Other Comprehensive Income (Loss)
Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and retirement benefits from our investments in unconsolidated affiliates. See
Note 11
for further information on our investments in unconsolidated affiliates. Changes in each component of accumulated OCIL are presented below for the years ended
October 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
Changes in Accumulated OCIL
(1)
|
(in millions)
|
|
2016
|
|
2015
|
Accumulated OCIL beginning balance, net of tax
|
|
$
|
(0.8
|
)
|
|
$
|
(0.2
|
)
|
Hedging activities of equity method investments:
|
|
|
|
|
OCIL before reclassifications, net of tax
|
|
(2.8
|
)
|
|
(1.6
|
)
|
Amounts reclassified from accumulated OCIL, net of tax
|
|
3.4
|
|
|
1.0
|
|
Total current period activity of hedging activities of equity method investments, net of tax
|
|
0.6
|
|
|
(0.6
|
)
|
Accumulated OCIL ending balance, net of tax
|
|
$
|
(0.2
|
)
|
|
$
|
(0.8
|
)
|
|
|
|
|
|
(1)
Amounts in parentheses indicate debits to accumulated OCIL.
|
A reconciliation of the effect on certain line items of net income on amounts reclassified out of each component of accumulated OCIL is presented below for the years ended
October 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification Out of Accumulated OCIL
(1)
|
|
|
Years Ended
|
|
Affected Line Items on Statement of Operations and Comprehensive Income
|
|
|
October 31,
|
|
(in millions)
|
|
2016
|
|
2015
|
|
Hedging activities of equity method investments
|
|
$
|
1.4
|
|
|
$
|
1.7
|
|
|
Equity in earnings of unconsolidated affiliates
|
Income tax expense
|
|
2.0
|
|
|
(0.7
|
)
|
|
Income tax expense
|
Total reclassification for the period, net of tax
|
|
$
|
3.4
|
|
|
$
|
1.0
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts in parentheses indicate debits to accumulated OCIL.
|
5
.
Debt and Credit Facilities
Summary of Long-Term Debt
Our long-term debt consists of privately placed senior notes issued under note purchase agreements, as well as publicly issued medium-term and senior notes issued under an indenture. All of our long-term debt is unsecured and is issued at fixed rates. None of our debt is actively traded. The tables below reflect the detail of this presentation for our long-term debt as of October 31, 2016 and 2015.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt as of October 31, 2016
|
(in millions)
|
|
Principal
|
|
Unamortized Debt Issuance Expenses and Discounts
|
|
Total
|
Senior Notes:
|
|
|
|
|
|
|
8.51%, due September 30, 2017
|
|
$
|
35.0
|
|
|
$
|
—
|
|
|
$
|
35.0
|
|
4.24%, due June 6, 2021
|
|
160.0
|
|
|
(0.6
|
)
|
|
159.4
|
|
3.47%, due July 16, 2027
|
|
100.0
|
|
|
(0.6
|
)
|
|
99.4
|
|
3.57%, due July 16, 2027
|
|
200.0
|
|
|
(1.2
|
)
|
|
198.8
|
|
4.10%, due September 18, 2034
|
|
250.0
|
|
|
(2.5
|
)
|
|
247.5
|
|
4.65%, due August 1, 2043
|
|
300.0
|
|
|
(2.9
|
)
|
|
297.1
|
|
3.60%, due September 1, 2025
|
|
150.0
|
|
|
(1.4
|
)
|
|
148.6
|
|
3.64%, due November 1, 2046
|
|
300.0
|
|
|
(3.4
|
)
|
|
296.6
|
|
Medium-Term Notes:
|
|
|
|
|
|
|
|
6.87%, due October 6, 2023
|
|
45.0
|
|
|
(0.1
|
)
|
|
44.9
|
|
8.45%, due September 19, 2024
|
|
40.0
|
|
|
(0.1
|
)
|
|
39.9
|
|
7.40%, due October 3, 2025
|
|
55.0
|
|
|
(0.2
|
)
|
|
54.8
|
|
7.50%, due October 9, 2026
|
|
40.0
|
|
|
(0.1
|
)
|
|
39.9
|
|
7.95%, due September 14, 2029
|
|
60.0
|
|
|
(0.2
|
)
|
|
59.8
|
|
6.00%, due December 19, 2033
|
|
100.0
|
|
|
(0.7
|
)
|
|
99.3
|
|
Total
|
|
1,835.0
|
|
|
(14.0
|
)
|
|
1,821.0
|
|
Less current maturities
|
|
35.0
|
|
|
—
|
|
|
35.0
|
|
Total
|
|
$
|
1,800.0
|
|
|
$
|
(14.0
|
)
|
|
$
|
1,786.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt as of October 31, 2015
|
(in millions)
|
|
Principal
|
|
Unamortized Debt Issuance Expenses and Discounts
|
|
Total
|
Senior Notes:
|
|
|
|
|
|
|
2.92%, due June 6, 2016
|
|
$
|
40.0
|
|
|
$
|
(0.1
|
)
|
|
$
|
39.9
|
|
8.51%, due September 30, 2017
|
|
35.0
|
|
|
—
|
|
|
35.0
|
|
4.24%, due June 6, 2021
|
|
160.0
|
|
|
(0.8
|
)
|
|
159.2
|
|
3.47%, due July 16, 2027
|
|
100.0
|
|
|
(0.6
|
)
|
|
99.4
|
|
3.57%, due July 16, 2027
|
|
200.0
|
|
|
(1.3
|
)
|
|
198.7
|
|
4.10%, due September 18, 2034
|
|
250.0
|
|
|
(2.6
|
)
|
|
247.4
|
|
4.65%, due August 1, 2043
|
|
300.0
|
|
|
(3.0
|
)
|
|
297.0
|
|
3.60%, due September 1, 2025
|
|
150.0
|
|
|
(1.4
|
)
|
|
148.6
|
|
Medium-Term Notes:
|
|
|
|
|
|
|
6.87%, due October 6, 2023
|
|
45.0
|
|
|
(0.1
|
)
|
|
44.9
|
|
8.45%, due September 19, 2024
|
|
40.0
|
|
|
(0.1
|
)
|
|
39.9
|
|
7.40%, due October 3, 2025
|
|
55.0
|
|
|
(0.2
|
)
|
|
54.8
|
|
7.50%, due October 9, 2026
|
|
40.0
|
|
|
(0.1
|
)
|
|
39.9
|
|
7.95%, due September 14, 2029
|
|
60.0
|
|
|
(0.3
|
)
|
|
59.7
|
|
6.00%, due December 19, 2033
|
|
100.0
|
|
|
(0.7
|
)
|
|
99.3
|
|
Total
|
|
1,575.0
|
|
|
(11.3
|
)
|
|
1,563.7
|
|
Less current maturities
|
|
40.0
|
|
|
—
|
|
|
40.0
|
|
Total
|
|
$
|
1,535.0
|
|
|
$
|
(11.3
|
)
|
|
$
|
1,523.7
|
|
Current maturities for the next five years ending October 31 and thereafter are as follows.
|
|
|
|
|
(in millions)
|
|
2017
|
$
|
35.0
|
|
2018
|
—
|
|
2019
|
—
|
|
2020
|
—
|
|
2021
|
160.0
|
|
Thereafter
|
1,640.0
|
|
Total
|
$
|
1,835.0
|
|
In June 2014, we filed with the SEC a combined debt and equity shelf registration statement that became effective on June 6, 2014. The NCUC approved debt and equity issuances under this shelf registration statement up to
$1.0 billion
during its
three
-year life. As a result of the Acquisition, Piedmont's shelf registration statement is no longer valid for future issuances.
On
September 14, 2015
, we issued
$150.0 million
of
ten
-year, unsecured senior notes with an interest rate of 3.60% and at a discount of
.065%
or
$0.1 million
under the registration statement in effect noted above. We have the option to redeem all or part of the notes before the stated maturity prior to June 1,
2025
, at a
redemption price equal to the greater of a) 100% of the principal amount plus any accrued and unpaid interest to the date of redemption, or b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, plus 25 basis points and any accrued and unpaid interest to the date of redemption.
We have the option to redeem all or part of the notes before the stated maturity on or after
June 1, 2025
, at
100% of the principal amount plus any accrued and unpaid interest to the date of redemption
. We used the net proceeds of
$148.9 million
from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
On June 6, 2016, we repaid
$40.0 million
of our 2.92% senior notes at maturity.
On
July 28, 2016
, we issued
$300.0 million
of unsecured senior notes maturing
November 1, 2046
with an interest rate of
3.64%
and at a discount of
.122%
or
$0.4 million
under the registration statement in effect noted above. We have the option to redeem all or part of the notes before May 1,
2046
, at a
redemption price equal to the greater of a) 100% of the principal amount of the notes to be redeemed, and b) the sum of the present values of the remaining scheduled payments of principal and interest on the notes to be redeemed, discounted to the date of redemption on a semi-annual basis at the Treasury Rate as defined in the indenture, as supplemented, plus 25 basis points and any accrued and unpaid interest to the date of redemption.
We have the option to redeem all or part of the notes on or after
May 1, 2046
, at
100% of the principal amount plus any accrued and unpaid interest to the date of redemption
. We used the net proceeds of
$297.0 million
from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
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, 2016
, our net earnings available for restricted payments were
$1.3 billion
.
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, 2016
, we are in compliance with all default provisions.
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 $1.0 million that after 60 days is not discharged, satisfied or stayed pending appeal,
|
|
|
•
|
Specified events under the Employee Retirement Income Security Act of 1974,
|
|
|
•
|
Failure to observe or perform covenants, including:
|
|
|
•
|
Interest coverage of at least
1.75
times. Interest coverage was
4.65
times as of
October 31, 2016
;
|
|
|
•
|
Funded debt cannot exceed
70%
of total capitalization. Funded debt was
55%
of total capitalization as of
October 31, 2016
;
|
|
|
•
|
Funded debt of all subsidiaries in the aggregate cannot exceed
15%
of total capitalization. There is
no
funded debt of our subsidiaries as of
October 31, 2016
;
|
|
|
•
|
Restrictions on permitted liens;
|
|
|
•
|
Restrictions on paying dividends on or repurchasing our stock or making investments in subsidiaries; and
|
|
|
•
|
Restrictions on burdensome agreements.
|
The Acquisition constituted a change in control under the note agreements under which our 4.24% Senior Notes due 2021, 3.47% Senior Notes due 2027 and 3.57% Senior Notes due 2027 were issued. While the Acquisition did not constitute an event of default, upon the closing of the Acquisition, we were required to offer to prepay
100%
of the principal amounts plus accrued interest to these noteholders.
None
of the noteholders exercised the prepayment option.
Available Credit Facilities
At October 31, 2016, we have an
$850.0 million
five-year revolving syndicated credit facility that expires on
December 14, 2020
that has an option to request an expansion up to an additional
$200.0 million
. We pay an
annual
fee of
$35,000 plus 8.5 basis
points for any unused amount. The facility provides a line of credit for letters of credit of
$10.0 million
, of which
$1.7 million
and
$1.6 million
were issued and outstanding as of
October 31, 2016
and
2015
, 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 London Interbank Offered Rate (LIBOR) plus from 75 to 112.5 basis points
, based on our credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2020 provided that we are in compliance with all terms of the agreement. The facility expressly permitted the Acquisition by Duke Energy.
We have an
$850.0 million
unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed
$850.0 million
. The notes issued under the CP program may have maturities not to exceed
397
days
from the date of issuance and bear
interest based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings, plus a spread of 5 basis points
. Any borrowings under the CP program rank equally with our other unsecured debt. The notes under the CP program are not registered and are offered and issued pursuant to an exemption from registration. Due to the seasonal nature of our business, amounts borrowed can vary significantly during the year.
As of
October 31, 2016
, we had
$145.0 million
of notes outstanding under the CP program, as included in "
Notes payable and commercial paper
" within "
Current Liabilities
" on the
Consolidated Balance Sheets
, with original maturities ranging from
1
to
6
days from their dates of issuance at a weighted average interest rate of
.64%
. As of
October 31, 2015
, our outstanding notes under the CP program, included on the
Consolidated Balance Sheets
as stated above, were
$340.0 million
at a weighted average interest rate of
.22%
.
Other than outstanding CP balances, we did not have any borrowings under the revolving syndicated credit facility for the twelve months ended
October 31, 2016
. A summary of the short-term debt activity under our CP program for the twelve months ended
October 31, 2016
is as follows.
|
|
|
|
|
(in millions)
|
|
Minimum amount outstanding
|
$
|
110.0
|
|
Maximum amount outstanding
|
$
|
530.0
|
|
Minimum interest rate
|
.20
|
%
|
Maximum interest rate
|
.75
|
%
|
Weighted average interest rate
|
.55
|
%
|
Our five-year revolving syndicated 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 55%
at
October 31, 2016
.
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 with the purchase of financial gas call option derivative instruments (gas purchase options). The accounting guidance related to derivatives and hedging requires that we use a gross presentation, based on our election, for the fair value amounts of our gas purchase options. We use long position gas purchase options to provide some level of protection for our customers in the event of significant commodity price increases. As of
October 31, 2016
and
2015
, we had long gas purchase options providing total coverage of
15.4 million
dekatherms and
34.7 million
dekatherms, respectively. The long gas purchase options held as of
October 31, 2016
are for the period from December 2016 through May 2017
.
Derivative Assets and Liabilities - Gas Supply Contracts
We enter into forward gas supply contracts to provide diversification, reliability and gas cost benefits to our customers as part of our diversified gas supply portfolio. We evaluate all of our gas supply contracts at inception to determine if they meet the definition of a derivative in accordance with accounting guidance, whether any derivative contracts qualify as "normal purchases and normal sales" and would not be subject to fair value accounting requirements, or if they can be designated for hedge accounting purposes. Beginning with the year ended October 31, 2016, we have certain long-dated, fixed quantity forward gas supply contracts that meet the definition of derivative instruments that should be recorded at fair value. We have included gas supply contracts requiring fair value accounting in "
Other
" in "
Current Liabilities
" and "
Deferred Credits and Other Liabilities
" in the
Consolidated Balance Sheets
. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our PGA clauses in the jurisdictions in which we operate, we have recorded the offset to an applicable regulatory asset.
Fair Value Measurements and Quantitative and Qualitative Disclosures
We use gas purchase options as financial instruments that are not designated as hedges for accounting purposes to mitigate commodity price risk for our customers. Based on our continual evaluation under derivative accounting standards of contracts added to our supply portfolio, we have determined that certain of these long-dated, fixed quantity gas supply contracts that became effective beginning with the year ended October 31, 2016 should be recorded at fair value.
The costs of our gas cost hedging plans 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 designated hedging instruments under derivative accounting standards. As required by the accounting guidance, we present our derivative positions at fair value on a gross basis and have only asset positions for all periods presented for the fair value of our gas purchase options held for our utility operations. There are
no
gas purchase
options in a liability position, and we have posted
no
cash collateral nor received any cash collateral under our master netting arrangements. Therefore, we have no offsetting disclosures for financial assets or liabilities for our gas purchase options held for utility operations. Our gas purchase options held for utility operations are held with one broker as our counterparty. We have only liability positions for our gas supply derivative contracts presented at fair value that are held for our utility operations.
We also have trading securities that are held in rabbi trusts established for certain deferred compensation plans and are included in "
Other
" within "
Investments and Other Assets
" on 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 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 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 "Fair Value Measurements" in
Note 1
.
The following table sets forth, by level of the fair value hierarchy, our financial assets that were accounted for at fair value on a recurring basis as of
October 31, 2016
and
2015
. 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 within the fair value hierarchy levels. We have had
no
transfers between any level during the years ended
October 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2016
|
|
|
|
|
Significant
|
|
|
|
Effects of
|
|
|
|
|
Quoted Prices
|
|
Other
|
|
Significant
|
|
Netting and
|
|
|
|
|
in Active
|
|
Observable
|
|
Unobservable
|
|
Cash Collateral
|
|
Total
|
|
|
Markets
|
|
Inputs
|
|
Inputs
|
|
Receivables/
|
|
Carrying
|
(in millions)
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Payables
|
|
Value
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
1.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.5
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
Mutual funds
|
|
3.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3.7
|
|
Total fair value assets
|
|
$
|
5.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5.7
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
Derivatives - gas supply contracts held for utility operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
187.9
|
|
|
$
|
—
|
|
|
$
|
187.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2015
|
|
|
|
|
Significant
|
|
|
|
Effects of
|
|
|
|
|
Quoted Prices
|
|
Other
|
|
Significant
|
|
Netting and
|
|
|
|
|
in Active
|
|
Observable
|
|
Unobservable
|
|
Cash Collateral
|
|
Total
|
|
|
Markets
|
|
Inputs
|
|
Inputs
|
|
Receivables/
|
|
Carrying
|
(in millions)
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Payables
|
|
Value
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
1.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.3
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
Mutual funds
|
|
4.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4.4
|
|
Total fair value assets
|
|
$
|
6.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6.2
|
|
In our discounted cash flow valuation, our unobservable input was the price of natural gas in future periods past the observable market price, commencing in the middle of the contract terms. The unobservable prices of our gas supply derivative contracts in the mid to later years of contract terms ranged from
$2.60
to
$4.47
per dekatherm.
The fair value of our gas supply derivative contracts is sensitive to the pricing differential of various natural gas indexes relevant to those particular contracts. An increased market price spread between the indexes would increase the fair value of the derivative and result in an unrealized loss, while conversely, a decreased market price spread would decrease the fair value of the derivative and result in an unrealized gain.
The following is a reconciliation of the gas supply derivative liabilities that are classified as Level 3 in the fair value hierarchy for the twelve months ended October 31, 2016.
|
|
|
|
|
(in millions)
|
2016
|
Gas supply derivative liabilities, beginning balance
|
$
|
—
|
|
Realized and unrealized losses:
|
|
Recorded to regulatory assets *
|
187.9
|
|
Purchases, sales and settlements (net)
|
—
|
|
Transfer in/out of Level 3
|
—
|
|
Gas supply derivative liabilities, ending balance
|
$
|
187.9
|
|
|
|
* Included are the actual costs recorded within "Cost of natural gas" on the Consolidated Statements of Operations and Comprehensive Income due to the confidential nature of contract pricing.
|
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 hedge commodity price risks, but not for speculative trading. The strategy and objective of our hedging programs are to use these financial instruments to reduce gas cost volatility for our customers.
Our regulated utility operations gas purchase options 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 gas purchase options are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to these gas purchase options 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 operation of the hedging programs of the regulated utility operations as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as "
Current Regulatory Assets
" or amounts due to customers included as "
Current Regulatory Liabilities
" in
Note 3
and recognized on the
Consolidated Statements of Operations and Comprehensive Income
as a component of "Cost of natural gas" when the related costs are recovered through our rates. These gas purchase options are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.
Our gas supply derivatives are generally based on unobservable inputs and are classified within Level 3. In accordance with regulatory provisions for rate-regulated activities, any gains and losses associated with these derivatives are reflected as a regulatory asset or liability, as appropriate, in "
Derivatives - gas supply contracts held for utility operations
" in
Note 3
.
The following table presents the fair value and balance sheet classification of our gas purchase options and gas supply derivative contracts for natural gas as of
October 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
Fair Value of Derivative Instruments
|
(in millions)
|
|
2016
|
|
2015
|
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
|
Financial Asset Instruments:
|
|
|
|
|
Current Assets - Gas purchase derivative assets
|
|
$
|
1.5
|
|
|
$
|
1.3
|
|
Nonfinancial Liabilities Instruments:
|
|
|
|
|
Current Liabilities - Gas supply derivative liabilities
|
|
41.5
|
|
|
|
Noncurrent Liabilities - Gas supply derivative liabilities
|
|
146.4
|
|
|
|
The following table presents the impact that our gas purchase options not designated as hedging instruments under derivative accounting standards would have had on the
Consolidated Statements of Operations and Comprehensive Income
for the twelve months ended
October 31, 2016
and
2015
, absent the regulatory treatment under our approved PGA procedures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of
|
|
Amount of
|
|
Location of Gain (Loss)
|
|
|
Gain (Loss) Recognized
|
|
Gain (Loss) Deferred
|
|
Recognized through
|
|
|
on Derivative Instruments
|
|
Under PGA Procedures
|
|
PGA Procedures
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended
|
|
Twelve Months Ended
|
|
|
|
|
October 31,
|
|
October 31,
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
Gas purchase options
|
|
$
|
(5.2
|
)
|
|
$
|
(4.4
|
)
|
|
$
|
(5.2
|
)
|
|
$
|
(4.4
|
)
|
|
Cost of natural gas
|
In Tennessee, the cost of gas purchase 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 as approved by the TRA. In South Carolina, the costs of gas purchase options are subject to and are approved for recovery under the terms and conditions of our gas hedging plan as approved by the PSCSC. In North Carolina, the costs associated with our hedging program are treated as gas costs subject to an annual cost review proceeding by the NCUC.
We would have recorded an unrealized loss of
$187.9 million
related to our gas supply derivative contracts in the
Consolidated Statements of Operations and Comprehensive Income
for the twelve months ended
October 31, 2016
, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas supply derivative contracts in the
Consolidated Statements of Operations and Comprehensive Income
as a component of "Cost of natural gas" in the month purchased.
Our long-term debt is presented at net cost. 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 benchmark with consideration given to maturities, redemption terms and credit ratings. The principal and fair value of our long-term debt, which is classified within Level 2, are shown below.
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Principal
|
|
Fair Value
|
As of October 31, 2016
|
|
$
|
1,835.0
|
|
|
$
|
2,061.2
|
|
As of October 31, 2015
|
|
1,575.0
|
|
|
1,720.6
|
|
Credit and Counterparty Risk
We are exposed to credit risk as a result of transactions for the purchase and sale of natural gas and related products and services and management agreements of our transportation capacity, storage capacity and supply contracts with major companies in the energy industry and within our utility operations serving industrial, commercial, power generation, residential and municipal energy consumers. These transactions have historically occurred in the gulf coast and mid-west regions of the United States, but our portfolio is being rebalanced and diversified by adding gas supply from northeastern United States gas supply basins. Credit risk associated with receivables for the natural gas distribution operations is mitigated by the large number of individual customers and diversity in our customer base.
We enter into contracts with third parties to buy and sell natural gas. A significant portion of these transactions are with, or are associated with, energy producers, utility companies, off-system municipalities and natural gas marketers. The amount included in "Receivables" within "
Current Assets
" on the
Consolidated Balance Sheets
attributable to these entities amounted to
$14.2 million
, or approximately
31%
of our gross receivables as of
October 31, 2016
. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract, or in situations where counterparties do not have investment-grade or functionally equivalent credit ratings, our policy requires credit enhancements that include letters of credit or parental guaranties. In either circumstance, our 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 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 believe, based on our credit policies as of
October 31, 2016
, that our financial position, results of operations and cash flows will not be materially affected as a result of nonperformance by any single counterparty.
Natural gas distribution operating revenues and related receivables are generated from state-regulated utility natural gas sales and transportation to over one million residential, commercial and industrial customers, including power generation and municipal customers, located in North Carolina, South Carolina and Tennessee. A change in economic conditions may affect the ability of customers to meet their obligations. We have mitigated our exposure to the risk of non-payment of utility bills by our customers. Gas costs related to uncollectible accounts are recovered through PGA procedures in all jurisdictions. To manage the non-gas cost customer credit risk, we evaluate credit quality and payment history and may require cash deposits from our high risk customers that do not satisfy our predetermined credit standards until a satisfactory payment history has been established. Significant increases in the price of natural gas and colder-than-normal weather can slow our collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal receivables; however, we believe that our provision for possible losses on uncollectible receivables are adequate for our credit loss exposure.
Risk Management
Our financial derivative instruments do not contain material credit-risk-related or other contingent features that could require us to make accelerated payments.
We seek to identify, assess, monitor and manage risk in accordance with established comprehensive risk management policies under the direction of Duke Energy’s Chief Executive Officer (CEO) and Chief Financial Officer. The Finance and Risk Management Committee of Duke Energy's Board of Directors receives periodic updates from Duke Energy's Chief Risk Officer and other members of management on market risk positions, corporate exposures, and overall risk management activities. The Chief Risk Officer is responsible for the overall governance of managing commodity price risk, including monitoring exposure limits.
7
.
Commitments and Contingencies
Leases
We lease certain buildings, land and equipment for use in our operations under noncancelable operating leases. We account for these leases by recognizing the future minimum lease payments as expense on a straight-line basis over the respective minimum lease terms under current accounting guidance.
Operating lease payments for the years ended
October 31, 2016
,
2015
and
2014
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Operating lease payments
(1)
|
|
$
|
4.8
|
|
|
$
|
5.0
|
|
|
$
|
4.7
|
|
|
|
|
|
|
|
|
(1)
Operating lease payments do not include payments for common area maintenance, utilities or tax payments.
|
Future minimum lease obligations for the next five years ending October 31 and thereafter are as follows.
|
|
|
|
|
(in millions)
|
|
2017
|
$
|
4.7
|
|
2018
|
4.6
|
|
2019
|
4.4
|
|
2020
|
4.5
|
|
2021
|
4.6
|
|
Thereafter
|
19.8
|
|
Total
|
$
|
42.6
|
|
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. Costs arising from the gas supply commodity and capacity commitments, while significant, are pass-through costs to our customers and are fully recoverable subject to our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for fixed payments under pipeline and storage capacity contracts are up to
nineteen years
. The time periods for fixed payments of reservation fees under gas supply contracts are up to
two years
. The time period for the gas supply purchase commitments is up to
fifteen 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 are up to
five years
. Other purchase obligations consist primarily of commitments for pipeline products, equipment and contractors.
Certain storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the FERC in order to 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 on the
Consolidated Statements of Operations and Comprehensive Income
as part of gas purchases and included within "Cost of natural gas."
As of
October 31, 2016
, future unconditional purchase obligations for the next five years ending October 31 and thereafter are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pipeline
|
|
Gas Supply
|
|
Gas Supply
|
|
Telecommunications
|
|
|
|
|
|
|
and Storage
|
|
Reservation
|
|
Purchase
|
|
and Information
|
|
|
|
|
(in millions)
|
|
Capacity
|
|
Fees
|
|
Commitments
|
|
Technology
|
|
Other
|
|
Total
|
2017
|
|
$
|
170.0
|
|
|
$
|
2.2
|
|
|
$
|
124.4
|
|
|
$
|
9.6
|
|
|
$
|
62.1
|
|
|
$
|
368.3
|
|
2018
|
|
143.8
|
|
|
—
|
|
|
96.8
|
|
|
5.4
|
|
|
—
|
|
|
246.0
|
|
2019
|
|
133.4
|
|
|
—
|
|
|
96.8
|
|
|
5.2
|
|
|
—
|
|
|
235.4
|
|
2020
|
|
115.4
|
|
|
—
|
|
|
97.1
|
|
|
4.5
|
|
|
—
|
|
|
217.0
|
|
2021
|
|
113.7
|
|
|
—
|
|
|
96.8
|
|
|
1.1
|
|
|
—
|
|
|
211.6
|
|
Thereafter
|
|
405.5
|
|
|
—
|
|
|
896.1
|
|
|
—
|
|
|
—
|
|
|
1,301.6
|
|
Total
|
|
$
|
1,081.8
|
|
|
$
|
2.2
|
|
|
$
|
1,408.0
|
|
|
$
|
25.8
|
|
|
$
|
62.1
|
|
|
$
|
2,579.9
|
|
Legal
We have only routine litigation in the normal course of business. We do not expect any of these routine litigation matters to have a material effect, either individually or in the aggregate, on our financial position, results of operations or cash flows.
Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had
$1.7 million
in letters of credit that were issued and outstanding as of
October 31, 2016
. See
Note 5
for additional information concerning letters of credit.
Surety Bonds
In the normal course of business, we are occasionally required to provide financial commitments in the form of surety bonds to third parties as a guarantee of our performance on commercial obligations. We have agreements that indemnify certain issuers of surety bonds against losses that they may incur as a result of executing surety bonds on our behalf. If we were to fail to perform according to the terms of the underlying contract, any draws upon surety bonds issued on our behalf would then trigger our payment obligation to the surety bond issuer. As of
October 31, 2016
, we had open surety bonds with a total contingent obligation of
$6.4 million
.
Environmental Matters
Our
three
regulatory commissions have authorized us to utilize deferral accounting in connection with costs for environmental assessments and cleanups. Accordingly, we have established regulatory assets for actual environmental costs incurred and have recorded estimated environmental liabilities, including those for our manufactured gas plant (MGP) sites, LNG facilities and underground storage tanks (USTs).
We share environmental responsibility for various MGP sites with Duke Energy, and one of its subsidiaries. In 1997, we entered into a settlement with Duke Energy with respect to
nine
MGP sites that we have owned, leased or operated 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.
In connection with our 2003 North Carolina Natural Gas Corporation (NCNG) acquisition and prior to its closing, several MGP sites owned by NCNG were transferred to a wholly owned subsidiary of Progress Energy, Inc. (Progress), a subsidiary of Duke Energy since July 2012. Progress has complete responsibility for performing all of the former 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 were 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.
As of
October 31, 2016
, our estimated undiscounted environmental liability totaled
$1.0 million
, and consisted of
$0.8 million
for MGP sites for which we retain responsibility and
$0.2 million
for USTs, our Huntersville LNG facility and other environmental costs. The costs we reasonably expect to incur are estimated using assumptions based on actual costs incurred, the timing of future payments and inflation factors, among others. For the period ending
October 31, 2016
, we incurred
$0.1 million
of remediation costs related to our MGP sites and Huntersville LNG facility.
We continue to expand our sampling of our pipelines for coatings containing asbestos. Additionally, we continue to educate our employees on the hazards of asbestos and implemented procedures for removing these coatings from our pipelines when we must excavate and expose portions of the pipeline.
As of
October 31, 2016
, our regulatory assets for unamortized environmental costs in our three-state territory totaled
$5.1 million
. We received approval from the TRA to recover
$2.0 million
of our deferred Tennessee environmental costs over an
eight
-year period beginning March 2012, pursuant to the 2012 general rate case proceeding in Tennessee. We will seek recovery of the remaining Tennessee balance in future rate proceedings. The approval by the NCUC in December 2013 of the settlement of the general rate proceeding allowed recovery of
$6.3 million
of our deferred North Carolina environmental costs over a
five
-year period beginning January 2014.
Further evaluation of the MGP, LNG and UST sites could significantly affect recorded amounts; however, we believe that the ultimate resolution of these matters will not have a material effect on our financial position, results of operations or cash flows.
8
.
Employee Benefit Plans
We recognize all obligations related to our defined benefit pension and other postretirement employee benefits (OPEB) plans and quantify the plans’ funded status as an asset or liability on the Consolidated Balance Sheets. We measure the plans’ assets and obligations that determine our funded status as of the end of our fiscal year, October 31. Our plans’ assets are recorded at fair value. In accordance with accounting guidance, we are required to recognize as a component of OCI the changes in the funded status that occurred during the year that are not recognized as part of net periodic benefit cost; however, in 2006, we obtained regulatory treatment from the NCUC, the PSCSC and the TRA to record the amount that would have been recorded in accumulated OCI as a regulatory asset or liability as the future recovery of pension and OPEB costs is probable. To date, our regulators have allowed future recovery of our pension and OPEB costs. For the impact of this regulatory treatment, see the following table of actuarial plan information that specifies the amounts not yet recognized as a component of cost and recognized as a regulatory asset or liability.
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 is 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 an applicable year. 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. The qualified pension plan is closed to employees hired after December 31, 2007. Employees hired prior to January 1, 2008 continue to participate in the 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 a specific formula plus the accrued benefit calculated under a second formula for years of service after December 31, 2007, or the benefit for all years of service up to 35 years under the second formula.
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.
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.
We consider 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, where applicable.
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 the following types of investments:
|
|
•
|
Fixed income securities: includes U.S. treasuries, corporate bonds, high yield debt (bank loans), asset-backed securities and derivatives. The derivatives in the fixed income portfolio are fully collateralized. The investment guidelines limit liabilities created with derivatives in the fixed income portfolio to cash equivalents plus
10%
of the portfolio’s market value. The aggregate risk exposure of the plan can be no greater than that which could be achieved without using derivatives.
|
|
|
•
|
Equity securities: includes large cap growth, large cap value and small cap domestic equity securities, as well as international equity.
|
|
|
•
|
Real estate: includes a diversified global real estate investment trust fund.
|
|
|
•
|
Other investments: includes commodities, hedge funds and private equity funds that follow several diversified strategies.
|
The target and actual allocations of the qualified pension plan's assets are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
Target
|
|
Assets as of October 31,
|
Asset Allocations
|
|
Allocation
|
|
2016
|
|
2015
|
Fixed income securities
|
|
45
|
%
|
|
46
|
%
|
|
46
|
%
|
Equity securities
|
|
35
|
%
|
|
33
|
%
|
|
34
|
%
|
Real estate
|
|
5
|
%
|
|
5
|
%
|
|
5
|
%
|
Cash and cash equivalents
|
|
—
|
%
|
|
2
|
%
|
|
1
|
%
|
Other investments
|
|
15
|
%
|
|
14
|
%
|
|
14
|
%
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
Employees hired or rehired after December 31, 2007 cannot participate in the qualified pension plan but are participants in the 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 up to the Internal Revenue Service (IRS) compensation limit. The participant is vested in this plan after
three years
of service. During the year ended
October 31, 2016
,
2015
and
2014
, we contributed
$1.8 million
,
$1.4 million
and
$0.9 million
, respectively, to the MPP plan.
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 hired prior to January 1, 2008 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 hired after January 1, 2008 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. Employees who meet the eligibility requirements to retire also receive a life insurance benefit of
$15,000
.
Prior to January 1, 2016, employees who met the eligibility requirement noted above or were part of a "grandfathered" group received either full or partial retiree coverage paid by us, subject to certain participation limits. Retirees were responsible for the full cost of dependent coverage.
Effective January 1, 2016, we replaced the existing retiree medical and dental group coverage for eligible retirees with a tax-free Health Reimbursement Arrangement (HRA). Under the new HRA, participating eligible retirees and their dependents may qualify for a subsidy each year through the HRA account to help purchase medical and dental coverage available on public and private health care exchanges using a tax-advantaged account funded by us to pay for allowable medical and dental expenses.
OPEB plan assets are comprised of mutual funds within a 401(h) account and Voluntary Employees’ Beneficiary Association trusts. The investment philosophy is similar to the investment philosophy of the qualified pension plan as discussed above, except the OPEB fixed income portfolio does not include derivatives. We do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
The target and actual allocations of the OPEB plan's assets are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Target
|
|
|
Assets as of October 31,
|
Asset Allocations
|
|
Allocation
|
|
|
2016
|
|
2015
|
Fixed income securities
|
|
45
|
%
|
(1)
|
|
47
|
%
|
|
47
|
%
|
Equity securities
|
|
47
|
%
|
|
|
44
|
%
|
|
44
|
%
|
Real estate
|
|
5
|
%
|
|
|
5
|
%
|
|
5
|
%
|
Cash and cash equivalents
|
|
3
|
%
|
|
|
4
|
%
|
|
4
|
%
|
Total
|
|
100
|
%
|
|
|
100
|
%
|
|
100
|
%
|
|
|
|
|
|
|
|
|
(1)
Includes 5% target allocation to high yield fixed income.
|
Supplemental Executive Retirement Plans
We have pension liabilities related to supplemental executive retirement plans (SERPs) for certain former employees, non-employee directors or surviving spouses. There are
no
assets related to these SERPs, and no additional benefits accrue to the participants. Payments to the participants are made from operating funds during the year. Actuarial information for these nonqualified plans is presented below.
We have a non-qualified defined contribution restoration plan (DCR plan) for certain officers at the vice president level and above where benefits payable under the plan are informally funded annually through a rabbi trust with a bank as the trustee. We contribute
13%
of the total cash compensation (base salary, short-term incentive and MVP incentive) that exceeds the IRS compensation limit to the DCR plan account of each covered executive. Participants may not contribute to the DCR plan. In accordance with the Merger Agreement, the account balances were subject to accelerated vesting effective with the consummation of the Acquisition with distribution occurring upon the participant's separation of service from the Company.
Prior to the Acquisition, we had a voluntary deferred compensation plan for the benefit of all director-level employees and officers, where we made
no
contributions to this plan. Participants could defer a percentage of their base salary and annual incentive pay in accordance with the plan. Benefits under this plan, known as the Voluntary Deferral Plan, were informally funded monthly through a rabbi trust with a bank as the trustee. In accordance with the Merger Agreement, the account balances were subject to accelerated distribution effective with the consummation of the Acquisition.
Our funding to the DCR plan account for the years ended
October 31, 2016
and
2015
, and the amounts recorded as liabilities for these two deferred compensation plans as of
October 31, 2016
and
2015
, are presented below.
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
Funding
|
|
$
|
0.5
|
|
|
$
|
0.5
|
|
Liability
|
|
4.7
|
|
|
5.3
|
|
We provide term life insurance policies for certain officers at the vice president level and above who were former participants in a terminated SERP; the level of the insurance benefit is dependent upon the level of the benefit provided under the terminated SERP. These life insurance policies are owned exclusively by each officer. Premiums on these policies are paid and expensed. We also 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 was
$0.1 million
for the years ended
October 31, 2016
,
2015
and
2014
.
Actuarial Plan Information
A reconciliation of changes in the plans’ benefit obligations and fair value of assets for the years ended
October 31, 2016
and
2015
, a statement of the funded status and the amounts reflected in the
Consolidated Balance Sheets
for the years ended
October 31, 2016
and
2015
, and the weighted average assumptions used in the measurement of the benefit obligations as of
October 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
Nonqualified Pension
|
|
Other Benefits
|
(in millions)
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Accumulated benefit obligation at year end
|
|
$
|
296.3
|
|
|
$
|
263.1
|
|
|
$
|
4.6
|
|
|
$
|
5.5
|
|
|
N/A
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in projected benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
Obligation at beginning of year
|
|
$
|
311.5
|
|
|
$
|
302.7
|
|
|
$
|
5.5
|
|
|
$
|
5.9
|
|
|
$
|
37.6
|
|
|
$
|
37.8
|
|
Service cost
|
|
10.6
|
|
|
11.4
|
|
|
—
|
|
|
—
|
|
|
1.2
|
|
|
1.2
|
|
Interest cost
|
|
9.5
|
|
|
12.0
|
|
|
0.2
|
|
|
0.2
|
|
|
1.3
|
|
|
1.5
|
|
Plan amendments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.9
|
)
|
Plan settlements
|
|
—
|
|
|
—
|
|
|
(0.9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Actuarial loss (gain)
|
|
34.1
|
|
|
3.5
|
|
|
0.3
|
|
|
(0.1
|
)
|
|
1.6
|
|
|
1.7
|
|
Participant contributions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.6
|
|
Administrative expenses
|
|
(0.5
|
)
|
|
(0.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit payments
|
|
(13.5
|
)
|
|
(17.5
|
)
|
|
(0.5
|
)
|
|
(0.5
|
)
|
|
(2.5
|
)
|
|
(3.3
|
)
|
Obligation at end of year
|
|
351.7
|
|
|
311.5
|
|
|
4.6
|
|
|
5.5
|
|
|
39.3
|
|
|
37.6
|
|
Change in fair value of plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value at beginning of year
|
|
329.3
|
|
|
336.4
|
|
|
—
|
|
|
—
|
|
|
27.5
|
|
|
27.7
|
|
Actual return on plan assets
|
|
17.6
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
1.1
|
|
|
0.3
|
|
Employer contributions
|
|
10.0
|
|
|
10.0
|
|
|
1.4
|
|
|
0.5
|
|
|
2.6
|
|
|
2.2
|
|
Participant contributions
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.6
|
|
Administrative expenses
|
|
(0.5
|
)
|
|
(0.6
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Plan settlements
|
|
—
|
|
|
—
|
|
|
(0.9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Benefit payments
|
|
(13.5
|
)
|
|
(17.5
|
)
|
|
(0.5
|
)
|
|
(0.5
|
)
|
|
(2.5
|
)
|
|
(3.3
|
)
|
Fair value at end of year
|
|
342.9
|
|
|
329.3
|
|
|
—
|
|
|
—
|
|
|
28.8
|
|
|
27.5
|
|
Funded status at year end - (under) over
|
|
$
|
(8.8
|
)
|
|
$
|
17.8
|
|
|
$
|
(4.6
|
)
|
|
$
|
(5.5
|
)
|
|
$
|
(10.5
|
)
|
|
$
|
(10.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent assets
|
|
$
|
—
|
|
|
$
|
17.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Current liabilities
|
|
—
|
|
|
—
|
|
|
(0.5
|
)
|
|
(0.5
|
)
|
|
—
|
|
|
—
|
|
Noncurrent liabilities
|
|
(8.8
|
)
|
|
—
|
|
|
(4.1
|
)
|
|
(5.0
|
)
|
|
(10.5
|
)
|
|
(10.1
|
)
|
Net amount recognized
|
|
$
|
(8.8
|
)
|
|
$
|
17.8
|
|
|
$
|
(4.6
|
)
|
|
$
|
(5.5
|
)
|
|
$
|
(10.5
|
)
|
|
$
|
(10.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Not Yet Recognized as a Component
|
|
|
|
|
|
|
|
|
|
|
|
|
of Cost and Recognized in a Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory Account:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized prior service credit (cost)
|
|
$
|
10.7
|
|
|
$
|
12.8
|
|
|
$
|
—
|
|
|
$
|
(0.2
|
)
|
|
$
|
1.5
|
|
|
$
|
1.9
|
|
Unrecognized actuarial loss
|
|
(153.1
|
)
|
|
(120.5
|
)
|
|
(1.5
|
)
|
|
(1.6
|
)
|
|
(9.1
|
)
|
|
(7.2
|
)
|
Regulatory asset
|
|
(142.4
|
)
|
|
(107.7
|
)
|
|
(1.5
|
)
|
|
(1.8
|
)
|
|
(7.6
|
)
|
|
(5.3
|
)
|
Cumulative employer contributions in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
excess of cost
|
|
133.6
|
|
|
125.5
|
|
|
(3.1
|
)
|
|
(3.7
|
)
|
|
(2.9
|
)
|
|
(4.8
|
)
|
Net amount recognized
|
|
$
|
(8.8
|
)
|
|
$
|
17.8
|
|
|
$
|
(4.6
|
)
|
|
$
|
(5.5
|
)
|
|
$
|
(10.5
|
)
|
|
$
|
(10.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average assumptions used in the measurement of
|
|
|
|
|
|
|
|
|
|
|
|
|
the benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
3.80
|
%
|
|
4.34
|
%
|
|
3.80
|
%
|
|
3.85
|
%
|
|
3.80
|
%
|
|
4.38
|
%
|
Rate of compensation increase
|
|
4.05
|
%
|
|
4.07
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
Net periodic benefit cost components for the years ended
October 31, 2016
,
2015
and
2014
and the weighted average assumptions used to determine net period benefit cost as of
October 31, 2016
,
2015
and
2014
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
Nonqualified Pension
|
|
Other Benefits
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
|
2014
|
Service cost
|
|
$
|
10.6
|
|
|
$
|
11.4
|
|
|
$
|
10.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.2
|
|
|
$
|
1.2
|
|
|
$
|
1.1
|
|
Interest cost
|
|
9.5
|
|
|
12.0
|
|
|
11.7
|
|
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
|
1.3
|
|
|
1.5
|
|
|
1.5
|
|
Expected return on plan assets
|
|
(24.0
|
)
|
|
(23.6
|
)
|
|
(22.5
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.8
|
)
|
|
(1.8
|
)
|
|
(1.8
|
)
|
Amortization of prior service (credit)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
cost
|
|
(2.2
|
)
|
|
(2.2
|
)
|
|
(2.2
|
)
|
|
0.2
|
|
|
0.2
|
|
|
0.2
|
|
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
|
8.0
|
|
|
8.7
|
|
|
7.7
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
Settlement loss recognized
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Net periodic benefit cost
|
|
1.9
|
|
|
6.3
|
|
|
5.6
|
|
|
0.7
|
|
|
0.5
|
|
|
0.5
|
|
|
0.8
|
|
|
0.9
|
|
|
0.8
|
|
Other changes in plan assets and benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
obligation recognized through
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
regulatory asset or liability:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
(1.9
|
)
|
|
—
|
|
Net loss (gain)
|
|
40.5
|
|
|
26.2
|
|
|
14.4
|
|
|
0.3
|
|
|
(0.1
|
)
|
|
1.0
|
|
|
2.4
|
|
|
3.2
|
|
|
3.6
|
|
Amounts recognized as a component of
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of net loss
|
|
(8.0
|
)
|
|
(8.7
|
)
|
|
(7.7
|
)
|
|
—
|
|
|
(0.1
|
)
|
|
(0.1
|
)
|
|
(0.4
|
)
|
|
—
|
|
|
—
|
|
Settlement loss recognized
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Prior service credit (cost)
|
|
2.2
|
|
|
2.2
|
|
|
2.2
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
|
(0.2
|
)
|
|
0.3
|
|
|
—
|
|
|
—
|
|
Total recognized in regulatory asset
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(liability)
|
|
34.7
|
|
|
19.7
|
|
|
8.9
|
|
|
(0.2
|
)
|
|
(0.4
|
)
|
|
1.2
|
|
|
2.3
|
|
|
1.3
|
|
|
3.6
|
|
Total recognized in net periodic benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and regulatory asset
|
|
$
|
36.6
|
|
|
$
|
26.0
|
|
|
$
|
14.5
|
|
|
$
|
0.5
|
|
|
$
|
0.1
|
|
|
$
|
1.7
|
|
|
$
|
3.1
|
|
|
$
|
2.2
|
|
|
$
|
4.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average assumptions used to determine the net periodic benefit cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate
|
|
4.34
|
%
|
|
4.13
|
%
|
|
4.55
|
%
|
|
3.85
|
%
|
|
3.69
|
%
|
|
3.98
|
%
|
|
4.38
|
%
|
|
4.03
|
%
|
|
4.44
|
%
|
Expected long-term rate of return on plan assets
|
|
7.25
|
%
|
|
7.50
|
%
|
|
7.75
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
7.25
|
%
|
|
7.50
|
%
|
|
7.75
|
%
|
Rate of compensation increase
|
|
4.07
|
%
|
|
3.68
|
%
|
|
3.72
|
%
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
|
N/A
|
|
The
2017
estimated amortization of the following items for our plans, which are recorded as a regulatory asset or liability instead of accumulated OCIL discussed above, are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified
|
|
Nonqualified
|
|
Other
|
(in millions)
|
|
Pension
|
|
Pension
|
|
Benefits
|
Amortization of unrecognized prior service credit
|
|
$
|
(2.2
|
)
|
|
$
|
—
|
|
|
$
|
(0.3
|
)
|
Amortization of unrecognized actuarial loss
|
|
11.3
|
|
|
0.1
|
|
|
0.7
|
|
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 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, meaning that
20%
of the prior five years’ asset gains and losses are recognized each year. This method has been applied consistently in all years presented in the Consolidated Financial Statements.
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 amortization period used for the purposes mentioned above for the NCNG SERP and the Piedmont SERP is an expected future lifetime as there are no active members in these plans. The method of amortization in all cases is straight-line.
In addition to the assumptions in the above table, we also use subjective factors such as withdrawal and mortality rates in determining benefit obligations for all of our benefit plans. Our assumed mortality rates incorporate the new set of mortality tables issued by the Society of Actuaries in October 2014. We also applied the updated projection scale issued by the Society of Actuaries in October 2016.
We anticipate that we will contribute the following amounts to our plans during the twelve month period ending October 31,
2017
.
|
|
|
|
|
(in millions)
|
|
Qualified pension plan
|
$
|
10.0
|
|
Nonqualified pension plans
|
0.5
|
|
MPP plan
|
2.1
|
|
OPEB plan
|
2.2
|
|
The Pension Protection Act of 2006 (PPA) specified funding requirements for single employer defined benefit pension plans. We are in compliance with the
100%
funding target established in the PPA.
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 millions)
|
|
Pension
|
|
Pension
|
|
Benefits
|
2017
|
|
$
|
39.6
|
|
|
$
|
0.5
|
|
|
$
|
1.9
|
|
2018
|
|
25.2
|
|
|
0.5
|
|
|
2.1
|
|
2019
|
|
25.0
|
|
|
0.5
|
|
|
2.2
|
|
2020
|
|
24.8
|
|
|
0.4
|
|
|
2.4
|
|
2021
|
|
24.9
|
|
|
0.4
|
|
|
2.4
|
|
2022 – 2026
|
|
126.8
|
|
|
1.7
|
|
|
13.1
|
|
Based on the retiree medical and dental group coverage changing to a HRA where the retiree subsidy provided by Piedmont is fixed and assumed to not increase, we are no longer impacted by the health care cost component (projected health care cost trend rates) for our accumulated postretirement benefit obligation as of October 31, 2016 and 2015.
In fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our plans. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to determine the benefit obligations of the relevant projected cash flows. This change improved the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provided a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit obligation as the change in the service and interest costs is completely offset by the actuarial (gain) loss reported. We accounted for this change as a change in estimate and, accordingly, accounted for it prospectively beginning in 2016.
Effective with the consummation of the Acquisition, we changed the methodology we use to calculate the discount rate for the current year benefit obligation and next year's periodic net benefit cost for our plans. We replaced our full yield curve methodology with a bond selection-settlement portfolio approach used by Duke Energy. The selected bond portfolio is derived from a universe of non-callable corporate bonds rated Aa quality or higher. After the bond portfolio is selected, a single interest rate, which was
3.80%
as of
October 31, 2016
, is determined that equates the present value of the plan's projected benefit payments discounted at this rate with the market value of the bonds selected. This change decreased our total benefit obligations on our plans as of October 31, 2016 by
$2.4 million
.
Fair Value Measurements
Following is a description of the valuation methodologies used for assets measured at fair value in our qualified pension plan.
Cash and cash equivalents – These are Level 1 assets valued at face value as they are primarily cash or cash equivalents. The assets that are Level 2 assets are valued at the market value of the shares held by the plan at the valuation date for a money market mutual fund.
Fixed income securities – These assets include:
|
|
•
|
U.S. treasuries – These are Level 2 assets whose values are based on observable market information including quotes from a quotation reporting system, established market makers or pricing services. This asset class includes long duration fixed income investments.
|
|
|
•
|
Corporate bonds, collateralized mortgage obligations, municipals – These are Level 2 assets valued based on primarily observable market information or broker quotes on a non-active market. This class includes long duration fixed income investments.
|
|
|
•
|
Derivatives – The Level 1 assets are valued using a compilation of observable market information on an active market. The Level 2 assets are valued using broker quotes on a non-active market.
|
Equity securities – These are level 1 assets valued at the market price of the active market on which the individual security is traded.
Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date. Mutual funds with a NAV per share that is not publicly available are classified as Level 2.
Common trust fund – These are Level 2 assets held in a common trust fund in which we own interests that are valued at the NAV of the funds as traded on international exchanges. Currently, there are no restrictions on redemptions for the fund.
Private equity fund of funds – This is a Level 3 asset invested in hedge fund of funds valued based on a quarterly compilation of the financial statements from the underlying partnerships in which the fund invests. There are currently redemption restrictions for this fund. The target allocation for this investment is
3.5%
but is still being funded through capital calls;
$2.6 million
of the original
$12.0 million
subscription remains unfunded. Until a
3.5%
allocation can be achieved, the balance of the
3.5%
allocation is invested in a low-cost equity index fund that tracks the Standard & Poor's 500 Stock Index. Our investment is in various funds that invest in North American companies, allocate capital to private equity funds, invest in venture capital partnerships and private equity partnerships in emerging markets.
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance.
Hedge fund of funds – These investments are 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. Currently, there are no restrictions on redemptions for the fund.
Commodities fund of funds – These investments are in commodities fund of funds that are actively managed through a well-diversified group of underlying managers. Currently, there are no restrictions on redemptions for the fund.
High yield debt (bank loans) – These assets are held in a common trust fund that invest in global bank loans. Currently, there are no restrictions on redemption for the fund.
As stated above, some of our investments for the qualified pension plan have redemption limitations, restrictions and notice requirements which are further explained below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Redemptions
|
|
|
Redemption
|
|
|
|
Notice
|
Investment
|
|
Frequency
|
|
Other Redemption Restrictions
|
|
Period
|
Common trust fund -
International growth
|
|
Monthly
|
|
None
|
|
30 days
|
|
|
|
|
Hedge fund of funds
|
|
Quarterly
|
|
Redeemed in whole or part but not less than the minimum redemption amount for each currency. Redemption within one year of purchase is subject to 1.5% redemption fee. Redeemed on "first in first out" basis. None of our investment is subject to the redemption fee. Fund’s Board of Directors may limit or suspend share redemptions until a further notification ending suspension. No such notification has been received as of October 31, 2016.
|
|
65 days
|
|
|
|
|
Private equity fund of funds
|
|
Limited
|
|
Investors have only very limited withdrawal rights for specific legal or regulatory reasons. Any transfer of interest will be subject to approval.
|
|
(1)
|
|
|
|
|
Commodities fund of funds
|
|
Monthly
|
|
Redemption within one year of purchase is subject to 1% redemption fee. None of our investment is subject to the redemption fee. If 95% or more of the balance is requested, 95% of the balance will be paid within 30 days. Any outstanding balance or interest owed will be paid after the annual audit is complete.
|
|
35 business days
|
|
|
|
|
|
|
|
Bank loans
|
|
Daily
|
|
None
|
|
30 days
|
(1)
The investment cannot be redeemed. We receive distributions only through the liquidation of the underlying assets. The assets are expected to be liquidated over the next
8
to
10
years.
The qualified pension plan’s asset allocations by level within the fair value hierarchy as of
October 31, 2016
and
2015
are presented below. 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 consideration within the fair value hierarchy levels. For further information on a description of the fair value hierarchy, see "Fair Value Measurements" in
Note 1
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension Plan as of October 31, 2016
|
|
(in millions)
|
|
Quoted Prices In Active Markets (Level 1)
|
|
Significant Other Observable Inputs (Level 2)
|
|
Significant Unobservable Inputs (Level 3)
|
|
Total Carrying Value
|
|
Cash and cash equivalents
|
|
$
|
5.1
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
|
$
|
5.9
|
|
|
Fixed income securities
|
|
—
|
|
|
78.9
|
|
|
—
|
|
|
78.9
|
|
|
Equity securities
|
|
44.4
|
|
|
—
|
|
|
—
|
|
|
44.4
|
|
|
Mutual funds
|
|
78.2
|
|
|
55.0
|
|
|
—
|
|
|
133.2
|
|
|
Common trust fund
|
|
—
|
|
|
25.0
|
|
|
—
|
|
|
25.0
|
|
|
Private equity fund of funds
|
|
—
|
|
|
—
|
|
|
8.9
|
|
|
8.9
|
|
|
Other Investments:
|
|
|
|
|
|
|
|
|
|
Hedge fund of funds
|
|
|
|
|
|
|
|
20.0
|
|
(1)
|
Commodities fund of funds
|
|
|
|
|
|
|
|
9.2
|
|
(1)
|
High yield debt (bank loans)
|
|
|
|
|
|
|
|
17.4
|
|
(1)
|
Total assets at fair value
|
|
$
|
127.7
|
|
|
$
|
159.7
|
|
|
$
|
8.9
|
|
|
$
|
342.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension Plan as of October 31, 2015
|
|
(in millions)
|
|
Quoted Prices In Active Markets (Level 1)
|
|
Significant Other Observable Inputs (Level 2)
|
|
Significant Unobservable Inputs (Level 3)
|
|
Total Carrying Value
|
|
Cash and cash equivalents
|
|
$
|
2.8
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
2.9
|
|
|
Fixed income securities
|
|
—
|
|
|
84.1
|
|
|
—
|
|
|
84.1
|
|
|
Equity securities
|
|
44.7
|
|
|
—
|
|
|
—
|
|
|
44.7
|
|
|
Mutual funds
|
|
78.9
|
|
|
42.9
|
|
|
—
|
|
|
121.8
|
|
|
Common trust fund
|
|
—
|
|
|
23.6
|
|
|
—
|
|
|
23.6
|
|
|
Private equity fund of funds
|
|
—
|
|
|
—
|
|
|
8.3
|
|
|
8.3
|
|
|
Other Investments:
|
|
|
|
|
|
|
|
|
|
Hedge fund of funds
|
|
|
|
|
|
|
|
19.8
|
|
(1)
|
Commodities fund of funds
|
|
|
|
|
|
|
|
7.7
|
|
(1)
|
High yield debt (bank loans)
|
|
|
|
|
|
|
|
16.4
|
|
(1)
|
Total assets at fair value
|
|
$
|
126.4
|
|
|
$
|
150.7
|
|
|
$
|
8.3
|
|
|
$
|
329.3
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In accordance with accounting guidance, certain investments that are measured at fair value using the NAV per share (or its equivalent) practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.
|
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
|
|
|
Equity Fund
|
(in millions)
|
|
of Funds
|
Balance, October 31, 2014
|
|
$
|
7.2
|
|
Actual return on plan assets:
|
|
|
Relating to assets still held at the reporting date
|
|
0.4
|
|
Relating to assets sold during the period
|
|
0.6
|
|
Purchases, sales and settlements (net)
|
|
0.1
|
|
Transfer in/out of Level 3
|
|
—
|
|
Balance, October 31, 2015
|
|
8.3
|
|
Actual return on plan assets:
|
|
|
Relating to assets still held at the reporting date
|
|
0.1
|
|
Relating to assets sold during the period
|
|
0.5
|
|
Purchases, sales and settlements (net)
|
|
—
|
|
Transfer in/out of Level 3
|
|
—
|
|
Balance, October 31, 2016
|
|
$
|
8.9
|
|
During the year, the qualified pension plan raises cash from various plan assets in order to fund periodic and lump sum benefit payments. Cash is raised as needed primarily from investments that have exceeded their target allocation and is dependent upon the number of retirees seeking lump sum distributions.
There are significant unobservable inputs used in the fair value measurements of our investment in the private equity fund of funds’ limited partnerships. We are subject to the business risks inherent in the markets in which the partnerships are invested. The success or failure of the underlying businesses of the various partnerships that have been funded would result in a higher or lower fair value measurement.
Following is a description of the valuation methodologies used for assets measured at fair value in our OPEB plan.
Cash and cash equivalents – These are Level 1 assets having maturities of three months or less when purchased and are considered to be cash equivalents.
Mutual funds – These are Level 1 assets valued at the publicly quoted NAV per share computed as of the close of business on our balance sheet date.
The OPEB plan’s asset allocations by level within the fair value hierarchy as of
October 31, 2016
and
2015
are presented below. 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 "Fair Value Measurements" in
Note 1
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits as of October 31, 2016
|
(in millions)
|
|
Quoted Prices In Active Markets (Level 1)
|
|
Significant Other Observable Inputs (Level 2)
|
|
Significant Unobservable Inputs (Level 3)
|
|
Total Carrying Value
|
Cash and cash equivalents
|
|
$
|
1.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.2
|
|
Mutual funds
|
|
27.6
|
|
|
—
|
|
|
—
|
|
|
27.6
|
|
Total assets at fair value
|
|
$
|
28.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
28.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Benefits as of October 31, 2015
|
(in millions)
|
|
Quoted Prices In Active Markets (Level 1)
|
|
Significant Other Observable Inputs (Level 2)
|
|
Significant Unobservable Inputs (Level 3)
|
|
Total Carrying Value
|
Cash and cash equivalents
|
|
$
|
1.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.1
|
|
Mutual funds
|
|
26.4
|
|
|
—
|
|
|
—
|
|
|
26.4
|
|
Total assets at fair value
|
|
$
|
27.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27.5
|
|
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.
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 and compensation limits. We automatically enroll all eligible 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 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. Prior to the Acquisition, participants could direct up to
20%
of their contributions and company matching contributions as an investment in the Piedmont Stock Fund. Employees may change their contribution rate and investments at any time. For the years ended
October 31, 2016
,
2015
and
2014
, we made matching contributions to participant accounts as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
401(k) matching contributions
|
|
$
|
6.9
|
|
|
$
|
6.6
|
|
|
$
|
6.1
|
|
As a result of a plan merger effective in 2001, participants’ accounts in our employee stock ownership plan (ESOP) were transferred into the participants’ 401(k) accounts. Prior to the Acquisition, former ESOP participants could remain invested in Piedmont common stock in their 401(k) plan or could 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 Changes in Equity
as an increase in retained earnings.
9
.
Employee Share-Based Plans
Prior to the Acquisition, under our shareholder approved ICP, eligible officers and other participants were awarded units that paid out depending upon the level of performance achieved by Piedmont during
three
-year incentive plan performance periods. Distribution of those awards were made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans required that a minimum threshold performance level be achieved in order for any award to be distributed.
During 2016, we had
three
series of awards that were outstanding under the approved ICP, with a
three
-year performance period that ended
October 31, 2016
(2016 plan), October 31,
2017
(2017 plan) and October 31,
2018
(2018 plan). For the years ended
October 31, 2016
,
2015
and
2014
, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for these awards based on the fair market value of our stock at the end of each quarter. We re-measured the liability to market value each quarter and at the settlement date of the award.
The Merger Agreement provided for the conversion of the 2016 and 2017 plans shares subject to the ICP awards at the performance level specified in the Merger Agreement into the right to receive
$60
cash per share upon the closing of the transactions contemplated in the Merger Agreement. In November and December 2015, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at their election to accelerate, in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. The acceleration and payout of the ICP awards, at a
96%
election rate by the participants, was done for tax planning purposes and occurred on December 15, 2015. In connection with the election to accelerate the ICP awards, each respective participant executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated ICP awards. With the consummation of the Acquisition, all restrictions were lifted.
The accelerated ICP awards were priced at the NYSE composite closing price of
$56.85
on December 14, 2015. Under the accelerated ICP awards,
162,390
restricted nonvested shares of our common stock were issued to participants, net of shares withheld for applicable federal and state income taxes.
Upon consummation of the Acquisition, the participants that did not accelerate their ICP awards, as discussed above, received $60 per share under the 2016 and 2017 plans, or
$0.3 million
in cash, net of applicable income taxes withheld.
The 2018 plan was approved subsequent to the execution of the Merger Agreement with Duke Energy. Under the Merger Agreement, the 2018 plan performance awards were fully converted into Duke Energy restricted stock unit awards (Duke Energy RSU Award) upon consummation of the Acquisition. Vesting under the Duke Energy RSU Award will be subject to the participant remaining continuously employed by Duke Energy or its affiliates through October 31, 2018. The Duke Energy RSU Award will be subject to
100%
accelerated vesting upon certain types of terminations of employment and prorated accelerated vesting upon retirement. The Duke Energy RSU Award is recorded as an equity award on Duke Energy's balance sheet. As of
October 31, 2016
, our liability related to this plan is
$6.1 million
as reflected in "Accounts payable to affiliated companies" within "Current Liabilities" on the
Consolidated Balance Sheets
.
Also under our approved ICP,
64,700
nonvested restricted stock units (RSUs) were granted to our President and CEO prior to the consummation of the merger (former CEO) in December 2011. During the vesting period, any dividend equivalents were accrued on these stock units and converted into additional units at the same rate and based on the closing price on the same payment date as dividends on our common stock. The vested RSUs were payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, only if he remained an employee on each vesting date. In accordance with the vesting schedule,
20%
of the units vested on December 15, 2014 and
30%
of the units vested on December 15, 2015. The remaining
50%
of the units were scheduled to vest on December 15, 2016 (2016 RSU). The Merger Agreement provided for the conversion of the 2016 RSU into the right to receive $60 cash per share upon closing of the transaction contemplated in the Merger Agreement. Similar to the accelerated ICP awards discussed above, the Compensation Committee of our Board of Directors authorized the accelerated vesting, payment and taxation of the 2016 RSU (accelerated RSU) in the form of restricted shares of our common stock, net of shares withheld for applicable taxes. Our former CEO executed a share repayment agreement dated December 15, 2015 that placed certain restrictions on the accelerated RSU. The acceleration and payout of the accelerated RSU occurred on December 15, 2015. With the consummation of the Acquisition, all restrictions were lifted. For the twelve months ended
October 31, 2016
,
2015
and
2014
, we recorded compensation expense, and prior to the Acquisition, we accrued a liability for nonvested RSUs as applicable, based on the fair market value of our common stock at the end of each quarter. The liability was re-measured to market value each quarter and at the settlement date of the award.
The following table summarizes the settlement of the RSUs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 15, 2014 vesting (20% of the grant)
|
|
December 15, 2015 vesting (30% of the grant)
|
|
Accelerated RSU settled on December 15, 2015 (50% of the grant)
|
|
Shares of common stock issued, including accrued dividends, net of shares withheld for taxes
|
|
7,231
|
|
|
11,732
|
|
|
19,554
|
|
|
NYSE composite closing price
|
|
$
|
37.89
|
|
(1)
|
$
|
56.85
|
|
(2)
|
$
|
56.85
|
|
(2)
|
|
|
|
|
|
|
|
|
(1)
Closing price on December 12, 2014.
|
|
|
|
|
|
|
|
(2)
Closing price on December 14, 2015.
|
|
|
|
|
|
|
|
At the time of distribution of any award under the ICP, the number of shares of common stock issuable was reduced by the withholdings for payment of applicable income taxes for each participant. The participant could elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is
50%
. We present the net shares issued in the
Consolidated Statements of Changes in Equity
and in
Note 4
.
The compensation expense related to the awards under the ICP for the years ended
October 31, 2016
,
2015
and
2014
, and the amounts recorded as liabilities in "Other deferred credits and other liabilities" within "Deferred Credits and Other Liabilities" with the current portion recorded in "Other current liabilities" within "Current Liabilities" on the
Consolidated Balance Sheets
as of
October 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Compensation expense
|
|
$
|
16.1
|
|
(1)
|
$
|
14.2
|
|
|
$
|
8.5
|
|
Tax benefit
|
|
6.1
|
|
|
4.0
|
|
|
2.5
|
|
Liability
|
|
—
|
|
|
22.0
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes $5.3 million incremental expense related to the accelerated ICP and RSU awards, and the conversion of the 2018 plan to a Duke Energy RSU Award. See Note 2 for further information.
|
Equity Plan
Prior to the Acquisition, on a quarterly basis, we issued shares of common stock under the ESPP and accounted for the issuance as an equity transaction. The exercise price was calculated as
95%
of the fair market value on the purchase date of each quarter where the fair value was determined by calculating the average of the high and low trading prices on the purchase date.
In anticipation of the Acquisition, we suspended new investments in our ESPP and resulting issuances of common stock under this plan, effective July 31, 2016. The ESPP was terminated at the closing date of the Acquisition on October 3, 2016.
10
.
Income Taxes
The components of income tax expense for the years ended
October 31, 2016
,
2015
and
2014
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
(in millions)
|
|
Federal
|
|
State
|
|
Federal
|
|
State
|
|
Federal
|
|
State
|
Charged (Credited) to income:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
$
|
27.2
|
|
|
$
|
11.8
|
|
|
$
|
(0.7
|
)
|
|
$
|
1.1
|
|
|
$
|
2.5
|
|
|
$
|
1.8
|
|
Deferred
(1) (2)
|
|
79.6
|
|
|
5.8
|
|
|
77.9
|
|
|
12.1
|
|
|
76.5
|
|
|
14.2
|
|
Tax Credits:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
(0.2
|
)
|
|
—
|
|
|
(0.2
|
)
|
|
—
|
|
|
(0.2
|
)
|
|
—
|
|
Total
|
|
$
|
106.6
|
|
|
$
|
17.6
|
|
|
$
|
77.0
|
|
|
$
|
13.2
|
|
|
$
|
78.8
|
|
|
$
|
16.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Includes benefits from net operating loss (NOL) and tax carryforwards of $91.4 million and $64.3 million for the years ended October 31, 2016 and 2015, respectively.
|
(2)
Includes the anticipated utilization of NOL and tax carryforwards of $19.8 million and $28.6 million for the years ended October 31, 2015 and 2014, respectively.
|
The Protecting Americans from Tax Hikes Act of 2015 enacted in December 2015 and the Tax Increase Prevention Act of 2014, enacted in December 2014, retroactively extended the 50% bonus depreciation which had expired the December of the year preceding the enactments. As a result of the retroactive extensions of bonus depreciation, we were able to claim additional depreciation deductions on our tax returns for the years ended October 31, 2015 and 2014. Prior to the retroactive extensions, we had anticipated utilizing NOL and tax carryforwards to offset taxable income generated in our fiscal years 2015 and 2014 as discussed in note
(2)
in the table above. The benefits from NOL and tax carryforwards in note
(1)
in the table above include
$46.8 million
and
$61.1 million
to record the retroactive impact of the passage of bonus depreciation for the years ended
October 31, 2016
and
2015
, respectively.
A reconciliation of income tax expense at the federal statutory rate to recorded income tax expense for the years ended
October 31, 2016
,
2015
and
2014
is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Federal taxes at 35%
|
|
$
|
111.1
|
|
|
$
|
79.5
|
|
|
$
|
83.5
|
|
State income taxes, net of federal benefit
|
|
11.4
|
|
|
8.6
|
|
|
10.4
|
|
Amortization of investment tax credits
|
|
(0.2
|
)
|
|
(0.2
|
)
|
|
(0.2
|
)
|
Other, net
|
|
1.9
|
|
|
2.3
|
|
|
1.1
|
|
Total
|
|
$
|
124.2
|
|
|
$
|
90.2
|
|
|
$
|
94.8
|
|
|
|
|
|
|
|
|
Effective Tax Rate
|
|
39.1
|
%
|
|
39.7
|
%
|
|
39.7
|
%
|
We and our wholly owned subsidiaries file a consolidated federal income tax return and various state income tax returns. Effective with the Acquisition, our tax year end will change to December 31, 2016, and we and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns. Accordingly, Piedmont and its subsidiaries will file final consolidated income tax returns for the short tax year November 1, 2015 through October 3, 2016. We and our wholly owned subsidiaries will be included in the Duke Energy consolidated income tax returns for the period October 4, 2016 through December 31, 2016. Piedmont and each of our subsidiaries have entered into a tax sharing agreement with Duke Energy and subsidiaries. The tax sharing agreement provides allocation of consolidated tax liabilities and benefits based on amounts participants would incur as separate C-Corporations. Income taxes recorded for the period October 4, 2016 through October 31, 2016 are based on amounts we and our subsidiaries would incur as separate C-Corporations. Current and deferred income tax expense (benefit) of
$40.4 million
and
$(8.7) million
, respectively, was recorded for the period October 4 through October 31, 2016. "
Taxes accrued
" on the
Consolidated Balance Sheets
as of October 31, 2016 includes
$31.5 million
payable to Duke Energy for federal income taxes due under the tax sharing agreement. In accordance with IRS regulations, we and our subsidiaries are jointly and severally liable for the federal tax liability.
As of
October 31, 2016
and
2015
, deferred income taxes consists of the following temporary differences. As discussed in
Note 1
and Note 16, Piedmont early adopted ASU 2015-17, providing guidance that deferred tax assets and
liabilities be classified as noncurrent. With this retrospective adoption, the balance sheet classification of deferred tax assets and liabilities were classified as noncurrent.
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
Deferred tax assets:
|
|
|
|
|
Benefit of tax carryforwards
|
|
$
|
175.4
|
|
|
$
|
84.0
|
|
Revenues and cost of natural gas
|
|
—
|
|
|
3.5
|
|
Employee benefits and compensation
|
|
28.6
|
|
|
22.1
|
|
Revenue requirement
|
|
30.1
|
|
|
26.1
|
|
Property, plant and equipment
|
|
5.3
|
|
|
7.5
|
|
Regulatory asset - gas supply derivative contracts held for utility operations
|
|
70.6
|
|
|
—
|
|
Other
|
|
13.8
|
|
|
10.5
|
|
Total deferred tax assets
|
|
323.8
|
|
|
153.7
|
|
Valuation allowance
|
|
(0.8
|
)
|
|
(0.8
|
)
|
Total deferred tax assets, net
|
|
323.0
|
|
|
152.9
|
|
Deferred tax liabilities:
|
|
|
|
|
Property, plant and equipment
|
|
1,010.8
|
|
|
849.8
|
|
Revenues and cost of natural gas
|
|
20.0
|
|
|
—
|
|
Investments in equity method unconsolidated affiliates
|
|
34.8
|
|
|
44.8
|
|
Deferred costs
|
|
85.0
|
|
|
73.9
|
|
Gas supply derivative liabilities
|
|
70.6
|
|
|
—
|
|
Other
|
|
5.9
|
|
|
13.6
|
|
Total deferred tax liabilities
|
|
1,227.1
|
|
|
982.1
|
|
Net deferred income tax liabilities
|
|
$
|
904.1
|
|
|
$
|
829.2
|
|
As of
October 31, 2016
and
2015
, 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.
A reconciliation of changes in the deferred tax valuation allowance for the years ended
October 31, 2016
,
2015
and
2014
is presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Balance at beginning of year
|
|
$
|
0.8
|
|
|
$
|
0.5
|
|
|
$
|
0.5
|
|
Charged to income tax expense
|
|
—
|
|
|
0.3
|
|
|
—
|
|
Balance at end of year
|
|
$
|
0.8
|
|
|
$
|
0.8
|
|
|
$
|
0.5
|
|
The following table presents the expiration of tax carryforwards.
|
|
|
|
|
|
|
|
(in millions)
|
Amount
|
Expiration Year
|
Federal NOL
|
$
|
163.5
|
|
2020
|
–
|
2036
|
State NOL
|
8.4
|
|
2027
|
–
|
2036
|
Capital loss carryforward
|
0.3
|
|
|
|
2017
|
Charitable carryforward
|
3.2
|
|
2016
|
–
|
2019
|
Total NOL and charitable carryforwards
|
$
|
175.4
|
|
|
|
|
Following the Acquisition, utilization of our tax carryforwards is subject to various limitations. The primary limitation is federal NOL carryforwards of
$159.6 million
are subject to an effective annual limitation of
$31.8 million
.
There were
no
unrecognized tax benefits for the years ended
October 31, 2016
and
2015
.
During our 2016 fiscal year, we finalized the federal income tax examinations for tax years ended October 31, 2010, 2011 and 2012. We are no longer subject to federal examination and with few exceptions, state income tax examinations by tax
authorities for years ended before and including October 31, 2012. The statute of limitations for the tax year ending October 31, 2012 expires February 28, 2017.
During fiscal year 2016, we recognized
$0.5 million
in net interest income related to income taxes.
In July 2013, legislation was passed in North Carolina affecting corporate taxation. The following table presents the corporate income tax rates resulting from this legislation, including subsequent reductions based on certain tax collections exceeding certain thresholds under North Carolina tax statutes.
|
|
|
|
North Carolina Corporate Income Tax Rate *
|
|
Tax Year Rate is Effective
|
6.9%
|
|
Prior to November 1, 2014
|
6.0%
|
|
November 1, 2014 to October 31, 2015
|
5.0%
|
|
November 1, 2015 to October 3, 2016
|
4.0%
|
|
October 4, 2016 to December 31, 2016
|
3.0%
|
|
Beginning January 1, 2017
|
|
|
|
* We record deferred income taxes using the income tax rate in effect when the temporary difference is expected to reverse.
|
As a result of the state income tax rate reductions, we adjusted our deferred income tax balances during fiscal year 2016 and 2015 by approximately
$15.7 million
and
$17.5 million
, respectively, for temporary differences expected to reverse at the lower future rate. We recognized a tax benefit during fiscal years 2016 and 2015 in net income of approximately
$0.6 million
and
$0.5 million
and recorded the remainder of approximately
$15.1 million
and
$17.0 million
during fiscal 2016 and 2015, respectively, as regulatory "Deferred income taxes" as presented in "
Noncurrent Regulatory Liabilities
" in
Note 3
, reflecting a future benefit to our customers. During fiscal 2014, we recorded an additional
$3.0 million
for the difference in the tax rate included in our customers' rates and the rate at which the deferred taxes are expected to reverse. As of
October 31, 2016
, we have approximately
$58.6 million
related to the North Carolina tax rate change included in our "Deferred income taxes" recorded in "
Noncurrent Regulatory Liabilities
." The NCUC will determine the recovery period of this regulatory liability in future proceedings.
11
.
Investments in Unconsolidated Affiliates
The Consolidated Financial Statements include the accounts of our wholly owned subsidiaries who have investments in unconsolidated affiliates. These investments are in joint venture, energy-related businesses that are accounted for under the equity method. Our ownership interest in each entity is included in "
Investments in equity method unconsolidated affiliates
" within "
Investments and Other Assets
" on the
Consolidated Balance Sheets
. Earnings or losses from equity method investments are included in "Equity in earnings of unconsolidated affiliates" within "
Other Income and Expense
" in the
Consolidated Statements of Operations and Comprehensive Income
.
As of
October 31, 2016
, there were
no
amounts that represented undistributed earnings of our 50% or less owned equity method investments in our retained earnings.
Ownership Interests
We have the following membership interests in these companies as of
October 31, 2016
.
|
|
|
|
|
|
Entity Name
|
|
Interest
|
|
Activity
|
Cardinal Pipeline Company, LLC (Cardinal)
|
|
21.49%
|
|
Intrastate pipeline located in North Carolina; regulated by the NCUC
|
Pine Needle LNG Company, LLC (Pine Needle)
|
|
45%
|
|
Interstate LNG storage facility located in North Carolina; regulated by the FERC
|
SouthStar *
|
|
—%
|
|
Energy services company primarily selling natural gas in the unregulated retail gas market to residential, commercial and industrial customers in the eastern United States, primarily Georgia and Illinois
|
Hardy Storage Company, LLC (Hardy Storage)
|
|
50%
|
|
Underground interstate storage facility located in Hardy and Hampshire Counties, West Virginia; regulated by the FERC
|
Constitution Pipeline Company LLC (Constitution)
|
|
24%
|
|
To develop, construct, own and operate 124 miles of interstate natural gas pipeline and related facilities connecting shale natural gas supplies and gathering systems in Susquehanna County, Pennsylvania, to Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York; regulated by the FERC
|
Atlantic Coast Pipeline, LLC (ACP)
**
|
|
7%
|
|
To develop, construct, own and operate 564 miles of interstate natural gas pipeline with associated compression from West Virginia through Virginia into eastern North Carolina in order to provide interstate natural gas transportation services of Marcellus and Utica gas supplies into southeastern markets; regulated by the FERC
|
|
* On October 3, 2016, we sold our 15% interest in SouthStar, effective with the consummation of the Acquisition.
|
** On October 3, 2016, as a result of the Acquisition, we sold 3% of our interest, reducing our ownership from 10% to 7%.
|
As of
October 31, 2016
and
2015
, our investment balances are as follows.
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
Cardinal
|
|
$
|
14.2
|
|
|
$
|
15.1
|
|
Pine Needle
|
|
16.6
|
|
|
18.4
|
|
SouthStar
|
|
—
|
|
|
41.3
|
|
Hardy Storage
|
|
42.1
|
|
|
39.7
|
|
Constitution
|
|
93.1
|
|
|
82.4
|
|
ACP
|
|
33.2
|
|
|
10.1
|
|
Total investments in equity method unconsolidated affiliates
|
|
$
|
199.2
|
|
|
$
|
207.0
|
|
For the years ended
October 31, 2016
,
2015
and
2014
, we recorded our proportionate share of earnings or losses from these unconsolidated affiliates in "
Equity in earnings of unconsolidated affiliates
" within "Other Income and Expense" on the
Consolidated Statements of Operations and Comprehensive Income
as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Cardinal
|
|
$
|
1.5
|
|
|
$
|
1.7
|
|
|
$
|
1.7
|
|
Pine Needle
|
|
2.8
|
|
|
2.7
|
|
|
2.7
|
|
SouthStar
|
|
18.8
|
|
|
19.4
|
|
|
20.4
|
|
Hardy Storage
|
|
5.1
|
|
|
5.2
|
|
|
5.3
|
|
Constitution
|
|
(1.3
|
)
|
|
6.1
|
|
|
2.7
|
|
ACP
|
|
1.7
|
|
|
(0.6
|
)
|
|
—
|
|
Equity in earnings of unconsolidated affiliates
|
|
$
|
28.6
|
|
|
$
|
34.5
|
|
|
$
|
32.8
|
|
Accumulated Other Comprehensive Income (Loss)
As an equity method investor, we record the effect of certain transactions in our accumulated OCIL. Cardinal and Pine Needle enter into interest-rate swap agreements to modify the interest expense characteristics of their unsecured long-term debt which is nonrecourse to its members. Until the sale of our interest in SouthStar as discussed above, we recorded OCIL from this investment from financial contracts in the form of futures, options and swaps, all considered to be derivatives, to moderate the effect of price and weather changes on the timing of its earnings; fair value of these financial contracts was based on selected market indices. For these transactions with these unconsolidated affiliates, we record our share of movements in the market value of these hedged agreements and contracts and retirement benefit items in "
Accumulated other comprehensive loss
" within "
Equity
" on the
Consolidated Balance Sheets
; the detail of our share of the market value of the various financial instruments are presented in "
Other Comprehensive Income (Loss), net of tax
" on the
Consolidated Statements of Operations and Comprehensive Income
.
Related Party Transactions
We have related party transactions as a customer of our investments. For the years ended
October 31, 2016
,
2015
and
2014
, these gas costs and the amounts we owed to our unconsolidated affiliates, as of
October 31, 2016
and
2015
, are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related Party
|
|
Type of Expense
|
|
Cost of Natural Gas
(1)
|
|
Accounts Payable to Affiliated Companies
(2)
|
(in millions)
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
Cardinal
|
|
Transportation costs
|
|
$
|
8.7
|
|
|
$
|
8.8
|
|
|
$
|
8.8
|
|
|
$
|
0.7
|
|
|
$
|
0.7
|
|
Pine Needle
|
|
Gas storage costs
|
|
10.7
|
|
|
11.4
|
|
|
11.4
|
|
|
0.9
|
|
|
1.0
|
|
Hardy Storage
|
|
Gas storage costs
|
|
9.3
|
|
|
9.3
|
|
|
9.5
|
|
|
0.8
|
|
|
0.8
|
|
Totals
|
|
|
|
$
|
28.7
|
|
|
$
|
29.5
|
|
|
$
|
29.7
|
|
|
$
|
2.4
|
|
|
$
|
2.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In the Consolidated Statements of Operations and Comprehensive Income.
|
(2)
In the Consolidated Balance Sheets.
|
Through October 3, 2016, we had related party transactions as we sell wholesale gas supplies to SouthStar. For the years ended
October 31, 2016
,
2015
and
2014
, our operating revenues from these sales and the amounts SouthStar owed us as of
October 31, 2016
and
2015
, are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
(1)
|
|
Receivables from Affiliated Companies
(2)
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
|
2016
|
|
2015
|
Operating revenues
|
|
$
|
0.3
|
|
|
$
|
1.6
|
|
|
$
|
3.5
|
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In the Consolidated Statements of Operations and Comprehensive Income.
|
(2)
In the Consolidated Balance Sheets.
|
Information on Our Equity Method Investments
Cardinal
Cardinal is a North Carolina limited liability company. The other members are subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Cardinal has firm, long-term service agreements with local distribution companies for
100%
of the firm transportation capacity on the pipeline, of which Piedmont subscribes to approximately
53%
. Cardinal is dependent on the Williams – Transco pipeline system to deliver gas into its system for service to its customers.
Summarized financial information provided to us by Cardinal for 100% of Cardinal as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
2014
|
Current assets
|
$
|
10.3
|
|
$
|
9.5
|
|
|
Noncurrent assets
|
101.5
|
|
106.4
|
|
|
Current liabilities
|
46.0
|
|
1.2
|
|
|
Noncurrent liabilities
|
0.3
|
|
45.4
|
|
|
Revenues
|
16.6
|
|
16.6
|
|
$
|
16.7
|
|
Gross profit
|
16.6
|
|
16.6
|
|
16.7
|
|
Income before income taxes
|
7.7
|
|
7.7
|
|
8.0
|
|
Pine Needle
Pine Needle is a North Carolina limited liability company. The other members are the Municipal Gas Authority of Georgia, and subsidiaries of The Williams Companies, Inc. and SCANA Corporation. Pine Needle has firm, long-term service agreements for
100%
of the storage capacity of the facility, of which Piedmont subscribes to approximately
64%
. We are dependent on the Williams – Transco pipeline system for redelivery of Pine Needle volumes to our system for service to our customers.
Summarized financial information provided to us by Pine Needle for 100% of Pine Needle as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
2014
|
Current assets
|
$
|
7.7
|
|
$
|
9.9
|
|
|
Noncurrent assets
|
68.1
|
|
71.6
|
|
|
Current liabilities
|
3.0
|
|
5.4
|
|
|
Noncurrent liabilities
|
35.2
|
|
35.1
|
|
|
Revenues
|
17.1
|
|
16.9
|
|
$
|
18.0
|
|
Gross profit
|
15.4
|
|
15.3
|
|
15.3
|
|
Income before income taxes
|
6.8
|
|
6.0
|
|
6.0
|
|
SouthStar
SouthStar is a Delaware limited liability company. The other member is Georgia Natural Gas Company (GNGC), a wholly owned subsidiary of Southern Company Gas (effective July 1, 2016 following its acquisition of AGL Resources, Inc. (AGL)). In September 2015, under the terms of the SouthStar limited liability company agreement (SSE LLC Agreement) regarding GNGC's change in control, we affirmed our election by written notice to remain a member of SouthStar.
In accordance with the SSE LLC Agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to GNGC. In December 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective upon the consummation of the Acquisition. On October 3, 2016, we sold our
15%
interest in SouthStar, and at closing, we received
$160.0 million
from GNGC resulting in an after-tax gain of
$80.9 million
.
Summarized financial information provided to us by SouthStar for 100% of SouthStar as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
2014
|
Current assets
|
$
|
212.2
|
|
$
|
204.2
|
|
|
Noncurrent assets
|
126.8
|
|
132.3
|
|
|
Current liabilities
|
47.1
|
|
46.0
|
|
|
Noncurrent liabilities
|
—
|
|
—
|
|
|
Revenues
|
638.3
|
|
769.3
|
|
$
|
845.7
|
|
Gross profit
|
216.4
|
|
244.6
|
|
234.6
|
|
Income before income taxes
|
125.5
|
|
129.3
|
|
136.6
|
|
Hardy Storage
Hardy Storage is a West Virginia limited liability company. The other owner is a subsidiary of Columbia Gas Transmission, LLC, an indirect subsidiary of TransCanada Corporation. Hardy Storage has firm, long-term service agreements for
100%
of the storage capacity of the facility, of which Piedmont subscribes to approximately
40%
. We are dependent on Columbia Pipeline Group and the Williams – Transco pipeline system for redelivery of Hardy Storage volumes to our system for service to our customers.
Summarized financial information provided to us by Hardy Storage for 100% of Hardy Storage as of October 31, 2016 and 2015, and for the twelve months ended October 31, 2016, 2015 and 2014, is presented below.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
2014
|
Current assets
|
$
|
6.6
|
|
$
|
11.7
|
|
|
Noncurrent assets
|
151.8
|
|
156.8
|
|
|
Current liabilities
|
14.4
|
|
19.1
|
|
|
Noncurrent liabilities
|
59.1
|
|
70.0
|
|
|
Revenues
|
23.5
|
|
23.4
|
|
$
|
23.8
|
|
Gross profit
|
23.5
|
|
23.4
|
|
23.8
|
|
Income before income taxes
|
11.0
|
|
10.4
|
|
10.5
|
|
Constitution
Constitution is a Delaware limited liability company. The other members are subsidiaries of The Williams Companies, Inc., Cabot Oil & Gas Corporation and WGL Holdings, Inc. A subsidiary of The Williams Companies will be the operator of the pipeline. In December 2014, the FERC issued an order granting Constitution a certificate of public convenience and necessity.
On April 22, 2016, the New York State Department of Environmental Conservation (NYSDEC) denied Constitution’s application for a necessary water quality certification for the New York portion of the Constitution pipeline. Constitution filed legal actions in the U.S District Court for the Northern District of New York and in the U.S Court of Appeals for the Second Circuit (U.S. Court of Appeals) challenging the legality and appropriateness of the NYSDEC’s decision. Both courts granted Constitution's motions to expedite the schedules for the legal actions. On November 16, 2016, oral arguments were heard in the U.S. Court of Appeals.
Constitution has stated that it remains steadfastly committed to pursuing the project and that it intends to pursue all available options to challenge the NYSDEC's decision. In light of the denial of the certification, Constitution revised its target in-service date of the project to be as early as the second half of
2018
, assuming that the challenge process is satisfactorily and promptly concluded.
In July 2016, Constitution requested and the FERC approved an extension of the construction period and in-service deadline of the project to December 2018. Also in July, the FERC denied the New York Attorney General's (NYAG) complaint and request for a stay of the certificate order authorizing the project on the grounds that Constitution had improperly cut trees along the proposed route. The FERC found the complaint procedurally deficient and that there was no justification for a stay; it did find the filing constituted a valid request for investigation and thus referred the matter to FERC staff for further examination as may be appropriate. On November 22, 2016, the FERC denied the NYAG's request for reconsideration of this order.
As a result of the NYSDEC's actions, beginning in April 2016, Constitution stopped construction and discontinued capitalization of future development costs until the project's uncertainty is resolved. We evaluated our investment in the Constitution project for OTTI. Our impairment assessment uses a discounted cash flow income approach, including consideration of the severity and duration of any decline in fair value of our investment in the project. Our key inputs involve significant management judgments and estimates, including projections of the project’s cash flows, selection of a discount rate and probability weighting of potential outcomes of legal and regulatory proceedings. At this time, we believe we do not have an OTTI and have not recorded any impairment charge to reduce the carrying value of our investment. Our evaluation considered that the pending legal and regulatory proceedings are in early stages given the actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. See
Note 1
for information on our fair value evaluation process.
Pending the outcome of the matters described above, and when construction proceeds, we remain committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately
$955.0 million
, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately
$229.3 million
. As of
October 31, 2016
, our fiscal year contributions were
$12.1 million
, with our total equity contributions for the project totaling
$84.8 million
to date. The capacity of the pipeline is
100%
subscribed under fifteen-year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
Summarized financial information provided to us by Constitution for 100% of Constitution as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016, 2015 and 2014, is presented below.
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
2014
|
Current assets
|
$
|
6.6
|
|
$
|
6.2
|
|
|
Noncurrent assets
|
380.9
|
|
330.2
|
|
|
Current liabilities
|
1.2
|
|
4.4
|
|
|
Noncurrent liabilities
|
—
|
|
—
|
|
|
Revenues
|
—
|
|
—
|
|
$
|
—
|
|
Gross profit
|
—
|
|
—
|
|
—
|
|
Income (Loss) before income taxes
|
(3.4
|
)
|
24.6
|
|
10.1
|
|
ACP
On September 2, 2014, Piedmont, Duke Energy, Dominion Resources, Inc. (Dominion), and AGL announced the formation of ACP, a Delaware limited liability company. A Dominion subsidiary is the operator of the pipeline. The pipeline is being designed with an initial capacity of 1.5 billion cubic feet per day with a target in-service date sometime in the second half of
2019
, subject to state and other federal approvals. The capacity of ACP is substantially subscribed by the members of ACP, other utilities and related companies under
twenty
-year contracts.
The total cost for the project is expected to be between
$4.5 billion
to
$5.0 billion
, excluding financing costs. Members anticipate obtaining project financing for
60%
of the total costs during the construction period, and a project capitalization ratio of
50%
debt and
50%
equity when operational. As of
October 31, 2016
, our fiscal year contributions were
$35.3 million
, with our total equity contributions for the project totaling
$46.0 million
to date.
In November 2014, the FERC authorized the ACP pre-filing process under which environmental review for the natural gas pipeline will commence. In February 2015, ACP, along with Dominion Transmission, Inc. (DTI), filed a notice of intent to prepare its environmental impact statement for the project and DTI’s supply header project affecting ACP. ACP filed its FERC application in September 2015 to request FERC authorization to construct and operate the project facilities under the previously FERC-approved pre-filing process, including the environmental review for the natural gas pipeline. FERC approval of the application of the certificate of public convenience and necessity is expected in late 2017 with construction projected to begin thereafter.
On April 15, 2016, Dominion, on behalf of ACP, filed an updated application with the FERC. The filing included, among other items, updated alignment sheets, tables and information regarding the alternative routes adopted by the partners since filing a certificate application in September.
On August 12, 2016, the FERC issued its notice of schedule for environmental review of the project. Under the notice of schedule, we anticipate that the FERC will issue its final environmental impact statement by June 30, 2017.
On March 2, 2015, ACP entered into a Precedent Agreement with DTI for supply header transportation services. Under the Precedent Agreement, ACP is required to provide assurance of its ability to meet its financial obligations to DTI. DTI informed ACP that ACP, independent of its members, is not currently creditworthy as required by DTI’s FERC Gas Tariff. ACP requested that its members provide proportionate assurance of ACP’s ability to meet its financial obligations under the Precedent Agreement, which the Piedmont member provided through an Equity Contribution Agreement between Piedmont and ACP where Piedmont committed to make funds available to the Piedmont member for it to pay and perform its obligations under the ACP Limited Liability Company Agreement. Based on our reduced ownership percentage, this commitment is capped at
$10.6 million
. This commitment ceases when DTI acknowledges that ACP is independently creditworthy in accordance with the Precedent Agreement, termination or expiration of the Precedent Agreement, or when we are no longer a member of ACP.
On July 13, 2015, the parent companies of the members of ACP entered into an indemnification agreement with an insurance company to secure surety bonds in connection with preparatory and pre-construction activities on the ACP project. Liability under the indemnification agreement is several and is capped at each member’s proportionate share, based on its membership interest in ACP, of losses, if any, incurred by the insurance company.
Under a provision in the ACP limited liability company agreement, Dominion had an option to purchase additional ownership interests in ACP to maintain a majority ownership percentage relative to all other members. On October 3, 2016, in connection with the consummation of the Acquisition, Dominion purchased
3%
of our
10%
membership interest in ACP at book value for
$13.9 million
, whereby our interest in ACP was reduced to
7%
.
Summarized financial information provided to us by ACP for 100% of ACP as of September 30, 2016 and 2015, and for the twelve months ended September 30, 2016 and 2015, is presented below. Information for 2014 is not applicable as ACP was formed on September 2, 2014.
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
2015
|
Current assets
|
$
|
134.3
|
|
$
|
23.4
|
|
Noncurrent assets
|
376.3
|
|
86.1
|
|
Current liabilities
|
47.9
|
|
9.1
|
|
Noncurrent liabilities
|
—
|
|
—
|
|
Revenues
|
—
|
|
—
|
|
Gross profit
|
—
|
|
—
|
|
Income (Loss) before income taxes
|
17.3
|
|
(5.2
|
)
|
12
.
Variable Interest Entities
On a quarterly basis, we evaluate our variable interests in other entities, primarily ownership interests, to determine if they represent a variable interest entity (VIE) as defined by the authoritative guidance on consolidation, and if so, which party is the primary beneficiary. As of
October 31, 2016
, we have determined that we are not the primary beneficiary under VIE accounting guidance in any of our equity method investments, as discussed in
Note 11
. Based on our involvement in these investments, we do not have the power to direct the activities of these investments that most significantly impact the VIE’s economic performance, and we will continue to apply equity method accounting to these investments.
Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity, as presented in
Note 11
.
We have also reviewed various lease arrangements, contracts to purchase, sell or deliver natural gas and other agreements in which we hold a variable interest. In these cases, we have determined that we are not the primary beneficiary of the related VIE because we do not have the power to direct the activities of the VIE that most significantly impact the VIE’s
economic performance, or the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.
13
.
Business Segments
Effective with the consummation of the Acquisition, our reportable segments changed based on information used by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Our sole reportable segment is now Gas Utilities and Infrastructure, which includes local gas distribution as state regulated utilities, gas pipeline investments and other gas investments. We evaluate the performance of the gas distribution business, including the operations of merchandising and its related service work and home service agreements, based on segment income, which is defined as income from continuing operations. Although the state regulated operations of our Gas Utilities and Infrastructure segment are located in three states under the jurisdiction of individual state regulatory commissions, the operations are managed as one unit having similar economic and risk characteristics.
The remainder of our operations is presented in Other, which is primarily composed of our equity method investment in SouthStar that was held by a wholly owned subsidiary prior to the sale of our entire membership interest in SouthStar to GNGC on October 3, 2016, contributions to the Piedmont Natural Gas Foundation and certain Acquisition-related expenses. See
Note 11
for further information on the sale of SouthStar.
All of our operations are within the United States.
No
single customer accounts for more than 10% of our consolidated revenues.
Prior periods' segment information has been reclassified to conform to the current year presentation. None of these segment changes impact our reported consolidated revenues or net income. Segment assets as presented in the tables that follow exclude all intercompany assets.
Operations by segment for the years ended
October 31, 2016
,
2015
and
2014
, and related assets as of
October 31, 2016
,
2015
and
2014
, are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended October 31, 2016
|
|
|
Gas
|
|
|
|
|
|
|
Utilities and
|
|
|
|
|
(in millions)
|
|
Infrastructure
|
|
Other
|
|
Total
|
Unaffiliated revenues
|
|
$
|
1,141.7
|
|
|
$
|
—
|
|
|
$
|
1,141.7
|
|
Related party revenue from Duke Energy
|
|
7.0
|
|
|
—
|
|
|
7.0
|
|
Total Revenues
|
|
$
|
1,148.7
|
|
|
$
|
—
|
|
|
$
|
1,148.7
|
|
Interest Expense
|
|
$
|
68.6
|
|
|
$
|
—
|
|
|
$
|
68.6
|
|
Depreciation and amortization
|
|
137.3
|
|
|
—
|
|
|
137.3
|
|
Equity in earnings of unconsolidated affiliates
|
|
9.8
|
|
|
18.8
|
|
|
28.6
|
|
Gain on sale of unconsolidated affiliates
|
|
—
|
|
|
132.8
|
|
|
132.8
|
|
Income tax expense
|
|
85.2
|
|
|
39.0
|
|
|
124.2
|
|
Segment income
|
|
143.3
|
|
|
49.9
|
|
|
193.2
|
|
Capital investments and expenditures and acquisitions
|
|
$
|
569.2
|
|
|
$
|
—
|
|
|
$
|
569.2
|
|
Segment Assets
|
|
5,691.0
|
|
|
—
|
|
|
5,691.0
|
|
|
|
|
|
|
|
|
|
|
Year Ended October 31, 2015
|
|
|
Gas
|
|
|
|
|
|
|
Utilities and
|
|
|
|
|
(in millions)
|
|
Infrastructure
|
|
Other
|
|
Total
|
Unaffiliated Revenues
|
|
$
|
1,383.1
|
|
|
$
|
—
|
|
|
$
|
1,383.1
|
|
Interest Expense
|
|
68.6
|
|
|
—
|
|
|
68.6
|
|
Depreciation and amortization
|
|
128.7
|
|
|
—
|
|
|
128.7
|
|
Equity in earnings of unconsolidated affiliates
|
|
15.1
|
|
|
19.4
|
|
|
34.5
|
|
Income tax expense
|
|
85.9
|
|
|
4.3
|
|
|
90.2
|
|
Segment Income
|
|
131.1
|
|
|
5.9
|
|
|
137.0
|
|
Capital investments and expenditures and acquisitions
|
|
$
|
473.4
|
|
|
$
|
—
|
|
|
$
|
473.4
|
|
Segment Assets
|
|
5,045.0
|
|
|
41.3
|
|
|
5,086.3
|
|
|
|
|
|
|
|
|
|
|
Year Ended October 31, 2014
|
|
|
Gas
|
|
|
|
|
|
|
Utilities and
|
|
|
|
|
(in millions)
|
|
Infrastructure
|
|
Other
|
|
Total
|
Unaffiliated Revenues
|
|
$
|
1,479.5
|
|
|
$
|
—
|
|
|
$
|
1,479.5
|
|
Interest Expense
|
|
54.7
|
|
|
—
|
|
|
54.7
|
|
Depreciation and amortization
|
|
119.0
|
|
|
—
|
|
|
119.0
|
|
Equity in earnings of unconsolidated affiliates
|
|
12.3
|
|
|
20.5
|
|
|
32.8
|
|
Income tax expense
|
|
87.0
|
|
|
7.8
|
|
|
94.8
|
|
Segment Income
|
|
131.2
|
|
|
12.6
|
|
|
143.8
|
|
Capital investments and expenditures and acquisitions
|
|
$
|
498.1
|
|
|
$
|
—
|
|
|
$
|
498.1
|
|
Segment Assets
|
|
4,678.8
|
|
|
41.0
|
|
|
4,719.8
|
|
Products and Services
The following table summarizes revenues of our Gas Utilities and Infrastructure segment by type.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
Retail Natural Gas
|
|
$
|
1,066.3
|
|
|
$
|
1,237.4
|
|
|
$
|
1,300.5
|
|
Wholesale Natural Gas
|
|
72.3
|
|
|
134.3
|
|
|
169.5
|
|
Other
|
|
10.1
|
|
|
11.4
|
|
|
9.5
|
|
Total Revenues
|
|
$
|
1,148.7
|
|
|
$
|
1,383.1
|
|
|
$
|
1,479.5
|
|
14
.
Related Party Transactions with Duke Energy
Effective with the consummation of the Acquisition on
October 3, 2016
, we engage in related party transactions with Duke Energy and its subsidiary registrants in accordance with applicable state and federal regulations. Upon consummation of the Acquisition, our 2018 plan was converted to a Duke Energy RSU Award. Related to this conversion,
$6.1 million
is included in "Accounts payable to affiliated companies" within "Current Liabilities" on the
Consolidated Balance Sheets
. See
Note 9
for further information.
Amounts related to transactions with Duke Energy occurring subsequent to the consummation of the Acquisition are included in the
Consolidated Statements of Operations and Comprehensive Income
for the year ended
October 31, 2016
. The following financial information reflects amounts for the years ended
October 31, 2016
,
2015
and
2014
related to transactions, assuming the Acquisition had taken place November 1, 2013.
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
2016
|
|
2015
|
|
2014
|
Revenue from Duke Energy
(1)
|
$
|
80.8
|
|
|
$
|
83.2
|
|
|
$
|
86.2
|
|
Corporate governance and shared service expenses
(2)
|
0.2
|
|
|
|
|
|
|
|
|
|
|
|
(1)
We provide long-term natural gas delivery service to several of Duke Energy's subsidiaries' natural gas-fired power generation facilities in our market area. This intercompany profit on sales is not eliminated in accordance with accounting regulations prescribed under rate-based regulation, as discussed in Note 1.
|
(2)
We are charged our proportionate share of corporate governance and other shared services costs, primarily related to human resources, employee benefits, legal and accounting fees, as well as other third-party costs. Certain Piedmont executives are responsible for all of Duke Energy's natural gas operations and related infrastructure. A proportionate share of these individuals' payroll and employee benefits is charged to Duke Energy's subsidiary registrants. These amounts are recorded in "Operations, maintenance and other" in the Consolidated Statements of Operations and Comprehensive Income.
|
See Note 10 for discussion of related party income taxes.
15
.
Severance
In conjunction with the Acquisition, certain Piedmont senior executives terminated their employment from Piedmont effective with the closing of the Acquisition. The severance benefits owed to these executives were provided under contracts between the individual and Piedmont, effective upon a change in control. These severances will be paid in April 2017.
In September 2016, Piedmont announced a severance plan covering certain eligible employees whose employment will be involuntarily terminated without cause during the twelve-month period (or twenty-four months for certain senior level employees) following the close of the Acquisition. Upon the close of the Acquisition, positions within Piedmont began to be eliminated. These reductions are a part of the synergies expected to be realized with the Acquisition. The severance benefit payments will be made in accordance with the severance plan.
We recorded
$18.7 million
severance and related expenses that are included in "
Operations, maintenance and other
" on the
Consolidated Statements of Operations and Comprehensive Income
for the year ended
October 31, 2016
. The severance liability was also
$18.7 million
as of
October 31, 2016
and is included in "
Other
" within "
Current Liabilities
" on the
Consolidated Balance Sheets
. Additional accruals can continue through October 3, 2018 as more positions are eliminated.
16
.
Reclassification
of
Consolidated Statements of Operations and Comprehensive Income
,
Consolidated Balance Sheets
and
Consolidated Statements of Cash Flows
Reclassifications have been made to prior year
Consolidated Statements of Operations and Comprehensive Income
,
Consolidated Balance Sheets
and
Consolidated Statements of Cash Flows
.
In the first quarter of 2016, we early adopted ASU 2015-17
Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
. With the retrospective adoption of the new pronouncement, the fiscal year 2015 current line item of "
Deferred income taxes
" of
$32.4 million
was reclassified to net with the noncurrent line item "
Deferred income taxes
," similarly reducing "
Total Assets
" and "
Total Liabilities and Equity
."
Reclassifications have also been made to conform to the presentation currently used by Piedmont’s new parent company, Duke Energy. None of these reclassifications had a significant effect on the previously reported results of operations, financial position or cash flows of Piedmont but were rather the movement of line items or accounts to conform to Duke Energy’s presentation.
The effect on our
Consolidated Statements of Operations and Comprehensive Income
was largely related to the statement presentation. Piedmont previously used a utility income statement presentation showing a line item of "Margin" on the face of the income statement that is defined as natural gas revenues less natural gas commodity and fixed gas costs. With Duke Energy’s presentation, the line item of "Cost of natural gas" is presented within "
Operating Expenses
" with no presentation of regulated margin. See the discussion of regulated margin in "
Results of Operations
" presented in Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in this Form 10-K. Also, we reclassified previously reported utility income taxes of
$76.9 million
and
$83.2 million
from line item "Total operating expenses" and non-utility income taxes of
$13.3 million
and
$11.6 million
from line item “Total other income (expense)” to the new line item "
Income Tax Expense
" for the years ended October 31, 2015 and 2014, respectively. These two changes in presentation had no effect on net income.
The effect on our
Consolidated Statements of Cash Flows
for the years ended October 31, 2015 and 2014 reflects the reclassifications of the balance sheet line items. These reclassifications had no effect on previously reported amounts for net cash provided by operating activities and by financing activities or net cash used in investing activities for the periods previously presented.
17
.
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. See
Note 3
for information on subsequent event disclosure items related to regulatory matters.
18
.
Quarterly Financial Data
(In millions except per share amounts) (Unaudited)
On October 3, 2016, the Acquisition of Piedmont by Duke Energy was consummated, with Piedmont surviving as a wholly owned subsidiary of Duke Energy. As a result of the Acquisition, the Consolidated Financial Statements for our fiscal year ended October 31, 2015 have been reclassified to conform to the presentation of Duke Energy, our parent.
The following table reflects the reclassification of our
Consolidated Statements of Operations and Comprehensive Income
to conform to Duke Energy's presentation.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
Net
|
|
|
|
Operating
|
|
Income
|
|
Income
|
|
|
|
Revenues
|
|
(Loss)
|
|
(Loss)
|
|
Fiscal Year 2016
|
|
|
|
|
|
|
|
January 31
|
|
$
|
463.5
|
|
|
$
|
171.3
|
|
|
$
|
97.8
|
|
|
April 30
|
|
352.9
|
|
|
103.9
|
|
|
63.4
|
|
|
July 31
|
|
160.4
|
|
|
0.5
|
|
|
(6.7
|
)
|
|
October 31
|
|
171.9
|
|
|
(50.3
|
)
|
(1)
|
38.7
|
|
(2)
|
|
|
|
|
|
|
|
|
Fiscal Year 2015
|
|
|
|
|
|
|
|
January 31
|
|
$
|
609.5
|
|
|
$
|
162.2
|
|
|
$
|
93.0
|
|
|
April 30
|
|
427.3
|
|
|
111.1
|
|
|
66.4
|
|
|
July 31
|
|
162.2
|
|
|
(1.7
|
)
|
|
(8.3
|
)
|
|
October 31
|
|
184.1
|
|
|
(8.8
|
)
|
|
(14.1
|
)
|
|
|
|
|
|
|
|
|
|
(1)
The quarter loss is primarily due to Acquisition and integration-related expenses incurred in 2016. See Note 2 for further information.
|
(2)
The increase is primarily due to the gain on the sale of our 15% ownership interest in SouthStar, partially offset by Acquisition and integration-related expenses. See Note 11 for further information on the sale of SouthStar.
|
The pattern of quarterly earnings is the result of the highly seasonal nature of the business as variations in weather conditions and our regulated utility rate designs generally result in greater earnings during the winter months. Basic earnings per share were calculated using the weighted average number of shares outstanding 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.