are
incorporated by reference into Part III.
Piedmont Natural Gas Company, Inc.
2010 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
PART I
Item 1. Business
Piedmont Natural Gas Company, Inc. (Piedmont) was incorporated in New York in 1950 and began
operations in 1951. In 1994, we merged into a newly formed North Carolina corporation with the
same name for the purpose of changing our state of incorporation to North Carolina.
Piedmont 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 51,600 customers served by
municipalities who are our wholesale customers. We are invested in joint venture, energy-related
businesses, including unregulated retail natural gas marketing, interstate natural gas storage and
intrastate natural gas transportation.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. We
provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte,
Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine,
Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro
in North Carolina. In North Carolina, we also provide wholesale natural gas service to the cities
of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of
Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.
We have two reportable business segments, regulated utility and non-utility activities. The
regulated utility segment is the largest segment of our business with approximately 97% of our
consolidated assets. Factors critical to the success of the regulated segment include operating a
safe, reliable natural gas distribution system and the ability to recover the costs and expenses of
the business in the rates charged to customers. For 2010, our earnings before taxes, including the
gain from the sale of half of our ownership interest in SouthStar Energy Services LLC (SouthStar)
of $49.7 million, were $205.6 million, 67% of which came from our regulated utility segment. The
non-utility activities segment consists of our equity method investments in joint venture,
energy-related businesses that are involved in unregulated retail natural gas marketing and
regulated interstate natural gas storage and intrastate natural gas transportation. For 2010, the
earnings before taxes from our non-utility activities segment, including the gain from the sale of
half of our ownership interest in SouthStar, was 33%, with 4% from regulated non-utility activities
and 29% from unregulated non-utility activities.
The generally accepted accounting principles presentation does not adequately reflect our
segments because of the inclusion of the gain from the sale of half of our ownership interest in
SouthStar, which is in our non-utility activities segment. Excluding this gain for the year ended
October 31, 2010, 85% of our earnings before taxes came from our regulated utility segment, and
earnings before taxes from our non-utility activities segment was 15%, with 5% from regulated
non-utility activities and 10% from unregulated non-utility activities. Operations of both
segments are conducted within the United States of America. For further information on equity
method investments and business segments, see Note 11 and Note 12, respectively, to the
consolidated financial statements.
1
Operating revenues shown in the consolidated statements of income represent revenues from the
regulated utility segment. The cost of purchased gas is a component of operating revenues.
Increases or decreases in prudently incurred purchased gas costs from suppliers are passed on to
customers through purchased gas adjustment procedures. Therefore, our operating revenues are
impacted by changes in gas costs as well as by changes in volumes of gas sold and transported. For
the year ended October 31, 2010, 48% of our operating revenues were from residential customers, 28%
from commercial customers, 10% from large volume customers, including industrial, power generation
and resale customers, and 14% from secondary market activities. Secondary market transactions
consist of off-system sales and capacity release arrangements and are part of our utility gas
supply management program with regulator-approved sharing mechanisms between our utility customers
and our shareholders. Operations of the non-utility activities segment are included in the
consolidated statements of income in “Income from equity method investments” and “Non-operating
income.”
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. We are also regulated by the NCUC as to the issuance of
securities. We are also subject to or affected by various federal regulations. 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 purchase and sale
and the prices paid for the interstate transportation and storage of natural gas, regulations of
the 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. In addition, we
are subject to numerous regulations, such as those relating to employment practices, which are
generally applicable to companies doing business in the United States of America.
We hold non-exclusive franchises for natural gas service in many of the communities we serve,
with expiration dates from 2011 to 2058. The franchises are adequate for the operation of our gas
distribution business and do not contain materially burdensome restrictions or conditions.
Nineteen franchise agreements have expired as of October 31, 2010. We continue to operate in those
areas pursuant to the provisions of the expired franchises with no significant impact on our
business. Four franchise agreements will expire during the 2011 fiscal year. The likelihood of
cessation of service under an expired franchise is remote. We believe that these franchises will
be renewed or that service will be continued in the ordinary course of business under our
state-granted franchise rights without specific franchise agreements with each city or
municipality, with no material adverse impact on us.
The natural gas distribution business is seasonal in nature as variations in weather
conditions generally result in greater revenues and earnings during the winter months when
temperatures are colder. For further information on weather sensitivity and the impact of
seasonality on working capital, see “Financial Condition and Liquidity” in Item 7 of this Form
10-K. As is prevalent in the industry, we inject natural gas into storage during the summer months
(principally April through October) when customer demand is lower for withdrawal from storage
during the winter heating season (principally November through March) when customer demand is
higher. During the year ended October 31, 2010, the amount of natural gas in storage varied from
2
13.3 million dekatherms (one dekatherm equals 1,000,000 BTUs) to 26.9 million dekatherms, and
the aggregate commodity cost of this gas in storage varied from $77.5 million to $145.9 million.
During the year ended October 31, 2010, 154.3 million dekatherms of gas were sold to
or transported for large volume customers compared with 123.1 million dekatherms in 2009.
Of these volumes sold to or transported for large volume customers, we transported 63
million dekatherms this year to power generation facilities as compared with 39.6 million
dekatherms in the prior year. The margin earned from power generation customers does not
vary significantly with volumes. Deliveries to temperature-sensitive residential and
commercial customers, whose consumption varies with the weather, totaled 98.3 million
dekatherms in 2010, compared with 93.8 million dekatherms in 2009. Weather, as measured by
degree days, was 6% colder than normal in 2010 and 3% colder than normal in 2009.
3
The following is a five-year comparison of operating statistics for the years ended October
31, 2006 through 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Operating Revenues (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales and Transportation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
$
|
743,346
|
|
|
$
|
787,994
|
|
|
$
|
813,032
|
|
|
$
|
743,637
|
|
|
$
|
841,051
|
|
|
Commercial
|
|
|
428,085
|
|
|
|
462,160
|
|
|
|
503,317
|
|
|
|
418,426
|
|
|
|
498,956
|
|
|
Industrial
|
|
|
116,122
|
|
|
|
126,855
|
|
|
|
209,341
|
|
|
|
190,204
|
|
|
|
205,384
|
|
|
For Power Generation
|
|
|
21,708
|
|
|
|
19,609
|
|
|
|
25,266
|
|
|
|
29,135
|
|
|
|
22,963
|
|
|
For Resale
|
|
|
11,061
|
|
|
|
11,746
|
|
|
|
12,326
|
|
|
|
13,907
|
|
|
|
11,342
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,320,322
|
|
|
|
1,408,364
|
|
|
|
1,563,282
|
|
|
|
1,395,309
|
|
|
|
1,579,696
|
|
|
Secondary Market Sales
|
|
|
224,973
|
|
|
|
221,300
|
|
|
|
515,968
|
|
|
|
308,904
|
|
|
|
337,278
|
|
|
Miscellaneous
|
|
|
7,000
|
|
|
|
8,452
|
|
|
|
9,858
|
|
|
|
7,079
|
|
|
|
7,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,552,295
|
|
|
$
|
1,638,116
|
|
|
$
|
2,089,108
|
|
|
$
|
1,711,292
|
|
|
$
|
1,924,628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Volumes — Dekatherms
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
System Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
58,327
|
|
|
|
55,298
|
|
|
|
51,909
|
|
|
|
50,072
|
|
|
|
49,119
|
|
|
Commercial
|
|
|
39,994
|
|
|
|
38,526
|
|
|
|
36,766
|
|
|
|
33,647
|
|
|
|
34,476
|
|
|
Industrial
|
|
|
82,805
|
|
|
|
74,363
|
|
|
|
81,780
|
|
|
|
79,266
|
|
|
|
80,490
|
|
|
For Power Generation
|
|
|
63,024
|
|
|
|
39,639
|
|
|
|
30,875
|
|
|
|
34,096
|
|
|
|
26,099
|
|
|
For Resale
|
|
|
8,465
|
|
|
|
9,048
|
|
|
|
8,921
|
|
|
|
8,923
|
|
|
|
8,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
252,615
|
|
|
|
216,874
|
|
|
|
210,251
|
|
|
|
206,004
|
|
|
|
198,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary Market Sales
|
|
|
46,823
|
|
|
|
46,057
|
|
|
|
53,442
|
|
|
|
42,049
|
|
|
|
40,994
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of Customers Billed
(12-month average):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
864,205
|
|
|
|
855,670
|
|
|
|
852,586
|
|
|
|
835,636
|
|
|
|
815,579
|
|
|
Commercial
|
|
|
94,287
|
|
|
|
94,404
|
|
|
|
94,045
|
|
|
|
93,472
|
|
|
|
92,692
|
|
|
Industrial
|
|
|
2,273
|
|
|
|
2,358
|
|
|
|
2,937
|
|
|
|
2,959
|
|
|
|
3,008
|
|
|
For Power Generation
|
|
|
20
|
|
|
|
20
|
|
|
|
20
|
|
|
|
15
|
|
|
|
12
|
|
|
For Resale
|
|
|
16
|
|
|
|
17
|
|
|
|
17
|
|
|
|
15
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
960,801
|
|
|
|
952,469
|
|
|
|
949,605
|
|
|
|
932,097
|
|
|
|
911,310
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Per Residential Customer:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Used — Dekatherms
|
|
|
67.49
|
|
|
|
64.63
|
|
|
|
60.88
|
|
|
|
59.92
|
|
|
|
60.23
|
|
|
Revenue
|
|
$
|
860.15
|
|
|
$
|
920.91
|
|
|
$
|
953.61
|
|
|
$
|
889.90
|
|
|
$
|
1,031.23
|
|
|
Revenue Per Dekatherm
|
|
$
|
12.74
|
|
|
$
|
14.25
|
|
|
$
|
15.66
|
|
|
$
|
14.85
|
|
|
$
|
17.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of Gas (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Commodity Costs
|
|
$
|
753,529
|
|
|
$
|
727,744
|
|
|
$
|
1,454,073
|
|
|
$
|
1,055,600
|
|
|
$
|
1,229,326
|
|
|
Capacity Demand Charges
|
|
|
127,137
|
|
|
|
128,081
|
|
|
|
127,640
|
|
|
|
116,977
|
|
|
|
99,333
|
|
|
Natural Gas Withdrawn From
(Injected Into) Storage, net
|
|
|
5,293
|
|
|
|
126,480
|
|
|
|
(78,283
|
)
|
|
|
(12,815
|
)
|
|
|
15,709
|
|
|
Regulatory Charges, net
|
|
|
113,744
|
|
|
|
94,237
|
|
|
|
32,705
|
|
|
|
27,365
|
|
|
|
56,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
999,703
|
|
|
$
|
1,076,542
|
|
|
$
|
1,536,135
|
|
|
$
|
1,187,127
|
|
|
$
|
1,401,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Supply Available for Distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dekatherms in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Purchased
|
|
|
157,021
|
|
|
|
149,696
|
|
|
|
159,857
|
|
|
|
143,598
|
|
|
|
140,999
|
|
|
Transportation Gas
|
|
|
147,038
|
|
|
|
115,519
|
|
|
|
108,332
|
|
|
|
108,355
|
|
|
|
101,414
|
|
|
Natural Gas Withdrawn From
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Injected Into) Storage, net
|
|
|
(1,309
|
)
|
|
|
1,010
|
|
|
|
(2,980
|
)
|
|
|
(1,640
|
)
|
|
|
(197
|
)
|
|
Company Use
|
|
|
(282
|
)
|
|
|
(283
|
)
|
|
|
(135
|
)
|
|
|
(141
|
)
|
|
|
(127
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
302,468
|
|
|
|
265,942
|
|
|
|
265,074
|
|
|
|
250,172
|
|
|
|
242,089
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We purchase natural gas under firm contracts to meet our design-day requirements for firm
sales customers. These contracts provide that we pay a reservation fee to the supplier to reserve
or guarantee the availability of gas supplies for delivery. Under these provisions, absent force
majeure conditions, any disruption of supply deliverability is subject to penalty and damage
assessment against the supplier. We ensure the delivery of the gas supplies to our distribution
system to meet the peak day, seasonal and annual needs of our firm customers by using a variety of
firm transportation and storage capacity contracts. The pipeline capacity contracts require the
payment of fixed demand charges to reserve firm transportation or storage entitlements. We align
the contractual agreements for supply with the firm capacity agreements in terms of volumes,
receipt and delivery locations and demand fluctuations. We may supplement these firm contracts
with other supply arrangements to serve our interruptible market.
As of October 31, 2010, we had contracts for the following pipeline firm transportation
capacity in dekatherms per day.
|
|
|
|
|
|
|
Williams-Transco
|
|
|
632,200
|
|
|
El Paso-Tennessee Pipeline
|
|
|
74,100
|
|
|
Spectra-Texas Eastern (through East Tennessee and Transco)
|
|
|
36,700
|
|
|
NiSource-Columbia Gas (through Transco and Columbia Gulf)
|
|
|
42,800
|
|
|
NiSource-Columbia Gulf
|
|
|
10,000
|
|
|
ONEOK-Midwestern (through Tennessee, Columbia Gulf, East Tennessee and Transco)
|
|
|
120,000
|
|
|
|
|
|
|
|
Total
|
|
|
915,800
|
|
|
|
|
|
|
As of October 31, 2010, we had the following assets or contracts for local peaking
facilities and storage for seasonal or peaking capacity in dekatherms of daily deliverability to
meet the firm demands of our markets with deliverability from 5 days to one year.
|
|
|
|
|
|
|
Piedmont Liquefied Natural Gas (LNG)
|
|
|
278,000
|
|
|
Pine Needle LNG (through Transco)
|
|
|
263,400
|
|
|
Williams-Transco Storage
|
|
|
86,100
|
|
|
NiSource-Columbia Gas Storage
|
|
|
96,400
|
|
|
Hardy Storage (through Columbia Gas and Transco)
|
|
|
68,800
|
|
|
Dominion Storage (through Transco)
|
|
|
13,200
|
|
|
El Paso-Tennessee Pipeline Storage
|
|
|
55,900
|
|
|
|
|
|
|
|
Total
|
|
|
861,800
|
|
|
|
|
|
|
5
As of October 31, 2010, we own or have under contract 36.2 million dekatherms of storage
capacity, either in the form of underground storage or LNG. This capability is used to supplement
or replace regular pipeline supplies.
The source of the gas we distribute is primarily from the Gulf Coast production region and is
purchased primarily from major and independent producers and marketers. Natural gas demand is
continuing to grow in our service area. As part of our long-term plan to diversify our reliance
away from the Gulf Coast region, we receive firm, long-term market area storage service from Hardy
Storage Company, LLC, a storage facility in West Virginia, and firm, long-term transportation
service from Midwestern Gas Transmission Company that provides access to gas supplies from Canadian
and Rocky Mountain supply basins via the Chicago hub.
We have agreements with Progress Energy Carolinas, Inc., a subsidiary of Progress Energy,
Inc., to provide natural gas delivery service to their planned power generation facilities to be
built at their Wayne County, North Carolina power generation site and at their Sutton site near
Wilmington, North Carolina. We also completed construction on a power generation project to
provide natural gas delivery service to a Progress Energy Carolinas’ power generation facility
located in Richmond County, North Carolina during the first quarter of fiscal 2011. In addition to
the environmental benefits associated with using natural gas at these new plants in lieu of coal,
the construction of the natural gas pipelines for these projects will also add to our natural gas
infrastructure in the eastern part of North Carolina and enhance future opportunities for economic
growth and development. In addition, we have agreements with Duke Energy Carolinas, LLC, a
subsidiary of Duke Energy Corporation, to provide natural gas delivery service to two new power
generation facilities. The facility located in Rowan County, North Carolina, was placed into
service during the first quarter of fiscal 2011. The Rockingham County, North Carolina, power
generation facility is under construction and scheduled to be placed in service November 2011. We
will continue to seek opportunities to provide long-term gas transportation service to power
generation projects in our market area. For further information on our anticipated capital
investment related to the construction of the natural gas pipelines to service these new power
generation facilities, see “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in
Management’s Discussion and Analysis. For further information on gas supply and regulation, see
“Gas Supply and Regulatory Proceedings” in Item 7 of this Form 10-K and Note 2 to the consolidated
financial statements.
We are continuing to see challenging economic conditions in our market area as evidenced by
high rates of unemployment, a depressed housing market, significantly reduced new home construction
and little new commercial development. In 2010, we experienced declines in residential
conversions, residential new construction and in the small commercial market. However, as
discussed above, we are positioning ourselves to capitalize on new opportunities as the economy
slowly improves, and continue to focus on customer conversions to natural gas and power generation
gas delivery service opportunities. Seeking to expand the use of natural gas, we continue to
emphasize natural gas as the fuel of choice for customers, including the comfort, affordability,
reliability and efficiency of natural gas, as well as reminding our customers of our reliability
and safety as a company. We are forecasting gross customer addition growth for fiscal 2011 to be
1.2%.
During the year ended October 31, 2010, approximately 5% of our margin (operating revenues
less cost of gas) was generated from deliveries to industrial or large commercial
6
customers that
have the capability to burn a fuel other than natural gas. The alternative fuels are primarily
fuel oil and propane and, to a much lesser extent, coal or wood. Our ability to maintain or
increase deliveries of gas to these customers depends on a number of factors, including weather
conditions, governmental regulations, the price of gas from suppliers, availability and the
price of alternate fuels. Under FERC policies, certain large volume customers located in proximity
to the interstate pipelines delivering gas to us could bypass us and take delivery of gas directly
from the pipeline or from a third party connecting with the pipeline. During the fiscal year ended
October 31, 2010, the City of Monroe, a wholesale customer, completed construction of a pipeline to
bypass our system with a direct connection to Transco. This action had and will have no impact on
our utility margin as a result of a regulatory provision approved in our last North Carolina rate
case. The future level of bypass activity cannot be predicted.
The regulated utility also competes with other energy products, such as electricity and
propane, in the residential and small commercial customer markets. The most significant product
competition is with electricity for space heating, water heating and cooking. There are four major
electric companies within our service areas. We continue to attract the majority of the new
residential construction market on or near our distribution mains, and we believe that the
consumer’s preference for natural gas is influenced by such factors as price, value, availability,
environmental attributes, comfort, convenience, reliability and energy efficiency. The direct use
of natural gas in homes and businesses is the most efficient and cost effective use of natural gas
and lowers the carbon footprint of those premises in our market area.
As noted above, many of our industrial 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 price with natural gas historically having
a price advantage over fuel oil. 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 US dollar versus other
currencies. Our revenues could be impacted, either positively or negatively, as a result of
alternate fuel decisions made by industrial customers.
During the year ended October 31, 2010, our largest revenue generating customer contributed
$62.7 million, or 4%, of total operating revenues. Our largest margin generating customer
contributed $11.7 million, or 2% of total margin.
Our costs for research and development are not material and are primarily limited to natural
gas industry-sponsored research projects.
Compliance with federal, state and local environmental protection laws have had no material
effect on our construction expenditures, earnings or competitive position. For further information
on environmental issues, see “Environmental Matters” in Item 7 of this Form 10-K.
As of October 31, 2010, our fiscal year end, we had 1,788 employees, compared with 1,821 as of
October 31, 2009.
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 Securities and Exchange Commission.
7
Item 1A. Risk Factors
An overall economic downturn or slow economic recovery could negatively impact our earnings.
Weakening or slow recovery of economic activity in our markets could result in a loss of
customers, a decline in customer additions, especially in the new home construction market, or a
decline in energy consumption, which could adversely affect our revenues or restrict our future
growth. It may become more difficult for customers to pay their gas bills, leading to slow
collections and higher-than-normal levels of accounts receivable. This could increase our
financing requirements and non-gas cost bad debt expense. Earnings and liquidity would be
negatively affected, reducing our ability to grow the business.
Increases in the wholesale price of natural gas could reduce our earnings and working capital.
|
The supply and demand balance in natural gas markets could cause an increase in the price of
natural gas. The prudently incurred cost we pay for natural gas is passed directly through to our
customers. Therefore, significant increases in the price of natural gas may cause our existing
customers to conserve or motivate them to switch to alternate sources of energy as well as cause
new home developers, builders and new customers to select alternative sources of energy. Decreases
in the volume of gas we sell could reduce our earnings in the absence of decoupled rate structures,
and a decline in new customers could impede growth in our future earnings. In addition, during
periods when natural gas prices are higher than historical levels, our working capital costs could
increase due to higher carrying costs of gas storage inventories, and customers may have trouble
paying higher bills leading to bad debt expenses, which may reduce our earnings.
|
A decrease in the availability of adequate interstate pipeline transportation
capacity and natural gas supply could reduce our earnings.
We purchase all of our gas supply from interstate sources that must then be transported to our
service territory. Interstate pipeline companies transport the gas to our system under firm
service agreements that are designed to meet the requirements of our core markets. A significant
disruption to that supply or interstate pipeline capacity due to unforeseen events, including but
not limited to, operational failures or disruptions, hurricanes, tornadoes, floods, freeze off of
natural gas wells, terrorist attacks or other acts of war, could reduce our normal interstate
supply of gas and thereby reduce our earnings. Moreover, if additional natural gas infrastructure,
including but not limited to exploration and drilling rigs and platforms, processing and gathering
systems, off-shore pipelines, interstate pipelines and storage, cannot be built at a pace that
meets demand, then our growth opportunities would be limited and our earnings negatively impacted.
Our business is subject to competition that could negatively affect our results of operations.
|
The natural gas business is competitive, and we are facing increasing competition from other
companies that supply energy, including electric companies, oil and propane dealers, renewable
energy providers and, as it relates to sources of energy for electric power plants, coal.
|
8
|
A significant competitive factor is price.
|
In residential and commercial customer markets, our natural gas distribution operations
compete with other energy products, primarily electricity, fuel oil and propane. Our primary
product competition is with electricity for heating, water heating and cooking. Increases in
the price of natural gas or decreases in the price of other energy sources could negatively impact
our competitive position by decreasing the price benefits of natural gas to the consumer. In the
case of industrial customers, such as manufacturing plants, adverse economic or market conditions,
including higher gas costs, could cause these customers to use alternative sources of energy or
bypass our systems in favor of energy sources with lower per-unit costs.
Higher gas costs or decreases in the price of other energy sources may allow competition from
alternative energy sources for applications that have traditionally used natural gas, encouraging
some customers to move away from natural gas-fired equipment to equipment fueled by other energy
sources. Competition between natural gas and other forms of energy is also based on efficiency,
performance, reliability, safety and other non-price factors. Technological improvements in other
energy sources and events that impair the public perception of these non-price attributes of
natural gas could erode our competitive advantage. These factors in turn could decrease the demand
for natural gas, impair our ability to attract new customers, and cause existing customers to
switch to other forms of energy or to bypass our systems in favor of alternative competitive
sources. This could result in slow or no customer growth and could cause customers to reduce or
cease using our product, thereby reducing our ability to make capital expenditures and otherwise
grow our business and adversely affecting our earnings.
Changes in federal laws or regulations could reduce the availability or increase the cost of our
interstate pipeline capacity and/or gas supply and thereby reduce our earnings.
The FERC has regulatory authority over some of our operations, including sales of natural gas
in the wholesale market and the purchase and sale of interstate pipeline and storage capacity.
Additionally, the Commodities Futures Trading Commission under the 2010 Dodd-Frank Wall Street
Reform and Consumer Protection Act has regulatory authority of the over-the-counter derivatives
markets. Any federal legislation or agency legislation that has the effect of significantly
raising costs that could not be recovered in rates from our customers or reducing the availability
of supply or capacity, the liquidity of the natural gas supply market or our competitiveness could
negatively impact our earnings.
Climate change legislation or regulations could increase our operating costs, negatively affecting
our growth, cash flows and earnings.
The federal government may enact legislation that attempts to control or limit the causes of
climate change, including greenhouse gas emissions such as carbon dioxide. The Environmental
Protection Agency has announced plans to issue climate change regulations beginning in January
2011. These initiatives could result in various new laws or regulations. Such laws or regulations
could impose operational requirements, impose additional charges to fund energy efficiency
activities, provide a cost advantage to alternative energy sources other than natural gas, impose
costs or restrictions on end users of natural gas, or result in other costs or requirements. As a
result, there is a possibility that, if enacted or adopted, such legislation or regulation could
put upward pressure on the cost of natural gas relative to other energy sources, increase our costs
and impact the competitive position of natural gas, negatively affecting our growth opportunities,
cash
9
flows and earnings.
Regulatory actions at the state level could impact our ability to earn a reasonable rate of return
on our invested capital and to fully recover our operating costs as well as reduce our earnings.
Our regulated utility segment is regulated by the NCUC, the PSCSC and the TRA. These agencies
set the rates that we charge our customers for our services. We monitor allowed rates of return
and our ability to earn appropriate rates of return based on factors, such as increased operating
costs, and initiate general rate proceedings as needed. If a state regulatory commission were to
prohibit us from setting rates that allow for the timely recovery of our costs and a reasonable
return by significantly lowering our allowed return or negatively altering our cost allocation,
rate design, cost trackers (including margin decoupling and cost of gas) or other tariff
provisions, then our earnings could be negatively impacted. In the normal course of business in
the regulatory environment, assets are placed in service before rate cases can be filed that could
result in an adjustment of our returns. Once rate cases are filed, regulatory bodies have the
authority to suspend implementation of the new rates while studying the cases. Because of this
process, we may suffer the negative financial effects of having placed in service assets that do
not initially earn our authorized rate of return without the benefit of rate relief, which is
commonly referred to as “regulatory lag.” Rate cases also involve a risk of rate reduction,
because once rates have been filed, they are still subject to challenge for their reasonableness by
various appropriate entities. Regulatory authorities may also review whether our gas cost
purchases are prudent and can adjust the amount of our gas costs that we pass through to our
customers. Additionally, our state regulators foster a competitive regulatory model that, for
example, allows us to recover any margin losses associated with negotiated transactions designed to
retain large volume customers that could use alternative fuels or that may directly access natural
gas supply through their own connection to an interstate pipeline. If there were changes in
regulatory philosophies that altered our ability to compete for these customers, then we could lose
customers or incur significant unrecoverable expenses to retain them. Both scenarios would impact
our results of operations, financial condition and cash flows. Our debt and equity financings are
also subject to regulation by the NCUC. Delays or failure to receive NCUC approval could limit our
ability to access or take advantage of changes in the capital markets. This could negatively
impact our liquidity or earnings.
Weather conditions may cause our earnings to vary from year to year.
Our earnings can vary from year to year, depending in part on weather conditions. Currently,
we have in place regulatory mechanisms that normalize our margin for weather during the winter,
providing for an adjustment up or down, to take into account warmer-than-normal or
colder-than-normal weather. Mild winter temperatures can cause a decrease in the amount of gas we
sell and deliver in any year and the margin we collect from these customers. If our rates and
tariffs were modified to eliminate weather protection, such as weather normalization and rate
decoupling tariffs, then we would be exposed to significant risk associated with weather, and our
earnings could vary as a result.
Our gas supply risk management programs are subject to state regulatory approval or annual review
in gas cost proceedings.
10
We manage our gas supply costs through short-term and long-term procurement and storage
contracts. In the normal course of business, we utilize New York Mercantile Exchange (NYMEX)
exchange traded instruments of various durations for the forward purchase or sale of our natural
gas requirements, subject to regulatory approval or review. As a component of our gas costs, these
expenses are subject to regulatory approval, and we may be exposed to additional liability if the
recovery of these costs of gas supply procurement or risk management activities is
excluded by our regulators in gas cost recovery proceedings.
Operational interruptions to our gas distribution activities caused by accidents, work stoppage,
severe weather conditions, including destructive weather patterns such as hurricanes, tornadoes and
floods, pandemic or acts of terrorism could adversely impact earnings.
Inherent in our gas distribution activities are a variety of hazards and operational risks,
such as leaks, ruptures, mechanical problems and third party excavation damage. Severe weather
conditions, as well as acts of terrorism, can also damage our pipelines and other infrastructure
and disrupt our ability to conduct our natural gas distribution and transportation business.
Pandemic could result in a significant part of our workforce being unable to operate or maintain
our infrastructure or perform other tasks necessary to conduct our business. If the foregoing
events are severe enough or if they lead to operational interruptions, they could cause substantial
financial losses. In addition, these risks could result in loss of human life, significant damage
to property, environmental damage, impairment of our operations and substantial loss to us. The
location of pipeline and storage facilities near populated areas, including residential areas,
commercial business centers, industrial sites and other public gathering places, could increase the
level of damages resulting from these risks. Our regulators may not allow us to recover part or
all of the increased cost related to the foregoing events from our customers, which would
negatively affect our earnings. With part of our workforce represented by unions, we are exposed
to the risk of a work stoppage. The occurrence of any of these events could adversely affect our
financial position, results of operations and cash flows.
We may not be able to complete necessary or desirable infrastructure development projects, which
may delay or prevent us from expanding our business.
In order to serve new customers or expand our service to existing customers, we often need to
expand or upgrade our distribution, transmission and/or storage infrastructure, including laying
new pipeline and building compressor stations or LNG storage tanks. Various factors may prevent or
delay us from completing such projects or make completion more costly, such as the inability to
obtain required approval from local, state and/or federal regulatory and governmental bodies,
public opposition to the project, inability to obtain adequate financing, construction delays, cost
overruns, and inability to negotiate acceptable agreements relating to rights-of-way, construction
or other material development components. As a result, we may not be able to adequately support
customer growth, which would negatively impact our earnings.
A downgrade in our credit rating could negatively affect our cost of and ability to access capital.
Our ability to obtain adequate and cost effective financing depends on our credit ratings. A
negative change in our ratings outlook or any downgrade in our current investment-grade credit
ratings by our rating agencies, particularly below investment grade, could adversely affect our
cost of borrowing and/or access to sources of liquidity and capital. Such a downgrade could
further limit our access to private credit markets and increase the costs of borrowing under
available credit
11
lines. Should our credit ratings be downgraded, the interest rate on our
borrowings under our revolving credit agreement would increase. An increase in borrowing costs
without the ability to recover these higher costs in the rates charged to our customers could
adversely affect earnings by limiting our ability to earn our allowed rate of return.
The inability to access capital or significant increases in the cost of capital could adversely
affect
our business.
Our ability to obtain adequate and cost effective financing is dependent upon the liquidity of
the financial markets, in addition to our credit ratings. Disruptions in the capital and credit
markets could adversely affect our ability to access short-term and long-term capital. Our access
to funds under short-term credit facilities is dependent on the ability of the participating banks
to meet their funding commitments. Those banks may not be able to meet their funding commitments
if they experience shortages of capital and liquidity. Longer disruptions in the capital and
credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives
or failures of significant financial institutions could adversely affect our access to capital
needed for our business. The inability to access adequate capital may require us to conserve cash,
prevent or delay us from making capital expenditures, and require us to reduce or eliminate the
dividend or other discretionary uses of cash.
Changes in federal and state fiscal and monetary policy could significantly increase our costs or
decrease our cash flows.
Changes in federal and state fiscal and monetary policy may result in increased taxes,
interest rates, and inflationary pressures on the costs of goods and services. This could increase
our expenses and decrease our earnings if we are not able to recover such increased costs from our
customers. This series of events may increase our rates to customers and thus may negatively
impact customer billings and customer growth. Changes in accounting or tax rules, such as
accelerated tax depreciation, could negatively affect our cash flow. Any of these events may cause
us to increase debt, conserve cash, negatively affect our ability to make capital expenditures to
grow the business or require us to reduce or eliminate the dividend or other discretionary uses of
cash, and could negatively affect earnings.
We do not generate sufficient cash flows to meet all our cash needs.
Historically, we have made large capital expenditures in order to finance the expansion and
upgrading of our distribution system. We also purchase natural gas for storage. We have made
several equity method investments and will continue to pursue other similar investments, all of
which are and will be important to our profitability. Volatility in gas prices may require us to
post cash collateral as part of our regulated gas price hedging program. We have funded a portion
of our cash needs for these purposes, as well as contributions to our employee pensions and benefit
plans, through borrowings under credit arrangements and by offering new securities in the open
market. Our dependency on external sources of financing creates the risk that our profits could
decrease as a result of higher borrowing costs and that we may not be able to secure external
sources of cash necessary to fund our operations and new investments on terms acceptable to us.
Volatility in seasonal cash flow requirements, including requirements for our gas supply
procurement and risk management programs, may require increased levels of borrowing that could
result in non-compliance with the debt-to-equity ratios in our credit facilities as well as cause a
12
credit rating downgrade. Any disruptions in the capital and credit markets could require us to
conserve cash until the markets stabilize or until alternative credit arrangements or other funding
required for our needs can be secured. Such measures could cause deferral of major capital
expenditures, changes in our gas supply procurement and risk management programs, the reduction or
elimination of the dividend payment or other discretionary uses of cash.
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy
all of our outstanding obligations in the event of a default on our part.
The terms of our senior indebtedness, including our revolving credit facility, contain
cross-default provisions which provide that we will be in default under such agreements in the
event of certain defaults under the indenture or other loan agreements. Accordingly, should an
event of default occur under any of those agreements, we face the prospect of being in default
under all of our debt agreements, obliged in such instance to satisfy all of our outstanding
indebtedness and unable to satisfy all of our outstanding obligations simultaneously. In such an
event, we might not be able to obtain alternative financing or, if we are able to obtain such
financing, we might not be able to obtain it on terms acceptable to us, which would negatively
affect our ability to implement our business plan, make capital expenditures and finance our
operations.
We are exposed to credit risk of counterparties with whom we do business.
Adverse economic conditions affecting, or financial difficulties of, counterparties with whom
we do business could impair the ability of these counterparties to pay for our services or fulfill
their contractual obligations. We depend on these counterparties to remit payments to fulfill
their contractual obligations on a timely basis. Any delay or default in payment or failure of the
counterparties to meet their contractual obligations could adversely affect our financial position,
results of operations or cash flows.
Poor investment performance of pension plan holdings and other factors impacting pension plan costs
could unfavorably impact our liquidity and results of operations.
|
Our costs of providing for the non-contributory defined benefit pension plan are dependent on
a number of factors, such as the rates of return on plan assets, discount rates, the level of
interest rates used to measure the required minimum funding levels of the plan, changes in these
actuarial assumptions, future government regulation and our required or voluntary contributions
made to the plan. A significant decline in the value of investments that fund our pension plan, if
not offset or mitigated by a decline in our liabilities, may significantly differ from or alter the
values and actuarial assumptions used to calculate our future pension expense. A decline in the
value of these investments could increase the expense of our pension plan, and we could be required
to fund our plan with significant amounts of cash. Such cash funding obligations could have a
material impact on our liquidity by reducing cash flows and could negatively affect results of
operations.
|
We are subject to numerous environmental laws and regulations that may require significant
expenditures or increase operating costs.
|
We are subject to numerous federal and state environmental laws and regulations affecting many
aspects of our present and future operations. These laws and regulations can result in
|
13
|
increased
capital, operating and other costs. These laws and regulations generally require us to obtain and
comply with a wide variety of environmental licenses, permits, inspections and approvals.
Compliance with these laws and regulations can require significant expenditures for clean-up costs
and damages arising out of contaminated properties. Failure to comply may result in fines,
penalties and injunctive measures affecting operating assets. Additionally, the discovery of
presently unknown environmental conditions could give rise to expenditures and liabilities,
including fines or penalties, which could have a material adverse effect on our business,
results of operations or financial condition.
|
We are subject to new and existing pipeline safety and system integrity laws and regulations that
may require significant expenditures or significantly increase operating costs.
We are subject to existing and may be subject to new pipeline safety and system integrity laws
and regulations affecting various aspects of our present and future operations. These laws and
regulations generally require us to enhance pipeline safety and system integrity by identifying and
reducing pipeline risks. Compliance with these laws and regulations may result in increased
capital, operating and other costs which may not be recoverable in rates from our customers.
Furthermore, because the language in some of these laws and regulations is not prescriptive, there
is a risk that an incorrect or inadequate interpretation of these laws and regulations may lead to
a failure to comply. Such a failure for this or other reasons may result in fines, penalties or
injunctive measures. All of the above could result in a material adverse effect on our business,
results of operations or financial condition.
We may invest in companies that have risks that are inherent in their businesses, and these risks
may negatively affect our earnings from those companies.
We are invested in several natural gas related businesses as an equity method investor. One
of these businesses is not directly regulated by state or federal regulatory bodies and could be
subject to adverse market conditions not experienced by the regulated utility segment. These
businesses could be subject to laws, regulations or market conditions, or have risks inherent in
their operations, that adversely affect their performance. We do not control the operations of
these businesses, and thus management of these businesses could make decisions that adversely
impact their performance. All the foregoing could adversely affect our earnings from or return of
our investment in these businesses. We could make future investments in similarly unregulated
businesses that have the similar potential to adversely affect our earnings from or return of our
investment in those businesses. All these adverse impacts could negatively affect our results of
operations or financial condition.
Our inability to attract and retain professional and technical employees could adversely impact our
earnings.
Our ability to implement our business strategy and serve our customers is dependent upon the
continuing ability to employ talented professionals and attract and retain a skilled workforce.
Without such a skilled workforce, our ability to provide quality service to our customers and meet
our regulatory requirements will be challenged, and this could negatively impact our earnings.
14
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
All property included in the consolidated balance sheets in “Utility Plant” is owned by us and
used in our regulated utility segment. This property consists of intangible plant, production
plant, storage plant, transmission plant, distribution plant and general plant as categorized by
natural gas utilities, with 93% of the total invested in utility distribution and transmission
plant to serve our customers. We have approximately 2,600 miles of transmission pipelines up to 30
inches in diameter that connect our distribution systems with the transmission systems of our
pipeline suppliers. We distribute natural gas through approximately 28,900 miles (three-inch
equivalent) of distribution mains. The transmission pipelines and distribution mains are generally
underground, located near public streets and highways, or on property owned by others, for which we
have obtained the necessary legal rights to place and operate our facilities on such property. All
of these properties are located in North Carolina, South Carolina and Tennessee. Utility Plant
includes “Construction work in progress,” which primarily represents distribution, transmission and
general plant projects that have not been placed into service pending completion.
None of our property is encumbered and all property is in use except for “Plant held for
future use” as classified in our consolidated balance sheets. The amount classified as plant held
for future use relates to expenditures associated with the Robeson County LNG facility. We have
delayed proceeding with work on the Robeson LNG facility given the slowing of our growth due to
current economic conditions and because the Sutton facilities will help serve our near term system
pressure requirements in a cost effective manner in the eastern part of North Carolina. The timing
and design scope of expansion of our facilities in this area will be determined as our system
infrastructure and market supply growth requirements in North Carolina dictate.
We own or lease for varying periods our corporate headquarters building located in Charlotte,
North Carolina and district and regional offices in the locations shown below. Lease payments for
these various offices totaled $4.7 million for the year ended October 31, 2010.
15
|
|
|
|
|
|
|
North Carolina
|
|
South Carolina
|
|
Tennessee
|
|
Burlington
|
|
Anderson
|
|
Nashville
|
|
Cary
|
|
Gaffney
|
|
|
|
Charlotte
|
|
Greenville
|
|
|
|
Elizabeth City
|
|
Spartanburg
|
|
|
|
Fayetteville
|
|
|
|
|
|
Goldsboro
|
|
|
|
|
|
Greensboro
|
|
|
|
|
|
Hickory
|
|
|
|
|
|
High Point
|
|
|
|
|
|
Indian Trail
|
|
|
|
|
|
New Bern
|
|
|
|
|
|
Reidsville
|
|
|
|
|
|
Rockingham
|
|
|
|
|
|
Salisbury
|
|
|
|
|
|
Spruce Pine
|
|
|
|
|
|
Tarboro
|
|
|
|
|
|
Wilmington
|
|
|
|
|
|
Winston-Salem
|
|
|
|
|
Property included in the consolidated balance sheets in “Other Physical Property” is owned by
the parent company and one of its subsidiaries. The property owned by the parent company primarily
consists of commercial water heaters leased to natural gas customers. The property owned by the
subsidiary is real estate. None of our other subsidiaries directly own property as their
operations consist solely of participating in joint ventures as an equity member.
Item 3. Legal Proceedings
We have only routine immaterial litigation in the normal course of business.
Item 4. (Removed and Reserved).
16
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Market Information
Our common stock (symbol PNY) is traded on the New York Stock Exchange (NYSE). The following
table provides information with respect to the high and low sales prices from the NYSE Composite
for each quarterly period for the years ended October 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
High
|
|
|
Low
|
|
|
Quarter ended:
|
|
|
|
|
|
|
|
|
|
January 31
|
|
$
|
27.84
|
|
|
$
|
22.51
|
|
|
April 30
|
|
|
28.52
|
|
|
|
23.87
|
|
|
July 31
|
|
|
27.97
|
|
|
|
24.50
|
|
|
October 31
|
|
|
29.85
|
|
|
|
26.15
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
High
|
|
|
Low
|
|
|
Quarter ended:
|
|
|
|
|
|
|
|
|
|
January 31
|
|
$
|
33.92
|
|
|
$
|
24.77
|
|
|
April 30
|
|
|
27.55
|
|
|
|
20.68
|
|
|
July 31
|
|
|
25.50
|
|
|
|
21.65
|
|
|
October 31
|
|
|
25.87
|
|
|
|
23.10
|
|
Holders
As of December 17, 2010, our common stock was owned by 14,260 shareholders of record. Holders
of record exclude the individual and institutional security owners whose shares are held in street
name or in the name of an investment company.
Dividends
The following table provides information with respect to quarterly dividends paid on common
stock for the years ended October 31, 2010 and 2009. We expect that comparable cash dividends will
continue to be paid in the future.
|
|
|
|
|
|
|
|
|
Dividends Paid
|
|
|
2010
|
|
Per Share
|
|
|
Quarter ended:
|
|
|
|
|
|
January 31
|
|
|
27¢
|
|
|
April 30
|
|
|
28¢
|
|
|
July 31
|
|
|
28¢
|
|
|
October 31
|
|
|
28¢
|
|
|
|
|
|
|
|
|
|
|
Dividends Paid
|
|
|
2009
|
|
Per Share
|
|
|
Quarter ended:
|
|
|
|
|
|
January 31
|
|
|
26¢
|
|
|
April 30
|
|
|
27¢
|
|
|
July 31
|
|
|
27¢
|
|
|
October 31
|
|
|
27¢
|
|
The amount of cash dividends that may be paid on common stock is restricted by provisions
contained in certain note agreements under which long-term debt was issued, with those for the
senior notes being the most restrictive. We cannot pay or declare any dividends or make any other
distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary
to do any of the above (all of the foregoing being “restricted payments”) except out of net
earnings available for restricted payments. As of October 31, 2010, net earnings available for
restricted payments were greater than retained earnings; therefore, our retained earnings were not
restricted.
17
Sale of Unregistered Securities
On November 16, 2009, we discovered in our fiscal 2009 and early fiscal 2010 that we had
inadvertently sold more shares under our dividend reinvestment and stock purchase plan (DRIP) than
were registered with the Securities and Exchange Commission (SEC) and authorized by our Board of
Directors for issuance under the DRIP. We also discovered that the registration statement we
believed had registered shares issued under the DRIP between December 1, 2008 and November 16, 2009
had expired for some of those shares. As a result, from November 1, 2009 through November 16,
2009, we sold 15,029 shares under the DRIP that may not have been registered at the time of
issuance for proceeds of $347,000. Our Board of Directors ratified the authorization and issuance
of the excess number of shares, and on November 20, 2009, we filed a registration statement
covering the sale and issuance of an additional 2.75 million shares of our common stock under the
DRIP. On February 8, 2010, we filed a registration statement (Rescission Offer) which offered to
rescind the purchase of the shares sold under the DRIP between December 1, 2008 and November 16,
2009 and registered all previously unregistered shares issued under the DRIP during that period.
Under the Rescission Offer, the purchase of 711 shares was rescinded for an aggregate consideration
of $18,900. We incurred costs related to the Rescission Offer of $.8 million, which have been
recorded against retained earnings. We reported these events to the relevant regulatory
authorities, including the SEC and the North Carolina Utilities Commission (NCUC). The sale of
unregistered securities could subject us to enforcement actions or penalties and fines by these
regulatory authorities, though no such regulatory action has been initiated. While we are unable
to predict the full consequences of these events, we do not expect them to have a material adverse
effect on us.
Share Repurchases
The following table provides information with respect to repurchases of our common stock under
the Common Stock Open Market Purchase Program during the three months ended October 31, 2010.
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of
|
|
Maximum Number
|
|
|
|
Total Number
|
|
|
|
|
|
Shares Purchased
|
|
of Shares that May
|
|
|
|
of Shares
|
|
Average Price
|
|
as Part of Publicly
|
|
Yet be Purchased
|
|
Period
|
|
Purchased
|
|
Paid Per Share
|
|
Announced Program
|
|
Under the Program (1)
|
|
Beginning of the period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,510,074
|
|
|
8/1/10 - 8/31/10
|
|
|
—
|
|
|
$
|
—
|
|
|
|
—
|
|
|
|
4,510,074
|
|
|
9/1/10 - 9/30/10
|
|
|
10,103
|
(2)
|
|
$
|
27.93
|
|
|
|
—
|
|
|
|
4,510,074
|
|
|
10/1/10 - 10/31/10
|
|
|
—
|
|
|
$
|
—
|
|
|
|
—
|
|
|
|
4,510,074
|
|
|
|
|
Total
|
|
|
10,103
|
|
|
$
|
27.93
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The Common Stock Open Market Purchase Program was approved by the Board of Directors
and announced on June 4, 2004 to purchase up to three million shares of common stock for
reissuance under our dividend reinvestment and stock purchase, employee stock purchase and
incentive compensation plans. On December 16, 2005, the Board of Directors approved an
increase in the number of shares in this program from three million to six million to
reflect the two-for-one stock split in 2004. The Board also approved on that date an
amendment of the Common Stock Open Market Purchase Program to provide for the purchase of
up to four million additional shares of common stock to maintain our debt-to-equity
capitalization ratios at target levels. The additional four million shares were referred
to as our accelerated share repurchase (ASR) program with an expiration date of December
31, 2010. On March 6, 2009, the Board of Directors authorized the repurchase of up to an
additional four million shares under the Common Stock Open Market Purchase Program and the
ASR program, which were consolidated.
|
|
|
|
(2)
|
|
The total number of shares purchased is shares withheld by us to satisfy tax
withholding obligations related to the vesting of shares of restricted stock under an
incentive compensation plan, which are outside of the Common Stock Open Market Purchase
Program.
|
Comparisons of Cumulative Total Shareholder Returns
The following performance graph compares our cumulative total shareholder return from October
31, 2005 through October 31, 2010 (a five-year period), with the Standard & Poor’s 500 Stock Index,
a broad market index (the S&P 500) and with our utility peer group. Large natural gas distribution
companies that are representative of our peers in the natural gas distribution industry are
included in our LDC Peer Group index.
The graph assumes that the value of an investment in Common Stock and in each index was $100
at October 31, 2005 and that all dividends were reinvested. Stock price performances shown on the
graph are not indicative of future price performance.
19
Comparisons of Five-Year Cumulative Total Returns
Value of $100 Invested as of October 31, 2005
LDC Peer Group—The following companies are included: AGL Resources Inc., Atmos Energy
Corporation, New Jersey Resources Corporation, NICOR Inc., NiSource Inc., Northwest Natural Gas
Company, Southwest Gas Corporation, Vectren Corporation and WGL Holdings, Inc.
Item 6. Selected Financial Data
The following table provides selected financial data for the years ended October 31, 2006
through 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands except per share amounts
|
|
2010
|
|
2009
|
|
2008
|
|
2007
|
|
2006
|
|
Operating Revenues
|
|
$
|
1,552,295
|
|
|
$
|
1,638,116
|
|
|
$
|
2,089,108
|
|
|
$
|
1,711,292
|
|
|
$
|
1,924,628
|
|
|
Margin (operating revenues less cost of gas)
|
|
$
|
552,592
|
|
|
$
|
561,574
|
|
|
$
|
552,973
|
|
|
$
|
524,165
|
|
|
$
|
523,479
|
|
|
Net Income
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
$
|
104,387
|
|
|
$
|
97,189
|
|
|
Earnings per Share of Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.96
|
|
|
$
|
1.68
|
|
|
$
|
1.50
|
|
|
$
|
1.41
|
|
|
$
|
1.28
|
|
|
Diluted
|
|
$
|
1.96
|
|
|
$
|
1.67
|
|
|
$
|
1.49
|
|
|
$
|
1.40
|
|
|
$
|
1.28
|
|
|
Cash Dividends per Share of Common Stock
|
|
$
|
1.11
|
|
|
$
|
1.07
|
|
|
$
|
1.03
|
|
|
$
|
0.99
|
|
|
$
|
0.95
|
|
|
Total Assets *
|
|
$
|
3,053,275
|
|
|
$
|
3,118,819
|
|
|
$
|
3,138,401
|
|
|
$
|
2,823,106
|
|
|
$
|
2,743,826
|
|
|
Long-Term Debt (less current maturities)
|
|
$
|
671,922
|
|
|
$
|
732,512
|
|
|
$
|
794,261
|
|
|
$
|
824,887
|
|
|
$
|
825,000
|
|
|
|
|
|
|
*
|
|
Total assets for the years 2006 through 2008 have been adjusted to reflect the gross presentation
rather than a net presentation in accordance with the adoption of new accounting guidance related
to offsetting of amounts related to certain contracts with the same counterparty.
|
20
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations
Forward-Looking Statements
This report, as well as other documents we file with the 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 and 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. Factors that may make the actual results differ from
anticipated results include, but are not limited to:
|
|
•
|
|
Regulatory issues affecting us and those from whom we purchase natural gas
transportation and storage service, including those that affect allowed rates of
return, terms and conditions of service, rate structures and financings. We monitor
our ability to earn appropriate rates of return and initiate general rate proceedings
as needed.
|
|
|
|
|
•
|
|
Residential, commercial, industrial and power generation growth and energy
consumption in our service areas. The ability to retain and grow our customer base,
the pace of that growth and the levels of energy consumption are impacted by general
business and economic conditions, such as interest rates, inflation, fluctuations in
the capital markets and the overall strength of the economy in our service areas and
the country, and fluctuations in the wholesale prices of natural gas and competitive
energy sources.
|
|
|
|
|
•
|
|
Deregulation, regulatory restructuring and competition in the energy industry. We
face competition from electric companies and energy marketing and trading companies,
and we expect this competitive environment to continue.
|
|
|
|
|
•
|
|
The potential loss of large-volume industrial customers to alternate fuels or to
bypass, or the shift by such customers to special competitive contracts or to tariff
rates that are at lower per-unit margins than that customer’s existing rate.
|
|
|
|
|
•
|
|
The capital-intensive nature of our business. In order to maintain growth, we must
add to our natural gas distribution system each year. The cost of and the ability to
complete these capital projects may be affected by the ability to obtain and the cost
of obtaining governmental approvals, compliance with federal and state pipeline safety
and integrity regulations, cost and timing of project development-related contracts,
project development delays and the cost and availability of labor and materials.
Weather, general economic conditions and the cost of funds to finance our capital
projects can materially alter the cost and timing of a project.
|
|
|
|
|
•
|
|
Access to capital markets. Our internally generated cash flows are not adequate to
finance the full cost of capital expenditures. As a result, we rely on access to both
short-term and long-term capital markets as a significant source of liquidity for
capital requirements not satisfied by cash flows from operations. Changes in the
capital
|
21
|
|
|
|
markets in our financial condition or in the financial condition of our lenders
or investors could affect access to and cost of capital.
|
|
|
|
|
•
|
|
Changes in the availability and cost of natural gas. To meet firm customer
requirements, we must acquire sufficient gas supplies and pipeline capacity to ensure
delivery to our distribution system while also ensuring that our supply and capacity
contracts allow us to remain competitive. Natural gas is an unregulated commodity
market subject to supply and demand and price volatility. Producers, marketers and
pipelines are subject to operating, regulatory and financial risks associated with
exploring, drilling, producing, gathering, marketing and transporting natural gas and
have risks that increase our exposure to supply and price fluctuations. Since such
risks may affect the availability and cost of natural gas, they also may affect the
competitive position of natural gas relative to other energy sources.
|
|
|
|
|
•
|
|
Changes in weather conditions. Weather conditions and other natural phenomena can
have a material impact on our earnings. Severe weather conditions, including
destructive weather patterns such as hurricanes, tornadoes and floods, can impact our
customers, our suppliers and the pipelines that deliver gas to our distribution system
and our distribution and transmission assets. Weather conditions directly influence the
supply, demand, distribution and cost of natural gas.
|
|
|
|
|
•
|
|
Changes in environmental, safety, system integrity, tax and other laws and
regulations, including those related to climate change, and the cost of compliance. We
are subject to extensive federal, state and local laws and regulations. Compliance
with such laws and regulations could increase capital or operating costs, affect our
reported earnings, increase our liabilities or change the way our business is
conducted.
|
|
|
|
|
•
|
|
Ability to retain and attract professional and technical employees. To provide
quality service to our customers and meet regulatory requirements, we are dependent on
our ability to recruit, train, motivate and retain qualified employees.
|
|
|
|
|
•
|
|
Changes in accounting regulations and practices. We are subject to accounting
regulations and practices issued periodically by accounting standard-setting bodies.
New accounting standards may be issued that could change the way we record revenues,
expenses, assets and liabilities, and could affect our reported earnings or increase
our liabilities.
|
|
|
|
|
•
|
|
Earnings from our equity method investments. We invest in companies that have risks
that are inherent in their businesses, and these risks may negatively affect our
earnings from those companies.
|
|
|
|
|
•
|
|
Changes in outstanding shares. The number of outstanding shares may fluctuate due
to new issuances or repurchases under our Common Stock Open Market Purchase Program.
|
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 rely on
these forward-looking statements when making investment decisions. When used in our documents or
22
oral presentations, the words “expect,” “believe,” “project,” “anticipate,” “intend,” “should,”
“could,” “will,” “assume,” “can,” “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 only 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. Please reference
our website at
www.piedmontng.com
for current information. 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 as soon as
reasonably practicable after the report is filed with or furnished to the SEC.
Executive 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 51,600 customers served by municipalities who are our
wholesale customers. We are invested in joint venture, energy-related businesses, including
unregulated retail natural gas marketing, interstate natural gas storage and intrastate natural gas
transportation.
In 1994, our predecessor, incorporated in 1950 under the same name, was merged into a newly
formed North Carolina corporation for the purpose of changing our state of incorporation to North
Carolina.
In the Carolinas, our service area is comprised of numerous cities, towns and communities. We
provide service to Anderson, Gaffney, Greenville and Spartanburg in South Carolina and Charlotte,
Salisbury, Greensboro, Winston-Salem, High Point, Burlington, Hickory, Indian Trail, Spruce Pine,
Reidsville, Fayetteville, New Bern, Wilmington, Tarboro, Elizabeth City, Rockingham and Goldsboro
in North Carolina. In North Carolina, we also provide wholesale natural gas service to the cities
of Greenville, Rocky Mount and Wilson. In Tennessee, our service area is the metropolitan area of
Nashville, including wholesale natural gas service to the cities of Gallatin and Smyrna.
We have two reportable business segments, regulated utility and non-utility activities. The
regulated utility segment is the largest segment of our business with approximately 97% of our
consolidated assets. Factors critical to the success of the regulated utility segment include
operating a safe, reliable natural gas distribution system and the ability to recover the costs and
expenses of the business in rates charged to customers. For 2010, our earnings before taxes,
including the gain from the sale of half of our ownership interest in SouthStar Energy Services LLC
(SouthStar) of $49.7 million, were $205.6 million, 67% of which came from our regulated utility
segment. The non-utility activities segment consists of our equity method investments in joint
venture, energy-related businesses that are involved in unregulated retail natural gas marketing
and regulated interstate natural gas storage and intrastate natural gas transportation. For 2010,
the earnings before taxes from our non-utility activities segment, including the gain from the sale
of half of our ownership in SouthStar was 33%, with 4% from regulated non-utility activities and
29% from unregulated non-utility activities.
23
The generally accepted accounting principles (GAAP) presentation does not adequately reflect
our segments because of the inclusion of the gain from the sale of half of our ownership interest
in SouthStar, which is in our non-utility activities segment. Excluding this gain for 2010, 85% of
our earnings before taxes came from our regulated utility segment, and earnings before taxes from
our non-utility activities segment was 15%, with 5% from regulated non-utility activities and 10%
from unregulated non-utility activities.
For further information on business segments, see Note 12 to the consolidated financial
statements. For information about our equity method investments, see Note 11 to the consolidated
financial statements.
Our utility operations are regulated by the 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 securities. We are also subject to
or affected by various federal regulations. 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 purchase and sale of and the prices paid for the interstate
transportation and storage of natural gas, regulations of the 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. In addition, we are subject to numerous regulations, such as those
relating to employment 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 generate revenues to cover our gas and non-gas costs and to earn a fair rate of
return on invested capital for our shareholders. In North Carolina, a margin decoupling mechanism
provides for the recovery of our approved margin from residential and commercial customers
independent of consumption patterns. The margin decoupling mechanism results in semi-annual rate
adjustments to refund any over-collection of margin or recover any under-collection of margin. We
have weather normalization adjustment (WNA) mechanisms in South Carolina and Tennessee that
partially offset the impact of colder- or warmer-than-normal weather on bills rendered during the
months of November through March for residential and commercial customers. The WNA formula
calculates the actual weather variance from normal, using 30 years of history, which increases
revenues when weather is warmer than normal and decreases revenues when weather is colder than
normal. 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. For further
information, see Note 2 to the consolidated financial statements.
Our strategic focus is our core business of providing safe, reliable and quality natural gas
distribution service to our customers in the growing Southeast market area. Part of our strategic
plan is to responsibly manage our gas distribution business through control of our operating costs,
implementation of new technologies and sound rate and regulatory initiatives. To enhance the value
and growth of our utility assets, we focus on the sound management of our capital spending, looking
at projects and initiatives that will improve service for current customers and provide
24
profitable customer growth opportunities in our service areas with an appropriate return on invested capital.
We strive for quality customer service by investing in technology, processes and people. We work
with our state regulators to maintain fair rates of return and balance the interests of our
customers and shareholders.
Our capital plan includes maintaining a long-term debt-to-capitalization ratio within a range
of 45% to 50%. We also seek to maintain a strong balance sheet and investment-grade credit ratings
to support our operating and investment needs.
We continue to work toward a business model that positions us for long-term success in a
low-carbon energy economy with a focus on future growth opportunities as there continues to be
attention at the national level with climate change legislation and impending regulation in 2011 by
the Environmental Protection Agency. We are seeking opportunities for regulatory innovation and
strategic alliances to advance our customers’ interests in energy conservation and efficiency and
environmental stewardship. We are continually reviewing our business processes for quality and
efficiency with a concentration on customer-oriented process improvements to be in a position to
seize future business opportunities.
We continually assess alternative rate structures and cost recovery mechanisms that are more
appropriate to the changing energy economy. We have been pursuing alternatives to the traditional
utility rate design that provide for the collection of margin revenue based on volumetric
throughput with new rate designs and incentives that allow utilities to encourage energy efficiency
and conservation. By breaking the link between energy consumption and margin revenues, or
decoupling as we say, utilities’ interests are aligned with customers’ interests around
conservation and energy efficiency. In North Carolina, we have decoupled rates. In South
Carolina, we operate under a rate stabilization mechanism that achieves the objectives of margin
decoupling with a one-year lag. Earlier this year, the TRA denied our filing to decouple
residential rates without prejudice to us refiling for a decoupled rate structure in a future
general rate proceeding. For 2010, these rate designs have stabilized our gas utility margin by
providing fixed recovery of 71% of our utility margins, including margin decoupling in North
Carolina, facilities charges to our customers and fixed-rate contracts; semi-fixed recovery of 18%
of our utility margins, including the rate stabilization mechanism in South Carolina and WNA in
South Carolina and Tennessee; and volumetric or periodic renegotiation of 11% of our utility
margins. For 2010, the margin decoupling mechanism in North Carolina reduced margin by $5.9
million, and the WNA in South Carolina and Tennessee reduced margin by $8.8 million.
We will continue our efforts to promote the direct use of natural gas in more homes,
businesses, industries and vehicles. We continue to believe that the expanded use of domestic
natural gas can help revitalize our economy, reduce both overall greenhouse gas emissions and
energy consumption and enhance our national energy security. With the success of on-shore drilling
and completion technologies, recent production of domestic natural gas supplies from shale
formations has resulted in an increase of domestic gas supply, which in turn has contributed to a
moderation in the price of gas. This price moderation has made natural gas more competitive
against other fuels.
We have agreements with Progress Energy Carolinas, Inc., a subsidiary of Progress Energy,
Inc., to provide natural gas delivery service to their planned power generation facilities to be
built at their Wayne County, North Carolina power generation site and at their Sutton site near
25
Wilmington, North Carolina. We also completed construction on a power generation project to
provide natural gas delivery service to a Progress Energy Carolinas’ power generation facility
located in Richmond County, North Carolina during the first quarter of fiscal 2011. In addition to
the environmental benefits associated with using natural gas at these new plants in lieu of coal,
the construction of the natural gas pipelines for these projects will also add to our natural gas
infrastructure in the eastern part of North Carolina and enhance future opportunities for economic
growth and development. In addition, we have agreements with Duke Energy Carolinas, LLC, a
subsidiary of Duke Energy Corporation, to provide natural gas delivery service to two new power
generation facilities. The facility located in Rowan County, North Carolina, was placed into
service during the first quarter of fiscal 2011. The Rockingham County, North Carolina, power
generation facility is under construction and scheduled to be placed in service November 2011. We
will continue to seek opportunities to provide long-term gas transportation service to power
generation projects in our market area. See the following discussion of our anticipated capital
investment related to the construction of the natural gas pipelines to service these new power
generation facilities in “Cash Flows from Investing Activities” in Item 7 of this Form 10-K in
Management’s Discussion and Analysis.
We are continuing to see challenging economic conditions in our market area as evidenced by
high rates of unemployment, a depressed housing market, significantly reduced new home construction
and little new commercial development. As discussed above, we are positioning ourselves to
capitalize on new opportunities as the economy slowly improves, and continue to focus on customer
conversions to natural gas and power generation gas delivery service opportunities. Seeking to
expand the use of natural gas, we continue to emphasize natural gas as the fuel of choice for
customers, including the comfort, affordability, reliability and efficiency of natural gas, as well
as reminding our customers of our reliability and safety as a company. We are forecasting gross
customer addition growth for fiscal 2011 to be 1.2%.
We invest in joint ventures to complement or supplement income from our regulated utility
operations if an opportunity aligns with our overall business strategies and allows us to leverage
our core competencies. We analyze and evaluate potential projects with a major factor being a
projected rate of return at least equal to the returns allowed in our utility operations based on
the risk of such projects. We participate in the governance of our ventures by having management
representatives on the governing boards. We monitor actual performance against expectations, and
any decision to exit an existing joint venture would be based on many factors, including
performance results and continued alignment with our business strategies. On January 1, 2010, we
sold half of our 30% interest in SouthStar to Georgia Natural Gas Company (GNGC), a subsidiary of
AGL Resources, Inc., for $57.5 million. For further information, see Note 11 to the consolidated
financial statements.
In March 2010, President Obama signed into law the “Patient Protection and Affordable Care
Act” and the “Health Care and Education Act of 2010.” These health care reform laws require
regulatory agencies to issue new regulations implementing many provisions of the laws with a phase
in over an eight-year period. We have changed the design of our health care plan in order to
comply with provisions that have already gone into effect or will be going into effect in 2011,
such as eliminating lifetime maximums on benefits, extending coverage of dependent children to age
26 and including all costs of preventive coverage. While we are not able to assess the full impact
of these laws until the implementing regulations have been adopted, based on the
26
information available to us at this time, we do not expect these laws to have a material adverse impact on our
financial position, results of operations or cash flows.
In July 2010, the “Dodd-Frank Wall Street Reform and Consumer Protection Act” (Dodd-Frank Act)
was enacted, representing an overhaul of the framework for regulation of U.S. financial markets.
The Dodd-Frank Act calls for various regulatory agencies, including the SEC and the Commodities
Futures Trading Commission, to establish regulations for implementation of many of the provisions
of the Dodd-Frank Act, and we anticipate that these new regulations will provide additional clarity
regarding the extent of the impact of this legislation on us. We expect to be able to continue to
participate in financial markets for the purchase of our financial price hedging options under our
gas supply hedging programs. However, the costs of doing so may be increased as a result of the
new legislation. We may also incur additional costs associated with our compliance with the new
regulations and anticipated additional reporting and disclosure obligations. While we are not able
to assess the full impact of the Dodd-Frank Act until all the implementing regulations have been
adopted, based on the information available to us at this time, we do not believe provisions of the
regulations implementing the Dodd-Frank Act will have a material adverse effect on our financial
position, results of operations or cash flows.
Results of Operations
The following tables present our financial highlights for the years ended October 31, 2010,
2009 and 2008.
Income Statement Components
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 vs.
|
|
|
2009 vs.
|
|
|
In thousands except per share amounts
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Operating Revenues
|
|
$
|
1,552,295
|
|
|
$
|
1,638,116
|
|
|
$
|
2,089,108
|
|
|
|
(5.2)
|
%
|
|
|
(21.6
|
)%
|
|
Cost of Gas
|
|
|
999,703
|
|
|
|
1,076,542
|
|
|
|
1,536,135
|
|
|
|
(7.1)
|
%
|
|
|
(29.9
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Margin
|
|
|
552,592
|
|
|
|
561,574
|
|
|
|
552,973
|
|
|
|
(1.6)
|
%
|
|
|
1.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and Maintenance
|
|
|
219,829
|
|
|
|
208,105
|
|
|
|
210,757
|
|
|
|
5.6
|
%
|
|
|
(1.3
|
)%
|
|
Depreciation
|
|
|
98,494
|
|
|
|
97,425
|
|
|
|
93,121
|
|
|
|
1.1
|
%
|
|
|
4.6
|
%
|
|
General Taxes
|
|
|
33,909
|
|
|
|
34,590
|
|
|
|
33,170
|
|
|
|
(2.0)
|
%
|
|
|
4.3
|
%
|
|
Income Taxes
|
|
|
62,082
|
|
|
|
70,079
|
|
|
|
62,814
|
|
|
|
(11.4)
|
%
|
|
|
11.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Expenses
|
|
|
414,314
|
|
|
|
410,199
|
|
|
|
399,862
|
|
|
|
1.0
|
%
|
|
|
2.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
138,278
|
|
|
|
151,375
|
|
|
|
153,111
|
|
|
|
(8.7)
|
%
|
|
|
(1.1
|
)%
|
|
Other Income (Expense), net of tax
|
|
|
47,387
|
|
|
|
18,124
|
|
|
|
16,169
|
|
|
|
161.5
|
%
|
|
|
12.1
|
%
|
|
Utility Interest Charges
|
|
|
43,711
|
|
|
|
46,675
|
|
|
|
59,273
|
|
|
|
(6.4)
|
%
|
|
|
(21.3
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
|
15.6
|
%
|
|
|
11.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares of Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
72,275
|
|
|
|
73,171
|
|
|
|
73,334
|
|
|
|
(1.2)
|
%
|
|
|
(0.2
|
)%
|
|
Diluted
|
|
|
72,525
|
|
|
|
73,461
|
|
|
|
73,612
|
|
|
|
(1.3)
|
%
|
|
|
(0.2
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per Share of Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.96
|
|
|
$
|
1.68
|
|
|
$
|
1.50
|
|
|
|
16.7
|
%
|
|
|
12.0
|
%
|
|
Diluted
|
|
$
|
1.96
|
|
|
$
|
1.67
|
|
|
$
|
1.49
|
|
|
|
17.4
|
%
|
|
|
12.1
|
%
|
27
Gas Deliveries, Customers, Weather Statistics and Number of Employees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent Change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 vs.
|
|
|
2009 vs.
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
Deliveries in Dekatherms (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Volumes
|
|
|
105,583
|
|
|
|
110,379
|
|
|
|
110,801
|
|
|
|
(4.3)
|
%
|
|
|
(0.4)
|
%
|
|
Transportation Volumes
|
|
|
147,032
|
|
|
|
106,495
|
|
|
|
99,450
|
|
|
|
38.1
|
%
|
|
|
7.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Throughput
|
|
|
252,615
|
|
|
|
216,874
|
|
|
|
210,251
|
|
|
|
16.5
|
%
|
|
|
3.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Secondary Market Volumes
|
|
|
46,823
|
|
|
|
46,057
|
|
|
|
53,442
|
|
|
|
1.7
|
%
|
|
|
(13.8)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customers Billed (at period end)
|
|
|
946,785
|
|
|
|
937,962
|
|
|
|
935,724
|
|
|
|
0.9
|
%
|
|
|
0.2
|
%
|
|
Gross Customer Additions
|
|
|
10,975
|
|
|
|
12,608
|
|
|
|
20,506
|
|
|
|
(13.0)
|
%
|
|
|
(38.5)
|
%
|
|
Degree Days
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual
|
|
|
3,535
|
|
|
|
3,413
|
|
|
|
3,195
|
|
|
|
3.6
|
%
|
|
|
6.8
|
%
|
|
Normal
|
|
|
3,321
|
|
|
|
3,324
|
|
|
|
3,358
|
|
|
|
(0.1)
|
%
|
|
|
(1.0)
|
%
|
|
Percent colder (warmer) than normal
|
|
|
6.4
|
%
|
|
|
2.7
|
%
|
|
|
(4.9)
|
%
|
|
|
n/a
|
|
|
|
n/a
|
|
|
Number of Employees (at period end)
|
|
|
1,788
|
|
|
|
1,821
|
|
|
|
1,833
|
|
|
|
(1.8)
|
%
|
|
|
(0.7)
|
%
|
Net Income
Net income increased $19.1 million in 2010 compared with 2009 primarily due to the following
changes, which increased net income:
|
|
•
|
|
$49.7 million gain on sale of interest in equity method investment.
|
|
|
|
|
•
|
|
$3 million decrease in utility interest charges.
|
|
|
|
|
•
|
|
$.9 million decrease in non-operating expense.
|
|
|
|
|
•
|
|
$.7 million decrease in general taxes.
|
|
|
|
|
•
|
|
$.6 million decrease in charitable contributions.
|
|
|
|
|
•
|
|
$.6 million increase in non-operating income.
|
These changes were partially offset by the following changes, which decreased net income:
|
|
•
|
|
$11.7 million increase in operations and maintenance expenses.
|
|
|
|
|
•
|
|
$10 million increase in income taxes.
|
|
|
|
|
•
|
|
$9 million decrease in margin (operating revenues less cost of gas).
|
|
|
|
|
•
|
|
$4.6 million decrease in income from equity method investments.
|
|
|
|
|
•
|
|
$1.1 million increase in depreciation.
|
Net income increased $12.8 million in 2009 compared with 2008 primarily due to the following
changes, which increased net income:
|
|
•
|
|
$12.6 million decrease in utility interest charges.
|
|
|
|
|
•
|
|
$8.6 million increase in margin.
|
|
|
|
|
•
|
|
$5.7 million increase in income from equity method investments.
|
|
|
|
|
•
|
|
$2.7 million decrease in operations and maintenance expenses.
|
These changes were partially offset by the following changes, which decreased net income:
28
|
|
•
|
|
$8.4 million increase in income taxes.
|
|
|
|
|
•
|
|
$4.3 million increase in depreciation.
|
|
|
|
|
•
|
|
$2.7 million decrease in net other income (expense) items.
|
|
|
|
|
•
|
|
$1.4 million increase in general taxes.
|
Operating Revenues
Operating revenues in 2010 decreased $85.8 million compared with 2009 primarily due to the
following decreases:
|
|
•
|
|
$65.4 million of gas costs primarily from lower total gas costs passed through to
sales customers.
|
|
|
|
|
•
|
|
$11.9 million from decreased revenues under the margin decoupling mechanism. As
discussed in “Financial Condition and Liquidity,” the margin decoupling mechanism in
North Carolina adjusts for variations in residential and commercial use per customer,
including those due to conservation and weather.
|
|
|
|
|
•
|
|
$7.6 million from decreased revenues under the WNA in South Carolina and Tennessee.
|
These decreases were partially offset by the following increases:
|
|
•
|
|
$3.7 million from revenues in secondary market transactions due to increased
activity. Secondary market transactions consist of off-system sales and capacity
release arrangements and are part of our regulatory gas supply management program with
regulatory-approved sharing mechanisms between our utility customers and our
shareholders.
|
|
|
|
|
•
|
|
$1.2 million increase from volumes delivered to transportation customers.
|
Operating revenues in 2009 decreased $451 million compared with 2008 primarily due to the
following decreases:
|
|
•
|
|
$294.7 million from revenues in secondary market transactions due to decreased
activity and gas costs.
|
|
|
|
|
•
|
|
$112.1 million primarily from lower gas costs passed through to sales customers.
|
|
|
|
|
•
|
|
$19.4 million from revenues under the margin decoupling mechanism.
|
|
|
|
|
•
|
|
$12.7 million of commodity gas costs from volume deliveries to sales customers.
|
|
|
|
|
•
|
|
$8 million from revenues under the WNA in South Carolina and Tennessee.
|
|
|
|
|
•
|
|
$5.4 million from a decrease in volumes delivered to transportation customers other
than power generation.
|
Cost of Gas
Cost of gas in 2010 decreased $76.8 million compared with 2009 primarily due to $131.1 million
from lower priced gas costs passed through to sales customers, partially offset by the following
increases:
29
|
|
•
|
|
$31.7 million of commodity gas costs from increased volume deliveries to sales
customers.
|
|
|
|
|
•
|
|
$4.8 million from commodity gas costs in secondary market transactions due to
increased activity.
|
Cost of gas in 2009 decreased $459.6 million compared with 2008 primarily due to the following
decreases:
|
|
•
|
|
$294.2 million from commodity gas costs in secondary market transactions due to
decreased activity and gas costs.
|
|
|
|
|
•
|
|
$127.2 million from lower gas costs passed through to sales customers.
|
|
|
|
|
•
|
|
$12.7 million of commodity gas costs from volume deliveries to sales customers.
|
In all three states, we are authorized to recover from customers all prudently incurred gas
costs. Changes 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 and are added to or deducted from cost of gas and are included in “Amounts due from
customers” or “Amounts due to customers” in the consolidated balance sheets.
Margin
Our utility margin is defined as natural gas revenues less natural gas commodity purchases and
fixed gas costs for transportation and storage capacity. Margin, rather than revenues, is used by
management to evaluate utility operations due to the passthrough of changes in wholesale commodity
prices, which accounted for 49% of revenues for the twelve months ended October 31, 2010, and
transportation and storage costs, which accounted for 8%.
In general rate proceedings, state regulatory commissions authorize us to recover a margin,
which is the applicable billing rate less cost of gas, on each unit of gas delivered. The
commissions also authorize us to recover margin losses resulting from negotiating lower rates to
industrial customers when necessary to remain competitive. The ability to recover such negotiated
margin reductions is subject to continuing regulatory approvals.
Our utility margin is also impacted by certain regulatory mechanisms as defined elsewhere in
this document. These include WNA in Tennessee and South Carolina, the Natural Gas Rate
Stabilization in South Carolina, secondary market activity in North Carolina and South Carolina,
Tennessee Incentive Plan (TIP) in Tennessee, margin decoupling mechanism in North Carolina and
negotiated loss treatment and the collection of uncollectible gas costs in all three jurisdictions.
We retain 25% of secondary market margins generated through off-system sales and capacity release
activity in all jurisdictions, with 75% credited to customers through the incentive plans.
Margin decreased $9 million in 2010 compared with 2009 primarily due to the following
decreases:
|
|
•
|
|
$6.6 million from net adjustments to gas costs, accounts payable and lost and
unaccounted for gas.
|
|
|
|
|
•
|
|
$1.1 million from decreased volatility in secondary market transactions.
|
30
|
|
•
|
|
$1 million from our residential and commercial markets, primarily due to a $3
million negative impact of warmer weather in the non-weather normalized months of April
and October, partially offset by customer growth.
|
Margin increased $8.6 million in 2009 compared with 2008 primarily due to an increase of $15.7
million from increased rates approved in the North Carolina general rate case effective November 1,
2008.
This increase was partially offset by the following decreases:
|
|
•
|
|
$4.7 million from net adjustments to gas costs, inventory, supplier refunds and lost
and unaccounted for gas due to regulatory gas cost reviews.
|
|
|
|
|
•
|
|
$2.9 million from decreased volumes delivered to industrial customers.
|
Operations and Maintenance Expenses
Operations and maintenance expenses increased $11.7 million in 2010 compared with 2009
primarily due to the following increases:
|
|
•
|
|
$4.2 million in payroll expense primarily from increases in long-term incentive plan
accruals priced at a higher current stock price and merit wage increases for
non-officer
employees.
|
|
|
|
|
•
|
|
$3.3 million in employee benefits expense due primarily to increases in pension
expense from a lower discount rate used to determine periodic benefit cost and group
insurance expense from higher claims.
|
|
|
|
|
•
|
|
$2.4 million in contract labor for contract billing
services, telecom and activity related to a new corporate rebranding campaign.
|
|
|
|
|
•
|
|
$.9 million in advertising and sales promotion related to a new corporate rebranding
campaign.
|
Operations and maintenance expenses decreased $2.7 million in 2009 compared with 2008
primarily due to the following decreases:
|
|
•
|
|
$3.6 million in employee benefits expense due to reductions in pension expense
resulting from changes in the discount rate and plan design, regulatory deferral of the
Tennessee portion of the annual plan funding and lower group insurance expense from
claims experience, and fewer employees.
|
|
|
|
|
•
|
|
$1.4 million in contract labor for contract billing services, telecom and financial,
gas accounting and compliance systems.
|
These decreases were partially offset by an increase of $2.7 million in regulatory
amortization expense.
Depreciation
Depreciation expense increased from $93.1 million to $98.5 million over the three-year period
2008 to 2010 primarily due to increases in plant in service.
31
General Taxes
General taxes decreased by an insignificant amount in 2010 compared with 2009.
General taxes increased $1.4 million in 2009 compared with 2008 primarily due to increases in
property taxes related to a larger property tax base and reassessments.
Other Income (Expense)
Other Income (Expense) is comprised of income from equity method investments, gain on sale of
interest in equity method investment, non-operating income, charitable contributions, non-operating
expense and income taxes related to these items. Non-operating income includes non-regulated
merchandising and service work, home warranty programs, subsidiary operations, interest income and
other miscellaneous income. Non-operating expense is comprised of other miscellaneous expenses.
The primary changes to Other Income (Expense) were in income from equity method investments
and the gain on the sale of half of our ownership interest in SouthStar. All other changes were
not significant.
On January 1, 2010, we sold half of our 30% membership interest in SouthStar to the other
member of the joint venture and retained a 15% earnings and membership interest after the sale.
The pre-tax gain on the sale was $49.7 million. The after-tax gain was $30.3 million, or $.42 per
diluted earnings per share, for 2010.
Income from equity method investments decreased $4.6 million in 2010 compared with 2009 due to
a $4.5 million decrease in earnings from SouthStar primarily due to the recording of earnings at
the new 15% ownership interest as of January 1, 2010 and a change in the retail pricing mix chosen
by SouthStar customers with a decrease in the average number of customers, losses on weather
derivatives and a decreased contribution from storage and transportation asset management due to
higher transportation and commodity prices, partially offset by increased average customer usage
due to colder weather, favorable changes in the lower of cost or market storage inventory
adjustments and higher retail price spreads.
Income from equity method investments increased $5.7 million in 2009 compared with 2008
primarily due to an increase of $6.3 million in earnings from SouthStar largely due to higher
contributions from the management of storage and transportation assets, margin impacts from lower
of cost or market inventory adjustments, higher operating margins in Ohio, a 2008 pricing
settlement with the Georgia Public Service Commission and increased average customer usage,
partially offset by a change in retail pricing plan mix and a decrease in the average number of
customers.
Utility Interest Charges
Utility interest charges decreased $3 million in 2010 compared with 2009 primarily due to the
following changes:
32
|
|
•
|
|
$9.1 million increase in net interest expense due to a decrease in interest charged
on amounts due from customers (receivable), which earn a carrying charge, as those
balances were lower in the current period.
|
|
|
|
|
•
|
|
$7.7 million decrease in interest expense due to an increase in the borrowed allowance for
funds used during construction (AFUDC), which is recorded as income, primarily due to
increased construction expenditures.
|
|
|
|
|
•
|
|
$2.4 million decrease in interest expense on long-term debt primarily due to lower
amounts of debt outstanding.
|
|
|
|
|
•
|
|
$1.8 million decrease in interest expense on short-term debt primarily due to lower
levels of borrowing in the current period combined with an average interest rate for
the current period approximately 35 basis points lower than the prior year period.
|
Utility interest charges decreased $12.6 million in 2009 compared with 2008 primarily due to
the following changes:
|
|
•
|
|
$9.1 million decrease in net interest expense due to an increase in interest earned
on amounts due from customers in the current period.
|
|
|
|
|
•
|
|
$4.7 million decrease in interest on short-term debt primarily due to the average
interest rates during the current period being 290 basis points lower than the prior
year period even though borrowings were higher in the current period.
|
|
|
|
|
•
|
|
$1.7 million increase in the allowance for borrowed funds.
|
Financial Condition and Liquidity
To meet our capital and liquidity requirements, we rely on certain resources, including cash
flows from operating activities, access to capital markets, cash generated from our investments in
joint ventures and short-term bank borrowings. Our capital market 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.
We believe that the amounts available to us under our existing and planned new credit facility
and the issuance of debt and equity securities, together with cash provided by operating
activities, will continue to allow us to meet our needs for working capital, construction
expenditures, investments in joint ventures, anticipated debt redemptions, dividend payments,
pension plan contributions, common stock repurchases and other cash needs.
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 bank borrowings to meet seasonal working capital needs. During our first and
second quarters, we generally experience overall positive cash flows from the sale of flowing gas
and gas in storage and the collection of amounts billed to customers during the winter heating
season (November through March). Cash requirements generally increase during the third and fourth
quarters due to increases in natural gas purchases for storage, seasonal construction activity and
decreases in receipts from customers.
33
During the winter heating season, our accounts payable increase to reflect amounts due to our
natural gas suppliers for commodity and pipeline capacity. The cost of the 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 and in
amounts due to/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. 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.
Because of the economic weakness, including continued high unemployment, we may incur
additional bad debt expense as a result of the winter heating season, as well as experience
increased customer conservation. We may incur more short-term debt to pay for gas supplies and
other operating costs since collections from customers could be slower and some customers may not
be able to pay their bills. Regulatory margin stabilizing and cost recovery mechanisms, such as
those that allow us to recover the gas cost portion of bad debt expense, will significantly
mitigate the impact these factors may have on our results of operations.
Net cash provided by operating activities was $360.5 million in 2010, $344.3 million in 2009
and $69.2 million in 2008. Net cash provided by operating activities reflects a $19.1 million
increase in net income for 2010 compared with 2009, including the after-tax gain of $30.3 million
on the sale of half of our interest in SouthStar as discussed above in “Results of Operations.”
The effect of changes in working capital on net cash provided by operating activities is described
below:
|
|
•
|
|
Trade accounts receivable and unbilled utility revenues decreased $21.3 million in
the current period primarily due to a decrease in unbilled volumes and amounts billed
to customers reflecting lower gas costs in 2010 as compared with 2009, partially offset
by weather in the current period being 3.6% colder than the same prior period. Volumes
sold to residential and commercial customers increased 4.5 million dekatherms primarily
due to the colder weather. Total throughput, including industrial and power generation
volumes, increased 35.7 million dekatherms as compared with the same prior period.
|
|
|
|
|
•
|
|
Net amounts due from customers decreased $133.8 million in the current period
primarily due to the collection of deferred gas costs through rates.
|
|
|
|
|
•
|
|
Gas in storage decreased $1.9 million in the current period primarily due to a
decrease in the weighted average cost of gas purchased for injection, partially offset
by an increased volume of gas in storage at period end.
|
|
|
|
|
•
|
|
Prepaid gas costs decreased $3.6 million in the current period primarily due to the
lower average cost of gas in prepaid storage and a decrease in the volumes. Under
|
34
|
|
|
|
some gas supply contracts, prepaid gas costs incurred during 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 $4.2 million in the current period primarily due to
gas purchases at lower costs during the period.
|
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 a WNA mechanism in South Carolina and Tennessee that
partially offsets the impact of colder- or warmer-than-normal weather on bills rendered in November
through March for residential and commercial customers. The WNA in South Carolina and Tennessee
generated credits to customers of $8.8 million in 2010 and $1.2 million in 2009 and charges of $6.8
million in 2008. In Tennessee, adjustments are made directly to individual customer bills. In
South Carolina, the adjustments are calculated at the individual customer level but are recorded in
“Amounts due from customers” or “Amounts due to customers” in the
consolidated balance sheets 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 consumption patterns. The
margin decoupling mechanism reduced margin by $5.9 million in 2010 and increased margin by $6
million in 2009 and $25.4 million in 2008. Our gas costs are recoverable through PGA procedures
and are not affected by the WNA or the margin decoupling mechanism.
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.
The regulated utility competes with 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. Numerous factors can influence customer
demand for natural gas, including price, value, availability, environmental attributes, 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 price. 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 US dollar versus other currencies. Our liquidity could be impacted, either positively or
negatively, as a result of alternate fuel decisions made by industrial customers.
35
In an effort to keep customer rates competitive and to maximize earnings, we continue to
implement business process improvement and operations and maintenance cost management programs to
capture operational efficiencies while improving customer service and maintaining a safe and
reliable system.
Cash Flows from Investing Activities
. Net cash used in investing activities was $128.6
million in 2010, $129.6 million in 2009 and $177.4 million in 2008. Net cash used in investing
activities was primarily for utility construction expenditures. Gross utility construction
expenditures were $199.1 million in 2010, a 54% increase from the $129 million in 2009, primarily
due to expending $52 million for the construction of power generation projects in 2010 as compared
with $3 million funded for these projects in the prior year.
We have a substantial capital expansion program for construction of distribution facilities,
purchase of equipment and other general improvements. This program primarily supports our
system infrastructure and the growth in our customer base. Significant utility construction
expenditures are expected to continue to meet long-term growth, particularly in the power
generation market, and are part of our long-range forecasts that are prepared at least annually and
typically cover a forecast period of five years. We are not contractually obligated to expend
capital until the work is completed.
We anticipate making capital expenditures, including AFUDC, of $146 million, $122 million and $58 million in our
fiscal years 2011, 2012 and 2013, respectively, to provide natural gas service in the power
generation market. Specific projects are discussed in more detail below. These expenditures are
significantly higher than we have traditionally expended. All expenditures related to these
projects will be funded with internally generated cash as well as short-term and long-term debt.
We do not anticipate the need to issue additional equity to fund these projects.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In millions
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Utility capital expenditures
|
|
$
|
167
|
|
|
$
|
178
|
|
|
$
|
206
|
|
|
Power generation related capital expenditures
|
|
|
146
|
|
|
|
122
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total forecasted capital expenditures
|
|
$
|
313
|
|
|
$
|
300
|
|
|
$
|
264
|
|
|
|
|
|
|
|
|
|
|
|
|
In October 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide
natural gas delivery service to a power generation facility to be built at their Wayne County,
North Carolina site. The agreement, approved by the NCUC in May 2010, calls for us to construct 38
miles of 20-inch transmission pipeline along with compression facilities to provide natural gas
delivery service to the plant by June 2012; construction began in February 2010. Our investment in
the pipeline and compression facilities is estimated at $89 million and is supported by a long-term
service agreement. We have incurred $3.5 million on this project as of October 31, 2010. To
provide the additional delivery service, we have executed an agreement with Cardinal Pipeline
Company, LLC (Cardinal) to expand our firm capacity requirement by 149,000 dekatherms per day to
serve this facility. This will require Cardinal to spend as much as $53.1 million to expand its
system. As a 21.49% equity venture partner of Cardinal, we will invest as much as $11.4 million in
Cardinal’s system expansion. For further information regarding this agreement, see Note 11 to the
consolidated financial statements.
36
In April 2010, we reached another agreement with Progress Energy Carolinas to provide natural
gas delivery service to a power generation facility to be built at their existing Sutton site near
Wilmington, North Carolina. The agreement, approved by the NCUC in May 2010, calls for us to
construct 133 miles of transmission pipeline along with compression facilities to provide natural
gas delivery service to the plant by June 2013; we began construction in May 2010. Our investment
in the pipeline and compression facilities is estimated at $231 million, and our service to
Progress Energy Carolinas is supported by a long-term service agreement. We have incurred $3
million on this project as of October 31, 2010.
The Sutton facilities will also create cost effective expansion capacity that we will use to
help serve the growing natural gas requirements of our customers in the eastern part of North
Carolina. At the present time with the timing and design scope of the Sutton facilities, there is
no current need to proceed with our previously announced Robeson liquefied natural gas (LNG) peak
storage project. The timing and design scope of the expansion of our facilities in this area will
be determined as our system infrastructure and market supply growth requirements in North
Carolina dictate.
During the first quarter of fiscal 2011, we completed construction on a power generation
project that will provide natural gas delivery service to a Progress Energy Carolinas’ power
generation facility located in Richmond County, North Carolina, at a total estimated project cost
of $23 million.
During the first quarter of fiscal 2011, we placed a power generation project into service for
natural gas delivery service to a Duke Energy Carolinas’ power generation facility located in Rowan
County, North Carolina, at a total estimated project cost of $29 million. We have a second
agreement with Duke Energy Carolinas for their Rockingham County, North Carolina power generation
facility for service planned November 2011.
During 2007, $2.2 million of supplier refunds was recorded as restricted cash. Pursuant to a
2007 NCUC order, restrictions on cash totaling $2.2 million were removed in 2008, and we liquidated
all certificates of deposit and similar investments that held any supplier refunds due to customers
and transferred these funds upon maturity to the North Carolina deferred account.
In 2009 and 2008, we contributed $.9 million and $10.9 million, respectively, to our Hardy
Storage Company, LLC (Hardy Storage) joint venture as part of our equity contribution for
construction of the FERC regulated interstate storage facility. We made no contribution in 2010 as
Hardy Storage converted its construction interim notes in March 2010. For further information on
Hardy Storage, see Note 11 to the consolidated financial statements.
On January 1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and
retained a 15% earnings and membership share in SouthStar after the sale. Prior to the sale,
earnings and losses were allocated to us at 25% with the exception of earnings and losses in the
Ohio and Florida markets, which were allocated to us at our membership percentage of 30%. At
closing, we received $57.5 million from GNGC resulting in an after-tax gain of $30.3 million, or
$.42 per diluted share. For further information regarding the sale, see Note 11 to the
consolidated financial statements.
37
During 2008, we sold various properties located in Burlington and High Point, North Carolina,
Spartanburg, South Carolina and Nashville, Tennessee for $13.2 million, net of expenses. In
accordance with utility plant accounting, we recorded the disposition of the land from these sales
as a pre-tax gain of $1.2 million with a deferral of $.5 million related to the Nashville sale.
The net pre-tax gain of $.7 million was recorded in “Other Income (Expense)” in the consolidated
statements of income. We recorded a gain of $3.1 million on the disposition of the buildings as a
charge to “Accumulated depreciation” in the consolidated balance sheets. We entered into a
sale-leaseback agreement on the Nashville property for a lease of 18
1
/
2
months, where the $.5
million deferred gain was amortized on a straight-line basis over the life of the lease and
recorded to “Other Income (Expense)” in the consolidated statements of income. As of October 31,
2010, the $.5 million deferred gain was fully amortized.
Cash Flows from Financing Activities
. Net cash provided by (used in) financing activities
was ($233.9) million in 2010, ($214.1) million in 2009 and $107.7 million in 2008. Funds are
primarily provided from bank borrowings and the issuance of common stock through DRIP and
employee stock purchase plans, net of purchases under the common stock repurchase program. We may
sell common stock and long-term debt when market and other conditions favor such long-term
financing. Funds are primarily used to pay down outstanding short-term bank borrowings, to
repurchase common stock under the common stock repurchase program and to pay quarterly dividends on
our common stock. As of October 31, 2010, our current assets were $327.8 million and our current
liabilities were $498.6 million, primarily due to seasonal requirements as discussed above.
As of October 31, 2010, we had committed lines of credit of $450 million with the ability to
expand up to $600 million under our syndicated credit facility that expires April 2011 to meet
working capital needs, capital expenditures and approved acquisitions. We pay an annual fee of
$35,000 plus six basis points for any unused amount up to $450 million. Outstanding short-term
bank borrowings decreased from $306 million as of October 31, 2009 to $242 million as of October
31, 2010 primarily due to lower commodity gas costs and recovery of amounts due from customers.
During the twelve months ended October 31, 2010, short-term bank borrowings ranged from zero to
$342.5 million, and interest rates ranged from .48% to .61% when borrowing (weighted average of
.50%).
Effective December 3, 2008, we entered into a syndicated seasonal credit facility with
aggregate commitments totaling $150 million. Advances under this seasonal facility bore interest
at a rate based on the 30-day LIBOR rate plus from 75 to 175 basis points, based on our credit
ratings. This seasonal credit facility expired on March 31, 2009. We entered into this facility
to provide lines of credit in addition to the syndicated credit facility discussed above in order
to have additional resources to meet seasonal cash flow requirements and general corporate needs.
This seasonal credit facility replaced the two short-term credit facilities with banks for
unsecured commitments totaling $75 million that were effective from October 27 and 29, 2008 through
December 3, 2008.
As of October 31, 2010, we had available letters of credit of $5 million under our syndicated
five-year revolving credit facility, of which $2.7 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 October 31, 2010, unused lines of credit available under our
38
syndicated five-year revolving credit facility, including the issuance of the letters of credit, totaled
$205.3 million.
On November 18, 2010, we entered into a joint commitment letter dated November 17, 2010 to
replace our existing credit facility with a syndicated $650 million three-year revolving credit
facility, scheduled to be executed and effective by January 31, 2011. The new credit facility is
expected to have an option for an additional commitment of $200 million, for a total aggregate
commitment of $850 million. The new credit facility is expected to have financial covenants
similar to our current existing syndicated credit facility and provisions regarding defaulting
lenders and replacements of lenders. Because of the current market conditions, we anticipate that
the costs of our new credit facility will be higher than those costs incurred under our current
credit facility.
The level of short-term bank borrowings can vary significantly due to changes in the wholesale
prices of natural gas, the level of purchases of natural gas supplies for storage and hedging
transactions 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.
With the appropriate notice, we have the right to redeem our 6.25% insured quarterly notes on
June 1, 2011 and thereafter without incurring a premium or penalty. These notes have a balance of
$196.9 million as of October 31, 2010. We intend to exercise our redemption right effective June
1, 2011 and finance the redemption by issuing $200 million of long-term debt at a lower interest
rate. We do not anticipate issuing any other long-term debt in fiscal 2011. We intend to issue
$225 million of long-term debt in the first quarter of our fiscal year 2012 for general corporate
purposes. We continually monitor customer growth trends in our markets along with the economic
recovery of our service area for the timing of any infrastructure investments that would require
the need for additional long-term debt.
We retired the balance of $60 million of our 7.8% medium-term notes and $30 million of our
7.35% medium-term notes in September 2010 and September 2009, respectively, as they became due.
The balance of $60 million of our 6.55% medium-term notes becomes due in September 2011.
From time to time, we have repurchased shares of common stock under our Common Stock Open
Market Purchase Program and our ASR program as described in Note 5 to the consolidated financial
statements. During 2010, we repurchased 1.8 million shares for $47.3 million, leaving a balance of
4,510,074 shares in the Common Stock Open Market Purchase Program. During 2009 and 2008, we
repurchased .7 million and 1.6 million shares for $17.9 million and $42.7 million, respectively.
We anticipate repurchasing .8 million shares of common stock through an ASR agreement in the first
quarter of our fiscal year 2011.
During 2010, we issued $19.1 million of common stock through DRIP and employee stock purchase
plans. During 2009, we issued $14.4 million of common stock through the DRIP and employee stock
purchase plan. As a result of an administrative error, we received $347,000 from November 1, 2009
through November 16, 2009 from the sale of shares of common stock under our DRIP that was from
unregistered shares. On February 8, 2010, we filed a registration statement
39
(Rescission Offer) which offered to rescind the purchase of these unregistered shares
and registered all previously unregistered shares issued under the DRIP during that period. Under
the Rescission Offer, 711 shares were rescinded for an aggregate consideration of $18,900. For
further information, see Note 5 to the consolidated financial statements.
We have paid quarterly dividends on our common stock since 1956. We increased our common
stock dividend on an annualized basis by $.04 per share in 2010, 2009 and 2008. Dividends of $80.3
million, $78.4 million and $75.5 million for 2010, 2009 and 2008, respectively, were paid on common
stock. Provisions contained in certain note agreements under which long-term debt was issued
restrict the amount of cash dividends that may be paid. As of October 31, 2010, our retained
earnings were not restricted. On December 16, 2010, the Board of Directors declared a quarterly
dividend on common stock of $.28 per share, payable January 18, 2011 to shareholders of record at
the close of business on December 27, 2010. For further information, see Note 3 to the
consolidated financial statements.
Our long-term targeted capitalization ratio is 45-50% in long-term debt and 50-55% in common
equity. Accomplishing this capital structure objective and maintaining sufficient cash flow are
necessary to maintain attractive credit ratings. As of October 31, 2010, our capitalization,
including current maturities of long-term debt, consisted of 43% in long-term debt and 57% in
common equity.
The components of our total debt outstanding (short-term and long-term) to our total
capitalization as of October 31, 2010 and 2009 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 31
|
|
|
October 31
|
|
|
In thousands
|
|
2010
|
|
|
Percentage
|
|
|
2009
|
|
|
Percentage
|
|
|
Short-term debt
|
|
$
|
242,000
|
|
|
|
12
|
%
|
|
$
|
306,000
|
|
|
|
15
|
%
|
|
Current portion of long-term debt
|
|
|
60,000
|
|
|
|
3
|
%
|
|
|
60,000
|
|
|
|
3
|
%
|
|
Long-term debt
|
|
|
671,922
|
|
|
|
35
|
%
|
|
|
732,512
|
|
|
|
36
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt
|
|
|
973,922
|
|
|
|
50
|
%
|
|
|
1,098,512
|
|
|
|
54
|
%
|
|
Common stockholders’ equity
|
|
|
964,941
|
|
|
|
50
|
%
|
|
|
927,948
|
|
|
|
46
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capitalization (including short-term debt)
|
|
$
|
1,938,863
|
|
|
|
100
|
%
|
|
$
|
2,026,460
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Credit ratings impact our ability to obtain short-term and long-term financing and the
cost of such financings. 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. In determining our credit
ratings, the rating agencies consider various factors. The more significant quantitative factors
include:
|
|
•
|
|
Ratio of total debt to total capitalization, including balance sheet leverage,
|
|
|
|
|
•
|
|
Ratio of net cash flows to capital expenditures,
|
|
|
|
|
•
|
|
Funds from operations interest coverage,
|
|
|
|
|
•
|
|
Ratio of funds from operations to average total debt,
|
|
|
|
|
•
|
|
Pension liabilities and funding status, and
|
|
|
|
|
•
|
|
Pre-tax interest coverage.
|
40
Qualitative factors include, among other things:
|
|
•
|
|
Stability of regulation in the jurisdictions in which we operate,
|
|
|
|
|
•
|
|
Consistency of our earnings over time,
|
|
|
|
|
•
|
|
Risks and controls inherent in the distribution of natural gas,
|
|
|
|
|
•
|
|
Predictability of cash flows,
|
|
|
|
|
•
|
|
Quality of business strategy and management,
|
|
|
|
|
•
|
|
Corporate governance guidelines and practices,
|
|
|
|
|
•
|
|
Industry position, and
|
|
|
|
|
•
|
|
Contingencies.
|
As of October 31, 2010, all of our long-term debt was unsecured. Our long-term debt is rated
“A” by Standard & Poor’s Ratings Services and “A3” by Moody’s Investors Service (Moody’s).
Currently, with respect to our long-term debt, the credit agencies maintain their stable outlook.
A significant decline in our operating performance or a significant reduction in our liquidity
could trigger a negative change in our ratings outlook or even a reduction in our credit ratings by
our 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 October 31,
2010, there has been no event of default giving rise to acceleration of our debt.
The default provisions of some or all of our senior debt include:
|
|
•
|
|
Failure to make principal or interest payments,
|
|
|
|
|
•
|
|
Bankruptcy, liquidation or insolvency,
|
|
|
|
|
•
|
|
Final judgment against us in excess of $1 million that after 60 days is not
discharged, satisfied or stayed pending appeal,
|
|
|
|
|
•
|
|
Specified events under the Employee Retirement Income Security Act of 1974,
|
|
|
|
|
•
|
|
Change in control, and
|
|
|
|
|
•
|
|
Failure to observe or perform covenants, including:
|
|
|
•
|
|
interest coverage of 1.75 times, which was 5.91 times as of October
31, 2010,
|
|
|
|
|
•
|
|
funded debt cannot exceed 70% of total capitalization, which was 43%
as of October 31, 2010,
|
|
|
|
|
•
|
|
funded debt of all subsidiaries in the aggregate cannot exceed 15% of
total capitalization, of which there is no funded debt of our
subsidiaries as of October 31, 2010,
|
|
|
|
|
•
|
|
restrictions on permitted liens,
|
|
|
|
|
•
|
|
restrictions on paying dividends on or repurchasing our stock or
making investments in subsidiaries, and
|
|
|
|
|
•
|
|
restrictions on burdensome agreements.
|
41
Contractual Obligations and Commitments
We have incurred various contractual obligations and commitments in the normal course of
business. As of October 31, 2010, our estimated recorded and unrecorded contractual obligations
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
4-5
|
|
|
After
|
|
|
|
|
|
In thousands
|
|
1 year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Recorded contractual obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (1)
|
|
$
|
60,000
|
|
|
$
|
100,000
|
|
|
$
|
—
|
|
|
$
|
571,922
|
|
|
$
|
731,922
|
|
|
Short-term debt (2)
|
|
|
242,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
242,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
302,000
|
|
|
$
|
100,000
|
|
|
$
|
—
|
|
|
$
|
571,922
|
|
|
$
|
973,922
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
See Note 3 to the consolidated financial statements.
|
|
|
|
(2)
|
|
See Note 4 to the consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than
|
|
|
1-3
|
|
|
4-5
|
|
|
After
|
|
|
|
|
|
In thousands
|
|
1 year
|
|
|
Years
|
|
|
Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Unrecorded contractual obligations
and commitments: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline and storage capacity (2)
|
|
$
|
150,914
|
|
|
$
|
315,831
|
|
|
$
|
120,252
|
|
|
$
|
296,836
|
|
|
$
|
883,833
|
|
|
Gas supply (3)
|
|
|
11,862
|
|
|
|
60
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,922
|
|
|
Interest on long-term debt (4)
|
|
|
50,163
|
|
|
|
131,272
|
|
|
|
79,286
|
|
|
|
532,656
|
|
|
|
793,377
|
|
|
Telecommunications and
information technology (5)
|
|
|
15,316
|
|
|
|
5,448
|
|
|
|
—
|
|
|
|
—
|
|
|
|
20,764
|
|
|
Qualified and nonqualified
pension plan
funding (6)
|
|
|
22,862
|
|
|
|
36,394
|
|
|
|
11,453
|
|
|
|
—
|
|
|
|
70,709
|
|
|
Postretirement benefits plan
funding (6)
|
|
|
1,400
|
|
|
|
4,000
|
|
|
|
1,300
|
|
|
|
—
|
|
|
|
6,700
|
|
|
Operating leases (7)
|
|
|
4,584
|
|
|
|
12,834
|
|
|
|
4,546
|
|
|
|
1,411
|
|
|
|
23,375
|
|
|
Other purchase obligations (8)
|
|
|
5,147
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5,147
|
|
|
Letters of credit (9)
|
|
|
2,714
|
|
|
|
10,474
|
|
|
|
6,982
|
|
|
|
—
|
|
|
|
20,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
264,962
|
|
|
$
|
516,313
|
|
|
$
|
223,819
|
|
|
$
|
830,903
|
|
|
$
|
1,835,997
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
In accordance with GAAP, these items are not reflected in our consolidated balance sheets.
|
|
|
|
(2)
|
|
Recoverable through PGA procedures.
|
|
|
|
(3)
|
|
Reservation fees are recoverable through PGA procedures.
|
|
|
|
(4)
|
|
See Note 3 to the consolidated financial statements.
|
|
|
|
(5)
|
|
Consists primarily of maintenance fees for hardware and software applications, usage fees, local and
long-distance data costs, frame relay, and cell phone and pager usage fees.
|
|
|
|
(6)
|
|
Estimated funding beyond five years is not available. See Note 8 to the consolidated financial statements.
|
|
|
|
(7)
|
|
See Note 7 to the consolidated financial statements.
|
|
|
|
(8)
|
|
Consists primarily of pipeline products, vehicles, contractors and merchandise.
|
|
|
|
(9)
|
|
See Note 4 to the consolidated financial statements.
|
|
|
42
Off-balance Sheet Arrangements
We have no off-balance sheet arrangements other than operating leases, letters of credit and
the credit extended by our counterparty in over-the-counter (OTC) derivative contracts. The
letters of credit and operating leases are discussed in Note 4 and Note 7, respectively, to the
consolidated financial statements and are reflected in the table above. The credit extended by our
counterparty in OTC derivative contracts in 2009 is discussed in Note 6 to the consolidated
financial statements.
As of October 31, 2009, Piedmont Energy Partners, Inc., a wholly owned subsidiary of Piedmont,
had entered into a guaranty in the normal course of business pertaining to our investment in Hardy
Storage. The guaranty involved some levels of performance and credit risk that were not included
in our consolidated balance sheets. We had recorded an estimated liability of $1.2 million as of
October 31, 2009. The possibility of having to perform on the guaranty was largely dependent upon
the future operations of Hardy Storage, third parties or the occurrence of certain future events.
In March 2010, Hardy Storage obtained long-term non-recourse project financing, and we were
released from any liability under the guaranty, and accordingly, we reversed the liability for the
guaranty. For further information on this guaranty, see Note 11 to the consolidated financial
statements.
Critical Accounting 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 at 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. Management has discussed
these critical accounting estimates presented below with the Audit Committee of the Board of
Directors.
Regulatory Accounting
. Our regulated utility segment is subject to regulation by certain
state and federal authorities. Our accounting policies conform to the accounting regulations
required by rate regulated operations and are in accordance with accounting requirements and
ratemaking practices prescribed by the regulatory authorities. The application of these accounting
policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and
liabilities when those expenses and revenues will be allowed in the ratemaking process in a period
different from the period in which they would have been reflected in the income statement by an
unregulated company. We then recognize these deferred regulatory assets and liabilities through
the income
43
statement in the period in which the same amounts are reflected in rates. If we, for
any reason, cease to meet the criteria for application of regulatory accounting treatment for all
or part of our operations, we would eliminate from the balance sheet the regulatory assets and
liabilities related to those portions ceasing to meet such criteria and include them in the income
statement for the period in which the discontinuance of regulatory accounting treatment occurs.
Such an event could have a material effect on our results of operations in the period this action
was recorded. Regulatory assets as of October 31, 2010 and 2009 totaled $197.8 million and $337.5
million, respectively. Regulatory liabilities as of October 31, 2010 and 2009 totaled $439.1
million and $409.3 million, respectively. The detail of these regulatory assets and liabilities is
presented in Note 1.B. to the consolidated financial statements.
Revenue Recognition
. Utility sales and transportation revenues are based on rates approved
by state regulatory commissions. Base rates charged to customers may not be changed without formal
approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas
component of rates may be adjusted periodically under PGA procedures. In South Carolina and
Tennessee, we have WNA mechanisms that are designed to protect a portion of our revenues against
warmer-than-normal weather as deviations from normal weather can affect our financial performance
and liquidity. The WNA also serves to offset the impact of colder-than-normal weather by reducing
the amounts we can charge our customers. In North Carolina, a margin
decoupling mechanism provides for the recovery of our approved margin from residential and
commercial customers independent of consumption patterns. The margin earned monthly under the
margin decoupling mechanism results in semi-annual rate adjustments to refund any over-collection
or recover any under-collection. The gas cost portion of our costs is recoverable through PGA
procedures and is not affected by the WNA or the margin decoupling mechanism. Without the WNA or
margin decoupling mechanism, our operating revenues would have been higher by $14.7 million in 2010
and lower by $4.8 million and $32.2 million in 2009 and 2008, respectively.
Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas
delivered to customers but not yet billed under the cycle-billing method from the last meter
reading date to month end. Meters are read throughout the month based on an approximate 30-day
usage cycle; therefore, at any point in time, volumes are delivered to customers that have not been
metered and billed. The unbilled revenue estimate reflects factors requiring judgment related to
estimated usage by customer class, changes in weather during the period and the impact of the WNA
or margin decoupling mechanism, as applicable. Secondary market revenues are recognized when the
physical sales are delivered based on contract or market prices.
Pension and Postretirement Benefits
. For eligible employees hired on or before December
31, 2007 (December 31, 2008 for employees covered under the bargaining unit contract in Nashville,
Tennessee), we have a traditional defined benefit pension plan, which was amended to close the plan
to employees hired after December 31, 2007 (December 31, 2008 for employees covered under the
bargaining unit contract in Nashville, Tennessee) and to modify how benefits are accrued. We also
provide certain postretirement health care and life insurance benefits to eligible employees. For
further information and our reported costs of providing these benefits, see Note 8 to the
consolidated financial statements. The costs of providing these benefits are impacted by numerous
factors, including the provisions of the plans, changing employee demographics and various
actuarial calculations, assumptions and accounting mechanisms. Because of the
44
complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions used,
our estimate of these costs is a critical accounting estimate.
Several statistical and other factors, which attempt to anticipate future events, are used in
calculating the expenses and liabilities related to the plans. These factors include assumptions
about the discount rate used in determining future benefit obligations, projected health care cost
trend rates, expected long-term return on plan assets and rate of future compensation increases,
within certain guidelines. In addition, we also use subjective factors such as withdrawal and
mortality rates to estimate projected benefit obligations. The actuarial assumptions used may
differ materially from actual results due to changing market and economic conditions, higher or
lower withdrawal rates or longer or shorter life spans of participants. These differences may
result in a significant impact on the amount of pension expense or other postretirement benefit
costs recorded in future periods.
The discount rate has been separately determined for each plan by projecting the plan’s cash
flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and Moody’s AA
or better-rated non-callable bonds. Based on this approach, the weighted average discount rate
used in the measurement of the benefit obligation for the qualified pension plan changed from 5.99%
in 2009 to 5.47% in 2010. For the nonqualified pension plans, the weighted average discount rate
used in the measurement of the benefit obligation changed from 5.28% in
2009 to 4.37% in 2010. Similarly, based on this approach, the weighted average discount rate
for postretirement benefits changed from 5.58% in 2009 to 4.85% in 2010. Based on our review of
actual cost trend rates and projected future trends in establishing health care cost trend rates,
the initial health care cost trend rate as established in 2009 was assumed to be 8% in 2010,
declining gradually to 5% in 2027.
In determining our expected long-term rate of return on plan assets, we review past long-term
performance, asset allocations and long-term inflation assumptions. We target our asset
allocations for qualified pension plan assets and other postretirement benefit assets to be
approximately 50% equity securities and 50% fixed income securities. The expected long-term rate
of return on plan assets was 8% in 2008, 2009 and 2010. Based on a fairly stagnant inflation
trend, our age-related assumed rate of increase in future compensation levels was 3.97% in 2008,
decreasing to 3.92% in 2009 and further decreasing to 3.87% in 2010 due to changes in the
demographics of the participants.
The following reflects the sensitivity of pension cost to changes in certain actuarial
assumptions for our qualified pension plan, assuming that the other components of the calculation
are constant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in
|
|
|
Impact on 2010
|
|
|
Impact on Projected
|
|
|
Actuarial Assumption
|
|
Assumption
|
|
|
Benefit Cost
|
|
|
Benefit Obligation
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
|
|
|
|
|
In thousands
|
|
|
Discount rate
|
|
|
(.25
|
)%
|
|
$
|
459
|
|
|
$
|
5,255
|
|
|
Rate of return on plan assets
|
|
|
(.25
|
)%
|
|
|
586
|
|
|
|
N/A
|
|
|
Rate of increase in compensation
|
|
|
.25
|
%
|
|
|
539
|
|
|
|
3,160
|
|
45
The following reflects the sensitivity of postretirement benefit cost to changes in
certain actuarial assumptions, assuming that the other components of the calculation are constant.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impact on 2010
|
|
|
Impact on Accumulated
|
|
|
|
|
Change in
|
|
|
Postretirement
|
|
|
Postretirement Benefit
|
|
|
Actuarial Assumption
|
|
Assumption
|
|
|
Benefit Cost
|
|
|
Obligation
|
|
|
|
|
|
|
|
|
Increase (Decrease)
|
|
|
|
|
|
|
|
|
In thousands
|
|
|
Discount rate
|
|
|
(.25
|
)%
|
|
$
|
9
|
|
|
$
|
767
|
|
|
Rate of return on plan assets
|
|
|
(.25
|
)%
|
|
|
46
|
|
|
|
N/A
|
|
|
Health care cost trend rate
|
|
|
.25
|
%
|
|
|
14
|
|
|
|
182
|
|
We utilize accounting methods consistently applied that are allowed under GAAP which
reduce the volatility of reported pension costs. Differences between actuarial assumptions and
actual plan results are deferred and amortized into cost when the accumulated differences exceed
10% of the greater of the projected benefit obligation or the market-related value of the plan
assets. If necessary, the excess is amortized over the average remaining service period of active
employees.
Gas Supply and Regulatory Proceedings
In recent years, we have sought to diversify our supply portfolio through pipeline capacity
arrangements that access new sources of supply and market-area storage and that diversify supply
concentration away from the Gulf Coast region. We have firm, long-term transportation contract
service that provides access to Canadian and Rocky Mountain gas supplies via the Chicago hub,
primarily to serve our Tennessee markets. We have firm, long-term market-area storage service in
West Virginia from Hardy Storage, a venture in which we have a 50% equity interest in the project
which is more fully discussed in Note 11 to the consolidated financial statements.
We are currently expanding our transmission system and compression facilities to provide
natural gas delivery service to Progress Energy Carolinas for two power generation facilities that
are under construction at their Wayne County, North Carolina site and at their existing Sutton site
near Wilmington, North Carolina. Our investment to service these new contracts will occur over the
next two and one-half years. For further information on these investments, see “Cash Flows from
Investing Activities” in Management’s Discussion and Analysis of this Form 10-K. Also, in relation
to the Wayne County agreement, we have executed an agreement with Cardinal to expand our firm
capacity requirement by 149,000 dekatherms per day to serve this facility. As a 21.49% equity
venture partner of Cardinal, we will invest as much as $11.4 million in Cardinal’s system
expansion. For further information on our equity venture, see Note 11 to the consolidated
financial statements.
The Sutton facilities will also create expansion capacity that we will use to help serve the
growing natural gas requirements of our customers in the eastern part of North Carolina. While not
satisfying any future market supply requirements, since the Sutton facilities will help serve our
near term system pressure requirements in a cost effective manner, we have delayed work on the
Robeson LNG peak storage facility. The timing and design scope of expansion of our facilities in
this area will be determined as our system infrastructure and market supply growth requirements in
North Carolina dictate.
46
Secondary market transactions permit us to market gas supplies and transportation services by
contract with wholesale or off-system customers. These sales contribute smaller per-unit margins
to earnings; however, the program allows us to act as a wholesale marketer of natural gas and
transportation capacity in order to generate operating margin from sources not restricted by the
capacity of our retail distribution system. A sharing mechanism is in effect where 75% of any
margin is passed through to customers in all of our jurisdictions. However, secondary market
transactions in Tennessee are included in the TIP discussed in Note 2 to the consolidated financial
statements.
In October 2008, the NCUC approved a settlement in our general rate case proceeding that
provided an annual revenue increase of $15.7 million and the continuation of the margin decoupling
mechanism. The new rates became effective November 1, 2008. Also in October 2008, the PSCSC
issued an order approving a settlement that provided for an annual decrease of $1.5 million in
margin under the rate stabilization adjustment mechanism based on a return on equity of 11.2%,
effective November 1, 2008. In October 2009, the PSCSC issued an order approving a settlement that
provides for an annual increase in margin of $1.1 million based on a return on equity of 11.2%,
effective November 1, 2009. In October 2010, the PSCSC issued an order approving a settlement that
provides an annual increase in margin of $.75 million based on a return on equity of 11.3%,
effective November 1, 2010.
In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy
efficiency programs to residential and commercial customers at a total cost of $.35 million that
were designed to promote energy conservation and efficiency. These programs were similar to
approved energy efficiency programs in North Carolina. On May 20, 2010, the PSCSC approved the
energy efficiency programs on a three-year experimental basis with equipment rebates on the
purchase of high-efficiency natural gas equipment and weatherization assistance for low-income
residential customers. For further information on these programs, see the discussion in Note 2 to
the consolidated financial statements.
In February 2010, we filed a petition with the TRA to adjust the applicable rate for the
collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was
calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as
of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee
rate designed to recover only the net under-collections that have accrued since June 1, 2005, which
would deny recovery of $1.5 million for us. Once the TRA issues its order on this matter, we
intend to seek their reconsideration. We are unable to predict the outcome of this proceeding at
this time. However, we do not believe this matter will have a material effect on our financial
position, results of operations or cash flows.
We continue to work with our regulatory commissions to earn a fair rate of return for our
shareholders and provide safe, reliable natural gas distribution service to our customers. For
further information about regulatory proceedings and other regulatory information, see Note 2 to
the consolidated financial statements.
47
Equity Method Investments
For information about our equity method investments, see Note 11 to the consolidated financial
statements.
Environmental Matters
We have developed an environmental self-assessment plan to assess our facilities and program
areas for compliance with federal, state and local environmental regulations and to correct any
deficiencies identified. As a member of the North Carolina MGP Initiative Group, we, along with
other responsible parties, work directly with the North Carolina Department of Environment and
Natural Resources to set priorities for manufactured gas plant (MGP) site remediation. For
additional information on environmental matters, see Note 7 to the consolidated financial
statements.
Accounting Guidance
For information regarding recently issued accounting guidance, see Note 1.Q. to the
consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to various forms of market risk, including the credit risk of our suppliers and
our customers, interest rate risk, commodity price risk and weather risk. We seek to identify,
assess, monitor and manage market risk and credit risk in accordance with defined policies and
procedures under an Enterprise Risk Management Policy and with the direction of the Energy Price
Risk Management Committee. Risk management is guided by senior management with Board of Directors’
oversight, and senior management takes an active role in the development of policies and
procedures.
We hold all financial instruments discussed below for purposes other than trading.
Credit Risk
We enter into contracts with third parties to buy and sell natural gas. Our policy requires
counterparties to have an investment-grade credit rating at the time of the contract. In
situations where our counterparties do not have investment grade credit ratings, our policy
requires credit enhancements that include letters of credit or parental guaranties. In either
circumstance, the policy specifies limits on the contract amount and duration based on the
counterparty’s credit rating and/or credit support. In order to minimize our exposure, we
continually re-evaluate third-party creditworthiness and market conditions and modify our
requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity
assets for the purpose of maximizing their value. These arrangements include a counterparty credit
evaluation according to our policy described above prior to contract execution and typically have
durations of one year or less. In the event that a party is unable to perform under these
48
arrangements, we have exposure to satisfy our underlying supply or demand contractual obligations
that were incurred while under the management of this third party.
We have mitigated exposure to the risk of nonpayment of utility bills by customers. In
North Carolina and South Carolina, gas costs related to uncollectible accounts are recovered
through PGA procedures. In Tennessee, the gas cost portion of net write-offs for a fiscal year
that exceed the gas cost portion included in base rates is recovered through PGA procedures. To
manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and
may require cash deposits from those customers that do not satisfy our predetermined credit
standards. Significant increases in the price of natural gas can also slow our collection
efforts as customers experience increased difficulty in paying their gas bills, leading to higher
than normal accounts receivable.
Interest Rate Risk
We are exposed to interest rate risk as a result of changes in interest rates on short-term
debt. As of October 31, 2010, all of our long-term debt was issued at fixed rates, and therefore
not subject to interest rate risk.
We have short-term borrowing arrangements to provide working capital and general corporate
liquidity. The level of borrowings under such arrangements varies from period to period depending
upon many factors, including the cost of wholesale natural gas and our gas supply hedging programs,
our investments in capital projects, the level and expense of our storage
inventory and the collection of receivables. Future short-term interest expense and payments
will be impacted by both short-term interest rates and borrowing levels.
As of October 31, 2010, we had $242 million of short-term debt outstanding under our
syndicated revolving credit facility at an interest rate of .51%. The carrying amount of our
short-term debt approximates fair value. A change of 100 basis points in the underlying average
interest rate for our short-term debt would have caused a change in interest expense of
approximately $1.6 million during 2010.
As of October 31, 2010, information about our long-term debt is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected Maturity Date
|
|
|
Fair Value as
of October 31,
|
|
|
In millions
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2015
|
|
|
Thereafter
|
|
|
Total
|
|
|
2010
|
|
|
Fixed Rate Long-term
Debt
|
|
$
|
60
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
100
|
|
|
$
|
—
|
|
|
$
|
571.9
|
|
|
$
|
731.9
|
|
|
$
|
890.3
|
|
|
Average Interest Rate
|
|
|
6.55
|
%
|
|
|
—
|
%
|
|
|
—
|
%
|
|
|
5.00
|
%
|
|
|
—
|
%
|
|
|
6.93
|
%
|
|
|
6.64
|
%
|
|
|
|
|
Commodity Price Risk
We have mitigated the cash flow risk resulting from commodity purchase contracts under our
regulatory gas cost recovery mechanisms that permit the recovery of these costs in a timely manner.
As such, we face regulatory recovery risk associated with these costs. With regulatory commission
approval, we revise rates periodically without formal rate proceedings to reflect changes in the
wholesale cost of gas, including costs associated with our hedging programs under the recovery
mechanism allowed by each of our state regulators. Under our PGA procedures,
49
differences between gas costs incurred and gas costs billed to customers are deferred, and any under-recoveries are
included in “Amounts due from customers” or any over-recoveries are included in “Amounts due to
customers” in our consolidated balance sheets for collection or refund over subsequent periods.
When we have “Amounts due from customers,” we earn a carrying charge that mitigates any incremental
short-term borrowing costs. When we have “Amounts due to customers,” we incur a carrying charge
that we must refund to our customers.
We manage our gas supply costs through a portfolio of short- and long-term procurement and
storage contracts with various suppliers. We actively manage our supply portfolio to balance sales
and delivery obligations. We inject natural gas into storage during the summer months and withdraw
the gas during the winter heating season. In the normal course of business, we utilize New York
Mercantile Exchange (NYMEX) exchange traded instruments and have used OTC instruments of various
durations for the forward purchase of a portion of our natural gas requirements, subject to
regulatory review and approval.
Our gas purchasing practices and costs are subject to regulatory reviews in all three states
in which we operate. Costs have never been disallowed on the basis of prudence in any
jurisdiction.
Weather Risk
We are exposed to weather risk in our regulated utility segment in South Carolina and
Tennessee where revenues are collected from volumetric rates without a margin decoupling
mechanism. Our rates are designed based on an assumption of normal weather. In these states,
this risk is mitigated by WNA mechanisms that are designed to offset the impact of
colder-than-normal or warmer-than-normal weather in our residential and commercial markets. In
North Carolina, we manage our weather risk through a margin decoupling mechanism that allows us to
recover our approved margin from residential and commercial customers independent of volumes sold.
Additional information concerning market risk is set forth in “Financial Condition and
Liquidity” in Item 7 of this Form 10-K in Management’s Discussion and Analysis of Financial
Condition and Results of Operations.
Item 8. Financial Statements and Supplementary Data
Consolidated financial statements required by this item are listed in Item 15 (a) 1 in Part IV
of this Form 10-K.
50
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.
Charlotte, North Carolina
We have audited the accompanying consolidated balance sheets of Piedmont Natural Gas Company, Inc.
and subsidiaries (the “Company”) as of October 31, 2010 and 2009, and the related consolidated
statements of income, stockholders’ equity, and cash flows for each of the three years in the
period ended October 31, 2010. These financial statements are the responsibility of the Company’s
management. Our responsibility is to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Piedmont Natural Gas Company, Inc. and subsidiaries at October 31, 2010
and 2009, and the results of their operations and their cash flows for each of the three years in
the period ended October 31, 2010, in conformity with accounting principles generally accepted in
the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the Company’s internal control over financial reporting as of October 31,
2010, based on the criteria established in
Internal Control—Integrated Framework
issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 23,
2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2010
51
Consolidated Balance Sheets
October 31, 2010 and 2009
ASSETS
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Utility Plant:
|
|
|
|
|
|
|
|
|
|
Utility plant in service
|
|
$
|
3,176,312
|
|
|
$
|
3,071,742
|
|
|
Less accumulated depreciation
|
|
|
917,300
|
|
|
|
862,079
|
|
|
|
|
|
|
|
|
|
|
Utility plant in service, net
|
|
|
2,259,012
|
|
|
|
2,209,663
|
|
|
Construction work in progress
|
|
|
171,901
|
|
|
|
87,978
|
|
|
Plant held for future use
|
|
|
6,751
|
|
|
|
6,751
|
|
|
|
|
|
|
|
|
|
|
Total utility plant, net
|
|
|
2,437,664
|
|
|
|
2,304,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Physical Property, at cost (net of accumulated
depreciation of $729 in 2010 and $2,497 in 2009)
|
|
|
528
|
|
|
|
719
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets:
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
5,619
|
|
|
|
7,558
|
|
|
Trade accounts receivable (less allowance for doubtful
accounts of $929 in 2010 and $990 in 2009)
|
|
|
62,370
|
|
|
|
70,979
|
|
|
Income taxes receivable
|
|
|
24,856
|
|
|
|
44,413
|
|
|
Other receivables
|
|
|
2,289
|
|
|
|
4,712
|
|
|
Unbilled utility revenues
|
|
|
21,337
|
|
|
|
33,925
|
|
|
Inventories:
|
|
|
|
|
|
|
|
|
|
Gas in storage
|
|
|
101,734
|
|
|
|
103,584
|
|
|
Materials, supplies and merchandise
|
|
|
4,547
|
|
|
|
5,262
|
|
|
Gas purchase derivative assets, at fair value
|
|
|
2,819
|
|
|
|
2,559
|
|
|
Amounts due from customers
|
|
|
62,336
|
|
|
|
196,130
|
|
|
Prepayments
|
|
|
39,832
|
|
|
|
43,930
|
|
|
Other current assets
|
|
|
101
|
|
|
|
96
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
327,840
|
|
|
|
513,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Assets:
|
|
|
|
|
|
|
|
|
|
Equity method investments in non-utility activities
|
|
|
80,287
|
|
|
|
104,430
|
|
|
Goodwill
|
|
|
48,852
|
|
|
|
48,852
|
|
|
Marketable securities, at fair value
|
|
|
997
|
|
|
|
441
|
|
|
Overfunded postretirement asset
|
|
|
17,342
|
|
|
|
—
|
|
|
Regulatory asset for postretirement benefits
|
|
|
64,775
|
|
|
|
76,905
|
|
|
Unamortized debt expense
|
|
|
8,576
|
|
|
|
9,177
|
|
|
Regulatory cost of removal asset
|
|
|
17,825
|
|
|
|
16,293
|
|
|
Other noncurrent assets
|
|
|
48,589
|
|
|
|
44,462
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent assets
|
|
|
287,243
|
|
|
|
300,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,053,275
|
|
|
$
|
3,118,819
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
52
Consolidated Balance Sheets
October 31, 2010 and 2009
CAPITALIZATION AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Stockholders’ equity:
|
|
|
|
|
|
|
|
|
|
Cumulative preferred stock — no par value - 175 shares authorized
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Common stock — no par value — shares authorized: 200,000;
shares outstanding: 72,282 in 2010 and 73,266 in 2009
|
|
|
445,640
|
|
|
|
471,569
|
|
|
Retained earnings
|
|
|
519,831
|
|
|
|
458,826
|
|
|
Accumulated other comprehensive loss
|
|
|
(530
|
)
|
|
|
(2,447
|
)
|
|
|
|
|
|
|
|
|
|
Total stockholders’ equity
|
|
|
964,941
|
|
|
|
927,948
|
|
|
Long-term debt
|
|
|
671,922
|
|
|
|
732,512
|
|
|
|
|
|
|
|
|
|
|
Total capitalization
|
|
|
1,636,863
|
|
|
|
1,660,460
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities:
|
|
|
|
|
|
|
|
|
|
Current maturities of long-term debt
|
|
|
60,000
|
|
|
|
60,000
|
|
|
Bank debt
|
|
|
242,000
|
|
|
|
306,000
|
|
|
Trade accounts payable
|
|
|
66,019
|
|
|
|
67,010
|
|
|
Other accounts payable
|
|
|
49,645
|
|
|
|
48,431
|
|
|
Accrued interest
|
|
|
20,134
|
|
|
|
21,294
|
|
|
Customers’ deposits
|
|
|
25,631
|
|
|
|
25,202
|
|
|
Deferred income taxes
|
|
|
4,933
|
|
|
|
14,138
|
|
|
General taxes accrued
|
|
|
20,100
|
|
|
|
19,993
|
|
|
Gas purchase derivative liabilities, at fair value
|
|
|
—
|
|
|
|
30,603
|
|
|
Other current liabilities
|
|
|
10,098
|
|
|
|
7,540
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
498,560
|
|
|
|
600,211
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent Liabilities:
|
|
|
|
|
|
|
|
|
|
Deferred income taxes
|
|
|
429,225
|
|
|
|
377,562
|
|
|
Unamortized federal investment tax credits
|
|
|
2,145
|
|
|
|
2,422
|
|
|
Accumulated provision for postretirement benefits
|
|
|
14,805
|
|
|
|
31,641
|
|
|
Cost of removal obligations
|
|
|
436,072
|
|
|
|
408,955
|
|
|
Other noncurrent liabilities
|
|
|
35,605
|
|
|
|
37,568
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent liabilities
|
|
|
917,852
|
|
|
|
858,148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,053,275
|
|
|
$
|
3,118,819
|
|
|
|
|
|
|
|
|
|
See notes to consolidated financial statements.
53
Page Intentionally Blank
54
Consolidated Statements of Income
For the Years Ended October 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands except per share amounts
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Operating Revenues
|
|
$
|
1,552,295
|
|
|
$
|
1,638,116
|
|
|
$
|
2,089,108
|
|
|
Cost of Gas
|
|
|
999,703
|
|
|
|
1,076,542
|
|
|
|
1,536,135
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Margin
|
|
|
552,592
|
|
|
|
561,574
|
|
|
|
552,973
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
219,829
|
|
|
|
208,105
|
|
|
|
210,757
|
|
|
Depreciation
|
|
|
98,494
|
|
|
|
97,425
|
|
|
|
93,121
|
|
|
General taxes
|
|
|
33,909
|
|
|
|
34,590
|
|
|
|
33,170
|
|
|
Income taxes
|
|
|
62,082
|
|
|
|
70,079
|
|
|
|
62,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses
|
|
|
414,314
|
|
|
|
410,199
|
|
|
|
399,862
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
138,278
|
|
|
|
151,375
|
|
|
|
153,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from equity method investments
|
|
|
28,854
|
|
|
|
33,464
|
|
|
|
27,718
|
|
|
Gain on sale of interest in equity method investment
|
|
|
49,674
|
|
|
|
—
|
|
|
|
—
|
|
|
Non-operating income
|
|
|
659
|
|
|
|
32
|
|
|
|
1,320
|
|
|
Charitable contributions
|
|
|
(1,363
|
)
|
|
|
(2,011
|
)
|
|
|
(1,327
|
)
|
|
Non-operating expense
|
|
|
(643
|
)
|
|
|
(1,558
|
)
|
|
|
(864
|
)
|
|
Income taxes
|
|
|
(29,794
|
)
|
|
|
(11,803
|
)
|
|
|
(10,678
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense)
|
|
|
47,387
|
|
|
|
18,124
|
|
|
|
16,169
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Interest Charges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest on long-term debt
|
|
|
52,666
|
|
|
|
55,105
|
|
|
|
55,449
|
|
|
Allowance for borrowed funds used during construction
|
|
|
(9,981
|
)
|
|
|
(2,298
|
)
|
|
|
(4,002
|
)
|
|
Other
|
|
|
1,026
|
|
|
|
(6,132
|
)
|
|
|
7,826
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total utility interest charges
|
|
|
43,711
|
|
|
|
46,675
|
|
|
|
59,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Shares of Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
72,275
|
|
|
|
73,171
|
|
|
|
73,334
|
|
|
Diluted
|
|
|
72,525
|
|
|
|
73,461
|
|
|
|
73,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share of Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.96
|
|
|
$
|
1.68
|
|
|
$
|
1.50
|
|
|
Diluted
|
|
$
|
1.96
|
|
|
$
|
1.67
|
|
|
$
|
1.49
|
|
See notes to consolidated financial statements.
55
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Cash Flows from Operating Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
Adjustments to reconcile net income to net
cash provided by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
102,776
|
|
|
|
102,592
|
|
|
|
97,637
|
|
|
Amortization of investment tax credits
|
|
|
(277
|
)
|
|
|
(204
|
)
|
|
|
(358
|
)
|
|
Allowance for doubtful accounts
|
|
|
(61
|
)
|
|
|
(76
|
)
|
|
|
522
|
|
|
Gain on sale of interest in equity method investment,
net of tax
|
|
|
(30,286
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Net gain on sale of property
|
|
|
(89
|
)
|
|
|
(495
|
)
|
|
|
(711
|
)
|
|
Income from equity method investments
|
|
|
(28,854
|
)
|
|
|
(33,464
|
)
|
|
|
(27,718
|
)
|
|
Distributions of earnings from equity method
investments
|
|
|
28,834
|
|
|
|
23,954
|
|
|
|
34,060
|
|
|
Deferred income taxes
|
|
|
21,831
|
|
|
|
81,468
|
|
|
|
28,370
|
|
|
Stock-based compensation expense
|
|
|
—
|
|
|
|
—
|
|
|
|
338
|
|
|
Changes in assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas purchase
derivatives, at fair value
|
|
|
(30,863
|
)
|
|
|
18,741
|
|
|
|
23,029
|
|
|
Receivables
|
|
|
23,493
|
|
|
|
25,018
|
|
|
|
(12,685
|
)
|
|
Inventories
|
|
|
2,565
|
|
|
|
87,953
|
|
|
|
(60,139
|
)
|
|
Amounts due from customers
|
|
|
133,794
|
|
|
|
(14,385
|
)
|
|
|
(105,710
|
)
|
|
Settlement of legal asset retirement obligations
|
|
|
(1,141
|
)
|
|
|
(1,480
|
)
|
|
|
(1,358
|
)
|
|
Overfunded postretirement asset
|
|
|
(17,342
|
)
|
|
|
6,797
|
|
|
|
29,459
|
|
|
Regulatory asset for postretirement benefits
|
|
|
12,130
|
|
|
|
(48,173
|
)
|
|
|
(26,867
|
)
|
|
Other assets
|
|
|
18,184
|
|
|
|
(13,573
|
)
|
|
|
(8,936
|
)
|
|
Accounts payable
|
|
|
(3,007
|
)
|
|
|
(22,154
|
)
|
|
|
(8,617
|
)
|
|
Amounts due to customers
|
|
|
—
|
|
|
|
—
|
|
|
|
(162
|
)
|
|
Regulatory liability for postretirement benefits
|
|
|
—
|
|
|
|
(372
|
)
|
|
|
(13,504
|
)
|
|
Provision for postretirement benefits
|
|
|
(16,836
|
)
|
|
|
15,384
|
|
|
|
(1,212
|
)
|
|
Other liabilities
|
|
|
3,706
|
|
|
|
(6,085
|
)
|
|
|
13,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
360,511
|
|
|
|
344,270
|
|
|
|
69,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility construction expenditures
|
|
|
(199,059
|
)
|
|
|
(129,006
|
)
|
|
|
(181,001
|
)
|
|
Allowance for funds used during construction
|
|
|
(9,981
|
)
|
|
|
(2,298
|
)
|
|
|
(4,002
|
)
|
|
Contributions to equity method investments
|
|
|
—
|
|
|
|
(862
|
)
|
|
|
(10,917
|
)
|
|
Distributions of capital from equity method investments
|
|
|
18,260
|
|
|
|
32
|
|
|
|
98
|
|
|
Proceeds from sale of interest in equity method
investment
|
|
|
57,500
|
|
|
|
—
|
|
|
|
—
|
|
|
Proceeds from sale of property
|
|
|
1,653
|
|
|
|
748
|
|
|
|
13,159
|
|
|
Decrease in restricted cash
|
|
|
—
|
|
|
|
—
|
|
|
|
2,196
|
|
|
Investments in marketable securities
|
|
|
(498
|
)
|
|
|
(380
|
)
|
|
|
—
|
|
|
Other
|
|
|
3,554
|
|
|
|
2,154
|
|
|
|
3,090
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(128,571
|
)
|
|
|
(129,612
|
)
|
|
|
(177,377
|
)
|
|
|
|
|
|
|
|
|
|
|
|
56
Consolidated Statements of Cash Flows
For the Years Ended October 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Cash Flows from Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings under bank debt
|
|
|
1,058,000
|
|
|
|
1,075,000
|
|
|
|
1,687,000
|
|
|
Repayments under bank debt
|
|
|
(1,122,000
|
)
|
|
|
(1,175,500
|
)
|
|
|
(1,476,000
|
)
|
|
Retirement of long-term debt
|
|
|
(60,590
|
)
|
|
|
(31,749
|
)
|
|
|
(626
|
)
|
|
Expenses related to the issuance of long-term debt
|
|
|
—
|
|
|
|
—
|
|
|
|
(10
|
)
|
|
Expenses related to expansion of the credit facility
|
|
|
(46
|
)
|
|
|
—
|
|
|
|
(113
|
)
|
|
Issuance of common stock through dividend
reinvestment
and employee stock plans
|
|
|
19,099
|
|
|
|
14,435
|
|
|
|
15,591
|
|
|
Repurchases of common stock
|
|
|
(47,295
|
)
|
|
|
(17,857
|
)
|
|
|
(42,678
|
)
|
|
Dividends paid
|
|
|
(80,255
|
)
|
|
|
(78,370
|
)
|
|
|
(75,513
|
)
|
|
Other
|
|
|
(792
|
)
|
|
|
(50
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
(233,879
|
)
|
|
|
(214,091
|
)
|
|
|
107,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease) in Cash and Cash Equivalents
|
|
|
(1,939
|
)
|
|
|
567
|
|
|
|
(524
|
)
|
|
Cash and Cash Equivalents at Beginning of Year
|
|
|
7,558
|
|
|
|
6,991
|
|
|
|
7,515
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Year
|
|
$
|
5,619
|
|
|
$
|
7,558
|
|
|
$
|
6,991
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Paid During the Year for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
56,554
|
|
|
$
|
61,050
|
|
|
$
|
63,769
|
|
|
Income taxes
|
|
|
30,460
|
|
|
|
50,787
|
|
|
|
29,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash Investing and Financing Activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued construction expenditures
|
|
$
|
3,225
|
|
|
$
|
1,305
|
|
|
$
|
1,340
|
|
|
Guaranty
|
|
|
1,234
|
|
|
|
—
|
|
|
|
101
|
|
See notes to consolidated financial statements.
57
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
Common
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
|
|
|
In thousands except per share amounts
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
Balance, October 31, 2007
|
|
$
|
497,570
|
|
|
$
|
402
|
|
|
$
|
379,682
|
|
|
$
|
720
|
|
|
$
|
878,374
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
110,007
|
|
|
|
|
|
|
|
110,007
|
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain from hedging activities of
equity
method investments, net of tax of $891
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,399
|
|
|
|
1,399
|
|
|
Reclassification adjustment of realized gain
from
hedging activities of equity method
investments
included in net income, net of tax of ($922)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,449
|
)
|
|
|
(1,449
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109,957
|
|
|
Common Stock Issued
|
|
|
16,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,673
|
|
|
Common Stock Repurchased
|
|
|
(42,678
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42,678
|
)
|
|
Share-Based Compensation Expense
|
|
|
|
|
|
|
338
|
|
|
|
|
|
|
|
|
|
|
|
338
|
|
|
Dividends — Incentive Compensation Plan
|
|
|
|
|
|
|
23
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
—
|
|
|
Tax Benefit from Dividends Paid on ESOP Shares
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
93
|
|
|
Dividends Declared ($1.03 per share)
|
|
|
|
|
|
|
|
|
|
|
(75,513
|
)
|
|
|
|
|
|
|
(75,513
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2008
|
|
|
471,565
|
|
|
|
763
|
|
|
|
414,246
|
|
|
|
670
|
|
|
|
887,244
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
122,824
|
|
|
|
|
|
|
|
122,824
|
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain from hedging activities of
equity
method investments, net of tax of ($3,886)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,032
|
)
|
|
|
(6,032
|
)
|
|
Reclassification adjustment of realized gain
from
hedging activities of equity method
investments
included in net income, net of tax of $1,879
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,915
|
|
|
|
2,915
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
119,707
|
|
|
Common Stock Issued
|
|
|
17,861
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,861
|
|
|
Common Stock Repurchased
|
|
|
(17,857
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17,857
|
)
|
|
Share-Based Compensation Expense
|
|
|
|
|
|
|
(730
|
)
|
|
|
|
|
|
|
|
|
|
|
(730
|
)
|
|
Dividends — Incentive Compensation Plan
|
|
|
|
|
|
|
(33
|
)
|
|
|
33
|
|
|
|
|
|
|
|
—
|
|
|
Tax Benefit from Dividends Paid on ESOP Shares
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
93
|
|
|
Dividends Declared ($1.07 per share)
|
|
|
|
|
|
|
|
|
|
|
(78,370
|
)
|
|
|
|
|
|
|
(78,370
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2009
|
|
|
471,569
|
|
|
|
—
|
|
|
|
458,826
|
|
|
|
(2,447
|
)
|
|
|
927,948
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
Consolidated Statements of Stockholders’ Equity
For the Years Ended October 31, 2010, 2009 and 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
Common
|
|
|
Paid-in
|
|
|
Retained
|
|
|
Comprehensive
|
|
|
|
|
|
In thousands except per share amounts
|
|
Stock
|
|
|
Capital
|
|
|
Earnings
|
|
|
Income (Loss)
|
|
|
Total
|
|
|
Comprehensive Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
141,954
|
|
|
|
|
|
|
|
141,954
|
|
|
Other comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain from hedging activities of
equity
method investments, net of tax of ($52)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(88
|
)
|
|
|
(88
|
)
|
|
Reclassification adjustment of realized gain
from
hedging activities of equity method
investments
included in net income, net of tax of $1,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,005
|
|
|
|
2,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
143,871
|
|
|
Common Stock Issued
|
|
|
21,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,366
|
|
|
Common Stock Repurchased
|
|
|
(47,276
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(47,276
|
)
|
|
Rescission Offer
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19
|
)
|
|
Costs of Rescission Offer
|
|
|
|
|
|
|
|
|
|
|
(792
|
)
|
|
|
|
|
|
|
(792
|
)
|
|
Tax Benefit from Dividends Paid on ESOP Shares
|
|
|
|
|
|
|
|
|
|
|
98
|
|
|
|
|
|
|
|
98
|
|
|
Dividends Declared ($1.11 per share)
|
|
|
|
|
|
|
|
|
|
|
(80,255
|
)
|
|
|
|
|
|
|
(80,255
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2010
|
|
$
|
445,640
|
|
|
$
|
—
|
|
|
$
|
519,831
|
|
|
$
|
(530
|
)
|
|
$
|
964,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The components of accumulated other comprehensive income (loss) (OCI) as of October 31, 2010 and 2009 are as follows.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Hedging activities of equity method investments, net of tax
|
|
$
|
(530
|
)
|
|
$
|
(2,447
|
)
|
See notes to consolidated financial statements.
59
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. Operations and Principles of Consolidation.
Piedmont is an energy services company primarily engaged in the distribution of natural gas to
residential, commercial, industrial and power generation customers in portions of North Carolina,
South Carolina and Tennessee. We are invested in joint venture, energy-related businesses,
including unregulated retail natural gas marketing, interstate natural gas storage and intrastate
natural gas transportation. Our utility operations are regulated by three state regulatory
commissions. For further information on regulatory matters, see Note 2 to the consolidated
financial statements.
The consolidated financial statements reflect the accounts of Piedmont and its wholly owned
subsidiaries. Investments in non-utility activities are accounted for under the equity method as
we do not have controlling voting interests or otherwise exercise control over the management of
such companies. Our ownership interest in each entity is recorded in “Equity method investments in
non-utility activities” in the consolidated balance sheets. Earnings or losses from equity method
investments are recorded in “Income from equity method investments” in the consolidated statements
of income. For further information on equity method investments, see Note 11 to the consolidated
financial statements. Revenues and expenses of all other non-utility activities are included in
“Non-operating income” in the consolidated statements of income. Inter-company transactions have
been eliminated in consolidation where appropriate; however, we have not eliminated inter-company
profit on sales to affiliates and costs from affiliates in accordance with accounting regulations
prescribed under rate-based regulation.
We monitor significant events occurring after the balance sheet date and prior to the issuance
of the financial statements to determine the impacts, if any, of events on the financial statements
to be issued. All subsequent events of which we are aware were evaluated through the filing date
of this Form 10-K. There are no subsequent events that had a material impact on our financial
position, results of operations or cash flows. For further information, see Note 13 to the
consolidated financial statements.
B. Rate-Regulated Basis of Accounting.
Our utility operations are subject to regulation with respect to rates, service area,
accounting and various other matters by the regulatory commissions in the states in which we
operate. The accounting regulations provide that rate-regulated public utilities account for and
report assets and liabilities consistent with the economic effect of the manner in which
independent third-party regulators establish rates. In applying these regulations, we capitalize
certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide
for recovery from or refund to utility customers in future periods.
Our regulatory assets are recoverable through either rate riders or base rates specifically
authorized by a state regulatory commission. Base rates are designed to provide both a recovery of
cost and a return on investment during the period the rates are in effect. As such, all of our
regulatory assets are subject to review by the respective state regulatory commission during any
60
future rate proceedings. In the event that accounting for the effects of regulation were no
longer applicable, we would recognize a write-off of the regulatory assets and regulatory
liabilities that would result in an adjustment to net income. Our utility operations continue to
recover their costs through cost-based rates established by the state regulatory commissions. As a
result, we believe that the accounting prescribed under rate-based regulation remains appropriate.
It is our opinion that all of our recorded regulatory assets are recoverable in current rates or
future rate proceedings.
Regulatory assets and liabilities in the consolidated balance sheets as of October 31, 2010
and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
|
Unamortized debt expense
|
|
$
|
8,576
|
|
|
$
|
9,177
|
|
|
Amounts due from customers
|
|
|
62,336
|
|
|
|
196,130
|
|
|
Environmental costs *
|
|
|
7,960
|
|
|
|
6,205
|
|
|
Demand-side management costs *
|
|
|
—
|
|
|
|
474
|
|
|
Deferred operations and maintenance expenses *
|
|
|
8,258
|
|
|
|
8,816
|
|
|
Deferred pipeline integrity expenses *
|
|
|
6,728
|
|
|
|
6,467
|
|
|
Deferred pension and other retirement benefits
costs *
|
|
|
18,783
|
|
|
|
15,535
|
|
|
Amounts not yet recognized as a component of
pension
and other retirement benefits costs
|
|
|
64,775
|
|
|
|
76,905
|
|
|
Regulatory cost of removal asset
|
|
|
17,825
|
|
|
|
16,293
|
|
|
Other *
|
|
|
2,531
|
|
|
|
1,541
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
197,772
|
|
|
$
|
337,543
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
|
Regulatory cost of removal obligations
|
|
$
|
412,776
|
|
|
$
|
385,624
|
|
|
Deferred income taxes *
|
|
|
26,299
|
|
|
|
23,699
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
439,075
|
|
|
$
|
409,323
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Regulatory assets are included in “Other” in “Noncurrent Assets” and regulatory liabilities are
included in “Other” in “Noncurrent Liabilities” in the consolidated balance sheets.
|
As of October 31, 2010, we had regulatory assets totaling $2.4 million on which we do not
earn a return during the applicable recovery periods. The original amortization periods for these
assets range from 3 to 15 years and, accordingly, $1.8 million will be fully amortized by 2011 and
$.6 million will be fully amortized by 2018. We have $6.2 million related to unrealized
mark-to-market amounts on which we do not earn a return until they are recorded in interest-bearing
amounts due to/from customer accounts when realized and $64.8 million of regulatory postretirement
assets, $17.8 million of asset retirement obligations (AROs) and $8 million of estimated
environmental costs on which we do not earn a return.
C. Utility Plant and Depreciation.
Utility plant is stated at original cost, including direct labor and materials, allocable
overhead charges and allowance for funds used during construction (AFUDC). Major expenditures that
last longer than a year and improve or lengthen the expected useful life of the overall property
from original expectations that are recoverable in regulatory rate base are capitalized while
expenditures not meeting these criteria are expensed as incurred. The portion of
61
AFUDC attributable to borrowed funds is shown as a reduction of “Utility Interest Charges” in
the consolidated statements of income. Any portion of AFUDC attributable to equity funds would be
included in “Other Income (Expense)” in the consolidated statements of income. The costs of
property retired are removed from utility plant and charged to accumulated depreciation. AFUDC for
the years ended October 31, 2010, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
AFUDC
|
|
$
|
9,981
|
|
|
$
|
2,298
|
|
|
$
|
4,002
|
|
At this time, we have delayed proceeding with work on the Robeson County liquefied natural gas
(LNG) peak storage facility given the slowing of our market growth due to current economic
conditions. As conditions improve and additional supply is required for this growth, we will
evaluate the timing for this project. Also, while not satisfying any future market supply
requirements, the Sutton facilities will help serve our near term system pressure requirements in a
cost effective manner in the eastern part of North Carolina. The timing and design scope of the
expansion of our facilities in this area will be determined as our system infrastructure and market
supply growth requirements in North Carolina dictate. In accordance with utility accounting
practice, we have classified expenditures associated with the LNG facility as “Plant held for
future use” in the consolidated balance sheets.
We compute depreciation expense using the straight-line method over periods ranging from four
to 88 years. The composite weighted-average depreciation rates were 3.20% for 2010, 3.25% for 2009
and 3.23% for 2008.
Depreciation rates for utility plant are approved by our regulatory commissions. In North
Carolina, we are required to conduct a depreciation study every five years and propose new
depreciation rates for approval. Our last depreciation study was completed using fiscal year 2004
data, and new depreciation rates were approved effective November 1, 2005. We are currently
engaged in a depreciation study using fiscal year 2009 data. Completion of the study is expected
in early 2011, at which time the results will be filed with the appropriate regulatory authorities.
No such five-year requirement exists in South Carolina or Tennessee; however, we periodically
propose revised rates in those states based on depreciation studies. We collect through rates the
estimated costs of removal on certain regulated properties through depreciation expense, with a
corresponding credit to accumulated depreciation. Our approved depreciation rates are comprised of
two components, one based on average service life and one based on cost of removal for certain
regulated properties. Therefore, through depreciation expense, we accrue estimated non-legal costs
of removal on any depreciable asset that includes cost of removal in its depreciation rate.
D. Asset Retirement Obligations.
The accounting guidance for AROs addresses the financial accounting and reporting for AROs
associated with the retirement of long-lived assets that result from the acquisition, construction,
development and operation of the assets. The accounting guidance requires the recognition of the
fair value of a liability for AROs in the period in which the liability is incurred if a reasonable
estimate of fair value can be made. We have determined that AROs exist for our underground mains
and services.
62
In accordance with long-standing regulatory treatment, our depreciation rates are comprised of
two components, one based on average service life and one based on cost of removal, as stated
above. We collect through rates the estimated costs of removal on certain regulated properties
through depreciation expense, with a corresponding credit to accumulated depreciation. These
removal costs are non-legal obligations as defined by the accounting guidance. Because these
estimated removal costs meet the requirements of rate regulated accounting guidance, we have
accounted for these non-legal AROs as a regulatory liability. We record the estimated non-legal
AROs in “Cost of removal obligations” in “Noncurrent Liabilities” in our consolidated balance
sheets. In the rate setting process, the liability for non-legal costs of removal is treated as a
reduction to the net rate base upon which the regulated utility has the opportunity to earn its
allowed rate of return.
In 2006, we applied the accounting guidance for conditional AROs that requires recognition of
a liability for the fair value of conditional AROs when incurred if the liability can be reasonably
estimated. AROs will be capitalized concurrently by increasing the carrying amount of the related
asset by the same amount as the liability. In periods subsequent to the initial measurement, any
changes in the liability resulting from the passage of time (accretion) or due to the revisions of
either timing or the amount of the originally estimated cash flows to settle conditional AROs must
be recognized. The estimated cash flows to settle conditional AROs are discounted using the credit
adjusted risk-free rate, which ranged from 5.87% to 5.12% with a weighted average of 5.87% as of
October 31, 2010. The estimate was calculated using a time value weighted average credit adjusted
risk-free rate. Any accretion will not be reflected in the income statement as we have received
regulatory treatment for deferral as a regulatory asset with netting against a regulatory
liability. We have recorded a liability on our distribution and transmission mains and services.
The cost of removal obligations recorded in our consolidated balance sheets as of October 31,
2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Regulatory non-legal AROs
|
|
$
|
412,776
|
|
|
$
|
385,624
|
|
|
Conditional AROs
|
|
|
23,296
|
|
|
|
23,331
|
|
|
|
|
|
|
|
|
|
|
Total cost of removal obligations
|
|
$
|
436,072
|
|
|
$
|
408,955
|
|
|
|
|
|
|
|
|
|
A reconciliation of the changes in conditional AROs for the year ended October 31, 2010 and
2009 is presented below.
63
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Beginning of period
|
|
$
|
23,331
|
|
|
$
|
8,148
|
|
|
Liabilities incurred during the period
|
|
|
137
|
|
|
|
1,368
|
|
|
Liabilities settled during the period
|
|
|
(1,141
|
)
|
|
|
(1,480
|
)
|
|
Accretion
|
|
|
1,350
|
|
|
|
702
|
|
|
Adjustment to estimated cash flows
|
|
|
(382
|
)
|
|
|
14,593
|
|
|
|
|
|
|
|
|
|
|
End of period
|
|
$
|
23,295
|
|
|
$
|
23,331
|
|
|
|
|
|
|
|
|
|
E. Trade Accounts Receivable and Allowance for Doubtful Accounts.
Trade accounts receivable consist of natural gas sales and transportation services,
merchandise sales and service work. We maintain an allowance for doubtful accounts, which we
adjust periodically, based on the aging of receivables and our historical and projected charge-off
activity. Our estimate of recoverability could differ from actual experience based on customer
credit issues, the level of natural gas prices and general economic conditions. Pursuant to orders
issued by the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South
Carolina (PSCSC), we are authorized to recover all uncollected gas costs through the purchased gas
adjustment (PGA). As a result, only the portion of accounts written off relating to the non-gas
costs, or margin, is included in base rates and, accordingly, only this portion is included in the
provision for uncollectibles expense. In Tennessee, to the extent that the gas cost portion of net
write-offs for a fiscal year is less than the gas cost portion included in base rates, the
difference would be refunded to customers through the Actual Cost Adjustment (ACA) filings.
Non-regulated merchandise and service work receivables due beyond one year are included in “Other”
in “Noncurrent Assets” in the consolidated balance sheets.
Our principal business activity is the distribution of natural gas. We believe that we have
provided an adequate allowance for any receivables which may not be ultimately collected. As of
October 31, 2010 and 2009, our trade accounts receivable consisted of the following.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Gas receivables
|
|
$
|
60,823
|
|
|
$
|
69,386
|
|
|
Non-regulated merchandise and
service work receivables
|
|
|
2,476
|
|
|
|
2,583
|
|
|
Allowance for doubtful accounts
|
|
|
(929
|
)
|
|
|
(990
|
)
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
$
|
62,370
|
|
|
$
|
70,979
|
|
|
|
|
|
|
|
|
|
A reconciliation of the changes in the allowance for doubtful accounts for the years ended
October 31, 2010, 2009 and 2008 is presented below.
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Balance at beginning of year
|
|
$
|
990
|
|
|
$
|
1,066
|
|
|
$
|
544
|
|
|
Additions charged to uncollectibles expense
|
|
|
4,886
|
|
|
|
5,570
|
|
|
|
5,308
|
|
|
Accounts written off, net of recoveries
|
|
|
(4,947
|
)
|
|
|
(5,646
|
)
|
|
|
(4,786
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
929
|
|
|
$
|
990
|
|
|
$
|
1,066
|
|
|
|
|
|
|
|
|
|
|
|
|
F. Fair Value Measurements
Our financial assets and liabilities are recorded at fair value. They consist primarily of
derivatives that are recorded in the consolidated balance sheets in accordance with derivative
accounting standards. The adoption of the fair value guidance for our financial assets and
liabilities on November 1, 2008 had no impact on our financial position, results of operations or
cash flows. There was no cumulative effect adjustment to retained earnings as a result of the
adoption. Effective November 1, 2009, we adopted the additional authoritative guidance related to
nonrecurring fair value guidance for certain nonfinancial assets and liabilities, such as the
initial measurement of an ARO and the use of fair value in the impairment testing of goodwill,
intangible assets and long-lived assets. In addition, in February 2010, we adopted the amended
fair value guidance, which clarified disclosure requirements for fair value measurements and
requires disclosure of transfers between Levels 1, 2 or 3. The adoption of the additional fair
value guidance had no material impact on our financial position, results of operations or cash
flows. As of October 31, 2010, in accordance with new accounting guidance for employers’
disclosures about plan assets of defined benefit pension and other postretirement plans, the plan
assets of our benefit plans are classified within the fair value hierarchy by asset allocation.
The carrying value of cash and cash equivalents, receivables, bank debt, accounts payable and
accrued interest approximates fair value.
We utilize market data or assumptions about risk and the risks inherent in the inputs to the
valuation technique. These inputs can be readily observable, market corroborated or generally
observable. We primarily apply the market approach for recurring fair value measurements and
endeavor to utilize the best available information. Accordingly, we use valuation techniques that
maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value
of our financial assets and liabilities are subject to potentially significant volatility based on
changes in market prices, the portfolio valuation of our contracts, as well as the maturity and
settlement of those contracts, and subsequent newly originated transactions, each of which directly
affects the estimated fair value of our financial instruments. We are able to classify fair value
balances based on the observance of those inputs into the following fair value hierarchy levels as
set forth in the fair value guidance.
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or
liabilities that we have the ability to access as of the reporting date. Active markets have
sufficient frequency and volume to provide pricing information for the asset or liability on an
ongoing basis. Our Level 1 items consist of financial instruments of exchange-traded derivatives,
investments in marketable securities and benefit plan assets held in registered investment
companies and individual stocks.
65
Level 2 inputs are inputs other than quoted prices in active markets included in Level 1 and
are either directly or indirectly corroborated or observable as of the reporting date, generally
using valuation methodologies. Our Level 2 items include non-exchange-traded derivative
instruments, such as over-the-counter (OTC) options and some qualified pension plan assets held in
hedge fund of funds, swaps, futures, currency forwards, corporate bonds and government and agency
obligations that are valued at the closing price reported in the active market for similar assets
in which the individual securities are traded or based on yields currently available on comparable
securities of issuers with similar credit ratings or based on the most recent available financial
information for the respective funds and securities. For some qualified pension plan assets, the
determination of Level 2 assets was completed through a process of reviewing each individual
security while consulting research and other metrics provided by investment managers, including a
pricing matrix detailing the pricing source and security type, annual audited financial statements
and valuation policies and procedures.
Level 3 inputs include significant pricing inputs that are generally less observable from
objective sources and may be used with internally developed methodologies that result in
management’s best estimate of fair value. Our Level 3 inputs include cost estimates for removal
(contract fees or manpower/equipment estimates), inflation factors, risk premiums, the remaining
life of long-lived assets, the credit adjusted risk free rate to discount for the time value of
money over an appropriate time span, and the most recent available financial information of an
investment in a hedge fund of funds and diversified private equity fund of funds for some of our
qualified pension plan assets. We do not have any other assets or liabilities classified as Level
3.
Significant transfers between Level 1 and Level 2 are determined based on the transfer in
relation to the total assets invested. These transfers represent existing assets or liabilities
previously categorized as a higher level for which the inputs to the estimate became less
observable or assets and liabilities previously classified as Level 2 or Level 3 for which the
lowest significant input became more observable during the period. Transfers into and out of each
level are measured at the end of the reporting period.
For the fair value measurements of our derivatives and marketable securities, see Note 6 to
the consolidated financial statements. For the fair value measurements of our benefit plan assets,
see Note 8 to the consolidated financial statements.
G. Goodwill, Equity Method Investments and Long-Lived Assets.
All of our goodwill is attributable to the regulated utility segment. We annually evaluate
goodwill for impairment on October 31, or more frequently if impairment indicators arise during the
year. An impairment charge would be recognized if the carrying value of the reporting unit,
including goodwill, exceeded its fair value.
Our annual goodwill impairment assessment was performed as of October 31, 2010, and we
determined that there was no impairment to the carrying value of our goodwill. No impairment has
been recognized during the years ended October 31, 2010, 2009 and 2008.
We review our equity method investments and long-lived assets for impairment whenever events
or changes in circumstances indicate that the carrying amounts may not be recoverable.
66
There were no events or circumstances during the years ended October 31, 2010, 2009 and 2008
that resulted in any impairment charges. For further information on equity method investments, see
Note 11 to the consolidated financial statements.
H. Unamortized Debt Expense.
Unamortized debt expense consists of costs, such as underwriting and broker dealer fees,
discounts and commissions, legal fees, accountant fees, registration fees and rating agency fees,
related to issuing long-term debt and the short-term syndicated revolving credit facility. We
amortize long-term debt expense on a straight-line basis, which approximates the effective interest
method, over the life of the related debt which has lives ranging from 10 to 30 years. We amortize
bank debt expense over the life of the syndicated revolving credit facility, which is five years.
I. Inventories.
We maintain gas inventories on the basis of average cost. Injections into storage are priced
at the purchase cost at the time of injection, and withdrawals from storage are priced at the
weighted average purchase price in storage. The cost of gas in storage is recoverable under rate
schedules approved by state regulatory commissions. Inventory activity is subject to regulatory
review on an annual basis in gas cost recovery proceedings.
We utilize asset management agreements with counterparties for certain natural gas storage and
transportation assets. At October 31, 2010 and 2009, such counterparties held natural gas storage
assets, included in “Prepayments” in the consolidated balance sheets, with a value of $36.6 million
and $40.2 million, respectively, through capacity release and agency relationships. Under the
terms of the asset management agreements, we receive capacity and storage asset management fees,
which are recorded as secondary market transactions and shared between our utility customers and
our shareholders. The asset management agreements expire at various times through March 31, 2011.
Materials, supplies and merchandise inventories are valued at the lower of average cost or
market and removed from such inventory at average cost.
J. Deferred Purchased Gas Adjustments.
Rate schedules for utility sales and transportation customers include PGA provisions that
provide for the recovery of prudently incurred gas costs. With regulatory commission approval, we
revise rates periodically without formal rate proceedings to reflect changes in the wholesale cost
of gas. Under PGA provisions, charges to cost of gas are based on the amount recoverable under
approved rate schedules. By jurisdiction, differences between gas costs incurred and gas costs
billed to customers are deferred and included in “Amounts due from customers” or “Amounts due to
customers” in the consolidated balance sheets. We review gas costs and deferral activity
periodically and, with regulatory commission approval, increase rates to collect under-recoveries
or decrease rates to refund over-recoveries over a subsequent period.
67
K. Marketable Securities.
We have marketable securities that are invested in money market and mutual funds that are
liquid and actively traded on the exchanges. These securities are assets that are held in a rabbi
trust established for our deferred compensation plans that became effective on January 1, 2009.
For further information on the deferred compensation plans, see Note 8 to the consolidated
financial statements.
We have classified these marketable securities as trading securities since their inception as
the assets are held in a rabbi trust. Trading securities are recorded at fair value on the
consolidated balance sheets with any gains or losses recognized currently in earnings. We do not
intend to engage in active trading of the securities, and participants in the deferred compensation
plans may redirect their investments at any time. The balance in a participant’s account that
exceeds $25,000 will be paid over five years upon retirement. A lesser amount will be paid upon
retirement in a lump sum. We have matched the current portion of the deferred compensation
liability with the current asset and the noncurrent deferred compensation liability with the
noncurrent asset; the current portion has been included in “Other current assets” in the
consolidated balance sheets.
The money market investments in the trust approximate fair value due to the short period of
time to maturity. The fair values of the equity securities are based on quoted market prices as
traded on the exchanges. The composition of these securities as of October 31, 2010 and 2009 is as
follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
In thousands
|
|
Cost
|
|
|
Fair Value
|
|
|
Cost
|
|
|
Fair Value
|
|
|
Current trading securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Mutual funds
|
|
|
4
|
|
|
|
5
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current trading securities
|
|
|
4
|
|
|
|
5
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent trading securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
254
|
|
|
|
254
|
|
|
|
169
|
|
|
|
169
|
|
|
Mutual funds
|
|
|
618
|
|
|
|
743
|
|
|
|
205
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent trading
securities
|
|
|
872
|
|
|
|
997
|
|
|
|
374
|
|
|
|
441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading securities
|
|
$
|
876
|
|
|
$
|
1,002
|
|
|
$
|
374
|
|
|
$
|
441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
L. Taxes.
Deferred income taxes are determined based on the estimated future tax effects of differences
between the book and tax basis of assets and liabilities. Deferred taxes are primarily
attributable to utility plant, deferred gas costs, revenues and cost of gas, equity method
investments, benefit of loss carryforwards and employee benefits and compensation. We have
provided valuation allowances to reduce the carrying amount of deferred tax assets to amounts that
are more likely than not to be realized. To the extent that the establishment of deferred income
taxes is different from the recovery of taxes through the ratemaking process, the differences
are deferred in accordance with rate-regulated accounting provisions, and a regulatory asset or
liability is recognized for the impact of tax expenses or benefits that will be collected from or
refunded to
68
customers in different periods pursuant to rate orders. We amortize deferred
investment and energy tax credits to income over the estimated useful lives of the property to
which the credits relate.
Excise taxes, sales taxes and franchises fees separately stated on customer bills are recorded
on a net basis as liabilities payable to the applicable jurisdictions. All other taxes other than
income taxes are recorded as general taxes. General taxes consist of property taxes, payroll
taxes, Tennessee gross receipt taxes, franchise taxes, tax on company use, public utility fees and
other miscellaneous taxes.
M. Revenue Recognition.
Utility sales and transportation revenues are based on rates approved by state regulatory
commissions. Base rates charged to jurisdictional customers may not be changed without formal
approval by the regulatory commission in that jurisdiction; however, the wholesale cost of gas
component of rates may be adjusted periodically under PGA provisions. In South Carolina and
Tennessee, a weather normalization adjustment (WNA) is calculated for residential and commercial
customers during the winter heating season November through March. The WNA is designed to offset
the impact that warmer-than-normal or colder-than-normal weather has on customer billings during
the winter heating season. In North Carolina, a margin decoupling mechanism provides for the
recovery of our approved margin from residential and commercial customers independent of
consumption patterns. The gas cost portion of our costs is recoverable through PGA procedures and
is not affected by the WNA or the margin decoupling mechanism.
Revenues are recognized monthly on the accrual basis, which includes estimated amounts for gas
delivered to customers but not yet billed under the cycle-billing method from the last meter
reading date to month end. The unbilled revenue estimate reflects factors requiring judgment
related to estimated usage by customer class, changes in weather during the period and the impact
of the WNA or margin decoupling mechanism, as applicable.
Secondary market revenues associated with the commodity are recognized when the physical sales
are delivered based on contract or market prices. Asset management fees for storage and
transportation remitted on a monthly basis are recognized as earned given the monthly capacity
costs associated with the contracts involved. Asset management fees remitted in a lump sum are
deferred and amortized ratably into income over the period over which they are earned, which is
typically the contract term. See Note 2 to the consolidated financial statements regarding revenue
sharing of secondary market transactions.
Utility sales, transportation and secondary market revenues are reported on a net of tax
basis. For further information, see Note 1.L to the consolidated financial statements.
N. Earnings Per Share.
We compute basic earnings per share (EPS) using the weighted average number of shares of
common stock outstanding during each period. A reconciliation of basic and diluted EPS for
the years ended October 31, 2010, 2009 and 2008 is presented below.
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands except per share amounts
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net Income
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of common stock outstanding for basic
earnings per share
|
|
|
72,275
|
|
|
|
73,171
|
|
|
|
73,334
|
|
|
Contingently issuable shares under incentive
compensation plans
|
|
|
250
|
|
|
|
290
|
|
|
|
278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average shares of dilutive stock
|
|
|
72,525
|
|
|
|
73,461
|
|
|
|
73,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.96
|
|
|
$
|
1.68
|
|
|
$
|
1.50
|
|
|
Diluted
|
|
$
|
1.96
|
|
|
$
|
1.67
|
|
|
$
|
1.49
|
|
O. Statements of Cash Flows.
For purposes of reporting cash flows, we consider instruments purchased with an original
maturity at date of purchase of three months or less to be cash equivalents.
P. Use of Estimates.
We make estimates and assumptions when preparing the consolidated financial statements. These
estimates and assumptions affect the reported amounts of assets and liabilities and the disclosure
of contingent assets and liabilities as of the date of the consolidated financial statements and
the reported amounts of revenues and expenses during the reporting period. Actual results could
differ from estimates.
Q. Recently Issued Accounting Guidance.
In December 2008, the Financial Accounting Standards Board (FASB) issued new accounting
guidance for employers’ disclosures about plan assets of defined benefit pension and other
postretirement plans. This guidance requires that employers provide more transparency about the
assets held by retirement plans or other postretirement employee benefit plans, the concentration
of risk in those plans and information about the fair value measurements of plan assets similar to
the disclosures required by current fair value guidance. The guidance is effective for fiscal
years ending after December 15, 2009. Since only additional disclosures about plan assets of
defined benefit pension and other postretirement plans are required, the adoption of this guidance,
as of October 31, 2010, had no impact on our financial position, results of operations or cash
flows. For information regarding these disclosures, see Note 8 to the consolidated financial
statements.
In June 2009, the FASB amended accounting guidance to eliminate the quantitative approach that
entities use to determine whether an entity has a controlling financial interest in a variable
interest entity (VIE) and to require that the entity with a variable interest in a VIE
qualitatively assess whether it has a controlling financial interest, and if so, determine whether
it is the primary beneficiary. The guidance requires companies to continually evaluate the VIE for
consolidation, rather than performing the assessment only when specific events occur. It also
requires enhanced disclosures to provide more information about the entity’s involvement with the
VIE. The guidance is effective for fiscal periods beginning after November 15, 2009. Our
adoption of this guidance on consolidation of variable interest entities, effective November 1,
70
2010, is not expected to have a material impact on our financial position, results of operations or
cash flows.
In January 2010, the FASB issued accounting guidance to require new fair value measurement and
classification disclosures and to clarify existing disclosures. The guidance requires disclosures
about transfers into and out of Levels 1 and 2 of the fair value hierarchy and separate disclosures
about purchases, sales, issuances and settlements relating to Level 3 measurements. It also
clarifies the existing fair value disclosures about the level of disaggregation and about inputs
and valuation techniques used to measure fair value and amends guidance on employers’ disclosures
about postretirement benefit plan assets to require disclosures be provided by asset class instead
of major categories of assets. The guidance was effective for interim and fiscal periods beginning
after December 15, 2009, with the exception that the Level 3 activity disclosure requirement will
be effective for interim periods for fiscal years beginning after December 15, 2010. Since the
guidance addresses only disclosure related to fair value measurements, adoption of the guidance
during our fiscal second quarter beginning February 1, 2010 did not have a material impact on our
financial position, results of operations or cash flows. We will adopt the guidance for Level 3
disclosure for recurring and non-recurring items covered under the fair value guidance for the
first quarter of our fiscal year ending October 31, 2012. Since the guidance addresses only
disclosures related to fair value measurements under Level 3, we do not expect the adoption of this
guidance to have a material impact on our financial position, results of operations or cash flows.
In July 2010, the FASB issued accounting guidance to improve disclosures related to an
entity’s allowance for credit losses and the credit quality of its financing receivables, excluding
short-term trade accounts receivable or receivables measured at fair value or cost if lower than
fair value. The guidance requires additional disclosures about financing receivables such as the
credit quality indicators, the aging of past due financing receivables, the nature and extent of
troubled debt restructurings, any modifications of financing receivables as troubled debt
restructurings and the related effect on the allowance for credit losses and any significant
purchases or sales of financing receivables during the reporting period. End of reporting period
disclosures are required for the reporting period ending on or after December 15, 2010. The
disclosures about activity that occurred during a reporting period are effective for interim and
annual periods beginning on or after December 15, 2010. Comparative disclosure for earlier
reporting periods is encouraged but not required. We will adopt the guidance for the end of period
disclosures as of January 31, 2011, and for the disclosures related to activity in the reporting
period during our fiscal second quarter beginning February 1, 2011. Since the guidance addresses
only disclosures related to credit quality of financing receivables and the allowance for credit
losses, we do not expect the adoption of this guidance to have a material impact on our financial
position, results of operations or cash flows.
2. Regulatory Matters
Our utility operations are regulated by the NCUC, PSCSC and Tennessee Regulatory Authority
(TRA) as to rates, service area, adequacy of service, safety standards, extensions and abandonment
of facilities, accounting and depreciation. We are also regulated by the NCUC as to the issuance
of securities.
71
In March 2008, we filed a general rate case proceeding with the NCUC requesting an increase in
rates and charges for all customers to produce overall increased annual revenues of $40.5 million,
or 4% above the current annual revenues. In October 2008, the NCUC approved a settlement between
us, the North Carolina Public Staff and all intervening parties with the exception of the North
Carolina Attorney General’s office, in which the parties agreed to an annual revenue increase of
$15.7 million and the continuation of the margin decoupling mechanism that provides for the
recovery of our approved margin from residential and commercial customers independent of
consumption patterns. Initially, the margin decoupling mechanism was experimental for a three-year
period beginning in 2005, subject to semi-annual reviews and approval for extension in a future
general rate case. In addition to the revenue increase, the stipulation also included cost
allocation and rate design changes under our existing rate schedules, approval to implement energy
conservation and efficiency programs of $1.3 million annually with appropriate cost recovery
mechanisms and changes to existing service regulations and tariffs. The new rates became effective
November 1, 2008.
Since the inception of the North Carolina energy conservation program on November 1, 2005, we
have incurred charges of $6.4 million for the benefit of residential and commercial customers. The
charges consist of $3.75 million for the funding of conservation programs in North Carolina, $2.25
million for the reduction of residential and commercial customer rates in North Carolina and $.4
million for interest accruals on the conservation funding and reduction of customer rates. At
October 31, 2010 and 2009, we had liabilities for the conservation programs of $.4 million and $1.1
million, respectively.
The North Carolina General Assembly enacted the Clean Water and Natural Gas Critical Needs Act
of 1998 which provided for the issuance of $200 million of general obligation bonds of the state
for the purpose of providing grants, loans or other financing for the cost of constructing natural
gas facilities in unserved areas of North Carolina. In 2000, the NCUC issued an order awarding
Eastern North Carolina Natural Gas Company (EasternNC) an exclusive franchise to provide natural
gas service to 14 counties in the eastern-most part of North Carolina that had not been able to
obtain gas service because of the relatively small population of those counties and the resulting
uneconomic feasibility of providing service and granted $38.7 million in state bond funding. In
2001, the NCUC issued an order granting EasternNC an additional $149.6 million, for a total of
$188.3 million. With a 2003 acquisition and subsequent merger of EasternNC into our regulated
utility segment, we are required to provide an accounting of the operational feasibility of this
area to the NCUC every two years. Should this operational area become economically feasible and
generate a profit, we would begin to repay the state bond funding.
The NCUC had allowed EasternNC to defer its operations and maintenance expenses during the
first eight years of operation or until the first rate case order, whichever occurred first, with a
maximum deferral of $15 million. The deferred amounts accrued interest at a rate of 8.69% per
annum. In December 2003, the NCUC confirmed that these deferred expenses should be treated as a
regulatory asset for future recovery from customers to the extent they are deemed prudent and
proper. As a part of the 2005 general rate case proceeding, deferral ceased on October 31, 2005,
and the balance in the deferred account as of June 30, 2005, $7.9 million, including accrued
interest, is being amortized over 15 years beginning November 1, 2005. Under the settlement of the
2008 general rate proceeding, the unamortized balance of the EasternNC deferred
operations and maintenance expenses was $9 million at October 31, 2008. This balance is being
amortized over a twelve-year period and is accruing interest at a rate of 7.84% per annum.
72
We incur certain pipeline integrity management costs in compliance with the Pipeline Safety
Improvement Act of 1992 and regulations of the United States Department of Transportation. The
NCUC approved deferral treatment of these costs applicable to all incremental expenditures
beginning November 1, 2004. As a part of the 2005 general rate case, the balance of $.4 million in
the deferred account as of June 30, 2005 was amortized over three years beginning November 1, 2005,
and subsequent expenditures that totaled $4.3 million as of October 31, 2007 were deferred. Under
the settlement of the 2008 general rate proceeding, the pipeline integrity management costs
incurred between July 1, 2005 and June 30, 2008 of $4.6 million are being amortized over a
three-year period beginning November 1, 2008. The existing regulatory asset treatment for ongoing
pipeline integrity management costs will continue until another recovery mechanism is established
in a future rate proceeding. The balance as of October 31, 2010 that is not being amortized that
is subject to a future rate proceeding is $5.2 million.
We currently operate under the Natural Gas Rate Stabilization Act (RSA) of 2005 in South
Carolina. The law provides electing natural gas utilities, including Piedmont, with a mechanism
for the regular, periodic and more frequent (annual) adjustment of rates which is intended to: (1)
encourage investment by natural gas utilities, (2) enhance economic development efforts, (3) reduce
the cost of rate adjustment proceedings and (4) result in smaller but more frequent rate changes
for customers. If the utility elects to operate under the RSA, the annual filing will provide that
the utility’s rate of return on equity will remain within a 50-basis point band above or below the
current allowed rate of return on equity.
In June 2008, we filed with the PSCSC a quarterly monitoring report for the twelve months
ended March 31, 2008 and a cost and revenue study as permitted by the RSA requesting a change in
rates from those approved by the PSCSC in the October 2007 order. In October 2008, the PSCSC
issued an order approving a settlement between the Office of Regulatory Staff (ORS), the South
Carolina Energy Users Committee (SCEUC) and us that resulted in a $1.5 million annual decrease in
margin based on a return on equity of 11.2%, effective November 1, 2008.
In June 2009, we filed with the PSCSC a quarterly monitoring report for the twelve months
ended March 31, 2009 and a cost and revenue study as permitted by the RSA requesting a change in
rates from those approved by the PSCSC in the October 2008 order. In October 2009, the PSCSC
issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $1.1
million annual increase in margin based on a return on equity of 11.2%, effective November 1, 2009.
In June 2010, we filed with the PSCSC a quarterly monitoring report for the twelve months
ended March 31, 2010 and a cost and revenue study as permitted by the RSA requesting a change in
rates from those approved by the PSCSC in the October 2009 order. In October 2010, the PSCSC
issued an order approving a settlement between the ORS, the SCEUC and us that resulted in a $.75
million annual increase in margin on a return on equity of 11.3%, effective November 1, 2010.
The NCUC and the PSCSC regulate our gas purchasing practices under a standard of prudence and
audit our gas cost accounting practices. The TRA regulates our gas purchasing
practices under a gas supply incentive program which compares our actual costs to market
pricing benchmarks. As part of this jurisdictional oversight, all three states address our gas
supply
73
hedging activities. Additionally, North Carolina and South Carolina allow for recovery of
uncollectible gas costs through the PGA. The portion of uncollectibles related to gas costs is
recovered through the deferred account and only the non-gas costs, or margin, portion of
uncollectibles is included in base rates and uncollectibles expense. In Tennessee, to the extent
that the gas cost portion of net write-offs for a fiscal year is less than the gas cost portion
included in base rates, the difference would be refunded to customers through the ACA filings.
In North Carolina, our recovery of gas costs is subject to annual gas cost proceedings to
determine the prudence of our gas purchases. Costs have never been disallowed on the basis of
prudence.
During 2007, under the provisions of the August 2007 NCUC order, we recorded as restricted
cash $2.2 million, including interest, of supplier refunds. In September 2007, we petitioned the
NCUC for authority to liquidate all certificates of deposit and similar investments that held any
supplier refunds due to customers. In October 2007, the NCUC approved the transfer of these
restricted funds to the North Carolina deferred account. The various certificates of deposit
matured by January 31, 2008.
In February 2009, the NCUC approved our accounting of gas costs for the twelve months ended
May 31, 2008, with adjustments agreed to by us as a result of the North Carolina Public Staff’s
audit of the 2008 gas cost review period. We were deemed prudent on our gas purchasing policies
and practices during this review period and allowed 100% recovery.
In February 2010, the NCUC approved our accounting of gas costs for the twelve months ended
May 31, 2009, with adjustments agreed to by us as a result of the North Carolina Public Staff’s
audit of the 2009 gas cost review period. We were deemed prudent on our gas purchasing policies
and practices during this review period and allowed 100% recovery.
In July 2010, we filed testimony with the NCUC in support of our gas cost purchasing and
accounting practices for the twelve months ended May 31, 2010. A hearing was held on October 5,
2010. We are unable to predict the outcome of this proceeding at this time.
Our gas cost hedging plan for North Carolina is designed for the purpose of cost
stabilization, targets a percentage range of annual normalized sales volumes for North Carolina and
operates using historical pricing indices that are tied to future projected gas prices as traded on
a national exchange. Unlike South Carolina as discussed below, recovery of costs associated with
the North Carolina hedging plan is not pre-approved by the NCUC, and the costs are treated as gas
costs subject to the annual gas cost prudence review. Any gain or loss recognized under the
hedging program is a reduction in or an addition to gas costs, respectively, which, along with any
hedging expenses, are flowed through to North Carolina customers in rates. The gas cost review
orders issued February 2009 and 2010 found our hedging activities during the review periods to be
reasonable and prudent. In 2009, as a part of our North Carolina annual cost review proceeding for
the twelve months ended May 31, 2009, the NCUC approved an adjustment of $1.1 million related to
hedging activity as reflected in “Amounts due from customers” as agreed to by us and the North
Carolina Public Staff.
74
In South Carolina, our recovery of gas costs is subject to annual gas cost proceedings to
determine the prudence of our gas purchases. Costs have never been disallowed on the basis of
prudence.
In August 2008, the PSCSC approved our PGAs and found our gas purchasing policies to be
prudent for the twelve months ended March 31, 2008.
In August 2009, the PSCSC approved our PGAs and found our gas purchasing policies to be
prudent for the twelve months ended March 31, 2009.
In August 2010, the PSCSC approved our PGAs and found our gas purchasing policies to be
prudent for the twelve months ended March 31, 2010.
The PSCSC has approved a gas cost hedging plan for the purpose of cost stabilization for South
Carolina customers. The plan targets a percentage range of annual normalized sales volumes for
South Carolina and operates using historical pricing indices that are tied to future projected gas
prices as traded on a national exchange. All properly accounted for costs incurred in accordance
with the plan are deemed to be prudently incurred and are recovered in rates as gas costs. Any
gain or loss recognized under the hedging program is a reduction in or an addition to gas costs,
respectively, and are flowed through to South Carolina customers in rates.
In October 2009, we filed a petition with the PSCSC requesting approval to offer three energy
efficiency programs to residential and commercial customers at a total annual cost of $.35 million.
The proposed programs in South Carolina were designed to promote energy conservation and
efficiency by residential and commercial customers with full ratepayer recovery of program costs
through annual RSA filings and were similar to approved energy efficiency programs in North
Carolina. In May 2010, the PSCSC approved the energy efficiency programs on a three-year
experimental basis with equipment rebates on the purchase of high-efficiency natural gas equipment
and weatherization assistance for low-income residential customers.
In Tennessee, the Tennessee Incentive Plan (TIP) replaced annual prudence reviews under the
ACA mechanism in 1996 by benchmarking gas costs against amounts determined by published market
indices and by sharing secondary market (capacity release and off-system sales) activity
performance. In 2007, the TRA modified our TIP to clarify and simplify the calculation of
allocated gains and losses to ratepayers and shareholders by adopting a uniform 75/25 sharing
ratio, maintain the $1.6 million annual incentive cap on gains and losses, improve the transparency
of plan operations by an agreed to request for proposal procedures for asset management
transactions and provide for a triennial review of TIP operations by an independent consultant.
We filed an annual report for the twelve months ended December 31, 2006 with the TRA that
reflected the transactions in the deferred gas cost account for the ACA mechanism. In June 2008,
the TRA staff filed its final audit report, with which we concurred. In August 2008, the TRA
issued an order adopting all findings from the staff audit. The order included cost of gas
adjustments for the calendar year 2006 review period. There was no material impact from these gas
cost adjustments on our financial position, results of operations or cash flows.
In December 2008, we filed an annual report for the twelve months ended December 31, 2007 with
the TRA that reflected the transactions in the deferred gas cost account for the ACA
75
mechanism. In April 2009, the TRA staff filed its final audit report, with which we
concurred. In May 2009, the TRA issued an order adopting all findings from the staff audit. The
order included cost of gas adjustments for the calendar year 2007 review period. There was no
material impact from these gas cost adjustments on our financial position, results of operations or
cash flows. We were found to be in compliance with the TRA rules in the use of the ACA mechanism.
In July 2009, we filed an annual report for the twelve months ended December 31, 2008 with the
TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. In
July 2010, in coordination with the TRA Audit Staff, we withdrew the annual report filed in July
2009 and concurrently filed a revised annual report for the twelve months ended December 31, 2008.
There was no material impact from these gas cost adjustments on our financial position, results of
operations or cash flows. In October 2010, the TRA issued its order adopting the findings of the
revised TRA Audit Staff report on this matter, which were in agreement with our revised report.
In December 2010, we filed our report for the eighteen months ended June 30, 2010 with the TRA
that reflected the transactions in the deferred gas cost account for the ACA mechanism. This
one-time eighteen month audit period is designed to synchronize the ACA audit year with the TIP
year in order to facilitate the audit process for future periods. We are unable to predict the
outcome of this proceeding at this time.
In July 2009, we filed a petition with the TRA requesting approval to decouple residential
rates in Tennessee and to offer three energy efficiency programs to residential customers. We
proposed a margin decoupling tracker mechanism that was designed to allow us to recover from our
residential customers the approved per customer margin as approved in our last general rate
proceeding. The proposed energy efficiency programs in Tennessee were designed to promote energy
conservation and efficiency by residential customers and were similar to approved energy efficiency
programs in North Carolina. In August 2009, the TRA suspended the tariff and established a
contested case to address the filing. A hearing on our requests was held in December 2009. In
January 2010, the TRA denied our petition without prejudice to us refiling a margin decoupling
tracker mechanism (or other similar mechanism) and energy efficiency programs for residential
customers in a future general rate proceeding.
In February 2010, we filed a petition with the TRA to adjust the applicable rate for the
collection of the Nashville franchise fee from certain customers. The proposed rate adjustment was
calculated to recover the net $2.9 million of under-collected Nashville franchise fee payments as
of May 31, 2009. In April 2010, the TRA passed a motion approving a new Nashville franchise fee
rate designed to recover only the net under-collections that have accrued since June 1, 2005, which
would deny recovery of $1.5 million for us. Once the TRA issues its order on this matter, we
intend to seek their reconsideration. We are unable to predict the outcome of this proceeding at
this time. However, we do not believe this matter will have a material effect on our financial
position, results of operations or cash flows.
In September 2010, we filed a petition with the TRA requesting deferred accounting treatment
for the direct, incremental expenses incurred as a result of our response to the severe flooding in
Nashville in May 2010. The TRA approved our petition in October 2010. As of October 31, 2010, the
balance in the deferred account is $1 million.
76
Due to the seasonal nature of our business, we contract with customers in the secondary market
to sell supply and capacity assets when available. In North Carolina and South Carolina, we
operate under sharing mechanisms approved by the NCUC and the PSCSC for secondary market
transactions where 75% of the net margins are flowed through to jurisdictional customers in rates
and 25% is retained by us. In Tennessee, we operate under the amended TIP where gas purchase
benchmarking gains and losses are combined with secondary market transaction gains and losses and
shared 75% by customers and 25% by us. Our share of net gains or losses in Tennessee is subject to
an overall annual cap of $1.6 million. In all three jurisdictions for the twelve months ended
October 31, 2010, we generated $42.8 million of margin from secondary market activity, $32.1
million of which was allocated to customers as gas cost reductions and $10.7 million as margin
allocated to us.
The NCUC, the PSCSC and the TRA approved our 2006 request to place certain defined benefit
postretirement obligations related to the implementation of accounting guidance for employers’
accounting for defined benefit pension and other postretirement plans in a deferred account instead
of OCI. Also in 2006, as a result of adopting accounting guidance for conditional AROs, the
placing of certain ARO costs in deferred accounts to preserve the regulatory treatment for these
costs was approved in all jurisdictions.
We currently have commission approval in all three states that place tighter credit
requirements on the retail natural gas marketers that schedule gas into our system in order to
mitigate the risk exposure to the financial condition of the marketers.
3. Long-Term Debt
All of our long-term debt is unsecured and is issued at fixed rates. Long-term debt as of
October 31, 2010 and 2009 is as follows.
77
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Senior Notes:
|
|
|
|
|
|
|
|
|
|
8.51%, due 2017
|
|
$
|
35,000
|
|
|
$
|
35,000
|
|
|
Medium-Term Notes:
|
|
|
|
|
|
|
|
|
|
7.80%, due 2010
|
|
|
—
|
|
|
|
60,000
|
|
|
6.55%, due 2011
|
|
|
60,000
|
|
|
|
60,000
|
|
|
5.00%, due 2013
|
|
|
100,000
|
|
|
|
100,000
|
|
|
6.87%, due 2023
|
|
|
45,000
|
|
|
|
45,000
|
|
|
8.45%, due 2024
|
|
|
40,000
|
|
|
|
40,000
|
|
|
7.40%, due 2025
|
|
|
55,000
|
|
|
|
55,000
|
|
|
7.50%, due 2026
|
|
|
40,000
|
|
|
|
40,000
|
|
|
7.95%, due 2029
|
|
|
60,000
|
|
|
|
60,000
|
|
|
6.00%, due 2033
|
|
|
100,000
|
|
|
|
100,000
|
|
|
Insured Quarterly Notes:
|
|
|
|
|
|
|
|
|
|
6.25%, due 2036
|
|
|
196,922
|
|
|
|
197,512
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
731,922
|
|
|
|
792,512
|
|
|
Less current maturities
|
|
|
60,000
|
|
|
|
60,000
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
671,922
|
|
|
$
|
732,512
|
|
|
|
|
|
|
|
|
|
Current maturities for the next five years ending October 31 and thereafter are as follows.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
2011
|
|
$
|
60,000
|
|
|
2012
|
|
|
—
|
|
|
2013
|
|
|
—
|
|
|
2014
|
|
|
100,000
|
|
|
2015
|
|
|
—
|
|
|
Thereafter
|
|
|
571,922
|
|
|
|
|
|
|
|
Total
|
|
$
|
731,922
|
|
|
|
|
|
|
Payments of $.6 million and $1.7 million in 2010 and 2009, respectively, were paid to
noteholders of the 6.25% insured quarterly notes based on a redemption right upon the death of the
owner of the notes, within specified limitations. We retired the balance of $60 million of our
7.8% medium-term notes and $30 million of our 7.35% medium-term notes in September 2010 and
September 2009, respectively, as they became due.
The amount of cash dividends that may be paid on common stock is restricted by provisions
contained in certain note agreements under which long-term debt was issued, with those for the
senior notes being the most restrictive. We cannot pay or declare any dividends or make any other
distribution on any class of stock or make any investments in subsidiaries or permit any subsidiary
to do any of the above (all of the foregoing being “restricted payments”), except out of net
earnings available for restricted payments. As of October 31, 2010, our retained earnings were
78
not restricted as the amount available for restricted payments was greater than our actual
retained earnings as presented below.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
Amount available for restricted payments
|
|
$
|
591,595
|
|
|
Retained earnings
|
|
|
519,831
|
|
We are subject to default provisions related to our long-term debt and short-term debt. Since
there are cross-default provisions in all of our debt agreements, failure to satisfy any of the
default provisions may result in total outstanding issues of debt becoming due. As of October 31,
2010, we are in compliance with all default provisions.
4. Short-Term Debt Instruments
We have a syndicated five-year revolving credit facility that expires April 2011 with
aggregate commitments totaling $450 million to meet working capital needs, capital expenditures and
approved acquisitions. This facility may be increased up to $600 million and includes annual
renewal options and letters of credit. We pay an annual fee of $35,000 plus six basis points for
any unused amount up to $450 million. The facility provides a line of credit for letters of credit
of $5 million, of which $2.7 million and $2.4 million were issued and outstanding at October 31,
2010 and 2009, respectively. These letters of credit are used to guarantee claims from
self-insurance under our general and automobile liability policies. The credit facility bears
interest based on the 30-day LIBOR rate plus from 15 to 35 basis points, based on our credit
ratings. Amounts borrowed remain outstanding until repaid and such amounts do not mature daily.
Due to the seasonal nature of our business, amounts borrowed can vary significantly during the
year.
Effective December 3, 2008, we entered into a syndicated seasonal credit facility with
aggregate commitments totaling $150 million. Advances under this seasonal facility bore interest
at a rate based on the 30-day LIBOR rate plus from 75 to 175 basis points, based on our credit
ratings. This seasonal credit facility expired on March 31, 2009. We entered into this facility
to provide lines of credit in addition to the syndicated five-year revolving credit facility
discussed above in order to have additional resources to meet seasonal cash flow requirements and
general corporate needs. This seasonal credit facility replaced the two short-term credit
facilities with banks for unsecured commitments totaling $75 million that were effective from
October 27 and 29, 2008 through December 3, 2008, bearing interest at the same rate as the seasonal
facility.
As of October 31, 2010 and 2009, outstanding short-term borrowings under our syndicated
five-year revolving credit facility as included in “Bank debt” in the consolidated balance sheets
were $242 million and $306 million, respectively, in LIBOR cost-plus loans at a weighted average
interest rate of .50% in 2010 and .85% in 2009. During the twelve months ended October 31, 2010,
short-term borrowings ranged from zero to $342.5 million, and interest rates ranged from .48% to
.61% when borrowing. Our syndicated five-year revolving credit facility’s financial covenants
require us to maintain a ratio of total debt to total capitalization of no greater than 70%, and
our actual ratio was 50% at October 31, 2010.
79
5. Capital Stock and Accelerated Share Repurchase
Changes in common stock for the years ended October 31, 2010, 2009 and 2008 are as follows.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Shares
|
|
|
Amount
|
|
|
Balance, October 31, 2007
|
|
|
74,208
|
|
|
$
|
497,570
|
|
|
Issued to participants in the Employee Stock Purchase Plan (ESPP)
|
|
|
33
|
|
|
|
838
|
|
|
Issued to the Dividend Reinvestment and Stock Purchase Plan
(DRIP)
|
|
|
567
|
|
|
|
14,753
|
|
|
Issued to participants in the Executive Long-Term Incentive Plan
(LTIP)
|
|
|
40
|
|
|
|
1,082
|
|
|
Shares repurchased under Common Stock Open Market Repurchase Plan
|
|
|
(1,000
|
)
|
|
|
(26,139
|
)
|
|
Shares repurchased under Accelerated Share Repurchase (ASR) Plan
|
|
|
(602
|
)
|
|
|
(16,539
|
)
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2008
|
|
|
73,246
|
|
|
|
471,565
|
|
|
Issued to ESPP
|
|
|
37
|
|
|
|
875
|
|
|
Issued to DRIP
|
|
|
565
|
|
|
|
13,560
|
|
|
Issued to LTIP
|
|
|
89
|
|
|
|
2,755
|
|
|
Issued to participants in the Incentive Compensation Plan (ICP)
|
|
|
29
|
|
|
|
671
|
|
|
Shares repurchased under ASR Plan
|
|
|
(700
|
)
|
|
|
(17,857
|
)
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2009
|
|
|
73,266
|
|
|
|
471,569
|
|
|
Issued to ESPP
|
|
|
35
|
|
|
|
899
|
|
|
Issued to DRIP
|
|
|
676
|
|
|
|
17,663
|
|
|
Issued to ICP
|
|
|
106
|
|
|
|
2,804
|
|
|
Shares repurchased under ASR Plan
|
|
|
(1,800
|
)
|
|
|
(47,276
|
)
|
|
Shares repurchased under Rescission Offer
|
|
|
(1
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
Balance, October 31, 2010
|
|
|
72,282
|
|
|
$
|
445,640
|
|
|
|
|
|
|
|
|
|
In June 2004, the Board of Directors approved a Common Stock Open Market Purchase Program that
authorized the repurchase of up to three million shares of currently outstanding shares of common
stock. We implemented the program in September 2004. On December 16, 2005, the Board of Directors
approved an increase in the number of shares in this program from three million to six million to
reflect the two-for-one stock split in 2004. The Board also approved on that date an amendment of
the Common Stock Open Market Purchase Program to provide for the repurchase of up to four million
additional shares of common stock to maintain our debt-to-equity capitalization ratios at target
levels. These combined actions increased the total authorized share repurchases from three million
to ten million shares. The additional four million shares were referred to as our ASR program with
an expiration date of December 31, 2010. On March 6, 2009, the Board of Directors authorized the
repurchase of up to an additional four million shares under the Common Stock Open Market Purchase
Program and the ASR program, which were consolidated. We utilize a broker to repurchase the shares
on the open market and such shares are cancelled and become authorized but unissued shares
available for issuance.
In January 2010, we began to purchase and retire 1.8 million shares of our common stock under
the Common Stock Open Market Purchase Plan. We repurchased 1.4 million shares for $36.9 million
and .4 million shares for $10.4 million in January 2010 and February 2010,
80
respectively, at an average share price of $26.26. Total consideration paid of $47.3 million
to purchase the shares was recorded in “Stockholders’ equity” as a reduction in “Common stock” in
the consolidated balance sheets.
As of October 31, 2010, 4.6 million shares of common stock were reserved for issuance as
follows.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
ESPP
|
|
|
303
|
|
|
DRIP
|
|
|
2,088
|
|
|
LTIP and ICP
|
|
|
2,221
|
|
|
|
|
|
|
|
Total
|
|
|
4,612
|
|
|
|
|
|
|
On November 16, 2009, we discovered in fiscal 2009 and early fiscal 2010 that we had
inadvertently sold more shares under our DRIP than were registered with the Securities and Exchange
Commission (SEC) and authorized by our Board of Directors for issuance under the DRIP. We also
discovered that the registration statement we believed had registered shares issued under the DRIP
between December 1, 2008 and November 16, 2009 had expired for some of those shares. As a result,
from November 1, 2009 through November 16, 2009, we sold 15,029 shares under the DRIP that may not
have been registered at the time of issuance for proceeds of $347,000. Our Board of Directors
ratified the authorization and issuance of the excess number of shares, and on November 20, 2009,
we filed a registration statement covering the sale and issuance of an additional 2.75 million
shares of our common stock under the DRIP. On February 8, 2010, we filed a registration statement
(Rescission Offer) which offered to rescind the purchase of the shares sold under the DRIP between
December 1, 2008 and November 16, 2009 and registered all previously unregistered shares issued
under the DRIP during that period. Under the Rescission Offer, the purchase of 711 shares was
rescinded for an aggregate consideration of $18,900. We incurred costs related to the Rescission
Offer of $.8 million, which have been recorded against retained earnings. We reported these events
to the relevant regulatory authorities, including the SEC and the NCUC. The sale of unregistered
securities could subject us to enforcement actions or penalties and fines by these regulatory
authorities, though no regulatory action has been initiated. While we are unable to predict the
full consequences of these events, we do not expect them to have a material adverse effect on us.
6. Financial Instruments and Related Fair Value
Derivative Assets and Liabilities under Master Netting Arrangements
We maintain brokerage accounts to facilitate transactions that support our gas cost hedging
plans. Based on the value of our positions in these brokerage accounts and the associated margin
requirements, we may be required to deposit cash into these accounts. The accounting guidance
related to derivatives and hedging requires that we use a gross presentation for the fair value
amounts for our derivative instruments and the fair value of the right to reclaim cash collateral.
We include amounts recognized for the right to reclaim cash collateral in our current assets and
current liabilities. We had no cash deposited in the brokerage accounts as of October 31, 2010,
and we had the right to reclaim cash collateral of $35.4 million as of October 31, 2009.
81
Fair Value Measurements
We use financial instruments to mitigate commodity price risk for our customers. In
developing our fair value measurements of these financial instruments, we utilize market data or
assumptions about risk and the risks inherent in the inputs to the valuation technique. Fair value
refers to the price that would be received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants in the market in which the entity transacts. We
are able to classify fair value balances based on the observance of those inputs into the fair
value hierarchy levels as set forth in the fair value accounting guidance and fully described in
Note 1.F.
The following table sets forth, by level of the fair value hierarchy, our financial assets and
liabilities that were accounted for at fair value on a recurring basis as of October 31, 2010 and
2009. Financial assets and liabilities are classified in their entirety based on the lowest level
of input that is significant to the fair value measurement. Our assessment of the significance of
a particular input to the fair value measurement requires judgment and may affect the valuation of
fair value assets and liabilities and their consideration with the fair value hierarchy levels. We
have had no transfers between Level 1 and Level 2 during this fiscal year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2010
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Total
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Carrying
|
|
|
In thousands
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
2,819
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,819
|
|
|
Debt and equity securities held as trading
securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
254
|
|
|
|
—
|
|
|
|
—
|
|
|
|
254
|
|
|
Mutual funds
|
|
|
748
|
|
|
|
—
|
|
|
|
—
|
|
|
|
748
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value assets
|
|
$
|
3,821
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2009
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Total
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Carrying
|
|
|
In thousands
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
2,559
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,559
|
|
|
Debt and equity securities held as trading
securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
169
|
|
|
|
—
|
|
|
|
—
|
|
|
|
169
|
|
|
Mutual funds
|
|
|
272
|
|
|
|
—
|
|
|
|
—
|
|
|
|
272
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fair value assets
|
|
$
|
3,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
30,290
|
|
|
$
|
313
|
|
|
$
|
—
|
|
|
$
|
30,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The determination of the fair values incorporates various factors required under the fair
value guidance. These factors include the credit standing of the counterparties involved, the
impact of credit enhancements (such as cash deposits, letters of credit and priority interests) and
the impact of our nonperformance risk on our liabilities.
Our utility segment derivative instruments are used in accordance with programs filed with or
approved by the NCUC, the PSCSC and the TRA to hedge the impact of market fluctuations in natural
gas prices. These derivative instruments are accounted for at fair value each reporting period.
In accordance with regulatory requirements, the net costs and the gains and losses related to these
derivatives are reflected in purchased gas costs and ultimately passed through to customers through
our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the
unrecovered amounts related to these instruments are reflected as a regulatory asset or liability,
as appropriate, in “Amounts due to customers” or “Amounts due from customers” in our consolidated
balance sheets. These derivative instruments include exchange-traded and OTC derivative contracts.
Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and
are classified within Level 1. OTC derivative contracts are valued using broker or dealer
quotation services or market transactions in either the listed or OTC markets and are classified
within Level 2.
Trading securities include assets in a rabbi trust established for our deferred compensation
plans and are included in “Marketable securities, at fair value” in the consolidated balance
sheets. Securities classified within Level 1 include funds held in money market and mutual funds,
which are highly liquid and are actively traded on the exchanges.
In developing the fair value of our long-term debt, we use a discounted cash flow technique,
consistently applied, that incorporates a developed discount rate using long-term debt similarly
rated by credit rating agencies combined with the U.S. Treasury bench mark with consideration given
to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying
amount and fair value of our long-term debt, including the current portion,
are shown below.
83
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
|
|
|
|
In thousands
|
|
Amount
|
|
Fair Value
|
|
As of October 31, 2010
|
|
$
|
731,922
|
|
|
$
|
890,277
|
|
|
As of October 31, 2009
|
|
|
792,512
|
|
|
|
910,310
|
|
Quantitative and Qualitative Disclosures
The costs of our financial price hedging options for natural gas and all other costs related
to hedging activities of our regulated gas costs are recorded in accordance with our regulatory
tariffs approved by our state regulatory commissions, and thus are not accounted for as hedging
instruments under derivative accounting standards. As required by the accounting guidance, the
fair value amounts are presented on a gross basis and do not reflect any netting of asset and
liability amounts or cash collateral amounts under master netting arrangements. As of October 31,
2010, our financial options were comprised of long commodity positions and as of October 31, 2009,
our financial options were comprised of both long and short commodity positions. A long position
in an option contract is a right to purchase or sell the commodity at a specified price, while a
short position in an option contract is the obligation, if the option is exercised, to purchase or
sell the commodity at a specified price. As of October 31, 2010, we had long gas options providing
total coverage of 33.5 million dekatherms. As of October 31, 2009, we had long options providing
total coverage of 49.7 million dekatherms, of which 40.9 million dekatherms were limited in upside
protection; we sold options for 25.4 million dekatherms that guaranteed a minimum floor price for
supply. As of October 31, 2010, the long options are for the period from December 2010 through
November 2011.
The following table presents the fair value and balance sheet classification of our financial
options for natural gas as of October 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Instruments
|
|
|
|
|
Fair Value
|
|
|
Fair Value
|
|
|
In thousands
|
|
October 31, 2010
|
|
|
October 31, 2009
|
|
|
Derivatives Not Designated as Hedging Instruments under Derivative Accounting
Standards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments
|
|
|
|
|
|
|
|
|
|
Current Assets — Gas purchase derivative assets (December 2010 - November 2011)
|
|
$
|
2,819
|
|
|
|
|
|
|
Current Assets — Gas purchase derivative assets (December 2009 - November 2010)
|
|
|
|
|
|
$
|
2,559
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability Financial Instruments
|
|
|
|
|
|
|
|
|
|
Current Liabilities — Gas purchase derivative liabilities (December 2009 -
November 2010)
|
|
|
|
|
|
|
30,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments, net
|
|
$
|
2,819
|
|
|
$
|
(28,044
|
)
|
|
|
|
|
|
|
|
|
We purchase natural gas for our regulated operations for resale under tariffs approved by
state regulatory commissions. We recover the cost of gas purchased for regulated operations
through PGA procedures. Our risk management policies allow us to use financial instruments to
84
hedge commodity price risks, but not for speculative trading. The strategy and objective of
our hedging programs is to use these financial instruments to provide protection against
significant price increases. Accordingly, the operation of the hedging programs on the regulated
utility segment as a result of the use of these financial derivatives generally has no earnings
impact.
The following table presents the impact that financial instruments not designated as hedging
instruments under derivative accounting standards would have had on our consolidated statements of
income for 2010 and 2009, absent the regulatory treatment under our approved PGA procedures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss Recognized
|
|
|
Amount of Loss Deferred
|
|
|
|
|
|
|
|
on Derivatives Instruments
|
|
|
Under PGA Procedures
|
|
|
|
|
|
|
|
Twelve Months Ended
|
|
|
Twelve Months Ended
|
|
|
Location of Loss
|
|
|
|
|
October 31,
|
|
|
October 31,
|
|
|
Recognized through
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
PGA Procedures
|
|
|
Gas purchase options
|
|
$
|
62,516
|
|
|
$
|
148,461
|
|
|
$
|
62,516
|
|
|
$
|
147,370
|
|
|
Cost of Gas
|
In Tennessee, the cost of these options and all other costs related to hedging activities
up to 1% of total annual gas costs are approved for recovery under the terms and conditions of our
TIP approved by the TRA. In South Carolina, the costs of these options are pre-approved by the
PSCSC for recovery from customers subject to the terms and conditions of our gas hedging plan
approved by the PSCSC. In North Carolina, costs associated with our hedging program are not
pre-approved by the NCUC but are treated as gas costs subject to an annual cost review proceeding
by the NCUC. In 2009, as a part of our North Carolina annual cost review proceeding for the twelve
months ended May 31, 2009, we and the North Carolina Public Staff agreed to an adjustment of $1.1
million related to hedging activity as reflected in “Amounts due from customers,” which was
approved by the NCUC in February 2010.
Risk Management
Our OTC derivative financial instruments do not contain material credit-risk-related or other
contingent features that could require us to make accelerated payments over and above payments made
in the normal course of business when we are in a net liability position. At October 31, 2010 and
October 31, 2009, we have five International Swaps and Derivatives Association (ISDA) agreements
for the purpose of securing put options as a part of our overall hedging program. The ISDA
agreements specify a total net liability of $162 million before we are obligated to post
collateral. The net liability extended under the agreements is a function of the credit rating
assigned to us by Standard & Poor’s Ratings Services (S&P), which is currently A/stable. In the
event of a downgrade in our S&P credit rating to A-, the net liability available to us would
decline to $142 million before we would be obligated to post collateral. We have no outstanding
positions under any ISDA agreement as of October 31, 2010 and $.3 million aggregate fair value of
the derivative instruments that are in a net liability position as of October 31, 2009 for which we
were not required to post collateral. These instruments are acquired under the provisions of our
regulatory tariffs. Therefore, should credit-risk-related factors require us to deposit funds as
collateral, these amounts would be handled in accordance with our hedging programs under the
recovery mechanism filed with and allowed by each of our state regulators.
85
We seek to identify, assess, monitor and manage risk in accordance with defined policies and
procedures under an Enterprise Risk Management Policy. In addition, we have an Energy Price Risk
Management Committee that monitors compliance with our hedging programs, policies and procedures.
7. Commitments and Contingent Liabilities
Leases
We lease certain buildings, land and equipment for use in our operations under noncancelable
operating leases. Operating lease payments for the years ended October 31, 2010, 2009 and 2008 are
as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Operating lease payments
|
|
$
|
5,303
|
|
|
$
|
6,173
|
|
|
$
|
5,483
|
|
Future minimum lease obligations for the next five years ending October 31 and thereafter are
as follows.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
2011
|
|
$
|
4,584
|
|
|
2012
|
|
|
4,468
|
|
|
2013
|
|
|
4,208
|
|
|
2014
|
|
|
4,158
|
|
|
2015
|
|
|
3,973
|
|
|
Thereafter
|
|
|
1,984
|
|
|
|
|
|
|
|
Total
|
|
$
|
23,375
|
|
|
|
|
|
|
Long-term contracts
We routinely enter into long-term gas supply commodity and capacity commitments and other
agreements that commit future cash flows to acquire services we need in our business. These
commitments include pipeline and storage capacity contracts and gas supply contracts to provide
service to our customers and telecommunication and information technology contracts and other
purchase obligations. The time periods for pipeline and storage capacity contracts range from one
to twenty-two years. The time periods for gas supply contracts range from one to two years. The
time periods for the telecommunications and technology outsourcing contracts, maintenance fees for
hardware and software applications, usage fees, local and long-distance costs and wireless service
range from one to three years. Other purchase obligations consist primarily of commitments for
pipeline products, vehicles and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are
based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to
86
maintain our right to access the natural gas storage or the pipeline capacity on a firm basis
during the contract term. The demand charges that are incurred in each period are recognized in
the consolidated statements of income as part of gas purchases and included in cost of gas.
As of October 31, 2010, future unconditional purchase obligations for the next five years
ending October 31 and thereafter are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline and
|
|
|
|
|
|
|
Telecommunications
|
|
|
|
|
|
|
|
|
|
|
Storage
|
|
|
|
|
|
|
and Information
|
|
|
|
|
|
|
|
|
In thousands
|
|
Capacity
|
|
|
Gas Supply
|
|
|
Technology
|
|
|
Other
|
|
|
Total
|
|
|
2011
|
|
$
|
150,914
|
|
|
$
|
11,862
|
|
|
$
|
15,316
|
|
|
$
|
5,147
|
|
|
$
|
183,239
|
|
|
2012
|
|
|
142,627
|
|
|
|
48
|
|
|
|
5,381
|
|
|
|
—
|
|
|
|
148,056
|
|
|
2013
|
|
|
97,553
|
|
|
|
12
|
|
|
|
67
|
|
|
|
—
|
|
|
|
97,632
|
|
|
2014
|
|
|
75,651
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
75,651
|
|
|
2015
|
|
|
68,093
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
68,093
|
|
|
Thereafter
|
|
|
348,995
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
348,995
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
883,833
|
|
|
$
|
11,922
|
|
|
$
|
20,764
|
|
|
$
|
5,147
|
|
|
$
|
921,666
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Legal
We have only routine litigation in the normal course of business.
Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general liability
policies. We had $2.7 million in letters of credit that were issued and outstanding at October 31,
2010. Additional information concerning letters of credit is included in Note 4 to the
consolidated financial statements.
Environmental Matters
Our three regulatory commissions have authorized us to utilize deferral accounting in
connection with environmental costs. Accordingly, we have established regulatory assets for actual
environmental costs incurred and for estimated environmental liabilities recorded.
In October 1997, we entered into a settlement with a third party with respect to nine
manufactured gas plant (MGP) sites that we have owned, leased or operated and paid $5.3 million,
charged to the estimated environmental liability, that released us from any investigation and
remediation liability. Although no such claims are pending or, to our knowledge, threatened, the
settlement did not cover any third-party claims for personal injury, death, property damage and
diminution of property value or natural resources.
There are three other MGP sites located in Hickory, North Carolina, Nashville, Tennessee and
Anderson, South Carolina that we have owned, leased or operated. In addition to these sites, we
acquired the liability for an MGP site located in Reidsville, North Carolina in connection with the
acquisition in 2002 of certain assets and liabilities of North Carolina Services, a division of NUI
Utilities, Inc.
87
As part of a voluntary agreement with the North Carolina Department of Environment and Natural
Resources (NCDENR), we started the initial steps for investigating the Hickory, North Carolina MGP
site in 2007. Based on a limited site assessment report in 2007, we concluded that gas plant
residuals remaining on the Hickory site were thought to be mostly contained within two former tar
separators associated with the site’s operations. During 2008, more extensive testing was
conducted and completed, including soil investigation and phase 1 of the groundwater investigation.
The soil investigation revealed that most of the site surface soils and a significant area of deep
soils exceed the site specific cleanup standards, and phase 1 of the groundwater investigation
revealed contamination from an underground storage tank (UST) and the MGP. A remedial work plan to
remove the soil has been submitted and approved by the NCDENR. The removal of approximately 10,000
tons of MGP impacted soil and phase 2 groundwater investigation was initiated in April 2010 and
completed in June 2010. During 2010, our estimate of the total cost to remediate the facility
increased from $1 million to $1.3 million. In accordance with the deferral accounting authorized
by our regulatory commissions, we adjusted the regulatory asset and the estimated liability for
this additional $.3 million. We have incurred $1.3 million on this site through October 31, 2010.
The state may require additional groundwater remediation after it reviews our phase 2 groundwater
investigation report. If the state does not require any further action, we will then submit our
final report with the state.
In September 2009, the NCDENR requested a remediation plan for the Reidsville, North Carolina
MGP site. In January 2010, we submitted our plan to the NCDENR. In June 2010, we conducted our
initial investigation which consisted of digging test pits and completing soil and groundwater
contamination testing. Our estimate of the total cost to remediate the Reidsville site is $.8
million for which we have recorded a liability.
In November 2008, we submitted our final report of the remediation of the Nashville MGP holder
site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been
completed, and a consent order imposing usage restrictions on the property was approved and signed
by the TDEC in June 2010. The consent order is subject to public comment, which we anticipate
being completed in our first quarter of 2011. We have incurred $1.5 million through October 31,
2010 for this remediation.
In connection with the 2003 North Carolina Natural Gas Corporation (NCNG) acquisition, several
MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc.
(Progress) prior to closing. Progress has complete responsibility for performing all of NCNG’s
remediation obligations to conduct testing and clean-up at these sites, including both the costs of
such testing and clean-up and the implementation of any affirmative remediation obligations that
NCNG has related to the sites. Progress’ responsibility does not include any third-party claims
for personal injury, death, property damage, and diminution of property value or natural resources.
We know of no such pending or threatened claims.
During 2008, we became aware of and began investigating several contamination concerns at our
Huntersville LNG facility. One area of concern was where a molecular sieve had been buried and
potentially contaminated with hydrocarbons and trichloroethylene. Additionally, groundwater at the
property had trichloroethylene detected at levels which exceeded state standards. The Huntersville
LNG facility also was originally coated with lead-based paint. The molecular sieve and the related
contaminated soil were removed and properly disposed, and in June 2010, we received a determination
letter from the NCDENR that no further soil remediation
88
would be required for the Huntersville LNG molecular sieve issue. The facility uses
groundwater for fire-fighting, and the supply well was equipped with filters to remove any
chlorinated solvents. As a precautionary measure to ensure that no lead contamination occurs,
removal of lead-based paint from the site was initiated in spring 2010. Based on the activities
mentioned above, during 2010, our estimate of the total cost to remediate the facility increased
from $1.6 million to $3.1 million. In accordance with the deferral accounting authorized by our
regulatory commissions, we adjusted the regulatory asset and the estimated liability for this
additional $1.5 million. We have incurred $2.3 million through October 31, 2010. We are
continuing to address the remaining remediation issues, including completing a groundwater
monitoring plan and removing lead-based paint, both scheduled to be finished in our fiscal 2011.
Since 2009, we have identified USTs that may require remediation and have removed USTs that
did not require additional remediation efforts. As of October 31, 2010, our undiscounted
environmental liability for USTs for which we retain remediation responsibility is $.4 million.
As of October 31, 2010, our undiscounted environmental liability totaled $2.7 million, and
consisted of $1.5 million for the four MGP sites for which we retain remediation responsibility,
$.8 million for the LNG facility and $.4 million for USTs not yet remediated.
As of October 31, 2010, our regulatory assets for unamortized environmental costs totaled $8
million. We have not sought recovery of these amounts in our rates. However, we will seek
recovery in future rate proceedings.
In July 2005, we were notified by the NCDENR that we were named as a potentially responsible
party for alleged environmental issues associated with an UST site in Clemmons, North Carolina. We
owned and operated this site from March 1986 until June 1988 in connection with a non-utility
venture. There have been at least four owners of the site. We contractually transferred any
clean-up costs to the new owner of the site when we sold this venture in June 1988. Our current
estimate of the cost to remediate the site is approximately $139,000. It is unclear how many of
the former owners may ultimately be held liable for this site; however, based on the uncertainty of
the ultimate liability, we established a non-regulated environmental liability for $34,700,
one-fourth of the estimated cost.
One of our operating districts has coatings containing asbestos on some of their pipelines.
We have educated our employees on the hazards of asbestos and implemented procedures for removing
these coatings from our pipelines when we must excavate and expose small portions of the pipeline.
Lead-based paint is being removed at multiple LNG facilities that we own. Employees have been
trained on the hazards of lead exposure, and we have engaged independent environmental contractors
to remove and dispose of the lead-based paint at these facilities.
Further evaluation of the MGP sites, the UST sites and removal of lead-based paint could
significantly affect recorded amounts; however, we believe that the ultimate resolution of these
matters will not have a material adverse effect on our financial position, results of operations or
cash flows.
89
8. Employee Benefit Plans
Effective January 1, 2008, we amended our noncontributory defined benefit pension plan, other
postretirement employee benefits (OPEB) plan and our 401(k) plans. These amendments applied to
nonunion employees and employees covered by the Carolinas bargaining unit contract. Effective
January 1, 2009, these same amendments applied to all employees, including those covered by the
Nashville, Tennessee bargaining unit contract.
Pension Benefits
We have a noncontributory, tax-qualified defined benefit pension plan (qualified pension plan)
for our eligible employees. A defined benefit plan specifies the amount of benefit that an
eligible participant eventually will receive upon retirement using information about that
participant. An employee became eligible on the January 1 or July 1 following either the date on
which he or she attained age 30 or attained age 21 and completed 1,000 hours of service during the
12-month period commencing on the employment date. Plan benefits are generally based on credited
years of service and the level of compensation during the five consecutive years of the last ten
years prior to retirement or termination during which the participant received the highest
compensation. Our policy is to fund the plan in an amount not in excess of the amount that is
deductible for income tax purposes. Effective January 1, 2008, the qualified pension plan was
amended for all employees not covered by the bargaining unit contract in Nashville, Tennessee to
close the plan to employees hired after December 31, 2007 and to modify how benefits are accrued in
the future for existing employees. Employees hired prior to January 1, 2008 continue to
participate in the amended traditional qualified pension plan. Employees are vested after five
years of service and can be credited with up to a total of 35 years of service. When a vested
employee leaves the company, his benefit payment will be calculated as the greater of the accrued
benefit as of December 31, 2007 under the old formula plus the accrued benefit under the new
formula for years of service after December 31, 2007, or the benefit for all years of service up to
35 years under the new formula. These amendments were effective on January 1, 2009 for employees
covered by the bargaining unit contract in Nashville, Tennessee.
The investment objectives of the qualified pension plan are oriented to meet both the current
ongoing and future commitments to the participants and designed to grow at an acceptable rate of
return for the risks permitted under the investment policy guidelines. Assets are structured to
provide for both short-term and long-term needs and to meet the objectives of the qualified pension
plan as overseen by the Benefits Committee of the Board of Directors.
Our primary investment objective of the qualified pension plan is to generate sufficient
assets to meet plan liabilities. The plan’s assets will therefore be invested to maximize
long-term returns in a manner that is consistent with the plan’s liabilities, cash flow
requirements and risk tolerance. The plan’s liabilities are defined in terms of participant
salaries. Given the nature of these liabilities and recognizing the long-term benefits of
investing in return-generating assets, the qualified pension plan seeks to invest in a diversified
portfolio to:
|
|
•
|
|
Achieve full funding over the longer term, and
|
|
|
|
|
•
|
|
Control year-to-year fluctuations in pension expense that is created by asset and
liability volatility.
|
90
We consider the historical long-term return experience of our assets, the current and targeted
allocation of our plan assets and the expected long-term rates of return. Investment advisors
assist us in deriving expected long-term rates of return. These rates are generally based on a
20-year horizon for various asset classes, our expected investments of plan assets and active asset
management instead of a passive investment strategy of an index fund. In June 2009, the Benefits
Committee of the Board of Directors approved a new asset allocation of our portfolio that includes
additional asset classes, such as hedge fund of funds, private equity fund of funds, high yield
bonds, global real estate and commodities. The intent of this new allocation was to provide
further diversification and reduce volatility of plan assets.
The investment philosophy of the qualified pension plan is to maintain a balanced portfolio
which is diversified across asset classes. The portfolio is primarily composed of equity and fixed
income investments in order to provide diversification as to issuers, economic sectors, markets and
investment instruments. Risk and quality are viewed in the context of the diversification
requirements of the aggregate portfolio. We measure and monitor investment risk on an ongoing
basis through quarterly investment portfolio reviews, annual liability measurements and periodic
asset/liability studies. We do not have a concentration of assets in a single entity, industry,
country, commodity or class of investment fund.
The qualified pension plan maintains a 45% target allocation to fixed income securities,
including U.S. treasuries, corporate bonds, high yield bonds, asset-backed securities and
derivatives. The derivatives must be fully collateralized so that they either hedge an existing
position or there is a cash position for an equivalent value of the underlying principal. No
leveraged position can be taken with derivatives, and the aggregate risk exposure of the plan can
be no greater than that which could be achieved without using derivatives. The qualified pension
plan maintains a 35% target allocation to equities, including exposure to large cap growth, large
cap value and small cap domestic equity securities, as well as exposure to international equity.
There is a 5% target allocation to real estate in a diversified global real estate investment trust
(REIT) fund. The remaining 15% target allocation is for investments in other types of funds,
including commodities, hedge funds and private equity funds that follow several diversified
strategies.
Employees hired or rehired after December 31, 2007 (or December 31, 2008 for employees covered
by the bargaining unit contract in Nashville, Tennessee) cannot participate in the amended
traditional pension plan but are participants in the new Money Purchase Pension (MPP) plan, a
defined contribution pension plan that allows the employee to direct the investments and assume the
risk of investment returns. A defined contribution plan specifies the amount of the employer’s
annual contribution to individual participant accounts established for the retirement benefit.
Eligible employees who have completed 30 days of continuous service and have attained age 18 are
eligible to participate. Under the MPP plan, we annually deposit a percentage of each
participant’s pay into an account of the MPP plan. This contribution equals 4% of the
participant’s compensation plus an additional 4% of compensation above the social security wage
base. The participant is vested in this plan after three years of service. During the year ended
October 31, 2010, we contributed $.2 million to the MPP plan.
91
OPEB Plan
We provide certain postretirement health care and life insurance benefits to eligible
retirees. The liability associated with such benefits is funded in irrevocable trust funds that
can only be used to pay the benefits. Employees are first eligible to retire and receive these
benefits at age 55 with ten or more years of service after the age of 45. Employees who met this
requirement in 1993 or who retired prior to 1993 are in a “grandfathered” group for whom we pay the
full cost of the retiree’s coverage. Retirees not in the grandfathered group have 80% of the cost
of retiree coverage paid by us, subject to certain annual contribution limits. Retirees are
responsible for the full cost of dependent coverage. Effective January 1, 2008 (January 1, 2009
for new employees covered under the bargaining unit contract in Nashville, Tennessee), new
employees have to complete ten years of service after age 50 to be eligible for benefits, and no
benefits are provided to those employees after age 65 when they are automatically eligible for
Medicare benefits to cover health costs. Our OPEB plan includes a defined dollar benefit to pay
the premiums for Medicare Part D. Employees who meet the eligibility requirements to retire also
receive a life insurance benefit. For employees who retire after July 1, 2005, this benefit is
$15,000. The life insurance amount for employees who retired prior to this date was calculated as
a percentage of their basic life insurance prior to retirement.
OPEB plan assets are comprised of mutual funds within a 401(h) and Voluntary Employees’
Beneficiary Association trusts. The investment philosophy is the same as the qualified pension
plan as discussed above. We target an OPEB allocation of 45% to fixed income securities, including
U.S. treasuries, corporate bonds, high yield bonds and asset-backed securities. The OPEB plan
maintains a 47% target allocation to equities, which includes exposure to large cap growth, large
cap value and small cap domestic equity, as well as exposure to international equity. The OPEB
plan maintains a 5% target allocation to real estate in a diversified global REIT fund and a 3%
target allocation to cash. We do not have a concentration of assets in a single entity, industry,
country, commodity or class of investment fund.
Supplemental Executive Retirement Plans
We have pension liabilities related to supplemental executive retirement plans (SERPs) for
certain former employees, non-employee directors or the surviving spouse. There are no assets
related to the SERPs, and no additional benefits accrue to the participants. Payments to the
participants are made from operating funds during the year. These nonqualified plans are presented
below.
We previously had a SERP covering all officers at the vice president level and above. It
provided supplemental retirement income as well as a life insurance benefit for officers to
indirectly address the tax code limitations on qualified retirement plans. The level of insurance
benefit and target retirement income benefits intended to be provided under the SERP depended upon
the position of the officer. The SERP was funded by life insurance policies covering each officer,
and the policy was owned exclusively by each officer.
On September 4, 2008, the Compensation Committee of our Board of Directors terminated the
former SERP effective October 31, 2008 and replaced the supplemental retirement benefit with a
non-qualified defined contribution restoration plan (DCR plan), effective January 1, 2009.
Benefits payable under the new plan are informally funded through a rabbi trust with a bank as the
92
trustee. We contribute 13% of the total cash compensation that exceeds the Internal Revenue
Service compensation limit to the DCR plan account of each executive. An additional one-time
contribution was made for all eligible officers in January 2009 equal to the greater of:
|
|
•
|
|
13% of base salary paid in November 2008 and December 2008 (to the extent that calendar
year-to-date base salary exceeded the 2008 annual limit), or
|
|
|
|
|
•
|
|
Two monthly premiums (without adjustment for taxes) under the former SERP.
|
In addition, an opening balance that totaled $.3 million was established for four Vice
Presidents to compensate them for the loss of future benefits under the new plan. Participants may
not contribute to the DCR plan. Vesting under the DCR plan is five-year cliff vesting, including
service prior to adoption, of annual company contributions, and prospective five-year cliff vesting
for the opening balances of the four Vice Presidents. If the officer severs employment before the
expiration of the relevant five-year period, he or she receives nothing from that portion of the
DCR plan. Participants in the DCR plan may provide instructions to us for the deemed investment of
their plan accounts. Distribution will occur upon separation of service or death of the
participant. The insurance portion of the SERP benefit has been maintained in the form of new term
life insurance as discussed below.
Also on September 4, 2008, the Compensation Committee of our Board of Directors approved a
voluntary deferred compensation plan, effective January 1, 2009, for the benefit of all officers
and director-level employees. Benefits under this plan, known as the Voluntary Deferral Plan, are
also informally funded through a rabbi trust with a bank as the trustee. There are no company
contributions to the Voluntary Deferral Plan. Participants may defer up to 50% of base salary with
elections made by December 31 prior to the upcoming calendar year, and up to 95% of annual
incentive pay with elections made by April 30. Vesting is immediate and deferrals are held in the
rabbi trust. Participants may provide instructions to us for the deemed investment of their plan
accounts. Distributions can be made from the Voluntary Deferral Plan on a specified date that is
at least two years from the date of deferral, on separation of service or upon death.
The funding to the DCR plan accounts for the years ended October 31, 2010 and 2009, and the
amounts recorded as liabilities for these deferred compensation plans as of October 31, 2010 and
2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Funding
|
|
$
|
444
|
|
|
$
|
356
|
|
|
Liability:
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
5
|
|
|
|
—
|
|
|
Noncurrent
|
|
|
1,293
|
|
|
|
717
|
|
We provide term life insurance policies for officers at the vice president level and above who
were participants in the former SERP that terminated on October 31, 2008; the level of the
insurance benefit is dependent upon the position of the officer. These life insurance policies are
owned exclusively by each officer. Premiums on these policies are paid and expensed, as grossed up
for taxes to the individual officer. Beginning on December 1, 2008, we provide a term life
insurance benefit equal to $200,000 to all officers and director-level employees for which we bear
the cost of the policies. The cost of these premiums is presented below.
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Vice president and above term life policies
|
|
$
|
57
|
|
|
$
|
59
|
|
|
$
|
—
|
|
|
SERP premiums (benefit superseded)
|
|
|
—
|
|
|
|
—
|
|
|
|
446
|
|
|
Officers, director-level employees and regional
executives
|
|
|
24
|
|
|
|
20
|
|
|
|
—
|
|
Actuarial Plan Information
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the
years ended October 31, 2010 and 2009, and a statement of the funded status and the amounts
reflected in the consolidated balance sheets for the years ended October 31, 2010 and 2009 are
presented below.
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
Nonqualified Pension
|
|
|
Other Benefits
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Accumulated benefit obligation at year end
|
|
$
|
182,822
|
|
|
$
|
173,352
|
|
|
$
|
5,039
|
|
|
$
|
4,828
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation at beginning of year
|
|
$
|
195,329
|
|
|
$
|
143,460
|
|
|
$
|
4,828
|
|
|
$
|
4,194
|
|
|
$
|
35,523
|
|
|
$
|
28,112
|
|
|
Service cost
|
|
|
8,069
|
|
|
|
5,733
|
|
|
|
38
|
|
|
|
25
|
|
|
|
1,337
|
|
|
|
885
|
|
|
Interest cost
|
|
|
10,898
|
|
|
|
11,240
|
|
|
|
243
|
|
|
|
325
|
|
|
|
1,906
|
|
|
|
2,267
|
|
|
Actuarial (gain) loss
|
|
|
7,549
|
|
|
|
45,669
|
|
|
|
420
|
|
|
|
920
|
|
|
|
(3,769
|
)
|
|
|
7,506
|
|
|
Settlement gain
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(126
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Administrative expenses
|
|
|
(306
|
)
|
|
|
(233
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Benefit payments
|
|
|
(10,536
|
)
|
|
|
(10,540
|
)
|
|
|
(490
|
)
|
|
|
(510
|
)
|
|
|
(3,078
|
)
|
|
|
(3,247
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation at end of year
|
|
$
|
211,003
|
|
|
$
|
195,329
|
|
|
$
|
5,039
|
|
|
$
|
4,828
|
|
|
$
|
31,919
|
|
|
$
|
35,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at beginning of year
|
|
$
|
184,277
|
|
|
$
|
150,257
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
19,278
|
|
|
$
|
15,522
|
|
|
Actual return on plan assets
|
|
|
32,910
|
|
|
|
22,793
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,841
|
|
|
|
2,146
|
|
|
Employer contributions
|
|
|
22,000
|
|
|
|
22,000
|
|
|
|
490
|
|
|
|
510
|
|
|
|
2,595
|
|
|
|
4,857
|
|
|
Administrative expenses
|
|
|
(306
|
)
|
|
|
(233
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Benefit payments
|
|
|
(10,536
|
)
|
|
|
(10,540
|
)
|
|
|
(490
|
)
|
|
|
(510
|
)
|
|
|
(3,078
|
)
|
|
|
(3,247
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at end of year
|
|
$
|
228,345
|
|
|
$
|
184,277
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
21,636
|
|
|
$
|
19,278
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
$
|
17,342
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Current liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
(517
|
)
|
|
|
(484
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Noncurrent liabilities
|
|
|
—
|
|
|
|
(11,052
|
)
|
|
|
(4,522
|
)
|
|
|
(4,344
|
)
|
|
|
(10,283
|
)
|
|
|
(16,245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
17,342
|
|
|
$
|
(11,052
|
)
|
|
$
|
(5,039
|
)
|
|
$
|
(4,828
|
)
|
|
$
|
(10,283
|
)
|
|
$
|
(16,245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Not Yet Recognized as a Component
of Cost and Recognized as Regulatory Asset
or Liability (1):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized transition obligation
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(2,001
|
)
|
|
$
|
(2,668
|
)
|
|
Unrecognized prior service (cost) credit
|
|
|
23,836
|
|
|
|
26,033
|
|
|
|
(88
|
)
|
|
|
(107
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Unrecognized actuarial loss
|
|
|
(85,661
|
)
|
|
|
(94,247
|
)
|
|
|
(852
|
)
|
|
|
(442
|
)
|
|
|
(9
|
)
|
|
|
(5,474
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory asset
|
|
|
(61,825
|
)
|
|
|
(68,214
|
)
|
|
|
(940
|
)
|
|
|
(549
|
)
|
|
|
(2,010
|
)
|
|
|
(8,142
|
)
|
|
Cumulative employer contribution in
excess of cost
|
|
|
79,167
|
|
|
|
57,162
|
|
|
|
(4,099
|
)
|
|
|
(4,279
|
)
|
|
|
(8,273
|
)
|
|
|
(8,103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net amount recognized
|
|
$
|
17,342
|
|
|
$
|
(11,052
|
)
|
|
$
|
(5,039
|
)
|
|
$
|
(4,828
|
)
|
|
$
|
(10,283
|
)
|
|
$
|
(16,245
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
As the future recovery of pension and OPEB costs is probable, we were granted permission to
record the amount that would have been recorded in accumulated OCI as a regulatory asset or
liability.
|
Net periodic benefit cost for the years ended October 31, 2010, 2009 and 2008 includes
the following components.
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
|
|
|
|
|
|
|
|
Nonqualified Pension
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Service cost
|
|
$
|
8,069
|
|
|
$
|
5,733
|
|
|
$
|
7,634
|
|
|
$
|
38
|
|
|
$
|
25
|
|
|
$
|
27
|
|
|
$
|
1,337
|
|
|
$
|
885
|
|
|
$
|
1,250
|
|
|
Interest cost
|
|
|
10,898
|
|
|
|
11,240
|
|
|
|
11,408
|
|
|
|
243
|
|
|
|
325
|
|
|
|
277
|
|
|
|
1,906
|
|
|
|
2,267
|
|
|
|
2,011
|
|
|
Expected return on plan
assets
|
|
|
(18,773
|
)
|
|
|
(16,755
|
)
|
|
|
(16,895
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,381
|
)
|
|
|
(1,104
|
)
|
|
|
(1,461
|
)
|
|
Amortization of
transition
obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
667
|
|
|
|
667
|
|
|
|
667
|
|
|
Amortization of prior
service (cost) credit
|
|
|
(2,198
|
)
|
|
|
(2,198
|
)
|
|
|
(1,893
|
)
|
|
|
20
|
|
|
|
20
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Amortization of actuarial
loss (gain)
|
|
|
1,998
|
|
|
|
—
|
|
|
|
—
|
|
|
|
9
|
|
|
|
(20
|
)
|
|
|
—
|
|
|
|
236
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit
(income) cost
|
|
|
(6
|
)
|
|
|
(1,980
|
)
|
|
|
254
|
|
|
|
310
|
|
|
|
350
|
|
|
|
304
|
|
|
|
2,765
|
|
|
|
2,715
|
|
|
|
2,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other changes in plan
assets and benefit
obligation recognized
through regulatory asset
or liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost
(credit)
|
|
|
—
|
|
|
|
—
|
|
|
|
(4,133
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
127
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Net (gain) loss
|
|
|
(6,587
|
)
|
|
|
39,631
|
|
|
|
42,446
|
|
|
|
420
|
|
|
|
923
|
|
|
|
(532
|
)
|
|
|
(5,229
|
)
|
|
|
6,464
|
|
|
|
1,237
|
|
|
Amounts recognized as a
component of net
periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transition obligation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(667
|
)
|
|
|
(667
|
)
|
|
|
(667
|
)
|
|
Amortization of net
(loss)
gain
|
|
|
(1,998
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(9
|
)
|
|
|
20
|
|
|
|
—
|
|
|
|
(236
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Prior service (cost)
credit
|
|
|
2,198
|
|
|
|
2,198
|
|
|
|
1,893
|
|
|
|
(20
|
)
|
|
|
(20
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in
regulatory asset
(liability)
|
|
|
(6,387
|
)
|
|
|
41,829
|
|
|
|
40,206
|
|
|
|
391
|
|
|
|
923
|
|
|
|
(405
|
)
|
|
|
(6,132
|
)
|
|
|
5,797
|
|
|
|
570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in net
periodic benefit cost
and
regulatory asset
(liability)
|
|
$
|
(6,393
|
)
|
|
$
|
39,849
|
|
|
$
|
40,460
|
|
|
$
|
701
|
|
|
$
|
1,273
|
|
|
$
|
(101
|
)
|
|
$
|
(3,367
|
)
|
|
$
|
8,512
|
|
|
$
|
3,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 2011 estimated amortization of the following items is recorded as a regulatory asset
or liability instead of accumulated OCI discussed above and expected refunds for our plans are as
follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Qualified Pension
|
|
|
Nonqualified Pension
|
|
|
Other Benefits
|
|
|
Amortization of transition obligation
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
667
|
|
|
Amortization of unrecognized prior service
(cost) credit
|
|
|
(2,198
|
)
|
|
|
20
|
|
|
|
—
|
|
|
Amortization of unrecognized actuarial loss
|
|
|
3,113
|
|
|
|
41
|
|
|
|
—
|
|
|
Refunds expected
|
|
|
915
|
|
|
|
61
|
|
|
|
667
|
|
In addition, equity market performance has a significant effect on our market-related
value of plan assets. In determining the market-related value of plan assets, we use the following
methodology: The asset gain or loss is determined each year by comparing the fund’s actual return
to the expected return, based on the disclosed expected return on investment assumption. Such
asset gain or loss is then recognized ratably over a five-year period. Thus, the market-related
value
96
of assets as of year end is determined by adjusting the market value of assets by the portion
of the prior five years’ gains or losses that has not yet been recognized. This method has been
applied consistently in all years presented in the consolidated financial statements. The discount
rate can vary from plan year to plan year. October 31 is the measurement date for the plans.
The discount rate has been separately determined for each plan by projecting the plan’s
cash flows and developing a zero-coupon spot rate yield curve using non-arbitrage pricing and
Moody’s Investors Service’s AA or better-rated non-callable bonds that produces similar results to
a hypothetical bond portfolio. As of October 31, 2010, the benchmark by plan was as follows.
|
|
|
|
|
|
|
Pension plan
|
|
|
5.47
|
%
|
|
NCNG SERP
|
|
|
4.33
|
%
|
|
Directors’ SERP
|
|
|
4.61
|
%
|
|
Piedmont SERP
|
|
|
3.49
|
%
|
|
OPEB
|
|
|
4.85
|
%
|
We amortize unrecognized prior-service cost over the average remaining service period for
active employees. We amortize the unrecognized transition obligation over the average remaining
service period for active employees expected to receive benefits under the plan as of the date of
transition. We amortize gains and losses in excess of 10% of the greater of the benefit obligation
and the market-related value of assets over the average remaining service period for active
employees. The method of amortization in all cases is straight-line.
The weighted average assumptions used in the measurement of the benefit obligation as of
October 31, 2010 and 2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
Nonqualified Pension
|
|
|
Other Benefits
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
2010
|
|
|
2009
|
|
|
Discount rate
|
|
|
5.47
|
%
|
|
|
5.99
|
%
|
|
|
4.37
|
%
|
|
|
5.28
|
%
|
|
|
4.85
|
%
|
|
|
5.58
|
%
|
|
Rate of compensation increase
|
|
|
3.87
|
%
|
|
|
3.92
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
The weighted average assumptions used to determine the net periodic benefit cost as of
October 31, 2010, 2009 and 2008 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
Nonqualified Pension
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Discount rate
|
|
|
5.99
|
%
|
|
|
8.15
|
%
|
|
|
6.43
|
%
|
|
|
5.28
|
%
|
|
|
8.46
|
%
|
|
|
6.06
|
%
|
|
Expected long-term rate of return on plan assets
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
Rate of compensation increase
|
|
|
3.92
|
%
|
|
|
3.97
|
%
|
|
|
3.99
|
%
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Discount rate
|
|
|
5.58
|
%
|
|
|
8.50
|
%
|
|
|
6.25
|
%
|
|
Expected long-term rate of return on plan assets
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
Rate of compensation increase
|
|
|
N/A
|
|
|
|
N/A
|
|
|
|
N/A
|
|
97
In November 2010, we contributed $22 million to the qualified pension plan. We
anticipate that we will contribute the following amounts to our plans in 2011.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
Nonqualified pension plans
|
|
$
|
517
|
|
|
MPP plan
|
|
|
345
|
|
|
OPEB plan
|
|
|
1,400
|
|
The Pension Protection Act of 2006 (PPA) specified new funding requirements for single
employer defined benefit pension plans. The PPA established a 100% funding target for plan years
beginning after December 31, 2007, and we are in compliance.
Benefit payments, which reflect expected future service, as appropriate, are expected to be
paid for the next ten years ending October 31 as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified
|
|
|
Nonqualified
|
|
|
Other
|
|
|
In thousands
|
|
Pension
|
|
|
Pension
|
|
|
Benefits
|
|
|
2011
|
|
$
|
19,122
|
|
|
$
|
517
|
|
|
$
|
2,193
|
|
|
2012
|
|
|
12,122
|
|
|
|
489
|
|
|
|
2,185
|
|
|
2013
|
|
|
13,289
|
|
|
|
486
|
|
|
|
2,210
|
|
|
2014
|
|
|
12,550
|
|
|
|
454
|
|
|
|
2,422
|
|
|
2015
|
|
|
13,613
|
|
|
|
453
|
|
|
|
2,524
|
|
|
2016 - 2020
|
|
|
82,692
|
|
|
|
1,934
|
|
|
|
13,978
|
|
The assumed health care cost trend rates used in measuring the accumulated OPEB
obligation for the medical plans for all participants as of October 31, 2010 and 2009 are presented
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
Health care cost trend rate assumed for next year
|
|
|
7.80
|
%
|
|
|
8.00
|
%
|
|
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
|
|
|
5.00
|
%
|
|
|
5.00
|
%
|
|
Year that the rate reaches the ultimate trend rate
|
|
|
2027
|
|
|
|
2027
|
|
The health care cost trend rate assumptions could have a significant effect on the
amounts reported. A change of 1% would have the following effects.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
1% Increase
|
|
1% Decrease
|
|
|
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost for the year ended October 31, 2010
|
|
$
|
57
|
|
|
$
|
(55
|
)
|
|
Effect on the health care cost component of the accumulated postretirement
benefit obligation as of October 31, 2010
|
|
|
732
|
|
|
|
(723
|
)
|
98
Fair Value Measurements
The qualified pension plan’s asset allocations by level within the fair value hierarchy at
October 31, 2010 are presented below. The plan’s assets were accounted for at fair value and are
classified in their entirety based on the lowest level of input that is significant to the fair
value
measurement. Our assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of fair value assets and their placement
within the fair value hierarchy levels. For further information on a description of the fair value
hierarchy, see Note 1.F. to the consolidated financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension Plan
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Total
|
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Carrying
|
|
|
% of
|
|
|
In thousands
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
Total
|
|
|
Cash
|
|
$
|
1,969
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,969
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Income Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. treasuries
|
|
|
—
|
|
|
|
26,886
|
|
|
|
—
|
|
|
|
26,886
|
|
|
|
12
|
%
|
|
Long duration bonds (1)
|
|
|
60,393
|
|
|
|
—
|
|
|
|
—
|
|
|
|
60,393
|
|
|
|
26
|
%
|
|
Corporate bonds
|
|
|
—
|
|
|
|
13,063
|
|
|
|
—
|
|
|
|
13,063
|
|
|
|
6
|
%
|
|
High yield bonds (2)
|
|
|
11,509
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,509
|
|
|
|
5
|
%
|
|
Derivatives
|
|
|
(27
|
)
|
|
|
1,694
|
|
|
|
—
|
|
|
|
1,667
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities: (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large cap core index (4)
|
|
|
10,815
|
|
|
|
—
|
|
|
|
—
|
|
|
|
10,815
|
|
|
|
5
|
%
|
|
Large cap value
|
|
|
10,640
|
|
|
|
—
|
|
|
|
—
|
|
|
|
10,640
|
|
|
|
5
|
%
|
|
Large cap growth
|
|
|
12,601
|
|
|
|
—
|
|
|
|
—
|
|
|
|
12,601
|
|
|
|
5
|
%
|
|
Small cap
|
|
|
21,748
|
|
|
|
—
|
|
|
|
—
|
|
|
|
21,748
|
|
|
|
9
|
%
|
|
International value
|
|
|
17,170
|
|
|
|
—
|
|
|
|
—
|
|
|
|
17,170
|
|
|
|
7
|
%
|
|
International growth
|
|
|
17,243
|
|
|
|
—
|
|
|
|
—
|
|
|
|
17,243
|
|
|
|
8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real Estate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Global REIT
|
|
|
12,070
|
|
|
|
—
|
|
|
|
—
|
|
|
|
12,070
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hedge fund of funds (5)
|
|
|
—
|
|
|
|
4,795
|
|
|
|
5,196
|
|
|
|
9,991
|
|
|
|
5
|
%
|
|
Private equity fund of funds
(6)
|
|
|
—
|
|
|
|
—
|
|
|
|
580
|
|
|
|
580
|
|
|
|
—
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at fair value
|
|
$
|
176,131
|
|
|
$
|
46,438
|
|
|
$
|
5,776
|
|
|
$
|
228,345
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of fair value hierarchy
|
|
|
77
|
%
|
|
|
20
|
%
|
|
|
3
|
%
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
This category represents actively managed long duration fixed income funds.
|
|
|
|
(2)
|
|
This category represents actively managed high yield fixed income funds.
|
|
|
|
(3)
|
|
This category represents actively managed equity funds and separate accounts with diversified
investment strategies with the exception of the Large Cap Core Index Fund category.
|
|
|
|
(4)
|
|
This category represents low-cost equity index funds not actively managed that track the S&P
500 Index.
|
|
|
|
(5)
|
|
This category represents investments across a variety of markets through investment funds or
managed accounts that invest in equities, equity-related instruments, fixed income and other
debt-related instruments.
|
|
|
|
(6)
|
|
This category represents exposure to a diversified private equity fund of funds investment.
The target allocation is 5% but is still being funded through capital calls. Until a 5% allocation
can be achieved, the balance of the 5% allocation is invested in a low-cost equity fund managed to
track the S&P 500 index.
|
99
The following is a reconciliation of the assets in the qualified pension plan that are
classified as Level 3 in the fair value hierarchy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Private
|
|
|
|
|
|
|
|
Hedge Fund
|
|
|
Equity Fund
|
|
|
|
|
|
In thousands
|
|
of Funds
|
|
|
of Funds
|
|
|
Total
|
|
|
Beginning balance at October 31, 2009
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Actual return on plan assets:
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Relating to assets still held at the reporting date
|
|
|
307
|
|
|
|
(4
|
)
|
|
|
303
|
|
|
Relating to assets sold during the period
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Purchases, sales and settlements (net)
|
|
|
4,889
|
|
|
|
584
|
|
|
|
5,473
|
|
|
Transfer in/out of Level 3
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance at October 31, 2010
|
|
$
|
5,196
|
|
|
$
|
580
|
|
|
$
|
5,776
|
|
|
|
|
|
|
|
|
|
|
|
|
The OPEB plan’s asset allocations by level within the fair value hierarchy at October 31,
2010 are presented below. The plan’s assets were accounted for at fair value and are classified in
their entirety based on the lowest level of input that is significant to the fair value
measurement. Our assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of fair value assets and their placement
within the fair value hierarchy levels. For further information on a description of the fair value
hierarchy, see Note 1.F. to the consolidated financial statements.
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits (1)
|
|
|
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quoted Prices
|
|
|
Other
|
|
|
Significant
|
|
|
|
|
|
|
|
|
|
|
in Active
|
|
|
Observable
|
|
|
Unobservable
|
|
|
Total
|
|
|
|
|
|
|
|
Markets
|
|
|
Inputs
|
|
|
Inputs
|
|
|
Carrying
|
|
|
% of
|
|
|
In thousands
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Value
|
|
|
Total
|
|
|
Cash
|
|
$
|
526
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
526
|
|
|
|
3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Income Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. treasuries
|
|
|
2,164
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,164
|
|
|
|
10
|
%
|
|
Corporate bonds (2) / Asset-backed
securities
|
|
|
7,603
|
|
|
|
—
|
|
|
|
—
|
|
|
|
7,603
|
|
|
|
35
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
47
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Large cap value
|
|
|
1,131
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,131
|
|
|
|
5
|
%
|
|
Large cap growth
|
|
|
1,152
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,152
|
|
|
|
5
|
%
|
|
Small cap value
|
|
|
1,158
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,158
|
|
|
|
5
|
%
|
|
Small cap growth
|
|
|
1,162
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,162
|
|
|
|
5
|
%
|
|
Large cap index
|
|
|
2,019
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,019
|
|
|
|
10
|
%
|
|
International blend
|
|
|
3,650
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3,650
|
|
|
|
17
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Real Estate:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Global REIT
|
|
|
1,071
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,071
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets at fair value
|
|
$
|
21,636
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
21,636
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percent of fair value hierarchy
|
|
|
100
|
%
|
|
|
—
|
|
|
|
—
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The plan assets are invested in mutual funds.
|
|
|
|
(2)
|
|
This category represents primarily investment grade corporate securities even though the plan
maintains a 5% allocation to a high yield bond fund.
|
401(k) Plan
We maintain a 401(k) plan that is a profit-sharing plan under Section 401(a) of the Internal
Revenue Code of 1986, as amended (the Tax Code), which includes qualified cash or deferred
arrangements under Tax Code Section 401(k). The 401(k) plan is subject to the provisions of the
Employee Retirement Income Security Act. Eligible employees who have completed 30 days of
continuous service and have attained age 18 are eligible to participate. Participants may defer a
portion of their base salary and cash incentive payments to the plan, and we match a portion of
their contributions. Employee contributions vest immediately, and company contributions vest after
six months of service.
Effective January 1, 2008, we made changes to our 401(k) plan. Prior to January 1, 2008, we
matched 50% of employee contributions up to the first 10% of pay contributed. Beginning January 1,
2008 (January 1, 2009 for employees covered under the bargaining unit contract in Nashville,
Tennessee), employees receive a company match of 100% up to the first 5% of eligible pay
contributed. Employees may contribute up to 50% of eligible pay to the 401(k) on a pre-tax basis,
up to the Tax Code annual contribution limit. We automatically enroll all affected
non-participating employees in the 401(k) plan at a 2% contribution rate unless the employee
chooses not to participate by notifying our record keeper. For employees who are automatically
enrolled
in the 401(k) plan, we automatically increase their contributions by 1% each year to a maximum
of 5% unless the employee chooses to opt out of the automatic increase by contacting our record
101
keeper. If the employee does not make an investment election, employee contributions and
matches are automatically invested in a diversified portfolio of stocks and bonds. Participants
may invest in Piedmont stock up to a maximum of 20% of their account. Employees may change their
contribution rate and investments at any time. For the years ended October 31, 2010, 2009 and
2008, we made matching contributions to participant accounts as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
401(k) matching contributions
|
|
$
|
5,269
|
|
|
$
|
4,698
|
|
|
$
|
4,252
|
|
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock
ownership plan (ESOP) were transferred into our 401(k) plans. Former ESOP participants may remain
invested in Piedmont common stock in their 401(k) plan or may sell the common stock at any time and
reinvest the proceeds in other available investment options. The tax benefit of any dividends paid
on ESOP shares still in participants’ accounts is reflected in the consolidated statements of
stockholders’ equity as an increase in retained earnings.
9. Employee Share-Based Plans
Under Board of Directors approved incentive compensation plans, eligible officers and other
participants are awarded units that pay out depending upon the level of performance achieved by
Piedmont during three-year performance periods. Distribution of those awards may be made in the
form of shares of common stock and withholdings for payment of applicable taxes on the
compensation. These plans require that a minimum threshold performance level be achieved in order
for any award to be distributed. For the years ended October 31, 2010, 2009 and 2008, we recorded
compensation expense, and as of October 31, 2010 and 2009, we have accrued amounts for these awards
based on the fair market value of our stock at the end of each quarter. The liability is
re-measured to market value at the settlement date.
We have three awards under approved incentive compensation plans with three-year performance
periods ending October 31, 2010, October 31, 2011 and October 31, 2012. Fifty percent of the units
awarded will be based on achievement of a target annual compounded increase in basic EPS. For this
50% portion, an EPS performance of 80% of target will result in an 80% payout, an EPS performance
of 100% of target will result in a 100% payout and an EPS performance of 120% of target will result
in a maximum 120% payout, and EPS performance levels between these levels will be subject to
mathematical interpolation. EPS performance below 80% of target will result in no payout of this
portion. The other 50% of the units awarded will be based on the achievement of total annual
shareholder return (increase in our common stock price plus dividends reinvested over the specified
period of time) in comparison to a peer group consisting of natural gas distribution companies.
The total shareholder return performance measure will be our percentile ranking in relationship to
the peer group. For this 50% portion, a ranking below the 25th percentile will result in no
payout, a ranking between the 25th and 39th percentile will result in an 80% payout, a ranking
between the 40th and 49th percentile will result in a 90% payout, a ranking between the 50th and
74th percentile will result in a 100% payout, a ranking between the 75th and 89th percentile will
result in a 110% payout, and a ranking at or above the 90th percentile will result in a maximum
120% payout.
102
Also under our approved incentive compensation plan, 65,000 unvested shares of our common
stock were granted to our President and Chief Executive Officer in September 2006. During the
five-year vesting period, any dividends paid on these shares are accrued and converted into
additional shares at the closing price on the date of the dividend payment. In accordance with the
vesting schedule, 20% and 30% of the shares vested on September 1, 2009 and 2010, respectively.
The remaining 50% of the shares will vest on September 1, 2011.
The compensation expense related to the incentive compensation plans for the years ended
October 31, 2010, 2009 and 2008, and the amounts recorded as liabilities as of October 31, 2010 and
2009 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Compensation expense
|
|
$
|
6,118
|
|
|
$
|
2,487
|
|
|
$
|
7,027
|
|
|
Tax benefit
|
|
|
1,756
|
|
|
|
207
|
|
|
|
1,555
|
|
|
Liability
|
|
|
9,914
|
|
|
|
8,173
|
|
|
|
|
|
Based on current accrual assumptions, the expected payout for the approved incentive
compensation plans ending October 31, 2010, 2011 and 2012 will occur in the following fiscal years.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
Amount of payout
|
|
$
|
7,094
|
|
|
$
|
1,594
|
|
|
$
|
1,227
|
|
On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for
the issuance as an equity transaction. The exercise price is calculated as 95% of the fair market
value on the purchase date of each quarter where fair market value is determined by calculating the
mean average of the high and low trading prices on the purchase date.
As discussed in Note 5 to the consolidated financial statements, we repurchase shares on the
open market and such shares are then cancelled and become authorized but unissued shares.
Currently, it is our policy to issue new shares for share-based awards. Shares of common stock to
be issued under approved incentive compensation plans are contingently issuable shares and are
included in our calculation of fully diluted earnings per share.
103
10. Income Taxes
The components of income tax expense for the years ended October 31, 2010, 2009 and 2008 are
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
In thousands
|
|
Federal
|
|
|
State
|
|
|
Federal
|
|
|
State
|
|
|
Federal
|
|
|
State
|
|
|
Charged (Credited) to operating income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
18,133
|
|
|
$
|
3,928
|
|
|
$
|
(7,774
|
)
|
|
$
|
181
|
|
|
$
|
27,971
|
|
|
$
|
6,679
|
|
|
Deferred
|
|
|
33,432
|
|
|
|
6,866
|
|
|
|
65,828
|
|
|
|
12,047
|
|
|
|
24,285
|
|
|
|
4,237
|
|
|
Tax Credits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utilization
|
|
|
105
|
|
|
|
—
|
|
|
|
130
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Amortization
|
|
|
(382
|
)
|
|
|
—
|
|
|
|
(333
|
)
|
|
|
—
|
|
|
|
(358
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
51,288
|
|
|
|
10,794
|
|
|
|
57,851
|
|
|
|
12,228
|
|
|
|
51,898
|
|
|
|
10,916
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Charged (Credited) to other income
(expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
22,519
|
|
|
|
3,755
|
|
|
|
7,764
|
|
|
|
1,064
|
|
|
|
10,040
|
|
|
|
1,786
|
|
|
Deferred
|
|
|
2,963
|
|
|
|
557
|
|
|
|
2,492
|
|
|
|
483
|
|
|
|
(1,025
|
)
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
25,482
|
|
|
|
4,312
|
|
|
|
10,256
|
|
|
|
1,547
|
|
|
|
9,015
|
|
|
|
1,663
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
76,770
|
|
|
$
|
15,106
|
|
|
$
|
68,107
|
|
|
$
|
13,775
|
|
|
$
|
60,913
|
|
|
$
|
12,579
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of income tax expense at the federal statutory rate to recorded income
tax expense for the years ended October 31, 2010, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Federal taxes at 35%
|
|
$
|
81,841
|
|
|
$
|
71,647
|
|
|
$
|
64,225
|
|
|
State income taxes, net of federal benefit
|
|
|
9,819
|
|
|
|
8,954
|
|
|
|
8,176
|
|
|
Amortization of investment tax credits
|
|
|
(382
|
)
|
|
|
(333
|
)
|
|
|
(358
|
)
|
|
Other, net
|
|
|
598
|
|
|
|
1,614
|
|
|
|
1,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
91,876
|
|
|
$
|
81,882
|
|
|
$
|
73,492
|
|
|
|
|
|
|
|
|
|
|
|
|
As of October 31, 2010 and 2009, deferred income taxes consisted of the following
temporary differences.
104
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
|
Benefit of loss carryforwards
|
|
$
|
2,474
|
|
|
$
|
17,995
|
|
|
Employee benefits and compensation
|
|
|
13,082
|
|
|
|
17,233
|
|
|
Revenue requirement
|
|
|
10,530
|
|
|
|
7,647
|
|
|
Utility plant
|
|
|
9,183
|
|
|
|
9,197
|
|
|
Other
|
|
|
4,958
|
|
|
|
7,881
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
40,227
|
|
|
|
59,953
|
|
|
Valuation Allowance
|
|
|
(1,324
|
)
|
|
|
(1,400
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets, net
|
|
|
38,903
|
|
|
|
58,553
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
|
Utility plant
|
|
|
370,348
|
|
|
|
334,878
|
|
|
Revenues and cost of gas
|
|
|
14,976
|
|
|
|
40,043
|
|
|
Equity method investments
|
|
|
27,244
|
|
|
|
22,597
|
|
|
Deferred costs
|
|
|
46,387
|
|
|
|
49,279
|
|
|
Other
|
|
|
14,106
|
|
|
|
3,456
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
473,061
|
|
|
|
450,253
|
|
|
|
|
|
|
|
|
|
|
Net deferred income tax liabilities
|
|
$
|
434,158
|
|
|
$
|
391,700
|
|
|
|
|
|
|
|
|
|
As of October 31, 2010 and 2009, total net deferred income tax assets were net of a
valuation allowance to reduce amounts to the amounts that we believe will be more likely than not
realized. We and our wholly owned subsidiaries file a consolidated federal income tax return and
various state income tax returns. As of October 31, 2010 and 2009, we had federal net operating
loss carryforwards of $6.5 million and $45.6 million, respectively, which expire from 2023 through
2029. As of October 31, 2010 and 2009, we had state net operating loss carryforwards of $7.1
million and $58.2 million, respectively, which expire from 2018 through 2024. We may use the loss
carryforwards to offset taxable income. Of the loss carryforwards, $6.5 million are subject to an
annual limitation of $.3 million.
Our returns for the tax years ended October 31, 2006 through 2007 are currently under
examination by the Internal Revenue Service. We do not expect the audit to have a material effect
on our financial position, results of operations or cash flows. We are no longer subject to
federal income tax examinations for tax years ending before and including October 31, 2005, and
with few exceptions, state income tax examinations by tax authorities for years ended before and
including October 31, 2005.
A reconciliation of changes in the deferred tax valuation allowance for the years ended
October 31, 2010, 2009 and 2008 is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Balance at beginning of year
|
|
$
|
1,400
|
|
|
$
|
1,114
|
|
|
$
|
394
|
|
|
Charged (credited) to income tax expense
|
|
|
(76
|
)
|
|
|
286
|
|
|
|
720
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year
|
|
$
|
1,324
|
|
|
$
|
1,400
|
|
|
$
|
1,114
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the unrecognized tax benefits for the years ended October 31, 2010
and 2009 is presented below.
105
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
Balance, beginning of year
|
|
$
|
293
|
|
|
$
|
506
|
|
|
Decrease from settlements with taxing authorities
|
|
|
—
|
|
|
|
125
|
|
|
Decrease from expiration of statute of limitations
|
|
|
293
|
|
|
|
88
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year
|
|
$
|
—
|
|
|
$
|
293
|
|
|
|
|
|
|
|
|
|
The amount of unrecognized tax benefits at 2009 which would impact our effective income
tax rate, if recognized, was $.2 million.
We recognize accrued interest and penalties related to unrecognized tax benefits in operating
expenses in the consolidated statements of income, which is consistent with the recognition of
these items in prior reporting periods. We recorded immaterial amounts of interest related to
unrecognized tax benefits during the years ended October 31, 2010 and 2009.
11. Equity Method Investments
The consolidated financial statements include the accounts of wholly owned subsidiaries whose
investments in joint venture, energy-related businesses are accounted for under the equity method.
Our ownership interest in each entity is included in “Equity method investments in non-utility
activities” in the consolidated balance sheets. Earnings or losses from equity method investments
are included in “Income from equity method investments” in the consolidated statements of income.
As of October 31, 2010, there were no amounts that represented undistributed earnings of our
50% or less owned equity method investments in our retained earnings.
Cardinal Pipeline Company, L.L.C.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a
North Carolina limited liability company. The other members are subsidiaries of The Williams
Companies, Inc. and SCANA Corporation. Cardinal owns and operates an intrastate natural gas
pipeline in North Carolina and is regulated by the NCUC. Cardinal has firm service agreements with
local distribution companies for 100% of the firm transportation capacity on the pipeline, of which
Piedmont subscribes to approximately 37%. Cardinal is dependent on the Williams-Transco pipeline
system to deliver gas into its system for service to its customers. Cardinal’s long-term debt is
nonrecourse to the members and is secured by Cardinal’s assets and by each member’s equity
investment in Cardinal.
On October 22, 2009, we reached an agreement with Progress Energy Carolinas, Inc. to provide
natural gas delivery service to a power generation facility to be built at their Wayne County,
North Carolina site. To provide the additional delivery service, we have executed an agreement
with Cardinal, which was approved by the NCUC in May 2010, to expand our firm capacity requirement
by 149,000 dekatherms per day to serve Progress Energy Carolinas. This will require Cardinal to
spend as much as $53.1 million for a new compressor station and expanded meter stations in order to
increase the capacity of its system by up to 199,000 dekatherms per day of firm capacity. As an
equity venture partner of Cardinal, we will invest as much as $11.4 million in Cardinal’s system
expansion. The members’ capital will be replaced
106
with permanent financing with a target overall capital structure of 45-50% debt and 50-55%
equity after the project is placed into service, scheduled to be July 1, 2012. In addition,
Piedmont’s service subscription to Cardinal following the system expansion will increase from
approximately 37% to approximately 53%. The NCUC issued a formal certificate order for Progress
Energy Carolinas for their Wayne County generation project on October 1, 2009.
We have related party transactions as a transportation customer of Cardinal, and we record in
cost of gas the transportation costs charged by Cardinal. For each of the years ended October 31,
2010, 2009 and 2008, these transportation costs and the amounts we owed Cardinal as of October 31,
2010 and 2009 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Transportation costs
|
|
$
|
4,104
|
|
|
$
|
4,104
|
|
|
$
|
4,116
|
|
|
Trade accounts payable
|
|
|
349
|
|
|
|
349
|
|
|
|
|
|
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of
September 30, 2010 and 2009, and for the twelve months ended September 30, 2010, 2009 and 2008 is
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current assets
|
|
$
|
9,239
|
|
|
$
|
9,078
|
|
|
|
|
|
|
Non-current assets
|
|
|
75,508
|
|
|
|
78,089
|
|
|
|
|
|
|
Current liabilities
|
|
|
3,977
|
|
|
|
3,990
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
26,592
|
|
|
|
29,075
|
|
|
|
|
|
|
Revenues
|
|
|
13,633
|
|
|
|
13,633
|
|
|
$
|
13,670
|
|
|
Gross profit
|
|
|
13,633
|
|
|
|
13,633
|
|
|
|
13,670
|
|
|
Income before income taxes
|
|
|
6,375
|
|
|
|
6,893
|
|
|
|
7,050
|
|
Pine Needle LNG Company, L.L.C.
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C., (Pine Needle), a
North Carolina limited liability company. The other members are the Municipal Gas Authority of
Georgia and subsidiaries of The Williams Companies, Inc., SCANA Corporation and Hess Corporation.
Pine Needle owns an interstate LNG storage facility in North Carolina and is regulated by the FERC.
Pine Needle has firm service agreements for 100% of the storage capacity of the facility, of which
Piedmont subscribes to approximately 64%.
Pine Needle enters into interest-rate swap agreements to modify the interest characteristics
of its long-term debt. Our share of movements in the market value of these agreements are recorded
as a hedge in “Accumulated other comprehensive loss” in the consolidated balance sheets. Pine
Needle’s long-term debt is nonrecourse to the members and is secured by Pine Needle’s assets and by
each member’s equity investment in Pine Needle.
107
We have related party transactions as a customer of Pine Needle, and we record in cost of
gas the storage costs charged by Pine Needle. For the years ended October 31, 2010, 2009 and
2008, these gas storage costs and the amounts we owed Pine Needle as of October 31, 2010 and 2009
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Gas storage costs
|
|
$
|
12,158
|
|
|
$
|
12,364
|
|
|
$
|
11,516
|
|
|
Trade accounts payable
|
|
|
985
|
|
|
|
1,081
|
|
|
|
|
|
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of
September 30, 2010 and 2009, and for the twelve months ended September 30, 2010, 2009 and 2008 is
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current assets
|
|
$
|
15,593
|
|
|
$
|
10,618
|
|
|
|
|
|
|
Non-current assets
|
|
|
78,863
|
|
|
|
78,452
|
|
|
|
|
|
|
Current liabilities
|
|
|
3,923
|
|
|
|
8,485
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
35,007
|
|
|
|
20,526
|
|
|
|
|
|
|
Revenues
|
|
|
18,808
|
|
|
|
18,744
|
|
|
$
|
18,694
|
|
|
Gross profit
|
|
|
18,808
|
|
|
|
18,744
|
|
|
|
18,694
|
|
|
Income before income taxes
|
|
|
8,317
|
|
|
|
8,381
|
|
|
|
8,227
|
|
SouthStar Energy Services LLC
We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a
Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a
wholly-owned subsidiary of AGL Resources, Inc. SouthStar primarily sells natural gas to
residential, commercial and industrial customers in the southeastern United States and Ohio with
most of its business being conducted in the unregulated retail gas market in Georgia. On January
1, 2010, we sold half of our 30% membership interest in SouthStar to GNGC and retained a 15%
earnings and membership share in SouthStar after the sale. At closing, we received $57.5 million
from GNGC resulting in an after-tax gain of $30.3 million, or $.42 per diluted share for 2010.
GNGC has no further rights to acquire our remaining 15% interest. We will continue to account for
our 15% membership interest in SouthStar using the equity method, as we retain board representation
with voting rights equal to GNGC on significant governance matters and policy decisions, and thus,
exercise significant influence over the operations of SouthStar.
SouthStar’s business is seasonal in nature as variations in weather conditions generally
result in greater revenue and earnings during the winter months when weather is colder and natural
gas consumption is higher. Also, because SouthStar is not a rate-regulated company, the timing of
its earnings can be affected by changes in the wholesale price of natural gas. While SouthStar
uses financial contracts to moderate the effect of price and weather changes on the timing of its
earnings, wholesale price and weather volatility can cause variations in the timing of the
recognition of earnings.
108
These financial contracts, in the form of futures, options and swaps, are considered to be
derivatives and fair value is based on selected market indices. Our share of movements in the
market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss”
in the consolidated balance sheets.
We have related party transactions as we sell wholesale gas supplies to SouthStar, and we
record in operating revenues the amounts billed to SouthStar. For the years ended October 31,
2010, 2009 and 2008, our operating revenues from these sales and the amounts SouthStar owed us as
of October 31, 2010 and 2009 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Operating revenues
|
|
$
|
5,083
|
|
|
$
|
8,226
|
|
|
$
|
14,624
|
|
|
Trade accounts receivable
|
|
|
713
|
|
|
|
639
|
|
|
|
|
|
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of
September 30, 2010 and 2009, and for the twelve months ended September 30, 2010, 2009 and 2008 is
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current assets
|
|
$
|
167,218
|
|
|
$
|
148,402
|
|
|
|
|
|
|
Non-current assets
|
|
|
9,382
|
|
|
|
9,454
|
|
|
|
|
|
|
Current liabilities
|
|
|
62,899
|
|
|
|
50,010
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
160
|
|
|
|
—
|
|
|
|
|
|
|
Revenues
|
|
|
843,483
|
|
|
|
854,455
|
|
|
$
|
941,123
|
|
|
Gross profit
|
|
|
183,748
|
|
|
|
169,639
|
|
|
|
143,534
|
|
|
Income before income taxes
|
|
|
107,096
|
|
|
|
98,308
|
|
|
|
73,224
|
|
Hardy Storage Company, LLC
Piedmont Hardy Storage Company, LLC, a wholly owned subsidiary of Piedmont, owns 50% of the
membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited
liability company. The other owner is a subsidiary of Columbia Gas Transmission Corporation, a
subsidiary of NiSource Inc. Hardy Storage owns and operates an underground interstate natural gas
storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the
FERC. Hardy Storage has firm service contracts with customers for 100% of its storage capacity of
the facility, of which Piedmont subscribes to approximately 40%.
On June 29, 2006, Hardy Storage signed a note purchase agreement for interim notes and a
revolving equity bridge facility for up to a total of $173.1 million for funding during the
construction period. On November 1, 2007, Hardy Storage paid off the equity line of $10.2 million
with member equity contributions, leaving an amount outstanding on the interim notes of $123.4
million.
109
The members of Hardy Storage each guaranteed 50% of the construction financing as well as a
separate guaranty of 50% of construction expenditures should contingency wells be required based on
the performance of the facility over the first three years after the in-service date. The Guaranty
of Principal and Residual Guaranty were executed by a wholly owned subsidiary of Piedmont, Piedmont
Energy Partners, Inc. (PEP). Our share of the guaranty was capped at $111.5 million and expired
upon the closing of permanent financing. Securing our guaranty was a pledge of intercompany notes
issued by Piedmont to its non-utility subsidiaries held under its wholly owned subsidiary. Also
pledged was our membership interest in Hardy Storage.
On March 17, 2010, Hardy Storage paid $3.6 million on the interim notes to enable completion
of its conversion of the interim notes to long-term project financing. The new long-term notes are
for $119.8 million due in 2023 at 5.88%. As a result of the conversion, our Guaranty of Principal
and Residual Guaranty, as executed in connection with the interim financing, terminated with no
payments having been made. The long-term project financing is non-recourse to the members of Hardy
Storage and their parent entities.
Prior to the long-term financing, we had recorded a liability of $1.2 million for the fair
value of the guaranty based on the present value of 50% of the construction financing outstanding
at the end of each quarter with the risk of the project evaluated at each quarter end, with a
corresponding increase to our investment account in the venture. Upon completion of the permanent
financing in March 2010, the liability was reversed, and our investment account was adjusted
accordingly to reflect the elimination of the guaranty.
The detail of the guaranty as of October 31, 2009 is as follows.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
Guaranty liability- PEP
|
|
$
|
1,234
|
|
|
Amount outstanding under the construction financing
- Hardy Storage
|
|
|
123,410
|
|
During 2010, we made no equity contributions to Hardy Storage and received distributions
totaling $12.9 million. As of October 31, 2010, we have made net equity contributions for the
project totaling $11.8 million.
We have related party transactions as a customer of Hardy Storage and record in cost of gas
the storage costs charged by Hardy Storage. For the years ended October 31, 2010, 2009 and 2008,
these gas storage costs and the amounts we owed Hardy Storage as of October 31, 2010 and 2009 are
as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Gas storage costs
|
|
$
|
9,386
|
|
|
$
|
9,340
|
|
|
$
|
9,219
|
|
|
Trade accounts
payable
|
|
|
808
|
|
|
|
781
|
|
|
|
|
|
110
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as
of October 31, 2010 and 2009, and for the twelve months ended October 31, 2010, 2009 and 2008 is
presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current assets
|
|
$
|
13,070
|
|
|
$
|
37,136
|
|
|
|
|
|
|
Non-current assets
|
|
|
170,693
|
|
|
|
166,663
|
|
|
|
|
|
|
Current liabilities
|
|
|
15,280
|
|
|
|
127,288
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
109,495
|
|
|
|
—
|
|
|
|
|
|
|
Revenues
|
|
|
23,562
|
|
|
|
23,465
|
|
|
$
|
23,658
|
|
|
Gross profit
|
|
|
23,562
|
|
|
|
23,465
|
|
|
|
23,658
|
|
|
Income before income taxes
|
|
|
8,249
|
|
|
|
8,155
|
|
|
|
9,297
|
|
12. Business Segments
We have two reportable business segments, regulated utility and non-utility activities. These
segments were identified based on products and services, regulatory environments and our current
corporate organization and business decision-making activities. Operations of our regulated
utility segment are conducted by the parent company. Operations of our non-utility activities
segment are comprised of our equity method investments in joint ventures.
Operations of the regulated utility segment are reflected in “Operating Income” in the
consolidated statements of income. Operations of the non-utility activities segment are included
in the consolidated statements of income in “Income from equity method investments” and
“Non-operating income.”
We evaluate the performance of the regulated utility segment based on margin, operations and
maintenance expenses and operating income. We evaluate the performance of the non-utility
activities segment based on earnings from the ventures. All of our operations are within the
United States. No single customer accounts for more than 10% of our consolidated revenues.
Operations by segment for the years ended October 31, 2010, 2009 and 2008, and as of October
31, 2010 and 2009 are presented below.
111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Regulated
|
|
|
Non-Utility
|
|
|
|
|
|
2010
|
|
Utility
|
|
|
Activities
|
|
|
Total
|
|
|
Revenues from external customers
|
|
$
|
1,552,295
|
|
|
$
|
—
|
|
|
$
|
1,552,295
|
|
|
Margin
|
|
|
552,592
|
|
|
|
—
|
|
|
|
552,592
|
|
|
Operations and maintenance expenses
|
|
|
219,829
|
|
|
|
301
|
|
|
|
220,130
|
|
|
Depreciation
|
|
|
98,494
|
|
|
|
29
|
|
|
|
98,523
|
|
|
Income from equity method investments
|
|
|
—
|
|
|
|
28,854
|
|
|
|
28,854
|
|
|
Gain on sale of interest in equity method
investment
|
|
|
—
|
|
|
|
49,674
|
|
|
|
49,674
|
|
|
Interest expense
|
|
|
43,711
|
|
|
|
—
|
|
|
|
43,711
|
|
|
Operating income (loss) before income taxes
|
|
|
200,360
|
|
|
|
(697
|
)
|
|
|
199,663
|
|
|
Income before income taxes
|
|
|
155,923
|
|
|
|
77,907
|
|
|
|
233,830
|
|
|
Total assets
|
|
|
2,784,087
|
|
|
|
80,808
|
|
|
|
2,864,895
|
|
|
Equity method investments in non-utility activities
|
|
|
—
|
|
|
|
80,287
|
|
|
|
80,287
|
|
|
Construction expenditures
|
|
|
199,059
|
|
|
|
—
|
|
|
|
199,059
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Regulated
|
|
|
Non-Utility
|
|
|
|
|
|
2009
|
|
Utility
|
|
|
Activities
|
|
|
Total
|
|
|
Revenues from external customers
|
|
$
|
1,638,116
|
|
|
$
|
—
|
|
|
$
|
1,638,116
|
|
|
Margin
|
|
|
561,574
|
|
|
|
—
|
|
|
|
561,574
|
|
|
Operations and maintenance expenses
|
|
|
208,105
|
|
|
|
326
|
|
|
|
208,431
|
|
|
Depreciation
|
|
|
97,425
|
|
|
|
29
|
|
|
|
97,454
|
|
|
Income from equity method investments
|
|
|
—
|
|
|
|
33,464
|
|
|
|
33,464
|
|
|
Interest expense
|
|
|
46,675
|
|
|
|
34
|
|
|
|
46,709
|
|
|
Operating income (loss) before income taxes
|
|
|
221,454
|
|
|
|
(503
|
)
|
|
|
220,951
|
|
|
Income before income taxes
|
|
|
171,752
|
|
|
|
32,954
|
|
|
|
204,706
|
|
|
Total assets
|
|
|
2,919,260
|
|
|
|
104,891
|
|
|
|
3,024,151
|
|
|
Equity method investments in non-utility activities
|
|
|
—
|
|
|
|
104,429
|
|
|
|
104,429
|
|
|
Construction expenditures
|
|
|
129,006
|
|
|
|
—
|
|
|
|
129,006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Regulated
|
|
|
Non-Utility
|
|
|
|
|
|
2008
|
|
Utility
|
|
|
Activities
|
|
|
Total
|
|
|
Revenues from external customers
|
|
$
|
2,089,108
|
|
|
$
|
—
|
|
|
$
|
2,089,108
|
|
|
Margin
|
|
|
552,973
|
|
|
|
—
|
|
|
|
552,973
|
|
|
Operations and maintenance expenses
|
|
|
210,757
|
|
|
|
160
|
|
|
|
210,917
|
|
|
Depreciation
|
|
|
93,121
|
|
|
|
29
|
|
|
|
93,150
|
|
|
Income from equity method investments
|
|
|
—
|
|
|
|
27,718
|
|
|
|
27,718
|
|
|
Interest expense
|
|
|
59,273
|
|
|
|
79
|
|
|
|
59,352
|
|
|
Operating income (loss) before income taxes
|
|
|
215,925
|
|
|
|
(277
|
)
|
|
|
215,648
|
|
|
Income before income taxes
|
|
|
156,400
|
|
|
|
27,099
|
|
|
|
183,499
|
|
|
Construction expenditures
|
|
|
181,012
|
|
|
|
—
|
|
|
|
181,012
|
|
Reconciliations to the consolidated financial statements for the years ended October 31,
2010, 2009 and 2008, and as of October 31, 2010 and 2009 are as follows.
112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Operating Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income before income
taxes
|
|
$
|
199,663
|
|
|
$
|
220,951
|
|
|
$
|
215,648
|
|
|
Utility income taxes
|
|
|
(62,082
|
)
|
|
|
(70,079
|
)
|
|
|
(62,814
|
)
|
|
Non-utility activities before income taxes
|
|
|
697
|
|
|
|
503
|
|
|
|
277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
138,278
|
|
|
$
|
151,375
|
|
|
$
|
153,111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes for reportable
segments
|
|
$
|
233,830
|
|
|
$
|
204,706
|
|
|
$
|
183,499
|
|
|
Income taxes
|
|
|
(91,876
|
)
|
|
|
(81,882
|
)
|
|
|
(73,492
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
141,954
|
|
|
$
|
122,824
|
|
|
$
|
110,007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets for reportable segments
|
|
$
|
2,864,895
|
|
|
$
|
3,024,151
|
|
|
|
|
|
|
Eliminations/Adjustments
|
|
|
188,380
|
|
|
|
94,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,053,275
|
|
|
$
|
3,118,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13. Subsequent Events
We monitor significant events occurring after the balance sheet date and prior to the issuance of
the financial statements to determine the impacts, if any, of events on the financial statements to
be issued. All subsequent events of which we are aware were evaluated. For information on
subsequent event disclosure related to regulatory matters, see Note 2 to the consolidated financial
statements.
14. Selected Quarterly Financial Data (In thousands except per share amounts) (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
Net
|
|
|
Per Share of
|
|
|
|
|
Operating
|
|
|
|
|
|
|
Income
|
|
|
Income
|
|
|
Common Stock
|
|
|
|
|
Revenues
|
|
|
Margin
|
|
|
(Loss)
|
|
|
(Loss)
|
|
|
Basic
|
|
|
Diluted
|
|
|
Fiscal Year 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31
|
|
$
|
673,736
|
|
|
$
|
222,942
|
|
|
$
|
87,801
|
|
|
$
|
113,749
|
|
|
$
|
1.55
|
|
|
$
|
1.55
|
|
|
April 30
|
|
|
472,846
|
|
|
|
168,678
|
|
|
|
52,225
|
|
|
|
46,825
|
|
|
|
0.65
|
|
|
|
0.65
|
|
|
July 31
|
|
|
211,603
|
|
|
|
77,897
|
|
|
|
(3,471
|
)
|
|
|
(9,518
|
)
|
|
|
(0.13
|
)
|
|
|
(0.13
|
)
|
|
October 31
|
|
|
194,110
|
|
|
|
83,075
|
|
|
|
1,723
|
|
|
|
(9,102
|
)
|
|
|
(0.13
|
)
|
|
|
(0.13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fiscal Year 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 31
|
|
$
|
779,644
|
|
|
$
|
220,683
|
|
|
$
|
88,131
|
|
|
$
|
80,876
|
|
|
$
|
1.10
|
|
|
$
|
1.10
|
|
|
April 30
|
|
|
455,432
|
|
|
|
169,953
|
|
|
|
55,351
|
|
|
|
53,525
|
|
|
|
0.73
|
|
|
|
0.73
|
|
|
July 31
|
|
|
180,201
|
|
|
|
80,839
|
|
|
|
1,585
|
|
|
|
(7,300
|
)
|
|
|
(0.10
|
)
|
|
|
(0.10
|
)
|
|
October 31
|
|
|
222,839
|
|
|
|
90,099
|
|
|
|
6,308
|
|
|
|
(4,277
|
)
|
|
|
(0.06
|
)
|
|
|
(0.06
|
)
|
The pattern of quarterly earnings is the result of the highly seasonal nature of the
business as variations in weather conditions generally result in greater earnings during the winter
months. Basic earnings per share are calculated using the weighted average number of shares
outstanding
113
during the quarter. The annual amount may differ from the total of the quarterly amounts due
to changes in the number of shares outstanding during the year.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial
Disclosure
None.
114
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
Our management, including the President and Chief Executive Officer and the Senior Vice
President and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls
and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act as of the end of
the period covered by this Form 10-K. Such disclosure controls and procedures are designed to
provide reasonable assurance that the information we are required to disclose in the reports we
file or submit under the Exchange Act is recorded, processed, summarized and reported within the
time periods required by the United States Securities and Exchange Commission’s rules and forms
and that such information is accumulated and communicated to our management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding
required disclosure. Based on such evaluation, the President and Chief Executive Officer and the
Senior Vice President and Chief Financial Officer concluded that, as of the end of the period
covered by this Form 10-K, our disclosure controls and procedures were effective at the reasonable
assurance level.
We routinely review our internal control over financial reporting and from time to time make
changes intended to enhance the effectiveness of our internal control over financial reporting.
There were no changes to our internal control over financial reporting as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act during the fourth quarter of fiscal 2010 that
materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
115
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
December 23, 2010
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting. Internal control over financial reporting as that term is defined in Rules
13a-15(f) under the Securities Exchange Act of 1934 is designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. The Company’s
internal control over financial reporting is supported by a program of internal audits and
appropriate reviews by management, written policies and guidelines, careful selection and training
of qualified personnel and a written Code of Ethics and Business Conduct adopted by the Company’s
Board of Directors and applicable to all Company Directors, officers and employees.
Because of the inherent limitations, any system of internal control over financial reporting,
no matter how well designed, may not prevent or detect misstatements due to the possibility that a
control can be circumvented or overridden or that misstatements due to error or fraud may occur
that are not detected. Also, projections of the effectiveness to future periods are subject to the
risk that the internal controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies and procedures included in such controls may deteriorate.
We have conducted an evaluation of the effectiveness of our internal control over financial
reporting based upon the framework in “Internal Control — Integrated Framework” issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based upon such evaluation, our
management concluded that as of October 31, 2010, our internal control over financial reporting was
effective.
The Company’s independent registered public accounting firm, Deloitte & Touche LLP, has issued
its report on the effectiveness of the Company’s internal control over financial reporting as of
October 31, 2010.
|
|
|
|
|
|
|
|
Piedmont Natural Gas Company, Inc.
|
|
|
|
/s/ Thomas E. Skains
|
|
|
|
Thomas E. Skains
|
|
|
|
Chairman, President and Chief Executive Officer
|
|
|
|
|
|
|
|
/s/ David J. Dzuricky
|
|
|
|
David J. Dzuricky
|
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
|
|
|
|
|
/s/ Jose M. Simon
|
|
|
|
Jose M. Simon
|
|
|
|
Vice President and Controller
|
|
|
|
116
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Piedmont Natural Gas Company, Inc.
Charlotte, North Carolina
We have audited the internal control over financial reporting of Piedmont Natural Gas Company, Inc.
and subsidiaries (the “Company”) as of October 31, 2010, based on criteria established in
Internal
Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company’s management is responsible for maintaining effective internal control
over financial reporting and for its assertion of the effectiveness of internal control over
financial reporting, included in the accompanying Management’s Report on Internal Control over
Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles and
that receipts and expenditures of the company are being made only in accordance with authorizations
of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected and corrected on a timely basis. Also, projections
of any evaluation of the effectiveness of the internal control over financial reporting to future
periods are subject to the risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of October 31, 2010, based on the criteria established in
Internal
Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated financial statements as of and for the year ended October
31, 2010 of the Company and our report dated December 23, 2010 expressed an unqualified opinion on
those financial statements.
/s/ Deloitte & Touche LLP
Charlotte, North Carolina
December 23, 2010
117
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information concerning our executive officers and directors is set forth in the sections
entitled “Information Regarding the Board of Directors” and “Executive Officers” in our Proxy
Statement for the 2011 Annual Meeting of Shareholders, which sections are incorporated in this
annual report on Form 10-K by reference. Information concerning compliance with Section 16(a) of
the Securities Exchange Act of 1934, as amended, is set forth in the section entitled “Section
16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2011 Annual Meeting
of Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
Information concerning our Audit Committee and our Audit Committee financial experts is set
forth in the section entitled “Committees of the Board” in our Proxy Statement for the 2011 Annual
Meeting of Shareholders, which section is incorporated in this annual report on Form 10-K by
reference.
We have adopted a Code of Ethics and Business Conduct that is applicable to all our directors,
officers and employees, including our principal executive officer, principal financial officer and
principal accounting officer. We have also adopted Special Provisions Relating to the Company’s
Principal Executive Officer and Senior Financial Officers (Special Provisions) that are part of our
Corporate Governance Guidelines and that apply to our principal executive officer, principal
financial officer and principal accounting officer. The Code of Ethics and Business Conduct and
Special Provisions are available on the “For Investors-Corporate Governance” section of our website
at
www.piedmontng.com
. If we amend or grant a waiver, including an implicit waiver, from
the Code of Ethics and Business Conduct or Special Provisions that apply to the principal executive
officer, principal financial officer and controller or persons performing similar functions and
that relate to any element of the code enumerated in Item 406(b) of Regulation S-K, we will
disclose the amendment or waiver on the “For Investors-Corporate Governance” section of our website
within four business days of such amendment or waiver.
Item 11. Executive Compensation
Information for this item is set forth in the sections entitled “Executive Compensation,”
“Director Compensation,” “Compensation Committee Interlocks and Insider Participation,” and
“Compensation Committee Report” in our Proxy Statement for the 2011 Annual Meeting of Shareholders,
which sections are incorporated in this annual report on Form 10-K by reference.
118
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Information for this item is set forth in the section entitled “Security Ownership of
Management and Certain Beneficial Owners” in our Proxy Statement for the 2011 Annual Meeting of
Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
We know of no arrangement, or pledge, which may result in a change in control.
Information concerning securities authorized for issuance under our equity compensation plans
is set forth in the section entitled “Equity Compensation Plan Information” in our Proxy Statement
for the 2011 Annual Meeting of Shareholders, which section is incorporated in this annual report on
Form 10-K by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information for this item is set forth in the section entitled “Independence of Board Members
and Related Party Transactions” in our Proxy Statement for the 2011 Annual Meeting of Shareholders,
which section is incorporated in this annual report on Form 10-K by reference.
Item 14. Principal Accounting Fees and Services
Information for this item is set forth in the table entitled “Fees For Services” in “Proposal
2 — Ratification of the Appointment of Deloitte & Touche LLP As Independent Registered Public
Accounting Firm For the 2011 Fiscal Year” in our Proxy Statement for the 2011 Annual Meeting of
Shareholders, which section is incorporated in this annual report on Form 10-K by reference.
119
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) 1. Financial Statements
The following consolidated financial statements for the year ended October 31, 2010, are
included in Item 8 of this report as follows:
Consolidated Balance Sheets — October 31, 2010 and 2009
Consolidated Statements of Income — Years Ended
October 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows — Years Ended
October 31, 2010, 2009 and 2008
Consolidated Statements of Stockholders’ Equity — Years Ended
October 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
(a) 2. Supplemental Consolidated Financial Statement Schedules
None
Schedules and certain other information are omitted for the reason that they are not required
or are not applicable, or the required information is shown in the consolidated financial
statements or notes thereto.
|
|
|
|
|
|
|
|
(a)
|
|
3.
|
|
|
Exhibits
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Where an exhibit is filed by incorporation by reference to a
previously filed registration statement or report, such
registration statement or report is identified in
parentheses. Upon written request of a shareholder, we will
provide a copy of the exhibit at a nominal charge.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The exhibits numbered 10.1 through 10.22 are management
contracts or compensatory plans or arrangements.
|
|
|
|
|
|
|
|
|
|
|
3.1
|
|
|
Restated Articles of Incorporation of Piedmont Natural Gas Company,
Inc., dated as of March 2009 (Exhibit 3.1, Form 10-Q for the quarter
ended July 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
3.2
|
|
|
Copy of Certificate of Merger (New York) and Articles of Merger
(North Carolina), each dated March 1, 1994, evidencing merger of
Piedmont Natural Gas Company, Inc., with and into PNG Acquisition
Company, with PNG Acquisition Company being renamed “Piedmont Natural
Gas Company, Inc.” (Exhibits 3.2 and 3.1, Registration Statement on
Form 8-B, dated March 2, 1994).
|
120
|
|
|
|
|
|
|
|
|
|
|
|
3.3
|
|
|
By-Laws of Piedmont Natural Gas Company, Inc., dated December 15,
2006 (Exhibit 3.3, Form 10-K for the fiscal year ended October 31,
2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.1
|
|
|
Note Agreement, dated as of September 21, 1992, between Piedmont and
Provident Life and Accident Insurance Company (Exhibit 4.30, Form
10-K for the fiscal year ended October 31, 1992).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.2
|
|
|
Amendment to Note Agreement, dated as of September 16, 2005, by and
between Piedmont and Provident Life and Accident Insurance Company
(Exhibit 4.2, Form 10-K for the fiscal year ended October 31, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.3
|
|
|
Indenture, dated as of April 1, 1993, between Piedmont and The Bank
of New York Mellon Trust Company, N.A. (as successor to Citibank,
N.A.), Trustee (Exhibit 4.1, Form S-3 Registration Statement No.
33-59369).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.4
|
|
|
Medium-Term Note, Series A, dated as of October 6, 1993 (Exhibit 4.8,
Form 10-K for the fiscal year ended October 31, 1993).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.5
|
|
|
First Supplemental Indenture, dated as of February 25, 1994, between
PNG Acquisition Company, Piedmont Natural Gas Company, Inc., and
Citibank, N.A., Trustee (Exhibit 4.2, Form S-3 Registration Statement
No. 33-59369).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.6
|
|
|
Medium-Term Note, Series A, dated as of September 19, 1994 (Exhibit
4.9, Form 10-K for the fiscal year ended October 31, 1994).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.7
|
|
|
Form of Master Global Note (Exhibit 4.4, Form S-3 Registration
Statement No. 33-59369).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.8
|
|
|
Pricing Supplement of Medium-Term Notes, Series B, dated October 3,
1995 (Exhibit 4.10, Form 10-K for the fiscal year ended October 31,
1995).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.9
|
|
|
Pricing Supplement of Medium-Term Notes, Series B, dated October 4,
1996 (Exhibit 4.11, Form 10-K for the fiscal year ended October 31,
1996).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.10
|
|
|
Form of Master Global Note, executed September 9, 1999 (Exhibit 4.4,
Form S-3 Registration Statement No. 333-26161).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.11
|
|
|
Pricing Supplement of Medium-Term Notes, Series C, dated September
15, 1999 (Rule 424(b)(3) Pricing Supplement to Form S-3 Registration
Statement Nos. 33-59369 and 333-26161).
|
121
|
|
|
|
|
|
|
|
|
|
|
|
4.12
|
|
|
Pricing Supplement No. 3 of Medium-Term Notes, Series C, dated
September 26, 2000 (Rule 424(b)(3) Pricing Supplement to Form S-3
Registration Statement No. 333-26161).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.13
|
|
|
Form of Master Global Note, executed June 4, 2001 (Exhibit 4.4, Form
S-3 Registration Statement No. 333-62222).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.14
|
|
|
Pricing Supplement No. 1 of Medium-Term Notes, Series D, dated
September 18, 2001 (Rule 424(b)(3) Pricing Supplement to Form S-3
Registration Statement No. 333-62222).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.15
|
|
|
Second Supplemental Indenture, dated as of June 15, 2003, between
Piedmont and Citibank, N.A., Trustee (Exhibit 4.3, Form S-3
Registration Statement No. 333-106268).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.16
|
|
|
Form of 5% Medium-Term Note, Series E, dated as of December 19, 2003
(Exhibit 99.1, Form 8-K, dated December 23, 2003).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.17
|
|
|
Form of 6% Medium-Term Note, Series E, dated as of December 19, 2003
(Exhibit 99.2, Form 8-K, dated December 23, 2003).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.18
|
|
|
Third Supplemental Indenture, dated as of June 20, 2006, between
Piedmont Natural Gas Company, Inc. and Citibank, N.A., as trustee
(Exhibit 4.1, Form 8-K dated June 20, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.19
|
|
|
Form of 6.25% Insured Quarterly Note Series 2006, Due 2036 (Exhibit
4.2 (as included in Exhibit 4.1), Form 8-K dated June 20, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
4.20
|
|
|
Agreement of Resignation, Appointment and Acceptance dated as of
March 29, 2007, by and among the registrant, Citibank, N.A., and The
Bank of New York Trust Company, N.A. (Exhibit 4.1, Form 10-Q for
quarter ended April 30, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Compensatory Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
10.1
|
|
|
Form of Director Retirement Benefits Agreement with outside
directors, dated September 1, 1999 (Exhibit 10.54, Form 10-K for the
fiscal year ended October 31, 1999).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.2
|
|
|
Establishment of Measures for Long-Term Incentive Plan 10 (filed in
Form 8-K dated October 20, 2006, as Item 1.01).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.3
|
|
|
Employment Agreement with David J. Dzuricky, dated December 1, 1999
(Exhibit 10.37, Form 10-K for the fiscal year ended October 31,
1999).
|
122
|
|
|
|
|
|
|
|
|
|
|
|
10.4
|
|
|
Employment Agreement with Thomas E. Skains, dated December 1, 1999
(Exhibit 10.40, Form 10-K for the fiscal year ended October 31,
1999).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5
|
|
|
Employment Agreement with Franklin H. Yoho, dated March 18, 2002
(Exhibit 10.23, Form 10-K for the fiscal year ended October 31,
2002).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.6
|
|
|
Employment Agreement with Michael H. Yount, dated May 1, 2006
(Exhibit 10.1, Form 10-Q for the quarter ended April 30, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.7
|
|
|
Employment Agreement with Kevin M. O’Hara, dated May 1, 2006 (Exhibit
10.2, Form 10-Q for the quarter ended April 30, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.8
|
|
|
Form of Severance Agreement with Thomas E. Skains, dated September 4,
2007 (Substantially identical agreements have been entered into as of
the same date with David J. Dzuricky, Franklin H. Yoho, Michael H.
Yount, Kevin M. O’Hara, June B. Moore and Jane R. Lewis-Raymond)
(Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.9
|
|
|
Schedule of Severance Agreements with Executives (Exhibit 10.2a, Form
10-Q for the quarter ended July 31, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.10
|
|
|
Piedmont Natural Gas Company, Inc. Incentive Compensation Plan
(Exhibit 10.1, Form 8-K dated March 3, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.11
|
|
|
Restricted Stock Award Agreement between Piedmont Natural Gas
Company, Inc. and Thomas E. Skains, dated September 1, 2006 (Exhibit
10.26, Form 10-K for the fiscal year ended October 31, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.12
|
|
|
Form of Performance Unit Award Agreement (Exhibit 10.1, Form 10-Q
for the quarter ended January 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.13
|
|
|
Resolution of Board of Directors, February 26, 2010, establishing
compensation for non-management directors (Exhibit 10.1, Form 10-Q
for the quarter ended April 30, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.14
|
|
|
Incentive Compensation Plan Interpretive Guidelines as of September
7, 2007 (Exhibit 10.24, Form 10-K for the fiscal year ended October
31, 2007).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.15
|
|
|
Piedmont Natural Gas Company, Inc. Voluntary Deferral Plan, dated as
of December 8, 2008, effective November 1, 2008 (Exhibit 10.1, Form
10-Q for quarter ended January 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.16
|
|
|
Piedmont Natural Gas Company, Inc. Defined Contribution Restoration
Plan, dated as of December 8, 2008, effective January 1, 2009
(Exhibit 10.2, Form 10-Q for quarter ended January 31, 2009).
|
123
|
|
|
|
|
|
|
|
|
|
|
|
10.17
|
|
|
Piedmont Natural Gas Company Employee Stock Purchase Plan, amended
and restated as of April 1, 2009 (Exhibit 4.1, Form 8-K dated April
13, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.18
|
|
|
Amendment No. 1 to Director Retirement Benefits Agreements with
outside directors, dated as of December 31, 2008 (Exhibit 10.1, Form
10-Q for quarter ended July 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.19
|
|
|
Instrument of Amendment for Piedmont Natural Gas Company, Inc.
401(k) Plan dated as of December 17, 2009 (Exhibit 10.2, Form 10-Q
for the quarter ended January 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.20
|
|
|
Form of Amendment No. 1 to Employment Agreement between Piedmont
Natural Gas Company, Inc. and Thomas E. Skains, dated as of June 4,
2010 (Substantially identical agreements have been entered into as
of the same date with David J. Dzuricky, Kevin M. O’Hara, Michael H.
Yount and Franklin H. Yoho) (Exhibit 10.1, Form 10-Q for the quarter
ended July 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.21
|
|
|
Employment Agreement between Piedmont Natural Gas Company, Inc. and
Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.2, Form 10-Q
for the quarter ended July 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.22
|
|
|
Severance Agreement between Piedmont Natural Gas Company, Inc. and
Karl W. Newlin, dated as of June 4, 2010 (Exhibit 10.3, Form 10-Q
for the quarter ended July 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
10.23
|
|
|
Amended and Restated Limited Liability Company Agreement of
SouthStar Energy Services LLC, effective January 1, 2004, between
Piedmont Energy Company and Georgia Natural Gas Company (Exhibit
10.1, Form 10-Q for the quarter ended April 30, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.24
|
|
|
First Amendment to Amended and Restated Limited Liability Company
Agreement of SouthStar Energy Services LLC, dated as of July 31,
2006, between Piedmont Energy Company and Georgia Natural Gas
Company (Exhibit 10.28, Form 10-K for the fiscal year ended October
31, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.25
|
|
|
Amendment by Written Consent to Amended and Restated Limited
Liability Company Agreement of SouthStar Energy Services LLC, dated
as of August 28, 2006, between Piedmont Energy Company and Georgia
Natural Gas Company (Exhibit 10.29, Form 10-K for the fiscal year
ended October 31, 2006).
|
124
|
|
|
|
|
|
|
|
|
|
|
|
10.26
|
|
|
Amendment by Written Consent to Amended and Restated Limited
Liability Company Agreement of SouthStar Energy Services LLC, dated
as of September 20, 2006, between Piedmont Energy Company and
Georgia Natural Gas Company (Exhibit 10.30, Form 10-K for the fiscal
year ended October 31, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.27
|
|
|
Equity Contribution Agreement, dated as of November 12, 2004,
between Columbia Gas Transmission Corporation and Piedmont Natural
Gas Company (Exhibit 10.1, Form 8-K dated November 16, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.28
|
|
|
Construction, Operation and Maintenance Agreement by and Between
Columbia Gas Transmission Corporation and Hardy Storage Company,
LLC, dated November 12, 2004 (Exhibit 10.2, Form 8-K dated November
16, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.29
|
|
|
Operating Agreement of Hardy Storage Company, LLC, dated as of
November 12, 2004 (Exhibit 10.3, Form 8-K dated November 16, 2004).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.30
|
|
|
Guaranty of Principal dated as of June 29, 2006, by Piedmont Energy
Partners, Inc. in favor of U.S. Bank National Association, as agent
(Exhibit 10.1, Form 8-K dated July 5, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.31
|
|
|
Residual Guaranty dated as of June 29, 2006, by Piedmont Energy
Partners, Inc. in favor of U.S. Bank National Association, as agent
(Exhibit 10.2, Form 8-K dated July 5, 2006).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.32
|
|
|
Credit Agreement dated as of April 25, 2006 among Piedmont Natural
Gas Company, Inc. and Bank of America, N.A. as Administrative Agent,
Swing Line Lender and L/C Issuer, and The Other Lenders Party Hereto
(Exhibit 10.4, Form 10-Q for the quarter ended July 31, 2010).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.33
|
|
|
Revolving Credit Facility between Piedmont Natural Gas Company, Inc.
and Bank of America, N.A., dated October 27, 2008 (Exhibit 10.32,
Form 10-K for the fiscal year ended October 31, 2008).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.34
|
|
|
Revolving Credit Facility between Piedmont Natural Gas Company, Inc.
and Branch Banking and Trust Company, dated October 29, 2008
(Exhibit 10.33, Form 10-K for the fiscal year ended October 31,
2008).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.35
|
|
|
Credit Agreement dated as of December 3, 2008 among Piedmont Natural
Gas Company, Inc., Bank of America, N.A., as Administrative Agent,
and the Other Lenders Party Thereto (Exhibit 10.5, Form 10-Q for the
quarter ended July 31, 2010).
|
125
|
|
|
|
|
|
|
|
|
|
|
|
10.36
|
|
|
Amended and Restated Revolving Credit Facility dated December 1,
2008 between Piedmont Natural Gas Company, Inc. and Bank of America,
N.A. (Exhibit 10.4, Form 10-Q for the quarter ended January 31,
2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.37
|
|
|
Amended and Restated Revolving Credit Facility dated December 1,
2008 between Piedmont Natural Gas Company, Inc. and Branch Banking
and Trust Company (Exhibit 10.5, Form 10-Q for the quarter ended
January 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.38
|
|
|
Second Amendment to Amended and Restated Limited Liability Company
Agreement of SouthStar Energy Services LLC by and between Georgia
Natural Gas Company and Piedmont Energy Company, dated July 2, 2009
(Exhibit 10.2, Form 10-Q for the quarter ended July 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.39
|
|
|
Settlement Agreement by and between Georgia Natural Gas Company and
Piedmont Energy Company, dated July 29, 2009 (Exhibit 10.1, Form 8-K
dated August 4, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.40
|
|
|
Third Amendment to Amended and Restated Limited Liability Company
Agreement of SouthStar Energy Services LLC by and between Georgia
Natural Gas Company and Piedmont Energy Company, dated July 29, 2009
(Exhibit 10.2, Form 8-K dated August 4, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
10.41
|
|
|
Assignment and Assumption between Citibank, N.A. and Northern Trust
Company, dated as of September 18, 2009 (Exhibit 10.37, Form 10-K
for the fiscal year ended October 31, 2009).
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
Computation of Ratio of Earnings to Fixed Charges.
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
List of Subsidiaries.
|
|
|
|
|
|
|
|
|
|
|
|
|
23.1
|
|
|
Consent of Independent Registered Public Accounting Firm.
|
|
|
|
|
|
|
|
|
|
|
|
|
31.1
|
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Executive Officer.
|
|
|
|
|
|
|
|
|
|
|
|
|
31.2
|
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Financial Officer.
|
|
|
|
|
|
|
|
|
|
|
|
|
32.1
|
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief
Executive Officer.
|
126
|
|
|
|
|
|
|
|
|
|
|
32.2
|
|
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief
Financial Officer.
|
|
|
|
|
|
|
|
|
|
|
|
101.INS
|
|
XBRL Instance Document (1)
|
|
|
|
|
|
|
|
|
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema (1)
|
|
|
|
|
|
|
|
|
|
|
|
101.CAL
|
|
XBRL Taxonomy Calculation Linkbase (1)
|
|
|
|
|
|
|
|
|
|
|
|
101.DEF
|
|
XBRL Taxonomy Definition Linkbase (1)
|
|
|
|
|
|
|
|
|
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Label Linkbase (1)
|
|
|
|
|
|
|
|
|
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase (1)
|
|
|
|
|
|
(1)
|
|
Furnished, not filed.
|
Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible
business reporting language (XBRL): (1) Document and Entity Information; (2) Consolidated Balance
Sheets as of October 31, 2010 and 2009; (3) Consolidated Statements of Income for the years ended
October 31, 2010, 2009 and 2008; (4) Consolidated Statements of Cash Flows for the years ended
October 31, 2010, 2009 and 2008; (5) Consolidated Statements of Stockholders’ Equity for the years
ended October 31, 2010, 2009 and 2008; and (6) Notes to Consolidated Financial Statements.
Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed as part
of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act
of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise not subject to
liability. We also make available on our web site the Interactive Data Files submitted as Exhibit
101 to this Annual Report.
127
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
|
|
Piedmont Natural Gas Company, Inc.
(Registrant)
|
|
|
|
By:
|
/s/ Thomas E. Skains
|
|
|
|
|
Thomas E. Skains
|
|
|
|
|
Chairman of the Board, President
and Chief Executive Officer
|
|
|
|
Date: December 23, 2010
|
|
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
|
|
Signature
|
|
|
|
Title
|
|
|
|
|
|
|
|
Chairman of the Board, President and
|
|
Thomas E. Skains
|
|
|
|
Chief Executive Officer
|
|
|
|
|
|
(Principal Executive Officer)
|
|
|
|
|
|
|
|
Date: December 23, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Vice President and
|
|
David J. Dzuricky
|
|
|
|
Chief Financial Officer
|
|
|
|
|
|
(Principal Financial Officer)
|
|
|
|
|
|
|
|
Date: December 23, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vice President and Controller
|
|
Jose M. Simon
|
|
|
|
(Principal Accounting Officer)
|
|
|
|
|
|
|
|
Date: December 23, 2010
|
|
|
|
|
128
|
|
|
|
|
|
|
Signature
|
|
|
|
Title
|
|
|
|
/s/ Jerry W. Amos
|
|
|
|
Director
|
|
|
|
|
|
|
|
Jerry W. Amos
|
|
|
|
|
|
|
|
|
|
|
|
/s/ E. James Burton
|
|
|
|
Director
|
|
|
|
|
|
|
|
E. James Burton
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Malcolm E. Everett III
|
|
|
|
Director
|
|
|
|
|
|
|
|
Malcolm E. Everett III
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
John W. Harris
|
|
|
|
|
|
|
|
|
|
|
/s/ Aubrey B. Harwell, Jr.
|
|
|
|
Director
|
|
Aubrey B. Harwell, Jr.
|
|
|
|
|
|
|
|
|
|
|
/s/ Frank B. Holding, Jr.
|
|
|
|
Director
|
|
Frank B. Holding, Jr.
|
|
|
|
|
|
|
|
|
|
|
/s/ Frankie T. Jones, Sr.
|
|
|
|
Director
|
|
Frankie T. Jones, Sr.
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Vicki McElreath
|
|
|
|
Director
|
|
|
|
|
|
|
|
Vicki McElreath
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
Minor M. Shaw
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
Muriel W. Sheubrooks
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
David E. Shi
|
|
|
|
|
129
Piedmont Natural Gas Company, Inc.
Form 10-K
For the Fiscal Year Ended October 31, 2010
Exhibits
|
|
|
|
|
12
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
21
|
|
List of Subsidiaries
|
|
|
|
|
|
23.1
|
|
Consent of Independent Registered Public Accounting Firm
|
|
|
|
|
|
31.1
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Executive Officer
|
|
|
|
|
|
31.2
|
|
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002 of the Chief Financial Officer
|
|
|
|
|
|
32.1
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief
Executive Officer
|
|
|
|
|
|
32.2
|
|
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 of the Chief
Financial Officer
|
Piedmont Nat Gas (NYSE:PNY)
Historical Stock Chart
From Jun 2024 to Jul 2024
Piedmont Nat Gas (NYSE:PNY)
Historical Stock Chart
From Jul 2023 to Jul 2024
