Notes to Consolidated Financial Statements (Unaudited)
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1.
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Summary of Significant Accounting Policies
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Unaudited Interim Financial Information
The consolidated financial statements have not been
audited. We have prepared the unaudited consolidated financial statements under the rules of the Securities and Exchange Commission (SEC). Therefore, certain financial information and note disclosures normally included in annual financial statements
prepared in conformity with generally accepted accounting principles (GAAP) in the United States of America are omitted in this interim report under these SEC rules and regulations. These financial statements should be read in conjunction with the
Consolidated Financial Statements and Notes included in our Form 10-K for the year ended October 31, 2012.
Seasonality
and Use of Estimates
The unaudited consolidated financial statements include all normal recurring adjustments necessary for a fair
presentation of the statement of financial position at April 30, 2013 and October 31, 2012, the results of operations for the three months and six months ended April 30, 2013 and 2012, and cash flows and stockholders’ equity for
the six months ended April 30, 2013 and 2012. Our business is seasonal in nature. The results of operations for the three months and six months ended April 30, 2013 do not necessarily reflect the results to be expected for the full year.
In accordance with GAAP, we make certain estimates and assumptions regarding reported amounts of assets and liabilities, disclosure of
contingent assets and liabilities as of the date of the consolidated financial statements, and reported amounts of revenues and expenses during the periods reported. These estimates and assumptions affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these
estimates and assumptions.
Significant Accounting Policies
Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended October 31, 2012. There were no significant changes to those accounting
policies during the six months ended April 30, 2013.
Rate-Regulated Basis of Accounting
Our utility operations are subject to regulation with respect to rates, service area, accounting and various other matters by the regulatory commissions
in the states in which we operate. The accounting regulations provide that rate-regulated public utilities account for and report assets and liabilities consistent with the economic effect of the manner in which independent third-party regulators
establish rates. In applying these regulations, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to utility customers in future periods.
Our regulatory assets are recoverable through either base rates or rate riders specifically authorized by a state regulatory commission. Base rates are
designed to provide both a recovery of cost and a return on investment during the period the rates are in effect. As such, all of our regulatory assets are subject to review by the respective state regulatory commissions during any future rate
proceedings. In the event that accounting for the effects of regulation were no longer applicable, we would recognize a write-off of the regulatory assets and
7
regulatory liabilities that would result in an adjustment to net income. Our utility operations continue to recover their costs through cost-based rates established by the state regulatory
commissions. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate. It is our opinion that all regulatory assets are recoverable in current rates or future rate proceedings.
Regulatory assets and liabilities in the Consolidated Balance Sheets as of April 30, 2013 and October 31, 2012 are as follows.
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In thousands
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April 30,
2013
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October 31,
2012
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Regulatory assets
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$
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239,106
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$
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293,104
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Regulatory liabilities
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504,470
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489,692
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Inter-company transactions have been eliminated in consolidation where appropriate; however, we have not eliminated
inter-company profit on sales to affiliates and costs from affiliates in accordance with accounting regulations prescribed under rate-based regulation. For information on related party transactions, see Note 12 to the consolidated financial
statements in this Form 10-Q.
Fair Value Measurements
The carrying values of cash and cash equivalents, receivables, short-term debt, accounts payable, accrued interest and other current liabilities approximate fair value as all amounts reported are to be
collected or paid within one year. Our financial assets and liabilities are recorded at fair value. They consist primarily of derivatives that are recorded in the Consolidated Balance Sheets in accordance with derivative accounting standards and
marketable securities that are held in rabbi trusts established for our deferred compensation plans and are classified as trading securities. Our qualified pension and postretirement plan assets and liabilities are recorded at fair value in the
Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans.
Fair value is the
price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date, or exit date. We utilize market data or assumptions that market participants would use in
valuing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market
approach for fair value measurements and endeavor to utilize the best available information. Accordingly, we use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value of our
financial assets and liabilities are subject to potentially significant volatility based on changes in market prices, the portfolio valuation of our contracts, as well as the maturity and settlement of those contracts, and subsequent newly
originated transactions, each of which directly affects the estimated fair value of our financial instruments. We are able to classify fair value balances based on the observance of those inputs at the lowest level that is significant to the fair
value measurement, in its entirety, in the fair value hierarchy levels as set forth in the fair value guidance.
For the fair value
measurements of our derivatives and marketable securities, see Note 8 to the consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 9 to the consolidated financial statements in our
Form 10-K for the year ended October 31, 2012. For further information on our fair value methodologies, see “Fair Value Measurements” in Note 1 to the consolidated financial statements in our Form 10-K for the year ended
October 31, 2012. There were no significant changes to these fair value methodologies during the three months ended April 30, 2013.
8
Recently Issued Accounting Guidance
In December 2011, the Financial Accounting Standards Board (FASB) issued accounting guidance to improve disclosures and make information more comparable
to International Financial Reporting Standards regarding the nature of an entity’s rights of offset and related arrangements associated with its financial instruments and derivative instruments. The guidance requires an entity to disclose
information about offsetting and related arrangements in tabular format to enable users of financial statements to understand the effect of those arrangements on the entity’s financial position. The new disclosure requirements are effective for
annual periods beginning after January 1, 2013 and interim periods therein and require retrospective application in all periods presented. We will adopt this offsetting disclosure guidance for the first quarter of our fiscal year ending
October 31, 2014. The adoption of this guidance will have no impact on our financial position, results of operations or cash flows.
In
November 2012, the FASB finalized the presentation disclosures on items reclassified from other comprehensive income. In February 2013, the FASB further clarified the presentation disclosures. This disclosure guidance, which we adopted this quarter,
is effective for interim and annual periods beginning after December 15, 2012. The adoption of this guidance had no impact on our financial position, results of operations or cash flows.
In October 2012, we filed a
petition with the North Carolina Utility Commission (NCUC) seeking authority to transfer $6.7 million of capital costs held in “Plant held for future use” in “Utility Plant” in the Consolidated Balance Sheets to a deferred
regulatory asset account, effective November 1, 2012. This balance in “Plant held for future use” relates to the development of the liquefied natural gas (LNG) facility in Robeson County, North Carolina, construction of which was
suspended by Piedmont in March 2009. In January 2013, we filed a motion to suspend this filing in order to incorporate it into a future regulatory proceeding. On April 30, 2013, we withdrew the petition, citing our intent to file a general rate
application and address the appropriate treatment of the Robeson County LNG costs in that general rate application.
On May 31, 2013, we
filed a general rate application with the NCUC requesting an increase in rates and charges for all customers to produce overall increased annual revenues of $79.8 million, or 9.3% above the current annual revenues. This represents an annual average
cost increase of 1.86% since our last general rate proceeding in 2008. In this proceeding, we are seeking authorization from the NCUC to:
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Update and increase our rates and charges based on an overall rate base of $1.9 billion, an equity capital structure component of 50.7% and a return on
common equity of 11.3%,
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•
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Increase total revenues by $79.8 million, including $66.2 million related to gas utility margin and $13.6 million related to increased fixed gas costs,
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•
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Implement a new integrity rider designed to separately track and recover the costs associated with significant levels of capital expenditures projected
to be incurred to comply with federal pipeline safety and integrity requirements,
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•
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Implement new depreciation rates to amortize the costs of assets, net of salvage value, over the estimated useful life of the assets,
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•
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Update and revise our existing service regulations and tariffs,
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•
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Amortize and collect certain non-real estate costs associated with the initial development of the Robeson County LNG facility as discussed above,
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•
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Amortize and collect certain environmental expenses and pipeline safety and integrity compliance expenses that have been deferred in the period since
our last general rate case, and
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9
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Provide for ongoing annual contributions to help fund pipeline safety and integrity research.
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New rates are proposed to be effective January 1, 2014. We are waiting on a hearing date to be set by the NCUC for this general rate proceeding at
this time.
On February 7, 2013, the Public Service Commission of South Carolina (PSCSC) set a hearing date of July 11, 2013 for our
annual review of purchased gas adjustment (PGA) and gas purchasing policies for the twelve months ended March 31, 2013. We filed our testimony in this proceeding on June 4, 2013.
In August 2012, we filed an annual report with the Tennessee Regulatory Authority (TRA) reflecting the shared gas cost savings from gains and losses derived from gas purchase benchmarking and secondary
market transactions for the twelve months ended June 30, 2012 under the Tennessee Incentive Plan (TIP). On February 27, 2013, the TRA Utilities Division Audit Staff (Staff) submitted their Audit Report with which we concurred. On
March 13, 2013, the TRA approved and adopted the Staff’s Audit Report and issued its written order on March 26, 2013.
In
September 2012, we filed an annual report for the twelve months ended June 30, 2012 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. On February 26, 2013, the
Staff submitted their ACA Compliance Audit Report with which we concurred. On March 13, 2013, the TRA approved and adopted the Staff’s ACA Compliance Audit Report and issued its written order on March 26, 2013.
We compute basic earnings
per share (EPS) using the weighted average number of shares of common stock outstanding during each period. Shares of common stock to be issued under approved incentive compensation plans are contingently issuable shares, as determined by applying
the treasury stock method, and are included in our calculation of fully diluted EPS.
A reconciliation of basic and diluted EPS for the three
months and six months ended April 30, 2013 and 2012 is presented below.
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Three Months
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Six Months
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In thousands except per share amounts
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2013
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2012
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2013
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2012
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Net Income
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$
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55,790
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$
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50,192
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$
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141,713
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$
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126,419
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Average shares of common stock outstanding for basic earnings per share
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75,463
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71,731
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73,884
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71,931
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Contingently issuable shares under incentive compensation plans
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314
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295
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333
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295
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Contingently issuable shares under forward sale agreements
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127
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-
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84
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-
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Average shares of dilutive stock
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75,904
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72,026
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74,301
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72,226
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Earnings Per Share of Common Stock:
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Basic
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$
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0.74
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$
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0.70
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$
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1.92
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$
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1.76
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Diluted
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$
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0.74
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$
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0.70
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$
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1.91
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$
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1.75
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10
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4.
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Long-Term Debt Instruments
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We have an open
combined debt and equity shelf registration statement filed with the SEC in July 2011 that is available for future use until its expiration date of July 6, 2014. Unless otherwise specified at the time such securities are offered for sale, the
net proceeds from the sale of the securities will be used for general corporate purposes, including capital expenditures, additions to working capital and advances for or investments in our subsidiaries, and for repurchases of shares of our common
stock. On January 29, 2013, we entered into an underwriting agreement to sell shares of common stock under this registration statement. For further information on this transaction, see Note 6 to the consolidated financial statements in this
Form 10-Q.
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5.
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Short-Term Debt Instruments
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We have a $650
million five-year revolving syndicated credit facility that expires on October 1, 2017. The credit facility has an option to request an expansion up to $850 million. We pay an annual fee of $35,000 plus 8.5 basis points for any unused amount up
to $650 million. The facility provides a line of credit for letters of credit of $10 million, of which $2.1 million and $3.6 million were issued and outstanding as of April 30, 2013 and October 31, 2012, 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 125 basis points, based on our
credit ratings. Amounts borrowed are continuously renewable until the expiration of the facility in 2017 provided that we are in compliance with all terms of the agreement. Due to the seasonal nature of our business, amounts borrowed can vary
significantly during the period.
We have a $650 million unsecured commercial paper (CP) program that is backstopped by the revolving
syndicated credit facility. 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. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $650 million unless the option to
expand the credit facility is exercised as discussed above. Any borrowings under the CP program rank equally with our other unsubordinated and unsecured debt. The notes under the CP program are not registered and are being offered and issued
pursuant to an exemption from registration.
As of April 30, 2013, we have $345 million of notes outstanding under the CP program, as
included in “Short-term debt” in “Current Liabilities” in the Consolidated Balance Sheets with original maturities ranging from 8 to 14 days from their dates of issuance at a weighted average interest rate of .30%. As of
October 31, 2012, our outstanding notes under the CP program, included in the Consolidated Balance Sheets as stated above, were $365 million.
A summary of the short-term debt activity for the three months and six months ended April 30, 2013 is as follows.
11
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Credit Facility
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Commercial Paper
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Total Borrowings
(3)
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In millions
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Three
Months
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Six
Months
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Three
Months
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Six
Months
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Three
Months
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Six
Months
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Minimum amount outstanding during period
(1)
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$
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-
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$
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-
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$
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315
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$
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315
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$
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315
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$
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315
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Maximum amount outstanding during period
(1)
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-
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10
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525
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555
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525
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555
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Minimum interest rate during period
(2)
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-
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%
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1.12
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%
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.28
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%
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.28
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%
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.28
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%
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.28
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%
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Maximum interest rate during period
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-
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%
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1.12
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%
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.37
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%
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.45
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%
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.37
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%
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1.12
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%
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Weighted average interest rate during period
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-
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%
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1.12
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%
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.33
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%
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.36
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%
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.33
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%
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.36
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%
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(1)
During December 2012,
we were borrowing under both the credit facility and CP program for a portion of the month.
(2)
This is the minimum rate when we were borrowing under the credit facility and/or CP program.
(3)
The minimum and maximum balances outstanding for each short-term debt instrument occurred at different times during the
period; therefore, the total balances may not be indicative of actual borrowings on any one day during the period.
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 52% at April 30, 2013.
Capital Stock
Changes in
common stock for the six months ended April 30, 2013 are as follows.
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In thousands
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Shares
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Amount
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Balance, October 31, 2012
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72,250
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$
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442,461
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Issued to participants in the Employee Stock Purchase Plan (ESPP)
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16
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505
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Issued to the Dividend Reinvestment and Stock Purchase Plan
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360
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11,136
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Issued to participants in the Incentive Compensation Plan (ICP)
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94
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2,999
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Issuance of common stock through public share offering, net of underwriting fees
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3,000
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92,640
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Costs from issuance of common stock
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-
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(358
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)
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Balance, April 30, 2013
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75,720
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$
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549,383
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On January 29, 2013, we entered into an underwriting agreement under our open combined debt and equity shelf
registration statement to sell up to 4.6 million shares of our common stock as follows.
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•
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Direct shares – 3 million shares were issued by us and delivered directly to the underwriters with settlement on February 4, 2013. We
received $92.6 million from the underwriters and recorded this amount in “Stockholders’ equity” as an addition to “Common Stock” in the Consolidated Balance Sheets. The shares were purchased by the underwriters at the net
price of $30.88 per share, the offering price to the public of $32 per share per the prospectus less an underwriting discount of $1.12 per share. The net proceeds from this sale of our common stock were used to repay outstanding short-term,
unsecured notes under our CP program.
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•
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Forward shares – 1 million shares were borrowed by a forward counterparty and sold to the underwriters for resale to the public on
February 4, 2013. Under this initial forward sale agreement (FSA) that we executed with the forward counterparty on January 29, 2013, we agreed to sell 1 million shares to the forward counterparty at the same price as the direct
shares to be settled no later than December 15, 2013. Under the terms of this FSA, at our election, we may physically settle in shares, cash or net share settle
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for all or a portion of our obligation under the agreement. We expect to settle by delivering shares. If we physically settle by issuing 1 million shares of our common stock to the forward
counterparty, the forward counterparty will, at settlement, pay us the proceeds of $30.88 per share less certain adjustments from its sale of the borrowed shares to the underwriters.
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•
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Additional shares – Up to .6 million shares were subject to a 30-day option by the underwriters to purchase these additional shares at the
same price as the direct shares and would be, at our option, either issued at the time of purchase and delivered directly to the underwriters or borrowed and delivered to the underwriters by the forward counterparty. On February 19, 2013, the
underwriters exercised their option to purchase the full additional .6 million shares of our common stock at the net price described above of $30.88 per share with settlement on February 22, 2013. We elected to place the .6 million
shares under an additional FSA having substantially similar terms as the original FSA, including settlement options at our election as described above. In connection with the additional FSA, the .6 million shares were borrowed from third
parties and sold to the underwriters by the forward counterparty. We expect to settle by delivering shares. Under the terms of the additional FSA, to the extent that the transaction is physically settled, we will be required to issue and deliver an
equivalent number of shares of our common stock to the forward counterparty at the then applicable forward sale price, which will be the net price described above of $30.88 per share less certain adjustments.
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In accordance with ASC 815-40,
Derivatives and Hedging- Contracts in Entity’s Own Equity,
we have classified the FSAs as equity transactions
because the forward sale transactions are indexed to our own stock and physical settlement is within our control. As a result of this classification, no amounts will be recorded in the consolidated financial statements until settlement of each FSA.
Upon physical settlement of the FSAs, delivery of our shares will result in dilution to our EPS at the date of the settlement. In quarters
prior to the settlement date, any dilutive effect of the FSAs on our EPS could occur during periods when the average market price per share of our common stock is above the per share adjusted forward sale price described above. See Note 3 to the
consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS at April 30, 2013 with the inclusion of incremental shares in our average shares of dilutive stock as calculated under the treasury stock method.
If we had settled the FSAs by delivery of 1.6 million shares of our common stock to the forward counterparty at April 30, 2013, we
would have received net proceeds of approximately $48.8 million based on the net settlement price of $30.88 per share described above less certain adjustments. Upon settlement, the net proceeds from these FSA transactions will be used to repay
outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
Other Comprehensive Income
(Loss)
Our other comprehensive income (loss) (OCIL) is a part of our accumulated OCIL and is comprised of hedging activities from our equity
method investments. For further information on these hedging activities by our equity method investments, see Note 12 to the consolidated financial statements in this Form 10-Q. Changes of each component of accumulated OCIL are presented below for
the three months and six months ended April 30, 2013.
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Changes in Accumulated
OCIL
(1)
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In thousands
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Three
Months
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Six
Months
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Accumulated OCIL beginning balance, net of tax
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$
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(463
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)
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$
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(305
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)
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OCIL before reclassifications, net of tax
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238
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|
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|
59
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Amounts reclassified from accumulated OCIL, net of tax
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76
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|
|
|
97
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Total current period activity, net of tax
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|
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314
|
|
|
|
156
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|
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Accumulated OCIL ending balance, net of tax
|
|
$
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(149
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)
|
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$
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(149
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)
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(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 three months and six months ended April 30, 2013.
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Reclassifications Out of
Accumulated OCIL
(1)
|
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Affected Line Items on Statement of
Comprehensive Income
|
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In thousands
|
|
Three
Months
|
|
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Six
Months
|
|
|
|
Hedging activities of equity method investments
|
|
$
|
(125
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)
|
|
$
|
(160
|
)
|
|
Income from equity method investments
|
|
Income tax expense
|
|
|
49
|
|
|
|
63
|
|
|
Income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total reclassification for the period, net of tax
|
|
$
|
(76
|
)
|
|
$
|
(97
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts in
parentheses indicate credits to accumulated OCIL.
We have marketable
securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on
the deferred compensation plans, see Note 10 to the consolidated financial statements in this Form 10-Q.
We have classified these marketable
securities as trading securities since their inception as the assets are held in rabbi trusts. Trading securities are recorded at fair value in the Consolidated Balance Sheets with any gains or losses recognized currently in earnings. We do not
intend to engage in active trading of the securities, and participants in the deferred compensation plans may redirect their investments at any time. We have matched the current portion of the deferred compensation liability with the current asset
and the noncurrent deferred compensation liability with the noncurrent asset; the current portion is included in “Other current assets” in “Current Assets” in the Consolidated Balance Sheets.
The money market investments in the trust approximate fair value due to the short period of time to maturity. The fair values of the equity securities
are based on the quoted market prices as traded on the exchanges. The composition of these securities as of April 30, 2013 and October 31, 2012 is as follows.
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30, 2013
|
|
|
October 31, 2012
|
|
|
In thousands
|
|
Cost
|
|
|
Fair
Value
|
|
|
Cost
|
|
|
Fair
Value
|
|
|
|
|
|
|
|
|
Current trading securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Mutual funds
|
|
|
134
|
|
|
|
180
|
|
|
|
134
|
|
|
|
157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current trading securities
|
|
|
134
|
|
|
|
180
|
|
|
|
134
|
|
|
|
157
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent trading securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
335
|
|
|
|
335
|
|
|
|
243
|
|
|
|
243
|
|
|
Mutual funds
|
|
|
2,045
|
|
|
|
2,471
|
|
|
|
1,668
|
|
|
|
1,888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total noncurrent trading securities
|
|
|
2,380
|
|
|
|
2,806
|
|
|
|
1,911
|
|
|
|
2,131
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading securities
|
|
$
|
2,514
|
|
|
$
|
2,986
|
|
|
$
|
2,045
|
|
|
$
|
2,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.
|
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. 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 derivative
instruments and the fair value of the right to reclaim cash collateral. 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 April 30, 2013
and October 31, 2012, we had long gas purchase options providing total coverage of 14.9 million dekatherms and 35.8 million dekatherms, respectively. The long gas purchase options held at April 30, 2013 are for the period from
June 2013 through January 2014.
Fair Value Measurements
We use financial instruments that are not designated as hedges to mitigate commodity price risk for our customers. We also have marketable securities that are held in rabbi trusts established for certain
of our deferred compensation plans. 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 to the consolidated financial statements in our Form 10-K for the year ended
October 31, 2012.
The following table sets forth, by level of the fair value hierarchy, our financial assets and liabilities that were
accounted for at fair value on a recurring basis as of April 30, 2013 and October 31, 2012. 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 three months ended April 30, 2013 and 2012.
15
Recurring Fair Value Measurements as of April 30, 2013
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Quoted Prices
in Active
Markets
(Level 1)
|
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
|
Significant
Unobservable
Inputs
(Level
3)
|
|
|
Total
Carrying
Value
|
|
|
Recurring Fair Value Measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
4,091
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
4,091
|
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
335
|
|
|
|
-
|
|
|
|
-
|
|
|
|
335
|
|
|
Mutual funds
|
|
|
2,651
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,651
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recurring fair value assets
|
|
$
|
7,077
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
7,077
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Quoted Prices
in Active
Markets
(Level 1)
|
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
|
Significant
Unobservable
Inputs
(Level
3)
|
|
|
Total
Carrying
Value
|
|
|
Recurring Fair Value Measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives held for distribution operations
|
|
$
|
3,153
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3,153
|
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money markets
|
|
|
243
|
|
|
|
-
|
|
|
|
-
|
|
|
|
243
|
|
|
Mutual funds
|
|
|
2,045
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,045
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recurring fair value assets
|
|
$
|
5,441
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
5,441
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our utility segment derivative instruments are used in accordance with programs filed with or approved by the NCUC, the
PSCSC and the TRA to hedge the impact of market fluctuations in natural gas prices. These derivative instruments are accounted for at fair value each reporting period. In accordance with regulatory requirements, the net gains and losses related to
these derivatives are reflected in purchased gas costs and ultimately passed through to customers through our PGA procedures. In accordance with accounting provisions for rate-regulated activities, the unrecovered amounts related to these
instruments are reflected as a regulatory asset or liability, as appropriate, in “Amounts due to customers” in “Current Liabilities” or “Amounts due from customers” in “Current Assets” in the Consolidated
Balance Sheets. These derivative instruments are exchange-traded derivative contracts. Exchange-traded contracts are generally based on unadjusted quoted prices in active markets and are classified within Level 1.
Trading securities include assets in rabbi trusts established for our deferred compensation plans and are included in “Marketable securities, at
fair value” in “Noncurrent Assets” in the Consolidated Balance Sheets. Securities classified within Level 1 include funds held in money market and mutual funds which are highly liquid and are actively traded on the exchanges.
In developing the fair value of our long-term debt, we use a discounted cash flow technique, consistently applied, that incorporates a
developed discount rate using long-term debt similarly rated by credit rating agencies combined with the U.S. Treasury benchmark with consideration given to maturities, redemption terms and credit ratings similar to our debt issuances. The carrying
amount and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
16
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
|
|
|
|
|
As of April 30, 2013
|
|
$
|
975,000
|
|
|
$
|
1,165,585
|
|
|
As of October 31, 2012
|
|
|
975,000
|
|
|
|
1,163,227
|
|
Quantitative and Qualitative Disclosures
The costs of our financial price hedging options for natural gas and all other costs related to hedging activities of our regulated gas costs are recorded in accordance with our regulatory tariffs
approved by our state regulatory commissions, and thus are not accounted for as designated hedging instruments under derivative accounting standards. As required by the accounting guidance, the fair value amounts are presented on a gross basis and
do not reflect any netting of asset and liability amounts or cash collateral amounts under master netting arrangements.
The following table
presents the fair value and balance sheet classification of our financial options for natural gas as of April 30, 2013 and October 31, 2012.
Fair Value of Derivative Instruments
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Fair Value
April 30, 2013
|
|
|
Fair Value
October 31, 2012
|
|
|
|
|
|
|
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Financial Instruments:
|
|
|
|
|
|
|
|
|
|
Current Assets – Gas purchase derivative assets (June 2013-January 2014)
|
|
$
|
4,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets – Gas purchase derivative assets (December 2012-October 2013)
|
|
|
|
|
|
$
|
3,153
|
|
|
|
|
|
|
|
|
|
|
|
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 is to use these financial instruments to provide some level of protection against significant price increases. Accordingly, the operation of the hedging programs on the regulated utility segment as a result of the use of these
financial derivatives is initially deferred as amounts due to/from customers in the Consolidated Balance Sheets and recognized in the Consolidated Statements of Comprehensive Income as a component of cost of gas when the related costs are recovered
through our rates.
The following table presents the impact that financial instruments not designated as hedging instruments under derivative
accounting standards would have had on the Consolidated Statements of Comprehensive Income for the three months and six months ended April 30, 2013 and 2012, absent the regulatory treatment under our approved PGA procedures.
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
Amount of Loss Recognized on Derivatives and Deferred Under
PGA Procedures
|
|
|
Location of Loss
Recognized through
PGA Procedures
|
|
|
|
|
Three Months Ended
April 30
|
|
|
Six Months Ended
April 30
|
|
|
|
|
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas purchase options
|
|
$
|
1,816
|
|
|
$
|
2,365
|
|
|
$
|
4,291
|
|
|
$
|
5,288
|
|
|
|
Cost of 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 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 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.
Credit and Counterparty Risk
We are exposed to credit risk as a result of
transactions for the purchase and sale of 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, residential and municipal energy consumers. These transactions principally occur in the eastern, gulf coast and mid-west regions of the United States. We believe that this geographic concentration does not contribute
significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable for the natural gas distribution segment 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 “Trade accounts receivable” in “Current Assets” in the Consolidated Balance Sheets
attributable to these entities amounted to $11.3 million, or approximately 8% of our gross trade accounts receivable at April 30, 2013. Our policy requires counterparties to have an investment-grade credit rating at the time of the contract. 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, the policy specifies
limits on the contract amount and duration based on the counterparty’s credit rating and/or credit support. In order to minimize our exposure, we continually re-evaluate third-party creditworthiness and market conditions and modify our
requirements accordingly.
We also enter into contracts with third parties to manage some of our supply and capacity assets
for the purpose of maximizing their value. These arrangements include a counterparty credit evaluation according to our policy described above prior to contract execution and typically have durations of one year or less. In the event that a party is
unable to perform under these 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
April 30, 2013, 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 trade accounts receivable 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
18
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 can also slow our
collection efforts as customers experience increased difficulty in paying their gas bills, leading to higher than normal trade accounts receivable; however, we believe that our provision for possible losses on uncollectible trade accounts receivable
is 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 defined policies and procedures under an Enterprise Risk Management program. In
addition, we have an Energy Price Risk Management Committee that monitors compliance with our hedging programs, policies and procedures.
|
9.
|
Commitments and Contingent Liabilities
|
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 generally fully
recoverable through our PGA procedures and prudence reviews in North Carolina and South Carolina and under the TIP in Tennessee. The time periods for pipeline and storage capacity contracts are up to twenty-two years. The time periods for gas supply
contracts are up to eleven months. 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
four years. Other purchase obligations consist primarily of commitments for pipeline products, vehicles, equipment and contractors.
Certain
storage and pipeline capacity contracts require the payment of demand charges that are based on rates approved by the Federal Energy Regulatory Commission (FERC) in order to maintain our right to access the natural gas storage or the pipeline
capacity on a firm basis during the contract term. The demand charges that are incurred in each period are recognized in the Consolidated Statements of Comprehensive Income as part of gas purchases and included in cost of gas.
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.
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 on our financial position, results of operations or
cash flows.
19
Letters of Credit
We use letters of credit to guarantee claims from self-insurance under our general and automobile liability policies. We had $2.1 million in letters of credit that were issued and outstanding as of
April 30, 2013. Additional information concerning letters of credit is included in Note 5 to the consolidated financial statements in this Form 10-Q.
Environmental Matters
Our three regulatory commissions have authorized us to utilize deferral
accounting in connection with environmental costs. Accordingly, we have established regulatory assets for actual environmental costs incurred and for estimated environmental liabilities recorded.
We are responsible for any third-party claims for personal injury, death, property damage and diminution of property value or natural resources regarding
nine manufactured gas plant (MGP) sites that were a part of a 1997 settlement with a third party and several MGP sites retained by Progress Energy, Inc., now a subsidiary of Duke Energy Corporation, in connection with our 2003 acquisition of North
Carolina Natural Gas Corporation. We know of no such pending or threatened claims.
There are four other MGP sites located in Hickory and
Reidsville, North Carolina, Nashville, Tennessee and Anderson, South Carolina that we have owned, leased or operated and for which we have an investigation and remediation liability. In fiscal year 2012, we performed soil remediation work at our
Reidsville site. In July 2012, the North Carolina Department of Environment and Natural Resources (NCDENR) approved our proposed groundwater investigation work plan, which included installing five monitoring wells in September 2012. Although the
water samples from these wells yielded uncontaminated groundwater, NCDENR is requesting a groundwater remedial action plan requiring additional sampling activities to be conducted for one year. We have incurred $.6 million of remediation costs at
the Reidsville site through April 30, 2013.
As part of a voluntary agreement with the NCDENR, we conducted and completed soil
remediation for the Hickory, North Carolina MGP site in 2010. A Phase II groundwater investigation was conducted in 2011. A groundwater remedial action plan was submitted and approved by the NCDENR in 2012. We continue to conduct quarterly
groundwater monitoring at this site in accordance with our site remediation plan. We have incurred $1.5 million of remediation costs at this site through April 30, 2013.
In November 2008, we submitted our final report of the remediation of the Nashville MGP holding tank site to the Tennessee Department of Environment and Conservation (TDEC). Remediation has been
completed, and a final consent order imposing land usage restrictions on the property was approved and signed by the TDEC in June 2010. The final consent order required two years of semi-annual groundwater monitoring, which has been completed. In
February 2013, we received a letter from the TDEC certifying completion of the actions agreed to be taken in the consent order. We have incurred $1.5 million of remediation costs at this site through April 30, 2013.
During 2008, we became aware of and began investigating soil and groundwater molecular sieve contamination concerns at our Huntersville LNG facility. The
molecular sieve and the related contaminated soil were removed and properly disposed, and in June 2010, we received a determination letter from the NCDENR that no further soil remediation would be required at the site for this issue. In September
2011, we received a letter from the NCDENR indicating their desire to enter into an Administrative Consent Order (ACO) addressing the remaining groundwater issues at the site. In April 2012, we entered into a no admit/no deny ACO that imposed a fine
of $40,000, unpaid annual fees totaling $18,000 and $1,860 for investigative and administrative costs. As part of the ACO, we were required to develop a site assessment plan to determine the extent of the groundwater contamination related to the
sieve burial, a groundwater remediation strategy and a groundwater and surface
20
water site-wide monitoring program. A site assessment plan was accepted by the NCDENR, and we began groundwater sampling in July 2012. We performed an initial round of sampling in our first
quarter, and additional groundwater monitoring wells were installed during our second quarter to aid in determining the extent of the groundwater contamination. The groundwater sampling results will be submitted to the NCDENR, and based on their
response, we may be required to submit additional plan(s) to remediate and/or monitor the groundwater. These plan(s) are due within thirty days of the completion of the site assessment.
The Huntersville LNG facility was originally coated with lead-based paint. To avoid lead-based paint exposure, removal of lead-based paint from the site was initiated in spring 2010. The last phase of the
lead-based paint removal began in July 2012 on the LNG tank, and the remediation of rafters in a nearby building will begin in mid-2013 with completion anticipated for both projects by the end of fiscal 2014. We have incurred $4.3 million of
remediation costs through April 30, 2013 for all issues at the Huntersville LNG plant site. Once the lead-based paint is removed at our Huntersville LNG facility, we expect there will be no potential environmental or employee exposures.
We are transitioning away from owning and maintaining our own petroleum underground storage tanks (USTs). Our Charlotte, North Carolina
resource center is the only location that continues to operate USTs.
For all matters discussed above, as of April 30, 2013, our
estimated undiscounted environmental liability totaled $1.8 million and consisted of $1.1 million for the MGP sites for which we retain remediation responsibility, $.2 million for the LNG facilities, $.2 million for the groundwater remediation at
the Huntersville LNG site and $.3 million for the USTs not yet remediated. 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.
As of April 30, 2013, our regulatory assets for unamortized environmental costs in our three-state territory totaled $10.2 million. We
received approval from the TRA to recover $2 million of our deferred Tennessee environmental costs over an eight-year period beginning March 2012, pursuant to the recent general rate case proceeding in Tennessee. We will seek recovery of the
remaining balance in future rate proceedings. For further information on regulatory matters, see Note 2 to the consolidated financial statements in this Form 10-Q.
Further evaluation of the MGP, LNG and UST sites and removal of lead-based paint at our LNG site 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.
Additional information concerning
commitments and contingencies is set forth in Note 8 to the consolidated financial statements of our Form 10-K for the year ended October 31, 2012.
|
10.
|
Employee Benefit Plans
|
Components of the net
periodic benefit cost for our defined benefit pension plans and our other postretirement employee benefits (OPEB) plan for the three months ended April 30, 2013 and 2012 are presented below.
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
Nonqualified
Pension
|
|
|
Other Benefits
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
3,150
|
|
|
$
|
2,475
|
|
|
$
|
-
|
|
|
$
|
10
|
|
|
$
|
332
|
|
|
$
|
347
|
|
|
Interest cost
|
|
|
2,475
|
|
|
|
2,650
|
|
|
|
40
|
|
|
|
51
|
|
|
|
282
|
|
|
|
337
|
|
|
Expected return on plan assets
|
|
|
(5,300
|
)
|
|
|
(5,125
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(416
|
)
|
|
|
(388
|
)
|
|
Amortization of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
167
|
|
|
|
167
|
|
|
Amortization of prior service (credit) cost
|
|
|
(550
|
)
|
|
|
(550
|
)
|
|
|
20
|
|
|
|
20
|
|
|
|
-
|
|
|
|
-
|
|
|
Amortization of actuarial loss
|
|
|
2,750
|
|
|
|
1,375
|
|
|
|
40
|
|
|
|
12
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,525
|
|
|
$
|
825
|
|
|
$
|
100
|
|
|
$
|
93
|
|
|
$
|
365
|
|
|
$
|
463
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the six months
ended April 30, 2013 and 2012 are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
|
Nonqualified
Pension
|
|
|
Other Benefits
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
6,300
|
|
|
$
|
4,950
|
|
|
$
|
-
|
|
|
$
|
20
|
|
|
$
|
663
|
|
|
$
|
693
|
|
|
Interest cost
|
|
|
4,950
|
|
|
|
5,300
|
|
|
|
79
|
|
|
|
102
|
|
|
|
565
|
|
|
|
674
|
|
|
Expected return on plan assets
|
|
|
(10,600
|
)
|
|
|
(10,250
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(832
|
)
|
|
|
(776
|
)
|
|
Amortization of transition obligation
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
334
|
|
|
|
334
|
|
|
Amortization of prior service (credit) cost
|
|
|
(1,100
|
)
|
|
|
(1,100
|
)
|
|
|
40
|
|
|
|
40
|
|
|
|
-
|
|
|
|
-
|
|
|
Amortization of actuarial loss
|
|
|
5,500
|
|
|
|
2,750
|
|
|
|
80
|
|
|
|
24
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,050
|
|
|
$
|
1,650
|
|
|
$
|
199
|
|
|
$
|
186
|
|
|
$
|
730
|
|
|
$
|
925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In November 2012, we contributed $20 million to the qualified pension plan, and in January 2013, we contributed $.7
million to the money purchase pension plan. We anticipate that we will contribute the following amounts to our other plans in 2013.
|
|
|
|
|
|
|
In thousands
|
|
|
|
|
|
|
|
Nonqualified pension plans
|
|
$
|
502
|
|
|
OPEB plan
|
|
|
1,500
|
|
We have a non-qualified defined contribution restoration (DCR) plan that we fund annually and that covers all officers at
the vice president level and above. For the six months ended April 30, 2013, we contributed $.4 million to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral plan for the benefit of all director-level
employees and officers, where we make no contributions to this plan. Both deferred compensation plans are funded through rabbi trusts with a bank as the trustee. As of April 30, 2013, we have a liability of $3.1 million for these plans.
See Note 7 and Note 8 to the consolidated financial statements in this Form 10-Q for information on the investments in marketable securities
that are held in the trusts.
22
|
11.
|
Employee Share-Based Plans
|
Under our
shareholder approved ICP, eligible officers and other participants are awarded units that pay out depending upon the level of performance achieved by Piedmont during three-year incentive plan performance periods. Distribution of those awards may be
made in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. These plans require that a minimum threshold performance level be achieved in order for any award to be distributed. For the three
months and six months ended April 30, 2013 and 2012, we recorded compensation expense, and as of April 30, 2013 and October 31, 2012, we have accrued a liability for these awards based on the fair market value of our stock at the end
of each quarter. The liability is re-measured to market value at the settlement date.
In December 2010, a long-term retention stock unit
award under the ICP (where a stock unit equals one share of our common stock upon vesting) was approved for eligible officers and other participants to support our succession planning and retention strategies. This retention stock unit award will
vest for participants who have met the retention requirements at the end of a three-year period ending in December 2013 in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation. The Compensation
Committee of our Board of Directors has the discretion to accelerate the vesting of all or a portion of a participant’s units. For the three months and six months ended April 30, 2013 and 2012, we recorded compensation expense, and as of
April 30, 2013 and October 31, 2012, we have accrued a liability for this award based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.
Also under our approved ICP, 64,700 unvested retention stock units were granted to our President and Chief Executive Officer in December 2011. During the
five-year vesting period, any dividend equivalents will accrue on these stock units and be 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 stock units
will vest, payable in the form of shares of common stock and withholdings for payment of applicable taxes on the compensation, over a five-year period only if he is an employee on each vesting date. In accordance with the vesting schedule, 20% of
the units vest on December 15, 2014, 30% of the units vest on December 15, 2015 and 50% of the units vest on December 15, 2016. For the three months and six months ended April 30, 2013, we recorded compensation expense, and as of
April 30, 2013, we have accrued a liability for this award based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value at the settlement date.
At the time of distribution of awards under the ICP, the number of shares issuable is reduced by the withholdings for payment of applicable income taxes
for each participant. The participant may elect income tax withholdings at or above the minimum statutory withholding requirements. The maximum withholdings allowed is 50%. To date, shares withheld for payment of applicable income taxes have been
immaterial. We present these net shares issued in the Consolidated Statements of Stockholders’ Equity.
The compensation expense related
to the incentive compensation plans for the three months and six months ended April 30, 2013 and 2012, and the amounts recorded as liabilities as of April 30, 2013 and October 31, 2012 are presented below.
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Compensation expense
|
|
$
|
1,801
|
|
|
$
|
501
|
|
|
$
|
3,657
|
|
|
$
|
2,075
|
|
|
|
|
|
|
|
|
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability
|
|
$
|
10,228
|
|
|
$
|
10,631
|
|
|
|
|
|
|
|
|
|
On a quarterly basis, we issue shares of common stock under the ESPP and have accounted for the issuance as an equity
transaction. The exercise price is calculated as 95% of the fair market value on the purchase date of each quarter where fair market value is determined by calculating the mean average of the high and low trading prices on the purchase date.
|
12.
|
Equity Method Investments
|
The consolidated
financial statements include the accounts of wholly owned subsidiaries whose investments in joint venture, energy-related businesses are accounted for under the equity method. Our ownership interest in each entity is included in “Equity method
investments in non-utility activities” in “Noncurrent Assets” in the Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other
Income (Expense)” in the Consolidated Statements of Comprehensive Income.
Cardinal Pipeline Company, L.L.C.
We own 21.49% of the membership interests in Cardinal Pipeline Company, L.L.C. (Cardinal), a North Carolina limited liability company. Cardinal owns and
operates an intrastate natural gas pipeline in North Carolina and is regulated by the NCUC.
Cardinal enters into interest-rate swap
agreements to modify the interest expense characteristics of its unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in
“Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income
(Loss), net of tax” in the Consolidated Statements of Comprehensive Income. Cardinal’s long-term debt is nonrecourse to the members.
We have related party transactions as a transportation customer of Cardinal, and we record the transportation costs charged by Cardinal in “Cost of
Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, these transportation costs and the amounts we owed Cardinal as of April 30, 2013 and
October 31, 2012 are as follows.
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Transportation costs
|
|
$
|
2,155
|
|
|
$
|
1,012
|
|
|
$
|
4,294
|
|
|
$
|
2,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
Trade accounts payable
|
|
$
|
730
|
|
|
$
|
855
|
|
Pine Needle LNG Company, L.L.C.
We own 40% of the membership interests in Pine Needle LNG Company, L.L.C. (Pine Needle), a North Carolina limited liability company. Pine Needle owns an interstate LNG storage facility in North Carolina
and is regulated by the FERC.
Pine Needle enters into interest-rate swap agreements to modify the interest expense characteristics of its
unsecured long-term debt. Our share of movements in the market value of these agreements are recorded as a hedge in “Accumulated other comprehensive loss” in “Stockholders’ equity” in the Consolidated Balance Sheets; the
detail of our share of the market value of the swap agreements is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss), net of tax” in the Consolidated Statements of Comprehensive Income.
Pine Needle’s long-term debt is nonrecourse to the members.
We have related party transactions as a customer of Pine Needle, and we
record the storage costs charged by Pine Needle in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, these gas storage costs and the
amounts we owed Pine Needle as of April 30, 2013 and October 31, 2012 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Gas storage costs
|
|
$
|
2,730
|
|
|
$
|
2,464
|
|
|
$
|
5,516
|
|
|
$
|
4,983
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
Trade accounts payable
|
|
$
|
919
|
|
|
$
|
914
|
|
SouthStar Energy Services LLC
We own 15% of the membership interests in SouthStar Energy Services LLC (SouthStar), a Delaware limited liability company. SouthStar primarily sells natural gas to residential, commercial and industrial
customers in the southeastern United States, as well as Ohio, New York and Maryland, with most of its business being conducted in the unregulated retail gas market in Georgia. We account for our investment in SouthStar using the equity method, as we
have board representation with equal voting rights on significant governance matters and policy decisions, and thus, exercise significant influence over the operations of SouthStar.
SouthStar uses financial contracts to moderate the effect of price and weather changes on the timing of its earnings. These financial contracts, in the form of futures, options and swaps, are considered
to be derivatives
25
and fair value is based on selected market indices. Our share of movements in the market value of these contracts are recorded as a hedge in “Accumulated other comprehensive loss” in
“Stockholders’ equity” in the Consolidated Balance Sheets; the detail of our share of the market value of these contracts is combined with our other equity method investments and presented in “Other Comprehensive Income (Loss),
net of tax” in the Consolidated Statements of Comprehensive Income.
We have related party transactions as we sell wholesale gas supplies
to SouthStar, and we record the amounts billed to SouthStar in “Operating Revenues” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and 2012, our
operating revenues from these sales and the amounts SouthStar owed us as of April 30, 2013 and October 31, 2012 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
592
|
|
|
$
|
(26
|
)
|
|
$
|
583
|
|
|
$
|
(139
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
Trade accounts receivable
|
|
$
|
579
|
|
|
$
|
473
|
|
Hardy Storage Company, LLC
We own 50% of the membership interests in Hardy Storage Company, LLC (Hardy Storage), a West Virginia limited liability company. Hardy Storage owns and operates an underground interstate natural gas
storage facility located in Hardy and Hampshire Counties, West Virginia, that is regulated by the FERC.
We have related party transactions as
a customer of Hardy Storage and record the storage costs charged by Hardy Storage in “Cost of Gas” in the Consolidated Statements of Comprehensive Income. For each period of the three months and six months ended April 30, 2013 and
2012, these gas storage costs and the amounts we owed Hardy Storage as of April 30, 2013 and October 31, 2012 are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
In thousands
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Gas storage costs
|
|
$
|
2,425
|
|
|
$
|
2,425
|
|
|
$
|
4,851
|
|
|
$
|
4,851
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
Trade accounts payable
|
|
$
|
808
|
|
|
$
|
808
|
|
Constitution Pipeline Company, LLC
We own 24% of the membership interests in Constitution Pipeline Company, LLC (Constitution), a Delaware limited liability company. The purpose of the joint venture is to construct and operate
approximately 120 miles of interstate natural gas pipeline and related facilities connecting natural gas gathering systems in Susquehanna County, Pennsylvania to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in New York. We have
committed to fund an amount in proportion to our ownership interest for the development and construction
26
of the new pipeline, which is expected to cost approximately $680 million. As of April 30, 2013, our current quarter and fiscal year contributions were $1.2 million and $8.7 million,
respectively, and we expect our total contributions will be an estimated $163 million through 2015 with approximately 90% of that funding to occur during our fiscal 2014 and 2015 years. The target in-service date of the project is March 2015. The
capacity of the pipeline is 100% subscribed under fifteen year service agreements with two Marcellus producer-shippers with a negotiated rate structure.
|
13.
|
Variable Interest Entities
|
Under accounting
guidance, a variable interest entity (VIE) is a legal entity that conducts a business or holds property whose equity, by design, has any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity
owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity owners do not receive expected losses or returns. An entity may have
an interest in a VIE through ownership or other contractual rights or obligations and that interest changes as the entity’s net assets change. The consolidating investor is the entity that has the power to direct the activities of a VIE that
most significantly impact the VIE’s economic performance, the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the
VIE.
As of April 30, 2013, we have determined that we are not the primary beneficiary, as defined by the authoritative guidance related
to consolidations, in any of our equity method investments, as discussed in Note 12 to the consolidated financial statements in this Form 10-Q. 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. As we are not the consolidating investor, we will continue to apply equity method accounting to these investments, as discussed in Note 12 to the consolidated financial
statements in this Form 10-Q. Our maximum loss exposure related to these equity method investments is limited to our equity investment in each entity. As of April 30, 2013 and October 31, 2012, our investment balances are as follows.
|
|
|
|
|
|
|
|
|
|
|
In thousands
|
|
April 30,
2013
|
|
|
October 31,
2012
|
|
|
|
|
|
|
Cardinal
|
|
$
|
18,270
|
|
|
$
|
17,969
|
|
|
Pine Needle
|
|
|
18,585
|
|
|
|
19,239
|
|
|
SouthStar
|
|
|
15,467
|
|
|
|
18,118
|
|
|
Hardy Storage
|
|
|
33,465
|
|
|
|
32,541
|
|
|
Constitution
|
|
|
8,979
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity method investments in non-utility activities
|
|
$
|
94,766
|
|
|
$
|
87,867
|
|
|
|
|
|
|
|
|
|
|
|
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.
We have two reportable
business segments, regulated utility and non-utility activities. Our segments are identified based on products and services, regulatory environments and our current corporate organization and business decision-making activities. The regulated
utility segment is the gas distribution business, where we
27
include the operations of merchandising and its related service work and home warranty programs, with activities conducted by the parent company. Operations of our non-utility activities segment
are comprised of our equity method investments in joint ventures that are held by our wholly owned subsidiaries.
Operations of the regulated
utility segment are reflected in “Operating Income” in the Consolidated Statements of Comprehensive Income. Operations of the non-utility activities segment are included in the Consolidated Statements of Comprehensive Income in
“Income from equity method investments” and “Non-operating income.”
We evaluate the performance of the regulated utility
segment based on margin, operations and maintenance expenses and operating income. We evaluate the performance of the non-utility activities segment based on earnings from the ventures. The basis of segmentation and the basis of the measurement of
segment profit or loss are the same as reported in the Consolidated Financial Statements in our Form 10-K for the year ended October 31, 2012.
Operations by segment for the three months and six months ended April 30, 2013 and 2012 are presented below.
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|
|
|
|
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|
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|
In thousands
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|
Regulated Utility
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|
|
Non-utility
Activities
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|
|
Total
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|
|
|
|
2013
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|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
Three Months
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers
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|
$
|
399,411
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|
|
$
|
308,432
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|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
399,411
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|
|
$
|
308,432
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|
|
Margin
|
|
|
183,856
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|
|
|
171,951
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|
|
|
-
|
|
|
|
-
|
|
|
|
183,856
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|
|
|
171,951
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|
|
Operations and maintenance expenses
|
|
|
65,037
|
|
|
|
60,511
|
|
|
|
66
|
|
|
|
21
|
|
|
|
65,103
|
|
|
|
60,532
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|
|
Income from equity method investments
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|
|
-
|
|
|
|
-
|
|
|
|
12,437
|
|
|
|
11,652
|
|
|
|
12,437
|
|
|
|
11,652
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|
|
Operating income (loss) before income taxes
|
|
|
82,884
|
|
|
|
76,872
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|
|
|
(70
|
)
|
|
|
(26
|
)
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|
|
82,814
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|
|
|
76,846
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|
|
Income before income taxes
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|
|
79,678
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|
|
|
71,189
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|
|
|
12,367
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|
|
|
11,627
|
|
|
|
92,045
|
|
|
|
82,816
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|
|
|
|
|
|
|
|
|
|
Six Months
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers
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|
$
|
915,286
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|
|
$
|
780,272
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
915,286
|
|
|
$
|
780,272
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|
|
Margin
|
|
|
415,480
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|
|
|
392,187
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|
|
|
-
|
|
|
|
-
|
|
|
|
415,480
|
|
|
|
392,187
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|
|
Operations and maintenance expenses
|
|
|
120,919
|
|
|
|
118,908
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|
|
|
120
|
|
|
|
44
|
|
|
|
121,039
|
|
|
|
118,952
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|
|
Income from equity method investments
|
|
|
-
|
|
|
|
-
|
|
|
|
19,592
|
|
|
|
17,944
|
|
|
|
19,592
|
|
|
|
17,944
|
|
|
Operating income (loss) before income taxes
|
|
|
222,396
|
|
|
|
203,912
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|
|
|
(205
|
)
|
|
|
(132
|
)
|
|
|
222,191
|
|
|
|
203,780
|
|
|
Income before income taxes
|
|
|
214,555
|
|
|
|
190,770
|
|
|
|
19,386
|
|
|
|
17,812
|
|
|
|
233,941
|
|
|
|
208,582
|
|
Reconciliations to the Consolidated Statements of Comprehensive Income for the three months and six months ended
April 30, 2013 and 2012 are presented below.
28
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
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In thousands
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
2013
|
|
|
2012
|
|
|
2013
|
|
|
2012
|
|
|
|
|
|
|
|
|
Operating Income:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Segment operating income before income taxes
|
|
$
|
82,814
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|
|
$
|
76,846
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|
|
$
|
222,191
|
|
|
$
|
203,780
|
|
|
Utility income taxes
|
|
|
(31,380
|
)
|
|
|
(28,090
|
)
|
|
|
(84,679
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)
|
|
|
(75,311
|
)
|
|
Non-utility activities before income taxes
|
|
|
70
|
|
|
|
26
|
|
|
|
205
|
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
$
|
51,504
|
|
|
$
|
48,782
|
|
|
$
|
137,717
|
|
|
$
|
128,601
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income:
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes for reportable segments
|
|
$
|
92,045
|
|
|
$
|
82,816
|
|
|
$
|
233,941
|
|
|
$
|
208,582
|
|
|
Income taxes
|
|
|
(36,255
|
)
|
|
|
(32,624
|
)
|
|
|
(92,228
|
)
|
|
|
(82,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
55,790
|
|
|
$
|
50,192
|
|
|
$
|
141,713
|
|
|
$
|
126,419
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We monitor significant
events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For
information on subsequent event disclosures related to regulatory matters, see Note 2 to the consolidated financial statements in this Form 10-Q.