Notes to Condensed Consolidated Financial Statements (Unaudited)
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1
.
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Summary of Significant Accounting Policies
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Significant Accounting Policies
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, 2015
. Our accounting policies are described in Note 1 to the consolidated financial statements in our Form 10-K for the year ended
October 31, 2015
. There were no significant changes to those accounting policies during the
nine
months ended
July 31, 2016
.
Unaudited Interim Financial Information
The condensed consolidated financial statements have not been audited. We have prepared the unaudited condensed 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. The unaudited condensed consolidated financial statements include all normal recurring adjustments necessary for a fair presentation of the statement of financial position as of
July 31, 2016
and
October 31, 2015
, the results of operations for the
three months and nine
months ended
July 31, 2016
and
2015
, and cash flows and stockholders’ equity for the
nine
months ended
July 31, 2016
and
2015
.
Seasonality and Use of Estimates
Our business is seasonal in nature. The results of operations for the
three months and nine
months ended
July 31, 2016
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, liabilities, revenues and expenses and the related disclosures, using historical experience and other assumptions that we believe are reasonable at the time. Our estimates may involve complex situations requiring a high degree of judgment in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. These estimates and assumptions affect the reported amounts of assets and liabilities as of the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates and assumptions, which are evaluated on a continual basis.
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. Generally, regulatory assets are amortized to expense and regulatory liabilities are amortized to income over the period authorized by our regulators.
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 regulatory liabilities that would result in an adjustment to net income or accumulated other comprehensive income (loss) (OCIL). 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 in future rate proceedings. Our regulatory assets and liabilities are detailed in
Note 3
to the condensed consolidated financial statements in this Form 10-Q.
Fair Value Measurements
We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value in the Condensed Consolidated Balance Sheets are cash and cash equivalents, marketable securities held in rabbi trusts established for our deferred compensation plans and purchased call option derivative assets and liabilities, if any, that are held for our utility operations. The carrying values of receivables, short-term debt, accounts payable, accrued interest and other current assets and liabilities approximate fair value as all amounts reported are to be collected or paid within one year. Our nonfinancial assets and liabilities include our qualified pension and postretirement plan assets and liabilities that are recorded at fair value in the Condensed Consolidated Balance Sheets in accordance with employers’ accounting and related disclosures of postretirement plans. As discussed below, effective in our first quarter 2016, we have certain forward gas supply derivative contracts that are nonfinancial assets and liabilities requiring fair value treatment.
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 for the specific instrument, location or commodity being valued. 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 maturity and settlement of our 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 9
to the condensed consolidated financial statements in this Form 10-Q. For the fair value measurements of our benefit plan assets, see Note 10 to the consolidated financial statements in our Form 10-K for the year ended
October 31, 2015
. 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, 2015
. Effective in our first quarter 2016, we have long-dated, fixed quantity natural gas supply contracts for our utility operations which are accounted for as derivatives. We have classified these contracts as Level 3 in the fair value hierarchy, as the inputs are generally unobservable due to the tenure of the contracts and the absence of market quoted observable data. In the absence of actively quoted prices or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In determining the fair value, we use a discounted cash flow technique to calculate our valuation. We incorporate the following inputs and assumptions in our model: contract volume, forward market prices from third party pricing services with an evaluation of pricing information on active and inactive markets, price correlations, pricing projections, time value, fuel assumptions and credit adjusted risk free rate of return. There were no significant changes to these fair value methodologies during the three months ended
July 31, 2016
.
On a quarterly basis, or when events or changes in circumstances indicate, we evaluate our investments in our equity method investments for impairment. Each investment is recorded at cost plus post-acquisition contributions and earnings based on our ownership share less any distributions as received from the joint venture investment, and if applicable, less any impairment in value of the investment. Given the nature of our equity method investment, our assessment may include a discounted cash flow income approach, including consideration of qualitative factors or events or circumstances which could affect the fair value. To the extent the analysis indicates a decline in fair value, we consider both the severity and duration of any decline in our evaluation as to whether an other-than-temporary impairment (OTTI) has occurred. Our key inputs involve significant management judgments and estimates, including projections of the entity’s cash flows, selection of a discount rate and probability weighting of potential outcomes of any legal or regulatory proceedings or other events affecting the investment. For further information, see Note 13 to the condensed consolidated financial statements in this Form 10-Q.
Recently Issued Accounting Standards Update (ASU)
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Guidance
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Description
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Effective date
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Effect on the financial statements or other significant matters
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ASU 2014-09, May 2014,
Revenue from Contracts with Customers (Topic 606),
including subsequent ASUs clarifying the guidance
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Under the new standard, entities will recognize revenue to depict the transfer of goods and services to customers in amounts that reflect consideration expected to be received in exchange for those goods or services. In doing so, more judgment and estimates may be needed than under current guidance. The disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from an entity’s contracts with customers. An entity may choose to adopt the new standard on either a full retrospective basis (practical expedients available) or through a cumulative effect adjustment to retained earnings as of the start of the first period of adoption.
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Annual periods (and interim periods within those periods) beginning after December 15, 2017, with early adoption permitted for annual periods beginning after December 15, 2016.
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We are currently evaluating the effect on our financial position, results of operations and cash flows, as well as the transition approach we will take. The evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. In our evaluation, we are monitoring specific developments for our industry.
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ASU 2015-05, April 2015,
Intangibles -Goodwill and Other - Internal-Use Software: Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (Subtopic 350-40)
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The amendment provides customers with guidance on determining whether a cloud computing arrangement contains a software license that should be accounted for as internal-use software. The guidance applies only to hosting arrangements if both of the following criteria are met: (a) the customer has the contractual right to take possession of the software at any time during the hosting period without significant penalty and (b) it is feasible for the customer to run the software on its own hardware or contract with another party to host the software.
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Annual periods (and interim periods within those periods) beginning after December 15, 2015, with early adoption permitted. Entities may adopt the guidance retrospectively or prospectively to arrangements entered into, or materially modified, after the effective date.
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We intend to elect prospective transition upon adoption of this ASU, whereby we will disclose the effect of this change in accounting principle on the financial statement line items affected.
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ASU 2016-01, January 2016,
Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities
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The amendment addresses aspects of recognition, measurement, presentation and disclosure of financial instruments. It affects investments in equity securities and the presentation of certain fair value changes for financial liabilities measured at fair value. It simplifies the impairment assessment of equity investments without a readily determinable fair value by requiring a qualitative assessment.
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Annual periods (and interim periods within those periods) beginning after December 15, 2017.
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We are currently evaluating the effect on our financial position, results of operations and cash flows.
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Guidance
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Description
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Effective date
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Effect on the financial statements or other significant matters
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ASU 2016-02, February 2016,
Leases (Topic 842)
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Under the new standard, entities will recognize right-of-use (ROU) assets and related liabilities on the balance sheet for leases with a term greater than one year. Amortization of the ROU asset will be accounted for using: (1) the finance lease approach, or (2) the operating lease approach. Under the finance lease approach, the ROU asset will be amortized on a straight-line basis with the amortization and the interest on the lease liability presented separately in the income statement. Under the operating lease approach, a single straight-line expense will be presented in the income statement. Qualitative and quantitative disclosures are required to enable a user to assess the amount, timing and uncertainty of cash flows arising from leasing activities. A modified retrospective transition approach, including the option to elect practical expedients, is required for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements at the date of initial application.
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Annual periods (and interim periods within those periods) beginning after December 15, 2018, with early adoption permitted.
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We are currently evaluating the effect on our financial position, results of operations and cash flows.
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ASU 2016-09, March 2016,
Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
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The amendment is intended to simplify several areas of accounting for share-based compensation arrangements. The standard requires that all tax effects of share-based payments at settlement (or expiration) be recorded in the income statement at the time the tax effects arise. The standard also clarifies that excess tax benefits of share-based payments should be classified along with other income tax cash flows as an operating activity in the statement of cash flows, permits employers to withhold shares upon settlement of an award to satisfy an employee's tax liability up to the employee's maximum individual interest tax rate in the relevant jurisdiction without resulting in liability classification of the award with the cash paid by employers classified as a financing activity in the statement of cash flows and permits entities to make an accounting policy election to estimate or use actual forfeitures when recognizing share-based compensation expense.
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Annual periods (and interim periods within those periods) beginning after December 15, 2016. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.
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We are currently evaluating the effect on our financial position, results of operations and cash flows.
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Guidance
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Description
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Effective date
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Effect on the financial statements or other significant matters
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ASU 2016-13, June 2016,
Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
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The amendment is intended to replace the incurred loss impairment methodology in current guidance with a methodology that reflects expected credit losses requiring a broader range of reasonable and supportable information for credit loss estimates. The amendment affects loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables and other financial assets having the contractual right to receive cash that are not excluded from the scope. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial assets to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected credit losses that have occurred during the period.
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Annual periods (and interim periods within those periods) beginning after December 15, 2019, with early adoption permitted beginning after December 15, 2018.
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We are currently evaluating the effect on our financial position, results of operations and cash flows.
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ASU 2016-15, August 2016,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
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The amendment is intended to provide specific guidance on eight cash flow classification issues to reduce the diversity in practice. The eight issues are: 1) debt prepayment or debt extinguishment costs, 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, 3) contingent consideration payments made after a business combination, 4) proceeds from the settlement of life insurance claims, 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, 6) distributions received from equity method investees, 7) beneficial interests in securitization transactions and 8) separately identifiable cash flows and application of the predominance principle.
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Annual periods (and interim periods within those periods) beginning after December 15, 2017. Early adoption is permitted in any interim or annual period if all amendments are adopted in that period with any adjustments reflected as of the beginning of the fiscal year that includes the interim period.
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We are currently evaluating the effect on the presentation of our cash flows.
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Reclassifications and Changes in Presentation
A reclassification was made to the prior year Condensed Consolidated Balance Sheets to conform with the current year presentation. In our first fiscal quarter, we early adopted ASU 2015-17
Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes
. This ASU
eliminated the current requirement to present deferred tax assets and liabilities as current and noncurrent amounts in a classified balance sheet and replaced it with a noncurrent classification of deferred tax assets and liabilities. While the guidance would have been effective for us beginning November 1, 2017, we elected to adopt this guidance effective November 1, 2015 to simplify our presentation of deferred tax assets and liabilities.
With the adoption of the new pronouncement retrospectively, the fiscal year 2015 Condensed Consolidated Balance Sheets line item "Deferred income taxes" of
$32.4 million
previously included within "Current Assets" was reclassified to net with the noncurrent line item "Deferred income taxes" as
$829.2 million
within "Noncurrent Liabilities." Line item "Total current assets" was reduced by
$32.4 million
to
$223.5 million
, line item "Total noncurrent liabilities" was reduced to
$1,492.8 million
, resulting in total assets and total capitalization and liabilities totaling
$5,078.4 million
.
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2
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Proposed Acquisition by Duke Energy Corporation
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On
October 24, 2015
, we entered into an Agreement and Plan of Merger (Merger Agreement) with Duke Energy Corporation (Duke Energy) and Forest Subsidiary, Inc. (Merger Sub), a new wholly owned subsidiary of Duke Energy. The Merger Agreement provides for the merger of the Merger Sub with and into Piedmont, with Piedmont surviving as a wholly owned subsidiary of Duke Energy (the Acquisition). At the effective time of the Acquisition, subject to receipt of required regulatory approvals and meeting specified customary closing conditions, each share of Piedmont common stock issued and outstanding immediately prior to the closing will be converted automatically into the right to receive
$60
in cash per share, without interest, less any applicable withholding taxes. Upon consummation of the Acquisition, Piedmont common stock will be delisted from the New York Stock Exchange (NYSE).
On December 22, 2015, the Federal Trade Commission granted early termination of the thirty-day waiting period for the Acquisition under the federal Hart-Scott-Rodino Antitrust Improvements Act of 1976. Expiration or termination of the waiting period is one of the conditions required for completion of the Acquisition.
For information on the January 15, 2016 filing with the North Carolina Utilities Commission (NCUC) for approval of the Acquisition, including the hearing on this matter in July 2016, see
Note 3
to the condensed consolidated financial statements in this Form 10-Q. Also, on January 15, 2016, we and Duke Energy filed a joint application with the Tennessee Regulatory Authority (TRA) seeking approval to transfer Piedmont's Tennessee operating license effective at the closing of the Acquisition pursuant to state statue due to the change in control. In March 2016, the TRA approved the transfer contingent upon NCUC approval of the Acquisition.
At a specially called meeting held on January 22, 2016, the proposal to approve the Acquisition was approved by Piedmont's shareholders with a vote of
66.8%
of Piedmont's outstanding shares of common stock entitled to vote. Piedmont's shareholder approval of the transaction is one of the conditions required for completion of the Acquisition.
In connection with this transaction, during the three months and
nine months ended July 31, 2016
, we recorded Acquisition and integration-related expenses of
$.6 million
and
$2.6 million
, respectively, for costs paid to outside parties, which are reflected in “Operations and maintenance” in “Operating Expenses” in the Condensed Consolidated Statements of Operations and Comprehensive Income. These amounts do not include the cost of company personnel participating in Acquisition-related integration planning activities. Also during the three months and
nine months ended July 31, 2016
, we recorded incremental share-based compensation expense of
$.6 million
and
$6 million
, respectively, from the accelerated vesting, payment and taxation of certain share-based awards for our President and Chief Executive Officer (CEO) and other eligible officers and participants with the issuance of restricted nonvested shares of our common stock in December 2015. These share-based plan costs are reflected in "Operations and maintenance" and related payroll taxes in "General taxes" in "Operating Expenses" in the Condensed Consolidated Statements of Operations and Comprehensive Income. For further information on these accelerated share-based transactions, see
Note 12
to the condensed consolidated financial statements in this Form 10-Q.
Rate Regulated Basis of Accounting
Regulatory assets and liabilities in the Condensed Consolidated Balance Sheets as of
July 31, 2016
and
October 31, 2015
are as follows.
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In thousands
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July 31,
2016
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October 31,
2015
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Regulatory Assets:
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Current:
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Unamortized debt expense on reacquired debt
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$
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238
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$
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238
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Amounts due from customers
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34,621
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—
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Environmental costs
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1,516
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1,513
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Deferred operations and maintenance expenses
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889
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847
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Deferred pipeline integrity expenses
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3,470
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3,470
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Deferred pension and other retirement benefit costs
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2,757
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2,757
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Robeson liquefied natural gas (LNG) development costs
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223
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381
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Derivatives - gas supply contracts held for utility operations
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33,300
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—
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Other
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1,406
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1,730
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Total current
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78,420
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10,936
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Noncurrent:
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Unamortized debt expense on reacquired debt
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4,488
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4,666
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Environmental costs
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3,989
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5,107
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Deferred operations and maintenance expenses
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3,325
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3,997
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Deferred pipeline integrity expenses
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31,533
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29,824
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Deferred pension and other retirement benefit costs
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17,509
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17,861
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Amounts not yet recognized as a component of pension and other retirement benefit costs
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109,884
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114,854
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Regulatory cost of removal asset
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19,925
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19,087
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Robeson LNG development costs
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—
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127
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Derivatives - gas supply contracts held for utility operations
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149,600
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—
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Other
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871
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1,203
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Total noncurrent
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341,124
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196,726
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Total
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$
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419,544
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$
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207,662
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Regulatory Liabilities:
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Current:
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Amounts due to customers
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$
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3,908
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$
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13,367
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Noncurrent:
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Regulatory cost of removal obligations
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533,844
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521,478
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Deferred income taxes
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64,827
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68,738
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Amounts not yet recognized as a component of pension and other retirement benefit costs
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78
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85
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Total noncurrent
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598,749
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590,301
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Total
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$
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602,657
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$
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603,668
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Rate Oversight and Rate and Regulatory Actions
North Carolina
In November 2015, we filed a petition with the NCUC seeking authority, under the approved integrity management rider (IMR) mechanism, to change our rates effective December 1, 2015 to collect a total of
$40.9 million
in annual IMR margin revenues based on IMR-eligible capital investments in integrity and safety projects through September 30, 2015. In December 2015, the NCUC approved the requested IMR rate increase. In February 2016, the NCUC Public Staff filed their IMR audit report for the capital investment period through September 30, 2015, proposing an immaterial reduction in IMR margin for refund to customers, which we began recording in January 2016. In May 2016, we filed a petition to update our rates effective June 1, 2016 to collect an additional
$7.4 million
in annual IMR margin revenues from that approved by the NCUC in December 2015.
The June 2016 rate adjustment was based on
$74.9 million
of IMR-eligible capital investments in integrity and safety projects over the six-month period ended March 31, 2016. In May 2016, the NCUC approved the requested IMR rate increase.
In January 2016, we and Duke Energy filed a joint application with the NCUC seeking regulatory approval of the Acquisition. Subsequently, we, Duke Energy and the NCUC Public Staff reached an agreement of stipulation and settlement setting forth stipulations and conditions for approval of the proposed Acquisition, which was originally filed with the NCUC in June 2016. Among the stipulations contained in the agreement are:
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•
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Funding by the combined company of annual charitable contributions totaling at least
$17.5 million
in North Carolina during each of the four years after the Acquisition;
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•
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Commitment by the combined company of
$7.5 million
for low-income household energy assistance and workforce development programs in North Carolina during the first year after the Acquisition;
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•
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Exclusion of expenses related to the Acquisition, including severance costs, from customer bills;
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•
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Withdrawal of our March 2016 petition requesting approval of deferred accounting treatment for certain distribution integrity management program expenses; and
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•
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A one-time bill credit to our North Carolina customers collectively of
$10 million
.
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A hearing was held on July 18 and 19, 2016. On August 25, 2016, we, Duke Energy and the NCUC Public Staff filed a joint proposed order pursuant to the NCUC's procedural schedule. We are waiting on a ruling from the NCUC at this time.
In March 2016, we filed a petition with the NCUC requesting approval of deferred accounting treatment for certain distribution integrity management program expenses. We proposed this accounting treatment as an extension of the regulatory asset accounting treatment approved by the NCUC in December 2004 for our transmission integrity management program expenses. In June 2016, we agreed to withdraw this deferral request upon the NCUC’s approval of the agreement of stipulation and settlement in the proceeding seeking approval of the Acquisition as discussed above and upon closing of the Acquisition.
In August 2016, we filed testimony with the NCUC in support of our gas cost purchasing and accounting practices for the twelve months ended May 31, 2016. A hearing has been scheduled for October 3, 2016.
South Carolina
In June 2016, we filed testimony with the Public Service Commission of South Carolina (PSCSC) in support of our annual review of purchased gas adjustment and gas purchasing policies for the twelve months ended March 31, 2016. In June 2016, a settlement agreement with the Office of Regulatory Staff (ORS) was filed. A hearing was held on July 14, 2016. In August 2016, the PSCSC approved the settlement agreement finding that our gas purchasing policies were reasonable and prudent, that we properly adhered to the gas cost recovery provisions of our tariff and relevant PSCSC orders and that we managed our hedging program in a manner consistent with PSCSC orders.
In June 2016, we filed with the PSCSC a quarterly monitoring report for the twelve months ended March 31, 2016 and a cost and revenue study under the Rate Stabilization Act requesting a change in rates. In August 2016, a settlement agreement was filed with the ORS stipulating an $8.3 million annual increase in margin based on a return on equity of 10.2%, effective November 1, 2016. We are waiting on a ruling from the PSCSC at this time.
Tennessee
In February 2016, we filed an annual report for the twelve months ended June 30, 2015 with the TRA that reflected the transactions in the deferred gas cost account for the Actual Cost Adjustment (ACA) mechanism. In June 2016, the TRA approved the deferred gas cost account balances and issued its written order.
In August 2016, we filed an annual report for the twelve months ended June 30, 2016 with the TRA that reflected the transactions in the deferred gas cost account for the ACA mechanism. We are waiting on a ruling from the TRA at this time.
In August 2016, we filed an annual report with the 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, 2016 under the Tennessee Incentive Plan (TIP). We are waiting on a ruling from the TRA at this time.
In July 2016, the TRA Staff filed its compliance audit report for operation of our Weather Normalization Adjustment (WNA) rider during the 2015 – 2016 heating season, concluding that we had correctly implemented the WNA rider in all material aspects. The TRA Staff identified an immaterial error that resulted in an under-collection of our WNA revenues and
recommended a correcting adjustment through the ACA mechanism which we recorded in August 2016. In August 2016, the TRA approved and adopted the TRA Staff’s compliance audit report.
We compute basic earnings per share (EPS) using the daily weighted average number of shares of common stock outstanding during each period. In the calculation of fully diluted EPS, shares of common stock to be issued under approved incentive compensation plan (ICP) awards and forward sale agreements (FSAs) are contingently issuable shares, as determined by applying the treasury stock method, and are added to average common shares outstanding, resulting in a potential reduction in diluted EPS.
A reconciliation of basic and diluted EPS, which includes contingently issuable shares that could affect EPS if performance units ultimately vest and any FSAs settle, for the
three months and nine
months ended
July 31, 2016
and
2015
is presented below.
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Three Months
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Nine Months
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In thousands, except per share amounts
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2016
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2015
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2016
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2015
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Net Income (Loss)
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$
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(6,730
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)
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$
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(8,260
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)
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$
|
154,492
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$
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151,120
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Average shares of common stock outstanding for basic earnings per share
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81,214
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79,039
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81,095
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78,826
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Contingently issuable shares under ICP awards *
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—
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—
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87
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286
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|
Contingently issuable restricted nonvested shares under accelerated ICP awards *
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—
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182
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Contingently issuable shares under FSAs *
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—
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—
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28
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63
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Average shares of dilutive stock
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81,214
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|
79,039
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81,392
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79,175
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|
Earnings (Loss) Per Share of Common Stock:
|
|
|
|
|
|
|
|
Basic
|
$
|
(0.08
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
1.91
|
|
|
$
|
1.92
|
|
Diluted
|
$
|
(0.08
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
1.90
|
|
|
$
|
1.91
|
|
|
|
|
|
|
|
|
|
* The inclusion of 306 and 301 contingently issuable shares in the three months ended July 31, 2016 and 2015, respectively, under ICP awards and FSAs would have been antidilutive.
|
We accelerated the issuance of shares of common stock under approved ICP awards as permitted under the terms of the Merger Agreement. This acceleration resulted in the issuance of
181,944
restricted nonvested shares of our common stock in December 2015, plus
3,288
restricted nonvested shares of our common stock from the reinvestment of dividends on these shares during the nine months ended
July 31, 2016
. These restricted nonvested shares of our common stock are included in the calculation of diluted EPS in the table above but excluded in basic EPS and shares of our common stock outstanding because of their restricted nonvested nature. For further information on the acceleration of these shares of our common stock under our employee share-based plans, see
Note 12
to the condensed consolidated financial statements in this Form 10-Q.
|
|
5
.
|
Long-Term Debt Instruments
|
The NCUC approved debt and equity issuances under an effective debt and equity shelf registration statement up to
$1 billion
through June 6, 2017. As of
July 31, 2016
, we have
$244.1 million
remaining for debt and equity issuances as approved by the NCUC, including the issuance of debt discussed below. For further information on equity transactions, see
Note 7
to the condensed consolidated financial statements in this Form 10-Q. Unless otherwise specified at the time such securities are offered for sale, the net proceeds from the sale of the securities will be used to finance capital expenditures, to repay outstanding short-term, unsecured notes under our commercial paper (CP) program, to refinance other indebtedness, to repurchase our common stock, to pay dividends and for general corporate purposes.
On
June 6, 2016
, we repaid
$40 million
of our 2.92% senior notes at maturity.
On
July 28, 2016
, we issued
$300 million
of unsecured senior notes maturing
November 1, 2046
with an interest rate of
3.64%
and at a discount of
.122%
or
$366,000
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 million
from this issuance to finance capital expenditures, to repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes.
Our long-term debt as of
July 31, 2016
and
October 31, 2015
is presented below.
|
|
|
|
|
|
|
|
|
In thousands
|
July 31, 2016
|
|
October 31, 2015
|
Principal
|
$
|
1,835,000
|
|
|
$
|
1,575,000
|
|
Unamortized debt issuance expenses and discounts
|
(13,816
|
)
|
|
(11,323
|
)
|
Total
|
1,821,184
|
|
|
1,563,677
|
|
Less current maturities
|
—
|
|
|
40,000
|
|
Total long-term debt
|
$
|
1,821,184
|
|
|
$
|
1,523,677
|
|
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.
|
|
6
.
|
Short-Term Debt Instruments
|
We have an
$850 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 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 million
, of which
$1.7 million
and
$1.6 million
were issued and outstanding as of
July 31, 2016
and
October 31, 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
thirty-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.
We have an
$850 million unsecured CP program that is backstopped by the revolving syndicated credit facility. The amounts outstanding under the revolving syndicated credit facility and the CP program, either individually or in the aggregate, cannot exceed $850 million.
The notes issued under the CP program may have maturities not to exceed 397 days from the date of issuance 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 period.
As of
July 31, 2016
, we had
$240 million
of notes outstanding under the CP program, as included in “Short-term debt” in “Current Liabilities” in the Condensed Consolidated Balance Sheets, with original maturities ranging from
7
to
14
days from their dates of issuance at a weighted average interest rate of
.62%
. As of
October 31, 2015
, our outstanding notes under the CP program, included in the Condensed Consolidated Balance Sheets as stated above, were
$340 million
at a weighted average interest rate of
.22%
.
We did not have any borrowings under the revolving syndicated credit facility for the
nine
months ended
July 31, 2016
. A summary of the short-term debt activity under our CP program for the
three months and nine
months ended
July 31, 2016
is as follows.
|
|
|
|
|
|
|
|
|
In millions
|
Three Months
|
|
Nine Months
|
Minimum amount outstanding during period
|
$
|
240
|
|
|
$
|
240
|
|
Maximum amount outstanding during period
|
$
|
530
|
|
|
$
|
530
|
|
Minimum interest rate during period
|
.52
|
%
|
|
.20
|
%
|
Maximum interest rate during period
|
.68
|
%
|
|
.75
|
%
|
Weighted average interest rate during period
|
.60
|
%
|
|
.54
|
%
|
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 58%
at
July 31, 2016
.
Capital Stock
Changes in common stock for the
nine
months ended
July 31, 2016
are as follows.
|
|
|
|
|
|
|
|
In thousands
|
Shares
|
|
Amount
|
Balance, October 31, 2015
|
80,883
|
|
|
$
|
721,419
|
|
Issued to participants in the Employee Stock Purchase Plan (ESPP)
|
17
|
|
|
962
|
|
Issued to participants in the Dividend Reinvestment and Stock Purchase Plan (DRIP)
|
253
|
|
|
14,352
|
|
Issued to participants in the ICP
|
130
|
|
|
7,486
|
|
Costs from issuance of common stock
|
|
|
(88
|
)
|
Balance, July 31, 2016
|
81,283
|
|
|
$
|
744,131
|
|
In anticipation of the Acquisition by Duke Energy, we have suspended new investments in our DRIP and ESPP, effective July 31, 2016. During the suspension, we will not issue any common stock under these plans, except if the effective date of the Acquisition occurs on or after October 17, 2016, we will issue common stock for the reinvestment of dividends on the October 14, 2016 regular third-quarter dividend payment date. The DRIP and ESPP will be terminated at or prior to the effective date of the Acquisition.
Under our effective combined debt and equity shelf registration statement, we established an at-the-market (ATM) equity sales program, including a forward sale component. On January 7, 2015, we entered into separate ATM Equity Offering Sales Agreements (Sales Agreements) with Merrill Lynch, Pierce, Fenner & Smith Incorporated (Merrill) and J.P. Morgan Securities LLC (JP Morgan), in their capacity as agents and/or as principals (Agents). Under the terms of the Sales Agreements, we may issue and sell, through either of the Agents, shares of our common stock, up to an aggregate sales price of
$170 million
(subject to certain exceptions) through the end of fiscal year 2016.
In addition to the issuance and sale of shares by us through the Agents, we may also enter into FSAs with affiliates of the Agents as Forward Purchasers. In connection with each FSA, the Forward Purchasers will, at our request, borrow from third parties and, through the Agents, sell a number of shares of our common stock equal to the number of shares underlying the FSA as its hedge.
Under the Sales Agreements, we specify the maximum number of our shares to be sold and the minimum price per share. We will pay each Agent (or, in the case of a FSA, the Forward Purchaser through a reduced initial forward sale price) a commission of
1.5%
of the sales price of all shares sold through it as sales agent under the applicable Sales Agreement. The shares offered under the Sales Agreements may be offered, issued and sold in ATM sales through the Agents or offered in connection with one or more FSAs.
Under the terms of these FSAs, at our election, we may physically settle in shares, cash or net settle for all or a portion of our obligation under the agreements.
Under a FSA that we executed with JP Morgan on January 4, 2016,
360,000
shares were borrowed from third parties and sold by JP Morgan, from January 4, 2016 to January 28, 2016, at a weighted average share price of
$57.90
, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was
$57.04
.
Under a FSA that we executed with Merrill on March 11, 2016,
620,000
shares were borrowed from third parties and sold by Merrill, from March 14, 2016 to April 22, 2016, at a weighted average share price of
$59.66
, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was
$58.76
.
Under a FSA that we executed with JP Morgan on June 10, 2016,
820,000
shares were borrowed from third parties and sold by JP Morgan, from June 13, 2016 to July 29, 2016, at a weighted average share price of
$59.79
, net of adjustments. Based on the weighted average share price at the end of the trading period, the initial forward price was
$58.89
.
In accordance with accounting guidance,
we classified the FSAs as of July 31, 2016 as equity transactions because the forward sale transactions were indexed to our own stock and physical settlement was within our control
. As a result of this classification,
no
amounts were recorded in the condensed consolidated financial statements until the September 2016 settlement of the FSAs.
Upon physical settlement of the FSAs, delivery of our shares will result in dilution to our EPS at the settlement date. In quarters prior to any 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 prices described above. See
Note 4
to the condensed consolidated financial statements in this Form 10-Q for the dilutive effect of the FSAs on our EPS as of
July 31, 2016
with the inclusion of the 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 the combined
1.8
million shares of our common stock to the forward counterparties as of
July 31, 2016
, we would have received net proceeds of approximately
$104.7 million
.
On
September 1, 2016
, we issued
1.8 million
shares of our common stock to the forward counterparties in order to physically settle all of the FSAs entered into during 2016 and received net proceeds of
$104.7 million
. In September 2016, we recorded this amount in "Stockholders' equity" as an addition to "Common stock" in the Condensed Consolidated Balance Sheets. Upon settlement, we used the net proceeds from the FSA transactions to finance capital expenditures, repay outstanding short-term, unsecured notes under our CP program and for general corporate purposes. We do not expect to enter into another FSA through the remainder of this fiscal year.
Cash dividends paid per share of common stock for the
three months and nine
months ended
July 31, 2016
and
2015
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Cash dividends paid per share of common stock
|
$
|
0.34
|
|
|
$
|
0.33
|
|
|
$
|
1.01
|
|
|
$
|
0.98
|
|
Other Comprehensive Income (Loss)
Our OCIL is a part of our accumulated OCIL and is comprised of hedging activities and benefit activities from our equity method investments. For further information on these hedging activities by our equity method investments, see
Note 13
to the condensed consolidated financial statements in this Form 10-Q. Changes in each component of accumulated OCIL are presented below for the
three months and nine
months ended
July 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Accumulated OCIL
(1)
|
|
Three Months
|
|
Nine Months
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Accumulated OCIL beginning balance, net of tax
|
$
|
(640
|
)
|
|
$
|
(970
|
)
|
|
$
|
(855
|
)
|
|
$
|
(237
|
)
|
Hedging activities of equity method investments:
|
|
|
|
|
|
|
|
OCIL before reclassifications, net of tax
|
102
|
|
|
33
|
|
|
(360
|
)
|
|
(1,227
|
)
|
Amounts reclassified from accumulated OCIL, net of tax
|
206
|
|
|
307
|
|
|
881
|
|
|
872
|
|
Total current period activity of hedging activities of equity method investments, net of tax
|
308
|
|
|
340
|
|
|
521
|
|
|
(355
|
)
|
Net current period benefit activities of equity method investments, net of tax
|
(12
|
)
|
|
2
|
|
|
(10
|
)
|
|
(36
|
)
|
Accumulated OCIL ending balance, net of tax
|
$
|
(344
|
)
|
|
$
|
(628
|
)
|
|
$
|
(344
|
)
|
|
$
|
(628
|
)
|
|
|
|
|
|
|
|
|
(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 nine
months ended
July 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reclassification Out of Accumulated OCIL
(1)
|
|
Affected Line Items on Condensed
Statements of Operations and Comprehensive Income
|
|
Three Months
|
|
Nine Months
|
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
Hedging activities of equity method investments
|
$
|
330
|
|
|
$
|
505
|
|
|
$
|
1,438
|
|
|
$
|
1,430
|
|
|
Income from equity method investments
|
Income tax expense
|
(124
|
)
|
|
(198
|
)
|
|
(557
|
)
|
|
(558
|
)
|
|
Income taxes
|
Hedging activities of equity method investments
|
206
|
|
|
307
|
|
|
881
|
|
|
872
|
|
|
|
Net benefit activities of equity method investments
|
(19
|
)
|
|
3
|
|
|
(15
|
)
|
|
(60
|
)
|
|
Income from equity method investments
|
Income tax expense
|
7
|
|
|
(1
|
)
|
|
5
|
|
|
24
|
|
|
Income taxes
|
Net benefit activities of equity method investments
|
(12
|
)
|
|
2
|
|
|
(10
|
)
|
|
(36
|
)
|
|
|
Total reclassification for the period, net of tax
|
$
|
194
|
|
|
$
|
309
|
|
|
$
|
871
|
|
|
$
|
836
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Amounts in parentheses indicate debits to accumulated OCIL.
|
|
|
8
.
|
Marketable Securities
|
We have marketable securities that are invested in money market and mutual funds that are liquid and actively traded on the exchanges. These securities are assets that are held in rabbi trusts established for our deferred compensation plans. For further information on the deferred compensation plans, see
Note 11
to the condensed 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 on the Condensed 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 deemed 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 asset portion is included in “Other current assets” in “Current Assets” in the Condensed Consolidated Balance Sheets.
The money market investments in the trusts approximate fair value due to the short period of time to maturity. The fair values of the equity securities are based on quoted market prices as traded on the exchanges. The composition of these securities as of
July 31, 2016
and
October 31, 2015
is as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 31, 2016
|
|
October 31, 2015
|
In thousands
|
Cost
|
|
Fair
Value
|
|
Cost
|
|
Fair
Value
|
Current trading securities:
|
|
|
|
|
|
|
|
Money markets
|
$
|
26
|
|
|
$
|
26
|
|
|
$
|
51
|
|
|
$
|
51
|
|
Mutual funds
|
217
|
|
|
250
|
|
|
114
|
|
|
185
|
|
Total current trading securities
|
243
|
|
|
276
|
|
|
165
|
|
|
236
|
|
Noncurrent trading securities:
|
|
|
|
|
|
|
|
Money markets
|
579
|
|
|
579
|
|
|
465
|
|
|
465
|
|
Mutual funds
|
4,045
|
|
|
4,557
|
|
|
3,625
|
|
|
4,201
|
|
Total noncurrent trading securities
|
4,624
|
|
|
5,136
|
|
|
4,090
|
|
|
4,666
|
|
Total trading securities
|
$
|
4,867
|
|
|
$
|
5,412
|
|
|
$
|
4,255
|
|
|
$
|
4,902
|
|
|
|
9
.
|
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
July 31, 2016
and
October 31, 2015
, we had long gas purchase options providing total coverage of
22.2 million
dekatherms and
34.7 million
dekatherms, respectively. The long gas purchase options held as of
July 31, 2016
are for the period from September 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. Effective in the period ended January 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 "Gas supply derivative liabilities, at fair value" in "Current Liabilities" and "Noncurrent Liabilities" in the Condensed Consolidated Balance Sheets. As these contracts have been entered into for our regulated utility operations, and as commodity costs are recoverable through our purchased gas adjustment (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 in the period ended January 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 “Marketable securities, at fair value” in “Noncurrent Assets” in the Condensed 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.
We classify fair value balances based on the observance of 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, 2015
. For an updated discussion of our fair value methodology, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.
The following table sets forth, by level of the fair value hierarchy, our financial and nonfinancial assets and liabilities that were accounted for at fair value on a recurring basis as of
July 31, 2016
and
October 31, 2015
. 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
July 31, 2016
and
2015
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of July 31, 2016
|
In thousands
|
Quoted Prices
in Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Effects of
Netting and
Cash Collateral
Receivables /
Payables
|
|
Total
Carrying
Value
|
Assets:
|
|
|
|
|
|
|
|
|
|
Derivatives - gas purchase options held for utility operations
|
$
|
4,231
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,231
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
Money markets
|
605
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
605
|
|
Mutual funds
|
4,807
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,807
|
|
Total fair value assets
|
$
|
9,643
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,643
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Derivatives - gas supply contracts held for utility operations
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
182,900
|
|
|
$
|
—
|
|
|
$
|
182,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring Fair Value Measurements as of October 31, 2015
|
In thousands
|
Quoted Prices
in Active
Markets
(Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Effects of
Netting and
Cash Collateral
Receivables /
Payables
|
|
Total
Carrying
Value
|
Assets:
|
|
|
|
|
|
|
|
|
|
Derivatives - gas purchase options held for utility operations
|
$
|
1,343
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,343
|
|
Debt and equity securities held as trading securities:
|
|
|
|
|
|
|
|
|
|
Money markets
|
516
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
516
|
|
Mutual funds
|
4,386
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,386
|
|
Total fair value assets
|
$
|
6,245
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,245
|
|
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
$2.62
to
$4.80
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
three months and nine
months ended
July 31, 2016
.
|
|
|
|
|
|
|
|
|
In thousands
|
Three Months
|
|
Nine Months
|
Gas supply derivative liabilities, beginning balance
|
$
|
164,900
|
|
|
$
|
—
|
|
Realized and unrealized losses:
|
|
|
|
Recorded to regulatory assets *
|
18,000
|
|
|
182,900
|
|
Purchases, sales and settlements (net)
|
—
|
|
|
—
|
|
Transfer in/out of Level 3
|
—
|
|
|
—
|
|
Gas supply derivative liabilities, ending balance
|
$
|
182,900
|
|
|
$
|
182,900
|
|
|
|
|
|
* Included are the actual costs recorded in "Cost of Gas" in the Condensed 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 segment 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 segment as a result of the use of these gas purchase options is initially deferred as amounts due from customers included as “Regulatory Assets” or amounts due to customers included as “Regulatory Liabilities” in
Note 3
to the condensed consolidated financial statements in this Form 10-Q and recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of “Cost of 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
to the condensed consolidated financial statements in this Form 10-Q.
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
July 31, 2016
and
October 31, 2015
.
Fair Value of Derivative Instruments
|
|
|
|
|
|
|
|
|
|
July 31,
|
|
October 31,
|
In thousands
|
2016
|
|
2015
|
Derivatives Not Designated as Hedging Instruments under Derivative Accounting Standards:
|
|
|
|
Financial Asset Instruments:
|
|
|
|
Current Assets – Gas purchase derivative assets
|
$
|
4,231
|
|
|
$
|
1,343
|
|
Nonfinancial Liability Instruments:
|
|
|
|
Current Liabilities – Gas supply derivative liabilities
|
33,300
|
|
|
|
Noncurrent Liabilities – Gas supply derivative liabilities
|
149,600
|
|
|
|
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 Condensed Consolidated Statements of Operations and Comprehensive Income for the
three months and nine
months ended
July 31, 2016
and
2015
, absent the regulatory treatment under our approved PGA procedures.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Loss Recognized
on Derivative Instruments and Deferred Under PGA Procedures
|
|
Location of Loss
Recognized through
PGA Procedures
|
|
Three Months Ended
July 31
|
|
Nine Months Ended
July 31
|
|
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
Gas purchase options
|
$
|
(886
|
)
|
|
$
|
(1,007
|
)
|
|
$
|
(4,428
|
)
|
|
$
|
(3,296
|
)
|
|
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 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
$18 million
and
$182.9 million
related to our gas supply derivative contracts in the Condensed Consolidated Statements of Operations and Comprehensive Income for the
three months and nine
months ended
July 31, 2016
, respectively, absent regulatory provisions for rate-regulated activities. We recognize the actual costs of our gas
supply derivative contracts in the Condensed Consolidated Statements of Operations and Comprehensive Income as a component of "Cost of 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 similar to our debt issuances. The principal and fair value of our long-term debt, including the current portion, which is classified within Level 2, are shown below.
|
|
|
|
|
|
|
|
|
In thousands
|
Principal
|
|
Fair Value
|
As of July 31, 2016
|
$
|
1,835,000
|
|
|
$
|
2,131,778
|
|
As of October 31, 2015
|
1,575,000
|
|
|
1,720,586
|
|
Credit and Counterparty Risk
Information regarding our credit and counterparty risk is set forth in Note 8 to the consolidated financial statements in our Form 10-K for the year ended
October 31, 2015
. During the three months ended
July 31, 2016
, there were no material changes in our credit and counterparty risk.
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 Condensed Consolidated Balance Sheets
attributable to these entities amounted to
$9.2 million
, or approximately
15%
, of our gross trade accounts receivable as of
July 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.
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 the direction of the Treasurer and Chief Risk Officer and our Enterprise Risk Management program, including our Energy Price Risk Management Committee. Risk management is guided by senior management with Board of Directors oversight, and senior management takes an active role in the development of policies and procedures.
|
|
10
.
|
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 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
twenty years
. The time periods for fixed payments of reservation fees under gas supply contracts are up to
one year
. The time periods 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 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 Condensed Consolidated Statements of Operations and 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, 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
July 31, 2016
. Additional information concerning letters of credit is included in
Note 6
to the condensed consolidated financial statements in this Form 10-Q.
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
July 31, 2016
, we had open surety bonds with a total contingent obligation of
$6.5 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). There were no material changes in the status of environmental-related matters during the
nine
months ended
July 31, 2016
.
As of
July 31, 2016
, our estimated undiscounted environmental liability totaled
$1 million
, and consisted of
$.9 million
for MGP sites for which we retain responsibility and
$.1 million
for the USTs and the Huntersville LNG facility. 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.
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.
Additional information concerning commitments and contingencies is set forth in Note 9 to the consolidated financial statements of our Form 10-K for the year ended
October 31, 2015
.
|
|
11
.
|
Employee Benefit Plans
|
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 will receive 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.
Beginning in fiscal year 2016, we changed the methodology we use to calculate the periodic net benefit cost for our defined benefit pension plan. We replaced the zero-coupon spot rate yield curve as the basis to estimate the service and interest cost components with a full yield curve methodology. This methodology applies specific spot rates along the yield curve to
determine the benefit obligations of the relevant projected cash flows. This change improves the correlation between projected benefit cash flows and the corresponding yield curve spot rates and provides a more precise measurement of service and interest costs. This change did not affect the measurement of our total benefit 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.
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
July 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
Nonqualified
Pension
|
|
Other Benefits
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Service cost
|
$
|
2,750
|
|
|
$
|
2,452
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
294
|
|
|
$
|
295
|
|
Interest cost
|
2,400
|
|
|
3,063
|
|
|
40
|
|
|
52
|
|
|
321
|
|
|
369
|
|
Expected return on plan assets
|
(6,000
|
)
|
|
(5,860
|
)
|
|
—
|
|
|
—
|
|
|
(442
|
)
|
|
(459
|
)
|
Amortization of prior service (credit) cost
|
(550
|
)
|
|
(548
|
)
|
|
52
|
|
|
58
|
|
|
(83
|
)
|
|
—
|
|
Amortization of actuarial loss
|
2,100
|
|
|
2,407
|
|
|
20
|
|
|
21
|
|
|
115
|
|
|
7
|
|
Total
|
$
|
700
|
|
|
$
|
1,514
|
|
|
$
|
112
|
|
|
$
|
131
|
|
|
$
|
205
|
|
|
$
|
212
|
|
Components of the net periodic benefit cost for our defined benefit pension plans and our OPEB plan for the
nine
months ended
July 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Qualified Pension
|
|
Nonqualified
Pension
|
|
Other Benefits
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Service cost
|
$
|
8,250
|
|
|
$
|
8,552
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
883
|
|
|
$
|
886
|
|
Interest cost
|
7,200
|
|
|
9,013
|
|
|
118
|
|
|
157
|
|
|
962
|
|
|
1,107
|
|
Expected return on plan assets
|
(18,000
|
)
|
|
(17,710
|
)
|
|
—
|
|
|
—
|
|
|
(1,325
|
)
|
|
(1,378
|
)
|
Amortization of prior service (credit) cost
|
(1,650
|
)
|
|
(1,648
|
)
|
|
156
|
|
|
173
|
|
|
(249
|
)
|
|
—
|
|
Amortization of actuarial loss
|
6,300
|
|
|
6,507
|
|
|
61
|
|
|
64
|
|
|
344
|
|
|
22
|
|
Total
|
$
|
2,100
|
|
|
$
|
4,714
|
|
|
$
|
335
|
|
|
$
|
394
|
|
|
$
|
615
|
|
|
$
|
637
|
|
In November 2015, we contributed
$10 million
to the qualified pension plan, and in January
2016
, we contributed
$1.8 million
to the money purchase pension plan. During the
nine
months ended
July 31, 2016
, we contributed
$.4 million
to the nonqualified pension plans. We anticipate that we will contribute the following additional amounts to our plans in
2016
.
|
|
|
|
|
In thousands
|
|
Nonqualified pension plans
|
$
|
129
|
|
OPEB plan
|
1,300
|
|
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 funded from time to time, typically annually. For the
nine
months ended
July 31, 2016
, we contributed
$.5 million
to this plan. Participants may not contribute to the DCR plan. We have a voluntary deferral compensation 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
July 31, 2016
, we have a liability of
$5.7 million
for these plans.
See
Note 8
and
Note 9
to the condensed consolidated financial statements in this Form 10-Q for information on the investments in marketable securities that are held in the trusts.
|
|
12
.
|
Employee Share-Based Plans
|
Liability 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. We have granted three series of awards, each with a three-year performance period ending October 31, 2016 (2016 plan), October 31, 2017 (2017 plan) and October 31, 2018 (2018 plan). 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 nine
months ended
July 31, 2016
and
2015
, we recorded compensation expense, and as of
July 31, 2016
and
October 31, 2015
, we 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 each quarter and at the settlement date. The award with the performance period that ended October 31, 2015 was paid out to participants in December 2015. The 2016 plan and 2017 plan were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.
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 will be 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 the performance period ending 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.
Also under our approved ICP,
64,700
nonvested restricted stock units (RSUs) were granted to our President and CEO in December 2011. During the five-year vesting period, any dividend equivalents accrue on these stock units and are 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 RSUs 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 vested on December 15, 2014 and 30% of the units vested on December 15, 2015. The remaining 50% of the units that vest on December 15, 2016 (2016 RSU) were accelerated as authorized by the Compensation Committee of our Board of Directors as discussed below.
For the
three months and nine
months ended
July 31, 2016
and
2015
, we recorded compensation expense, and as of
July 31, 2016
and
October 31, 2015
, we accrued a liability for nonvested RSUs, as applicable, based on the fair market value of our stock at the end of the quarter. The liability is re-measured to market value each quarter and at the settlement date.
The December 15, 2015 vesting covered 30% of the grant, including accrued dividends, for a total of
22,434
shares of common stock. After withholdings of
$.6 million
for federal and state income taxes, our President and CEO received
11,732
shares of our common stock at the NYSE composite closing price on December 14, 2015 of
$56.85
per share.
The compensation expense related to the incentive compensation plans for the
three months and nine
months ended
July 31, 2016
and
2015
, and the amounts recorded as liabilities in “Other noncurrent liabilities” in “Noncurrent Liabilities” with the current portion recorded in “Other current liabilities” in “Current Liabilities” in the Condensed Consolidated Balance Sheets as of
July 31, 2016
and
October 31, 2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Compensation expense
|
$
|
1,534
|
|
|
$
|
1,317
|
|
|
$
|
9,400
|
|
|
$
|
4,596
|
|
|
|
|
|
|
|
|
|
|
|
July 31,
2016
|
|
October 31,
2015
|
Liability
|
$
|
12,895
|
|
|
$
|
22,037
|
|
The Merger Agreement provides for the conversion of the shares subject to the RSUs and 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 2016 RSU for our President and CEO (accelerated RSU) and the ICP awards under the 2016 plan and the 2017 plan (accelerated ICP awards) at the target level of performance to participants, at his and their elections to accelerate, in the form of restricted nonvested shares of our common stock, net of
shares withheld for applicable taxes. The acceleration of the vesting and payment of these awards will mitigate the effects of Section 280G of the Internal Revenue Code of 1986, as amended, including increasing the deductibility of such payments for the Company. The acceleration and payout of the ICP awards, at a
96%
election rate by the participants, and the 2016 RSU, per the election of our President and CEO, occurred on December 15, 2015.
In connection with the election to accelerate the ICP awards and the 2016 RSU, each respective participant executed a share repayment agreement dated December 15, 2015. Under the share repayment agreements, each participant agreed to repay to the Company the net after-tax shares of common stock issued to him/her in connection with the acceleration, as well as shares of common stock resulting from the reinvestment of dividends paid with respect to these shares of common stock that are required to be reinvested in additional shares of common stock, to the extent the shares of common stock would not otherwise have been earned or payable absent the acceleration. Under the share repayment agreements, the restricted nonvested shares of common stock delivered to the participants, including dividends paid by the Company and reinvested as discussed above, may not be transferred or encumbered until such shares of common stock are no longer subject to repayment under the applicable repayment agreement.
The restricted nonvested shares of common stock and dividends earned on those shares of common stock are subject to full or partial cancellation if the Acquisition is not consummated or the participant leaves the Company prior to consummation of the Acquisition. In accordance with accounting guidance, we have not presented these restricted nonvested shares as shares outstanding or included them in our calculation of basic EPS as they are contingent shares until earned; as applicable, they are included in our calculation of diluted EPS in
Note 4
to the condensed consolidated financial statements in this Form 10-Q. The participants otherwise have all rights of shareholders with respect to the restricted nonvested shares of common stock.
The accelerated ICP awards and the accelerated RSU 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. The gross value of the shares issued for the accelerated ICP awards was
$17.4 million
, or
$9.2 million
net of federal and state tax withholdings.
Under the accelerated 2016 RSU,
19,554
restricted nonvested shares of our common stock were issued to our President and CEO, net of shares withheld for applicable federal and state income taxes. The gross value of the shares issued for the accelerated RSU was
$2.1 million
, or
$1.1 million
net of federal and state tax withholdings.
Equity Plan
On a quarterly basis, we issue shares of common stock under the ESPP and account 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 average of the high and low trading prices on the purchase date.
In anticipation of the consummation of the Acquisition, we suspended new investments in the ESPP and resulting issuances of common stock under the ESPP, effective July 31, 2016. The ESPP will be terminated at or prior to the effective date of the Acquisition.
|
|
13
.
|
Equity Method Investments
|
The condensed 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 Condensed Consolidated Balance Sheets. Earnings or losses from equity method investments are included in “Income from equity method investments” in “Other Income (Expense)” in the Condensed Consolidated Statements of Operations and Comprehensive Income.
Ownership Interests
We have the following membership interests in these companies as of
July 31, 2016
and
October 31, 2015
.
|
|
|
|
|
|
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 LLC (SouthStar)
|
|
15%
|
|
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 (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)
|
|
10%
|
|
To develop, construct, own and operate approximately 600 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 diverse eastern gas supplies into southeastern markets; regulated by the FERC
|
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. SouthStar uses 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 is based on selected market indices. Retirement benefits are allocated to SouthStar by its majority member with the activity of prescribed benefit expense items reflected in accumulated OCIL. For these transactions with these equity method investees, 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
” in “Stockholders’ equity” in the Condensed Consolidated Balance Sheets; the detail of our share of the market value of the various financial instruments and the retirement benefits are presented in “Other Comprehensive Income (Loss), net of tax” in the Condensed Consolidated Statements of Operations and Comprehensive Income.
Related Party Transactions
We have related party transactions as a customer of our investments. For each period of the
three months and nine
months ended
July 31, 2016
and
2015
, these gas costs and the amounts we owed to our equity method investees as of
July 31, 2016
and
October 31, 2015
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Related Party
|
|
Type of Expense
|
|
Cost of Gas
(1)
|
|
Trade accounts payable
(2)
|
|
|
|
|
Three Months
|
|
Nine Months
|
|
July 31, 2016
|
|
October 31, 2015
|
In thousands
|
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
Cardinal
|
|
Transportation costs
|
|
$
|
2,198
|
|
|
$
|
2,207
|
|
|
$
|
6,550
|
|
|
$
|
6,556
|
|
|
$
|
741
|
|
|
$
|
744
|
|
Hardy Storage
|
|
Gas storage costs
|
|
2,322
|
|
|
2,322
|
|
|
6,967
|
|
|
6,967
|
|
|
774
|
|
|
774
|
|
Pine Needle
|
|
Gas storage costs
|
|
2,535
|
|
|
2,833
|
|
|
8,141
|
|
|
8,609
|
|
|
854
|
|
|
955
|
|
Totals
|
|
|
|
$
|
7,055
|
|
|
$
|
7,362
|
|
|
$
|
21,658
|
|
|
$
|
22,132
|
|
|
$
|
2,369
|
|
|
$
|
2,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In the Condensed Consolidated Statements of Operations and Comprehensive Income.
|
(2)
In the Condensed Consolidated Balance Sheets.
|
We have related party transactions as we sell wholesale gas supplies to SouthStar. For each period of the
three months and nine
months ended
July 31, 2016
and
2015
, our operating revenues from these sales and the amounts SouthStar owed us as of
July 31, 2016
and
October 31, 2015
are as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenues
(1)
|
|
Trade accounts receivable
(2)
|
|
|
Three Months
|
|
Nine Months
|
|
July 31, 2016
|
|
October 31, 2015
|
In thousands
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
|
Operating revenues
|
|
$
|
34
|
|
|
$
|
475
|
|
|
$
|
286
|
|
|
$
|
1,058
|
|
|
$
|
2
|
|
|
$
|
183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
In the Condensed Consolidated Statements of Operations and Comprehensive Income.
|
(2)
In the Condensed Consolidated Balance Sheets.
|
Other Information
SouthStar
In accordance with the SouthStar limited liability company (LLC) agreement, upon the announcement of the Acquisition, we delivered a notice of change of control to Georgia Natural Gas Company (GNGC). On December 9, 2015, GNGC delivered to us a written notice electing to purchase our entire 15% interest in SouthStar, subject to and effective with the consummation of the Acquisition. On February 12, 2016, we entered into a letter agreement with GNGC for the purchase of our interest for
$160 million
cash. The letter agreement provides that we and GNGC will execute a definitive agreement for the purchase, which will include the satisfaction of customary closing conditions and obtaining regulatory approvals or consents necessary to consummate the purchase of our interest. The definitive agreement has been negotiated, and the parties intend to execute it and close the purchase, simultaneously with the closing of the Acquisition.
Constitution
A subsidiary of The Williams Companies is the operator of the Constitution pipeline project. The total estimated cost of the project is
$1.1 billion
, including an allowance for funds used during construction (AFUDC).
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 challenging the legality and appropriateness of the NYSDEC’s decision. Both courts granted Constitution's motions to expedite the schedules for the legal actions.
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 to 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. The NYAG filed a motion for reconsideration of this order.
Our investment in Constitution totaled
$93.6 million
as of
July 31, 2016
. We evaluated our investment in the Constitution project for OTTI since the NYSDEC denied Constitution’s application for the water quality certification. 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 at very early stages given the recent actions of the NYSDEC in late April 2016. Further, the courts have granted Constitution's motions to expedite the schedules for the legal actions. However, to the extent that the legal and regulatory proceedings have unfavorable outcomes, or if Constitution concludes that the project is not viable or does not go forward as legal and regulatory
actions progress, our conclusions with respect to OTTI could change and may require that we recognize an impairment charge of up to our recorded investment in the project, net of any cash and working capital returned. We will continue to monitor and update our OTTI analysis as required. Different assumptions could affect the timing and amount of any charge recorded in a period. For information on our evaluation process, see "Fair Value Measurements" in Note 1 to the condensed consolidated financial statements in this Form 10-Q.
We believe that the denial of the certification and resulting delay in the project’s in-service date will not have a material impact on the Acquisition by Duke Energy that is expected to close by the end of
2016
.
Pending the outcome of the matters described above, and when construction proceeds, we remain committed to fund the project in an amount in proportion to our ownership interest for the development and construction of the new pipeline, which is expected to cost approximately
$955 million
, excluding AFUDC, subject to the terms of the LLC agreement. Our total anticipated contributions are approximately
$229.3 million
. As of
July 31, 2016
, our contributions for the quarter and fiscal year 2016 were
$.5 million
and
$10.2 million
, respectively, with our total equity contribution for the project totaling
$82.9 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.
ACP
A subsidiary of Dominion Resources, Inc. (Dominion) is the operator of the ACP pipeline project. The total cost of the project is expected to be between
$4.5 billion
to
$5 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.
We have committed to fund an amount in proportion to our ownership interest for the development and construction of the new pipeline. As of
July 31, 2016
, our contributions for the quarter and fiscal year 2016 were
$10 million
and
$20.4 million
, respectively, with our total equity contributions for the project totaling
$31 million
to date.
ACP is regulated by the FERC and subject to state and other federal approvals with a target in-service date that has moved into
2019
. The capacity of ACP is substantially subscribed by affiliates of the members of ACP and another utility under
twenty
-year contracts.
ACP filed its 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 mid-2017 with construction projected to begin in late summer of 2017.
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 a draft of its environmental impact statement (EIS) in December 2016 and the final EIS in the summer of 2017. Based on this schedule, ACP is reviewing the timing of the project, as well as refining the project cost estimates.
On March 2, 2015, ACP entered into a Precedent Agreement with Dominion Transmission, Inc. (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 has 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. This commitment is capped at
$15.2 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.
On October 24, 2015, Piedmont entered into a Merger Agreement with Duke Energy. The ACP Limited Liability Company Agreement includes provisions that grant Dominion an option, exercisable following consummation of the Acquisition, to purchase additional ownership interests in ACP from Duke Energy to maintain a majority ownership percentage relative to all other members. After consummation of the Acquisition, Duke Energy, together with our ownership, would have a 50% membership interest unless Dominion exercises its option.
|
|
14
.
|
Variable Interest Entities
|
As of
July 31, 2016
, we have determined that we are not the primary beneficiary under variable interest entity (VIE) accounting guidance in any of our equity method investments, as presented in
Note 13
to the condensed 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, 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 included in "Equity method investments in non-utility activities" in "Noncurrent Assets" in the Condensed Consolidated Balance Sheets. As of
July 31, 2016
and
October 31, 2015
, our investment balances are as follows.
|
|
|
|
|
|
|
|
|
In thousands
|
July 31,
2016
|
|
October 31,
2015
|
Cardinal
|
$
|
14,456
|
|
|
$
|
15,083
|
|
Pine Needle
|
17,155
|
|
|
18,396
|
|
SouthStar
|
41,371
|
|
|
41,325
|
|
Hardy Storage
|
41,753
|
|
|
39,706
|
|
Constitution
|
93,587
|
|
|
82,403
|
|
ACP
|
31,328
|
|
|
10,043
|
|
Total equity method investments in non-utility activities
|
$
|
239,650
|
|
|
$
|
206,956
|
|
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.
15
. Business Segments
We have
three
reportable business segments, regulated utility, regulated non-utility and unregulated 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 include the operations of merchandising and its related service work and home service agreements, with activities conducted by the parent company. Although the operations of our regulated utility 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 within one company. Operations of our regulated non-utility activities segment are comprised of our equity method investments in joint ventures with regulated activities that are held by our wholly-owned subsidiaries. Operations of our unregulated non-utility activities segment are comprised primarily of our equity method investment in a joint venture with unregulated activities that is held by a wholly-owned subsidiary; activities of our other minor subsidiaries are also included.
Operations of the regulated utility segment are reflected in “Operating Income” in the Condensed Consolidated Statements of Operations and Comprehensive Income. Operations of the regulated non-utility activities and unregulated non-utility activities segments are included in the Condensed Consolidated Statements of Operations and Comprehensive Income in “Other Income (Expense)” in “Income from equity method investments” and “Non-operating income.”
Our chief operating decision maker is the executive management team. We produce consolidated financial information internally that is supplemented with separate non-utility activity reporting that is used regularly to make operating decisions
and assess performance of our three business segments. 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 regulated and unregulated non-utility activities segments based on earnings and cash flows 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, 2015
.
Operations by segment for the
three months and nine
months ended
July 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulated Utility
|
|
Regulated
Non-Utility
Activities
|
|
Unregulated
Non-Utility
Activities
|
|
Total
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Three Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
157,806
|
|
|
$
|
158,266
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
157,806
|
|
|
$
|
158,266
|
|
Margin
|
114,771
|
|
|
111,572
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
114,771
|
|
|
111,572
|
|
Operations and maintenance expenses
|
68,867
|
|
|
69,587
|
|
|
16
|
|
|
19
|
|
|
58
|
|
|
49
|
|
|
68,941
|
|
|
69,655
|
|
Income from equity method investments
|
—
|
|
|
—
|
|
|
1,229
|
|
|
3,894
|
|
|
3,009
|
|
|
1,907
|
|
|
4,238
|
|
|
5,801
|
|
Operating income (loss) before income taxes
|
316
|
|
|
(1,864
|
)
|
|
(121
|
)
|
|
(89
|
)
|
|
(76
|
)
|
|
(68
|
)
|
|
119
|
|
|
(2,021
|
)
|
Income (loss) before income taxes
|
(15,233
|
)
|
|
(18,904
|
)
|
|
1,108
|
|
|
3,805
|
|
|
2,932
|
|
|
1,839
|
|
|
(11,193
|
)
|
|
(13,260
|
)
|
Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers
|
$
|
969,329
|
|
|
$
|
1,190,462
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
969,329
|
|
|
$
|
1,190,462
|
|
Margin
|
625,385
|
|
|
607,263
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
625,385
|
|
|
607,263
|
|
Operations and maintenance expenses
|
215,675
|
|
|
207,162
|
|
|
49
|
|
|
70
|
|
|
126
|
|
|
96
|
|
|
215,850
|
|
|
207,328
|
|
Income from equity method investments
|
—
|
|
|
—
|
|
|
9,495
|
|
|
11,242
|
|
|
18,530
|
|
|
18,666
|
|
|
28,025
|
|
|
29,908
|
|
Operating income (loss) before income taxes
|
275,587
|
|
|
271,697
|
|
|
(154
|
)
|
|
(140
|
)
|
|
(232
|
)
|
|
(203
|
)
|
|
275,201
|
|
|
271,354
|
|
Income before income taxes
|
225,601
|
|
|
218,414
|
|
|
9,341
|
|
|
11,102
|
|
|
18,299
|
|
|
18,464
|
|
|
253,241
|
|
|
247,980
|
|
Reconciliations to the condensed consolidated statements of operations and comprehensive income for the
three months and nine
months ended
July 31, 2016
and
2015
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
Nine Months
|
In thousands
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Operating Income (Loss):
|
|
|
|
|
|
|
|
Segment operating income (loss) before income taxes
|
$
|
119
|
|
|
$
|
(2,021
|
)
|
|
$
|
275,201
|
|
|
$
|
271,354
|
|
Utility income taxes
|
6,339
|
|
|
7,097
|
|
|
(87,660
|
)
|
|
(85,583
|
)
|
Regulated non-utility activities operating loss before income taxes
|
121
|
|
|
89
|
|
|
154
|
|
|
140
|
|
Unregulated non-utility activities operating loss before income taxes
|
76
|
|
|
68
|
|
|
232
|
|
|
203
|
|
Operating income
|
$
|
6,655
|
|
|
$
|
5,233
|
|
|
$
|
187,927
|
|
|
$
|
186,114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss):
|
|
|
|
|
|
|
|
Income (loss) before income taxes for reportable segments
|
$
|
(11,193
|
)
|
|
$
|
(13,260
|
)
|
|
$
|
253,241
|
|
|
$
|
247,980
|
|
Income taxes
|
4,463
|
|
|
5,000
|
|
|
(98,749
|
)
|
|
(96,860
|
)
|
Total
|
$
|
(6,730
|
)
|
|
$
|
(8,260
|
)
|
|
$
|
154,492
|
|
|
$
|
151,120
|
|
We monitor significant events occurring after the balance sheet date and prior to the issuance of the financial statements to determine the impacts, if any, of events on the financial statements to be issued. All subsequent events of which we are aware were evaluated. For information on subsequent event disclosure items related to regulatory matters, stockholders' equity and equity method investments, see
Note 3
,
Note 7
and
Note 13
, respectively, to the condensed consolidated financial statements in this Form 10-Q.